Attached files
UNITED
STATES SECURITIES AND EXCHANGE COMMISSION
Washington,
D.C. 20549
________________
Form
10-K
(Mark One)
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R
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ANNUAL
REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF
1934
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For
the fiscal year ended December 31, 2009
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OR
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£
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TRANSITION REPORT PURSUANT TO
SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF
1934
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For
the transition period
from to
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Commission
File Number 1-4101
Tennessee
Gas Pipeline Company
(Exact Name of
Registrant as Specified in Its Charter)
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Delaware
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74-1056569
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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
(Do not check
if a smaller reporting company)
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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 $5 per share. Shares outstanding on March 1, 2010: 208
TENNESSEE GAS PIPELINE 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
TENNESSEE
GAS PIPELINE COMPANY
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Caption
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Page
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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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MMBtu
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million
British thermal units
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BBtu
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billion
British thermal units
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MMcf
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million cubic
feet
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Bcf
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=
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billion cubic
feet
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NGL
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=
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natural gas
liquid
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Dth
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=
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dekatherm
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TBtu
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=
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trillion
British thermal units
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LNG
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=
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liquefied
natural gas
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Tonne
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=
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metric
tonne
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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 “TGP”, we are describing Tennessee Gas Pipeline
Company and/or our subsidiaries.
Overview
and Strategy
We are a Delaware
corporation incorporated in 1947, 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 system and storage facilities as discussed
below.
Our pipeline system
and storage facilities operate 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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executing
successfully on our backlog of committed expansion
projects;
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developing
new growth projects in our market and supply
areas;
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maintaining
the integrity and ensuring the safety of our pipeline system and other
assets;
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optimizing
our contract portfolio;
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focusing on
efficiency and synergies across our system;
and
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managing
market segmentation and
differentiation.
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Pipeline System. Our pipeline
system consists of approximately 13,700 miles of pipeline with a design capacity
of approximately 7,208 MMcf/d. During 2009, 2008 and 2007, average throughput
was 4,614 BBtu/d, 4,864 BBtu/d and 4,880 BBtu/d. This multiple-line system
begins in the natural gas producing regions of Louisiana, the Gulf of Mexico and
south Texas and extends to the northeast section of the U.S., including the
metropolitan areas of New York City and Boston. Our system also has
interconnects at the U.S.- Mexico border and the U.S.- Canada
border.
Underground Natural Gas Storage
Facilities. Along our pipeline system, we have approximately 92 Bcf of
underground working natural gas storage capacity. Of this amount, 29 Bcf is
contracted from Bear Creek Storage Company, LLC (Bear Creek), our affiliate.
Bear Creek, which owns and operates an underground natural gas storage facility
located in Bienville Parish, Louisiana, is a joint venture equally owned by us
and our affiliate, Southern Natural Gas Company (SNG). The facility has 58 Bcf
of working storage capacity that is committed equally to SNG and us under
long-term contracts.
Markets
and Competition
Our customers
consist of natural gas distribution and industrial companies, electric
generation companies, natural gas producers, other natural gas pipelines and
natural gas marketing and trading companies. We provide transportation and
storage services in both our natural gas supply and market areas. Our pipeline
system connects with multiple pipelines that provide our customers with access
to diverse sources of supply and various natural gas markets.
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 on pipelines. The impact will
vary among pipelines according to the proximity of the new supply sources. Our
pipeline is connected to two major shale formations, the Haynesville in northern
Louisiana and Texas and the Marcellus in Pennsylvania. It is likely that
natural gas from these sources, will over time, replace receipts from
traditional sources in south Texas and the Gulf of Mexico on our system. In
addition, our system is close to the Eagle Ford shale formation in south Texas,
which could be a major source of supply into the system in the future.
This will affect the flows on the system and the array of shipper
contracts.
Another change in
the supply patterns is the reduction in imports from Canada. This decrease has
been the result of declining production and increasing demand in Canada. This
reduction has led to increased demand for domestic supplies and related
transportation services, but it has been offset in part by imported LNG.
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 also may 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; however,
this sector experienced a decline in demand in 2009 as a result of the downturn
in the economy. We expect demand to return as the economy recovers. 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.
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 respond 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. 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.
In response to
changing market conditions, we have shifted from a traditional dependence solely
on long-term contracts to an approach that balances short-term and long-term
commitments. This shift, which can increase the volatility of our revenues, is
due to changes in market conditions and competition driven by state utility
deregulation, local distribution company mergers, new pipeline competition,
shifts in supply sources, volatility in natural gas prices, demand for
short-term capacity and new power generation markets.
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. However, we have entered into a substantial portion of firm
transportation contracts at amounts that are less than these maximum allowable
rates to remain competitive.
We face competition
in all our market areas and we compete with other interstate and intrastate
pipelines for deliveries to multiple-connection customers who can take
deliveries at alternative points. Natural gas delivered on our system competes
with alternative energy sources used to generate electricity such as,
hydroelectric power, coal and fuel oil. In addition, we compete with pipelines
and gathering systems for connection to new supply sources in Texas, the Gulf of
Mexico, and the emerging shale basins.
The following table
details our customer and contract information related to our pipeline system as
of December 31, 2009. Firm customers reserve capacity on our
pipeline system and storage facilities and are obligated to pay a monthly
reservation or demand charge, regardless of the amount of natural gas they
transport or store, for the term of their contracts. Interruptible customers are
customers without reserved capacity that pay usage charges based on the volume
of gas they transport, store, inject or withdraw.
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Customer Information
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Contract Information
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Approximately
470 firm and interruptible customers.
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Approximately 510
firm transportation contracts. Weighted average remaining contract term of
approximately four years.
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Major
Customer:
National Grid
USA and Subsidiaries
(766
BBtu/d)
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Expire in
2011-2029.
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Regulatory
Environment
Our interstate
natural gas transmission system and storage operations are regulated by the FERC
under the Natural Gas Act of 1938, the Natural Gas Policy Act of 1978 and the
Energy Policy Act of 2005. We operate under tariffs approved by the FERC that
establish rates, cost recovery mechanisms and other terms and conditions of
services 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 system is also subject to federal, state and local safety and
environmental statutes and regulations of the U.S. Department of Transportation
and the U.S. Department of the Interior. We have ongoing inspection programs
designed to keep our facilities in compliance with pipeline safety and
environmental requirements and we believe that our system is in material
compliance with the applicable regulations.
Environmental
A description of
our environmental activities is included in Part II, Item 8, Financial
Statements and Supplementary Data, Note 8, and is incorporated herein by
reference.
Employees
As of February 23,
2010, we had approximately 1,630 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 volumes of natural gas we are able to transport and store depends
on the actions of third parties and are beyond our control. Such actions include
factors that impact our customers’ demand and producers’ supply, including
factors that negatively impact our customers’ need for natural gas from us, as
well as the continued availability of natural gas production and reserves
connected to our pipeline system. Further, the following factors,
most of which are also beyond our control, may unfavorably impact our ability to
maintain or increase current throughput, or to remarket unsubscribed capacity on
our pipeline system:
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service area
competition;
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price
competition;
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changes in
regulation and actions of regulatory
bodies;
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weather
conditions that impact natural gas throughput and storage
levels;
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weather
fluctuations or warming or cooling trends that may impact demand in the
markets in which we do business, including trends potentially attributable
to climate change;
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continued
development of additional sources of gas supply that can be
accessed;
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decreased natural gas demand
due to various factors, including economic recession (as further discussed
below), availability of alternate energy sources and increases in
prices;
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legislative,
regulatory or judicial actions, such as mandatory renewable portfolio
standards and greenhouse gas (GHG) regulations and/or legislation that
could result in (i) changes in the demand for natural gas and oil, (ii)
changes in the availability of or demand for alternative energy sources
such as hydroelectric and nuclear power, wind and solar energy and/or
(iii) changes in the demand for less carbon intensive energy
sources;
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availability
and cost to fund ongoing maintenance and growth projects, especially in
periods of prolonged economic
decline;
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opposition to
energy infrastructure development, especially in environmentally sensitive
areas;
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adverse
general economic conditions including prolonged recessionary periods that
might negatively impact natural gas demand and the capital
markets;
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our ability
to achieve targeted annual operating and administrative expenses primarily
by reducing internal costs and improving efficiencies from leveraging a
consolidated supply chain organization;
and
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unfavorable
movements in natural gas prices in certain supply and demand
areas.
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A substantial
portion of our revenues are generated from firm transportation contracts that
must be renegotiated periodically.
Our revenues are
generated under transportation and storage contracts which expire periodically
and must be renegotiated, extended or replaced. If we are unable to extend or
replace these contracts when they expire or renegotiate contract terms as
favorable as the existing contracts, we could suffer a material reduction in our
revenues, earnings and cash flows. Currently, a substantial portion of our
revenues are under contracts that are discounted at rates below the maximum
rates allowed under our tariff. For additional information on the expiration of
our contract portfolio, see Part II, Item 7, Management’s Discussion and
Analysis of Financial Condition and Results of Operations. In particular, our
ability to extend and replace contracts could be adversely affected by factors
we cannot control as discussed in more detail above. In addition, changes in
state regulation of local distribution companies may cause us to negotiate
short-term contracts or turn back our capacity when our contracts
expire.
For 2009, our
revenues from National Grid USA and Subsidiaries represented approximately 12
percent of our operating revenues. For additional information on our revenues
from this customer, see Part II, Item 8, Financial Statements and Supplementary
Data, Note 10. The loss of this customer or a decline in its creditworthiness
could adversely affect our results of operations, financial position and cash
flows.
