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 1-2745
Southern
Natural Gas Company
(Exact Name of
Registrant as Specified in Its Charter)
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Delaware
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63-0196650
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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 equity held by non-affiliates of the registrant:
None
Documents
Incorporated by Reference: None
SOUTHERN
NATURAL GAS COMPANY
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Caption
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Page
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Below is a list of
terms that are common to our industry and used throughout this
document:
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/d
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=
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per
day
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LNG
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=
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liquefied
natural gas
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BBtu
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=
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billion
British thermal units
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MMcf
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=
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million cubic
feet
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Bcf
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=
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billion cubic
feet
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Tonne
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=
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metric
ton
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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 “SNG”, we are describing Southern Natural Gas
Company and/or our subsidiaries.
Overview
and Strategy
We are a Delaware
general partnership, originally formed in 1935 as a corporation. We are owned 75
percent indirectly through a wholly owned subsidiary of El Paso Corporation (El
Paso) and 25 percent by EPPP SNG GP Holdings, L.L.C., a subsidiary of El Paso
Pipeline Partners, L.P. (EPB), a master limited partnership of El Paso. EPB was
formed in November 2007 at which time El Paso contributed 10 percent of its
interest in us to EPB. In September 2008, EPB acquired an additional 15 percent
ownership interest in us from El Paso.
In November 2007,
in conjunction with the formation of EPB, we distributed our 50 percent interest
in Citrus Corp. (Citrus) and our wholly owned subsidiaries, Southern LNG, Inc.
(SLNG) and Elba Express Company, LLC (Elba Express), to El Paso. Citrus owns the
Florida Gas Transmission Company, LLC pipeline system and SLNG owns the Elba
Island LNG facility. SLNG and Elba Express have been reflected as discontinued
operations in our financial statements for periods prior to their distribution.
For a further discussion of these discontinued operations, see Part II, Item 8,
Financial Statements and Supplementary Data, Note 2. In addition, effective
November 1, 2007, we converted our legal structure into a general partnership,
and are no longer subject to income taxes. Accordingly, we settled our then
existing current and deferred tax balances through El Paso’s cash management
program pursuant to our tax sharing agreement with El Paso.
Our pipeline system
and storage facilities operate under 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 tariff are a function of our costs of providing services
to our customers, including a reasonable return on our invested
capital.
Our strategy
is to enhance the value of our transportation and storage business
by:
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providing
outstanding customer service;
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executing
successfully on time and on budget for our 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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successfully
recontracting expiring contracts for transportation capacity or
contracting available capacity; and
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focusing on
efficiency and synergies across our system.
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Pipeline System. Our pipeline
system consists of approximately 7,600 miles of pipeline with a design capacity
of 3,700 MMcf/d. During 2009, 2008 and 2007, average throughput was 2,322
BBtu/d, 2,339 BBtu/d and 2,345 BBtu/d. This system extends from supply
basins in Texas, Louisiana, Mississippi, Alabama and the Gulf of Mexico to
market areas in Louisiana, Mississippi, Alabama, Florida, Georgia, South
Carolina and Tennessee, including the metropolitan areas of Atlanta and
Birmingham. We are the principal natural gas transporter to the southeastern
markets in Alabama, Georgia and South Carolina. Our system is also connected to
the Elba Island LNG terminal near Savannah, Georgia. This terminal has a peak
send-out capacity of approximately 1.2 Bcf/d.
FERC Approved Projects. As
of December 31, 2009, we had the following FERC-approved expansion projects on
our system. For a further discussion of our other expansion projects, see Item
7, Management’s Discussion and Analysis of Financial Conditions and Results of
Operations.
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Project
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Capacity
(MMcf/d)
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Description
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Anticipated
Completion
or
In-Service Date
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South System
III
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370 |
To add 81
miles of pipe and 17,310 of horsepower compression on our pipeline
facilities.
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2011-2012 | ||||||
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Southeast
Supply Header
Phase
II
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350 |
To add 26,000
of horsepower compression to the jointly owned pipeline
facilities.
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2011 | ||||||
Storage
Facilities. Along our pipeline system, we own and operate 100 percent of
the Muldon storage facility in Monroe County, Mississippi and own a 50 percent
interest in and operate the Bear Creek Storage Company, LLC (Bear Creek) in
Bienville Parish, Louisiana. Bear Creek provides storage services pursuant to
firm contracts to us and Tennessee Gas Pipeline Company, a subsidiary of El
Paso, which owns the remaining 50 percent interest. Our interest in Bear Creek
and the Muldon storage facilities have a combined working natural gas storage
capacity of 60 Bcf and peak withdrawal capacity of 1.2 Bcf/d. We provide storage
services to our customers utilizing the Bear Creek and the Muldon storage
facilities at our FERC tariff rate.
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 southeastern
market served by our pipeline is the fastest growing natural gas demand region
in the United States. Demand for deliveries from our pipeline is
characterized by two peak delivery periods, the winter heating season and the
summer cooling season.
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 directly connected to the Haynesville Shale formation in
northern Louisiana. Our pipeline is also indirectly connected, through new
interconnecting pipelines, to the Barnett Shale, Bossier Sands, Woodford Shale
and Fayetteville Shale. It is likely that natural gas from these sources
will increase over time. This will affect the flows on the system and the array
of shipper contracts.
Imported LNG has
been a growing supply sector of the natural gas market. LNG terminals and other
regasification facilities can serve as alternate sources of supply for
pipelines, enhancing their delivery capabilities and operational flexibility and
complementing traditional supply transported into market areas. However, these
LNG delivery systems may also compete with us for transportation of gas into
market areas we serve.
Electric power
generation has been a growing demand sector of the natural gas market. The
growth of natural gas-fired electric power benefits the natural gas industry by
creating more demand for natural gas. This potential benefit is offset, in
varying degrees, by increased generation efficiency, the more effective use of
surplus electric capacity, increased natural gas prices and the use and
availability of other fuel sources for power generation. In addition, in several
regions of the country, new additions in electric generating capacity have
exceeded load growth and electric transmission capabilities out of those
regions. These developments may inhibit owners of new power generation
facilities from signing firm transportation contracts with natural gas
pipelines.
Growth of the
natural gas market has been adversely affected by the current economic slowdown
in the U.S. and global economies. The decline in economic activity reduced
industrial demand for natural gas and electricity, which affected natural gas
demand both directly in end-use markets and indirectly through lower power
generation demand for natural gas. We expect the demand and growth for natural
gas to return as the economy recovers. Natural gas has a favorable competitive
position as an electric generation fuel because it is a clean and abundant fuel
with lower capital requirements compared with other alternatives. The lower
demand and the credit restrictions on investments in the recent past may slow
development of supply projects. While our pipeline could experience some level
of reduced throughput and revenues, or slower development of expansion projects
as a result of these factors, we generate a significant (greater than 80
percent) portion of our revenues through fixed monthly reservation or demand
charges on long-term contracts at rates stipulated under our tariff or in our
contracts.
Our existing
transportation and storage contracts mature at various times and in varying
amounts of throughput capacity. Our ability to extend our existing customer
contracts or remarket expiring contracted capacity is dependent on competitive
alternatives, the regulatory environment at the federal, state and local levels
and market supply and demand factors at the relevant dates these contracts are
extended or expire. The duration of new or renegotiated contracts will be
affected by current prices, competitive conditions and judgments concerning
future market trends and volatility. Subject to regulatory requirements, we
attempt to recontract or remarket our capacity at the maximum rates allowed
under our tariffs, although at times, we enter into firm transportation
contracts at amounts that are less than these maximum allowable rates to remain
competitive.
We face competition
in a number of our key markets 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. Our four largest customers are able to
obtain a significant portion of their natural gas requirements through
transportation from other pipelines. Also, we compete with several pipelines for
the transportation business of our other customers. In addition, we compete with
pipelines and gathering systems for connection to new supply
sources.
Our most direct
competitor is Transco, which owns an approximately 10,500-mile pipeline
extending from Texas to New York. It has firm transportation contracts with some
of our largest customers, including Atlanta Gas Light Company, Alabama Gas
Corporation, Southern Company Services, and SCANA Corporation.
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
270 firm and interruptible customers.
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Approximately
200 firm transportation contracts. Weighted average remaining contract
term of approximately six years.
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Major
Customers:
Atlanta Gas Light Company(1)
(1,063
BBtu/d)
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Expire in
2013-2024.
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Southern
Company Services
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(433
BBtu/d)
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Expire in
2011-2018.
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Alabama Gas
Corporation
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(372
BBtu/d)
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Expire in
2010-2013.
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SCANA
Corporation
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(315
BBtu/d)
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Expire in
2013-2019.
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(1)
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Atlanta Gas
Light Company is currently releasing a significant portion of its firm
capacity to a subsidiary of SCANA Corporation under terms allowed by our
tariff.
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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 7, and is incorporated herein by
reference.
Employees
We do not have
employees. Following our reorganization, our former employees continue to
provide services to us through an affiliated service company owned by our
general partner, El Paso. We are managed and operated by officers of El Paso,
our general partner. We have an omnibus agreement with El Paso and its
affiliates under which we reimburse El Paso for the provision of various general
and administrative services for our benefit and for direct expenses incurred by
El Paso on our behalf.
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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expiration or
turn back of significant contracts;
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changes in
regulation and actions of regulatory
bodies;
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weather
conditions that impact natural gas throughput and storage
levels;
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weather
fluctuations or warming or cooling trends that may impact demand in the
markets in which we do business, including trends potentially attributed
to climate change;
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drilling
activity and decreased availability of conventional gas supply sources and
the availability and timing of other gas supply sources, such as
LNG;
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continued
development of additional sources of gas supply that can be
accessed;
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decreased
natural gas demand due to various factors, including economic recession
(as further discussed below), availability of alternate energy sources and
increases in prices;
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legislative,
regulatory or judicial actions, such as mandatory renewable portfolio
standards and greenhouse gas (GHG) regulations and/or legislation that
could result in (i) changes in the demand for natural gas and oil, (ii)
changes in the availability of or demand for alternative energy sources
such as hydroelectric and nuclear power, wind and solar energy and/or
(iii) changes in the demand for less carbon intensive energy
sources;
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availability
and cost to fund ongoing maintenance and growth projects, especially in
periods of prolonged economic
decline;
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opposition to
energy infrastructure development, especially in environmentally sensitive
areas;
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adverse
general economic conditions including prolonged recessionary periods that
might negatively impact natural gas demand and the capital
markets;
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our ability
to achieve targeted annual operating and administrative expenses primarily
by reducing internal costs and improving efficiencies from leveraging a
consolidated supply chain organization;
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 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 firm
transportation contacts are subscribed through 2013. 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.
