epng200910k.htm
UNITED
STATES SECURITIES AND EXCHANGE COMMISSION
Washington,
D.C. 20549
________________
Form
10-K
(Mark
One)
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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 1-2700
El
Paso Natural Gas Company
(Exact Name of
Registrant as Specified in Its Charter)
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Delaware
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74-0608280
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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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1001
Louisiana Street
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Houston,
Texas
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77002
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(Address of
Principal Executive Offices)
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(Zip
Code)
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Telephone
Number: (713) 420-2600
Securities
registered pursuant to Section 12(b) of the Act: None
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 stock held by non-affiliates of the registrant:
None
Indicate the number of shares
outstanding of each of the registrant’s classes of common stock, as of the latest
practicable date.
Common Stock, par
value $1 per share. Shares outstanding on March 1, 2010: 1,000
EL PASO NATURAL GAS COMPANY MEETS THE
CONDITIONS OF GENERAL INSTRUCTION I(1)(a) AND (b) TO FORM 10-K AND IS
THEREFORE FILING THIS REPORT WITH A REDUCED DISCLOSURE FORMAT AS PERMITTED BY
SUCH INSTRUCTION.
Documents
Incorporated by Reference: None
EL
PASO NATURAL GAS COMPANY
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*
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We have not
included a response to this item in this document since no response is
required pursuant to the reduced disclosure format permitted by General
Instruction I to Form 10-K.
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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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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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Tonne
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=
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metric
ton
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LNG
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=
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liquefied
natural gas
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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 “EPNG”, we are describing El Paso Natural Gas
Company and/or our subsidiaries.
Overview
and Strategy
We are a Delaware
corporation incorporated in 1928, and an indirect wholly owned subsidiary of El
Paso Corporation (El Paso). Our primary business consists of the interstate
transportation and storage of natural gas. We conduct our business activities
through our natural gas pipeline systems and a storage facility as discussed
below.
Each of our
pipeline systems and our storage facility operates under tariffs approved by the
Federal Energy Regulatory Commission (FERC) that establish rates, cost recovery
mechanisms and other terms and conditions of services to our customers. The fees
or rates established under our tariffs are a function of our costs of providing
services to our customers, including a reasonable return on our invested
capital.
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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developing
new growth projects in our market and supply
areas;
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maintaining
the integrity and ensuring the safety of our pipeline systems 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
systems.
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The EPNG System. The EPNG
system consists of approximately 10,200 miles of pipeline with a winter
sustainable west-flow capacity of 4,850 MMcf/d and east-end deliverability of
800 MMcf/d. During 2009, 2008 and 2007, average throughput was 3,937 BBtu/d,
4,379 BBtu/d and 4,189 BBtu/d. This system delivers natural gas from the San
Juan, Permian, Anadarko basins and via interconnections in the Rocky Mountains
to markets in California, Arizona, Nevada, New Mexico, Oklahoma, Texas and
northern Mexico.
The Mojave Pipeline Company (Mojave)
System. The Mojave system consists of approximately 500 miles of
pipeline with an east to west flow design capacity of approximately 400 MMcf/d.
During 2009, 2008 and 2007, average throughput was 379 BBtu/d, 349 BBtu/d and
458 BBtu/d. Mojave’s 2009, 2008 and 2007 throughput includes 334 BBtu/d, 306
BBtu/d and 431 BBtu/d transported volume for the EPNG system. The Mojave system
connects with the EPNG system near Cadiz, California, the EPNG and Transwestern
systems at Topock, Arizona and to the Kern River Gas Transmission Company system
in California. This system also extends to customers in the vicinity of
Bakersfield, California.
Storage Facility. We
utilize our Washington Ranch underground storage facility located in New Mexico,
which has up to approximately 44 Bcf of underground working natural gas storage
capacity, to manage our transportation needs and to offer interruptible storage
services.
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
systems connect 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.
Imported LNG has
been a significant supply source for the North American market. LNG terminals
and other regasification facilities can serve as alternate sources of supply for
pipelines, enhancing their delivery capabilities and operational flexibility and
complementing traditional supply transported into market areas. However, these
LNG delivery systems may also compete with us for transportation of gas into
market areas we serve.
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.
We provide
transportation services to the southwestern U.S. and to the Mexican border
through connections to other pipelines. The market demand for natural gas
distribution as well as gas-fired electric generation capacity has experienced
considerable growth in these areas in recent years. Historically, California
customers have been the largest holders of capacity on our EPNG system.
Currently, California and Arizona customers account for the majority of
transportation on the EPNG system, followed by Texas and New Mexico. The EPNG
system also delivers natural gas to the U.S./Mexico Border serving customers in
Chihuahua, Sonora, and Baja California, which are located in
Mexico.
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 pipelines could experience some level of reduced throughput and revenues, or
slower development of expansion projects as a result of these factors, each
generates a significant (greater than 80 percent) portion of their revenues
through fixed monthly reservation or demand charges on long-term contracts at
rates stipulated under our tariffs or in our contracts.
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.
The EPNG system
faces competition in the west and southwest from other existing and proposed
pipelines, from California storage facilities, and from alternative energy
sources that are used to generate electricity such as hydroelectric power,
nuclear energy, wind, solar, coal and fuel oil. We also face competition from
LNG facilities located in northern Mexico.
The Mojave system
faces competition from other existing and proposed pipelines and alternative
energy sources that are used to generate electricity such as hydroelectric
power, nuclear energy, wind, solar, coal and fuel oil. We also face competition
from LNG facilities located in northern Mexico.
The following table
details our customer and contract information for each of our pipeline systems
as of December 31, 2009. Firm customers reserve capacity on our pipeline systems
and storage facility 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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Pipeline System
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Customer Information
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Contract Information
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EPNG
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Approximately
160 firm and interruptible customers.
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Approximately
190 firm transportation contracts. Weighted average remaining contract
term of approximately three years.
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Major
Customers:
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Sempra Energy
and Subsidiaries, including Southern California Gas Company
(SoCal)
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(374
BBtu/d)
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Expires in
2010.
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(334
BBtu/d)
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Expires in
2011.
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( 12
BBtu/d)
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Expires in
2014.
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ConocoPhillips
Company
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(350
BBtu/d)
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Expires in
2010.
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( 35
BBtu/d)
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Expires in
2011.
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(392
BBtu/d)
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Expires in
2012.
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Southwest Gas
Corporation
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(412
BBtu/d)
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Expires in
2011.
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( 75
BBtu/d)
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Expires in
2015.
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Mojave
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Approximately
10 firm and interruptible customers.
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Approximately
three firm transportation contracts. Weighted average remaining contract
term of approximately six years.
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Major
Customer:
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EPNG
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(312
BBtu/d)
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Expires in
2015.
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Regulatory
Environment
Our interstate
natural gas transmission systems 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 establish 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;
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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 systems are 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 systems are 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 6, and is incorporated herein by
reference.
Employees
As of February 23,
2010, we had approximately 560 full-time employees, none of whom are subject to
a collective bargaining arrangement.
CAUTIONARY STATEMENT FOR PURPOSES OF
THE “SAFE HARBOR” PROVISIONS OF
THE
PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995
This report
contains forward-looking statements within the meaning of the Private Securities
Litigation Reform Act of 1995. These forward-looking statements are based on
assumptions or beliefs that we believe to be reasonable; however, assumed facts
almost always vary from actual results, and differences between assumed facts
and actual results can be material, depending upon the circumstances. Where,
based on assumptions, we or our management express an expectation or belief as
to future results, that expectation or belief is expressed in good faith and is
believed to have a reasonable basis. We cannot assure you, however, that the
stated expectation or belief will occur, be achieved or accomplished. The words
“believe,” “expect,” “estimate,” “anticipate,” and similar expressions will
generally identify forward-looking statements. All of our forward-looking
statements, whether written or oral, are expressly qualified by these cautionary
statements and any other cautionary statements that may accompany such
forward-looking statements. In addition, we disclaim any obligation to update
any forward-looking statements to reflect events or circumstances after the date
of this report.
With this in mind,
you should consider the risks discussed elsewhere in this report and other
documents we file with the Securities and Exchange Commission (SEC) from time to
time and the following important factors that could cause actual results to
differ materially from those expressed in any forward-looking statement made by
us or on our behalf.
Risks
Related to Our Business
Our success
depends on factors beyond our control.
The financial
results of our transportation and storage operations are impacted by the volumes
of natural gas we transport or store and the prices we are able to charge for
doing so. The volume of natural gas we are able to transport and store depends
on the actions of third parties, and is beyond our control. This includes
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 systems:
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service area
competition;
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expiration or
turn back of significant contracts;
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changes in
regulation and action 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, such as
LNG;
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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;
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expiration or
renewal of existing interests in real property including real property on
Native American lands; 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 additional
information on our revenues from our major customers, see Part II, Item 8,
Financial Statements and Supplementary Data, Note 8. The loss of any one of
these customers or a decline in their 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.
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
systems, which requires the development of additional oil and natural gas
reserves and obtaining additional supplies from interconnecting pipelines. 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 systems.
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 the pipeline’s 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 the pipeline’s 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.
If natural gas
prices in the supply basins connected to our pipeline systems 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 transportation and storage of natural
gas;
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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. In June 2008, we filed a rate case
with the FERC as required under the settlement of our previous rate case. The
filing proposed an increase in base tariff rates on our EPNG system. In August
2008, the FERC issued an order accepting the proposed rates effective January 1,
2009, subject to refund and the outcome of a hearing and a technical conference.
The FERC issued an order in December 2008 that generally accepted most of our
proposals in the technical conference proceeding. The FERC has appointed an
administrative law judge to preside over a hearing if we are unable to reach a
negotiated settlement with our customers on the remaining issues. Settlement
negotiations are continuing; however the hearing has been postponed until May
2010. The outcome of the settlement discussions or the hearing is not
currently determinable.
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 systems and that a successful
complaint against our rates could have an adverse impact on our cash flows and
results of operations.
Also, increased
regulatory requirements relating to the integrity of our pipelines requires
additional spending in order to maintain compliance with these requirements. Any
additional requirements that are enacted could significantly increase the amount
of these expenditures. Further, state agencies that regulate our local
distribution company customers could impose requirements that could impact
demand for our services.
Environmental
compliance and remediation costs and the costs of environmental liabilities could
exceed our estimates.