We
are exposed to the credit risk of our customers and our credit risk management
may not be adequate to protect against such risk.
We are subject to
the risk of delays in payment as well as losses resulting from nonpayment and/or
nonperformance by our customers, including default risk associated with adverse
economic conditions. Our credit procedures and policies may not be adequate to
fully eliminate customer credit risk. In addition, in certain situations, we may
assume certain additional credit risks for competitive reasons or otherwise. If
our existing or future customers fail to pay and/or perform and we are unable to
remarket the capacity, our business, the results of our operations
and our financial condition could be adversely affected. We may not be able to
effectively remarket capacity during and after insolvency proceedings involving
a shipper.
A
portion of our transportation services are provided pursuant to long-term,
fixed-price “negotiated rate” contracts that are not subject to adjustment, even
if our cost to perform such services exceeds the revenues received from such
contracts, and, as a result, our costs could exceed our revenues received under
such contracts.
It is possible that
costs to perform services under “negotiated rate” contracts will exceed the
negotiated rates. Under FERC policy, a regulated service provider and a customer
may mutually agree to sign a contract for service at a “negotiated rate” which
may be above or below the FERC regulated “recourse rate” for that service, and
that contract must be filed and accepted by FERC. These “negotiated rate”
contracts are not generally subject to adjustment for increased costs which
could be produced by inflation, cost of capital, taxes or other factors relating
to the specific facilities being used to perform the services. Any shortfall of
revenue, representing the difference between “recourse rates” (if higher) and
negotiated rates, under current FERC policy is generally not recoverable from
other shippers.
Fluctuations in
energy commodity prices could adversely affect our business.
Revenues generated
by our transportation and storage contracts depend on volumes and rates, both of
which can be affected by the price of natural gas. Increased natural gas prices
could result in a reduction of the volumes transported by our customers,
including power companies that may not dispatch natural gas-fired power plants
if natural gas prices increase. Increased prices could also result in industrial
plant shutdowns or load losses to competitive fuels as well as local
distribution companies’ loss of customer base. The success of our transmission
and storage operations is subject to continued development of additional gas
supplies to offset the natural decline from existing wells connected to our
system, which requires the development of additional oil and natural gas
reserves and obtaining additional supplies from interconnecting pipelines,
primarily in the emerging shale basins. A decline in energy prices could cause a
decrease in these development activities and could cause a decrease in the
volume of reserves available for transportation and storage through our
system.
We retain a fixed
percentage of natural gas transported as provided in our tariff. This retained
natural gas is used as fuel and to replace lost and unaccounted for natural gas.
We are at risk if we retain less natural gas than needed for fuel and to replace
lost and unaccounted for natural gas. Pricing volatility may impact the value of
under or over recoveries of retained natural gas, imbalances and system
encroachments. If natural gas prices in the supply basins connected to our
pipeline system are higher than prices in other natural gas producing regions,
our ability to compete with other transporters may be negatively impacted on a
short-term basis, as well as with respect to our long-term recontracting
activities. Furthermore, fluctuations in pricing between supply sources and
market areas could negatively impact our transportation revenues. Consequently,
a significant prolonged downtown in natural gas prices could have a material
adverse effect on our financial condition, results of operations and liquidity.
Fluctuations in energy prices are caused by a number of factors,
including:
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regional,
domestic and international supply and demand, including changes in supply
and demand due to general economic conditions and
weather;
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availability
and adequacy of gathering, processing and transportation
facilities;
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energy
legislation and regulation, including potential changes associated with
GHG emissions and renewable portfolio
standards;
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federal and
state taxes, if any, on the sale or transportation and storage of natural
gas and NGL;
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the price and
availability of supplies of alternative energy sources;
and
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the level of
imports, including the potential impact of political unrest among
countries producing oil and LNG, as well as the ability of certain foreign
countries to maintain natural gas and oil prices, production and export
controls.
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The agencies that
regulate us and our customers could affect our
profitability.
Our business is
regulated by the FERC, the U.S. Department of Transportation, the U.S.
Department of the Interior and various state and local regulatory agencies whose
actions have the potential to adversely affect our profitability. In particular,
the FERC regulates the rates we are permitted to charge our customers for our
services and sets authorized rates of return.
We periodically
file with the FERC to adjust the rates charged to our
customers. In establishing those rates, the FERC uses a discounted
cash flow model that incorporates the use of proxy groups to develop a range of
reasonable returns earned on equity interests in companies with corresponding
risks. The FERC then assigns a rate of return on equity within that range to
reflect specific risks of that pipeline when compared to the proxy group
companies. Depending on the specific risks faced by us and the companies
included in the proxy group, the FERC may establish rates that are not
acceptable to us and have a negative impact on our cash flows, profitability and
results of operations. In addition, pursuant to laws and regulations, our
existing rates may be challenged by complaint. The FERC commenced several
complaint proceedings in 2009 against unaffiliated pipeline systems to reduce
the rates they were charging their customers. There is a risk that
the FERC or our customers could file similar complaints on our pipeline system
and that a successful complaint against our rates could have an adverse impact
on our cash flows and results of operations.
Also, increased
regulatory requirements relating to the integrity of our pipeline requires
additional spending in order to maintain compliance with these requirements. Any
additional requirements that are enacted could significantly increase the amount
of these expenditures. Further, state agencies that regulate our local
distribution company customers could impose requirements that could impact
demand for our services.
Environmental
compliance and remediation costs and the costs of environmental liabilities could
exceed our estimates.
Our operations are
subject to various environmental laws and regulations regarding compliance and
remediation obligations. Compliance obligations can result in significant costs
to install and maintain pollution controls, fines and penalties resulting from
any failure to comply and potential limitations on our operations. Remediation
obligations can result in significant costs associated with the investigation or
clean-up of contaminated properties (some of which have been designated as
Superfund sites by the U.S. Environmental Protection Agency (EPA) under the
Comprehensive Environmental Response, Compensation and Liability Act), as well
as damage claims arising out of the contamination of properties or impact on
natural resources. Although we believe we have established appropriate reserves
for our environmental liabilities, it is not possible for us to estimate the
exact amount and timing of all future expenditures related to environmental
matters and we could be required to set aside additional amounts which could
significantly impact our future consolidated results of operations, financial
position, or cash flows. See Part II, Item 8, Financial Statements and
Supplementary Data, Note 8.
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;
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forecasting
cash flow timing to implement proposed pollution control and cleanup
costs;
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receiving
regulatory approval for remediation
programs;
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quantifying
liability under environmental laws that may impose joint and several
liability on potentially responsible parties and managing allocation
responsibilities;
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evaluating
and understanding environmental laws and regulations, including their
interpretation and enforcement;
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interpreting
whether various maintenance activities performed in the past
and currently being performed required pre-construction permits
pursuant to the Clean Air Act; and
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changing
environmental laws and regulations that may increase our
costs.
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In addition to
potentially increasing the cost of our environmental liabilities, changing
environmental laws and regulations may increase our future compliance costs,
such as the costs of complying with ozone standards, emission standards with
regard to our reciprocating internal combustion engines on our pipeline system,
GHG reporting and potential mandatory GHG emissions reductions. Future
environmental compliance costs relating to GHGs associated with our operations
are not yet clear. For a further discussion on GHGs, see Part II, Item 7,
Management’s Discussion and Analysis of Financial Condition and Results of
Operations, Commitments and Contingencies.
Although it is
uncertain what impact legislative, regulatory, and judicial actions might have
on us until further definition is provided in those forums, there is a risk that
such future measures could result in changes to our operations and to the
consumption and demand for natural gas. Changes to our operations could include
increased costs to (i) operate and maintain our facilities, (ii) install new
emission controls on our facilities, (iii) construct new facilities, (iv)
acquire allowances or pay taxes related to our GHG and other emissions, and (v)
administer and manage an emissions program for GHG and other emissions. Changes
in regulations, including adopting new standards for emission controls from
certain of our facilities, could also result in delays in obtaining required
permits to construct or operate our facilities. While we may be able to include
some or all of the costs associated with our environmental liabilities and
environmental compliance in the rates charged by our pipeline and in the prices
at which we sell natural gas, our ability to recover such costs is uncertain and
may depend on events beyond our control including the outcome of future rate
proceedings before the FERC and the provisions of any final regulations and
legislation.
Our operations
are subject to operational hazards and uninsured risks.
Our operations are
subject to the inherent risks normally associated with pipeline operations,
including pipeline failures, explosions, pollution, release of toxic substances,
fires, adverse weather conditions (such as hurricanes and 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
hurricanes, flooding, etc.) are uncertain at this time, changes in climate
patterns as a result of global emissions of GHG could have a negative impact on
our operations in the future.
While we maintain
insurance against many of these risks to the extent and in amounts that we
believe are reasonable, our insurance coverages have material deductibles as
well as limits on our maximum recovery, and do not cover all risks. There is
also the risk that our coverages will change over time in light of increased
premiums or changes in the terms of the insurance coverages that could result in
our decision to either terminate certain coverages, increase our deductibles or
decrease our maximum recoveries. In addition, there is a risk that our insurers
may default on their coverage obligations. As a result, our results of
operations, cash flows or financial condition could be adversely affected if a
significant event occurs that is not fully covered by insurance.
The expansion of
our business by constructing new facilities subjects us to construction and
other risks that may adversely affect our financial results.
