Attached files
UNITED
STATES SECURITIES AND EXCHANGE COMMISSION
Washington,
D.C. 20549
________________
Form
10-K
(Mark
One)
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R
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ANNUAL
REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF
1934
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For
the fiscal year ended December 31, 2009
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OR
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£
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TRANSITION REPORT PURSUANT TO
SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF
1934
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For
the transition period
from to
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Commission
File Number 1-4874
Colorado
Interstate Gas Company
(Exact Name of
Registrant as Specified in Its Charter)
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Delaware
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84-0173305
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(State or
Other Jurisdiction of
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(I.R.S.
Employer
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Incorporation
or Organization)
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Identification
No.)
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El
Paso Building
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77002
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1001
Louisiana Street
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(Zip
Code)
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Houston,
Texas
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(Address of
Principal Executive Offices)
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Telephone
Number: (713) 420-2600
Securities
registered pursuant to Section 12(b) of the Act:
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Title of each
class
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Name of each
exchange on which registered
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6.85% Senior
Debentures, due 2037
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New York
Stock Exchange
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Securities
registered pursuant to Section 12(g) of the Act: None
Indicate by check
mark if the registrant is a well-known seasoned issuer, as defined in Rule 405
of the Securities Act.
Yes £ No R
Indicate by check
mark if the registrant is not required to file reports pursuant to Section 13 or
Section 15(d) of the Act.
Yes £ No R
Indicate by check
mark whether the registrant (1) has filed all reports required to be filed by
Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding
12 months (or for such shorter period that the registrant was required to file
such reports), and (2) has been subject to such filing requirements for the past
90 days. Yes R No £
Indicate by check
mark whether the registrant has submitted electronically and posted on its
corporate Web site, if any, every Interactive Data File required to be submitted
and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months
(or for such shorter period that the registrant was required to submit and post
such files). Yes £ No
£
Indicate by check
mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K
is not contained herein, and will not be contained, to the best of registrant’s
knowledge, in definitive proxy or information statements incorporated by
reference in Part III of this Form 10-K or any amendment to this Form 10-K.
R
Indicate by check
mark whether the registrant is a large accelerated filer, an accelerated filer,
a non-accelerated filer, or a smaller reporting company. See the definitions of
"large accelerated filer," "accelerated filer" and "smaller reporting company"
in Rule 12b-2 of the Exchange Act. (Check one):
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Large
accelerated filer £
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Accelerated
filer £
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Non-accelerated
filer R
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Smaller
reporting company £
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(Do not check if a smaller reporting
company)
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Indicate by check
mark whether the registrant is a shell company (as defined in Rule 12b-2 of the
Act). Yes £ No R
State the aggregate market value of
the voting equity held by non-affiliates of the registrant:
None
Documents
Incorporated by Reference: None
COLORADO
INTERSTATE GAS COMPANY
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Caption
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Page
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Below is a list of
terms that are common to our industry and used throughout this
document:
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/d
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=
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per
day
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MDth
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=
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thousand
dekatherms
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BBtu
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=
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billion
British thermal units
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MMcf
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=
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million cubic
feet
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Bcf
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=
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billion cubic
feet
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NGL
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=
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natural gas
liquids
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Dth
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=
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dekatherm
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Tonne
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=
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metric
ton
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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.
Overview
and Strategy
We are a Delaware
general partnership, originally formed in 1927 as a corporation. We are owned 42
percent indirectly through a wholly owned subsidiary of El Paso Corporation (El
Paso) and 58 percent by EPPP CIG GP Holdings, L.L.C., a subsidiary of El Paso
Pipeline Partners, L.P. (EPB), a master limited partnership of El Paso. EPB
was formed in November 2007 at which time El Paso contributed 10 percent of its
interest in us to EPB. In September 2008, EPB acquired an additional 30 percent
ownership interest in us and in July 2009, EPB acquired an additional 18 percent
ownership interest in us. Our primary business consists of the
interstate transportation, storage and processing of natural gas. We
conduct our business activities through our natural gas pipeline system, storage
facilities, a processing plant and our 50 percent ownership interest in WYCO
Development LLC (WYCO) which is a joint venture with an affiliate of Public
Service Company of Colorado (PSCo).
In November 2007,
in conjunction with the formation of EPB, we distributed 100 percent of Wyoming
Interstate Company, Ltd. (WIC) to EPB 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:
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providing
outstanding customer service;
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executing
successfully on time and on budget for our committed expansion
projects;
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developing
new growth projects in our market and supply
areas;
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maintaining
the integrity and ensuring the safety of our pipeline system and other
assets;
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successfully
recontracting expiring contracts for transportation capacity;
and
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focusing on
efficiency and synergies across our
system.
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Pipeline System. Our pipeline
system consists of approximately 4,200 miles of pipeline with a design capacity
of approximately 3,750 MMcf/d. During 2009, 2008 and 2007, average throughput
was 2,299 BBtu/d, 2,225 BBtu/d and 2,339 BBtu/d. This system extends from
production areas in the U.S. Rocky Mountains and the Anadarko Basin directly to
customers in Colorado and Wyoming and indirectly to the midwest, southwest,
California and the Pacific northwest.
Storage and Processing Facilities.
Along our pipeline system, we own interests in five storage fields in
Colorado and Kansas with approximately 35 Bcf of underground working natural gas
storage capacity, including Bcf of storage capacity from Totem Gas Storage
owned by WYCO which is further discussed below. In addition, we have a
processing plant located in Wyoming.
WYCO. We own a 50 percent
interest in WYCO, a joint venture with an affiliate of PSCo. WYCO
owns Totem Gas Storage and the High Plains pipeline, which were placed in
service in June 2009 and November 2008, respectively and are 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 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. The Totem Gas Storage facility consists of a natural gas
storage field that services and interconnects with the High Plains pipeline. The
Totem Gas Storage field has 6 Bcf of working natural gas storage capacity with a
maximum withdrawal rate of 200 MMcf/d and a maximum injection rate of 100
MMcf/d. All of the storage capacity of this new storage field is fully
contracted with PSCo pursuant to a firm contract through 2040. WYCO
also owns a state regulated intrastate gas pipeline that extends from the
Cheyenne Hub in northeast Colorado to PSCo’s Fort St. Vrain’s electric
generation plant, which we do not operate, and a compressor station in Wyoming
operated by an affiliate.
Markets
and Competition
Our customers
consist of natural gas distribution and industrial companies, electric
generation companies, natural gas producers, other natural gas pipelines and
natural gas marketing and trading companies. We provide transportation and
storage services in both our natural gas supply and market areas. Our
pipeline system connects with multiple pipelines that provide our customers with
access to diverse sources of supply, including supply from unconventional
sources, and various natural gas markets. The natural gas industry is
undergoing a major shift in supply sources. Production from
conventional sources is declining while production from unconventional sources,
such as shale, tight sands, and coal bed methane, is rapidly
increasing. This shift will change the supply patterns and flows of
pipelines. The impact will vary among pipelines according to the
proximity of the new supply sources.
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, increased natural gas prices 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 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.
Growth
of the natural gas market has been adversely affected by the current economic
slowdown in the U.S. and global economies. The decline in economic activity
reduced industrial demand for natural gas and electricity, which affected
natural gas demand both directly in end-use markets and indirectly through lower
power generation demand for natural gas. We expect the demand and growth for
natural gas to return as the economy recovers. Natural gas has a
favorable competitive position as an electric generation fuel because it is a
clean and abundant fuel with lower capital requirements compared with other
alternatives. The lower demand and the credit restrictions on investments in the
recent past may 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 or in our contracts. 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.
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.
The following table
details our customer and contract information related to our pipeline system as
of December 31, 2009. Firm customers reserve capacity on our
pipeline system and storage facilities and are obligated to pay a monthly
reservation or demand charge, regardless of the amount of natural gas they
transport or store, for the term of their contracts. Interruptible customers are
customers without reserved capacity that pay usage charges based on the volume
of gas they transport, store, inject or withdraw.
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Customer Information
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Contract Information
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Approximately
100 firm and interruptible customers.
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Approximately
170 firm transportation contracts. Weighted average remaining contract
term of approximately eight years.
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Major
Customers:
PSCo
(1,787
BBtu/d)
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Expires in
2010 - 2029.
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Williams Gas
Marketing, Inc.
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(498
BBtu/d)
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Expires in
2010 - 2014.
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Anadarko
Petroleum Corporation
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(280
BBtu/d)
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Expires in
2011 - 2015.
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Regulatory
Environment
Our interstate
natural gas transmission system and storage operations are regulated by the FERC
under the Natural Gas Act of 1938, the Natural Gas Policy Act of 1978 and the
Energy Policy Act of 2005. We operate under a tariff approved by the FERC that
establishes rates, cost recovery mechanisms and other terms and conditions of
service to our customers. Generally, the FERC’s authority extends
to:
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rates and
charges for natural gas transportation and storage and related
services;
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certification
and construction of new facilities;
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extension or
abandonment of services and
facilities;
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maintenance
of accounts and records;
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relationships
between pipelines and certain
affiliates;
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terms and
conditions of service;
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depreciation
and amortization policies;
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acquisition
and disposition of facilities; and
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initiation
and discontinuation of services.
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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. 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.
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 volumes of natural gas and NGL we are able to transport and store
depends on the actions of third parties and are beyond our control. Such actions
include factors that impact our customers’ demand and producers’ supply,
including factors that negatively impact our customers’ need for natural gas
from us, as well as the continued availability of natural gas production and
reserves connected to our pipeline system. 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:
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service area
competition;
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price
competition;
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expiration or
turn back of significant contracts;
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changes in
regulation and actions of regulatory
bodies;
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weather
conditions that impact natural gas throughput and storage
levels;
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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;
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drilling
activity and decreased availability of conventional gas supply sources and
the availability and timing of other natural gas supply
sources;
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continued
development of additional sources of gas supply that can be
accessed;
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decreased
natural gas demand due to various factors, including economic recession
(as further discussed below), availability of alternate energy sources and
increases in prices;
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legislative,
regulatory or judicial actions, such as mandatory renewable portfolio
standards and greenhouse gas (GHG) 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 energy and/or
(iii) changes in the demand for less carbon intensive energy
sources;
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availability
and cost to fund ongoing maintenance and growth projects, especially in
periods of prolonged economic
decline;
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opposition to
energy infrastructure development, especially in environmentally sensitive
areas;
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adverse
general economic conditions including prolonged recessionary periods that
might negatively impact natural gas demand and the capital
markets;
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our ability
to achieve targeted annual operating and administrative expenses primarily
by reducing internal costs and improving efficiencies from leveraging a
consolidated supply chain organization;
and
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unfavorable
movements in natural gas prices in certain supply and demand
areas.
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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 as discussed in more detail above. In addition, changes in
state regulation of local distribution companies, may cause us to negotiate
short-term contracts or turn back our capacity when our contracts
expire.
For 2009, our
revenues with PSCo represented approximately 40 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. In addition, in certain situations we may
assume certain additional credit risks for competitive reasons or
otherwise. If our existing or future customers fail to pay and/or
perform 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.
A
portion of our transportation services are provided pursuant to long-term,
fixed-price “negotiated rate” contracts that are not subject to adjustment, even
if our cost to perform such services exceeds the revenues received from such
contracts, and, as a result, our costs could exceed our revenues received under
such contracts.
It is possible that
costs to perform services under “negotiated rate” contracts will exceed the
negotiated rates. Under FERC policy, a regulated service provider and a customer
may mutually agree to sign a contract for service at a “negotiated rate” which
may be above or below the FERC regulated “recourse rate” for that service, and
that contract must be filed and accepted by FERC. These “negotiated rate”
contracts are not generally subject to adjustment for increased costs which
could be produced by inflation, cost of capital, taxes or other factors relating
to the specific facilities being used to perform the services. Any shortfall of
revenue, representing the difference between “recourse rates” (if higher) and
negotiated rates, under current FERC policy is generally not recoverable from
other shippers.
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 natural gas 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 transportation and storage through our
system.
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 our tariff or
applicable contract terms. We revalue our natural gas imbalances and other gas
owed to or from shippers to an index price and periodically settle these
obligations in cash pursuant to our tariff, regulatory approval or each
balancing contract. Currently, our tariff provides that the difference between
the quantity of fuel retained and fuel used in operations will be
flowed-through or charged to shippers. Our tariff also 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. Consequently, a significant prolonged downturn 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:
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regional,
domestic and international supply and demand, including changes in supply
and demand due to general economic conditions and
weather;
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availability
and adequacy of gathering, processing and transportation
facilities;
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energy
legislation and regulation, including potential changes associated with
GHG emissions and renewable portfolio
standards;
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federal and
state taxes, if any, on the sale or transportation and storage of natural
gas and NGL;
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the price and
availability of supplies of alternative energy sources;
and
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the level of
imports, including the potential impact of political unrest among
countries producing oil and LNG, as well as the ability of certain foreign
countries to maintain natural gas and oil prices, production and export
controls.
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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.
We periodically
file with the FERC to adjust the rates charged to our customers. In
establishing those rates, 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. Depending on the
specific risks faced by us and the companies included in the proxy group, the
FERC may establish rates that are not acceptable to us and have a negative
impact on our cash flows, profitability and results of operations. In
addition, pursuant to laws and regulations, our existing rates may be challenged
by complaint. The FERC commenced several complaint proceedings in
2009 against unaffiliated pipeline systems to reduce the rates they were
charging their customers. There is a risk that the FERC or our
customers could file similar complaints on our pipeline system and that a
successful complaint against our rates could have an adverse impact on our cash
flows and results of operations.
In addition, 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.
Increased
regulatory requirements relating to the integrity of our pipeline requires
additional spending in order to maintain compliance with the FERC’s
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;
|
|
|
•
|
forecasting
cash flow timing to implement proposed pollution control and cleanup
costs;
|
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|
•
|
receiving
regulatory approval for remediation
programs;
|
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|
•
|
quantifying
liability under environmental laws that may impose joint and several
liability on potentially responsible parties and managing allocation
responsibilities;
|
|
|
•
|
evaluating
and understanding environmental laws and regulations, including their
interpretation and enforcement;
|
|
|
•
|
interpretating whether
various maintenance activities performed in the past and currently being
performed required pre-construction permits pursuant to the Clean Air Act;
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, emission standards with
regard to our reciprocating internal combustion engines on our pipeline system,
GHG reporting and potential mandatory GHG emissions reductions. Future
environmental compliance costs relating to GHGs associated with our operations
are not yet clear. For a further discussion on GHGs, see Part II, Item 7,
Management’s Discussion and Analysis of Financial Condition and Results of
Operations, Commitments and Contingencies.