Our operations are
subject to various environmental laws and regulations regarding compliance and
remediation obligations. Compliance obligations can result in significant costs
to install and maintain pollution controls, fines and penalties resulting from
any failure to comply and potential limitations on our operations. Remediation
obligations can result in significant costs associated with the investigation or
clean up of contaminated properties (some of which have been designated as
Superfund sites by the U. S. Environmental Protection Agency (EPA) under the
Comprehensive Environmental Response, Compensation and Liability Act), as well
as damage claims arising out of the contamination of properties or impact on
natural resources. Although we believe we have established appropriate reserves
for our environmental liabilities, it is not possible for us to estimate the
exact amount and timing of all future expenditures related to environmental
matters and we could be required to set aside additional amounts which could
significantly impact our future consolidated results of operations, financial
position or cash flows. See Part II, Item 8, Financial Statements and
Supplementary Data, Note 6.
In estimating our
environmental liabilities, we face uncertainties that include:
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estimating
pollution control and clean up costs, including sites where preliminary
site investigation or assessments have been
completed;
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discovering
new sites or additional information at existing
sites;
|
|
|
•
|
forecasting
cash flow timing to implement proposed pollution control and cleanup
costs;
|
|
|
•
|
receiving
regulatory approval for remediation
programs;
|
|
|
•
|
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;
|
|
|
•
|
interpreting 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 systems,
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 pipelines 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 pipelines or our storage facility by constructing
additional facilities. Construction of these facilities is subject to various
regulatory, development and operational risks, including:
|
|
•
|
our ability
to obtain necessary approvals and permits by the FERC and other regulatory
agencies on a timely basis and on terms that are acceptable to us,
including the potential impact of delays and increased costs caused by
certain environmental and landowner groups with interests along the route
of our pipelines;
|
|
|
•
|
the ability
to access sufficient capital at reasonable rates to fund expansion
projects, especially in periods of prolonged economic decline when we may
be unable to access the capital
markets;
|
|
|
•
|
the
availability of skilled labor, equipment, and materials to complete
expansion projects;
|
|
|
•
|
potential
changes in federal, state and local statutes, regulations and orders, such
as environmental requirements, including climate change requirements, that
delay or prevent a project from proceeding or increase the anticipated
cost of the project;
|
|
|
•
|
impediments
on our ability to acquire rights-of-way or land rights or to commence and
complete construction on a timely basis or on terms that are acceptable to
us;
|
|
|
•
|
our ability
to construct projects within anticipated costs, including the risk that we
may incur cost overruns resulting from inflation or increased costs of
equipment, materials, labor, contractor productivity, delays in
construction or other factors beyond our control, that we may not be able
to recover from our customers which may be
material;
|
|
|
•
|
the lack of
future growth in natural gas supply and/or demand;
and
|
|
|
•
|
the lack of
transportation, storage or throughput
commitments.
|
Any of these risks
could prevent a project from proceeding, delay its completion or increase its
anticipated costs. There is also the risk that the downturn in the economy and
its negative impact upon natural gas demand may result in either slower
development in our expansion projects or adjustments in the contractual
commitments supporting such projects. As a result, new facilities may be delayed
or we may not achieve our expected investment return, which could adversely
affect our results of operations, cash flows or financial position.
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 we are unable
to retain and recruit employees such as engineers and other technical personnel,
our business could be negatively impacted.
Adverse general
domestic economic conditions could negatively affect our operating
results, financial condition or liquidity.
We, El Paso, and
its subsidiaries are subject to the risks arising from adverse changes in
general domestic economic conditions including recession or economic slowdown.
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 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 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:
|
|
•
|
the
structured and commercial financial
markets;
|
|
|
•
|
market
perceptions of us or the natural gas and energy
industry;
|
|
|
•
|
tax rates due
to new tax laws; and
|
|
|
•
|
market prices
for hydrocarbon products.
|
Risks
Related to Our Affiliation with El Paso
El Paso files
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 an
indirect wholly owned subsidiary of El Paso.
As an indirect
wholly owned subsidiary of El Paso, subject to limitations in our credit
agreements and indentures, El Paso has substantial control over:
|
|
•
|
our payment
of dividends;
|
|
|
•
|
decisions on
our financing and capital raising
activities;
|
|
|
•
|
mergers or
other business combinations;
|
|
|
•
|
our
acquisitions or dispositions of assets;
and
|
|
|
•
|
our
participation in El Paso’s cash management
program.
|
El Paso may
exercise such control in its interests and not necessarily in the interests of
us or the holders of our long-term debt.
Our relationship
with El Paso and its financial condition subjects us to potential risks
that are beyond our control.
Due to our
relationship with El Paso, adverse developments or announcements concerning El
Paso or its other subsidiaries could adversely affect our financial condition,
even if we have not suffered any similar development. The ratings assigned to El
Paso’s senior unsecured indebtedness are below investment grade, currently rated
Ba3 by Moody’s Investor Service, BB- by Standard & Poor’s and BB+ by Fitch
Ratings. The ratings assigned to our senior unsecured indebtedness are currently
investment grade, with a Baa3 rating by Moody’s Investor Service and a BBB-
rating by Fitch Ratings. Standard & Poor’s has assigned a below investment
grade rating of BB to our senior unsecured indebtedness. El Paso and its
subsidiaries, including us, are (i) on a stable outlook with Moody’s Investor
Service and Fitch Ratings and (ii) on a negative outlook with Standard &
Poor’s. There is a risk that these credit ratings may be adversely affected in
the future as 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 and collateral requirements.
El Paso provides
cash management and other corporate services for us. Pursuant to El Paso’s cash
management program, we transfer surplus cash to El Paso in exchange for an
affiliated note receivable. In addition, we conduct commercial transactions with
some of our affiliates. If El Paso or such affiliates are unable to meet their
respective liquidity needs, we may not be able to access cash under the cash
management program, or our affiliates may not be able to pay their obligations
to us. However, we might still be required to satisfy 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 10.
We may be subject
to a change of control if an event of default occurs under El Paso’s credit
agreement.
Under El Paso’s
$1.5 billion credit agreement, our common stock and the common stock of one of
El Paso’s other subsidiaries are pledged as collateral. As a result, our
ownership is subject to change if there is a default under the credit agreement
and El Paso’s lenders exercise rights over their collateral, even if we do not
have any borrowings outstanding under the credit agreement. For additional
information concerning El Paso’s credit facility, see Part II, Item 8, Financial
Statements and Supplementary Data, Note 5.
A default under
El Paso’s $1.5 billion credit agreement by any party could accelerate our
future borrowings, if any, under the credit agreement and our long-term debt,
which could adversely affect our liquidity position.
We are a party to
El Paso’s $1.5 billion credit agreement. We are only liable, however, for our
borrowings under the credit agreement, which were zero at December 31, 2009.
Under the credit agreement, a default by El Paso, or any other borrower could
result in the acceleration of repayment of all outstanding borrowings, including
the borrowings of any non-defaulting party. The acceleration of repayments of
borrowings, if any, or the inability to borrow under the credit agreement, could
adversely affect our liquidity position and, in turn, our financial
condition.
Furthermore, the
indentures governing some of our long-term debt contain cross-acceleration
provisions, the most restrictive of which is $25 million. Therefore, if we
borrow $25 million or more under El Paso’s $1.5 billion credit agreement and
such borrowings are accelerated for any reason, including the default of another
party under the credit agreement, our long-term debt that contains these
provisions could also be accelerated. The acceleration of our long-term debt
could also adversely affect our liquidity position and, in turn, our financial
condition.
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 business,
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 6, and is incorporated herein by
reference.
Information has
been omitted from this report pursuant to the reduced disclosure format
permitted by General Instruction I to Form 10-K.
All of our common
stock, par value $1 per share, is owned by a subsidiary of El Paso and,
accordingly, our stock is not publicly traded.
We pay dividends on
our common stock from time to time from legally available funds that have been
approved for payment by our Board of Directors. During both 2009 and
2008, we utilized $200 million of our note receivable from the cash management
program to pay dividends to our parent.
Information has
been omitted from this report pursuant to the reduced disclosure format
permitted by General Instruction I to Form 10-K.
The information
required by this Item is presented in a reduced disclosure format pursuant to
General Instruction I to Form 10-K. 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.
Overview
Our primary
business consists of the interstate transportation and storage of natural gas.
Each of these businesses faces varying degrees of competition from other
existing and proposed pipelines and LNG facilities, as well as from alternative
energy sources used to generate electricity, such as hydroelectric power,
nuclear energy, wind, solar, coal and fuel oil. Our revenues from transportation
and storage services consist of the following types.
|
Type
|
Description
|
Percent
of Total
Revenues in 2009
|
|
Reservation
|
Reservation
revenues are from customers (referred to as firm customers) that reserve
capacity on our pipeline systems and storage facility. 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.
|
87
|
|
|
|
|
|
Usage and
Other
|
Usage
revenues are from both firm customers and interruptible customers (those
without reserved capacity) that pay usage charges based on the volume of
gas actually transported, stored, injected or withdrawn. We also earn
revenue from other miscellaneous sources.
|
13
|
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. On October 1, 2009, we received an order from the FERC directing us to
remove the cost and revenue component of our fuel recovery mechanism. Our
compliance filing, to remove the cost and revenue component, was approved in the
fourth quarter of 2009. Due to this order, our future earnings may be impacted
by both positive and negative fluctuations in gas prices related to the
revaluation of our fuel under or over recoveries, imbalances and system
encroachments. Our tariff continues to provide that the difference between
the quantity of fuel retained and fuel used in operations and lost and
unaccounted for will be flowed-through or charged to shippers. These fuel
trackers remove the impact of over or under collecting fuel and lost and
unaccounted for gas from our operational gas costs.
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 three 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
(1))
|
|
|
|
|
|
(In
millions)
|
|
|
|
|
|
2010
|
|
|
2,125 |
|
|
|
39 |
|
|
$ |
85 |
|
|
|
20 |
|
|
2011
|
|
|
1,300 |
|
|
|
24 |
|
|
|
133 |
|
|
|
32 |
|
|
2012
|
|
|
665 |
|
|
|
12 |
|
|
|
76 |
|
|
|
19 |
|
|
2013
|
|
|
269 |
|
|
|
5 |
|
|
|
25 |
|
|
|
6 |
|
|
2014
|
|
|
222 |
|
|
|
4 |
|
|
|
13 |
|
|
|
3 |
|
|
2015 and
beyond
|
|
|
848 |
|
|
|
16 |
|
|
|
85 |
|
|
|
20 |
|
|
Total
|
|
|
5,429 |
|
|
|
100 |
|
|
$ |
417 |
|
|
|
100 |
|
____________
|
(1)
|
Excludes
EPNG contracted capacity on the Mojave
system.
|
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. We believe EBIT is
useful to investors to provide them with the same measure used by El Paso
Corporation (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 net income, our throughput volumes and an analysis and discussion of our
results for the year ended December 31, 2009 compared with 2008.