In 2009, our
contracts with Atlanta Gas Light Company, Southern Company Services, Alabama Gas
Corporation and SCANA Corporation represented approximately 28 percent, 11
percent, 10 percent and 8 percent of our firm transportation capacity. For
additional information regarding our major customers, see Item 1, Business —
Markets and Competition. The loss of one of these customers or a decline in
their creditworthiness could adversely affect our results of operations,
financial position and cash flows.
We
are exposed to the credit risk of our customers and our credit risk management
may not be adequate to protect against such risk.
We are subject to
the risk of delays in payment as well as losses resulting from nonpayment and/or
nonperformance by our customers, including default risk associated with adverse
economic conditions. Our credit procedures and policies may not be adequate to
fully eliminate customer credit risk. In addition, in certain situations, we may
assume certain additional credit risks for competitive reasons or
otherwise. If our existing or future customers fail to pay and/or
perform and we are unable to remarket the capacity, our business, the results of
our operations and our financial condition could be adversely affected. We may
not be able to effectively remarket capacity during and after insolvency
proceedings involving a shipper.
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. 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 transporation
and storage through our system.
We retain a fixed
percentage of natural gas received for transportation and storage as provided in
our tariff. This retained natural gas is used as fuel and to replace lost
and unaccounted for natural gas. As calculated in a manner set forth in
our tariff, volumes from any excess natural gas retained and not used in
operations are to be given back to our customers through lower retention
percentages determined on an annual basis. Any under-recoveries will be returned
to us through higher percentages determined on an annual basis. If natural gas
prices in the supply basins connected to our pipeline system are higher than
prices in other natural gas producing regions, our ability to compete with other
transporters may be negatively impacted on a short-term basis, as well as with
respect to our long-term recontracting activities. Furthermore, fluctuations in
pricing between supply sources and market areas could negatively impact our
transportation revenues. Consequently, a significant prolonged downturn in
natural gas prices could have a material adverse effect on our financial
condition, results of operations and liquidity. Fluctuations in energy prices
are caused by a number of factors, including:
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regional,
domestic and international supply and demand, including changes in
supply and demand due to general economic conditions and
weather;
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availability
and adequacy of gathering, processing and transportation
facilities;
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energy
legislation and regulation, including potential changes associated with
GHG emissions and renewable portfolio
standards;
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federal and
state taxes, if any, on the sale or transportation and storage of natural
gas;
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the price and
availability of supplies of alternative energy sources;
and
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the level of
imports, including the potential impact of political unrest among
countries producing oil and LNG, as well as the ability of certain foreign
countries to maintain natural gas and oil prices, production and export
controls.
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The agencies that
regulate us and our customers could affect our
profitability.
Our business is
regulated by the FERC, the U.S. Department of Transportation, the U.S.
Department of the Interior and various state and local regulatory agencies whose
actions have the potential to adversely affect our profitability. In particular,
the FERC regulates the rates we are permitted to charge our customers for our
services and sets authorized rates of return. In January 2010, the FERC approved
our settlement in which we (i) increased our base tariff rates effective
September 1, 2009, (ii) implemented a volume tracker for gas used in operations,
(iii) agreed to file our next general rate case to be effective after August 31,
2012 but no later than September 1, 2013, and (iv) extended the vast majority of
our firm transportation contracts until August 31, 2013.
We periodically
file with the FERC to adjust the rates charged to our customers. In
establishing those rates, the FERC uses a discounted
cash flow model that incorporates the use of proxy groups to develop a range of
reasonable returns earned on equity interests in companies with corresponding
risks. The FERC then assigns a rate of return on equity within that range to
reflect specific risks of that pipeline when compared to the proxy group
companies. Depending on the specific risks faced by us and the companies
included in the proxy group, the FERC may establish rates that are not
acceptable to us and have a negative impact on our cash flows, profitability and
results of operations. In addition, pursuant to
laws and regulations, our existing rates may be challenged by complaint. The
FERC commenced several complaint proceedings in 2009 against unaffiliated
pipeline systems to reduce the rates they were charging their
customers. There is a risk that the FERC or our customers could file
similar complaints on our pipeline system and that a successful complaint
against our rates could have an adverse impact on our cash flows and
results of operations.
In addition, the
FERC currently allows partnerships and other pass through entities to include in
their cost-of-service an income tax allowance. Any changes to the FERC’s
treatment of income tax allowances in cost-of-service and to potential
adjustment in a future rate case of our equity rate of return may cause our
rates to be set at a level that is different from those currently in place and
in some instances lower than the level otherwise in effect.
Increased
regulatory requirements relating to the integrity of our pipeline requires
additional spending in order to maintain compliance with the FERC’s
requirements. Any additional requirements that are enacted could significantly
increase the amount of these expenditures. Further, state agencies that regulate
our local distribution company customers could impose requirements that could
impact demand for our services.
Environmental
compliance and remediation costs and the costs of environmental liabilities could
exceed our estimates.
Our operations are
subject to various environmental laws and regulations regarding compliance and
remediation obligations. Compliance obligations can result in significant costs
to install and maintain pollution controls, fines and penalties resulting from
any failure to comply and potential limitations on our operations. Remediation
obligations can result in significant costs associated with the investigation or
clean-up of contaminated properties (some of which have been designated as
Superfund sites by the U.S. Environmental Protection Agency (EPA) under the
Comprehensive Environmental Response, Compensation and Liability Act), as well
as damage claims arising out of the contamination of properties or impact on
natural resources. Although we believe we have established appropriate reserves
for our environmental liabilities, it is not possible for us to estimate the
exact amount and timing of all future expenditures related to environmental
matters and we could be required to set aside additional amounts which could
significantly impact our future consolidated results of operations, financial
position or cash flows. See Part II, Item 8, Financial Statements and
Supplementary Data, Note 7.
In estimating our
environmental liabilities, we face uncertainties that include:
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•
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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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•
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discovering
new sites or additional information at existing
sites;
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•
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forecasting
cash flow timing to implement proposed pollution control and cleanup
costs;
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•
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receiving
regulatory approval for remediation
programs;
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•
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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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•
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evaluating
and understanding environmental laws and regulations, including their
interpretation and enforcement;
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•
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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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•
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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 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 and storage facilities by constructing
additional facilities. Construction of these facilities is subject to various
regulatory, development and operational risks, including:
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our ability
to obtain necessary approvals and permits by the FERC and other regulatory
agencies on a timely basis and on terms that are acceptable to us,
including the potential impact of delays and increased costs caused by
certain environmental and landowner groups with interests along the route
of our pipeline;
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•
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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.
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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.
Adverse
general domestic economic conditions could negatively affect our
operating results, financial condition, or liquidity.
We, El Paso, and
its subsidiaries are subject to the risks arising from adverse changes in
general domestic economic conditions including recession or economic slowdown.
The global economy is experiencing a recession and the financial markets have
experienced extreme volatility and instability. In response, over the last year,
El Paso announced certain actions designed to reduce its need to access such
financial markets, including reductions in the capital programs of certain of
its operating subsidiaries and the sale of several non-core assets.
If we or El Paso
experience prolonged periods of recession or slowed economic growth in the U.S.,
demand growth from consumers for natural gas transported by us may continue to
decrease, which could impact the development of our future expansion projects.
Additionally, our or El Paso’s access to capital could be impeded and the cost
of capital we obtain could be higher. Finally, we are subject to the risks
arising from changes in legislation and regulation associated with any such
recession or prolonged economic slowdown, including creating preference for
renewables, as part of a legislative package to stimulate the economy. Any of
these events, which are beyond our control, could negatively impact our
business, results of operations, financial condition, and
liquidity.
We
are subject to financing and interest rate risks.
Our future success,
financial condition and liquidity could be adversely affected based on our
ability to access capital markets and obtain financing at cost effective rates.
This is dependent on a number of factors in addition to general economic
conditions discussed above, many of which we cannot control, including changes
in:
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our credit
ratings;
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•
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the
structured and commercial financial
markets;
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•
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market
perceptions of us or the natural gas and energy industry;
and
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•
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market prices
for hydrocarbon products.
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Risks
Related to Our Affiliation with El Paso and EPB
El Paso and EPB
file reports, proxy statements and other information with the SEC under the
Securities Exchange Act of 1934, as amended. Each prospective investor should
consider this information and the matters disclosed therein in addition to the
matters described in this report. Such information is not included herein or
incorporated by reference into this report.
We are a majority
owned subsidiary of El Paso.
As a majority owned
subsidiary of El Paso, subject to limitations in our indentures, El Paso has
substantial control over:
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decisions on
our financing and capital raising
activities;
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•
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mergers or
other business combinations;
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•
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our
acquisitions or dispositions of assets;
and
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our
participation in 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 business
requires the retention and recruitment of a skilled workforce and the loss of
employees could result in the failure to implement our business plan.
Our business
requires the retention and recruitment of a skilled workforce. If El Paso is
unable to retain and recruit employees such as engineers and other technical
personnel, our business could be negatively impacted.
Our relationship
with El Paso and its financial condition subjects us to potential risks
that are beyond our control.
Due to our
relationship with El Paso, adverse developments or announcements concerning El
Paso or its other subsidiaries could adversely affect our financial condition,
even if we have not suffered any similar development. The ratings assigned to El
Paso’s senior unsecured indebtedness are below investment grade, currently rated
Ba3 by Moody’s Investor Service, BB- by Standard & Poor’s and BB+ by Fitch
Ratings. The ratings assigned to our senior unsecured indebtedness are currently
investment grade, with a Baa3 rating by Moody’s Investor Service and a BBB-
rating by Fitch Ratings. Standard & Poor’s has assigned a below investment
grade rating of BB to our senior unsecured indebtedness. El Paso and its
subsidiaries, including us, are (i) on a stable outlook with Moody’s Investor
Service and Fitch Ratings and (ii) on a negative outlook with Standard &
Poor’s. There is a risk that these credit ratings may be adversely affected in
the future as the credit rating agencies continue to review our and El Paso’s
leverage, liquidity, and credit profile. Any reduction in our or El Paso’s
credit ratings could impact our ability to access the capital markets, as well
as our cost of capital.