Although it is
uncertain what impact 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 or pay taxes related to our GHG and other emissions and (v)
administer and manage an emissions program for GHG and other emissions. Changes
in regulations, including adopting new standards for emission controls from
certain of our facilities, could also result in delays in obtaining required
permits to construct or operate our facilities. While we may be able
to include some or all of the costs associated with our environmental
liabilities and environmental compliance in the rates charged by our pipeline
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 failures, 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. In addition, although the potential
effects of climate change on our operations (such as flooding, etc.) are
uncertain at this time, changes in climate patterns as a result of global
emissions of GHG could have a negative impact on our operations in the
future.
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. There is
also the risk that our coverages will change over time in light of increased
premiums or changes in the terms of the insurance coverages that could result in
our decision to either terminate certain coverages, increase our deductibles or
decrease our maximum recoveries. 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.
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:
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•
|
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,
including the potential impact of delays and increased costs caused by
certain environmental and landowner groups with interests along the route
of our pipeline;
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•
|
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;
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•
|
the
availability of skilled labor, equipment, and materials to complete
expansion projects;
|
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•
|
potential
changes in federal, state and local statutes, regulations and orders, such
as environmental requirements, including climate change requirements, that
delay or prevent a project from proceeding or increase the anticipated
cost of the project;
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•
|
impediments
on our ability to acquire rights-of-way or land rights or to commence and
complete construction on a timely basis or on terms that are acceptable to
us;
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•
|
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, delays in
construction or other factors beyond our control, that we may not be able
to recover from our customers which may be
material;
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•
|
the lack of
future growth in natural gas supply and/or demand;
and
|
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•
|
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 we 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, and other third-party competitors 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, EPB, El Paso,
and its subsidiaries are subject to the risks arising from adverse changes in
general domestic economic conditions including recession or economic slowdown.
The global economy is experiencing a recession and the financial markets have
experienced extreme volatility and instability. In response, over the last year,
El Paso announced certain actions 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.
If we, EPB or
El Paso experience prolonged periods of recession or slowed economic growth in
the U.S., 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, EPB’s, or El Paso’s access to capital
could 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 risks.
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:
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•
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our credit
ratings;
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•
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the
structured and commercial financial
markets;
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•
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market
perceptions of us or the natural gas and energy industry;
and
|
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•
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market prices
for hydrocarbon products.
|
Risks
Related to Our Affiliation with El Paso and EPB
El Paso and EPB
file reports, proxy statements and other information with the SEC under the
Securities Exchange Act of 1934, as amended. Each prospective investor should
consider this information and the matters disclosed therein in addition to the
matters described in this report. Such information is not included herein or
incorporated by reference into this report.
We are a majority
owned subsidiary of EPB and El Paso.
As a majority owned
subsidiary of EPB and El Paso, subject to limitations in our indentures, EPB and
El Paso have substantial control over:
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•
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decisions on
our financing and capital raising
activities;
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•
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mergers or
other business combinations;
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•
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our
acquisitions or dispositions of assets;
and
|
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•
|
our
participation in EPB’s cash management
program.
|
EPB and El Paso may
exercise such control in their interests and not necessarily in the interests of
us or the holders of our long-term debt.
Our business
requires the retention and recruitment of a skilled workforce and the loss of
employees could result in the failure to implement our business plan.
Our business
requires the retention and recruitment of a skilled workforce. If El Paso is
unable to retain and recruit employees such as engineers and other technical
personnel, our business could be negatively impacted.
Our relationship
with El Paso and EPB and their financial condition subjects us to potential risks
that are beyond our control.
Due to our
relationship with El Paso and EPB, adverse developments or announcements
concerning them or their other subsidiaries could adversely affect our financial
condition, even if we have not suffered any similar development. 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.
EPB provides cash
management service and El Paso provides other corporate services for us. We are
currently required to make distributions of available cash as defined in our
partnership agreement on a quarterly basis to our partners. In addition, we
conduct commercial transactions with some of our affiliates. If EPB, El Paso or
such affiliates are unable to meet their respective liquidity needs, we may not
be able to access cash under the cash management program, or our affiliates may
not be able to pay their obligations to us. However, we might still be required
to satisfy any affiliated payables we have established. Our inability to recover
any affiliated receivables owed to us could adversely affect our financial
position and cash flows. For a further discussion of these matters, see Part II,
Item 8, Financial Statements and Supplementary Data, Note 11.
Our relationship
with El Paso and EPB subjects us to potential conflicts of interest and they may
favor their interests to the detriment of us.
Although EPB has
majority control of most decisions affecting our business, there are certain
decisions that require the approval of both El Paso and EPB, including material
regulatory filings, any significant sale of our assets, mergers and certain
changes in affiliated service agreements. Conflicts of interest or disagreements
could arise between El Paso and EPB with regard to such matters requiring
unanimous approval, which could negatively impact our future
operations.
We have not
included a response to this item since no response is required under Item 1B of
Form 10-K.
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.
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 executed a Consent Decree with the DOJ and have paid a total of $1.02
million to settle all of these Title V and PSD issues at the Natural Buttes
Compressor Station. In addition, as required by the Consent Decree,
ambient air monitoring at the Uintah Basin commenced on January 1, 2010 for a
period of two years. In November 2009, we sold our Natural Buttes Compressor
Station and gas processing plant to a third party for $9 million.
None.
All of our
partnership interests are held by El Paso and EPB and, accordingly, are not
publicly traded. Prior to converting into a general partnership effective
November 1, 2007, all of our common stock was held by El Paso.
We are required to
make distributions to our partners of available cash as defined in our
partnership agreement on a quarterly basis from legally available funds that
have been approved for payment by our Management Committee. We made cash
distributions to our partners of approximately $144 million in 2009 and
approximately $109 million in 2008. No dividends or cash distributions were
declared or paid in 2007. Additionally, in January 2010, we made a cash
distribution of approximately $44 million to our partners.
The following
selected historical financial data is derived from our audited consolidated
financial statements and is not necessarily indicative of results to be expected
in the future. The selected financial data should be read together with Item 7,
Management’s Discussion and Analysis and Financial Condition and Results of
Operations and Item 8, Financial Statements and Supplementary Data included in
this Report on Form 10-K.
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As of or for the Year Ended December
31,
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|||||||||||||||||||
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|
2009
|
2008
|
2007
|
2006
|
2005
|
|||||||||||||||
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(In
millions)
|
||||||||||||||||||||
|
Operating
Results Data:
|
||||||||||||||||||||
|
Operating
revenues
|
$ | 383 | $ | 323 | $ | 317 | $ | 305 | $ | 302 | ||||||||||
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Operating
income
|
205 | 153 | 145 | 143 | 109 | |||||||||||||||
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Income from
continuing operations
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157 | 149 | 107 | 87 | 68 | |||||||||||||||
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Financial
Position Data:
|
||||||||||||||||||||
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Total
assets
|
$ | 1,569 | $ | 1,543 | $ | 1,769 | $ | 2,292 | $ | 2,121 | ||||||||||
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Long-term
debt and other financing obligations, less current
maturities
|
646 | 580 | 575 | 600 | 700 | |||||||||||||||
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Partners’
capital/stockholder’s equity
|
796 | 783 | 1,043 | 1,149 | 1,009 | |||||||||||||||
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 Pipeline Partners, L.P. (EPB), we
distributed 100 percent of Wyoming Interstate Company, Ltd. (WIC) to EPB and
certain other assets to El Paso Corporation (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.
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Type
|
Description
|
Percent
of Total
Revenues in 2009(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.
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91
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Usage and
Other
|
Usage
revenues are from both firm customers and interruptible customers (those
without reserved capacity) that pay usage charges based on the volume of
gas actually transported, stored, injected or withdrawn. We also earn
revenue from the processing and sale of natural gas liquids and other
miscellaneous sources.
|
9
|
____________
|
(1)
|
Excludes
liquids transportation revenue, amounts associated with retained fuel and
in the case of CIG, liquids revenue associated with our
processing plants.
|
The Federal Energy
Regulatory Commission (FERC) regulates the rates we can charge our customers.
These rates are generally a function of the cost of providing services to our
customers, including a reasonable return on our invested capital. Because of our
regulated nature and the high percentage of our revenues attributable to
reservation charges, our revenues have historically been relatively stable.
However, our financial results can be subject to volatility due to factors such
as changes in natural gas prices, changes in supply and demand, regulatory
actions, competition, declines in the creditworthiness of our customers and
weather. During 2008, we recorded cost and revenue tracker adjustments
associated with the implementation of fuel and related gas cost recovery
mechanisms, which the FERC approved subject to the outcome of technical
conferences. The implementation of these mechanisms was protested by a limited
number of shippers. On July 31, 2009, the FERC issued an order to us directing
us to remove the cost and revenue components from our fuel recovery mechanism.
Due to this order, our future earnings may be impacted by both positive and
negative fluctuations in gas prices related to fuel imbalance revaluations, our
settlement, and other gas balance related items. We continue to explore
options to minimize the price volatility associated with these operational
pipeline activities. Our tariff continues to provide that the
difference between the quantity of fuel retained and fuel used in operations and
lost and unaccounted for will be flowed-through or charged to shippers.
These fuel trackers remove the impact of over or under collecting fuel and lost
and unaccounted for from our operational gas costs. We are required to file a
new general rate case with the FERC to be effective no later than October
2011.
We continue to
manage the process of renewing expiring contracts to limit the risk of
significant impacts on our revenues. Our ability to extend our existing customer
contracts or remarket expiring contracted capacity is dependent on competitive
alternatives, the regulatory environment at the federal, state and local levels
and the market supply and demand factors at the relevant dates these contracts
are extended or expire. The duration of new or renegotiated contracts will be
affected by current prices, competitive conditions and judgments concerning
future market trends and volatility. Subject to regulatory requirements, we
attempt to recontract or remarket our capacity at the maximum rates allowed
under our tariffs, although at times, we enter into firm transportation
contracts at amounts that are less than these maximum allowable rates to remain
competitive. We refer to the difference between the maximum rates
allowed under our tariff and the contractual rate we charge as
discounts.
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, 2009. Below are the contract
expiration portfolio and the associated revenue expirations for our firm
transportation contracts as of December 31, 2009, including those with terms
beginning in 2010 or later.
|
|
Contracted
Capacity
|
Percent
of Total
Contracted Capacity
|
Reservation Revenue
|
Percent
of Total
Reservation Revenue
|
||||||||||||
|
(BBtu/d)
|
(In
millions)
|
|||||||||||||||
|
2010
|
250 | 6 | $ | 7 | 2 | |||||||||||
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2011
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323 | 8 | 20 | 6 | ||||||||||||
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2012
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590 | 14 | 47 | 14 | ||||||||||||
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2013
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1,063 | 26 | 79 | 24 | ||||||||||||
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2014
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263 | 6 | 28 | 9 | ||||||||||||
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2015 and
beyond
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1,697 | 40 | 146 | 45 | ||||||||||||
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Total
|
4,186 | 100 | $ | 327 | 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 Development LLC
(WYCO), a joint venture with an affiliate of PSCo in which we have a 50 percent
ownership interest. The High Plains pipeline consists of a 164-mile interstate
gas pipeline extending from the Cheyenne Hub in northeast Colorado to PSCo’s
Fort St. Vrain electric generation plant and other points of interconnection
with PSCo’s system. The system added approximately 900 MMcf/d of overall
transportation capacity to our system. The increased capacity is fully
contracted with PSCo and Coral Energy Resources pursuant to firm contracts
through 2029 and 2019.
In June 2009, the
Totem Gas Storage project was placed in service. We operate this
storage facility, which is also owned by WYCO. This project consists of a
natural gas storage field that services and interconnects with the High Plains
pipeline. The Totem Gas Storage field has 6 Bcf of working natural gas
storage capacity with a maximum withdrawal rate of 200 MMcf/d and a maximum
injection rate of 100 MMcf/d. All of the storage capacity of this new storage
field is fully contracted with PSCo pursuant to a firm contract through
2040.
Growth Projects. We expect to
spend approximately $110 million on contracted organic growth projects through
2014. Of this amount, approximately $86 million will be spent in 2010 primarily
on our Raton 2010 expansion project. The Raton 2010 expansion project
consists 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 December 2010. We
filed an application for certificate authorization with the FERC in September
2009.
In addition to our
contracted organic growth projects, we have other projects that are in various
phases of commercial development. Many of the potential projects involve
expansion capacity to serve increased natural gas-fired generation loads.
For example, along the Front Range of our system, utilities have various
projects under development that involve constructing new natural gas-fired
generation in part to provide backup capacity required when renewable generation
is not available during certain daily or seasonal periods. Most of these
potential expansion projects would have in-service dates for 2014 and beyond. If
we are successful in contracting for these new loads the capital requirements of
such projects could be substantial and would be incremental to our contracted
organic growth projects. Although we pursue the development of these potential
projects from time to time, there can be no assurance that we will be successful
in negotiating the definitive binding contracts necessary for such projects to
be included in our contracted organic growth projects.
We believe that
cash flows from operating activities, combined with amounts available to us
under EPB’s cash management program, the demand notes receivable from El Paso
and capital contributions from our partners, will be adequate to meet our
capital requirements and our existing operating needs.