Operating
Results:
|
|
|
2009
|
|
|
2008
|
|
|
|
|
(In millions,
|
|
|
|
|
except
for volumes)
|
|
|
Operating
revenues
|
|
$ |
593 |
|
|
$ |
590 |
|
|
Operating
expenses
|
|
|
(314 |
) |
|
|
(333 |
) |
|
Operating
income
|
|
|
279 |
|
|
|
257 |
|
|
Other income,
net
|
|
|
2 |
|
|
|
5 |
|
|
EBIT
|
|
|
281 |
|
|
|
262 |
|
|
Interest and
debt expense
|
|
|
(93 |
) |
|
|
(90 |
) |
|
Affiliated
interest income, net
|
|
|
19 |
|
|
|
46 |
|
|
Income tax
expense
|
|
|
(79 |
) |
|
|
(83 |
) |
|
Net
income
|
|
$ |
128 |
|
|
$ |
135 |
|
|
Throughput
volumes (BBtu/d)(1)
|
|
|
3,982 |
|
|
|
4,422 |
|
____________
|
(1)
|
Throughput
volumes exclude throughput transported on the Mojave system on behalf of
EPNG.
|
EBIT
Analysis:
|
|
|
Revenue
|
|
|
Expense
|
|
|
Other
|
|
|
Total
|
|
|
|
|
Favorable/(Unfavorable)
|
|
|
|
|
(In
millions)
|
|
|
Reservation
and other services revenues
|
|
$ |
11 |
|
|
$ |
— |
|
|
$ |
— |
|
|
$ |
11 |
|
|
Enron
bankruptcy settlement
|
|
|
(8 |
) |
|
|
(2 |
) |
|
|
— |
|
|
|
(10 |
) |
|
Operational
gas and revaluations
|
|
|
— |
|
|
|
4 |
|
|
|
— |
|
|
|
4 |
|
|
Operating and
general and administrative expenses
|
|
|
— |
|
|
|
5 |
|
|
|
— |
|
|
|
5 |
|
|
Asset
impairments
|
|
|
— |
|
|
|
14 |
|
|
|
— |
|
|
|
14 |
|
|
Other (1)
|
|
|
— |
|
|
|
(2 |
) |
|
|
(3 |
) |
|
|
(5 |
) |
|
Total impact
on EBIT
|
|
$ |
3 |
|
|
$ |
19 |
|
|
$ |
(3 |
) |
|
$ |
19 |
|
____________
|
(1)
|
Consists
of individually insignificant
items.
|
Reservation and Other Services
Revenues. Our reservation and other services revenues were higher for the
year ended December 31, 2009 compared to 2008, primarily due to an increase of
approximately $15 million in reservation charges for capacity on our EPNG system
resulting from higher contracted capacity to primary delivery points in
California and an increase in EPNG’s tariff rates effective January 1, 2009,
subject to refund, offset by a decrease of approximately $4 million in usage
revenue primarily due to decreased throughput. We may or may not be able to
sustain higher levels of contracted capacity by our customers in the
future.
During 2009, our
throughput volumes decreased compared with 2008. This was due, in
part, to a decrease in natural gas and electric generation demand due to weak
macroeconomic conditions in the southwestern U.S., as well as the introduction
in April 2009 of a new interstate natural gas pipeline with approximately 500
MDth/d of capacity serving the greater Phoenix, Arizona area. Additionally,
although a reduction in throughput on our system is not material to our
short-term financial results due to a substantial portion of our revenues being
based on firm reservation charges under long-term contracts, it can be an
indication of the risks we may face when seeking to recontract or renew any of
our existing firm transportation contracts in the future. If these macroeconomic
conditions continue, it could negatively impact basis differentials over the
longer term and our ability to renew firm transportation contracts that are
expiring on our system or our ability to renew such contracts at current
rates. If, however, we determine there is a significant change in our
cost of providing service or billing determinants, we have the option to file a
future rate case with the FERC to recover our prudently incurred costs.
Enron Bankruptcy Settlement.
During 2008, we recorded income of approximately $10 million, net of
amounts owed to certain customers as a result of settlements received from the
Enron bankruptcy.
Operational Gas and
Revaluations. On October 1, 2009, we received an order from
the FERC directing us to remove the cost and revenue component of our fuel
recovery mechanism on our EPNG system. Our compliance filing to
remove the cost and revenue component was approved in the fourth quarter of
2009. Due to this order, our future earnings may be impacted positively or
negatively depending on fluctuations in gas prices related to the revaluation of
our under or over recoveries, imbalances and system
encroachments. 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.
Operating and General and
Administrative Expenses. During the year ended December 31, 2009, our
operating and general and administrative expenses were lower primarily as a
result of decreased repair and maintenance expenses.
Asset Impairments. During
2008, we recorded impairments of approximately $14 million due to declining real
estate values related to our Arizona storage projects, which we are no longer
developing.
EPNG Regulatory
Matters. In June 2008, we filed a rate case with the
FERC as required under the settlement of our previous rate case. The filing
proposed an increase in base tariff rates on our EPNG system, which would
increase revenue by $83 million annually over previously effective tariff rates.
In August 2008, the FERC issued an order accepting the proposed rates effective
January 1, 2009, subject to refund and the outcome of a hearing and a technical
conference. The FERC issued an order in December 2008 that generally accepted
most of our proposals in the technical conference proceeding. The FERC has
appointed an administrative law judge to preside over a hearing if we are unable
to reach a negotiated settlement with our customers on the remaining issues.
Settlement negotiations are continuing; however the hearing has been postponed
until May 2010. The outcome of the settlement discussions or the
hearing is not currently determinable.
Interest
and Debt Expense
Interest and debt
expense for the year ended December 31, 2009, was $3 million higher than in 2008
primarily due to interest recorded in 2009 for EPNG’s rate refund provision
related to its rate case effective January 1, 2009, and lower capitalized
interest on allowance for funds used during construction due to lower capital
expenditures.
Affiliated
Interest Income, Net
Affiliated interest
income, net for the year ended December 31, 2009, was $27 million lower than in
2008 primarily due to lower average short-term interest rates on average
advances to El Paso under its cash management program. The following table shows
the average advances due from El Paso and the average short-term interest rates
for the year ended December 31:
|
|
|
2009
|
|
|
2008
|
|
|
|
|
(In billions, except for
rates)
|
|
|
Average
advance due from El Paso
|
|
$ |
1.1 |
|
|
$ |
1.1 |
|
|
Average
short-term interest rate
|
|
|
1.7 |
% |
|
|
4.4 |
% |
Income
Taxes
Our effective tax
rate of 38 percent for the years ended December 31, 2009 and 2008 was higher
than the statutory rate of 35 percent in both periods due to the effect of state
income taxes. For a reconciliation of the statutory rate to the effective tax
rates, see Item 8, Financial Statements and Supplementary Data, Note
2.
Liquidity
and Capital Resources
Our primary sources
of liquidity are cash flows from operating activities and amounts available to
us under El Paso’s cash management program. During 2009, we
utilized $200 million of our note receivable from the cash management program to
pay dividends to our parent. At December 31, 2009, we had a note
receivable from El Paso of approximately $1.0 billion of which
approximately $103 million was classified as current based on the net amount we
anticipate using in the next twelve months considering available cash sources
and needs. See Item 8, Financial Statements and Supplementary Data, Note
10, for a further discussion of El Paso’s cash management program. Our primary
uses of cash are for working capital, capital expenditures and debt service
requirements. Our cash capital expenditures for the year ended
December 31, 2009 and those planned for 2010 are listed below.
|
|
|
2009
|
|
|
Expected
2010
|
|
|
|
|
(In
millions)
|
|
|
Maintenance
|
|
$ |
112 |
|
|
$ |
113 |
|
|
Expansion/Other
|
|
|
4 |
|
|
|
7 |
|
|
Total
|
|
$ |
116 |
|
|
$ |
120 |
|
Our 2010
maintenance capital expenditures 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. Our expansion and
other capital expenditures primarily relate to expanding the capacity and
services of our pipeline systems.
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 flows from operating activities and
amounts available to us under El Paso’s cash management program. 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. In addition to the cash management
program above, we are eligible to borrow amounts available under El Paso’s
$1.5 billion credit agreement and are only liable for amounts we directly
borrow. As of December 31, 2009, El Paso had approximately $0.8 billion of
capacity remaining and available to us and our affiliates under this credit
agreement, and none of the amount outstanding under the facility was issued or
borrowed by us. 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.
Commitments
and Contingencies
For a further
discussion of our commitments and contingencies, see Item 8, Financial
Statements and Supplementary Data, Note 6, 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 3.6 million tonnes of carbon dioxide
equivalent emissions during 2008. We believe that approximately 3.2 million
tonnes of the GHG emissions that we reported to CCAR 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 59 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 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 systems. 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 $9 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 at 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.
New
Accounting Pronouncements Issued But Not Yet Adopted
As of December 31,
2009, the new accounting standards issued but not yet adopted by us did not have
any impact on our financial statements.
We are exposed to
the risk of changing interest rates. At December 31, 2009, we had an interest
bearing note receivable from El Paso of approximately $1.0 billion, with a
variable interest rate of 1.5% that is due upon demand. While we are exposed to
changes in interest income based on changes to the variable interest rate, the
fair value of this note receivable approximates the carrying value due to the
note being due on demand and the market-based nature of the interest
rate.