We may expand the
capacity of our existing pipeline or storage facilities by constructing
additional facilities. Construction of these facilities is subject to various
regulatory, development and operational risks, including:
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•
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our ability
to obtain necessary approvals and permits by the FERC and other regulatory
agencies on a timely basis and on terms that are acceptable to us,
including the potential impact of delays and increased costs caused by
certain environmental and landowner groups with interests along the route
of our pipeline;
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•
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the ability
to access sufficient capital at reasonable rates to fund expansion
projects, especially in periods of prolonged economic decline when we may
be unable to access the capital
markets;
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•
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the
availability of skilled labor, equipment, and materials to complete
expansion projects;
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•
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potential
changes in federal, state and local statutes, regulations and orders, such
as environmental requirements, including climate change requirements, that
delay or prevent a project from proceeding or increase the anticipated
cost of the project;
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•
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impediments
on our ability to acquire rights-of-way or land rights or to commence and
complete construction on a timely basis or on terms that are acceptable to
us;
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•
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our ability
to construct projects within anticipated costs, including the risk that we
may incur cost overruns resulting from inflation or increased costs of
equipment, materials, labor, contractor productivity, delays in
construction or other factors beyond our control, that we may not be able
to recover from our customers which may be
material;
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•
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the lack of
future growth in natural gas supply and/or demand;
and
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•
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the lack of
transportation, storage or throughput
commitments.
|
Any of these risks
could prevent a project from proceeding, delay its completion or increase its
anticipated costs. There is also the risk that the downturn in the economy and
its negative impact upon natural gas demand may result in either slower
development in our expansion projects or adjustments in the contractual
commitments supporting such projects. As a result, new facilities may be delayed
or we may not achieve our expected investment return, which could adversely
affect our results of operations, cash flows or financial position.
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 such
recession or prolonged economic slowdown, including creating preference for
renewables, as part of a legislative package to stimulate the economy. Any of
these events, which are beyond our control, could negatively impact our
business, results of operations, financial condition, and
liquidity.
We
are subject to financing and interest rate risks.
Our future success,
financial condition and liquidity could be adversely affected based on our
ability to access capital markets and obtain financing at cost effective rates.
This is dependent on a number of factors in addition to general economic
conditions discussed above, many of which we cannot control, including changes
in:
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•
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our credit
ratings;
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•
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the
structured and commercial financial
markets;
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•
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market
perceptions of us or the natural gas and energy
industry;
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•
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tax rates due
to new tax laws; and
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•
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market prices
for hydrocarbon products.
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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:
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•
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our payment
of dividends;
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•
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decisions on
our financing and capital raising
activities;
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•
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mergers or
other business combinations;
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•
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our
acquisitions or dispositions of assets;
and
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•
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our
participation in El Paso’s cash management
program.
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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 the credit rating agencies continue to review our and El Paso’s
leverage, liquidity and credit profile. Any reduction in our or El Paso’s credit
ratings could impact our ability to access the capital markets, as well as our
cost of capital 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 12.
We may be subject
to a change in 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 7.
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.
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 8, 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 $5 per share, is owned by an indirect 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. No common stock dividends were
declared or paid in 2009 or 2008.
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, coal
and fuel oil. Our revenues from transportation and storage services consist of
the following types.
|
Type
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Description
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Percent
of Total
Revenues in 2009
|
|
Reservation
|
Reservation
revenues are from customers (referred to as firm customers) that reserve
capacity on our pipeline system and storage facilities. These firm
customers are obligated to pay a monthly reservation or demand charge,
regardless of the amount of natural gas they transport or store, for the
term of their contracts.
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61
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Usage and
Other
|
Usage
revenues are from both firm customers and interruptible customers (those
without reserved capacity) that pay usage charges and provide fuel in-kind
based on the volume of gas actually transported, stored, injected or
withdrawn. We also earn revenue from other miscellaneous
sources.
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39
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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, 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. We also experience volatility in our financial results when the amounts
of natural gas used in our operations differ from the amounts we recover from
our customers for that purpose.
In response to
changing market conditions, we have shifted from a traditional dependence solely
on long-term contracts to an approach that balances short-term and long-term
commitments. This shift, which can increase the volatility of our revenues, is
due to changes in market conditions and competition driven by state utility
deregulation, local distribution company mergers, new pipeline competition,
shifts in supply sources, volatility in natural gas prices, demand for
short-term capacity and new power generation markets.
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. However, we have entered into a substantial portion of 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 four years as of December 31, 2009. Below are the
contract expiration portfolio and the associated revenue expirations for our
firm transportation contracts as of December 31, 2009, including those with
terms beginning in 2010 or later.
|
Contracted
Capacity
|
Percent
of Total
Contracted Capacity
|
Reservation Revenue
|
Percent
of Total
Reservation Revenue
|
|||||||||||||
| (BBtu/d) | (In millions) |
|
||||||||||||||
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2010
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635 | 8 | $ | 1 | — | |||||||||||
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2011
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603 | 8 | 30 | 6 | ||||||||||||
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2012
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2,348 | 29 | 77 | 14 | ||||||||||||
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2013
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1,392 | 17 | 121 | 23 | ||||||||||||
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2014
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624 | 8 | 68 | 13 | ||||||||||||
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2015 and
beyond
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2,409 | 30 | 234 | 44 | ||||||||||||
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Total
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8,011 | 100 | $ | 531 | 100 | |||||||||||
Results
of Operations
Our management uses
earnings before interest expense and income taxes (EBIT) as a measure to assess
the operating results and effectiveness of our business, which consists of
consolidated operations as well as an investment in an unconsolidated affiliate.
We believe EBIT is useful to investors to provide them with the same measure
used by El Paso to evaluate our performance. We define EBIT as net income
adjusted for items such as (i) interest and debt expense, (ii) affiliated
interest income, and (iii) income taxes. We exclude interest and debt expense
from this measure so that investors may evaluate our operating results without
regard to our financing methods. EBIT may not be comparable to measures used by
other companies. Additionally, EBIT should be considered in conjunction with net
income, income before taxes and other performance measures such as operating
income or operating cash flows. Below is a reconciliation of our EBIT to our net
income, our throughput volumes and an analysis and discussion of our results for
the year ended December 31, 2009 compared with 2008.
Operating
Results:
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2009
|
2008
|
||||||
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(In
millions,
|
||||||||
|
except
for volumes)
|
||||||||
|
Operating
revenues
|
$ | 933 | $ | 907 | ||||
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Operating
expenses
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(612 | ) | (645 | ) | ||||
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Operating
income
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321 | 262 | ||||||
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Earnings from
unconsolidated affiliate
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11 | 13 | ||||||
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Other income,
net
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13 | 10 | ||||||
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EBIT
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345 | 285 | ||||||
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Interest and
debt expense
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(155 | ) | (136 | ) | ||||
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Affiliated
interest income, net
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16 | 33 | ||||||
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Income tax
expense
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(79 | ) | (71 | ) | ||||
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Net
income
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$ | 127 | $ | 111 | ||||
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Throughput
volumes (BBtu/d)
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4,614 | 4,864 | ||||||
EBIT
Analysis:
|
|
Revenue
|
Expense
|
Other
|
EBIT
Impact
|
||||||||||||
|
Favorable/(Unfavorable)
|
||||||||||||||||
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(In
millions)
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||||||||||||||||
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Gas not used
in operations and other natural gas sales
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$ | 19 | $ | 13 | $ | — | $ | 32 | ||||||||
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Expansions
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7 | (2 | ) | 6 | 11 | |||||||||||
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Hurricanes
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10 | 11 | — | 21 | ||||||||||||
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Reservation
and other services revenue
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(12 | ) | — | — | (12 | ) | ||||||||||
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Loss on
long-lived assets
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— | 24 | — | 24 | ||||||||||||
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Operating and
general and administrative expenses
|
— | (7 | ) | — | (7 | ) | ||||||||||
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Other(1)
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2 | (6 | ) | (5 | ) | (9 | ) | |||||||||
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Total impact
on EBIT
|
$ | 26 | $ | 33 | $ | 1 | $ | 60 | ||||||||
____________
|
(1)
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Consists
of individually insignificant
items.
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Gas Not Used in Operations and Other
Natural Gas Sales. The financial impact of operational gas, net of gas
used in operations, is based on the amount of natural gas we are allowed to
retain and dispose of according to our tariff, relative to the amounts of
natural gas we use for operating purposes and the price of natural gas. The
financial impact of gas not used for operations is influenced by factors such as
system throughput, facility enhancements and the ability to operate the system
efficiently. Gas not used for operations results in revenues to us, which we
recognize when the volumes are retained. During 2009, our EBIT increased
primarily due to a $19 million favorable impact resulting from higher retained
fuel volumes in excess of fuel used to operate our system and higher average
realized prices on operational sales, partially offset by a lower index price
used to value the volumes that we retained as compared to 2008. Our EBIT was
also favorably impacted by $13 million due to lower electric compression
utilization.
Expansions
Projects Placed in Service in 2009
and 2008. In November 2008, we placed the Blue Water reconfiguration
project into service. In 2009, we placed several expansion projects in service
including the Carthage expansion in May, the Concord Lateral expansion in
October, and the Blue Water expansion in November. As a result, our revenues and
allowance for funds used during construction increased in 2009 as compared with
2008. These increases were partially offset by depreciation and operating
expenses of the new facilities.