Results
of Operations
Our management uses
earnings before interest expense and income taxes (EBIT) as a measure to assess
the operating results and effectiveness of our business, which consist of both
consolidated operations and an investment in an unconsolidated affiliate. We
believe EBIT is useful to investors to provide them with the same measure used
by El Paso to evaluate our performance. We define EBIT as net income adjusted
for items such as (i) interest and debt expense, (ii) affiliated
interest income and (iii) income taxes. 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 measures used by
other companies. Additionally, EBIT should be considered in conjunction with net
income, income before income taxes and other performance measures such as
operating income or operating cash flows. Below is a reconciliation of our EBIT
to our net income, our throughput volumes and an analysis and discussion of our
results in 2009 compared with 2008 and 2008 compared with 2007.
|
Operating
Results:
|
2009
|
2008
|
2007
|
|||||||||
|
(In
millions, except for volumes)
|
||||||||||||
|
Operating
revenues
|
$ | 383 | $ | 323 | $ | 317 | ||||||
|
Operating
expenses
|
(178 | ) | (170 | ) | (172 | ) | ||||||
|
Operating
income
|
205 | 153 | 145 | |||||||||
|
Other income,
net
|
4 | 11 | 5 | |||||||||
|
EBIT(1)
|
209 | 164 | 150 | |||||||||
|
Interest and
debt expense
|
(54 | ) | (38 | ) | (49 | ) | ||||||
|
Affiliated
interest income, net
|
2 | 23 | 50 | |||||||||
|
Income tax
expense
|
— | — | (44 | ) | ||||||||
|
Income from
continuing operations
|
157 | 149 | 107 | |||||||||
|
Discontinued
operations, net of income taxes
|
— | — | 42 | |||||||||
|
Net
income
|
$ | 157 | $ | 149 | $ | 149 | ||||||
|
Throughput
volumes (BBtu/d)
|
2,299 | 2,225 | 2,339 | |||||||||
____________
|
(1)
|
2007
EBIT represents EBIT from continuing
operations
|
EBIT Analysis:
|
|
2009 to 2008
|
2008 to 2007
|
||||||||||||||||||||||||||||||
|
|
Revenue
|
Expense
|
Other
|
Total
|
Revenue
|
Expense
|
Other
|
Total
|
||||||||||||||||||||||||
|
Favorable/(Unfavorable)
|
||||||||||||||||||||||||||||||||
|
(In
millions)
|
||||||||||||||||||||||||||||||||
|
Expansions
|
$ | 67 | $ | (18 | ) | $ | (3 | ) | $ | 46 | $ | 5 | $ | (1 | ) | $ | 5 | $ | 9 | |||||||||||||
|
Transportation
revenues
|
(5 | ) | — | — | (5 | ) | 2 | — | — | 2 | ||||||||||||||||||||||
|
Gain on sale
of long-lived asset
|
— | 8 | — | 8 | — | — | — | — | ||||||||||||||||||||||||
|
Operational
gas, revaluations and processing revenues
|
(2 | ) | 3 | — | 1 | (2 | ) | 6 | — | 4 | ||||||||||||||||||||||
|
Operating and
general and administrative expenses
|
— | (1 | ) | — | (1 | ) | — | (4 | ) | — | (4 | ) | ||||||||||||||||||||
|
Other(1)
|
— | — | (4 | ) | (4 | ) | 1 | 1 | 1 | 3 | ||||||||||||||||||||||
|
Total impact
on EBIT
|
$ | 60 | $ | (8 | ) | $ | (7 | ) | $ | 45 | $ | 6 | $ | 2 | $ | 6 | $ | 14 | ||||||||||||||
____________
|
(1)
|
Consists
of individually insignificant
items.
|
Expansions. Our EBIT
increased during the years ended December 31, 2009 and 2008 due to expansion
projects placed into service, as follows:
|
|
2009 to 2008
|
2008 to 2007
|
||||||
|
(In
millions)
|
||||||||
|
High Plains
Pipeline
|
$ | 28 | $ | 8 | ||||
|
Totem Gas
Storage
|
14 | 1 | ||||||
|
Other
|
4 | — | ||||||
|
Total impact
on EBIT
|
$ | 46 | $ | 9 | ||||
Transportation Revenues.
During the year
ended December 31, 2009, transportation revenue decreased primarily due to lower
usage revenues when compared to 2008. During the year ended December
31, 2008, increased demand for our off-system capacity resulted in higher
reservation revenues as compared to 2007, partially offset by lower
interruptible usage revenues in 2008.
Gain
on Sale of Long-Lived Asset. In the fourth quarter of 2009, we
recorded a gain of $8 million related to the sale of the Natural Buttes
compressor station and gas processing plant. For a further discussion
of the sale of Natural Buttes, see Item 8, Financial Statements and
Supplementary Data, Note 2.
Operational
Gas, Revaluations and Processing Revenues. Our EBIT for operational gas,
revaluations, and processing revenues increased during the year ended December
31, 2009 compared with the same periods in 2008. We experienced favorable prices
for gas consumed in processing natural gas liquids in 2009; however, this
favorable impact was largely offset by lower processing revenues for the year
ended December 31, 2009 primarily due to an unfavorable price change for natural
gas liquids in 2009 and regulatory-related cost tracking compared with the same
period in 2008.
Our operating
expenses for the years ended December 31, 2009 and 2008 were also impacted by
developments associated with our fuel and related gas cost recovery mechanism.
During the year ended December 31, 2008, we recorded cost and revenue
tracker adjustments associated with the implementation of fuel and related gas
cost recovery mechanisms, which the FERC approved subject to the outcome of
technical conferences. The implementation of these mechanisms was
protested by a limited number of shippers. On July 31, 2009, the FERC
issued an order to us directing us to remove the cost and revenue components
from our fuel recovery mechanism. Due to this order, our future earnings may be
impacted by both positive and negative fluctuations in gas prices related to
fuel imbalance revaluations, our settlement, and other gas balance related
items. We continue to explore options to minimize the price
volatility associated with these operational pipeline activities. Our tariff
continues to provide that the difference between the quantity of fuel retained
and fuel used in operations and lost and unaccounted for will be flowed-through
or charged to shippers. For a further discussion of our fuel recovery
mechanism, see Item 8, Financial Statements and Supplementary Data, Note
7.
Operating
and General and Administrative Expenses. During the year ended December
31, 2009, our operating and general and administrative expenses increased
primarily as a result of higher benefit costs in 2009 as compared with 2008
partially offset by lower field repair and maintenance
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.
Interest
and Debt Expense
Interest and debt
expense for the year ended December 31, 2009 was $16 million higher than in 2008
primarily related to the financing obligations to WYCO upon completion of High
Plains Pipeline and Totem Gas Storage (see Item 8, Financial Statements and
Supplementary Data, Note 6), partially offset by a lower average outstanding
long-term debt balance resulting from the repurchase of $100 million of our
senior notes in 2008. 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.
Affiliated
Interest Income, Net
Affiliated interest
income, net for the year ended December 31, 2009 was $21 million lower than in
2008 and $27 million lower for the year ended December 31, 2008 as compared with
2007 due to lower average advances due from El Paso under its cash management
program and lower short-term interest rates. In conjunction with EPB’s
acquisition of an additional interest in us in 2009, we terminated our
participation in El Paso’s cash management program. We converted our
note receivable with El Paso under its cash management program into a demand
note receivable from El Paso. The following table shows the average advances and
the average short-term interest rates for the years ended December
31:
|
2009
|
2008
|
2007
|
||||||||||
|
(In
millions, except for rates)
|
||||||||||||
|
Average
advance
|
$ | 158 | $ | 534 | $ | 819 | ||||||
|
Average
short-term interest rate
|
1.2 | % | 4.4 | % | 6.2 | % | ||||||
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.
Liquidity
and Capital Resources
Liquidity
Overview. Our primary sources of liquidity are cash flows from
operating activities, amounts available under EPB’s cash management program, the
demand note receivable from El Paso and capital contributions from our partners.
In conjunction with EPB’s acquisition of an additional interest in us during
July 2009, we terminated our participation in El Paso’s cash management program
and began to participate in EPB’s cash management program. As a result, we
converted our note receivable with El Paso under its cash management program
into a demand note receivable. At December 31, 2009, we had approximately $73
million remaining under this note classified as current based on the net amount
we anticipate using in the next twelve months considering available cash sources
and needs. In addition, at December 31, 2009, we had a note receivable from EPB
under its cash management program of approximately $61 million of which
approximately $28 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 Supplemental Data, Note 11 for a
further discussion of EPB’s and El Paso’s cash management programs. Our primary
uses of cash are for working capital, capital expenditures and for required
distributions to our partners.
Although recent
financial market conditions have shown signs of improvement, continued
volatility in 2010 and beyond in the financial markets could impact our
longer-term access to capital for future growth projects as well as the cost of
such capital. Additionally, although the impacts are difficult to quantify at
this point, a prolonged recovery of the global economy could have adverse
impacts on natural gas consumption and demand. However, we believe our exposure
to changes in natural gas consumption and demand is largely mitigated by a
revenue base that is significantly comprised of long-term contracts that are
based on firm demand charges and are less affected by a potential reduction in
the actual usage or consumption of natural gas.
We believe we have
adequate liquidity available to us to meet our capital requirements and our
existing operating needs through cash flow from operating activities, amounts
available under EPB’s cash management program, the demand note receivable from
El Paso and capital contributions from our partners. As of December 31, 2009,
EPB had approximately $215 million of capacity available to it under its $750
million revolving credit facility. In addition, as of December 31, 2009, El
Paso had approximately $1.8 billion of available liquidity, including
approximately $1.3 billion of capacity available to it under various committed
credit facilities. While we do not anticipate a need to directly access the
financial markets in 2010 for any of our operating activities or expansion
capital needs based on liquidity available to us, market conditions may impact
our ability to act opportunistically.
For further detail
on our risk factors including potential adverse general economic conditions
including our ability to access financial markets which could impact our
operations and liquidity, see Part I, Item 1A, Risk Factors.
2009 Cash Flow Activities.
Our cash flows for the year ended December 31, 2009 are summarized as follows
(In millions):
|
Cash
Flow from Operations
|
||||
|
Net income
|
$ | 157 | ||
|
Non-cash income
adjustments
|
46 | |||
|
Change in other assets and
liabilities
|
(7 | ) | ||
|
Total cash
flow from operations
|
196 | |||
|
Cash
Inflows
|
||||
|
Investing
activities
|
||||
|
Net change in notes receivable from
affiliates
|
45 | |||
|
Proceeds from sale of assets
|
10 | |||
|
Other
|
2 | |||
|
Total other cash inflows
|
57 | |||
|
Cash
Outflows
|
||||
|
Investing
activities
|
||||
|
Additions to
property, plant and equipment
|
103 | |||
|
Financing
activities
|
||||
|
Distributions to partners
|
144 | |||
|
Payments to
retire long term debt
|
4 | |||
| 148 | ||||
|
Total cash
outflows
|
251 | |||
|
Net change in
cash
|
$ | 2 | ||
During 2009, we
generated $196 million of operating cash flow. We utilize these
amounts to fund maintenance of our system as well as pay distributions to our
partners. During the year ended December 31, 2009, we paid cash distributions of
approximately $144 million to our partners. In addition, in January 2010 we paid
a cash distribution to our partners of approximately $44 million. Our
cash capital expenditures for the years ended December 31, 2009 and those
planned for 2010 are listed below:
|
|
2009
|
Expected 2010
|
||||||
|
(In
millions)
|
||||||||
|
Maintenance
|
$ | 25 | $ | 36 | ||||
|
Expansion(1)
|
78 | 101 | ||||||
|
Total
|
$ | 103 | $ | 137 | ||||
____________
(1) Amount
includes our share of costs related to our 50 percent joint investment in
WYCO.
Our expected 2010
expansion capital expenditures primarily relate to our Raton 2010 expansion
project. Our maintenance capital expenditures primarily relate to
maintaining and improving the integrity of our pipeline complying with
regulations and ensuring the safe and reliable delivery of natural gas to our
customers. While we expect to fund maintenance capital expenditures
through internally generated funds, we intend to fund our expansion capital
expenditures through the demand note receivable from El Paso, amounts
available under EPB’s cash management program and capital contributions
from 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 and storage 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, 2009, 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
|
$ | 4 | $ | 10 | $ | 10 | $ | 626 | $ | 650 | ||||||||||
|
Interest
|
59 | 116 | 113 | 561 | 849 | |||||||||||||||
|
Other
contractual liabilities
|
2 | 4 | 1 | 4 | 11 | |||||||||||||||
|
Operating
leases
|
2 | 4 | 5 | 1 | 12 | |||||||||||||||
|
Other
contractual commitments and purchase obligations:
|
||||||||||||||||||||
|
Transportation
and storage commitments
|
18 | 41 | 34 | 8 | 101 | |||||||||||||||
|
Other
commitments
|
30 | 4 | — | — | 34 | |||||||||||||||
|
Total
contractual obligations
|
$ | 115 | $ | 179 | $ | 163 | $ | 1,200 | $ | 1,657 | ||||||||||
Long-Term Financing Obligations
(Principal and Interest). Long-term financing obligations included in the
table above represent stated maturities. Interest payments are shown through the
stated maturity date of the related fixed rate obligations based on the
contractual interest rate. Included in these amounts are payments related to the
financing obligations for the construction of WYCO’s High Plains Pipeline and
Totem Gas Storage facility. We make monthly interest payments on these
obligations that are based on 50 percent of the operating results of the High
Plains Pipeline and Totem Gas Storage facility. For a further discussion of our
long-term financing obligations, see Item 8, Financial Statements and
Supplementary Data, Note 6.
Other Contractual Liabilities.
Included in this amount are environmental liabilities related to sites
that we own or have a contractual or legal obligation with a regulatory agency
or property owner upon which we perform remediation activities. These
liabilities are included in other current and non-current liabilities in our
balance sheet.
Operating Leases. For a
further discussion of these obligations, see Item 8, Financial Statements and
Supplementary Data, Note 7.
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 and Storage
Commitments. Included in these amounts are commitments for demand
charges for firm access to natural gas transportation and storage
capacity.
|
|
|
•
|
Other Commitments.
Included in these amounts are commitments for construction
contracts and purchase obligations. We exclude asset retirement
obligations and reserves for litigation and environmental remediation,
other than those disclosed above, as these liabilities are not
contractually fixed as to timing and amount. We have other
planned capital projects that are discretionary in nature, with no
substantial contractual capital commitments made in advance of the actual
expenditures.
|
Commitments
and Contingencies
For a further
discussion of our commitments and contingencies, see Item 8, Financial
Statements and Supplementary Data, Note 7, which is incorporated herein by
reference.
Climate Change and Energy
Legislation and Regulation. There are various legislative and regulatory
measures relating to climate change and energy policies that have been proposed
and, if enacted, will likely impact our business.
Climate Change Legislation and
Regulation. Measures to address climate change and greenhouse
gas (GHG) emissions are in various phases of discussions or implementation at
international, federal, regional and state levels. Over 50 countries, including
the U.S. have submitted formal pledges to cut or limit their emissions in
response to the United Nations-sponsored Copenhagen Accord. It is
reasonably likely that federal legislation requiring GHG controls will be
enacted within the next few years in the United States. Although it
is uncertain what legislation will ultimately be enacted, it is our belief that
cap-and-trade or other market-based legislation that sets a price on carbon
emissions will increase demand for natural gas, particularly in the power
sector. We believe this increased demand will occur due to
substantially less carbon emissions associated with the use of natural gas
compared with alternate fuel sources for power generation, including coal and
oil-fired power generation. However, the actual impact on demand will
depend on the legislative provisions that are ultimately adopted, including the
level of emission caps, allowances granted, offset programs established, cost of
emission credits and incentives provided to other fossil fuels and lower carbon
technologies like nuclear, carbon capture sequestration and renewable energy
sources.