The table below
shows the carrying value, the related weighted-average effective interest rates
on our non-affiliated fixed rate long-term debt securities and the fair value of
these securities estimated based on quoted market prices for the same or similar
issues.
|
|
|
December 31, 2009
|
|
|
|
|
|
|
|
Expected
Fiscal Year of Maturity of
Carrying Amounts
|
|
|
|
|
|
December 31, 2008
|
|
|
|
|
2010
|
|
|
2014
and Thereafter
|
|
|
Total
|
|
|
Fair
Value
|
|
|
Carrying
Amount
|
|
|
Fair
Value
|
|
|
|
|
(In
millions, except for rates)
|
|
|
Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term
debt — fixed rate
|
|
$ |
54 |
|
|
$ |
1,113 |
|
|
$ |
1,167 |
|
|
$ |
1,300 |
|
|
$ |
1,166 |
|
|
$ |
1,021 |
|
|
Average
effective interest rate
|
|
|
7.8 |
% |
|
|
7.5 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
The Board of
Directors and Stockholder of El Paso Natural Gas Company
We have audited the
accompanying consolidated balance sheets of El Paso Natural Gas Company (the
Company) as of December 31, 2009 and 2008, and the related consolidated
statements of income, 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 El Paso Natural 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
March 1,
2010
EL
PASO NATURAL GAS COMPANY
CONSOLIDATED
STATEMENTS OF INCOME
(In
millions)
|
|
|
Year Ended December 31,
|
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
Operating
revenues
|
|
$ |
593 |
|
|
$ |
590 |
|
|
$ |
557 |
|
|
Operating
expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operation and
maintenance
|
|
|
202 |
|
|
|
213 |
|
|
|
201 |
|
|
Depreciation
and amortization
|
|
|
83 |
|
|
|
80 |
|
|
|
82 |
|
|
Loss on
long-lived assets
|
|
|
— |
|
|
|
14 |
|
|
|
9 |
|
|
Taxes, other
than income taxes
|
|
|
29 |
|
|
|
26 |
|
|
|
27 |
|
|
|
|
|
314 |
|
|
|
333 |
|
|
|
319 |
|
|
Operating
income
|
|
|
279 |
|
|
|
257 |
|
|
|
238 |
|
|
Other income,
net
|
|
|
2 |
|
|
|
5 |
|
|
|
4 |
|
|
Interest and
debt expense
|
|
|
(93 |
) |
|
|
(90 |
) |
|
|
(98 |
) |
|
Affiliated
interest income, net
|
|
|
19 |
|
|
|
46 |
|
|
|
71 |
|
|
Income before
income taxes
|
|
|
207 |
|
|
|
218 |
|
|
|
215 |
|
|
Income tax
expense
|
|
|
79 |
|
|
|
83 |
|
|
|
83 |
|
|
Net
income
|
|
$ |
128 |
|
|
$ |
135 |
|
|
$ |
132 |
|
See accompanying
notes.
EL
PASO NATURAL GAS COMPANY
CONSOLIDATED
BALANCE SHEETS
(In
millions, except for share amounts)
|
|
|
December 31,
|
|
|
|
|
2009
|
|
|
2008
|
|
|
ASSETS
|
|
|
|
|
|
|
|
Current
assets
|
|
|
|
|
|
|
|
Cash and cash
equivalents
|
|
$ |
— |
|
|
$ |
— |
|
|
Accounts and
notes receivable
|
|
|
|
|
|
|
|
|
|
Customer, net
of allowance of $2 in 2009 and 2008
|
|
|
56 |
|
|
|
66 |
|
|
Affiliates
|
|
|
111 |
|
|
|
6 |
|
|
Other
|
|
|
3 |
|
|
|
6 |
|
|
Materials and
supplies
|
|
|
47 |
|
|
|
43 |
|
|
Deferred
income taxes
|
|
|
35 |
|
|
|
12 |
|
|
Prepaids
|
|
|
15 |
|
|
|
15 |
|
|
Other
|
|
|
11 |
|
|
|
8 |
|
|
Total current
assets
|
|
|
278 |
|
|
|
156 |
|
|
Property,
plant and equipment, at cost
|
|
|
3,899 |
|
|
|
3,804 |
|
|
Less
accumulated depreciation and amortization
|
|
|
1,409 |
|
|
|
1,365 |
|
|
Total
property, plant and equipment, net
|
|
|
2,490 |
|
|
|
2,439 |
|
|
Other
assets
|
|
|
|
|
|
|
|
|
|
Note
receivable from affiliate
|
|
|
886 |
|
|
|
986 |
|
|
Other
|
|
|
110 |
|
|
|
103 |
|
|
|
|
|
996 |
|
|
|
1,089 |
|
|
Total
assets
|
|
$ |
3,764 |
|
|
$ |
3,684 |
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES
AND STOCKHOLDER’S EQUITY
|
|
|
|
|
|
|
|
|
|
Current
liabilities
|
|
|
|
|
|
|
|
|
|
Accounts
payable
|
|
|
|
|
|
|
|
|
|
Trade
|
|
$ |
83 |
|
|
$ |
48 |
|
|
Affiliates
|
|
|
42 |
|
|
|
21 |
|
|
Other
|
|
|
14 |
|
|
|
18 |
|
|
Current
maturities of long-term debt
|
|
|
54 |
|
|
|
— |
|
|
Taxes
payable
|
|
|
103 |
|
|
|
79 |
|
|
Accrued
interest
|
|
|
21 |
|
|
|
20 |
|
|
Accrued
liabilities
|
|
|
82 |
|
|
|
9 |
|
|
Regulatory
liabilities
|
|
|
17 |
|
|
|
33 |
|
|
Other
|
|
|
30 |
|
|
|
31 |
|
|
Total current
liabilities
|
|
|
446 |
|
|
|
259 |
|
|
Long-term
debt, less current maturities.
|
|
|
1,113 |
|
|
|
1,166 |
|
|
Other
liabilities
|
|
|
|
|
|
|
|
|
|
Deferred
income taxes
|
|
|
408 |
|
|
|
389 |
|
|
Other
|
|
|
71 |
|
|
|
72 |
|
|
|
|
|
479 |
|
|
|
461 |
|
|
Commitments
and contingencies (Note 6)
|
|
|
|
|
|
|
|
|
|
Stockholder’s
equity
|
|
|
|
|
|
|
|
|
|
Common stock,
par value $1 per share; 1,000 shares authorized, issued and
outstanding
|
|
|
— |
|
|
|
— |
|
|
Additional
paid-in capital
|
|
|
1,268 |
|
|
|
1,268 |
|
|
Retained
earnings
|
|
|
458 |
|
|
|
530 |
|
|
Total
stockholder’s equity
|
|
|
1,726 |
|
|
|
1,798 |
|
|
Total
liabilities and stockholder’s equity
|
|
$ |
3,764 |
|
|
$ |
3,684 |
|
See accompanying
notes.
EL
PASO NATURAL GAS COMPANY
CONSOLIDATED
STATEMENTS OF CASH FLOWS
(In
millions)
|
|
|
Year Ended December 31,
|
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
Cash flows
from operating activities
|
|
|
|
|
|
|
|
|
|
|
Net
income
|
|
$ |
128 |
|
|
$ |
135 |
|
|
$ |
132 |
|
|
Adjustments
to reconcile net income to net cash from operating
activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation
and amortization
|
|
|
83 |
|
|
|
80 |
|
|
|
82 |
|
|
Deferred
income tax expense (benefit)
|
|
|
(3 |
) |
|
|
14 |
|
|
|
37 |
|
|
Loss on
long-lived assets
|
|
|
— |
|
|
|
14 |
|
|
|
9 |
|
|
Other
non-cash income items
|
|
|
(6 |
) |
|
|
12 |
|
|
|
8 |
|
|
Asset and
liability changes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts
receivable
|
|
|
10 |
|
|
|
3 |
|
|
|
9 |
|
|
Accounts
payable
|
|
|
55 |
|
|
|
(65 |
) |
|
|
65 |
|
|
Taxes
payable
|
|
|
12 |
|
|
|
24 |
|
|
|
(27 |
) |
|
Other current
assets
|
|
|
(4 |
) |
|
|
(13 |
) |
|
|
(5 |
) |
|
Other current
liabilities
|
|
|
80 |
|
|
|
(13 |
) |
|
|
(88 |
) |
|
Non-current
assets
|
|
|
(55 |
) |
|
|
56 |
|
|
|
(66 |
) |
|
Non-current
liabilities
|
|
|
8 |
|
|
|
8 |
|
|
|
(31 |
) |
|
Net cash
provided by operating activities
|
|
|
308 |
|
|
|
255 |
|
|
|
125 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows
from investing activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital
expenditures
|
|
|
(116 |
) |
|
|
(186 |
) |
|
|
(120 |
) |
|
Net change in
note receivable from affiliate
|
|
|
(3 |
) |
|
|
127 |
|
|
|
(43 |
) |
|
Proceeds from
disposal of property
|
|
|
14 |
|
|
|
— |
|
|
|
— |
|
|
Other
|
|
|
(3 |
) |
|
|
4 |
|
|
|
2 |
|
|
Net cash used
in investing activities
|
|
|
(108 |
) |
|
|
(55 |
) |
|
|
(161 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows
from financing activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dividends
paid to parent
|
|
|
(200 |
) |
|
|
(200 |
) |
|
|
— |
|
|
Net proceeds
from issuance of long-term debt
|
|
|
— |
|
|
|
— |
|
|
|
350 |
|
|
Payments to
retire long-term debt
|
|
|
— |
|
|
|
— |
|
|
|
(314 |
) |
|
Net cash
provided by (used in) financing activities
|
|
|
(200 |
) |
|
|
(200 |
) |
|
|
36 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net change in
cash and cash equivalents
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
Cash and cash
equivalents
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning of
period
|
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
End of
period
|
|
$ |
— |
|
|
$ |
— |
|
|
$ |
— |
|
See accompanying
notes.
EL
PASO NATURAL GAS COMPANY
CONSOLIDATED
STATEMENTS OF STOCKHOLDER’S EQUITY
(In
millions, except for share amounts)
|
|
|
Common Stock
|
|
|
Additional
Paid-in
|
|
|
Retained
|
|
|
Accumulated
Other
Comprehensive
|
|
|
Total
Stockholder’s
|
|
|
|
|
Shares
|
|
|
Amount
|
|
|
Capital
|
|
|
Earnings
|
|
|
Loss
|
|
|
Equity
|
|
|
January 1,
2007
|
|
|
1,000 |
|
|
$ |
— |
|
|
$ |
1,268 |
|
|
$ |
462 |
|
|
$ |
(4 |
) |
|
$ |
1,726 |
|
|
Net
income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
132 |
|
|
|
|
|
|
|
132 |
|
|
Reclassification
to regulatory asset (Note 7)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4 |
|
|
|
4 |
|
|
December 31,
2007
|
|
|
1,000 |
|
|
|
— |
|
|
|
1,268 |
|
|
|
594 |
|
|
|
— |
|
|
|
1,862 |
|
|
Net
income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
135 |
|
|
|
|
|
|
|
135 |
|
|
Dividend paid
to parent
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(200 |
) |
|
|
|
|
|
|
(200 |
) |
|
Adoption of
accounting standard updates related to postretirement benefits, net of
income tax of less than $1 (Note 7)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1 |
|
|
|
|
|
|
|
1 |
|
|
December 31,
2008
|
|
|
1,000 |
|
|
|
— |
|
|
|
1,268 |
|
|
|
530 |
|
|
|
— |
|
|
|
1,798 |
|
|
Net
income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
128 |
|
|
|
|
|
|
|
128 |
|
|
Dividend paid
to parent
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(200 |
) |
|
|
|
|
|
|
(200 |
) |
|
December 31,
2009
|
|
|
1,000 |
|
|
$ |
— |
|
|
$ |
1,268 |
|
|
$ |
458 |
|
|
$ |
— |
|
|
$ |
1,726 |
|
See accompanying
notes.