El Paso provides
cash management and other corporate services for us. We are currently required
to make distributions of available cash as defined in our partnership agreement
on a quarterly basis to our partners. In addition, we conduct commercial
transactions with some of our affiliates. If El Paso or such affiliates are
unable to meet their respective liquidity needs, we may not be able to access
cash under the cash management program, or our affiliates may not be able to pay
their obligations to us. However, we might still be required to satisfy any
affiliated payables we have established. Our inability to recover any affiliated
receivables owed to us could adversely affect our financial position and cash
flows. For a further discussion of these matters, see Part II, Item 8, Financial
Statements and Supplementary Data, Note 11.
Our
relationship with El Paso and EPB subjects us to potential conflicts of
interest and
they may favor their interests to the detriment of
us.
Although El Paso
has majority control of most decisions affecting our business, there are certain
decisions that require the approval of both El Paso and EPB, including material
regulatory filings, any significant sale of our assets, mergers and certain
changes in affiliated service agreements. Conflicts of interest or disagreements
could arise between El Paso and EPB with regard to such matters requiring
unanimous approval, which could negatively impact our future
operations.
We have not
included a response to this item since no response is required under Item 1B of
Form 10K.
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 interest in
these properties or the use of these properties in our business. We believe that
our properties are adequate and suitable for the conduct of our business in the
future.
A description of
our legal proceedings is included in Part II, Item 8, Financial Statements and
Supplementary Data, Note 7, and is incorporated herein by
reference.
None.
All of our
partnership interests are held by El Paso and EPB and, accordingly, are not
publicly traded. Prior to converting into a general partnership effective
November 1, 2007, all of our common stock was held by El Paso.
We are required to
make distributions to our partners of available cash as defined in our
partnership agreement on a quarterly basis from legally available funds that
have been approved for payment by our Management Committee. We made cash
distributions to our partners of approximately $171 million in 2009 and
approximately $200 million in 2008. No dividends or cash distributions were
declared or paid in 2007. Additionally, in January 2010, we made a cash
distribution of approximately $83 million to our partners.
The following
selected historical financial data is derived from our audited consolidated
financial statements and is not necessarily indicative of results to be expected
in the future. The selected financial data should be read together with Item 7,
Management’s Discussion and Analysis and Financial Condition and Results of
Operations and Item 8, Financial Statements and Supplementary Data included in
this Report on Form 10-K.
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As of or for the Year Ended December
31,
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|||||||||||||||||||
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2009
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2008
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2007
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2006
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2005
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(In
millions)
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||||||||||||||||||||
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Operating
Results Data:
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||||||||||||||||||||
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Operating
revenues
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$ | 510 | $ | 540 | $ | 482 | $ | 462 | $ | 437 | ||||||||||
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Operating
income
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255 | 271 | 242 | 218 | 215 | |||||||||||||||
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Income from
continuing operations
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208 | 235 | 202 | 162 | 155 | |||||||||||||||
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Financial
Position Data:
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Total
assets
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$ | 2,659 | $ | 2,629 | $ | 2,803 | $ | 3,395 | $ | 3,199 | ||||||||||
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Long-term
debt, less current maturities
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910 | 910 | 1,098 | 1,096 | 1,195 | |||||||||||||||
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Partners’
capital/stockholder’s equity
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1,614 | 1,577 | 1,542 | 1,644 | 1,455 | |||||||||||||||
Our Management’s
Discussion and Analysis (MD&A) should be read in conjunction with our
consolidated financial statements and the accompanying footnotes. MD&A
includes forward-looking statements that are subject to risks and uncertainties
that may result in actual results differing from the statements we make. These
risks and uncertainties are discussed further in Part I, Item 1A, Risk Factors.
We have included a discussion in this MD&A of our business, growth projects,
results of operations, liquidity, contractual obligations and critical
accounting policies and estimates that may affect us as we operate in the
future.
In November 2007,
in conjunction with the formation of El Paso Pipeline Partners, L.P. (EPB), we
distributed our 50 percent interest in Citrus Corp. (Citrus) and our wholly
owned subsidiaries Southern LNG, Inc. (SLNG) and Elba Express Company, LLC (Elba
Express), to El Paso Corporation (El Paso). Citrus owns the Florida Gas
Transmission Company, LLC pipeline system and SLNG owns the Elba Island LNG
facility. SLNG and Elba Express have been reflected as discontinued operations
in our financial statements for periods prior to their distribution. Our
continuing operating results include earnings from Citrus, but only through the
date of its distribution to El Paso. For a further discussion of these
discontinued operations, see Item 8, Financial Statements and Supplementary
Data, Note 2. In addition, effective November 1, 2007, we converted our legal
structure into a general partnership, and are no longer subject to income taxes.
Accordingly, we settled our then existing current and deferred tax balances
through El Paso’s cash management program pursuant to our tax sharing agreement
with El Paso.
Overview
Business. Our primary
business consists of the interstate transportation 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.
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Type
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Description
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Percent
of Total
Revenues in 2009
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Reservation
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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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88
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Usage and
Other
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Usage
revenues are from both firm customers and interruptible customers (those
without reserved capacity) that pay usage charges based on the volume of
gas actually transported, stored, injected or withdrawn. We also earn
revenue from other miscellaneous sources.
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12
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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. In January
2010, the FERC approved our settlement in which we (i) increased our base tariff
rates effective September 1, 2009, (ii) implemented a volume tracker for gas
used in operations, (iii) agreed to file our next general rate case to be
effective after August 31, 2012 but no later than September 1, 2013, and
(iv) extended the vast majority of our firm transportation contracts until
August 31, 2013. Because of our regulated nature and the high percentage of our
revenues attributable to reservation charges, our revenues have historically
been relatively stable. However, our financial results can be subject to
volatility due to factors such as changes in natural gas prices, changes in
supply and demand, regulatory actions, competition, declines in the
creditworthiness of our customers and weather.
We continue to
manage the process of renewing expiring contracts to limit the risk of
significant impacts on our revenues. Our ability to extend our existing customer
contracts or remarket expiring contracted capacity is dependent on competitive
alternatives, the regulatory environment at the federal, state and local levels
and the market supply and demand factors at the relevant dates these contracts
are extended or expire. The duration of new or renegotiated contracts will be
affected by current prices, competitive conditions and judgments concerning
future market trends and volatility. Subject to regulatory requirements, we
attempt to recontract or remarket our capacity at the maximum rates allowed
under our tariffs, although at times, we enter into firm transportation
contracts at amounts that are less than these maximum allowable rates to remain
competitive. We refer to the difference between the maximum rates allowed under
our tariff and the contractual rate we charge as discounts.
Our existing
contracts mature at various times and in varying amounts of throughput capacity.
The weighted average remaining contract term for our active contracts is
approximately six 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.
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Contracted
Capacity
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Percent
of Total
Contracted Capacity
|
Reservation
Revenue
|
Percent
of Total
Reservation Revenue
|
||||||||||||
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(BBtu/d)
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(In
millions)
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|||||||||||||||
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2010
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118 | 3 | $ | 16 | 4 | |||||||||||
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2011
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124 | 3 | 6 | 1 | ||||||||||||
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2012
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— | — | — | — | ||||||||||||
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2013
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2,127 | 56 | 255 | 58 | ||||||||||||
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2014 and beyond
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1,473 | 38 | 161 | 37 | ||||||||||||
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Total
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3,842 | 100 | $ | 438 | 100 | |||||||||||
Growth Projects. We
expect to spend approximately $403 million on contracted organic growth projects
from 2010 through 2014. Of this amount, we expect to spend $249 million in 2010
primarily on our South System III and the Southeast Supply Header projects
described below:
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South System III. The
South System III expansion project will expand our pipeline system
in Mississippi, Alabama and Georgia by adding approximately 81 miles
of pipeline looping and replacement on our south system and 17,310
horsepower of compression to serve an existing power generation facility
owned by the Southern Company in the Atlanta, Georgia area that is being
converted from coal-fired to cleaner burning natural gas. This expansion
project will be completed in three phases, at an estimated total cost of
$352 million, with each phase expected to add an additional 122 MMcf/d of
capacity. In August 2009, we received a certificate of authorization from
the FERC on this project. The project has estimated in-service dates of
January 2011 for Phase I, June 2011 for Phase II and June 2012 for Phase
III. We have entered into a precedent agreement with Southern Company
Services as agent for its affiliated operating companies, Georgia Power
Company, Alabama Power Company, Mississippi Power Company, Southern Power
Company and Gulf Power Company to provide an incremental firm
transportation service to such operating companies, commencing in phases
beginning January 1, 2011, and ending May 31, 2032, which is 20 years
after the estimated in-service date for Phase
III.
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•
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Southeast Supply
Header. We own an undivided interest in the northern
portion of the Southeast Supply Header project jointly owned by Spectra
Energy Corp (Spectra) and CenterPoint Energy, which added 115-mile
supply line to the western portion of our system. This project is expected
to provide access through pipeline interconnects to several supply basins,
including the Barnett Shale, Bossier Sands, Arkoma and Fayetteville Shale
basins. The estimated cost to us for Phase II is $69 million and is
expected to provide us with an additional 350 MMcf/d of supply capacity.
In August 2009, we received a certificate of authorization from the FERC
to construct Phase II, which is anticipated to be placed in service in
June 2011.
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We believe that
cash flows from operating activities, combined with amounts available to us
under El Paso’s cash management program and capital contributions from our
partners, will be adequate to meet our capital requirements and our existing
operating needs.
Results
of Operations
Our management uses
earnings before interest expense and income taxes (EBIT) as a measure to assess
the operating results and effectiveness of our business, which consists of both
consolidated operations and an investment in an unconsolidated affiliate. We
believe EBIT is useful to investors to provide them with the same measure used
by El Paso to evaluate our performance. We define EBIT as net income adjusted
for items such as (i) interest and debt expense, (ii) affiliated interest
income, and (iii) income taxes. We exclude interest and debt expense from this
measure so that investors may evaluate our operating results without regard to
our financing methods. EBIT may not be comparable to measures used by other
companies. Additionally, EBIT should be considered in conjunction with net
income, income before income taxes and other performance measures such as
operating income or operating cash flows. Below is a reconciliation of our EBIT
to our net income, our throughput volumes and an analysis and discussion of our
results in 2009 compared with 2008 and 2008 compared with 2007.