It is also
reasonably likely that any federal legislation enacted would increase our cost
of environmental compliance by requiring us to install additional equipment to
reduce carbon emissions from our larger facilities as well as to potentially
purchase emission allowances. Based on 2008 operational data we
reported to the California Climate Action Registry (CCAR), our operations in the
United States emitted approximately 1.5 million tonnes of carbon dioxide
equivalent emissions during 2008. We believe that approximately 1.3 million
tonnes of the GHG emissions would be subject to regulations under the climate
change legislation that passed in the U.S. House of Representatives (the House)
in June 2009. Of these amounts that would be subject to regulation,
we believe that approximately 51 percent would be subject to the cap-and-trade
rules contained in the proposed legislation and the remainder would be subject
to performance standards. As proposed by the House, the portion of
our GHG emissions that would be subject to cap-and-trade rules could require us
to purchase allowances or offset credits and the portion of our GHG emissions
that would be subject to performance standards could require us to install
additional equipment or initiate new work practice standards to reduce emission
levels at many of our facilities. The costs of purchasing emission
allowances or offset credits and installing additional equipment or changing
work practices would likely be material. Increases in costs of our
suppliers to comply with such cap-and-trade rules and performance standards,
such as the electricity we purchase in our operations, could also be material
and would likely increase our cost of operations. Although we believe
that many of these costs should be recoverable in the rates we charge our
customers, recovery is still uncertain at this time. A climate change
bill was also voted upon favorably by the Senate Committee on Energy and Public
Works (the Committee) in November 2009 and has been ordered to be reported out
of the Committee. Any final bill passed out of the U.S. Senate will
likely see further substantial changes and we cannot yet predict the form it may
take, the timing of when any legislation will be enacted or implemented or how
it may impact our operations if ultimately enacted.
The Environmental
Protection Agency (EPA) finalized regulations to monitor and report GHG
emissions on an annual basis. The EPA also proposed new regulations to regulate
GHGs under the Clean Air Act, which the EPA has indicated could be finalized as
early as March 2010. The effective date and substantive requirements
of any EPA final rule is subject to interpretation and possible legal
challenges. In addition, it is uncertain whether federal legislation
might be enacted that either delays in the implementation of any climate change
regulations of the EPA or adopts a different statutory structure for regulating
GHGs than is provided for pursuant to the Clean Air Act. Therefore,
the potential impact on our operations remains uncertain.
In addition, in
March 2009, the EPA proposed a rule impacting emissions from reciprocating
internal combustion engines, which would require us to install emission controls
on our pipeline system. It is expected that the rule will be
finalized in August 2010. As proposed, engines subject to the regulations
would have to be in compliance by August 2013. Based upon that timeframe,
we would expect that we would commence incurring expenditures in late 2010, with
the majority of the work and expenditures incurred in 2011 and
2012. If the regulations are adopted as proposed, we would expect to incur
approximately $14 million in capital expenditures over the period from 2010 to
2013.
Legislative and
regulatory efforts are underway in various states and regions. These
rules once finalized may impose additional costs on our operations and
permitting our facilities, which could include costs to purchase offset credits
or emission allowances, to retrofit or install equipment or to change existing
work practice standards. In addition, various lawsuits have been
filed seeking to force further regulation of GHG emissions, as well as to
require specific companies to reduce GHG emissions from their operations.
Enactment of additional regulations by the federal or state governments, as well
as lawsuits, could result in delays and have negative impacts on our ability to
obtain permits and other regulatory approvals with regard to existing and new
facilities, could impact our costs of operations, as well as require us to
install new equipment to control emissions from our facilities, the costs of
which would likely be material.
Energy
Legislation. In conjunction with these climate change
proposals, there have been various federal and state legislative and regulatory
proposals that would create additional incentives to move to a less carbon
intensive “footprint”. These proposals would establish renewable
energy and efficiency standards at both the federal and state level,
some of which would require a material increase of renewable sources, such as
wind and solar power generation, over the next several decades. There
have also been proposals to increase the development of nuclear power and
commercialize carbon capture and sequestration especially as coal-fired
facilities. Other proposals would establish incentives for energy
efficiency and conservation. Although it is reasonably likely that
many of these proposals will be enacted over the next few years, we cannot
predict the form of any laws and regulations that might be enacted, the timing
of their implementation, or the precise impact on our operations or demand for
natural gas. However, such proposals if enacted could negatively
impact natural gas demand over the longer term.
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, see 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 in accordance with current Financial
Accounting Standards Board’s accounting standards on rate-regulated
operations. The
economic effects of regulation can result in a regulated company recording
assets for costs that have been or are expected to be approved for recovery from
customers or recording liabilities for amounts that are expected to be returned
to customers in the rate-setting process in a period different from the period
in which the amounts would be recorded by an unregulated enterprise.
Accordingly, we record assets and liabilities that result from the regulated
ratemaking process that would not be recorded under U.S. generally accepted
accounting principles for non-regulated entities. Management regularly assesses
whether regulatory assets are probable of future recovery or if regulatory
liabilities are probable of being refunded to our customers by considering
factors such as applicable regulatory changes and recent rate orders applicable
to other regulated entities. Based on this continual assessment, management
believes the existing regulatory assets are probable of recovery. We
periodically evaluate the applicability of accounting standards related to
regulated operations, and consider factors such as regulatory changes and the
impact of competition. If cost-based regulation ends or competition increases,
we may have to reduce certain of our asset balances to reflect a market basis
lower than cost and write-off the associated regulatory assets.
Accounting for Environmental
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,
2009, we had accrued approximately $11 million for environmental matters. Our
environmental estimates range from approximately $11 million to approximately
$35 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 ($3 million). Second, where the most
likely outcome cannot be estimated, a range of costs is established ($8 million
to $32 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, 2009, our postretirement benefit
plan was over funded by $9 million. Our postretirement benefit obligation and
net benefit costs are primarily based on actuarial calculations. We use various
assumptions in performing these calculations, including those related to the
return that we expect to earn on our plan assets, the estimated cost of health
care when benefits are provided under our plan and other factors. A significant
assumption we utilize is the discount rates used in calculating our benefit
obligation. We select our discount rate by matching the timing and amount of our
expected future benefit payments for our postretirement benefit obligation to
the average yields of various high-quality bonds with corresponding
maturities.
Actual results may
differ from the assumptions included in these calculations, and as a result, our
estimates associated with our postretirement benefits can be, and often are,
revised in the future. The income statement impact of the changes in the
assumptions on our related benefit obligation, along with changes to the plan
and other items, are deferred and recorded as either a regulatory asset or
liability. A one 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.
We are exposed to
the risk of changing interest rates. At December 31, 2009, we had a note
receivable from EPB of approximately $61 million with a variable interest rate
of 0.7%. In addition, at December 31, 2009, we had a note receivable
from El Paso of approximately $73 million with a variable interest rate of
1.5%. While we are exposed to changes in interest income based on
changes to the variable interest rate, the fair value of these notes receivable
approximates the carrying value due to the notes being due on demand and the
market-based nature of the interest rates.
The table below
shows the carrying value, the related weighted-average effective interest rates
on our long-term interest bearing financing obligations and the fair value of
these securities estimated based on quoted market prices for the same or similar
issues.
|
December 31, 2009
|
December 31, 2008
|
|||||||||||||||||||||||||||||||||||||||
|
|
Expected Fiscal Year of Maturity of Carrying
Amounts
|
Fair
|
Carrying
|
Fair
|
||||||||||||||||||||||||||||||||||||
|
2010
|
2011 | 2012 | 2013 | 2014 |
Thereafter
|
Total
|
Value |
Amounts
|
Value | |||||||||||||||||||||||||||||||
|
(In
millions, except for rates)
|
||||||||||||||||||||||||||||||||||||||||
|
Long-term
debt and other financing obligations(1),
including current portion — fixed
rate.
|
$ | 4 | $ | 5 | $ | 5 | $ | 5 | $ | 5 | $ | 626 | $ | 650 | $ | 695 | $ | 583 | $ | 502 | ||||||||||||||||||||
|
Average
interest rate
|
14.8 | % | 14.8 | % | 14.8 | % | 14.8 | % | 14.8 | % | 8.6 | % | ||||||||||||||||||||||||||||
____________
(1)
Our
other financing obligations include amounts due to WYCO related to High Plains
pipeline and Totem Gas Storage. See additional information in Note
6.
MANAGEMENT’S ANNUAL REPORT ON
INTERNAL CONTROL OVER FINANCIAL REPORTING
Our management is
responsible for establishing and maintaining adequate internal control over
financial reporting, as defined by the Securities and Exchange Commission (SEC)
rules adopted under the Securities Exchange Act of 1934, as amended. Our
internal control over financial reporting is designed to provide reasonable
assurance regarding the reliability of financial reporting and the preparation
of financial statements for external purposes in accordance with generally
accepted accounting principles. It consists of policies and procedures
that:
|
|
•
|
Pertain to
the maintenance of records that, in reasonable detail, accurately and
fairly reflect the transactions and dispositions of our
assets;
|
|
|
•
|
Provide
reasonable assurance that transactions are recorded as necessary to permit
preparation of the financial statements in accordance with generally
accepted accounting principles, and that our receipts and expenditures are
being made only in accordance with authorizations of our management and
directors; and
|
|
|
•
|
Provide
reasonable assurance regarding prevention or timely detection of
unauthorized acquisition, use or disposition of our assets that could have
a material effect on the financial
statements.
|
Under the
supervision and with the participation of management, including the President
and Chief Financial Officer, we made an assessment of the effectiveness of our
internal control over financial reporting as of December
31, 2009. In making this assessment, we used the criteria established in Internal Control — Integrated
Framework issued by the Committee of Sponsoring Organizations of the
Treadway Commission. Based on our evaluation, we concluded that our internal
control over financial reporting was effective as of December 31,
2009.
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, 2009 and 2008, 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, 2009. 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, 2009. 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, 2009 and 2008, and the consolidated results of its operations
and its cash flows for each of the three years in the period ended
December 31, 2009, 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 January 1, 2008,
the Company adopted the provisions of an accounting standard update related to
the measurement date and changed the measurement date of its postretirement
benefit plan.
/s/
Ernst & Young LLP
Houston,
Texas
February 26,
2010
COLORADO
INTERSTATE GAS COMPANY
CONSOLIDATED
STATEMENTS OF INCOME
(In
millions)
|
|
Year Ended December 31,
|
|||||||||||
|
|
2009
|
2008
|
2007
|
|||||||||
|
Operating
revenues
|
$ | 383 | $ | 323 | $ | 317 | ||||||
|
Operating
expenses
|
||||||||||||
|
Operation and
maintenance
|
121 | 120 | 126 | |||||||||
|
Depreciation
and amortization
|
38 | 33 | 31 | |||||||||
|
Taxes, other
than income taxes
|
19 | 17 | 15 | |||||||||
| 178 | 170 | 172 | ||||||||||
|
Operating
income
|
205 | 153 | 145 | |||||||||
|
Other income,
net
|
4 | 11 | 5 | |||||||||
|
Interest and
debt expense
|
(54 | ) | (38 | ) | (49 | ) | ||||||
|
Affiliated
interest income, net
|
2 | 23 | 50 | |||||||||
|
Income before
income taxes
|
157 | 149 | 151 | |||||||||
|
Income tax
expense
|
— | — | 44 | |||||||||
|
Income from
continuing operations
|
157 | 149 | 107 | |||||||||
|
Discontinued
operations, net of income taxes
|
— | — | 42 | |||||||||
|
Net
income
|
$ | 157 | $ | 149 | $ | 149 | ||||||
See accompanying
notes.
COLORADO
INTERSTATE GAS COMPANY
CONSOLIDATED
BALANCE SHEETS
(In
millions)
|
|
December 31,
|
|||||||
|
|
2009
|
2008
|
||||||
|
ASSETS
|
||||||||
|
Current
assets
|
||||||||
|
Cash and cash
equivalents
|
$ | 2 | $ | — | ||||
|
Accounts and
notes receivable
|
||||||||
|
Customer
|
— | 8 | ||||||
|
Affiliates
|
121 | 119 | ||||||
|
Other
|
1 | 1 | ||||||
|
Materials and
supplies
|
9 | 7 | ||||||
|
Regulatory
assets
|
1 | 18 | ||||||
|
Other
|
4 | 2 | ||||||
|
Total current
assets
|
138 | 155 | ||||||
|
Property,
plant and equipment, at cost
|
1,753 | 1,675 | ||||||
|
Less
accumulated depreciation and amortization
|
404 | 413 | ||||||
|
Total
property, plant and equipment, net
|
1,349 | 1,262 | ||||||
|
Other
assets
|
||||||||
|
Notes
receivable from affiliates
|
33 | 76 | ||||||
|
Other
|
49 | 50 | ||||||
| 82 | 126 | |||||||
|
Total
assets
|
$ | 1,569 | $ | 1,543 | ||||
|
LIABILITIES
AND PARTNERS’ CAPITAL
|
||||||||
|
Current
liabilities
|
||||||||
|
Accounts
payable
|
||||||||
|
Trade
|
$ | 5 | $ | 11 | ||||
|
Affiliates
|
23 | 10 | ||||||
|
Other
|
10 | 30 | ||||||
|
Taxes
payable
|
14 | 10 | ||||||
|
Regulatory
liabilities
|
13 | 29 | ||||||
|
Accrued
interest
|
4 | 7 | ||||||
|
Contractual
deposits
|
7 | 8 | ||||||
|
Other
|
12 | 9 | ||||||
|
Total current
liabilities
|
88 | 114 | ||||||
|
Long-term
debt and other financing obligations, less current
maturities
|
646 | 580 | ||||||
|
Other
liabilities
|
39 | 66 | ||||||
|
Commitments
and contingencies (Note 7)
|
||||||||
|
Partners’
capital
|
796 | 783 | ||||||
|
Total
liabilities and partners’ capital
|
$ | 1,569 | $ | 1,543 | ||||
See accompanying
notes.