Committed Projects Not Yet
Completed. The 300 Line expansion project involves the installation of
seven looping segments in Pennsylvania and New Jersey totaling approximately 128
miles of 30-inch pipeline, and the addition of approximately 52,000 horsepower
of compression following the installation of two new compressor stations and
upgrades at seven existing compressor stations. Upon completion, we expect this
project to increase natural gas delivery capacity in the region by approximately
350 MMcf/d. The 300 Line Expansion project will provide access to diversified
natural gas supplies from the Gulf Coast, Appalachian, and Marcellus shale
basin, and gas deliveries to points along the 300 Line path and into various
interconnections with other pipelines in northern New Jersey, as well as an
existing delivery point in White Plains, New York. The expected cost for this
project is approximately $642 million and is anticipated to be placed in
service November 2011. In July 2009, we filed an application with the FERC
for certificate authorization to construct and we anticipate
receiving their approval in the first quarter of 2010. All of the firm
transportation capacity resulting from this project in the northeast U.S. market
area is fully subscribed with one shipper based on a precedent agreement which
was executed in the third quarter of 2009. An environmental
assessment is expected to be issued by the FERC in the first quarter of
2010.
Our system is
located over a significant portion of the Marcellus shale basin that is under
various phases of development by producers. We have executed firm transportation
contracts with shippers from the basin utilizing existing capacity. We have been
in discussions with producers to expand our system to provide additional
transportation capacity from the Marcellus basin.
In February 2010,
we entered into precedent agreements with two shippers to provide 620 MMcf/d of
additional firm transportation service from receipt points in the Marcellus
shale basin to an interconnect in New Jersey. In order to accommodate the
additional service, we will pursue the Northeast Upgrade project, which includes
approximately 37 miles of 30 inch pipeline looping and the addition of
approximately 20,600 horsepower of additional compression. The expected cost for
this project is approximately $416 million and construction is anticipated to be
placed in service November 2013.
Hurricanes. During 2008, we
incurred damage to sections of our Gulf Coast and offshore pipeline facilities
due to Hurricanes Gustav and Ike. In 2008, we recorded losses of $29 million
related to gas loss from various damaged facilities, lower volume of gas not
used in operations, lower usage revenue, and repair costs that were not
recoverable from insurance due to losses not exceeding self-retention levels. In
2009, we recorded losses of $8 million for repair costs that were not
recoverable from insurance. We continue to evaluate those damaged facilities for
further repair or retirement. See Liquidity and Capital
Resources for a further discussion of the hurricanes.
Reservation and Other Services
Revenues. During 2009, our EBIT was unfavorably impacted by a decrease of
$10 million in usage revenues due to decreased activity under various
interruptible services provided under our tariff and a decrease of approximately
$10 million due to increasing competition in the southeast area and milder
weather. Partially offsetting these decreases was an increase of approximately
$8 million in capacity sales primarily from the Marcellus shale basin in the
northeast market area due to transportation contracts with shippers which were
executed during 2009.
During 2009, our
throughput volumes decreased compared with 2008. This was due, in part, to
general weakness in natural gas demand in the U.S., including general reductions
in industrial and power generation loads in the northeast. The demand for gas
from the power generation sector was negatively impacted by economic factors but
positively impacted by the displacement of coal-fired generation by gas-fired
generation. Although fluctuations in throughput on our system have a limited
impact on our short-term financial results because the majority of
our revenues are derived from firm reservation charges, 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. Continuing negative economic
impacts on demand, as well as adverse shifting of sources of supply, could
negatively impact basis differentials 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 we determine there is a significant change
in our costs or billing determinants, we will have the option to file a rate
case with the FERC to recover our prudently incurred costs.
Loss on Long-Lived Assets.
During 2008, we recorded impairments of $25 million, including an impairment
related to our Essex-Middlesex Lateral project due to its prolonged permitted
process.
Operating and General and
Administrative Expenses. During 2009, our operating and
general and administrative expenses were increased primarily due to higher
benefits and pension costs of approximately $21 million, partially offset by a
reduction of $13 million in pipeline maintenance costs.
Interest
and Debt Expense
Interest and debt
expense for the year ended December 31, 2009, was $19 million higher than in
2008 primarily due to the issuance of $250 million of 8.00% senior notes in
January 2009.
Affiliated
Interest Income, Net
Affiliated interest
income, net for the year ended December 31, 2009, was $17 million lower than in
2008 primarily due to lower average short-term interest rates on advances to El
Paso under its cash management program, partially offset by higher average
advances. 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
millions, except for rates)
|
||||||||
|
Average
advance due from El Paso
|
$ | 931 | $ | 768 | ||||
|
Average
short-term interest rate
|
1.7 | % | 4.4 | % | ||||
Income
Taxes
Our effective tax
rate of 38 percent and 39 percent for the years ended December 31, 2009 and 2008
was higher than the statutory rate of 35 percent due to the effect of state
income taxes. For a reconciliation of the statutory rate to the effective tax
rates, see Item 8, Financial Statements and Supplementary Data, Note
3.
Liquidity
and Capital Resources
Our primary sources
of liquidity are cash flows from operating activities and El Paso’s cash
management program. At December 31, 2009, we had notes receivable from El Paso
of approximately $1.0 billion of which approximately $93 million was classified
as current based on the net amount we anticipate using in the next twelve months
considering available cash sources and needs. At December 31, 2009, we had a
non-interest bearing note receivable of $334 million from an El Paso affiliate.
This note is reflected as a reduction of our stockholder’s equity based on
uncertainties regarding the timing and method through which El Paso will settle
these balances. See Item 8, Financial Statements and Supplementary Data, Note 12
for a further discussion of El Paso’s cash management program and our other
affiliate note receivable. Our primary uses of cash are for working capital and
capital expenditures. 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
|
$ | 139 | $ | 159 | ||||
|
Expansions
|
128 | 179 | ||||||
|
Hurricanes
|
30 | 35 | ||||||
|
Other(1)
|
64 | 97 | ||||||
|
Total
|
$ | 361 | $ | 470 | ||||
____________
|
(1)
|
Relates
to building renovations at our corporate
facilities.
|
Our expected 2010
expansion capital expenditures primarily relate to our 300 Line expansion
project. Our maintenance capital expenditures primarily relate to maintaining
and improving the integrity of our pipeline, complying with regulations and
ensuring the safe and reliable delivery of natural gas to our customers. In
addition, we continue to evaluate our damaged facilities caused by hurricanes
Ike and Gustav for further repair or retirement.
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 mostly 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 8, 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 4.7 million tonnes of carbon dioxide equivalent emissions
during 2008. We
believe that approximately 4.1 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 one-third 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 and construction projects remains
uncertain.
In addition, in
March 2009, the EPA proposed a rule impacting emissions from reciprocating
internal combustion engines, which would require us to install emission controls
on our pipeline system. It is expected that the rule will be
finalized in August 2010. As proposed, engines subject to the regulations
would have to be in compliance by August 2013. Based upon that timeframe,
we would expect that we would commence incurring expenditures in late 2010, with
the majority of the work and expenditures incurred in 2011 and 2012.
If the regulations are adopted as proposed, we would expect to incur
approximately $22 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
See Item 8,
Financial Statements and Supplementary Data, Note 1, under New Accounting Pronouncements Issued But
Not Yet Adopted, which is incorporated herein by reference.
We are exposed to
the risk of changing interest rates. At December 31, 2009, we had interest
bearing notes receivable from El Paso of approximately $1.0 billion, with a
variable interest rate of 1.5% that are due upon demand. While we are exposed to
changes in interest income based on changes to the variable interest rate, the
fair value of these notes receivable approximates the carrying value due to the
notes being due on demand and the market-based nature of the interest
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
|
December 31, 2008
|
||||||||||||||||||||||
|
|
Expected
Fiscal Year of Maturity of
Carrying Amounts
|
|
||||||||||||||||||||||
|
|
2011
|
2014 and Thereafter
|
Total
|
Fair
Value
|
Carrying
Amount
|
Fair
Value
|
||||||||||||||||||
|
(In
millions, except for rates)
|
||||||||||||||||||||||||
|
Liabilities:
|
||||||||||||||||||||||||
|
Long-term
debt— fixed rate
|
$ | 83 | $ | 1,763 | $ | 1,846 | $ | 2,086 | $ | 1,605 | $ | 1,311 | ||||||||||||
|
Average
effective interest rate
|
7.5 | % | 7.8 | % | ||||||||||||||||||||
We are also exposed
to risks associated with changes in natural gas prices on natural gas that we
are allowed to retain, net of gas used in operations. Retained natural gas is
used as fuel and to replace lost and unaccounted for natural gas. We are at risk
if we retain less natural gas than needed for these purposes. Pricing volatility
may also impact the value of under or over recoveries of retained natural gas,
imbalances and system encroachments. We sell retained gas in excess of gas used
in operations when such gas is not operationally necessary or when such gas
needs to be removed from the system, which may subject us to both commodity
price and locational price differences depending on when and where that gas is
sold. In some cases, where we have made a determination that, by a certain point
in time, it is operationally necessary to dispose of gas not used in operations,
we use forward sales contracts, which include fixed price and variable price
contracts within certain price constraints, to manage this risk. In
December 2009, we entered into a contract with our affiliate, El Paso Marketing,
L.P., to sell up to 22 TBtu of natural gas not used in our operations in 2011 at
a price of $6.48 per MMBtu.