EL
PASO NATURAL GAS COMPANY
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
1.
Summary of Significant Accounting Policies
Basis
of Presentation and Principles of Consolidation
We are a Delaware
corporation incorporated in 1928, and an indirect wholly owned subsidiary of El
Paso Corporation (El Paso). 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.
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
pipelines 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 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 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 and rights-of-way, we depreciate the asset to zero. The
majority of our property, plant and equipment are on our EPNG system which has
depreciation rates ranging from one percent to 20 percent and depreciable lives
ranging from five to 92 years consistent with our rate settlements with the
FERC. The depreciation rates on our Mojave Pipeline Company system range from
two percent to 33 percent per year. 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 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.
Included in our
property balances are additional acquisition costs of $152 million which
represent the excess of allocated purchase costs over the historical costs of
the facilities. These costs are amortized on a straight-line basis over a
remaining life of 23 years, and we do not recover these excess costs in our
rates under current FERC policies. At December 31, 2009 and 2008, we had
unamortized additional acquisition costs of $55 million and $58
million.
At December 31,
2009 and 2008, we had $63 million and $54 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 less than $1 million, $1 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 $1
million, $3 million and $2 million. These equity amounts are included in other
income on our income statement.
Asset
Impairments
We evaluate assets
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 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 the
long-lived asset’s ability to generate future cash flows on an undiscounted
basis. 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.
During 2008, we
recorded impairments of approximately $14 million due to declining real estate
values related to our Arizona storage projects, which we are no longer
developing.
Revenue
Recognition
Our revenues are
primarily generated from natural gas transportation and storage 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 current
and other 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
El Paso maintains a
tax accrual policy to record both regular and alternative minimum taxes for
companies included in its consolidated federal and state income tax returns. The
policy provides, among other things, that (i) each company in a taxable
income position will accrue a current expense equivalent to its federal and
state income taxes, and (ii) each company in a tax loss position will accrue a
benefit to the extent its deductions, including general business credits, can be
utilized in the consolidated returns. El Paso pays all consolidated U.S. federal
and state income taxes directly to the appropriate taxing jurisdictions and,
under a separate tax billing agreement, El Paso may bill or refund its
subsidiaries for their portion of these income tax payments.
We record income
taxes on a separate return basis. Pursuant to El Paso’s policy, we
record current income taxes based on our taxable income and we provide for
deferred income taxes to reflect estimated future tax payments and receipts.
Deferred taxes represent the tax impacts of differences between the financial
statement and tax bases of assets and liabilities and carryovers at each year
end. We account for tax credits under the flow-through method, which reduces the
provision for income taxes in the year the tax credits first become available.
We reduce deferred tax assets by a valuation allowance when, based on our
estimates, it is more likely than not that a portion of those assets will not be
realized in a future period. The estimates utilized in the recognition of
deferred tax assets are subject to revision, either up or down, in future
periods based on new facts or circumstances.
We are required to
evaluate our tax positions for all jurisdictions and for all years where the
statute of limitations has not expired and we are required to meet a
more-likely-than-not threshold (i.e. a greater than 50 percent likelihood of a
tax position being sustained under examination) prior to recording a tax
benefit. Additionally, for tax positions meeting this more-likely-than-not
threshold, the amount of benefit is limited to the largest benefit that has a
greater than 50 percent probability of being realized upon effective
settlement.
Accounting
for Asset Retirement Obligations
We record a
liability for legal obligations associated with the replacement, removal or
retirement of our long-lived assets in the period the obligation is incurred.
Our asset retirement liabilities are initially recorded at their estimated fair
value with a corresponding increase to property, plant and equipment. This
increase in property, plant and equipment is then depreciated over the useful
life of the asset to which that liability relates. An ongoing expense is 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 systems, and intend to
do so as long as supply and demand for natural gas exists, which we expect for
the foreseeable future. Therefore, we believe that the substantial majority of
our natural gas pipelines 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 7.
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 the measurement date and changed the measurement date of our
postretirement benefit plan from September 30 to December 31. We
recorded an increase of $1 million, net of income taxes of less than $1 million,
to our January 1, 2008 retained earnings balance upon the adoption of the
measurement date provisions of this standard.
Effective December
31, 2009, we expanded our disclosures about postretirement benefit plan assets
as a result of new disclosure requirements. See Note 7 for these
expanded disclosures.
2.
Income Taxes
El Paso files
consolidated U.S. federal and certain state tax returns which include our
taxable income. In certain states, we file and pay taxes directly to the state
taxing authorities. With a few exceptions, we and El Paso are no longer subject
to state and local income tax examinations by tax authorities for years prior to
1999 and U.S. income tax examinations for years prior to 2007. In November 2009,
the Internal Revenue Service’s examination of El Paso’s U.S. income tax returns
for 2005 and 2006 was settled at the appellate level. The settlement of issues
raised in this examination did not materially impact our results of operations,
financial condition or liquidity. For our open tax years, we have no
unrecognized tax benefits (liabilities for uncertain tax matters).
Components of Income Tax Expense.
The following table reflects the components of income tax expense
included in net income for each of the three years ended December
31:
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
|
(In
millions)
|
|
|
Current
|
|
|
|
|
|
|
|
|
|
|
Federal
|
|
$ |
72 |
|
|
$ |
61 |
|
|
$ |
40 |
|
|
State
|
|
|
10 |
|
|
|
8 |
|
|
|
6 |
|
|
|
|
|
82 |
|
|
|
69 |
|
|
|
46 |
|
|
Deferred
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Federal
|
|
|
(3 |
) |
|
|
12 |
|
|
|
32 |
|
|
State
|
|
|
— |
|
|
|
2 |
|
|
|
5 |
|
|
|
|
|
(3 |
) |
|
|
14 |
|
|
|
37 |
|
|
Total income
tax expense
|
|
$ |
79 |
|
|
$ |
83 |
|
|
$ |
83 |
|
Effective Tax Rate Reconciliation.
Our income tax expense differs from the amount computed by applying the
statutory federal income tax rate of 35 percent for the following reasons for
each of the three years ended December 31:
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
|
(In
millions, except for rates)
|
|
|
Income tax
expense at the statutory federal rate of 35%
|
|
$ |
72 |
|
|
$ |
76 |
|
|
$ |
75 |
|
|
State income
taxes, net of federal income tax effect
|
|
|
7 |
|
|
|
7 |
|
|
|
7 |
|
|
Non-deductible
expenses
|
|
|
— |
|
|
|
— |
|
|
|
1 |
|
|
Income tax
expense
|
|
$ |
79 |
|
|
$ |
83 |
|
|
$ |
83 |
|
|
Effective tax
rate
|
|
|
38 |
% |
|
|
38 |
% |
|
|
39 |
% |
Deferred Tax Assets and Liabilities.
The following are the components of our net deferred tax liability at
December 31:
|
|
|
2009
|
|
|
2008
|
|
|
|
|
(In
millions)
|
|
|
Deferred tax
liabilities
|
|
|
|
|
|
|
|
Property,
plant and equipment
|
|
$ |
482 |
|
|
$ |
468 |
|
|
Regulatory
and other assets
|
|
|
28 |
|
|
|
27 |
|
|
Total
deferred tax liability
|
|
|
510 |
|
|
|
495 |
|
|
Deferred tax
assets
|
|
|
|
|
|
|
|
|
|
U.S. net
operating loss and tax credit carryovers
|
|
|
77 |
|
|
|
77 |
|
|
Regulatory
and other reserve
|
|
|
33 |
|
|
|
8 |
|
|
Other
liabilities
|
|
|
27 |
|
|
|
33 |
|
|
Total
deferred tax asset
|
|
|
137 |
|
|
|
118 |
|
|
Net deferred
tax liability
|
|
$ |
373 |
|
|
$ |
377 |
|
We believe it is
more likely than not that we will realize the benefit of our deferred tax assets
due to expected future taxable income, including the effect of future reversals
of existing taxable temporary differences primarily related to
depreciation.
Tax Credits and Carryovers.
As of December 31, 2009, we had approximately $19 million of alternative
minimum tax credits that carryover indefinitely. We also have approximately $167
million of net operating loss carryovers that expire between 2019 and 2028.
Usage of our carryovers is subject to the limitations provided under Sections
382 and 383 of the Internal Revenue Code as well as the separate return
limitation year rules of IRS regulations.
3.
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 and 2008, we had an interest bearing note receivable from El Paso of
approximately $1.0 billion due upon demand, 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 rate, the fair value of this note receivable
approximates the carrying value due to the note being due on demand and the
market-based nature of the interest rate.
In addition, the
carrying amounts of our long-term debt 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, including current maturities
|
|
$ |
1,167 |
|
|
$ |
1,300 |
|
|
$ |
1,166 |
|
|
$ |
1,021 |
|
4.