COLORADO
INTERSTATE GAS COMPANY
CONSOLIDATED
STATEMENTS OF CASH FLOWS
(In
millions)
|
|
Year Ended December 31,
|
|||||||||||
|
|
2009
|
2008
|
2007
|
|||||||||
|
Cash flows
from operating activities
|
||||||||||||
|
Net
income
|
$ | 157 | $ | 149 | $ | 149 | ||||||
|
Less income
from discontinued operations, net of income taxes
|
— | — | 42 | |||||||||
|
Income from
continuing operations
|
157 | 149 | 107 | |||||||||
|
Adjustments
to reconcile net income to net cash from operating
activities
|
||||||||||||
|
Depreciation
and amortization
|
38 | 33 | 31 | |||||||||
|
Deferred
income tax expense
|
— | — | 8 | |||||||||
|
Other
non-cash income items
|
8 | 3 | 8 | |||||||||
|
Asset and
liability changes
|
||||||||||||
|
Accounts
receivable
|
4 | (3 | ) | 3 | ||||||||
|
Accounts
payable
|
4 | 1 | 6 | |||||||||
|
Taxes
payable
|
— | — | (56 | ) | ||||||||
|
Current
assets
|
(5 | ) | (2 | ) | 6 | |||||||
|
Current
liabilities
|
(14 | ) | (9 | ) | — | |||||||
|
Non-current
assets
|
5 | (14 | ) | (4 | ) | |||||||
|
Non-current
liabilities
|
(1 | ) | 2 | (195 | ) | |||||||
|
Cash provided
by (used in) continuing activities
|
196 | 160 | (86 | ) | ||||||||
|
Cash provided
by discontinued activities
|
— | — | 54 | |||||||||
|
Net cash
provided by (used in) operating activities
|
196 | 160 | (32 | ) | ||||||||
|
Cash flows
from investing activities
|
||||||||||||
|
Capital
expenditures
|
(103 | ) | (134 | ) | (108 | ) | ||||||
|
Net change in
notes receivable from affiliates
|
45 | 183 | 271 | |||||||||
|
Proceeds from
sale of assets
|
10 | — | — | |||||||||
|
Other
|
2 | 3 | — | |||||||||
|
Cash provided
by (used in) continuing activities
|
(46 | ) | 52 | 163 | ||||||||
|
Cash used in
discontinued activities
|
— | — | (83 | ) | ||||||||
|
Net cash
provided by (used in) investing activities
|
(46 | ) | 52 | 80 | ||||||||
|
Cash flows
from financing activities
|
||||||||||||
|
Payments to
retire long-term debt and other financing obligations
|
(4 | ) | (103 | ) | (128 | ) | ||||||
|
Distributions
to partners
|
(144 | ) | (109 | ) | — | |||||||
|
Contribution
from parent
|
— | — | 7 | |||||||||
|
Distribution
from discontinued operations
|
— | — | 44 | |||||||||
|
Cash used in
continuing activities
|
(148 | ) | (212 | ) | (77 | ) | ||||||
|
Cash provided
by discontinued activities
|
— | — | 29 | |||||||||
|
Net cash used
in financing activities
|
(148 | ) | (212 | ) | (48 | ) | ||||||
|
Net change in
cash and cash equivalents
|
2 | — | — | |||||||||
|
Cash and cash
equivalents
|
||||||||||||
|
Beginning of
period
|
— | — | — | |||||||||
|
End of
period
|
$ | 2 | $ | — | $ | — | ||||||
See accompanying
notes.
COLORADO
INTERSTATE GAS COMPANY
CONSOLIDATED
STATEMENTS OF PARTNERS’ CAPITAL/STOCKHOLDER’S EQUITY
(In
millions, except share amounts)
|
Common Stock
|
Additional
Paid-in
|
Retained
|
Accumulated
Other
Comprehensive
|
Total
Stockholder’s
|
Total
Partners’
|
|||||||||||||||||||||||
|
|
Shares
|
Amount
|
Capital
|
Earnings
|
Income
|
Equity
|
Capital
|
|||||||||||||||||||||
|
January 1,
2007
|
1,000 | $ | — | $ | 47 | $ | 1,097 | $ | 5 | $ | 1,149 | $ | — | |||||||||||||||
|
Net
income
|
111 | 111 | ||||||||||||||||||||||||||
|
Reclassification
to regulatory liability (Note
8)
|
— | (5 | ) | (5 | ) | — | ||||||||||||||||||||||
|
October 31,
2007
|
1,000 | — | 47 | 1,208 | — | 1,255 | — | |||||||||||||||||||||
|
Conversion to
general partnership
(November 1,
2007)
|
(1,000 | ) | (47 | ) | (1,208 | ) | (1,255 | ) | 1,255 | |||||||||||||||||||
|
Contributions
|
82 | |||||||||||||||||||||||||||
|
Distributions
|
(332 | ) | ||||||||||||||||||||||||||
|
Net
income
|
38 | |||||||||||||||||||||||||||
|
December 31,
2007
|
— | — | — | — | — | — | 1,043 | |||||||||||||||||||||
|
Net
income
|
149 | |||||||||||||||||||||||||||
|
Distributions
|
(409 | ) | ||||||||||||||||||||||||||
|
December 31,
2008
|
— | — | — | — | — | — | 783 | |||||||||||||||||||||
|
Net
income
|
157 | |||||||||||||||||||||||||||
|
Distributions
|
(144 | ) | ||||||||||||||||||||||||||
|
December 31,
2009
|
— | $ | — | $ | — | $ | — | $ | — | $ | — | $ | 796 | |||||||||||||||
See accompanying
notes.
COLORADO
INTERSTATE GAS COMPANY
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
1.
Summary of Significant Accounting Policies
Basis
of Presentation and Principles of Consolidation
We are a Delaware
general partnership, originally formed in 1927 as a corporation. We are owned 58
percent by EPPP CIG GP Holdings, L.L.C., a subsidiary of the El Paso Pipeline
Partners, L.P. (EPB) which is majority owned by El Paso Corporation (El Paso)
and 42 percent by El Paso Noric Investments III, L.L.C., a wholly owned
subsidiary of El Paso. In conjunction with the formation of EPB in November
2007, we distributed 100 percent of Wyoming Interstate Company, Ltd. (WIC) to
EPB 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 consolidated
subsidiaries after the elimination of intercompany accounts and
transactions.
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 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
Financial Accounting Standards Board’s (FASB) accounting standards
for regulated operations. Under these standards, we record
regulatory assets and liabilities that would not be recorded under GAAP for
non-regulated entities. Regulatory assets and liabilities represent probable
future revenues or expenses associated with certain charges or credits that are
expected to be recovered from or refunded to customers through the rate making
process. Items to which we apply regulatory accounting requirements include
certain postretirement employee benefit plan costs, loss on reacquired debt, an
equity return component on regulated capital projects, certain costs related to
gas not used in operations and other costs included in, or expected to be
included in, future rates.
Cash
and Cash Equivalents
We consider
short-term investments with an original maturity of less than three months to be
cash equivalents.
Allowance
for Doubtful Accounts
We establish
provisions for losses on accounts receivable and for natural gas imbalances due
from shippers and operators if we determine that we will not collect all or part
of the outstanding balance. We regularly review collectability and establish or
adjust our allowance as necessary using the specific identification
method.
Materials
and Supplies
We value materials
and supplies at the lower of cost or market value with cost determined using the
average cost method.
Natural
Gas Imbalances
Natural gas
imbalances occur when the amount of natural gas delivered from or received by a
pipeline system, processing plant or storage facility differs from the 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, as
defined by the FERC. We include gains or losses on dispositions of operating
units in operation and maintenance expense in our income
statements.
At December 31,
2009 and 2008, we had $69 million and $106 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 capitalized during the years ended December
31, 2009, 2008 and 2007, were $1 million, $2 million and $1 million.
These debt amounts are included as a reduction to interest and debt expense on
our income statement. The equity portion 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, 2009, 2008 and 2007, were
$4 million, $8 million and $2 million. These equity amounts are
included in other income on our income statement.
Asset
and Investment Divestitures/Impairments
We evaluate assets
and investments for impairment when events or circumstances indicate that their
carrying values may not be recovered. These events include market declines that
are believed to be other than temporary, changes in the manner in which we
intend to use a long-lived asset, decisions to sell an asset or investment and
adverse changes in the legal or business environment such as adverse actions by
regulators. When an event occurs, we evaluate the recoverability of our carrying
value based on either (i) the long-lived asset’s ability to generate future cash
flows on an undiscounted basis or (ii) the fair value of the investment in an
unconsolidated affiliate. If an impairment is indicated, or if we decide to sell
a long-lived asset or group of assets, we adjust the carrying value of the asset
downward, if necessary, to its estimated fair value. Our fair value estimates
are generally based on market data obtained through the sales process or an
analysis of expected discounted cash flows. 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 to be sold in our financial statements as either held-for-sale or
from discontinued operations when it becomes probable that we will dispose of
the assets within the next twelve months and when they meet other criteria,
including 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 from discontinued
operations, and reflect the results of our discontinued operations in our income
statement separately from those of continuing operations.
Cash flows from our
discontinued businesses are reflected as discontinued operating, investing, and
financing activities in our statement of cash flows. Cash provided by
discontinued activities in the operating activities section of our cash flow
statement includes all operating cash flows generated by our discontinued
business during the period. Proceeds from the sale of our discontinued
operations are classified in cash provided by discontinued activities in the
cash flows from investing activities section of our cash flow statement. Our
discontinued business participated in El Paso’s cash management program as it
did not maintain separate bank accounts for its cash balances. We reflected
transactions between our continuing operations and discontinued operations
related to El Paso’s cash management program as financing activities in our cash
flow statement. 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. 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.
Income
Taxes
Effective November
1, 2007, we converted into a general partnership in conjunction with the
formation of EPB and accordingly, we are no longer subject to income taxes.
As a result of our conversion into a general partnership, we settled our then
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 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 initially recorded at their estimated fair
value with a corresponding increase to property, plant and equipment. This
increase in property, plant and equipment is then depreciated over the useful
life of the asset to which that liability relates. An ongoing expense is 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
accretion of the liabilities described above.
We have legal
obligations associated with the retirement of our natural gas pipeline,
transmission facilities and storage wells. We have obligations to plug storage
wells when we no longer plan to use them and when we abandon them. Our legal
obligations associated with our natural gas transmission facilities primarily
involve purging and sealing the pipeline if it is abandoned. We also have
obligations to remove hazardous materials associated with our natural gas
transmission facilities if they are 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, 2009 and 2008
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 benefit plan, see Note 8.
In accounting for
our postretirement benefit plan, we record an asset or liability based on the
over funded or under funded status of the plan. Any deferred amounts related to
unrecognized gains and losses or changes in actuarial assumptions are recorded
as either a regulatory asset or liability.
Effective January
1, 2008, we adopted the provisions of an accounting standard update
related to measurement date 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.
Effective December
31, 2009, we expanded our disclosures about postretirement benefit plan assets
as a result of new disclosure requirements. See Note 8 for these
expanded disclosures.
New
Accounting Pronouncements Issued But Not Yet Adopted
As of December 31,
2009, the following accounting standards had not yet been adopted by
us.
Transfers of Financial
Assets. In June 2009, the FASB updated accounting standards on financial
asset transfers. Among other items, this update eliminated the concept of a
qualifying special-purpose entity (QSPE) for purposes of evaluating whether an
entity should be consolidated or not. The changes are effective for
existing QSPEs as of January 1, 2010 and for transactions entered into on or
after January 1, 2010. The adoption of this accounting standard in
January 2010 did not have a material impact on our financial statements as we
amended our existing accounts receivable sales program in January 2010 (see Note
11).
Variable Interest Entities.
In June 2009, the FASB updated to existing accounting standards for variable
interest entities to revise how companies determine the primary beneficiary of
these entities, among other changes. Companies will now be required
to use a qualitative approach based on their responsibilities and power over the
entities’ operations, rather than a quantitative approach in determining the
primary beneficiary as previously required. The adoption of this
accounting standard in January 2010 did not have a material impact on our
financial statements.
2.
Divestitures
In November 2009,
we sold our Natural Buttes Compressor Station and gas processing plant to a
third party for $9 million and recorded a gain of approximately $8 million
related to the sale, which is included in our income statement as a reduction of
operation and maintenance expense. The historical gross cost of the assets
were approximately $35 million. Pursuant to the FERC order approving the sale of
the compressor station and the processing plant, we recently filed
our proposed accounting entries associated with the sale with the FERC for its
approval which utilized a technical obsolescence appraisal methodology for
determining the portion of the composite accumulated depreciation attributable
to the plant which resulted in us recording a gain on the sale. Although we
believe the entries proposed are appropriate for this sale, the FERC also
utilizes other methodologies in estimating the associated accumulated
depreciation that if applied could result in a non-cash loss on the
sale.
In November 2007,
in conjunction with the formation of EPB, we distributed 100 percent of WIC to
EPB 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. We classify assets (or groups of assets) to be disposed
of as held for sale or, if appropriate, from discontinued operations when they
have received appropriate approvals to be disposed of by our management and when
they meet other criteria. The table below summarizes the operating results of
our discontinued operations for the year ended December 31, 2007.
|
|
||||
|
(In
millions)
|
||||
|
Revenues
|
$ | 97 | ||
|
Operating
expenses
|
(41 | ) | ||
|
Other income,
net
|
5 | |||
|
Interest and
debt expense
|
1 | |||
|
Affiliated
interest income, net
|
1 | |||
|
Income before
income taxes
|
63 | |||
|
Income
taxes
|
21 | |||
|
Income from
discontinued operations, net of income taxes
|
$ | 42 | ||
3.
Income Taxes
In conjunction with
the formation of EPB, we converted our legal structure into a general
partnership effective November 1, 2007 and are no longer subject to income
taxes. We also settled our then existing current and deferred income
tax balances pursuant to our tax sharing agreement with El Paso with recoveries
of note receivables from El Paso under its cash management program.
Components of Income Tax Expense.
The following table reflects the components of income tax expense
included in income from continuing operations for the year ended December 31,
2007:
|
|
||||
|
(In
millions)
|
||||
|
Current
|
||||
|
Federal
|
$ | 33 | ||
|
State
|
3 | |||
| 36 | ||||
|
Deferred
|
||||
|
Federal
|
7 | |||
|
State
|
1 | |||
| 8 | ||||
|
Total income
taxes
|
$ | 44 | ||
Effective Tax Rate Reconciliation.
Our income tax expense included in income from continuing operations
differs from the amount computed by applying the statutory federal income tax
rate of 35 percent for the following reasons for the year ended December 31,
2007:
|
|
||||
|
(In
millions, except for rates)
|
||||
|
Income taxes
at the statutory federal rate of 35%
|
$ | 53 | ||
|
Increase
(decrease)
|
||||
|
Pretax income
not subject to income taxes after conversion to
partnership
|
(12 | ) | ||
|
State income
taxes, net of federal income tax benefit
|
3 | |||
|
Income
taxes
|
$ | 44 | ||
|
Effective tax
rate
|
29 | % | ||
4.
Fair Value of Financial Instruments
At December 31,
2009 and 2008, the carrying amounts of cash and cash equivalents and trade
receivables and payables are representative of their fair value because of the
short-term nature of these instruments. At December 31, 2009, we had a note
receivable from EPB of approximately $61 million with a variable interest rate
of 0.7%. In addition, at December 31, 2009 and 2008, we had a note
receivable from El Paso of approximately $73 million and $179 million, with a
variable interest rate of 1.5% and 3.2%. While we are exposed to changes in
interest income based on changes to the variable interest rates, the fair value
of these notes receivable approximates the carrying value due to the notes being
due on demand and the market-based nature of the interest rates.
In addition, the
carrying amounts of our long-term debt, other financing obligations and their
estimated fair values, which are based on quoted market prices for the same or
similar issues, are as follows at December 31:
|
|
2009
|
2008
|
||||||||||||||
|
|
Carrying
Amount
|
Fair
Value
|
Carrying
Amount
|
Fair
Value
|
||||||||||||
|
(In
millions)
|
||||||||||||||||
|
Long-term
debt and other financing obligations, including current
maturities
|
$ | 650 | $ | 695 | $ | 583 | $ | 502 | ||||||||
5.