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 Tennessee Gas Pipeline Company
We have audited the
accompanying consolidated balance sheets of Tennessee Gas Pipeline 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 Tennessee Gas Pipeline 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
Notes 3 and 1 to the consolidated financial statements, effective
January 1, 2007, the Company adopted a new income tax accounting
standard, and 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
TENNESSEE
GAS PIPELINE COMPANY
CONSOLIDATED
STATEMENTS OF INCOME
(In
millions)
|
|
Year Ended December 31,
|
|||||||||||
|
|
2009
|
2008
|
2007
|
|||||||||
|
Operating
revenues
|
$ | 933 | $ | 907 | $ | 862 | ||||||
|
Operating
expenses
|
||||||||||||
|
Operation and
maintenance
|
370 | 386 | 338 | |||||||||
|
Depreciation
and amortization
|
187 | 182 | 170 | |||||||||
|
Loss on
long-lived assets
|
1 | 25 | — | |||||||||
|
Taxes, other
than income taxes
|
54 | 52 | 56 | |||||||||
| 612 | 645 | 564 | ||||||||||
|
Operating
income
|
321 | 262 | 298 | |||||||||
|
Earnings from
unconsolidated affiliate
|
11 | 13 | 13 | |||||||||
|
Other income,
net
|
13 | 10 | 19 | |||||||||
|
Interest and
debt expense
|
(155 | ) | (136 | ) | (130 | ) | ||||||
|
Affiliated
interest income, net
|
16 | 33 | 44 | |||||||||
|
Income before
income taxes
|
206 | 182 | 244 | |||||||||
|
Income tax
expense
|
79 | 71 | 91 | |||||||||
|
Net
income
|
$ | 127 | $ | 111 | $ | 153 | ||||||
See accompanying
notes.
22
TENNESSEE
GAS PIPELINE COMPANY
CONSOLIDATED
BALANCE SHEETS
(In
millions, except share amounts)
|
December 31,
|
||||||||
|
2009
|
2008
|
|||||||
|
ASSETS
|
||||||||
|
Current
assets
|
||||||||
|
Cash and cash
equivalents
|
$ | — | $ | — | ||||
|
Accounts and
notes receivable
|
||||||||
|
Customer
|
12 | 24 | ||||||
|
Affiliates
|
152 | 81 | ||||||
|
Other
|
13 | 13 | ||||||
|
Materials and
supplies
|
43 | 41 | ||||||
|
Deferred
income taxes
|
44 | 8 | ||||||
|
Other
|
8 | 10 | ||||||
|
Total current
assets
|
272 | 177 | ||||||
|
Property,
plant and equipment, at cost
|
4,680 | 4,365 | ||||||
|
Less
accumulated depreciation and amortization
|
936 | 884 | ||||||
| 3,744 | 3,481 | |||||||
|
Additional
acquisition cost assigned to utility plant, net
|
1,963 | 2,002 | ||||||
|
Total
property, plant and equipment, net
|
5,707 | 5,483 | ||||||
|
Other
assets
|
||||||||
|
Notes
receivable from affiliate
|
939 | 800 | ||||||
|
Investment in
unconsolidated affiliate
|
79 | 81 | ||||||
|
Other
|
70 | 53 | ||||||
| 1,088 | 934 | |||||||
|
Total
assets
|
$ | 7,067 | $ | 6,594 | ||||
|
LIABILITIES
AND STOCKHOLDER’S EQUITY
|
||||||||
|
Current
liabilities
|
||||||||
|
Accounts
payable
|
||||||||
|
Trade
|
$ | 60 | $ | 54 | ||||
|
Affiliates
|
72 | 36 | ||||||
|
Other
|
47 | 52 | ||||||
|
Taxes
payable
|
94 | 82 | ||||||
|
Contractual
deposits
|
31 | 60 | ||||||
|
Asset
retirement obligations
|
66 | 5 | ||||||
|
Accrued
interest
|
33 | 24 | ||||||
|
Regulatory
liabilities
|
28 | 3 | ||||||
|
Other
|
24 | 23 | ||||||
|
Total current
liabilities
|
455 | 339 | ||||||
|
Long-term
debt
|
1,846 | 1,605 | ||||||
|
Other
liabilities
|
||||||||
|
Deferred
income taxes
|
1,351 | 1,314 | ||||||
|
Regulatory
liabilities
|
153 | 191 | ||||||
|
Other
|
64 | 74 | ||||||
| 1,568 | 1,579 | |||||||
|
Commitments
and contingencies (Note 8)
|
||||||||
|
Stockholder’s
equity
|
||||||||
|
Common stock,
par value $5 per share; 300 shares authorized; 208 shares issued and
outstanding
|
— | — | ||||||
|
Additional
paid-in capital
|
2,209 | 2,209 | ||||||
|
Retained
earnings
|
1,323 | 1,196 | ||||||
|
Note
receivable from affiliate
|
(334 | ) | (334 | ) | ||||
|
Total
stockholder’s equity
|
3,198 | 3,071 | ||||||
|
Total
liabilities and stockholder’s equity
|
$ | 7,067 | $ | 6,594 | ||||
See accompanying
notes.
TENNESSEE
GAS PIPELINE COMPANY
CONSOLIDATED
STATEMENTS OF CASH FLOWS
(In
millions)
|
|
Year Ended December 31,
|
|||||||||||
|
|
2009
|
2008
|
2007
|
|||||||||
|
Cash flows
from operating activities
|
||||||||||||
|
Net
income
|
$ | 127 | $ | 111 | $ | 153 | ||||||
|
Adjustments
to reconcile net income to net cash from operating
activities
|
||||||||||||
|
Depreciation
and amortization
|
187 | 182 | 170 | |||||||||
|
Deferred
income tax expense
|
2 | 14 | 88 | |||||||||
|
Earnings from
unconsolidated affiliate, adjusted for cash distributions
|
2 | 3 | 14 | |||||||||
|
Loss on
long-lived assets
|
1 | 25 | — | |||||||||
|
Other
non-cash income items
|
(2 | ) | (4 | ) | (10 | ) | ||||||
|
Asset and
liability changes
|
||||||||||||
|
Accounts
receivable
|
17 | 19 | 15 | |||||||||
|
Accounts
payable
|
36 | 10 | (15 | ) | ||||||||
|
Taxes
payable
|
17 | 45 | (40 | ) | ||||||||
|
Other current
assets
|
(1 | ) | (5 | ) | (6 | ) | ||||||
|
Other current
liabilities
|
16 | (16 | ) | (4 | ) | |||||||
|
Non-current
assets
|
(24 | ) | — | (13 | ) | |||||||
|
Non-current
liabilities
|
(10 | ) | 21 | (66 | ) | |||||||
|
Net cash
provided by operating activities
|
368 | 405 | 286 | |||||||||
|
Cash flows
from investing activities
|
||||||||||||
|
Capital
expenditures
|
(361 | ) | (323 | ) | (364 | ) | ||||||
|
Net change in
notes receivable from affiliates
|
(232 | ) | (100 | ) | 39 | |||||||
|
Proceeds from
the sale of asset
|
— | — | 35 | |||||||||
|
Other
|
(9 | ) | 18 | 4 | ||||||||
|
Net cash used
in investing activities
|
(602 | ) | (405 | ) | (286 | ) | ||||||
|
Cash flows
from financing activities
|
||||||||||||
|
Net proceeds
from the issuance of long-term debt
|
234 | — | — | |||||||||
|
Other
|
— | — | — | |||||||||
|
Net cash
provided by financing activities
|
234 | — | — | |||||||||
|
Net change in
cash and cash equivalents
|
— | — | — | |||||||||
|
Cash and cash
equivalents
|
||||||||||||
|
Beginning of
period
|
— | — | — | |||||||||
|
End of
period
|
$ | — | $ | — | $ | — | ||||||
See accompanying
notes.
TENNESSEE
GAS PIPELINE COMPANY
CONSOLIDATED
STATEMENTS OF STOCKHOLDER’S EQUITY
(In
millions, except share amounts)
|
Common Stock
|
Additional
Paid-in
|
Retained
|
Note
Receivable from
|
Accumulated
Other
Comprehensive
|
Total
Stockholder’s
|
|||||||||||||||||||||||
| Shares | Amount |
Capital
|
Earnings | Affiliate | Income | Equity | ||||||||||||||||||||||
|
January 1,
2007
|
208 | $ | — | $ | 2,207 | $ | 947 | $ | — | $ | 3 | $ | 3,157 | |||||||||||||||
|
Net
income
|
153 | 153 | ||||||||||||||||||||||||||
|
Adoption of
new income tax accounting standard, net of income taxes of $(8) (Note
3)
|
(15 | ) | (15 | ) | ||||||||||||||||||||||||
|
Reclassification
to regulatory liability (Note 9)
|
(3 | ) | (3 | ) | ||||||||||||||||||||||||
|
Other
|
2 | 2 | ||||||||||||||||||||||||||
|
December 31,
2007
|
208 | — | 2,209 | 1,085 | — | — | 3,294 | |||||||||||||||||||||
|
Net
income
|
111 | 111 | ||||||||||||||||||||||||||
|
Reclassification
of note receivable from affiliate (Note 12)
|
(334 | ) | (334 | ) | ||||||||||||||||||||||||
|
December 31,
2008
|
208 | — | 2,209 | 1,196 | (334 | ) | — | 3,071 | ||||||||||||||||||||
|
Net
income
|
127 | 127 | ||||||||||||||||||||||||||
|
December 31,
2009
|
208 | $ | — | $ | 2,209 | $ | 1,323 | $ | (334 | ) | $ | — | $ | 3,198 | ||||||||||||||
See accompanying
notes.
TENNESSEE
GAS PIPELINE 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 1947, 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. We apply the equity method of accounting
where we can exert significant influence over, but do not control, the policies
and decisions of an entity and where we are not allocated a majority of the
entity’s losses and/or returns. We use the cost method of accounting where we
are unable to exert significant influence over the entity.
Use
of Estimates
The preparation of
our financial statements requires the use of estimates and assumptions that
affect the amounts we report as assets, liabilities, revenues and expenses and
our disclosures in these financial statements. Actual results can, and often do,
differ from those estimates.