Regulatory Assets and Liabilities
Our current
regulatory assets are included in other current assets on our balance
sheets. 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
|
|
$ |
7 |
|
|
$ |
5 |
|
|
Other
|
|
|
3 |
|
|
|
2 |
|
|
Total current
regulatory assets
|
|
|
10 |
|
|
|
7 |
|
|
Non-current
regulatory assets
|
|
|
|
|
|
|
|
|
|
Taxes on
capitalized funds used during construction
|
|
|
24 |
|
|
|
22 |
|
|
Unamortized
loss on reacquired debt
|
|
|
24 |
|
|
|
27 |
|
|
Postretirement
benefits
|
|
|
8 |
|
|
|
9 |
|
|
Under-collected
state income taxes
|
|
|
5 |
|
|
|
6 |
|
|
Other
|
|
|
4 |
|
|
|
4 |
|
|
Total
non-current regulatory assets
|
|
|
65 |
|
|
|
68 |
|
|
Total regulatory assets
|
|
$ |
75 |
|
|
$ |
75 |
|
|
|
|
|
|
|
|
|
|
|
|
Current
regulatory liabilities
|
|
|
|
|
|
|
|
|
|
Property and
plant depreciation
|
|
$ |
3 |
|
|
$ |
5 |
|
|
Gas retained
and not used in operations
|
|
|
5 |
|
|
|
15 |
|
|
Pipeline
integrity program
|
|
|
— |
|
|
|
3 |
|
|
Other
|
|
|
9 |
|
|
|
10 |
|
|
Total current
regulatory liabilities
|
|
|
17 |
|
|
|
33 |
|
|
Non-current
regulatory liabilities
|
|
|
|
|
|
|
|
|
|
Property and
plant depreciation
|
|
|
30 |
|
|
|
37 |
|
|
Postretirement
benefits
|
|
|
15 |
|
|
|
4 |
|
|
Excess
deferred federal income taxes
|
|
|
2 |
|
|
|
2 |
|
|
Total
non-current regulatory liabilities
|
|
|
47 |
|
|
|
43 |
|
|
Total
regulatory liabilities
|
|
$ |
64 |
|
|
$ |
76 |
|
The significant
regulatory assets and liabilities include:
Deferred Fuel Lost and Unaccounted
for Gas. 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 and 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 the deferral of customer-funded amounts
for costs of future asset retirements.
5.
Debt and Credit Facilities
Debt. Our long-term debt
consisted of the following at December 31:
|
|
|
2009
|
|
|
2008
|
|
|
|
|
(In
millions)
|
|
|
7.625% Notes
due August 2010
|
|
$ |
54 |
|
|
$ |
54 |
|
|
5.95% Notes
due April 2017
|
|
|
355 |
|
|
|
355 |
|
|
8.625%
Debentures due January 2022
|
|
|
260 |
|
|
|
260 |
|
|
7.50%
Debentures due November 2026
|
|
|
200 |
|
|
|
200 |
|
|
8.375% Notes
due June 2032
|
|
|
300 |
|
|
|
300 |
|
|
|
|
|
1,169 |
|
|
|
1,169 |
|
|
Less: Current
maturities of long-term debt
|
|
|
54 |
|
|
|
— |
|
|
Unamortized discount
|
|
|
2 |
|
|
|
3 |
|
|
Total
long-term debt
|
|
$ |
1,113 |
|
|
$ |
1,166 |
|
Credit Facility. We are
eligible to borrow amounts available under El Paso’s $1.5 billion credit
agreement and are only liable for amounts we directly borrow. As of December 31,
2009, El Paso had approximately $0.8 billion of capacity remaining and available
to us and our affiliates under this credit agreement, and none of the amount
outstanding under the facility was issued or borrowed by us. Our common stock
and the common stock of another El Paso subsidiary are pledged as collateral
under the credit agreement.
Under El Paso’s
$1.5 billion credit agreement and our indentures, we are subject to a number of
restrictions and covenants. The most restrictive of these include (i)
limitations on the incurrence of additional debt, based on a ratio of debt to
EBITDA (as defined in the agreements), which shall not exceed 5 to 1; (ii)
limitations on the use of proceeds from borrowings; (iii) limitations, in some
cases, on transactions with our affiliates; (iv) limitations on the incurrence
of liens; (v) potential limitations on our ability to declare and pay dividends;
and (vi) potential limitations on our ability to participate in the El Paso’s
cash management program. The indentures governing some of our long-term debt
contain cross-acceleration provisions, the most restrictive of which is $25
million. For the year ended December 31, 2009, we were in compliance with our
debt-related covenants.
6.
Commitments and Contingencies
Legal
Proceedings
Baldonado et al. v. EPNG. In
August 2000, a main transmission line owned and operated by us ruptured at the
crossing of the Pecos River near Carlsbad, New Mexico. Individuals at the site
were fatally injured. In June 2003, a lawsuit entitled Baldonado et al. v. EPNG was
filed in state court in Eddy County, New Mexico, on behalf of 26 firemen and
emergency medical service personnel who responded to the fire and who allegedly
have suffered psychological trauma. After a trial which began in October 2009, a
jury returned a verdict in our favor in December 2009. Subsequently, the
firemen and emergency medical service personnel agreed to waive their right to
appeal. As a result, this case was closed.
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.
Bank of America. We are a
named defendant, along with Burlington Resources, Inc. (Burlington), now a
subsidiary of ConocoPhillips Company, in a class action lawsuit styled Bank of America, et al. v. El Paso
Natural Gas and Burlington Resources Oil and Gas Company, L.P., filed in
October 2003 in the District Court of Kiowa County, Oklahoma asserting royalty
underpayment claims related to specified shallow wells in Oklahoma, Texas and
New Mexico. The Plaintiffs assert that royalties were underpaid starting in the
1980s when the purchase price of gas was lowered below the Natural Gas Policy
Act maximum lawful prices. The Plaintiffs assert that royalties were further
underpaid by Burlington as a result of post-production cost deductions taken
starting in the late 1990s. This action was transferred to Washita County
District Court in 2004. A tentative settlement reached in November 2005 was
disapproved by the court in June 2007. A class certification hearing occurred in
April 2009. The court certified a Texas and Oklahoma class of royalty
owners. The class certification has been appealed to the Oklahoma
Court of Appeals. A companion case styled Bank of America v. El Paso Natural
Gas involving similar claims made as to certain wells in Oklahoma was
settled in 2006. Our costs and legal exposure related to this lawsuit 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
believe we have established appropriate reserves for these matters. It is
possible, however, that new information or future developments could require us
to reassess our potential exposure related to these matters and adjust our
accruals accordingly, and these adjustments could be material. At December 31,
2009, we had accrued approximately $2 million for our outstanding legal
matters.
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 $19 million and $22 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 $40 million at December 31, 2009. Our accrual at December 31, 2009
includes $17 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.
Comprehensive Environmental
Response, Compensation and Liability Act (CERCLA) Matters. We have
received notice that we could be designated, or have been asked for information
to determine whether we could be designated, as a Potentially Responsible Party
(PRP) with respect to three active sites under the CERCLA or state equivalents.
We have sought to resolve our liability as a PRP at these sites through
indemnification by third parties and settlements, which provide for payment of
our allocable share of remediation costs. As of December 31, 2009, we have
estimated our share of the remediation costs at these sites to be between $8
million and $14 million. Because the clean-up costs are estimates and are
subject to revision as more information becomes available about the extent of
remediation required, and in some cases we have asserted a defense to any
liability, our estimates could change. Moreover, liability under the federal
CERCLA statute may be joint and several, meaning that we could be required to
pay in excess of our pro rata share of remediation costs. Our understanding of
the financial strength of other PRPs has been considered, where appropriate, in
estimating our liabilities. Accruals for these matters are included in the
environmental reserve discussed above.
For 2010, we
estimate that our total remediation expenditures will be approximately $4
million, which will be expended under government directed clean-up
plans.
It is possible that
new information or future developments could require us to reassess our
potential exposure related to environmental matters. We may incur significant
costs and liabilities in order to comply with existing environmental laws and
regulations. It is also possible that other developments, such as increasingly
strict environmental laws, regulations and orders of regulatory agencies, as
well as claims for damages to property and the environment or injuries to
employees and other persons resulting from our current or past operations, could
result in substantial costs and liabilities in the future. As this information
becomes available, or other relevant developments occur, we will adjust our
accrual amounts accordingly. While there are still uncertainties related to the
ultimate costs we may incur, based upon our evaluation and experience to date,
we believe our reserves are adequate.
Rates
and Regulatory Matter
EPNG Rate Case. In June 2008,
we filed a rate case with the FERC as required under the settlement of our
previous rate case. The filing proposed an increase in base tariff rates on our
EPNG system, which would increase revenue by $83 million annually over
previously effective tariff rates. In August 2008, the FERC issued an order
accepting the proposed rates effective January 1, 2009, subject to refund and
the outcome of a hearing and a technical conference. The FERC issued an order in
December 2008, that generally accepted most of our proposals in the technical
conference proceeding. The FERC has appointed an administrative law judge to
preside over a hearing if we are unable to reach a negotiated settlement with
our customers on the remaining issues. Settlement negotiations are continuing;
however, the hearing has been postponed until May 2010. The outcome
of the settlement discussions or the hearing is not currently
determinable.
Other
Matters
Navajo Nation. In March 2009,
representatives of the Navajo Nation and EPNG executed a final agreement setting
forth the full terms and conditions of the Navajo Nation’s consent to EPNG’s
rights-of-way through the Navajo Nation. Under this agreement, we will make
annual payments of approximately $19 million for our rights-of-way beginning in
2009 and continuing through 2025, subject to annual adjustments. We
submitted the Navajo Nation’s consent agreement in support of our pending
application to the United States Department of the Interior (the Department) for
an extension of the Department’s current rights-of-way grant. We expect the
submission will result in the Department’s final processing of our application.
We have filed with the FERC for recovery of payments under rights-of-way in our
recent rate case.
Tuba City Uranium Milling
Facility. For a period of approximately ten years beginning in the mid to
late 1950s, Rare Metals Corporation of America, a historical affiliate,
conducted uranium mining and milling operations in the vicinity of Tuba City,
Arizona, under a contract with the United States government as part of the Cold
War nuclear program. The site of the Tuba City uranium mill, which is on land
within the Navajo Indian Reservation, reverted to the Navajo Nation after the
mill closed in 1966. The tailings at the mill site were encapsulated and a
ground water remediation system was installed by the U.S. Department of Energy
(DOE) under the Federal Uranium Mill Tailings Radiation Control Act of 1978. In
May 2007, we filed suit against the DOE and other federal agencies requesting a
judicial determination that the DOE was fully and legally responsible for any
remediation of any waste associated with historical uranium production activity
at two sites in the vicinity of the mill facilities near Tuba City, Arizona. In
March 2009, the United States District Court for the District of Columbia issued
an opinion dismissing one of our claims, for which we intend to make an
appeal. Also in March 2009, following our close cooperation with the
Navajo Nation in joint legislative efforts, President Obama signed the Fiscal
Year 2009 Omnibus Appropriations Act, which appropriated $5 million toward the
final remediation by the DOE of one of the two sites that are the subject of our
lawsuit. The DOE has assigned to the Navajo Nation the obligation to remediate
the site. We anticipate that the Navajo Nation will perform the remediation in
the near future, and we are continuing to maintain the interim site control
measures we have installed at the site.