Regulatory Assets and Liabilities
Our non-current
regulatory assets and liabilities are included in other non-current assets and
liabilities on our balance sheets. Our regulatory asset and liability balances
are recoverable or reimbursable over various periods. Below are the details of
our regulatory assets and liabilities at December 31:
|
|
2009
|
2008
|
||||||
|
(In
millions)
|
||||||||
|
Current
regulatory assets
|
||||||||
|
Deferred fuel
lost and unaccounted for gas
|
$ | — | $ | 17 | ||||
|
Other
|
1 | 1 | ||||||
|
Total current
regulatory assets
|
1 | 18 | ||||||
|
Non-current
regulatory assets
|
||||||||
|
Taxes on
capitalized funds used during construction
|
11 | 11 | ||||||
|
Unamortized
loss on reacquired debt
|
6 | 7 | ||||||
|
Postretirement
benefits
|
1 | 2 | ||||||
|
Under-collected
income taxes
|
1 | 1 | ||||||
|
Total
non-current regulatory assets
|
19 | 21 | ||||||
|
Total
regulatory assets
|
$ | 20 | $ | 39 | ||||
|
Current
regulatory liabilities
|
||||||||
|
Gas retained
and not used in operations
|
$ | 13 | $ | 29 | ||||
|
Non-current
regulatory liabilities
|
||||||||
|
Property and
plant depreciation
|
18 | 19 | ||||||
|
Postretirement
benefits
|
10 | 6 | ||||||
|
Total
non-current regulatory liabilities
|
28 | 25 | ||||||
|
Total
regulatory liabilities
|
$ | 41 | $ | 54 | ||||
The significant
regulatory assets and liabilities include:
Difference Between Gas Retained and
Gas Consumed in Operations. These amounts reflect the value of the
volumetric difference between the gas retained from our customers and the gas
consumed in operations. These amounts are not included in the rate base
but are expected to be recovered or refunded in subsequent fuel filing
periods.
Taxes on Capitalized Funds Used
During Construction. These regulatory asset balances
were established to offset the deferred tax for the equity component of the
allowance for funds used during the construction of long-lived
assets. Taxes on capitalized funds used during construction and the
offsetting deferred income taxes are included in the rate base. Both are
recovered over the depreciable lives of the long-lived asset to which they
relate.
Unamortized Loss on Reacquired
Debt. These amounts represent the deferred and unamortized portion
of losses on reacquired debt which are not included in the rate base, but
are recovered over the original life of the debt issue through the authorized
rate of return.
Postretirement Benefits.
These balances represent deferred amounts related to unrecognized gains and
losses or changes in actuarial assumptions related to our postretirement benefit
plan and differences in the postretirement benefit related amounts expensed and
the amounts recoverable in rates. Postretirement benefit amounts have
been included in the rate base computations and are recoverable in such
periods as benefits are funded.
Property and Plant
Depreciation. Amounts represent 1) the deferral of customer-funded
amounts for costs of future asset retirements, and 2) the excess of ratemaking
depreciation expense over the depreciation expense recorded in the financial
statements. These amounts are included in the rate base computations
and the depreciation-related amounts are refunded over the lives of the
long-lived assets to which they relate.
6.
Long-Term Debt and Other Financing Obligations
Debt. Our long-term debt and
financing obligations consisted of the following at December 31:
|
|
2009
|
2008
|
||||||
|
(In
millions)
|
||||||||
|
5.95% Senior
Notes due March 2015
|
$ | 35 | $ | 35 | ||||
|
6.80% Senior
Notes due November 2015
|
340 | 340 | ||||||
|
6.85% Senior
Debentures due June 2037
|
100 | 100 | ||||||
|
Total
long-term debt
|
475 | 475 | ||||||
|
Other
financing obligations
|
175 | 108 | ||||||
|
Total
long-term debt and other financing obligations
|
650 | 583 | ||||||
|
Less: Current
maturities
|
4 | 3 | ||||||
|
Total
long-term debt and other financing obligations, less current
maturities
|
$ | 646 | $ | 580 | ||||
In March 2009, we,
Colorado Interstate Issuing Corporation (CIIC), El Paso and certain other El
Paso subsidiaries filed a registration statement on Form S-3 under which we and
CIIC may co-issue debt securities in the future. CIIC is a wholly owned finance
subsidiary of us and is the co-issuer of our outstanding debt securities. CIIC
has no material assets, operations, revenues or cash flows other than those
related to its service as a co-issuer of our debt securities. Accordingly, it
has no ability to service obligations on our debt securities.
Under our various
financing documents, we are subject to a number of restrictions and covenants.
The most restrictive of these include limitations on the incurrence of liens and
limitations on sale-leaseback transactions. For the year ended December 31,
2009, we were in compliance with our debt-related covenants.
Other Financing Obligations.
In June 2009 and November 2008, the Totem Gas Storage project and the High
Plains pipeline were placed in service. Upon placing these projects in service,
we transferred our title in the projects to WYCO Development LLC (WYCO) (a joint
venture with an affiliate of Public Service Company of Colorado (PSCo) in which
we have a 50 percent ownership interest). Although we transferred the title in
these projects to WYCO, we continue to reflect the Totem Gas Storage facility
and the High Plains Pipeline as property, plant and equipment in our financial
statements as of December 31, 2009 due to our continuing involvement with the
projects through WYCO.
We constructed the
Totem Gas Storage project and the High Plains pipeline and our joint venture
partner in WYCO funded 50 percent of the construction costs, which we reflected
as other non-current liabilities in our balance sheet during the construction
period. Upon completion of the construction, our obligations to the affiliate of
PSCo for these construction advances were converted into financing obligations
to WYCO and accordingly, we reclassified the amounts from other non-current
liabilities to debt and other financing obligations.
Totem Gas Storage financing
obligation. The Totem Gas Storage obligation has a principal amount of
$69 million as of December 31, 2009 and has monthly principal payments totaling
approximately $1 million each year through 2060. We also make monthly interest
payments on this obligation that are based on 50 percent of the operating
results of the Totem Gas Storage facility, which is currently estimated at a
15.5% rate as of December 31, 2009.
High Plains Pipeline financing
obligation. The High Plains Pipeline obligation has a principal amount of
$106 million as of December 31, 2009, 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, 2009.
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. In
March 2009, the Tenth Circuit Court of Appeals affirmed the dismissals and in
October 2009, the plaintiff’s appeal to the United States Supreme Court was
denied.
Similar allegations
were filed in a 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 seek certification of a class of royalty owners in wells
on non-federal and non-Native American lands in Kansas, Wyoming and
Colorado. The plaintiffs seek 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. In September 2009, the court denied the motions for class
certification. The plaintiffs have filed a motion for
reconsideration. Our costs and legal exposure related to this lawsuit 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 or claim, our exposure to the matter, possible legal or settlement
strategies and the likelihood of an unfavorable outcome. If we determine that an
unfavorable outcome is probable and can be estimated, we establish the necessary
accruals. While the outcome of these matters, 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, 2009. It is
possible, however, that new information or future developments could require us
to reassess our potential exposure related to these matters and establish
accruals accordingly.
Environmental
Matters
We are subject to
federal, state and local laws and regulations governing environmental quality
and pollution control. These laws and regulations require us to remove or remedy
the effect of the disposal or release of specified substances at current and
former operating sites. At December 31, 2009 and 2008, we had accrued
approximately $11 million and $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 $35 million at December 31, 2009. Our accrual at December 31, 2009
includes $8 million for environmental contingencies related to properties we
previously owned.
Our environmental
remediation projects are in various stages of completion. Our recorded
liabilities reflect our current estimates of amounts we will 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.
For 2010, we
estimate that our total remediation expenditures will be approximately $2
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.
Regulatory
Matter
Fuel Recovery Mechanism.
During 2008, we recorded cost and revenue tracker adjustments associated with
the implementation of fuel and related gas cost recovery mechanisms, which the
FERC approved subject to the outcome of technical conferences. The
implementation of these mechanisms was protested by a limited number of
shippers. On July 31, 2009, the FERC issued an order to us directing us to
remove the cost and revenue components from our fuel recovery mechanism. Due to
this order, our future earnings may be impacted by both positive and negative
fluctuations in gas prices related to fuel imbalance revaluations, our
settlement, and other gas balance related items. We continue to explore
options to minimize the price volatility associated with these operational
pipeline activities. Our tariff continues to provide that the difference between
the quantity of fuel retained and fuel used in operations and lost and
unaccounted for will be flowed-through or charged to shippers. These fuel
trackers remove the impact of over or under collecting fuel and lost and
unaccounted for from our operational gas costs.
Other
Commitments
Capital
Commitments. At December 31, 2009, we had capital commitments
of $33 million related primarily to CIG’s Raton 2010 expansion project, the
majority of which will be paid in 2010. 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.
Transportation and Storage
Commitments. We have entered into transportation commitments and storage
capacity contracts totaling approximately $101 million at December 31, 2009, of
which $59 million is related to storage capacity contracts with our affiliate,
Young Gas Storage Company, Ltd. Our annual commitments under these agreements
are $18 million in 2010, $19 million in 2011, $22 million in 2012, $17 million
in 2013, $17 million in 2014 and $8 million in total thereafter.
Operating Leases. We lease
property, facilities and equipment under various operating leases. Future
minimum annual rental commitments under our operating leases at December 31,
2009, were as follows:
|
Year
Ending
December 31,
|
|
||||
|
(In
millions)
|
|||||
| 2010 |
|
$ | 2 | ||
| 2011 |
|
2 | |||
| 2012 |
|
2 | |||
| 2013 |
|
2 | |||
| 2014 |
|
3 | |||
| Thereafter |
|
1 | |||
|
Total
|
|
$ | 12 | ||
Rental expense on
our lease obligations for the years ended December 31, 2009, 2008 and 2007 was
$2 million. These amounts include our share of rent allocated to us from El
Paso.
Other Commercial Commitments.
We hold cancelable easements or rights-of-way arrangements from
landowners permitting the use of land for the construction and operation of our
pipeline system. Currently, our obligations under these easements are not
material to the results of our operations.
Guarantees. We are or have
been involved in various ownership and other contractual arrangements that
sometimes require us to provide additional financial support that results in the
issuance of financial and performance guarantees that are not recorded in our
financial statements. In a financial guarantee, we are obligated to make
payments if the guaranteed party failed to make payments under, or violated the
terms of, the financial arrangement. During 2009, our financial guarantee with a
maximum exposure of approximately $2 million was terminated.
8.
Retirement Benefits
Pension and Retirement Savings
Plans. El Paso maintains a pension plan and a retirement savings plan
covering substantially all of its U.S. employees, including our former
employees. The benefits under the pension plan are determined under a cash
balance formula. Under its retirement savings plan, El Paso matches 75 percent
of participant basic contributions up to six percent of eligible compensation
and can make additional discretionary matching contributions depending on 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 Plan. We provide postretirement medical benefits for a closed
group of retirees. These benefits may be subject to deductibles,
co-payment provisions, and other limitations and dollar caps on the amount of
employer costs and El Paso reserves the right to change these
benefits. In addition, certain former employees continue to receive
limited postretirement life insurance benefits. Our postretirement benefit plan
costs are prefunded to the extent these costs are recoverable through our rates.
To the extent actual costs differ from the amounts recovered in rates, a
regulatory asset or liability is recorded. We do not expect to make any
contributions to our postretirement benefit plan in 2010.
Accumulated Postretirement Benefit
Obligation, Plan Assets and Funded Status. In accounting for our
postretirement benefit plan, we record an asset or liability based on the over
funded or under funded status. 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.
The table below
provides information about our postretirement benefit plan. In 2008,
we adopted the FASB’s revised measurement date provisions for other
postretirement benefit plans and the information below for 2008 is presented and
computed as of and for the fifteen months ended December 31,
2008. For 2009, the information is presented and computed as of and
for the twelve months ended December 31, 2009.
|
|
December
31,
2009
|
December
31,
2008
|
||||||
|
(In
millions)
|
||||||||
|
Change in
accumulated postretirement benefit obligation:
|
||||||||
|
Accumulated
postretirement benefit obligation - beginning of period
|
$ | 7 | $ | 7 | ||||
|
Interest
cost
|
— | 1 | ||||||
|
Participant
contributions
|
1 | — | ||||||
|
Actuarial
(gain) loss
|
(2 | ) | 1 | |||||
|
Benefits
paid(1)
|
(1 | ) | (2 | ) | ||||
|
Accumulated
postretirement benefit obligation - end of period
|
$ | 5 | $ | 7 | ||||
|
Change in
plan assets:
|
||||||||
|
Fair value of
plan assets - beginning period
|
$ | 12 | $ | 18 | ||||
|
Actual return
on plan assets
|
2 | (4 | ) | |||||
|
Participant
contributions
|
1 | — | ||||||
|
Benefits
paid
|
(1 | ) | (2 | ) | ||||
|
Fair value of
plan assets - end of period
|
$ | 14 | $ | 12 | ||||
|
Reconciliation
of funded status:
|
||||||||
|
Fair value of
plan assets
|
$ | 14 | $ | 12 | ||||
|
Less:
accumulated postretirement benefit obligation
|
5 | 7 | ||||||
|
Net asset at
December 31
|
$ | 9 | $ | 5 | ||||
____________
|
(1)
|
Amounts
shown net of a subsidy of less than $1 million for each of the years ended
December 31, 2009 and 2008 related to the Medicare Prescription Drug,
Improvement, and Modernization Act of
2003.
|
Plan Assets. The primary
investment objective of our plan is to ensure that, over the long-term life of
the plan an adequate pool of sufficiently liquid assets exists to meet the
benefit obligations to retirees and beneficiaries. Investment objectives are
long-term in nature covering typical market cycles. Any shortfall of investment
performance compared to investment objectives is generally the result of
economic and capital market conditions. Although actual allocations
vary from time to time from our targeted allocations, the target allocations of
our postretirement plan’s assets are 65 percent equity and 35 percent fixed
income securities. We may invest assets in a manner that replicates,
to the extent feasible, the Russell 3000 Index and the Barclays Capital
Aggregate Bond Index to achieve equity and fixed income diversification,
respectively.