Regulated
Operations
Our natural gas
pipeline and storage operations are subject to the jurisdiction of the Federal
Energy Regulatory Commission (FERC) under the Natural Gas Act of 1938, the
Natural Gas Policy Act of 1978 and the Energy Policy Act of 2005. We follow the
Financial Accounting Standards Board’s (FASB) accounting standards for regulated
operations. Under these standards, we record regulatory assets and liabilities
that would not be recorded under GAAP for non-regulated entities. Regulatory
assets and liabilities represent probable future revenues or expenses associated
with certain charges or credits that are expected to be recovered from or
refunded to customers through the rate making process. Items to which we apply
regulatory accounting requirements include certain postretirement employee
benefit plan costs, loss on reacquired debt, an equity return component on
regulated capital projects and certain costs related to gas not used in
operations and other costs included in, or expected to be included in, future
rates.
Cash
and Cash Equivalents
We consider
short-term investments with an original maturity of less than three months to be
cash equivalents.
Allowance
for Doubtful Accounts
We establish
provisions for losses on accounts receivable and for natural gas imbalances due
from shippers and operators if we determine that we will not collect all or part
of the outstanding balance. We regularly review collectability and establish or
adjust our allowance as necessary using the specific identification
method.
Materials
and Supplies
We value materials
and supplies at the lower of cost or market value with cost determined using the
average cost method.
Natural
Gas Imbalances
Natural gas
imbalances occur when the amount of natural gas delivered from or received by a
pipeline system 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 regulated 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.
Currently, our depreciation rates vary from one percent to 25 percent per year.
Using these rates, the remaining depreciable lives of these assets range from
one to 51 years. We re-evaluate depreciation rates each time we file with the
FERC for a change in our transportation and storage rates.
When we retire
regulated 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. For properties not
subject to regulation by the FERC, we reduce property, plant and equipment for
its original cost, less accumulated depreciation and salvage value with any
remaining gain or loss recorded in income.
Included in our
property balances are additional acquisition costs assigned to utility plant,
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
62 years using the same rates as the related assets, and we do not recover these
excess costs in our rates under current FERC policies.
At December 31,
2009 and 2008, we had $271 million and $207 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 $3 million, $3 million and $6 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 rate based on cost of service amounts
capitalized (exclusive of taxes) during the years ended December 31, 2009, 2008
and 2007, were $6 million, $6 million and $12 million. These equity amounts are
included in other income on our income statement.
Asset
and Investment Impairments
We evaluate assets
and investments for impairment when events or circumstances indicate that their
carrying values may not be recovered. These events include market declines that
are believed to be other than temporary, changes in the manner in which we
intend to use a long-lived asset, decisions to sell an asset or investment and
adverse changes in the legal or business environment such as adverse actions by
regulators. When an event occurs, we evaluate the recoverability of our carrying
value based on either (i) the long-lived asset’s ability to generate future cash
flows on an undiscounted basis or (ii) the fair value of the investment in an
unconsolidated affiliate. If an impairment is indicated, or if we decide to sell
a long-lived asset or group of assets, we adjust the carrying value of the asset
downward, if necessary, to its estimated fair value. Our fair value estimates
are generally based on market data obtained through the sales process or an
analysis of expected discounted cash flows. The magnitude of any impairment is
impacted by a number of factors, including the nature of the assets being sold
and our established time frame for completing the sale, among other
factors.
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.
Gas not used in operations is based on the volumes of natural gas we are allowed
to retain relative to the amounts of gas we use for operating purposes. We
recognize revenue on gas not used in operations from our shippers when we retain
the volumes at the market price required under our tariffs. We are subject to
FERC regulations and, as a result, revenues we collect may be subject to refund
in a rate proceeding. We establish reserves for these potential
refunds.
Environmental
Costs and Other Contingencies
Environmental Costs. We
record liabilities at their undiscounted amounts on our balance sheet as other
current and long-term liabilities when environmental assessments indicate that
remediation efforts are probable and the costs can be reasonably estimated.
Estimates of our liabilities are based on currently available facts, existing
technology and presently enacted laws and regulations, taking into consideration
the likely effects of other societal and economic factors, and include estimates
of associated legal costs. These amounts also consider prior experience in
remediating contaminated sites, other companies’ clean-up experience and data
released by the Environmental Protection Agency (EPA) or other organizations.
Our estimates are subject to revision in future periods based on actual costs or
new circumstances. We capitalize costs that benefit future periods and we
recognize a current period charge in operation and maintenance expense when
clean-up efforts do not benefit future periods.
We evaluate any
amounts paid directly or reimbursed by government sponsored programs and
potential recoveries or reimbursements of remediation costs from third parties,
including insurance coverage, separately from our liability. Recovery is
evaluated based on the creditworthiness or solvency of the third party, among
other factors. When recovery is assured, we record and report an asset
separately from the associated liability on our balance sheet.
Other Contingencies. We
recognize liabilities for other contingencies when we have an exposure that,
when fully analyzed, indicates it is both probable that a liability has been
incurred and the amount of loss can be reasonably estimated. Where the most
likely outcome of a contingency can be reasonably estimated, we accrue a
liability for that amount. Where the most likely outcome cannot be estimated, a
range of potential losses is established and if no one amount in that range is
more likely than any other, the low end of the range is accrued.
Income
Taxes
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.
For a further discussion of this accounting standard, see Note 3.
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.
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 9.
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. The adoption of the
measurement date provisions of this standard did not have a material impact on
our financial statements.
Effective December
31, 2009, we expanded our disclosures about postretirement benefit plan assets
as a result of new accounting disclosure requirements. See Note 9 for these
expanded disclosures.
New
Accounting Pronouncements Issued But Not Yet Adopted
As of December 31,
2009, the following accounting standards had not yet been adopted by
us.
Transfers of Financial Assets.
In June 2009, the FASB updated accounting standards on financial asset
transfers. Among other items, this update eliminated the concept of a qualifying
special-purpose entity (QSPE) for purposes of evaluating whether an entity
should be consolidated or not. The changes are effective for existing QSPEs as
of January 1, 2010 and for transactions entered into on or after January 1,
2010. The adoption of this accounting standard in January 2010 did not have a
material impact on our financial statements as we amended our existing accounts
receivable sales program in January 2010 (see Note 12).
Variable Interest Entities.
In June 2009, the FASB updated accounting standards for variable interest
entities to revise how companies determine the primary beneficiaries of these
entities, among other changes. Companies will be required to use a qualitative
approach based on their responsibilities and power over the entities’
operations, rather than a quantitative approach in determining the primary
beneficiary as previously required. The adoption of this accounting standard in
January 2010 did not have a material impact on our financial
statements.
2.
Loss on Long-Lived Assets
During 2008,
we recorded impairments of $25 million, including an impairment related to our
Essex-Middlesex lateral project due to its prolonged permitting
process.
3.
Income Taxes
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
|
$ | 76 | $ | 54 | $ | (1 | ) | |||||
|
State
|
1 | 3 | 4 | |||||||||
| 77 | 57 | 3 | ||||||||||
|
Deferred
|
||||||||||||
|
Federal
|
(7 | ) | 7 | 85 | ||||||||
|
State
|
9 | 7 | 3 | |||||||||
| 2 | 14 | 88 | ||||||||||
|
Total income
tax expense
|
$ | 79 | $ | 71 | $ | 91 | ||||||
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 | $ | 64 | $ | 85 | ||||||
|
State income
taxes, net of federal income tax effect
|
7 | 7 | 5 | |||||||||
|
Other
|
— | — | 1 | |||||||||
|
Income tax
expense
|
$ | 79 | $ | 71 | $ | 91 | ||||||
|
Effective tax
rate
|
38 | % | 39 | % | 37 | % | ||||||
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
|
$ | 1,494 | $ | 1,456 | ||||
|
Other
|
7 | 12 | ||||||
|
Total
deferred tax liability
|
1,501 | 1,468 | ||||||
|
Deferred tax
assets
|
||||||||
|
Net operating
loss and credit carryovers
|
||||||||
|
U.S.
federal
|
54 | 22 | ||||||
|
State
|
21 | 24 | ||||||
|
Other
liabilities
|
119 | 116 | ||||||
|
Total
deferred tax asset
|
194 | 162 | ||||||
|
Net deferred
tax liability
|
$ | 1,307 | $ | 1,306 | ||||
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.
Net Operating Loss (NOL) Carryovers.
The table below presents the details of our federal and state NOL
carryover periods as of December 31, 2009:
|
|
2011-2014 | 2015-2019 | 2020-2029 |
Total
|
||||||||||||
|
(In
millions)
|
||||||||||||||||
|
U.S. federal
NOL
|
$ | — | $ | 58 | $ | 96 | $ | 154 | ||||||||
|
State
NOL
|
52 | 308 | 181 | 541 | ||||||||||||
Usage of our U.S.
federal 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.
Unrecognized Tax Benefits
(Liabilities) for Uncertain Tax Matters. 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 the issues raised in this examination did not materially impact
our results of operations, financial condition or liquidity. For years in which
our returns are still subject to review, our unrecognized tax benefits
(liabilities for uncertain tax matters) could increase or decrease our income
tax expense and our effective income tax rates as these matters are finalized.
We are currently unable to estimate the range of potential impacts the
resolution of any contested matters could have on our financial
statements.
Upon the adoption
of a new income tax accounting standard related to accounting for uncertain tax
matters, and a related amendment to our tax sharing agreement with El Paso, we
recorded a reduction of $15 million to the January 1, 2007 balance of retained
earnings. As of December 31, 2009 and 2008, we had unrecognized tax benefits of
$16 million and $17 million. As of December 31, 2009 and 2008,
approximately $15 million (net of federal tax benefits) of unrecognized tax
benefits would affect our income tax expense and our effective income tax rate
if recognized in future periods. While the amount of our unrecognized tax
benefits could change in the next twelve months, we do not expect this change to
have a significant impact on our results of operations or financial
position.