Operating
Results:
|
|
2009
|
2008
|
2007
|
|||||||||
|
(In
millions, except for volumes)
|
||||||||||||
|
Operating
revenues
|
$ | 510 | $ | 540 | $ | 482 | ||||||
|
Operating
expenses
|
(255 | ) | (269 | ) | (240 | ) | ||||||
|
Operating
income
|
255 | 271 | 242 | |||||||||
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Earnings from
unconsolidated affiliates
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11 | 13 | 88 | |||||||||
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Other income,
net
|
2 | 10 | 13 | |||||||||
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EBIT(1)
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268 | 294 | 343 | |||||||||
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Interest and
debt expense
|
(62 | ) | (72 | ) | (91 | ) | ||||||
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Affiliated
interest income
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2 | 13 | 19 | |||||||||
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Income tax
expense
|
— | — | (69 | ) | ||||||||
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Income from
continuing operations
|
208 | 235 | 202 | |||||||||
|
Discontinued
operations, net of income taxes
|
— | — | 19 | |||||||||
|
Net
income
|
$ | 208 | $ | 235 | $ | 221 | ||||||
|
Throughput
volumes (BBtu/d)(2)
|
2,322 | 2,339 | 2,345 | |||||||||
____________
|
(1)
|
2007
EBIT represents EBIT from continuing
operations.
|
|
(2)
|
Throughput
volumes include billable transportation throughput volumes for storage
injection.
|
EBIT Analysis:
|
|
2009 to 2008
|
2008 to 2007
|
||||||||||||||||||||||||||||||
|
Revenue
|
Expense
|
Other
|
Total
|
Revenue
|
Expense
|
Other
|
Total
|
|||||||||||||||||||||||||
|
Favorable/(Unfavorable)
|
||||||||||||||||||||||||||||||||
|
(In
millions)
|
||||||||||||||||||||||||||||||||
|
Expansions
|
$ | 2 | $ | (3 | ) | $ | (12 | ) | $ | (13 | ) | $ | 14 | $ | (2 | ) | $ | (2 | ) | $ | 10 | |||||||||||
|
Service
revenues
|
22 | — | — | 22 | 2 | — | — | 2 | ||||||||||||||||||||||||
|
Gas not used
in operations and other natural gas sales
|
(15 | ) | 22 | — | 7 | 9 | (12 | ) | — | (3 | ) | |||||||||||||||||||||
|
Calpine
bankruptcy
|
(35 | ) | — | — | (35 | ) | 33 | — | — | 33 | ||||||||||||||||||||||
|
Operating and
general and administrative expenses
|
— | — | — | — | — | (10 | ) | — | (10 | ) | ||||||||||||||||||||||
|
Earnings from
Citrus
|
— | — | — | — | — | — | (75 | ) | (75 | ) | ||||||||||||||||||||||
|
Other(1)
|
(4 | ) | (5 | ) | 2 | (7 | ) | — | (5 | ) | (1 | ) | (6 | ) | ||||||||||||||||||
|
Total impact
on EBIT
|
$ | (30 | ) | $ | 14 | $ | (10 | ) | $ | (26 | ) | $ | 58 | $ | (29 | ) | $ | (78 | ) | $ | (49 | ) | ||||||||||
____________
|
(1)
|
Consists
of individually insignificant
items.
|
Expansions. During 2009, the allowance for funds
used during construction (AFUDC) has been reduced by approximately $12 million
due to lower capital expenditures as compared to 2008. This decrease is
primarily attributable to the completion of the Cypress Phase II and Southeast
Supply Header Phase I projects placed into service in May 2008 and September
2008. Since we placed Phase I of the Cypress project in service in May 2007 and
Phase II of the project in May 2008, we experienced an increased level of
revenue throughout 2008 and a decrease in AFUDC on this project in 2008 as
compared to 2007. The reduction in AFUDC on the Cypress project during 2008 was
partially offset by higher AFUDC related to the construction of Phase I of the
Southeast Supply Header, which was placed into service in September
2008.
During 2009, BG LNG
Services (BG) informed us of their intent not to exercise their option to have
us construct the Cypress Phase III expansion. However, BG has made alternative
commitments to subscribe to certain other firm capacity on another of El Paso’s
pipeline systems and to provide certain rate considerations on its existing
transportation contract for Cypress Phases I and II. In August 2009, we received
certificates of authorization from the FERC on the South System III and
Southeast Supply Header Phase II projects.
In addition to our
backlog of contracted organic growth projects, we have other projects that are
in various phases of commercial development. Many of the potential projects
involve expansion capacity to serve increased natural gas-fired generation
loads. Although we pursue the development of these potential projects from time
to time, there can be no assurance that we will be successful in negotiating the
definitive binding contracts necessary for such projects to be included in our
backlog of contracted organic growth projects.
Service
Revenues. During 2009, our service revenue increased primarily due to
higher tariff rates placed into service on September 1, 2009 pursuant to our
rate case settlement which is further discussed above. During 2008, our service
revenues increased primarily due to an increase in our firm transportation
revenue offset by lower interruptible services and usage revenue as compared to
2007.
Gas
Not Used in Operations and Other Natural Gas Sales and Purchases. Prior
to September 1, 2009, the financial impacts of our operational gas, net of gas
used in operations, was based on the price of natural gas and the amount of
natural gas we were allowed to retain and dispose of according to our tariff,
relative to the amounts of natural gas we used for operating purposes and the
cost of operating our electric compression facilities. Effective September 1,
2009, a volume tracker was implemented as part of our rate case settlement as
further discussed below, therefore we no longer share retained gas not used in
operations. However, through August 31, 2009, our share of retained gas not used
in operations resulted in revenues to us, which were impacted by volumes and
prices during a given period. For the year ended December 31, 2009, our
operating expense was $22 million lower than in 2008 primarily due to favorable
revaluation of retained volumes on our system. Offsetting this favorable impact
during the year ended December 31, 2009 was a $15 million reduction in revenue
primarily related to favorable sales in 2008. During the year ended December 31,
2008, our EBIT was lower primarily due to higher cost of electric compression on
our system and lower gas prices at year end.
Calpine
Bankruptcy. During 2008, we recognized revenue related to distributions
received under Calpine’s approved plan of reorganization.
Operating
and General and Administrative Expenses. Our operating and general and
administrative costs were higher in 2008 than 2007, primarily due to higher
repair and maintenance costs and higher allocated costs from El Paso based
on the estimated level of resources devoted to us and the relative size of our
EBIT, gross property and payroll when compared to El Paso’s other
affiliates.
Earnings
from Citrus. Our operating results for 2007 reflect earnings from Citrus
prior to its distribution to El Paso in November 2007 in conjunction with
the formation of EPB.
Interest
and Debt Expense
Interest and debt
expense for the year ended December 31, 2009, was $10 million lower than in 2008
primarily due to lower average outstanding debt balances resulting from the
retirement and repurchases of debt in June and September 2008. Interest and debt
expense for the year ended December 31, 2008, was $19 million lower than in 2007
primarily due to lower average outstanding debt balances. For further
information on our outstanding debt balances, see Item 8, Financial Statements
and Supplementary Data, Note 6.
Affiliated
Interest Income
Affiliated interest income for the
year ended December 31, 2009 was $11 million lower than in 2008 and $6
million lower for the year ended December 31, 2008 as compared to 2007 due to
lower average advances due from El Paso under its cash management program and
lower short-term interest rates. During 2009, the average advances due from El
Paso decreased primarily due to debt retirement and repurchases in June and
September 2008 with recoveries of our note receivable. 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
|
2007
|
||||||||||
|
(In
millions, except for rates)
|
||||||||||||
|
Average
advance due from El Paso
|
$ | 85 | $ | 300 | $ | 315 | ||||||
|
Average
short-term interest rate
|
1.7 | % | 4.4 | % | 6.2 | % | ||||||
Income
Taxes
Effective November
1, 2007, we no longer pay income taxes as a result of our conversion into a
partnership, which impacted our 2007 effective tax rate. Our effective tax rate
of 25 percent for the year ended December 31, 2007, was lower than the
statutory rate of 35 percent primarily due to the tax effect of earnings from
unconsolidated affiliates that qualify for the dividends received deduction,
partially offset by 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
Liquidity Overview. Our
primary sources of liquidity are cash flows from operating activities, amounts
available under El Paso’s cash management program and capital contributions from
our partners. At December 31, 2009, we had a note receivable from El Paso of
approximately $154 million of which approximately $42 million was classified as
current based on the net amount we anticipate using in the next twelve months
considering available cash sources and needs. See Item 8, Financial Statements
and Supplementary Data, Note 11, for a further discussion of El Paso’s cash
management program. Our primary uses of cash are for working capital, capital
expenditures and for required distributions to our partners.
Although recent
financial conditions have shown signs of improvement, continued volatility in
2010 and beyond in the financial markets could impact our longer-term access to
capital for future growth projects as well as the cost of such capital. Additionally, although the
impacts are difficult to quantify at this point, a prolonged recovery of the
global economy could have adverse impacts on natural gas consumption and demand.
However, we believe our exposure to changes in natural gas consumption and
demand is largely mitigated by a revenue base that is significantly comprised of
long-term contracts that are based on firm demand charges and are less affected
by a potential reduction in the actual usage or consumption of natural
gas.
We believe we have
adequate liquidity available to us to meet our capital requirements and our
existing operating needs through cash flow from operating activities, amounts
available to us under El Paso’s cash management program and capital
contributions from our partners. As of December 31, 2009, El Paso had
approximately $1.8 billion of available liquidity, including approximately $1.3
billion of capacity available to it under various committed credit facilities.
While we do not anticipate a need to directly access the financial markets in
2010 for any of our operating activities or expansion capital needs based on
liquidity available to us, market conditions may impact our ability to act
opportunistically.
For further detail
on our risk factors including potential adverse general economic conditions
including our ability to access financial markets which could impact our
operations and liquidity, see Part I, Item 1A, Risk Factors.
2009
Cash Flow Activities. Our cash flows for the year ended December 31, 2009
are summarized as follows (In millions):
|
Cash
Flow from Operations
|
||||
|
Net income
|
$ | 208 | ||
|
Non-cash income
adjustments
|
56 | |||
|
Change in other assets and
liabilities
|
22 | |||
|
Total cash flow from
operations
|
286 | |||
|
Cash
Inflows
|
||||
|
Investing
activities
|
||||
|
Proceeds from sale of
assets
|
41 | |||
|
Cash
Outflows
|
||||
|
Investing
activities
|
||||
|
Additions to property, plant
and equipment
|
138 | |||
|
Net change in notes receivable
from affiliate
|
18 | |||
| 156 | ||||
|
Financing
activities
|
||||
|
Distributions to partners
|
171 | |||
|
Total cash outflows
|
327 | |||
|
Net change in cash
|
$ | — | ||
During 2009, we generated $286
million of operating cash flow. We utilized these amounts to fund maintenance of
our system as well as pay distributions to our partners. During the year ended
December 31, 2009, we paid cash distributions of approximately $171 million to
our partners. In addition, in January 2010 we paid a cash distribution to our
partners of approximately $83 million. 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
|
$ | 60 | $ | 95 | ||||
|
Expansion/Other
|
84 | 249 | ||||||
|
Hurricanes(1)
|
(6 | ) | — | |||||
|
Total
|
$ | 138 | $ | 344 | ||||
____________
(1) Amounts
shown are net of insurance proceeds of $9 million in 2009.