We use various
methods to determine the fair values of the assets in our other postretirement
benefit plans, which are impacted by a number of factors, including the
availability of observable market data over the contractual term of the
underlying assets. We separate these assets into three levels (Level
1, 2 and 3) based on our assessment of the availability of
this market data and the significance of non-observable data used to
determine the fair value of these assets. As of December 31, 2009,
our assets are comprised of an exchange-traded mutual fund with a fair value of
$1 million and common/collective trusts with a fair value of $13
million. Our exchange-traded mutual fund invests primarily in
dollar-denominated securities, and its fair value (which is considered a Level 1
measurement) is determined based on the price quoted for the fund in actively
traded markets. Our common/collective trusts are invested in
approximately 65 percent equity and 35 percent fixed income securities, and
their fair values (which are considered Level 2 measurements) are determined
primarily based on the net asset value reported by the issuer, which is based on
similar assets in active markets. We may adjust the fair value of our
common/collective trusts, when necessary, for factors such as liquidity or risk
of nonperformance by the issuer. We do not have any assets that are
considered Level 3 measurements. The methods described above may
produce a fair value that may not be indicative of net realizable value or
reflective of future fair values, and there have been no changes in the
methodologies used at December 31, 2009 and 2008.
Expected Payment of Future Benefits.
As of December 31, 2009, we expect the following benefit payments under
our plan:
|
Year
Ending
December 31,
|
Expected
Payments(1)
|
||||
|
(In
millions)
|
|||||
|
2010
|
$ | 1 | |||
|
2011
|
1 | ||||
|
2012
|
1 | ||||
|
2013
|
1 | ||||
|
2014
|
1 | ||||
|
2015 -
2019
|
2 | ||||
____________
|
(1)
|
Includes
a reduction of less than $1 million in each of the years 2010 – 2014 and
approximately $1 million in aggregate for 2015 – 2019 for an expected
subsidy related to the Medicare Prescription Drug, Improvement, and
Modernization Act of 2003.
|
Actuarial Assumptions and
Sensitivity Analysis. Accumulated postretirement benefit obligations and
net benefit costs are based on actuarial estimates and assumptions. The
following table details the weighted average actuarial assumptions used in
determining our postretirement plan obligations and net benefit costs for 2009,
2008 and 2007:
|
|
2009
|
2008
|
2007
|
|||||||||
|
(Percent)
|
||||||||||||
|
Assumptions
related to benefit obligations at December 31, 2009 and 2008
and
September 30,
2007 measurement dates:
|
||||||||||||
|
Discount
rate
|
5.06 | 5.82 | 6.05 | |||||||||
|
Assumptions
related to benefit costs at December 31:
|
||||||||||||
|
Discount
rate
|
5.82 | 6.05 | 5.50 | |||||||||
|
Expected
return on plan assets(1)
|
8.00 | 8.00 | 8.00 | |||||||||
____________
|
(1)
|
The
expected return on plan assets is a pre-tax rate of return based on our
targeted portfolio of investments. Our postretirement benefit plan’s
investment earnings are subject to unrelated business income taxes at a
rate of 35%. The expected return on plan assets for our postretirement
benefit plan is calculated using the after-tax rate of
return.
|
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 8.0 percent,
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 as of and for the years ended December 31, 2009 and
2008.
Components of Net Benefit Income.
For each of the years ended December 31, the components of net benefit
income are as follows:
|
|
2009
|
2008
|
2007
|
|||||||||
|
(In
millions)
|
||||||||||||
|
Interest
cost
|
$ | 1 | $ | 1 | $ | 1 | ||||||
|
Expected
return on plan assets
|
(1 | ) | (1 | ) | (1 | ) | ||||||
|
Other
|
— | (1 | ) | (1 | ) | |||||||
|
Net benefit
income
|
$ | — | $ | (1 | ) | $ | (1 | ) | ||||
9.
Transactions with Major Customer
The following table
shows revenues from our major customer for each of the three years ended
December 31:
|
|
2009
|
2008
|
2007
|
|||||||||
|
(In
millions)
|
||||||||||||
|
PSCo
|
$ | 154 | $ | 90 | $ | 91 | ||||||
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:
|
|
2009
|
2008
|
2007
|
|||||||||
|
(In
millions)
|
||||||||||||
|
Interest
paid, net of capitalized interest
|
$ | 52 | $ | 37 | $ | 52 | ||||||
|
Income tax
payments
|
— | — | 277 | (1) | ||||||||
____________
|
|
(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, a compressor station and the Totem Gas
storage. At December 31, 2009 and 2008, our investment in WYCO was approximately
$14 million and $17 million, which is included in other non-current assets in
our balance sheets. We have other financing obligations payable to WYCO totaling
$175 million and $108 million as of December 31, 2009 and 2008, which is further
described in Note 6.
Transactions
with Affiliates
EPB Acquisition. In July
2009, EPB acquired an additional 18 percent ownership interest in us from El
Paso. The acquisition increased EPB’s interest in us to 58
percent.
Contributions/Distributions.
On November 21, 2007, in conjunction with the formation of EPB, 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
EPB’s acquiring an additional 30 percent ownership interest in us, we made a
non-cash distribution to our partners of $300 million of our note receivable
under El Paso's cash management program. We are required to make
distributions of available cash as defined in our partnership agreement on a
quarterly basis to our partners. During 2009 and 2008, we paid cash
distributions of approximately $144 million and $109 million to our partners. We
did not make any distributions to our partners during 2007. In addition, in
January 2010 we paid a cash distribution to our partners of approximately $44
million.
Cash Management
Programs. In conjunction with EPB’s acquisition of an
additional interest in us as described above, during the third quarter of 2009
we began to participate in EPB’s cash management program which matches our
short-term cash surpluses and needs, thus minimizing our total borrowings from
outside sources. EPB uses the cash management program to settle
intercompany transactions with us. At December 31, 2009, we had a
note receivable from EPB of approximately $61 million with an interest rate of
0.7%. We classified $28 million of this receivable as
current based on the net amount we anticipate using in the next twelve months
considering available cash sources and needs.
In conjunction with
EPB’s acquisition of the additional interest in us as described above, we
terminated our participation in El Paso’s cash management program. We
converted our note receivable with El Paso under its cash management program
into a demand note receivable from El Paso. At December 31, 2009, we had $73
million remaining under this note at an interest rate of 1.5%, which is
classified as current based on the net amount we anticipate using in the next
twelve months considering available cash sources and needs. At December 31,
2008, we had a $179 million note receivable from El Paso of which $103
million was classified as current on our balance sheet. The interest rate on
this variable rate note was 3.2% at December 31, 2008.
Income Taxes. Effective
November 1, 2007, we converted into a general partnership as discussed in Note 1
and settled our then 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 QSPE whose purpose is solely
to invest in our receivables, which are short-term assets that generally settle
within 60 days. During the year ended December 31, 2009 and 2008, we received
net proceeds of approximately $0.4 billion and $0.3 billion related to sales of
receivables to the QSPE and changes in our subordinated beneficial interests and
recognized losses of less than $1 million on these transactions. As
of December 31, 2009 and 2008, we had approximately $37 million and $29 million
of receivables outstanding with the QSPE, for which we received cash of $20
million and $21 million and received subordinated beneficial interests of
approximately $17 million and $8 million. The QSPE also issued senior beneficial
interests on the receivables sold to a third party financial institution, which
totaled $20 million and $21 million as of December 31, 2009 and 2008. We reflect
the subordinated beneficial 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 collectability 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 accounts receivable 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, 2009
and 2008.
In January 2010, we
ceased selling accounts receivable to the QSPE and began selling those
receivables directly to a third party financial institution. In return, the
third party financial institution pays a certain amount of cash up front for the
receivables, and pays the remaining amount owed over time as cash is collected
from the receivables.
Other Affiliate Balances. At
December 31, 2009 and 2008, we had contractual deposits from our affiliates
of $7 million and $6 million included in other current liabilities on our
balance sheet.
Affiliate Revenues and Expenses.
We entered into transactions with our affiliates within the ordinary
course of business and the services are based on the same terms as
non-affiliates, including natural gas transportation services to and from
affiliates under long-term contracts and various operating agreements. We also
contract with an affiliate to process natural gas and sell extracted natural gas
liquids.
We do not have
employees. 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 (TGP), 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.
The following table
shows overall revenues and charges from our affiliates for each of the three
years ended December 31:
|
|
2009
|
2008
|
2007
|
|||||||||
|
(In
millions)
|
||||||||||||
|
Revenues from
affiliates
|
$ | 11 | $ | 17 | $ | 20 | ||||||
|
Operation and
maintenance expenses from affiliates
|
101 | 86 | 60 | |||||||||
|
Reimbursements
of operating expenses charged to affiliates
|
26 | 26 | 22 | |||||||||
12.
Supplemental Selected Quarterly Financial Information (Unaudited)
Our financial
information by quarter is summarized below. Due to the seasonal nature of our
business, information for interim periods may not be indicative of our results
of operations for the entire year.
|
|
Quarters Ended
|
|
||||||||||||||||||
|
|
March 31
|
June 30
|
September 30
|
December 31(1)
|
Total
|
|||||||||||||||
|
(In
millions)
|
||||||||||||||||||||
|
2009
|
||||||||||||||||||||
|
Operating
revenues
|
$ | 97 | $ | 85 | $ | 91 | $ | 110 | $ | 383 | ||||||||||
|
Operating
income
|
51 | 42 | 47 | 65 | 205 | |||||||||||||||
|
Net
income
|
41 | 33 | 33 | 50 | 157 | |||||||||||||||
|
2008
|
||||||||||||||||||||
|
Operating
revenues
|
$ | 90 | $ | 73 | $ | 71 | $ | 89 | $ | 323 | ||||||||||
|
Operating
income
|
50 | 26 | 26 | 51 | 153 | |||||||||||||||
|
Net
income
|
50 | 26 | 25 | 48 | 149 | |||||||||||||||
____________
|
(1)
|
The
quarter ended December 31, 2009 includes a gain of $8 million related to
the sale of the Natural Buttes compressor station and gas processing plant
(see Note 2).
|
SCHEDULE
II
COLORADO
INTERSTATE GAS COMPANY
VALUATION
AND QUALIFYING ACCOUNTS
Years
Ended December 31, 2009, 2008 and 2007
(In
millions)
|
Description
|
Balance
at
Beginning
of Period
|
Charged
to
Costs
and
Expenses
|
Deductions(1)
|
Charged
to
Other
Accounts
|
Balance
at End
of Period
|
|||||||||||||||
|
2009
|
||||||||||||||||||||
|
Environmental
reserves
|
$ | 13 | $ | 1 | $ | (3 | ) | $ | — | $ | 11 | |||||||||
|
2008
|
||||||||||||||||||||
|
Environmental
reserves
|
$ | 15 | $ | 1 | $ | (3 | ) | $ | — | $ | 13 | |||||||||
|
2007
|
||||||||||||||||||||
|
Legal
reserves
|
$ | — | $ | 3 | $ | (3 | ) | $ | — | $ | — | |||||||||
|
Environmental
reserves
|
17 | 1 | (3 | ) | — | 15 | ||||||||||||||
____________
|
(1)
|
Primarily
relates to payments for environmental remediation
activities.
|
None.
Evaluation
of Disclosure Controls and Procedures
As of December 31,
2009, 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
objective and our President and our Chief Financial Officer concluded that our
disclosure controls and procedures (as defined in Exchange Act Rules 13a – 15(e)
and 15d – 15(e)) were effective as of December 31, 2009. 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 2009 that have materially affected or are reasonably likely to
materially affect our internal control over financial reporting.
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.
None.
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 EPB (the “EPB Partner”). The EPB Partner
owns a 58 percent interest in our partnership, and the El Paso Partner owns
our remaining 42 percent interest. A general partnership agreement governs
our ownership and management. Although our management is vested in our partners,
the partners have agreed to delegate our management to a management committee.
Decisions of or actions taken by the management committee are binding on us. The
management committee is composed of four representatives, with three
representatives being designated by the EPB Partner and one representative being
designated by the El Paso Partner. Each member of the management committee has
full authority to act on behalf of the partner that designated such member with
respect to matters pertaining to us. Each member of the management committee is
entitled to one vote on each matter submitted for a vote of the management
committee, and the vote of a majority of the members of the management committee
constitutes action of the management committee, except for certain actions
specified in the general partnership agreement that require unanimous approval
of the management committee. Our officers are appointed by the management
committee.
The following
provides biographical information for each of our executive officers and
management committee members as of February 26, 2010.
There are no family
relationships among any of our executive officers or management committee
members, and, unless described herein, no arrangement or understanding exists
between any executive officer and any other person pursuant to which he was or
is to be selected as an officer.
|
Name
|
Age
|
Position
|
|
James J.
Cleary
|
55
|
President and
Management Committee Member
|
|
John R.
Sult
|
50
|
Senior Vice
President and Chief Financial Officer
|
|
James C.
Yardley
|
58
|
Management
Committee Member
|
|
Daniel B.
Martin
|
53
|
Senior Vice
President and Management Committee Member
|
|
Thomas L.
Price
|
54
|
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. Mr. Cleary also
serves as Senior Vice President of El Paso Pipeline GP Company, L.L.C., the
general partner of El Paso Pipeline Partners, L.P.
John R. Sult. Mr. Sult has
been Senior Vice President and Chief Financial Officer of Colorado Interstate
Gas Company since November 2009. Mr. Sult previously served as Senior Vice
President, Chief Financial Officer and Controller from November 2005 to November
2009. Mr. Sult also serves as Senior Vice President and Chief
Financial Officer of our parent El Paso and as Senior Vice President and Chief
Financial Officer of our affiliates El Paso Natural Gas Company, Southern
Natural Gas Company and Tennessee Gas Pipeline Company. Mr. Sult previously
served as Senior Vice President and Controller of El Paso from November 2005 to
November 2009. Mr. Sult held the position of Vice President and
Controller at Halliburton Energy Services Company from August 2004 until joining
El Paso in October 2005. Mr. Sult also serves as Director, Senior Vice President
and Chief Financial Officer of El Paso Pipeline GP Company, L.L.C., the general
partner of El Paso Pipeline Partners, L.P.
James C. Yardley. Mr. Yardley
has been a member of the Management Committee of Colorado Interstate Gas Company
since November 2007. Mr. Yardley also serves as Executive Vice President of our
parent El Paso with responsibility for the regulated pipeline business unit
since August 2006. He has been a member of the Management Committee of Southern
Natural Gas Company since November 2007 and President since May 1998. Mr.
Yardley has been President of Tennessee Gas Pipeline since February 2007 and
Chairman of the Board since August 2006. Mr. Yardley is currently a
member of the board of directors of Scorpion Offshore Ltd. He also serves on the
Board of Interstate Natural Gas Association of America and previously served as
its Chairman. Mr. Yardley also serves as Director, President and Chief Executive
Officer of El Paso Pipeline GP Company, L.L.C., the general partner of El Paso
Pipeline Partners, L.P.