We recognize
interest and penalties related to unrecognized tax benefits in income tax
expense on our income statement. As of December 31, 2009 and 2008, we had
liabilities for interest and penalties related to our unrecognized tax benefits
of approximately $7 million. During both 2009 and 2008, we accrued less than $1
million of interest.
4.
Fair Value of Financial Instruments
At December 31,
2009 and 2008, the carrying amounts of cash and cash equivalents and trade
receivables and payables are representative of their fair value because of the
short-term nature of these instruments. At December 31,
2009 and 2008, we had interest bearing notes receivable from El Paso of
approximately $1.0 billion and $0.8 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 these
notes receivable approximates the carrying value due to the notes 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
|
$ | 1,846 | $ | 2,086 | $ | 1,605 | $ | 1,311 | ||||||||
5.
Regulatory Assets and Liabilities
Our current and
non-current regulatory assets are included in other current and non-current
assets 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
|
$ | 3 | $ | 2 | ||||
|
Non-current
regulatory assets
|
||||||||
|
Taxes on
capitalized funds used during construction
|
31 | 29 | ||||||
|
Postretirement
benefits
|
4 | 10 | ||||||
|
Other
|
14 | 8 | ||||||
|
Total
non-current regulatory assets
|
49 | 47 | ||||||
|
Total
regulatory assets
|
$ | 52 | $ | 49 | ||||
|
Current
regulatory liabilities
|
||||||||
|
Environmental
|
$ | 28 | $ | — | ||||
|
Other
|
— | 3 | ||||||
|
Total current
regulatory liabilities
|
28 | 3 | ||||||
|
Non-current
regulatory liabilities
|
||||||||
|
Environmental
|
112 | 157 | ||||||
|
Postretirement
benefits
|
29 | 22 | ||||||
|
Other
|
12 | 12 | ||||||
|
Total
non-current regulatory liabilities
|
153 | 191 | ||||||
|
Total
regulatory liabilities
|
$ | 181 | $ | 194 | ||||
The significant
regulatory assets and liabilities include:
Taxes on Capitalized Funds Used
During Construction: These regulatory asset balance 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 are amortized 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.
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 recovered in rates. Postretirement
benefit amounts are recoverable in such periods as benefits are
funded.
Environmental: Includes
amounts collected, substantially in excess of certain Polychlorinated Biphenyls
(PCB) environmental remediation costs to date, through a surcharge to our
customers under a settlement approved by the FERC in November of
1995. For a further discussion of the PCB matter, see Note
8.
6. Property, Plant and
Equipment
Additional Acquisition Costs.
At December 31, 2009 and 2008, additional acquisition costs assigned to utility
plant was approximately $2.4 billion and accumulated depreciation was
approximately $418 million and $379 million, respectively. These additional
acquisition costs are being amortized over the life of the related pipeline
assets. Our amortization expense related to additional acquisition costs
assigned to utility plant was approximately $39 million, $41 million and $39
million for the years ended December 31, 2009, 2008 and 2007.
Asset Retirement Obligations.
We have legal obligations associated with the retirement of our natural gas
pipeline, transmission facilities and storage wells, as well as obligations
related to El Paso’s corporate headquarters building. Our legal obligations
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 and in El Paso’s corporate headquarters if these
facilities are ever demolished, replaced, or renovated. We continue to evaluate
our asset retirement obligations and future developments could impact the
amounts we record.
Where we can
reasonably estimate the asset retirement obligation, we accrue a liability based
on an estimate of the timing and amount of settlement. In estimating our asset
retirement obligations, we utilize several assumptions, including a projected
inflation rate of 2.5 percent, and credit-adjusted discount rates that currently
range from six to nine percent based on when the liabilities were recorded. We
record changes in estimates based on changes in the expected amount and timing
of payments to settle our obligations. We intend on operating and maintaining
our natural gas pipeline and storage system as long as supply and demand for
natural gas exists, which we expect for the foreseeable future. Therefore, we
believe that we cannot reasonably estimate the asset retirement obligation for
the substantial majority of our natural gas pipeline and storage system assets
because these assets have indeterminate lives.
The net asset
retirement obligation as of December 31 reported on our balance sheets in
current and other non-current liabilities, and the changes in the net
liability for the years ended December 31 were as follows:
|
|
2009
|
2008
|
||||||
|
(In
millions)
|
||||||||
|
Net asset
retirement obligation at January 1
|
$ | 42 | $ | 17 | ||||
|
Liabilities
settled
|
(6 | ) | (3 | ) | ||||
|
Accretion
expense
|
2 | 1 | ||||||
|
Changes in
estimate(1)
|
53 | 27 | ||||||
|
Net asset
retirement obligation at December 31(2)
|
$ | 91 | $ | 42 | ||||
____________
|
(1)
(2)
|
Increase
in estimate primarily due to updated information received on our hurricane
related asset retirement obligations.
For the
years ended December 31, 2009 and 2008, approximately $66 million and $5
million of this amount is reflected in current
liabilities.
|
7.
Debt and Credit Facilities
Debt. Our long-term debt
consisted of the following at December 31:
|
|
2009
|
2008
|
||||||
|
(In
millions)
|
||||||||
|
6.0%
Debentures due December 2011
|
$ | 86 | $ | 86 | ||||
|
8.0% Notes
due February 2016
|
250 | — | ||||||
|
7.5%
Debentures due April 2017
|
300 | 300 | ||||||
|
7.0%
Debentures due March 2027
|
300 | 300 | ||||||
|
7.0%
Debentures due October 2028
|
400 | 400 | ||||||
|
8.375% Notes
due June 2032
|
240 | 240 | ||||||
|
7.625%
Debentures due April 2037
|
300 | 300 | ||||||
| 1,876 | 1,626 | |||||||
|
Less:
Unamortized discount
|
30 | 21 | ||||||
|
Total long-term
debt
|
$ | 1,846 | $ | 1,605 | ||||
In January 2009, we
issued $250 million of 8.00% senior notes due in February 2016 and received
proceeds of $234 million, net of issuance costs.
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; and (v) potential limitations on our ability to declare and pay
dividends. For the year ended December 31, 2009, we were in compliance with our
debt-related covenants.
8.
Commitments and Contingencies
Legal
Proceedings
Gas Measurement Cases. We and
a number of our affiliates were named defendants in actions that generally
allege mismeasurement of natural gas volumes and/or heating content resulting in
the underpayment of royalties. The first set of cases was filed in 1997 by an
individual under the False Claims Act and have been consolidated for pretrial
purposes (In re: Natural
Gas Royalties Qui Tam
Litigation, U.S. District Court for the District of Wyoming). These
complaints allege an industry-wide conspiracy to underreport the heating value
as well as the volumes of the natural gas produced from federal and Native
American lands. In October 2006, the U.S. District Judge issued an order
dismissing all claims against all defendants. In March 2009, the Tenth Circuit
Court of Appeals affirmed the dismissals and in October 2009, the plaintiff’s
appeal to the United States Supreme Court was denied.
Similar allegations
were filed in a set of actions initiated in 1999 in Will Price, et al. v. Gas Pipelines
and Their Predecessors, et al., in the District Court of Stevens County,
Kansas. The plaintiffs seek certification of a class of royalty owners in wells
on non-federal and non-Native American lands in Kansas, Wyoming and Colorado.
The plaintiffs seek an unspecified amount of monetary damages in the form of
additional royalty payments (along with interest, expenses and punitive damages)
and injunctive relief with regard to future gas measurement practices. In
September 2009, the court denied the motions for class certification. The
plaintiffs have filed a motion for reconsideration. Our costs and legal exposure
related to this lawsuit and claim are not currently determinable.
In addition to the
above proceedings, we and our subsidiaries and affiliates are named defendants
in numerous lawsuits and governmental proceedings that arise in the ordinary
course of our business. For each of these matters, we evaluate the merits of the
case, our exposure to the matter, possible legal or settlement strategies and
the likelihood of an unfavorable outcome. If we determine that an unfavorable
outcome is probable and can be estimated, we establish the necessary accruals.
While the outcome of these matters, including those discussed above, cannot be
predicted with certainty, and there are still uncertainties related to the costs
we may incur, based upon our evaluation and experience to date, we 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 establish our
accruals accordingly, and these adjustments could be material. At December 31,
2009, we had accrued approximately $7 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 on the environment of the disposal or release of specified substances
at current and former operating sites. At December 31, 2009 and 2008, we had
accrued approximately $5 million and $6 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 $7 million at December 31, 2009.
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.
PCB Cost Recoveries. Since
1994, we have been conducting remediation activities at certain of our
compressor stations associated with PCBs and other hazardous
materials. We have collected amounts, substantially in excess of
remediation costs to date, through a surcharge to our customers under a
settlement approved by the FERC in November of 1995. In November
2009, the FERC approved an amendment to the 1995 settlement that provides for
interim refunds over a three year period of approximately $157 million of our
collected amounts plus interest of 8%. In December 2009, we refunded
approximately $30 million to our customers. Our refund obligations are recorded
as regulatory liabilities on our balance sheet and as of December 31, 2009, we
have classified approximately $28 million as current liabilities based on the
timing of when these amounts are expected to be refunded to our
customers.
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 four 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 $1
million and $2 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 $1
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.