Our expected 2010
expansion capital expenditures primarily relate to our South System III and
Southeast Supply Header expansion projects. Our maintenance capital expenditures
primarily relate to maintaining and improving the integrity of our pipeline,
complying with regulations and ensuring the safe and reliable delivery of
natural gas to our customers. While we expect to fund maintenance
capital expenditures through internally generated funds, we intend to fund our
expansion capital expenditures through amounts available under El Paso’s cash
management program and capital contributions from our partners. We anticipate to
receive approximately $150 million of capital contributions from our partners
during 2010.
Contractual
Obligations
We are party to
various contractual obligations. A portion of these obligations are reflected in
our financial statements, such as long-term debt and other accrued liabilities,
while other obligations, such as operating leases, demand charges under
transportation and storage commitments and capital commitments, are not
reflected on our balance sheet. We have excluded from these amounts expected
contributions to our other postretirement benefit plans, because these expected
contributions are not contractually required. For further information on our
expected contributions to our post retirement benefit plans, see Item 8,
Financial Statements and Supplementary Data, Note 8. The following table and
discussion summarizes our contractual cash obligations as of December 31, 2009,
for each of the periods presented (all amounts are undiscounted):
|
|
Due
in
less than 1 Year
|
Due
in
1 to 3 Years
|
Due
in
3 to 5 Years
|
Thereafter
|
Total
|
|||||||||||||||
|
(In
millions)
|
||||||||||||||||||||
|
Long-term
debt:
|
||||||||||||||||||||
|
Principal
|
$ | — | $ | — | $ | — | $ | 911 | $ | 911 | ||||||||||
|
Interest
|
61 | 123 | 123 | 620 | 927 | |||||||||||||||
|
Operating
leases
|
3 | 6 | 6 | 8 | 23 | |||||||||||||||
|
Other
contractual commitments and purchase obligations:
|
||||||||||||||||||||
|
Transportation
and storage commitments
|
18 | 9 | — | — | 27 | |||||||||||||||
|
Other
commitments
|
53 | 15 | — | — | 68 | |||||||||||||||
|
Total
contractual obligations
|
$ | 135 | $ | 153 | $ | 129 | $ | 1,539 | $ | 1,956 | ||||||||||
Long-Term Debt (Principal and
Interest). Debt obligations included in the table above represent stated
maturities. Interest payments are shown through the stated maturity date of the
related fixed rate debt based on the contractual interest rate. For a further
discussion of our debt obligations, see Item 8, Financial Statements and
Supplementary Data, Note 6.
Operating Leases. For a
further discussion of these obligations see Item 8, Financial Statements and
Supplementary Data, Note 7.
Other Contractual Commitments and
Purchase Obligations. Other contractual commitments and purchase
obligations are defined as legally enforceable agreements to purchase goods or
services that have fixed or minimum quantities and fixed or minimum variable
price provisions, and that detail approximate timing of the underlying
obligations. Included are the following:
|
·
|
Transportation and Storage
Commitments. Included in these amounts are commitments for
purchasing pipe and related assets in our pipeline operations, and various
other maintenance, engineering, procurement and construction contracts. We
have excluded asset retirement obligations, reserves for litigation and
environmental remediation as these liabilities are not contractually fixed
as to the timing and amount.
|
|
·
|
Other Commitments.
Included in these amounts are commitments for electric service to
provide power to certain of our compression facilities and contractual
obligations related to our expansion projects. We have excluded asset
retirement obligations and reserves for litigation and environmental
remediation as these liabilities are not contractually fixed as to timing
and amount.
|
Commitments
and Contingencies
For a further
discussion of our commitments and contingencies, see Item 8, Financial
Statements and Supplementary Data, Note 7, which is incorporated herein by
reference.
Climate Change and Energy
Legislation and Regulation. There are various legislative and regulatory
measures relating to climate change and energy policies that have been proposed
and, if enacted, will likely impact our business.
Climate Change Legislation and
Regulation. Measures to address climate change and greenhouse gas (GHG)
emissions are in various phases of discussions or implementation at
international, federal, regional and state levels. Over 50 countries, including
the U.S., have submitted formal pledges to cut or limit their emissions in
response to the United Nations-sponsored Copenhagen Accord. It is
reasonably likely that federal legislation requiring GHG controls will be
enacted within the next few years in the United States. Although it is uncertain
what legislation will ultimately be enacted, it is our belief that cap-and-trade
or other market-based legislation that sets a price on carbon emissions will
increase demand for natural gas, particularly in the power sector. We believe
this increased demand will occur due to substantially less carbon emissions
associated with the use of natural gas compared with alternate fuel sources for
power generation, including coal and oil-fired power generation. However, the
actual impact on demand will depend on the legislative provisions that are
ultimately adopted, including the level of emission caps, allowances granted,
offset programs established, cost of emission credits and incentives provided to
other fossil fuels and lower carbon technologies like nuclear, carbon capture
sequestration and renewable energy sources.
It is also
reasonably likely that any federal legislation enacted would increase our cost
of environmental compliance by requiring us to install additional equipment to
reduce carbon emissions from our larger facilities as well as to potentially
purchase emission allowances. Based on 2008 operational data we reported to the
California Climate Action Registry our operations in the United States emitted
approximately 1.8 million tonnes of carbon dioxide equivalent emissions during
2008. We believe that approximately 1.6 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 21 percent would be subject to the cap-and-trade rules contained
in the proposed legislation and the remainder would be subject to performance
standards. As proposed by the House, the portion of our GHG emissions that would
be subject to cap-and-trade rules could require us to purchase allowances or
offset credits and the portion of our GHG emissions that would be subject to
performance standards could require us to install additional equipment or
initiate new work practice standards to reduce emission levels at many of
our facilities. The costs of purchasing emission allowances or offset
credits and installing additional equipment or changing work practices would
likely be material. Increases in costs of our suppliers to comply with such
cap-and-trade rules and performance standards, such as the electricity we
purchase in our operations, could also be material and would likely increase our
cost of operations. Although we believe that many of these costs should be
recoverable in the rates we charge our customers, recovery is still uncertain at
this time. A climate
change bill was also voted upon favorably by the Senate Committee on Energy and
Public Works (the Committee) in November 2009 and has been ordered to be
reported out of the Committee. Any final bill passed out of the U.S. Senate will
likely see further substantial changes, and we cannot yet predict the form it
may take, the timing of when any legislation will be enacted or implemented or
how it may impact our operations if ultimately enacted.
The Environmental
Protection Agency (EPA) finalized regulations to monitor and report GHG
emissions on an annual basis. The EPA also proposed new regulations to regulate
GHGs under the Clean Air Act, which the EPA has indicated could be finalized as
early as March 2010. The effective date and substantive requirements of any EPA
final rule is subject to interpretation and possible legal challenges. In
addition, it is uncertain whether federal legislation might be enacted that
either delays the implementation of any climate change regulations of the EPA or
adopts a different statutory structure for regulating GHGs than is provided for
pursuant to the Clean Air Act. Therefore, the potential impact on our
operations 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 $12 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 federal and 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 in 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 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.
Off-Balance
Sheet Arrangements
For a discussion of
our off-balance sheet arrangements, see Item 8, Financial Statements and
Supplementary Data, Notes 7 and 11, which are incorporated herein by
reference.
Critical
Accounting Policies and Estimates
The accounting
policies discussed below are considered by management to be critical to an
understanding of our financial statements as their application places the most
significant demands on management’s judgment. Due to the inherent uncertainties
involved with this type of judgment, actual results could differ significantly
from estimates and may have a material impact on our results of operations. For
additional information concerning our other accounting policies, see the notes
to the financial statements included in Item 8, Financial Statements and
Supplementary Data, Note 1.
Cost-Based
Regulation. We account for our regulated operations in accordance with
current Financial Accounting Standards Board’s accounting standards on
rate-regulated operations. The economic effects of regulation can result in a
regulated company recording assets for costs that have been or are expected to
be approved for recovery from customers or recording liabilities for amounts
that are expected to be returned to customers in the rate-setting process in a
period different from the period in which the amounts would be recorded by an
unregulated enterprise. Accordingly, we record assets and liabilities that
result from the regulated ratemaking process that would not be recorded under
U.S. generally accepted accounting principles for non-regulated entities.
Management regularly assesses whether regulatory assets are probable of future
recovery or if regulatory liabilities are probable of being refunded to our
customers by considering factors such as applicable regulatory changes and
recent rate orders applicable to other regulated entities. Based on this
continual assessment, management believes the existing regulatory assets are
probable of recovery. We periodically evaluate the applicability of this
standard, and consider factors such as regulatory changes and the impact of
competition. If cost-based regulation ends or competition increases, we may have
to reduce certain of our asset balances to reflect a market basis lower than
cost and write-off the associated regulatory assets.
Accounting
for Other Postretirement Benefits. We reflect an asset
or liability for our postretirement benefit plan based on its over funded or
under funded status. As of December 31, 2009, our postretirement benefit plan
was under funded by $7 million. Our postretirement benefit obligation and net
benefit costs are primarily based on actuarial calculations. We use various
assumptions in performing these calculations, including those related to the
return that we expect to earn on our plan assets, the estimated cost of health
care when benefits are provided under our plan and other factors. A significant
assumption we utilize is the discount rates used in calculating our benefit
obligation. We select our discount rate by matching the timing and amount of our
expected future benefit payments for our postretirement benefit obligation to
the average yields of various high-quality bonds with corresponding
maturities.
Actual results may
differ from the assumptions included in these calculations, and as a result, our
estimates associated with postretirement benefits can be, and often are, revised
in the future. The income statement impact of the changes in the assumptions on
our related benefit obligation, along with changes to the plan and other items,
are deferred and recorded as either a regulatory asset or liability. A one
percent change in our primary assumptions would not have had a
significant effect on net postretirement benefit cost. The following table shows
the impact of a one percent change to the funded status for the year ended
December 31, 2009 (in millions):
|
Change
in Funded Status
|
||||
|
One percent
increase in:
|
||||
|
Discount
rates
|
$ | 5 | ||
|
Health care
cost trends
|
(5 | ) | ||
|
One percent
decrease in:
|
||||
|
Discount
rates
|
$ | (5 | ) | |
|
Health care
cost trends
|
4 | |||
New
Accounting Pronouncements Issued But Not Yet Adopted
See Item 8,
Financial Statements and Supplementary Data, Note 1, under New Accounting Pronouncements Issued But
Not Yet Adopted, which is incorporated herein by reference.