While the outcome
of these matters cannot be predicted with certainty, based on current
information, we do not expect the ultimate resolution of these matters to have a
material adverse effect on our financial position, operating results or cash
flows. It is possible that new information or future developments could require
us to reassess our potential exposure related to these matters. The impact of
these changes may have a material effect on our results of operations, our
financial position, and our cash flows in the periods these events
occur.
Other
Commitments
Capital Commitments. At
December 31, 2009, we had capital commitments of approximately $2 million. We
have other planned capital projects that are discretionary in nature, with no
substantial contractual capital commitments made in advance of the actual
expenditures.
Operating Leases. We lease
property, facilities and equipment under various operating leases. Future
minimum annual rental commitments under our operating leases at December 31,
2009, were as follows:
|
Year
Ending
December 31,
|
|
|
|
|
| |
|
|
(In
millions)
|
|
|
2010
|
|
|
$ |
3 |
|
|
2011
|
|
|
|
3 |
|
|
2012
|
|
|
|
3 |
|
|
Thereafter
|
|
|
|
6 |
|
|
Total
|
|
|
$ |
15 |
|
Rental expense on
our lease obligations for the years ended December 31, 2009, 2008 and 2007 was
$21 million, $22 million and $20 million. These amounts include 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 systems. We have executed a long-term rights-of-way
agreement with the Navajo Nation which will result in a significant commitment
by us upon approval of our pending application with the Department of Interior
(see Navajo Nation
above).
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 fails to make payments under, or violates the
terms of, the financial arrangement. In a performance guarantee, we provide
assurance that the guaranteed party will execute on the terms of the contract.
If they do not, we are required to perform on their behalf. As of December 31,
2009, we have financial and performance guarantees with a maximum exposure of
approximately $11 million, not otherwise recognized in the financial
statements.
7.
Retirement Benefits
Pension and Retirement Savings Plan.
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 employees who retired on or before March 1, 1986, and limited
postretirement life insurance for employees who retired after January 1, 1985.
As such, our obligation to accrue for other postretirement employee benefits is
primarily limited to the fixed population of retirees who retired on or before
March 1, 1986. 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 $4 million from accumulated other
comprehensive loss to a regulatory asset.
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
|
|
$ |
52 |
|
|
$ |
62 |
|
|
Interest
cost
|
|
|
3 |
|
|
|
5 |
|
|
Actuarial
gain
|
|
|
(4 |
) |
|
|
(8 |
) |
|
Benefits
paid(1)
|
|
|
(4 |
) |
|
|
(7 |
) |
|
Accumulated
postretirement benefit obligation - end of period
|
|
$ |
47 |
|
|
$ |
52 |
|
|
Change in
plan assets:
|
|
|
|
|
|
|
|
|
|
Fair value of
plan assets - beginning period
|
|
$ |
71 |
|
|
$ |
104 |
|
|
Actual return
on plan assets
|
|
|
13 |
|
|
|
(25 |
) |
|
Benefits
paid
|
|
|
(5 |
) |
|
|
(8 |
) |
|
Fair value of
plan assets - end of period
|
|
$ |
79 |
|
|
$ |
71 |
|
|
Reconciliation
of funded status:
|
|
|
|
|
|
|
|
|
|
Fair value of
plan assets
|
|
$ |
79 |
|
|
$ |
71 |
|
|
Less:
accumulated postretirement benefit obligation
|
|
|
47 |
|
|
|
52 |
|
|
Net asset at
December 31
|
|
$ |
32 |
|
|
$ |
19 |
|
____________
|
(1)
|
Amounts shown net of a subsidy of approximately $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
$2 million and common/collective trusts with a fair value of $77
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
|
|
|
$ |
5 |
|
|
2011
|
|
|
|
5 |
|
|
2012
|
|
|
|
5 |
|
|
2013
|
|
|
|
5 |
|
|
2014
|
|
|
|
5 |
|
|
2015 -
2019
|
|
|
|
19 |
|
____________
|
(1)
|
Includes
a reduction of approximately $1 million in each of the years 2010 – 2014
and approximately $3 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
|
|
|
5.14 |
|
|
|
5.90 |
|
|
|
6.05 |
|
|
Assumptions
related to benefit costs at December 31:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discount
rate
|
|
|
5.90 |
|
|
|
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. Assumed health care cost
trends can have a significant effect on the amounts reported for our
postretirement benefit plan. A one-percentage point change would not have had a
significant effect on interest costs in 2009 or 2008. A one-percentage point
change in assumed health care cost trends would have the following effect as of
December 31, 2009 and 2008:
|
|
|
2009
|
|
|
2008
|
|
|
|
|
(In
millions)
|
|
|
One
percentage point increase:
|
|
|
|
|
|
|
|
Accumulated
postretirement benefit obligation
|
|
$ |
3 |
|
|
$ |
3 |
|
|
One
percentage point decrease:
|
|
|
|
|
|
|
|
|
|
Accumulated
postretirement benefit obligation
|
|
$ |
(3 |
) |
|
$ |
(3 |
) |
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
|
|
$ |
3 |
|
|
$ |
4 |
|
|
$ |
4 |
|
|
Expected
return on plan assets
|
|
|
(5 |
) |
|
|
(7 |
) |
|
|
(6 |
) |
|
Amortization
of net actuarial gain
|
|
|
— |
|
|
|
(2 |
) |
|
|
— |
|
|
Net benefit
income
|
|
$ |
(2 |
) |
|
$ |
(5 |
) |
|
$ |
(2 |
) |
8.
Transactions with Major Customers
The following table
shows revenues from our major customers for each of the three years ended
December 31:
|
|
|
2009(1)
|
|
|
2008
|
|
|
2007
|
|
|
|
|
(In
millions)
|
|
|
ConocoPhillips
Company(2)
|
|
$ |
124 |
|
|
$ |
82 |
|
|
$ |
47 |
|
|
Sempra Energy
and Subsidiaries (3)
|
|
|
89 |
|
|
|
85 |
|
|
|
93 |
|
____________
|
(1)
|
Revenues
reflect rates subject to
refund.
|
|
(2)
|
In 2007,
ConocoPhillips Company did not represent more than 10 percent of our
revenues.
|
|
(3)
|
Amounts
include revenues from Southern California Gas
Company.
|
9.
Supplemental Cash Flow Information
The following table
contains supplemental cash flow information for each of the three years ended
December 31:
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
|
|
(In
millions)
|
|
|
Interest
paid, net of capitalized interest
|
|
$ |
88 |
|
|
$ |
88 |
|
|
$ |
106 |
|
|
Income tax
payments
|
|
|
71 |
|
|
|
45 |
|
|
|
112 |
|
10.
Transactions with Affiliates
Cash Management Program. We
participate in El Paso’s cash management program which matches short-term cash
surpluses and needs of participating affiliates, thus minimizing total
borrowings from outside sources. El Paso uses the cash management program to
settle intercompany transactions between participating affiliates. We have
historically advanced cash to El Paso in exchange for an affiliated note
receivable that is due upon demand. During both 2009 and 2008, we utilized $200
million of our notes receivable from the cash management program to pay
dividends to our parent. At December 31, 2009 and 2008, we had a note receivable
from El Paso of approximately $1.0 billion. We classified $103 million of this
receivable as current on our balance sheet at December 31, 2009, based on the
net amount we anticipate using in the next twelve months considering available
cash sources and needs. The interest rate on this variable rate note at December
31, 2009 and 2008 was 1.5% and 3.2%.
Income Taxes. El Paso files
consolidated U.S. federal and certain state tax returns which include our
taxable income. In certain states, we file and pay taxes directly to the state
taxing authorities. At December 31, 2009 and 2008, we had income taxes payable
of $90 million and $79 million. The majority of these balances, as well as our
deferred income taxes, will become payable to El Paso. See Note 1 for a
discussion of our income tax policy.
Other Affiliate Balances. At
both December 31, 2009 and 2008, we had contractual deposits from our affiliates
of $8 million included in other current liabilities on our balance
sheets.
Affiliate Revenues and Expenses.
We provide natural gas transportation services to an affiliate under
long-term contracts. We entered into these contracts within the ordinary course
of business and the services are based on the same terms as
non-affiliates.
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 also allocated costs from Tennessee Gas Pipeline Company
(TGP), our affiliate, associated with our pipeline services. We also allocate
costs to Colorado Interstate Gas Company, our affiliate, for its 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
|
|
$ |
20 |
|
|
$ |
17 |
|
|
$ |
19 |
|
|
Operation and
maintenance expenses from affiliates
|
|
|
62 |
|
|
|
56 |
|
|
|
53 |
|
|
Reimbursements
of operating expenses charged to affiliates
|
|
|
25 |
|
|
|
21 |
|
|
|
17 |
|
11.
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
|
|
$ |
157 |
|
|
$ |
144 |
|
|
$ |
145 |
|
|
$ |
147 |
|
|
$ |
593 |
|
|
Operating
income
|
|
|
81 |
|
|
|
67 |
|
|
|
66 |
|
|
|
65 |
|
|
|
279 |
|
|
Net
income
|
|
|
40 |
|
|
|
30 |
|
|
|
30 |
|
|
|
28 |
|
|
|
128 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
revenues
|
|
$ |
141 |
|
|
$ |
152 |
|
|
$ |
145 |
|
|
$ |
152 |
|
|
$ |
590 |
|
|
Operating
income
|
|
|
60 |
|
|
|
74 |
|
|
|
61 |
|
|
|
62 |
|
|
|
257 |
|
|
Net
income
|
|
|
33 |
|
|
|
40 |
|
|
|
31 |
|
|
|
31 |
|
|
|
135 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
____________
|
(1)
|
Includes
asset impairments of $14 million due to declining real estate values for
2008 related to our Arizona storage projects, which we are no longer
developing.
|
SCHEDULE
II
EL
PASO NATURAL 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
|
|
|
Balance at
End of Period
|
|
|
2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allowance for
doubtful accounts
|
|
$ |
2 |
|
|
$ |
— |
|
|
$ |
— |
|
|
$ |
2 |
|
|
Legal
reserves
|
|
|
6 |
|
|
|
4 |
|
|
|
(8 |
) |
|
|
2 |
|
|
Environmental
reserves
|
|
|
22 |
|
|
|
1 |
|
|
|
(4 |
) |
|
|
19 |
|
|
Regulatory
reserves
|
|
|
— |
|
|
|
74 |
(1) |
|
|
— |
|
|
|
74 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allowance for
doubtful accounts
|
|
$ |
4 |
|
|
$ |
(2 |
) |
|
$ |
— |
|
|
$ |
2 |
|
|
Legal
reserves
|
|
|
4 |
|
|
|
8 |
|
|
|
(6 |
) |
|
|
6 |
|
|
Environmental
reserves
|
|
|
25 |
|
|
|
1 |
|
|
|
(4 |
) |
|
|
22 |
|
|
Regulatory
reserves
|
|
|
10 |
|
|
|
— |
|
|
|
(10 |
) |
|
|
— |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allowance for
doubtful accounts
|
|
$ |
5 |
|
|
$ |
(1 |
) |
|
$ |
— |
|
|
$ |
4 |
|
|
Legal
reserves
|
|
|
16 |
|
|
|
4 |
|
|
|
(16 |
) |
|
|
4 |
|
|
Environmental
reserves
|
|
|
24 |
|
|
|
6 |
|
|
|
(5 |
) |
|
|
25 |
|
|
Regulatory
reserves
|
|
|
65 |
|
|
|
60 |
|
|
|
(115 |
) |
|
|
10 |
|
____________
|
(1)
|
See Note
6 to the financial statements for EPNG’s rate case
discussion.
|
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.