Regulatory
Matter
Notice of Proposed
Rulemaking. In October 2007, the Minerals Management Service (MMS) issued
a notice of proposed rulemaking that is applicable to pipelines located in the
Outer Continental Shelf (OCS). If adopted, the proposed rules would
substantially revise MMS OCS pipeline and rights-of-way regulations. The
proposed rules would have the effect of (i) increasing the financial obligations
of entities, like us, which have pipelines and pipeline rights-of-way in the
OCS; (ii) increasing the regulatory requirements imposed on the operation and
maintenance of existing pipelines and rights of way in the OCS; and (iii)
increasing the requirements and preconditions for obtaining new rights-of-way in
the OCS.
Other
Commitments
Capital Commitments. At
December 31, 2009, we had capital commitments of approximately $268 million
primarily related to our 300 Line expansion project, of which $63 million will
be spent in 2010, $200 million will be spent in 2011 and $5 million will be
spent in 2012. We have other planned capital projects that are discretionary in
nature, with no substantial contractual capital commitments made in advance of
the actual expenditures.
Purchase Obligations. We have
entered into unconditional purchase obligations primarily for transportation,
storage and other services, totaling $127 million at December 31, 2009. Our
annual obligations under these purchase obligations are $42 million in 2010, $34
million in 2011, $19 million in 2012, $9 million in 2013, $6 million in
2014, and $17 million in total thereafter.
Operating Leases. We lease
property, facilities and equipment under various operating leases. Future
minimum annual rental commitments under our operating leases at December 31,
2009, were as follows:
|
Year
Ending
December 31,
|
(In
millions)
|
||||
|
2010
|
$ | 1 | |||
|
2011
|
1 | ||||
|
2012
|
1 | ||||
|
Thereafter
|
2 | ||||
|
Total
|
$ | 5 | |||
Rental expense on
our lease obligations for the years ended December 31, 2009, 2008 and 2007 was
$2 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 system. Our obligations under these easements are not material to our
results of operations.
9.
Retirement Benefits
Pension and Retirement Savings
Plans. El Paso maintains a pension plan and a retirement savings plan
covering substantially all of its U.S. employees, including our former
employees. The benefits under the pension plan are determined under a cash
balance formula. Under its retirement savings plan, El Paso matches 75 percent
of participant basic contributions up to six percent of eligible compensation
and can make additional discretionary matching contributions depending on its
performance relative to its peers. El Paso is responsible for benefits accrued
under its plans and allocates the related costs to its affiliates.
Postretirement Benefits Plan.
We provide postretirement medical and life insurance benefits for a
closed group of employees who were eligible to retire on December 31, 1996, and
did so before July 1, 1997. Medical benefits for this closed group
may be subject to deductibles, co-payment provisions, and other limitations and
dollar caps on the amount of employer costs and El Paso reserves the right to
change these benefits. Employees in this group who retire after July
1, 1997 continue to receive limited postretirement life insurance benefits. Our
postretirement benefit plan costs are prefunded to the extent these costs are
recoverable through our rates. To the extent actual costs differ from the
amounts recovered in rates, a regulatory asset or liability is recorded. We
expect to contribute $5 million 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 for our
postretirement benefit plan 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 $3 million from accumulated other comprehensive loss to a
regulatory liability.
The table below
provides information about our postretirement benefit plan. In 2008, we adopted
the FASB’s revised measurement date provisions for other postretirement benefit
plans and the information below for 2008 is presented and computed as of and for
the fifteen months ended December 31, 2008. For 2009, the information
is presented and computed as of and for the twelve months ended December 31,
2009.
|
|
December
31, 2009
|
December
31,
2008
|
||||||
|
(In
millions)
|
||||||||
|
Change in
accumulated postretirement benefit obligation:
|
||||||||
|
Accumulated
postretirement benefit obligation - beginning of period
|
$ | 21 | $ | 22 | ||||
|
Interest
cost
|
1 | 1 | ||||||
|
Participant
contributions
|
1 | 2 | ||||||
|
Actuarial
gain
|
(4 | ) | — | |||||
|
Benefits
paid(1)
|
(1 | ) | (4 | ) | ||||
|
Accumulated
postretirement benefit obligation - end of period
|
$ | 18 | $ | 21 | ||||
|
Change in
plan assets:
|
||||||||
|
Fair value of
plan assets - beginning period
|
$ | 23 | $ | 29 | ||||
|
Actual return
on plan assets
|
6 | (9 | ) | |||||
|
Employer
contributions
|
4 | 5 | ||||||
|
Participant
contributions
|
1 | 2 | ||||||
|
Benefits
paid
|
(1 | ) | (4 | ) | ||||
|
Fair value of
plan assets - end of period
|
$ | 33 | $ | 23 | ||||
|
Reconciliation
of funded status:
|
||||||||
|
Fair value of
plan assets
|
$ | 33 | $ | 23 | ||||
|
Less:
accumulated postretirement benefit obligation
|
18 | 21 | ||||||
|
Net asset at
December 31
|
$ | 15 | $ | 2 | ||||
____________
|
(1)
|
Amounts shown
net of a subsidy of less than $1 million for each of the years ended
December 31, 2009 and 2008 related to the Medicare Prescription Drug,
Improvement, and Modernization Act of
2003.
|
Plan Assets. The primary
investment objective of our plan is to ensure that, over the long-term life of
the plan an adequate pool of sufficiently liquid assets exists to meet the
benefit obligations to retirees and beneficiaries. Investment objectives are
long-term in nature covering typical market cycles. Any shortfall of investment
performance compared to investment objectives is generally the result of
economic and capital market conditions. Although actual allocations vary from
time to time from our targeted allocations, the target allocations of our
postretirement plan’s assets are 65 percent equity and 35 percent fixed income
securities. We may invest plan assets in a manner that replicates, to
the extent feasible, the Russell 3000 Index and the Barclays Capital Aggregate
Bond Index to achieve equity and fixed income diversification,
respectively.
We use various
methods to determine the fair values of the assets in our other postretirement
benefit 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 $31 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
|
$ | 2 | |||
|
2011
|
2 | ||||
|
2012
|
2 | ||||
|
2013
|
2 | ||||
|
2014
|
2 | ||||
|
2015 -
2019
|
7 | ||||
____________
|
(1)
|
Includes a
reduction of less than $1 million in each of the years 2010 – 2014 and
approximately $1 million in aggregate for 2015 – 2019 for an expected
subsidy related to the Medicare Prescription Drug, Improvement, and
Modernization Act of 2003.
|
Actuarial Assumptions and
Sensitivity Analysis. Accumulated postretirement benefit obligations and
net benefit costs are based on actuarial estimates and assumptions. The
following table details the weighted average actuarial assumptions used in
determining our postretirement plan obligations and net benefit costs for 2009,
2008 and 2007:
|
|
2009
|
2008
|
2007
|
|||||||||
|
(Percent)
|
||||||||||||
|
Assumptions
related to benefit obligations at December 31, 2009 and 2008
and
September 30,
2007 measurement dates:
|
||||||||||||
|
Discount
rate
|
5.37 | 5.95 | 6.05 | |||||||||
|
Assumptions
related to benefit costs at December 31:
|
||||||||||||
|
Discount
rate
|
5.95 | 6.05 | 5.50 | |||||||||
|
Expected
return on plan assets(1)
|
8.00 | 8.00 | 8.00 | |||||||||
____________
|
(1)
|
The expected
return on plan assets is a pre-tax rate of return based on our targeted
portfolio of investments. Our postretirement benefit plan’s investment
earnings are subject to unrelated business income taxes at a rate of 35%.
The expected return on plan assets for our postretirement benefit plan is
calculated using the after-tax rate of
return.
|
Actuarial estimates
for our postretirement benefits plan assumed a weighted average annual rate of
increase in the per capita costs of covered health care benefits of 8.0 percent,
gradually decreasing to 5.0 percent by the year 2015. Changes in the
assumed health care cost trend rates do not have a material impact on the
amounts reported for our interest costs or our accumulated postretirement
benefit obligations.
Components of Net Benefit Income.
For each of the years ended December 31, the components of net benefit
income are as follows:
|
|
2009
|
2008
|
2007
|
|||||||||
|
(In
millions)
|
||||||||||||
|
Interest
cost
|
$ | 1 | $ | 1 | $ | 1 | ||||||
|
Expected
return on plan assets
|
(1 | ) | (1 | ) | (1 | ) | ||||||
|
Net benefit
income
|
$ | — | $ | — | $ | — | ||||||
10.
Transactions with Major Customer
The following table
shows revenues from our major customer for each of the three years ended
December 31:
|
|
2009
|
2008
|
2007
|
|||||||||
|
(In
millions)
|
||||||||||||
|
National Grid
USA and Subsidiaries (1)
|
$ | 109 | $ | 109 | $ | 77 | ||||||
____________
(1) In 2007,
National Grid USA and Subsidiaries did not represent more than 10 percent of our
revenues.
11.
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
|
$ | 130 | $ | 120 | $ | 116 | ||||||
|
Income tax
payments
|
60 | 12 | 121 | |||||||||
12.
Investment in Unconsolidated Affiliate and Transactions with
Affiliates
Investment
in Unconsolidated Affiliate
Bear Creek Storage Company, LLC
(Bear Creek). We have a 50 percent ownership interest in Bear Creek, a
joint venture with Southern Natural Gas Company, our affiliate. We account for
our investment in Bear Creek using the equity method of
accounting. During 2009, 2008 and 2007, we received $13 million, $16
million and $27 million in dividends from Bear Creek.
Summarized
financial information for our proportionate share of Bear Creek as of and for
the years ended December 31 is presented as follows:
|
|
2009
|
2008
|
2007
|
|||||||||
|
(In
millions)
|
||||||||||||
|
Operating
results data:
|
||||||||||||