We are exposed to
the risk of changing interest rates. At December 31, 2009, we had a note
receivable from El Paso of approximately $154 million, with a variable
interest rate of 1.5% that is due upon demand. While we are exposed to changes
in interest income based on changes to the variable interest rate, the fair
value of this note receivable approximates the carrying value due to the note
being due upon demand and the market-based nature of the interest
rate.
The table below
shows the carrying value, 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
|
Fair
|
Carrying
|
Fair
|
||||||||||||||||||||
|
|
2009-2013 |
Thereafter
|
Total
|
Value
|
Amount
|
Value
|
||||||||||||||||||
|
(In
millions, except for rate)
|
||||||||||||||||||||||||
|
Liabilities:
|
||||||||||||||||||||||||
|
Long-term
debt — fixed rate
|
$ | — | $ | 910 | $ | 910 | $ | 977 | $ | 910 | $ | 726 | ||||||||||||
|
Average
effective interest rate
|
6.8 | % | ||||||||||||||||||||||
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 Partners of
Southern Natural Gas Company
We have audited the
accompanying consolidated balance sheets of Southern Natural Gas Company (the
Company) as of December 31, 2009 and 2008, and the related consolidated
statements of income and comprehensive income, partners’ capital/stockholder’s
equity, and cash flows for each of the three years in the period ended
December 31, 2009. Our audits also included the financial statement
schedule listed in the Index at Item 15(a) for each of the three years in the
period ended December 31, 2009. These financial statements and schedule are
the responsibility of the Company’s management. Our responsibility is to express
an opinion on these financial statements and schedule based on our audits. The
consolidated financial statements of Citrus Corp. and Subsidiaries (a
corporation in which the Company had a 50% interest), have been audited by other
auditors whose report has been furnished to us, and our opinion on the
consolidated financial statements, insofar as it relates to the amounts included
from Citrus Corp. and Subsidiaries, is based solely on the report of the other
auditors, exclusive of the income adjustment related to the disposition of the
equity interest in November 2007. In the consolidated financial statements,
earnings from the Company’s investment in Citrus Corp. represent approximately
28% of income before income taxes for the year ended December 31,
2007.
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 and the report of other auditors provide a reasonable basis for our
opinion.
In our opinion,
based on our audits and the report of other auditors, the financial statements
referred to above present fairly, in all material respects, the consolidated
financial position of Southern Natural Gas Company at December 31, 2009 and
2008, and the consolidated results of its operations and its cash flows for each
of the three years in the period ended December 31, 2009, in conformity
with U.S. generally accepted accounting principles. Also, in our opinion, the
related financial statement schedule, when considered in relation to the basic
financial statements taken as a whole, presents fairly in all material respects
the information set forth therein.
As discussed in
Note 1 to the consolidated financial statements, effective January 1, 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 measurement date and changed the measurement date of
its postretirement benefit plan.
/s/ Ernst &
Young LLP
Houston,
Texas
February 26,
2010
SOUTHERN
NATURAL GAS COMPANY
CONSOLIDATED
STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(In
millions)
|
|
Year Ended December 31,
|
|||||||||||
|
|
2009
|
2008
|
2007
|
|||||||||
|
Operating
revenues
|
$ | 510 | $ | 540 | $ | 482 | ||||||
|
Operating
expenses
|
||||||||||||
|
Operation and
maintenance
|
173 | 189 | 160 | |||||||||
|
Depreciation
and amortization
|
55 | 53 | 53 | |||||||||
|
Taxes, other
than income taxes
|
27 | 27 | 27 | |||||||||
| 255 | 269 | 240 | ||||||||||
|
Operating
income
|
255 | 271 | 242 | |||||||||
|
Earnings from
unconsolidated affiliates
|
11 | 13 | 88 | |||||||||
|
Other income,
net
|
2 | 10 | 13 | |||||||||
|
Interest and
debt expense
|
(62 | ) | (72 | ) | (91 | ) | ||||||
|
Affiliated
interest income
|
2 | 13 | 19 | |||||||||
|
Income before
income taxes
|
208 | 235 | 271 | |||||||||
|
Income tax
expense
|
— | — | 69 | |||||||||
|
Income from
continuing operations
|
208 | 235 | 202 | |||||||||
|
Discontinued
operations, net of income taxes
|
— | — | 19 | |||||||||
|
Net
income
|
208 | 235 | 221 | |||||||||
|
Other
comprehensive income
|
— | — | 1 | |||||||||
|
Comprehensive
income
|
$ | 208 | $ | 235 | $ | 222 | ||||||
See accompanying
notes.
SOUTHERN
NATURAL GAS COMPANY
CONSOLIDATED
BALANCE SHEETS
(In
millions)
|
|
December
31,
|
|||||||
|
|
2009
|
2008
|
||||||
|
ASSETS
|
||||||||
|
Current
assets
|
||||||||
|
Cash and cash equivalents
|
$ | — | $ | — | ||||
|
Accounts and
notes receivable
|
||||||||
|
Customer
|
7 | 3 | ||||||
|
Affiliates
|
64 | 71 | ||||||
|
Other
|
2 | 2 | ||||||
|
Materials and supplies
|
15 | 14 | ||||||
|
Other
|
9 | 15 | ||||||
|
Total current assets
|
97 | 105 | ||||||
|
Property, plant and equipment,
at cost
|
3,709 | 3,636 | ||||||
|
Less accumulated depreciation
and amortization
|
1,411 | 1,373 | ||||||
|
Total property, plant and
equipment, net
|
2,298 | 2,263 | ||||||
|
Other
assets
|
||||||||
|
Investment in unconsolidated
affiliate
|
79 | 81 | ||||||
|
Note receivable from
affiliate
|
112 | 95 | ||||||
|
Other
|
73 | 85 | ||||||
| 264 | 261 | |||||||
|
Total
assets
|
$ | 2,659 | $ | 2,629 | ||||
|
LIABILITIES
AND PARTNERS’ CAPITAL
|
||||||||
|
Current
liabilities
|
||||||||
|
Accounts
payable
|
||||||||
|
Trade
|
$ | 19 | $ | 28 | ||||
|
Affiliates
|
27 | 10 | ||||||
|
Other
|
16 | 18 | ||||||
|
Taxes
payable
|
9 | 8 | ||||||
|
Accrued
interest
|
18 | 18 | ||||||
|
Asset
retirement obligation
|
14 | — | ||||||
|
Other
|
5 | 10 | ||||||
|
Total current
liabilities
|
108 | 92 | ||||||
|
Long-term
debt
|
910 | 910 | ||||||
|
Other
liabilities
|
27 | 50 | ||||||
|
Commitments
and contingencies (Note 7)
|
||||||||
|
Partners’
capital
|
1,614 | 1,577 | ||||||
|
Total
liabilities and partners’ capital
|
$ | 2,659 | $ | 2,629 | ||||
See accompanying
notes.
SOUTHERN
NATURAL GAS COMPANY
CONSOLIDATED
STATEMENTS OF CASH FLOWS
(In
millions)
|
|
Year Ended December 31,
|
|||||||||||
|
|
2009
|
2008
|
2007
|
|||||||||
|
Cash flows
from operating activities
|
||||||||||||
|
Net
income
|
$ | 208 | $ | 235 | $ | 221 | ||||||
|
Less income
from discontinued operations, net of income taxes
|
— | — | 19 | |||||||||
|
Income from
continuing operations
|
208 | 235 | 202 | |||||||||
|
Adjustments
to reconcile net income to net cash from operating
activities
|
||||||||||||
|
Depreciation
and amortization
|
55 | 53 | 53 | |||||||||
|
Deferred
income tax expense
|
— | — | 23 | |||||||||
|
Earnings from
unconsolidated affiliates, adjusted for cash distributions
|
2 | 3 | 42 | |||||||||
|
Other
non-cash income items
|
(1 | ) | (5 | ) | (6 | ) | ||||||
|
Asset and
liability changes
|
||||||||||||
|
Accounts
receivable
|
4 | 13 | (7 | ) | ||||||||
|
Accounts
payable
|
9 | 7 | (13 | ) | ||||||||
|
Taxes
payable
|
— | — | (21 | ) | ||||||||
|
Other current
assets
|
18 | (5 | ) | 5 | ||||||||
|
Other current
liabilities
|
10 | (9 | ) | (4 | ) | |||||||
|
Non-current
assets
|
— | (11 | ) | (5 | ) | |||||||
|
Non-current
liabilities
|
(19 | ) | 4 | (320 | ) | |||||||
|
Cash provided
by (used in) continuing activities
|
286 | 285 | (51 | ) | ||||||||
|
Cash provided
by discontinued activities
|
— | — | 25 | |||||||||
|
Net
cash provided by (used in)
operating activities
|
286 | 285 | (26 | ) | ||||||||
|
Cash flows
from investing activities
|
||||||||||||
|
Capital
expenditures
|
(138 | ) | (138 | ) | (243 | ) | ||||||
|
Net change in
notes receivable from affiliate
|
(18 | ) | 289 | (152 | ) | |||||||
|
Proceeds from
the sale of assets
|
41 | — | — | |||||||||
|
Cash provided
by (used in) continuing activities
|
(115 | ) | 151 | (395 | ) | |||||||
|
Cash used in
discontinued activities
|
— | — | (25 | ) | ||||||||
|
Net cash
provided by (used in) investing activities
|
(115 | ) | 151 | (420 | ) | |||||||
|
Cash flows
from financing activities
|
||||||||||||
|
Payments to
retire long-term debt
|
— | (236 | ) | (584 | ) | |||||||
|
Distributions
to partners
|
(171 | ) | (200 | ) | — | |||||||
|
Net proceeds
from issuance of long-term debt
|
— | — | 494 | |||||||||
|
Contribution
from parent
|
— | — | 536 | |||||||||
|
Net cash
provided by (used in) financing activities
|
(171 | ) | (436 | ) | 446 | |||||||
|
Net change in
cash and cash equivalents
|
— | — | — | |||||||||
|
Cash and cash
equivalents
|
||||||||||||
|
Beginning of
period
|
— | — | — | |||||||||
|
End of
period
|
$ | — | $ | — | $ | — | ||||||
See accompanying
notes.