Audit
Fees
The audit fees for
the years ended December 31, 2009 and 2008 of $796,000 and $751,000,
respectively, were primarily for professional services rendered by Ernst &
Young LLP and for the audits of the consolidated financial statements of El Paso
Natural 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 an indirect
wholly owned subsidiary of El Paso and do not have a separate audit committee.
El Paso’s Audit Committee has adopted a pre-approval policy for audit and
non-audit services. For a description of El Paso’s pre-approval policies for
audit and non-audit related services, see El Paso Corporation’s proxy statement
for its 2010 Annual Meeting of Stockholders.
|
|
(a)
|
The following documents are
filed as a part of this
report:
|
1.
Financial statements
The following
consolidated financial statements are included in Part II, Item 8 of this
report:
|
|
Page
|
|
Report of
Independent Registered Public Accounting Firm
|
23
|
|
Consolidated
Statements of Income
|
24
|
|
Consolidated
Balance Sheets
|
25
|
|
Consolidated
Statements of Cash Flows
|
26
|
|
Consolidated
Statements of Stockholder’s Equity
|
27
|
|
Notes to
Consolidated Financial Statements
|
28
|
|
|
|
|
2. Financial
statement schedules
|
|
|
|
|
|
Schedule II —
Valuation and Qualifying Accounts
|
43
|
All other schedules
are omitted because they are not applicable, or the required information is
disclosed in the financial statements or accompanying notes.
3.
Exhibits
The Exhibit Index,
which follows the signature page to this report and is hereby incorporated
herein by reference, sets forth a list of those exhibits filed herewith, and
includes and identifies contracts or arrangements required to be filed as
exhibits to this Form 10-K by Item 601(b)(10)(iii) of Regulation
S-K.
The agreements
included as exhibits to this report are intended to provide information
regarding their terms and not to provide any other factual or disclosure
information about us or the other parties to the agreements. The agreements may
contain representations and warranties by the parties to the agreements,
including us, solely for the benefit of the other parties to the applicable
agreement and:
|
•
|
should not in
all instances be treated as categorical statements of fact, but rather as
a way of allocating the risk to one of the parties if those statements
prove to be inaccurate;
|
|
•
|
may have been
qualified by disclosures that were made to the other party in connection
with the negotiation of the applicable agreement, which disclosures are
not necessarily reflected in the
agreement;
|
|
•
|
may apply
standards of materiality in a way that is different from what may be
viewed as material to certain investors;
and
|
|
•
|
were made
only as of the date of the applicable agreement or such other date or
dates as may be specified in the agreement and are subject to more recent
developments.
|
Accordingly, these
representations and warranties may not describe the actual state of affairs as
of the date they were made or at any other time.
Undertaking
We hereby
undertake, pursuant to Regulation S-K, Item 601(b), paragraph (4) (iii), to
furnish to the SEC upon request all constituent instruments defining the rights
of holders of our long-term debt and our consolidated subsidiaries not filed
herewith for the reason that the total amount of securities authorized under any
of such instruments does not exceed 10 percent of our total consolidated
assets.
Pursuant to the
requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, El
Paso Natural Gas Company has duly caused this report to be signed on its behalf
by the undersigned, thereunto duly authorized on the 1st day
of March 2010.
| |
EL
PASO NATURAL GAS COMPANY
|
|
| |
|
|
|
|
Date
|
By:
|
/s/ James
J. Cleary |
|
| |
|
James J.
Cleary |
|
| |
|
President |
|
| |
|
|
|
Pursuant to the
requirements of the Securities Exchange Act of 1934, this report has been signed
below by the following persons on behalf of El Paso Natural Gas Company and in
the capacities and on the dates indicated:
|
Signature
|
Title
|
Date
|
|
|
|
|
|
/s/ James J.
Cleary
|
President and
Director
|
March 1,
2010
|
|
James J.
Cleary
|
(Principal
Executive Officer)
|
|
|
|
|
|
|
/s/ John R. Sult
|
Senior Vice
President and
|
March 1,
2010
|
|
John R.
Sult
|
Chief
Financial Officer (Principal
Financial
Officer)
|
|
|
|
|
|
|
/s/ Rosa P.
Jackson
|
Vice
President and Controller
|
March 1,
2010
|
|
Rosa P.
Jackson
|
(Principal
Accounting Officer)
|
|
|
|
|
|
|
/s/ James C.
Yardley
|
Chairman of
the Board
|
March 1,
2010
|
|
James C.
Yardley
|
|
|
|
|
|
|
|
/s/ Daniel B.
Martin
|
Senior Vice
President and Director
|
March 1,
2010
|
|
Daniel B.
Martin
|
|
|
|
|
|
|
|
/s/ Thomas L.
Price
|
Vice
President and Director
|
March 1,
2010
|
|
Thomas L.
Price
|
|
|
|
|
|
|
EL
PASO NATURAL GAS COMPANY
EXHIBIT
INDEX
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.
|
Exhibit
Number
|
Description
|
|
3.A
|
Restated
Certificate of Incorporation dated April 8, 2003(Exhibit 3.A to our
Annual Report for the year ended December 31, 2008, filed with the SEC on
March 2, 2009).
|
|
|
|
|
3.B
|
By-laws dated
June 2, 2008(Exhibit 3.B to our Annual Report for the year ended
December 31, 2008, filed with the SEC on March 2,
2009).
|
|
|
|
|
*4.A
|
Indenture
dated as of January 1, 1992, between El Paso Natural Gas Company and
Wilmington Trust Company (as successor to Citibank, N.A.), as
Trustee.
|
|
|
|
|
*4.B
|
Indenture
dated as of November 13, 1996, between El Paso Natural Gas Company
and Wilmington Trust Company (as successor to JPMorgan Chase Bank,
formerly known as The Chase Manhattan Bank), as
Trustee.
|
|
|
|
|
4.C
|
Indenture
dated as of July 21, 2003, between El Paso Natural Gas Company and
Wilmington Trust Company, as Trustee (Exhibit 4.C to our Annual Report for
the year ended December 31, 2008, filed with the SEC on March 2,
2009).
|
|
|
|
|
4.D
|
First
Supplemental Indenture dated as of June 10, 2002 between El Paso
Natural Gas Company and Wilmington Trust Company (as successor in interest
to JPMorgan Chase Bank, formerly known as The Chase Manhattan Bank), as
Trustee, to indenture dated November 13, 1996(Exhibit 4.D to our Annual
Report for the year ended December 31, 2008, filed with the SEC on March
2, 2009).
|
|
|
|
|
4.E
|
Second
Supplemental Indenture dated as of April 4, 2007 between El Paso
Natural Gas Company and Wilmington Trust Company, as Trustee, to indenture
dated November 13, 1996 (Exhibit 4.A to our Current Report on
Form 8-K filed with the SEC on April 9,
2007).
|
|
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4.F
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First
Supplemental Indenture dated as of April 4, 2007 between El Paso
Natural Gas Company and Wilmington Trust Company, as trustee, to indenture
dated as of July 23, 2003 (Exhibit 4.C to our Current Report on
Form 8-K filed with the SEC on April 9,
2007).
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4.G
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Form of 5.95%
Senior Note due 2017 (included in Exhibit 4.E).
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*10.A
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Third Amended
and Restated Credit Agreement dated as of November 16, 2007, among El
Paso Corporation, El Paso Natural Gas Company, Tennessee Gas Pipeline
Company, the several banks and other financial institutions from time to
time parties thereto and JPMorgan Chase Bank, N.A., as administrative
agent and as collateral agent.
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*10.B
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Third
Amendment and Restated Security Agreement dated as of November 16,
2007, made by among El Paso Corporation, El Paso Natural Gas Company,
Tennessee Gas Pipeline Company, the subsidiary Grantors and certain other
credit parties thereto and JPMorgan Chase Bank, N.A., not in its
individual capacity, but solely as collateral agent for the Secured
Parties and as the depository bank.
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10.C
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Third Amended
and Restated Subsidiary Guarantee Agreement dated as of November 16,
2007, made by each of the Subsidiary Guarantors in favor of JPMorgan Chase
Bank, N.A., as Collateral Agent (Exhibit 10.C to our Current Report
on Form 8-K filed with the SEC on November 21,
2007.)
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10.D
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Registration
Rights Agreement, dated as of April 4, 2007, among El Paso Natural
Gas Company and Deutsche Bank Securities Inc., Citigroup Global Markets
Inc., ABN AMRO Incorporated, Goldman, Sachs & Co, Greenwich Capital
Markets, Inc., J.P. Morgan Securities Inc. and SG Americas Securities, LLC
(Exhibit 10.A to our Current Report on Form 8-K filed with the
SEC on April 9, 2007).
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*12
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Ratio of
Earnings to Fixed Charges.
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21
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Omitted
pursuant to the reduced disclosure format permitted by General Instruction
I to Form 10-K.
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*23
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Consent of
Independent Registered Public Accounting Firm Ernst & Young
LLP.
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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 Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley
Act of 2002.
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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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*32.B
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Certification
of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley
Act of 2002.
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49