Daniel B. Martin. Mr. Martin
has been a member of the Management Committee of Colorado Interstate Gas Company
since November 2007 and Senior Vice President since January 2001. Mr. Martin has
been a member of the Management Committee of our affiliate Southern Natural Gas
Company since November 2007. He previously served as a director of Colorado
Interstate Gas Company and Southern Natural Gas Company from May 2005 to
November 2007. Mr. Martin has been a director of our affiliates El Paso Natural
Gas Company and Tennessee Gas Pipeline Company since May 2005. Mr. Martin has
been Senior Vice President of Southern Natural Gas Company and Tennessee Gas
Pipeline Company since June 2000 and Senior Vice President of El Paso Natural
Gas Company since February 2000. He served as a director of ANR Pipeline Company
from May 2005 through February 2007 and Senior Vice President of ANR Pipeline
Company from January 2001 to February 2007. Mr. Martin also
serves as Senior Vice President of El Paso Pipeline GP Company, L.L.C., the
general partner of El Paso Pipeline Partners, L.P.
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.
Audit Committee, Compensation
Committee and Code of Ethics
As a majority owned
subsidiary of EPB, we rely on EPB for certain support services. As a result, we
do not have a separate corporate audit committee or audit committee financial
expert, or a separate compensation committee. Also, we have not adopted a
separate code of ethics. However, our executives are subject to El Paso’s code
of ethics, referred to as the “Code of 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.
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.
CIG is a Delaware
general partnership. CIG is owned 42 percent indirectly through a wholly owned
subsidiary of El Paso, and is owned 58 percent by EPPP CIG GP Holdings, L.L.C.,
a subsidiary of El Paso Pipeline Partners, L.P., El Paso’s master limited
partnership. The address of each of El Paso and El Paso Pipeline Partners, L.P.
is 1001 Louisiana Street, Houston, Texas 77002.
The following table
sets forth, as of February 12, 2010, 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
|
59,045 | 271,469 | 330,514 | * | ||||||||||||
|
John R.
Sult
|
85,588 | 149,985 | 235,573 | * | ||||||||||||
|
James C.
Yardley
|
274,233 | 477,421 | 751,654 | * | ||||||||||||
|
Daniel B.
Martin
|
151,068 | 242,662 | 393,730 | * | ||||||||||||
|
Thomas L.
Price
|
56,562 | 95,477 | 152,039 | * | ||||||||||||
|
All
management committee members and executive officers as a group (5
persons)
|
626,496 | 1,237,014 | 1,863,510 | * | ||||||||||||
___________________
|
*
|
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 12, 2010. Shares
subject to options cannot be
voted.
|
|
(2)
|
Based on
701,314,549 shares outstanding as of February 12,
2010.
|
The following table
sets forth, as of February 12, 2010, the number of common units of EPB owned by
each of our executive officers and management committee members and all of our
management committee members and executive officers as a group.
|
Name of Beneficial Owner
|
Total
Common Units Beneficially Owned
|
Percentage
of
Total
Common Units Beneficially Owned(1)
|
||||||
|
James J.
Cleary
|
2,000 | * | ||||||
|
John R.
Sult
|
10,000 | * | ||||||
|
James C.
Yardley
|
10,000 | * | ||||||
|
Daniel B.
Martin
|
— | — | ||||||
|
Thomas L.
Price
|
— | — | ||||||
|
All
management committee members and executive officers as a group (5
persons)
|
22,000 | * | ||||||
___________________
|
*
|
Less
than 1%.
|
|
(1)
|
Based on
107,484,747 units outstanding as of February 12,
2010.
|
El Paso Master Limited Partnership
(EPB)
We are a general
partnership presently owned 58 percent indirectly through a wholly owned
subsidiary of EPB and 42 percent through a wholly owned subsidiary of the
El Paso.
CIG Operating
Agreements
We entered into a
Construction and Operating Agreement with WIC, on March 12, 1982. This agreement
was amended in 1984 and 1988. Under this agreement, we agreed to design and
construct the WIC system and to operate WIC (including conducting WIC’s
marketing and administering WIC’s service agreements) using the same practices
that we adopt in the operation and administration of our own facilities. Under
this agreement, we are entitled to be reimbursed by WIC for all costs incurred
in the performance of the services, including both direct costs and allocations
of general and administrative costs based on direct field labor charges.
Included in our allocated expenses are a portion of El Paso’s general and
administrative expenses and El Paso Natural Gas and Tennessee Gas Pipeline
Company allocated payroll and other expenses. We are the operator of the WIC
facilities, and are reimbursed by WIC for operation, maintenance and general and
administrative costs allocated from us, in each case under the Construction and
Operating Agreement referred to above.
We entered into a
Construction and Operating Agreement with Young 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 57,950 Dth/d
expiring on December 31, 2011, 89,021 Dth/d expiring on July 31, 2012 and the
balance expiring thereafter. In response to a solicitation of offers to turn
back capacity in a WIC open season, we relinquished 70,000 Dth/d of capacity
effective January 1, 2008.
We are also a party
to a transportation service agreement with WIC pursuant to which we will
acquire 75,600 Dth/day of firm transportation capacity on WIC from a
Primary Point of Receipt at the Cheyenne Hub to a Primary Point of Delivery into
El Paso’s Ruby Pipeline at Opal, Wyoming. The rate that we will pay for
this service is WIC’s maximum recourse rates plus the cost of any off-system
capacity on a third party pipeline that is acquired by WIC to provide this
service. The service will commence on the in-service date of El Paso’s
Ruby Pipeline and will continue until the later of July 1, 2021 or ten years
from the commencement date.
We are party to a
capacity release agreement with PSCo, whereby PSCo has released storage capacity
in our affiliate, Young Gas Storage Company, Ltd., to us for a term expiring on
April 30, 2025. PSCo simultaneously contracted for a corresponding
quantity of transportation and storage balancing service (which utilizes the
storage capacity acquired through the capacity release).
In order to provide
“jumper” compression service between our system and the Cheyenne Plains pipeline
system, we added compression at our existing compressor station in Weld County,
Colorado. Cheyenne Plains entered into a 25-year contract that expires in 2030
for the full capacity of the additional compression pursuant to which our full
cost of service is covered. The contract is for 119,500 Dth/d.
Interconnection and Operational
Balancing Agreements and Other Inter-Affiliate
Agreements
We are party to an
operating balancing agreement with WIC and to an operating balancing agreement
with Cheyenne Plains. These agreements require the interconnecting parties to
use their respective reasonable efforts to cause the quantities of gas that are
tendered/accepted at each point of interconnection to equal the quantities
scheduled at those points. The agreements provide for the treatment and
resolution of imbalances. The agreements are terminable by either party on 30
days’ advance notice.
We and WIC are
parties to a capacity lease agreement dated November 1, 1997. In 1998, WIC
installed a compressor unit at WIC’s Laramie compressor station. The
installation of this compressor unit allowed the interconnection of our Powder
River lateral and WIC’s mainline transmission system and resulted in an increase
of approximately 49 MDth/d of capacity on our Powder River lateral (the original
capacity on the Powder River lateral was approximately 46 MDth/d). In connection
with the installation of the compression by WIC, we leased the additional 49
MDth/d of capacity in the Powder River lateral to WIC. WIC, in turn, leased to
us 46 MDth/d of capacity through the new WIC compressor unit. The initial term
of the lease of the Powder River lateral capacity from CIG to WIC was 10 years
from the November 15, 1998 in-service date of the additional compression. In
November 2008, the term of the lease was extended for 10 years. The term of the
lease of the compression unit capacity from WIC to us continues for as long as
we have shipper agreements for service using the compressor unit capacity. The
parties to this agreement have agreed that the reciprocal leases provide
adequate compensation to each other so there is no rental fee for either lease
other than an agreement by WIC to reimburse us for any increase in operating
expense incurred by us (including increased taxes, insurance or other
expenses).
Other
Agreements and Transactions
In addition, we
currently have and will have in the future other routine agreements with El Paso
or one of its subsidiaries that arise in the ordinary course of business,
including 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.
Audit
Fees
The audit fees for
the years ended December 31, 2009 and 2008 of $792,000 and $751,000,
respectively, were primarily for professional services rendered by Ernst &
Young LLP for the audits of the consolidated financial statements of Colorado
Interstate Gas Company and its subsidiaries as well as the review of documents
filed with the SEC and related consent.
All
Other Fees
No other
audit-related, tax or other services were provided by our independent registered
public accounting firm for the years ended December 31, 2009 and
2008.
Policy
for Approval of Audit and Non-Audit Fees
We are a majority
owned subsidiary of both El Paso and EPB and do not have a separate audit
committee. El Paso’s and EPB’s Audit Committees have
adopted pre-approval policies for audit and non-audit services. For a
description of El Paso’s pre-approval policies for audit and non-audit related
services, see El Paso Corporation’s proxy statement for its 2010 Annual Meeting
of Stockholders. For a description of EPB’s pre-approval for audit
and non-audit related services, see EPB’s Annual Report on Form 10-K for the
year ended December 31, 2009.
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(a)
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The following documents are
filed as part of this
report:
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1. Financial
statements
The following
consolidated financial statements are included in Part II, Item 8, of this
report:
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Page
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|
Report of
Independent Registered Public Accounting Firm
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28
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|
Consolidated
Statements of Income
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29
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|
Consolidated
Balance Sheets
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30
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|
Consolidated
Statements of Cash Flows
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31
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|
Consolidated
Statements of Partners’ Capital/ Stockholder’s Equity
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32
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Notes to
Consolidated Financial Statements
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33
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2. Financial
statement schedules
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|
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Schedule II —
Valuation and Qualifying Accounts
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49
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All other schedules
are omitted because they are not applicable, or the required information is
disclosed in the financial statements or accompanying notes.
3.
Exhibits
The Exhibit Index,
which follows the signature page to this report and is hereby incorporated
herein by reference, sets forth a list of those exhibits filed herewith, and
includes and identifies contracts or arrangements required to be filed as
exhibits to this Form 10-K by Item 601(b) (10)(iii) of Regulation
S-K.
The agreements
included as exhibits to this report are intended to provide information
regarding their terms and not to provide any other factual or disclosure
information about us or the other parties to the agreements. The agreements may
contain representations and warranties by the parties to the agreements,
including us, solely for the benefit of the other parties to the applicable
agreement and:
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•
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should not in
all instances be treated as categorical statements of fact, but rather as
a way of allocating the risk to one of the parties if those statements
prove to be inaccurate;
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|
•
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may have been
qualified by disclosures that were made to the other party in connection
with the negotiation of the applicable agreement, which disclosures are
not necessarily reflected in the
agreement;
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|
•
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may apply
standards of materiality in a way that is different from what may be
viewed as material to certain investors;
and
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|
•
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were made
only as of the date of the applicable agreement or such other date or
dates as may be specified in the agreement and are subject to more recent
developments.
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Accordingly, these
representations and warranties may not describe the actual state of affairs as
of the date they were made or at any other time.
Undertaking
We hereby
undertake, pursuant to Regulation S-K, Item 601(b), paragraph (4) (iii), to
furnish to the SEC upon request all constituent instruments defining the rights
of holders of our long-term debt and our consolidated subsidiaries not filed
herewith for the reason that the total amount of securities authorized under any
of such instruments does not exceed 10 percent of our total consolidated
assets.
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 26th day
of February 2010.
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COLORADO
INTERSTATE GAS COMPANY
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By:
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/s/ James J. Cleary | |
| James J. Cleary | |||
| President | |||
Pursuant to the
requirements of the Securities Exchange Act of 1934, this report has been signed
below by the following persons on behalf of Colorado Interstate Gas Company and
in the capacities and on the dates indicated:
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Signature
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Title
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Date
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/s/ James J.
Cleary
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President and
Management Committee Member
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February 26,
2010
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James J.
Cleary
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(Principal
Executive Officer)
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/s/ John R. Sult
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Senior Vice
President and
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February 26,
2010
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John R.
Sult
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Chief
Financial Officer
(Principal
Financial Officer)
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/s/ Rosa P. Jackson
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Vice
President and Controller
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February 26,
2010
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Rosa P. Jackson
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(Principal
Accounting Officer)
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/s/ James C. Yardley
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Management
Committee Member
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February 26,
2010
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James C.
Yardley
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||
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/s/ Daniel B. Martin
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Senior Vice
President and Management
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February 26,
2010
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Daniel B.
Martin
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Committee
Member
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/s/ Thomas L. Price
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Vice
President and Management Committee
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February 26,
2010
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Thomas L.
Price
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Member
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COLORADO
INTERSTATE GAS COMPANY
December
31, 2009
Each exhibit
identified below is filed as part of this report. Exhibits filed with this
report are designated by “*”. All exhibits not so designated are incorporated
herein by reference to a prior filing as indicated.
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Exhibit
Number
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Description
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||
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3.A
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Certificate
of Conversion (Exhibit 3.A to our Current Report on Form 8-K
filed with the SEC on November 7, 2007).
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||
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3.B
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Statement of
Partnership Existence (Exhibit 3.B to our Current Report on
Form 8-K filed with the SEC on November 7,
2007).
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||
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3.C
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General
Partnership Agreement dated November 1, 2007 (Exhibit 3.C to our
Current Report on Form 8-K filed with the SEC on November 7,
2007).
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||
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3.D
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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).
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||
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3.E
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Second
Amendment to the General Partnership Agreement of Colorado Interstate Gas
Company, dated July 24, 2009 (Exhibit 3 to our Current Report on Form 8-K
filed with the SEC on July 30, 2009).
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||
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*4.A
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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.
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||
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*4.A.1
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First
Supplemental Indenture dated as of June 27, 1997, between Colorado
Interstate Gas Company and The Bank of New York Trust Company, N.A., as
trustee.
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||
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*4.A.2
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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.
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||
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*4.A.3
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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.
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||
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4.A.4
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Fourth
Supplemental Indenture dated October 15, 2007 by and between Colorado
Interstate Gas Company and The Bank of New York Trust Company, N.A., as
trustee (Exhibit 4.A to our Current Report on Form 8-K filed
with the SEC on October 16, 2007).
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||
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4.A.5
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Fifth
Supplemental Indenture dated November 1, 2007 by and among Colorado
Interstate Gas Company, Colorado Interstate Issuing Corporation, and The
Bank of New York Trust Company, N.A., as trustee (Exhibit 4.A to our
Current Report on Form 8-K filed with the SEC on November 7,
2007).
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||
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*10.A
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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.
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||
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*10.B
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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.
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||
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*10.C
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Lease
Agreement dated December 17, 2008, and effective on November 1, 2008, by
and between WYCO Development LLC and Colorado Interstate Gas
Company.
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||
| *12 | Ratio of Earnings to Fixed Charges. | ||
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*21
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Subsidiaries
of Colorado Interstate Gas Company.
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||
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*23
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Consent of
Independent Registered Public Accounting Firm Ernst & Young
LLP.
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||
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*31.A
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Certification
of Principal Executive Officer pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002.
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*31.B
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Certification
of Principal Financial Officer pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002.
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||
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*32.A
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Certification
of Principal Executive Officer pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002.
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||
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*32.B
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Certification
of Principal Financial Officer pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002.
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60