SOUTHERN
NATURAL GAS COMPANY
CONSOLIDATED
STATEMENTS OF PARTNERS’ CAPITAL/STOCKHOLDER’S EQUITY
(In
millions, except share amounts)
|
Common Stock
|
Additional
Paid-in
|
Retained
|
Accumulated
Other
Comprehensive
|
Total
Stockholder’s
|
Total
Partners’
|
|||||||||||||||||||||||
|
|
Shares
|
Amount
|
Capital
|
Earnings
|
Income (Loss)
|
Equity
|
Capital
|
|||||||||||||||||||||
|
January 1,
2007
|
1,000 | $ | — | $ | 340 | $ | 1,304 | $ | — | $ | 1,644 | $ | — | |||||||||||||||
|
Net
income
|
187 | 187 | ||||||||||||||||||||||||||
|
Other
comprehensive income
|
1 | 1 | — | |||||||||||||||||||||||||
|
Adoption of
new tax accounting standard,
net of income tax
of $(3)
|
(5 | ) | (5 | ) | — | |||||||||||||||||||||||
|
Reclassification
to regulatory liability
(Note
8)
|
(5 | ) | (5 | ) | — | |||||||||||||||||||||||
|
October 31,
2007
|
1,000 | — | 340 | 1,486 | (4 | ) | 1,822 | — | ||||||||||||||||||||
|
Conversion to
general partnership
(November 1,
2007)
|
(1,000 | ) | (340 | ) | (1,486 | ) | 4 | (1,822 | ) | 1,822 | ||||||||||||||||||
|
Contributions
|
536 | |||||||||||||||||||||||||||
|
Distributions
|
(850 | ) | ||||||||||||||||||||||||||
|
Net
income
|
34 | |||||||||||||||||||||||||||
|
December 31,
2007
|
— | — | — | — | — | — | 1,542 | |||||||||||||||||||||
|
Net
income
|
235 | |||||||||||||||||||||||||||
|
Distributions
|
(200 | ) | ||||||||||||||||||||||||||
|
December 31,
2008
|
— | — | — | — | — | — | 1,577 | |||||||||||||||||||||
|
Net
income
|
208 | |||||||||||||||||||||||||||
|
Distributions
|
(171 | ) | ||||||||||||||||||||||||||
|
December 31,
2009
|
— | $ | — | $ | — | $ | — | $ | — | $ | — | $ | 1,614 | |||||||||||||||
See accompanying
notes.
SOUTHERN
NATURAL GAS COMPANY
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
1.
Summary of Significant Accounting Policies
Basis
of Presentation and Principles of Consolidation
We are a Delaware
general partnership, originally formed in 1935 as a corporation. We are
owned 75 percent by El Paso SNG Holding Company, L.L.C., a subsidiary of El Paso
Corporation (El Paso) and 25 percent by EPPP SNG GP Holdings, L.L.C., a
subsidiary of El Paso Pipeline Partners, L.P. (EPB) which is majority owned by
El Paso. In conjunction with the formation of EPB in November 2007, we
distributed our 50 percent interest in Citrus Corp. (Citrus), our wholly owned
subsidiaries Southern LNG, Inc. (SLNG) and Elba Express Company, LLC (Elba
Express) to El Paso effective November 21, 2007. Citrus owns the Florida Gas
Transmission Company, LLC (FGT) pipeline system and SLNG owns our Elba Island
LNG facility. We have reflected the SLNG and Elba Express operations as
discontinued operations in our financial statements for periods prior to their
distribution. Additionally, effective November 1, 2007, we converted to a
general partnership and are no longer subject to income taxes and settled our
current and deferred income tax balances through El Paso’s cash management
program. For a further discussion of these and other related transactions, see
Notes 2, 3 and 11.
Our consolidated
financial statements are prepared in accordance with U.S. generally accepted
accounting principles (GAAP) and include the accounts of all consolidated
subsidiaries after the elimination of intercompany accounts and transactions.
We consolidate
entities when we either (i) have the ability to control the operating and
financial decisions and policies of that entity or (ii) are allocated a majority
of the entity’s losses and/or returns through our interests in that entity. The
determination of our ability to control or exert significant influence over an
entity and whether we are allocated a majority of the entity’s losses and/or
returns involves the use of judgment. We apply the equity method of accounting
where we can exert significant influence over, but do not control the policies
and decisions of an entity and where we are not allocated a majority of the
entity’s losses and/or returns. We use the cost method of accounting where we
are unable to exert significant influence over the entity.
Use
of Estimates
The preparation of
our financial statements requires the use of estimates and assumptions that
affect the amounts we report as assets, liabilities, revenues and expenses and
our disclosures in these financial statements. Actual results can, and often do,
differ from those estimates.
Regulated
Operations
Our natural gas
pipeline and storage operations are subject to the jurisdiction of the Federal
Energy Regulatory Commission (FERC) under the Natural Gas Act of 1938, the
Natural Gas Policy Act of 1978 and the Energy Policy Act of 2005. We follow the
Financial Accounting Standards Board’s (FASB) accounting standards for regulated
operations. Under these standards, we record regulatory assets and liabilities
that would not be recorded under GAAP for non-regulated entities. Regulatory
assets and liabilities represent probable future revenues or expenses associated
with certain charges or credits that are expected to be recovered from or
refunded to customers through the rate making process. Items to which we apply
regulatory accounting requirements include certain postretirement employee
benefit plan costs, loss on reacquired debt, an equity return component on
regulated capital projects 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 received on a customer’s
contract at the supply point differs from the amount of natural gas delivered
under the customer’s transportation contract at the delivery point. We value
these imbalances due to or from shippers at specified index prices set forth in
our tariff based on the production month in which the imbalances occur. Customer
imbalances are aggregated and netted on a monthly basis, and settled in cash,
subject to the terms of our tariff. For differences in value between the amounts
we pay or receive for the purchase or sale of natural gas used to resolve
shipper imbalances over the course of a year, we have the right under our tariff
to recover applicable losses or refund applicable gains through a storage cost
reconciliation charge. This charge is applied to volumes as they are transported
on our system. Annually, we true-up any losses or gains obtained during the year
by adjusting the following years’ storage cost reconciliation
charge.
Imbalances due from
others are reported in our balance sheet as either accounts receivable from
customers or accounts receivable from affiliates. Imbalances owed to others are
reported on the balance sheet as either trade accounts payable or accounts
payable to affiliates. We classify all imbalances as current as we expect to
settle them within a year.
Property,
Plant and Equipment
Our property, plant
and equipment is recorded at its original cost of construction or, upon
acquisition, at either the fair value of the assets acquired or the cost to the
entity that first placed the asset in service. For assets we construct, we
capitalize direct costs, such as labor and materials, and indirect costs, such
as overhead, interest and an equity return component, as allowed by the FERC. We
capitalize major units of property replacements or improvements and expense
minor items.
We use the
composite (group) method to depreciate property, plant and equipment. Under this
method, assets with similar lives and characteristics are grouped and
depreciated as one asset. We apply the FERC-accepted depreciation rate to the
total cost of the group until its net book value equals its salvage value.
Currently, our depreciation rates vary from less than one percent to 20 percent
per year. Using these rates, the remaining depreciable lives of these assets
range from two to 43 years. We re-evaluate depreciation rates each time we file
with the FERC for a change in our transportation and storage rates.
When we retire
property, plant and equipment, we charge accumulated depreciation and
amortization for the original cost of the assets in addition to the cost to
remove, sell or dispose of the assets, less their salvage value. We do not
recognize a gain or loss unless we sell or retire an entire operating unit, as
defined by the FERC. We include gains or losses on dispositions of operating
units in operation and maintenance expense in our income
statements.
At December 31,
2009 and 2008, we had $34 million and $48 million of construction work in
progress included in our property, plant and equipment.
We capitalize a
carrying cost (an allowance for funds used during construction) on debt and
equity funds related to our construction of long-lived assets. This carrying
cost consists of a return on the investment financed by debt and a return on the
investment financed by equity. The debt portion is calculated based on our
average cost of debt. Interest costs capitalized during the years ended December
31, 2009, 2008 and 2007, were $1 million, $3 million and $4 million. These
debt amounts are included as a reduction to interest and debt expense on our
income statement. The equity portion is calculated using the most recent
FERC-approved equity rate of return. The equity amounts capitalized (exclusive
of taxes) during the years ended December 31, 2009, 2008 and 2007, were $3
million, $7 million and $8 million. These equity amounts are included in other
income on our income statement.
Asset
and Investment Divestitures/Impairments
We evaluate assets
and investments for impairment when events or circumstances indicate that their
carrying values may not be recovered. These events include market declines that
are believed to be other than temporary, changes in the manner in which we
intend to use a long-lived asset, decisions to sell an asset or investment and
adverse changes in the legal or business environment such as adverse actions by
regulators. When an event occurs, we evaluate the recoverability of our carrying
value based on either (i) the long-lived asset’s ability to generate future cash
flows on an undiscounted basis or (ii) the fair value of the investment in an
unconsolidated affiliate. If an impairment is indicated, or if we decide to sell
a long-lived asset or group of assets, we adjust the carrying value of the asset
downward, if necessary, to its estimated fair value. Our fair value estimates
are generally based on market data obtained through the sales process or an
analysis of expected discounted cash flows. The magnitude of any impairment is
impacted by a number of factors, including the nature of the assets being sold
and our established time frame for completing the sale, among other
factors.
We reclassify
assets to be sold in our financial statements as either held-for-sale or from
discontinued operations when it becomes probable that we will dispose of the
assets within the next twelve months and when they meet other criteria,
including whether we will have significant long-term continuing involvement with
those assets after they are sold. We cease depreciating assets in the
period that they are reclassified as either held for sale or from discontinued
operations, and reflect the results of our discontinued operations in our income
statement separtely from those of continuing operations.
Cash flows from our
discontinued businesses are reflected as discontinued operating, investing, and
financing activities in our statement of cash flows. Cash provided by
discontinued activities in the operating activities section of our cash flow
statement includes all operating cash flows generated by our discontinued
businesses during the period. Proceeds from the sale of our discontinued
operations are classified in cash provided by discontinued activities in the
cash flows from investing activities section of our cash flow statement. To the
extent that these operations participated in El Paso’s cash management program,
we reflected transactions related to El Paso’s cash management program as
financing activities in our cash flow statement. We cease depreciating assets in
the period that they are reclassified as either held for sale or as discontinued
operations.
Revenue
Recognition
Our revenues are
primarily generated from natural gas transportation 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
ratably over the contract period regardless of the amount of natural gas that is
transported or stored. For interruptible or volumetric-based services, we
record revenues when physical deliveries of natural gas are made at the agreed
upon delivery point or when gas is injected or withdrawn from the storage
facility. Gas not used in operations is based on the volumes of natural gas we
are allowed to retain and dispose of relative to the amounts we use for
operating purposes. As calculated in a manner set forth in our
tariff, volumes from any excess natural gas retained and not used in
operations are to be given back to our customers through lower retention
percentages determined on an annual basis. We recognize our share of
revenues on gas not used in operations from our shippers when we retain the
volumes at the market prices 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
Effective November 1, 2007, we
converted to a general partnership in conjunction with the formation of EPB
and accordingly, we are no longer subject to income taxes. As a result of our
conversion to a general partnership, we settled our then existing current and
deferred tax balances with recoveries of note receivables from El Paso under its
cash management program pursuant to our tax sharing agreement with El Paso (see
Notes 3 and 11). Prior to that date, we recorded current income taxes based on
our taxable income and provided for deferred income taxes to reflect estimated
future tax payments and receipts. Deferred taxes represented the income tax
impacts of differences between the financial statement and tax bases of assets
and liabilities and carryovers at each year end. We accounted for tax credits
under the flow-through method, which reduced the provision for income taxes in
the year the tax credits first became available. We reduced deferred tax assets
by a valuation allowance when, based on our estimates, it was more likely than
not that a portion of those assets would not be realized in a future
period.
On January 1, 2007,
we adopted a new income tax accounting standard. The adoption of the standard
did not have a material impact on our financial statements.
Accounting
for Asset Retirement Obligations
We record a
liability for legal obligations associated with the replacement, removal or
retirement of our long-lived assets in the period the obligation is incurred.
Our asset retirement liabilities are initially recorded at their estimated fair
value with a corresponding increase to property, plant and equipment. This
increase in property, plant and equipment is then depreciated over the useful
life of the asset to which that liability relates. An ongoing expense is also
recognized for changes in the value of the liability as a result of the passage
of time, which we record as depreciation and amortization expense in our income
statement. We have the ability to recover certain of these costs from our
customers and have recorded an asset (rather than expense) associated with the
accretion of the liabilities described above.
We have legal
obligations associated with the retirement of our natural gas pipeline,
transmission facilities and storage wells. 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 if they are replaced. 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. We record changes in
estimates based on changes in the expected amount and timing of payments to
settle our asset retirement 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
|
$ | 20 | $ | — | ||||
|
Accretion
expense
|
2 | — | ||||||
|
Changes in
estimate
|
(3 | ) | 20 | |||||
|
Net asset
retirement obligation at December 31(1)
|
$ | 19 | $ | 20 | ||||
____________
|
(1)
|
For the
year ended December 31, 2009, approximately $14 million of this amount is
reflected in current
liabilities.
|
Postretirement
Benefits
We maintain a
postretirement benefit plan covering certain of our former employees. This plan
requires us to make contributions to fund the benefits to be paid out under the
plan. These contributions are invested until the benefits are paid out to plan
participants. We record the net benefit cost related to this plan in our income
statement. This net benefit cost is a function of many factors including
benefits earned during the year by plan participants (which is a function of the
level of benefits provided under the plan, actuarial assumptions and the passage
of time), expected returns on plan assets and amortization of certain deferred
gains and losses. For a further discussion of our policies with respect to our
postretirement benefit plan, see Note 8.
In accounting for
our postretirement benefit plan, we record an asset or liability for our
postretirement benefit plan based on the over funded or under funded status of
the plan. Any deferred amounts related to unrecognized gains and losses or
changes in actuarial assumptions are recorded as either a regulatory asset or
liability.
Effective January
1, 2008, we adopted the provisions of an accounting standard update
related to measurement date and changed the measurement date of our
postretirement benefit plan from September 30 to December 31. The adoption of
the measurement date provisions of this standard did not have a material impact
on our financial statements.
Effective December
31, 2009, we expanded our disclosures about postretirement benefit plan assets
as a result of new disclosure requirements. See Note 8 for these expanded
disclosures.
New
Accounting Pronouncements Issued But Not Yet Adopted
As of December 31,
2009, the following accounting standards had not yet been adopted by
us.
Transfers of Financial
Assets. In June 2009, the FASB updated accounting standards on financial
asset transfers. Among other items, this update eliminated the concept of a
qualifying special-purpose entity (QSPE) for purposes of evaluating whether an
entity should be consolidated or not. The changes are effective for
existing QSPEs as of January 1, 2010 and for transactions entered into on or
after January 1, 2010. The adoption of this accounting standard in January of
2010 did not have a material impact on our financial statements as we amended
our existing accounts receivable sales program in January 2010 (see Note
11).
Variable Interest Entities.
In June 2009, the FASB updated accounting standards for variable interest
entities to revise how companies determine the primary beneficiaries of these
entities, among other changes. Companies will now be required to use a
qualitative approach based on their responsibilities and power over the
entities’ operations, rather than a quantitative approach in determining the
primary beneficiary as previously required. The adoption of this
accounting standard in January of 2010 did not have a material impact on our
financial statements.
2.
Divestitures
In November 2007,
in conjunction with the formation of EPB, we distributed our wholly owned
subsidiaries, SLNG and Elba Express, to El Paso. We have reflected these
operations as discontinued operations in our financial statements for periods
prior to their distribution. We classify assets (or groups of assets) to be
disposed of as held for sale or, if appropriate, from discontinued operations
when they have received appropriate approvals to be disposed of by our
management when they meet other criteria. We also distributed our investment in
Citrus to El Paso which is not reflected in discontinued operations. The table
below summarizes the operating results of our discontinued operations for the
year ended December 31, 2007.
|
|
(In
millions)
|
|||
|
Revenues
|
$ | 61 | ||
|
Costs and
expenses
|
(35 | ) | ||
|
Other income,
net
|
4 | |||
|
Interest and
debt expense
|
1 | |||
|
Income before
income taxes
|
31 | |||
|
Income
taxes
|
12 | |||
|
Income from
discontinued operations, net of income taxes
|
$ | 19 | ||
3.
Income Taxes
In conjunction with
the formation of EPB, we converted our legal structure into a general
partnership effective November 1, 2007 and are no longer subject to income
taxes. We also settled our then existing current and deferred income tax
balances pursuant to our tax sharing agreement with El Paso with recoveries of
note receivables from El Paso under its cash management program.
Components
of Income Tax Expense. The following table reflects the components of
income tax expesne included in income from continuing operations for the year
ended December 31, 2007:
|
(In
millions)
|
||||
|
Current
|
||||
|
Federal
|
$ | 40 | ||
|
State
|
6 | |||
| 46 | ||||
|
Deferred
|
||||
|
Federal
|
19 | |||
|
State
|
4 | |||
| 23 | ||||
|
Total income
taxes
|
$ | 69 | ||
Effective Tax Rate
Reconciliation. Our income tax expense, included in income from
continuing operations differs from the amount computed by applying the statutory
federal income tax rate of 35 percent for the following reasons for the year
ended December 31, 2007:
|
(In
millions, except for rates)
|
||||
|
Income taxes
at the statutory federal rate of 35%
|
$ | 95 | ||
|
Increase
(decrease)
|
||||
|
Pretax income
not subject to income tax after conversion to partnership
|
(11 | ) | ||
|
State income
taxes, net of federal income tax benefit
|
6 | |||
|
Earnings from
unconsolidated affiliates where we anticipate receiving
dividends
|
(21 | ) | ||
|
Income
taxes
|
$ | 69 | ||
|
Effective tax
rate
|
25 | % | ||
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 an
interest bearing note receivable from El Paso of approximately $154 million
and $136 million due upon demand, with a variable interest rate of
1.5% and 3.2%. While we are exposed to changes in interest income based on
changes to the variable interest rate, the fair value of this note receivable
approximates the carrying value due to the note being due on demand and the
market-based nature of the interest rate.
In addition, the
carrying amounts of our long-term debt and their estimated fair values, which
are based on quoted market prices for the same or similar issues, are as follows
at December 31:
|
|
2009
|
2008
|
||||||||||||||
|
|
Carrying
Amount
|
Fair
Value
|
Carrying
Amount
|
Fair
Value
|
||||||||||||
|
(In
millions)
|
||||||||||||||||
|
Long-term
debt, including current maturities
|
$ | 910 | $ | 977 | $ | 910 | $ | 726 | ||||||||
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 non-current regulatory liabilities are
included in other non-current liabilities on our balance sheets. Our regulatory
asset and liability balances are recoverable or reimbursable over various
periods. Below are
the details of our regulatory assets and liabilities at December
31:
|
|
2009
|
2008
|
||||||
|
(In
millions)
|
||||||||
|
Current
regulatory assets
|
$ | 4 | $ | 1 | ||||
|
Non-current
regulatory assets
|
||||||||
|
Taxes on
capitalized funds used during construction
|
29 | 34 | ||||||
|
Unamortized
loss on reacquired debt
|
32 | 36 | ||||||
|
Other
|
1 | 4 | ||||||
|
Total
non-current regulatory assets
|
62 | 74 | ||||||
|
Total
regulatory assets
|
$ | 66 | $ | 75 | ||||
|
Non-current
regulatory liabilities
|
||||||||
|
Postretirement
benefits
|
$ | 5 | $ | — | ||||
|
Other
|
3 | 4 | ||||||
|
Total
non-current regulatory liabilities
|
$ | 8 | $ | 4 | ||||
The
significant regulatory assets and liabilities
include:
Taxes on Capitalized Funds Used
During Construction: These regulatory asset
balances were established to offset the deferred tax for the equity
component of the allowance for funds used during the construction of long-lived
assets. Taxes on capitalized funds used during construction 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.
Unamortized Net Loss on
Reacquired Debt: These amounts represent the deferred and unamortized
portion of losses on reacquired debt which are not included in the rate
base, but are recovered over the original life of the debt issue through the
authorized rate of return.
Postretirement
Benefits: These balances represent deferred amounts related to
unrecognized gains and losses or changes in actuarial assumptions related to our
postretirement benefit plan and differences in the postretirement benefit
related amounts expensed and the amounts recoverable in
rates. Postretirement benefit amounts have been included in the rate
base computations and are recoverable in such periods as the benefits are
funded.
6.
Debt and Credit Facilities
Debt. Our long-term debt
consisted of the following at December 31:
|
|
2009
|
2008
|
||||||
|
(In
millions)
|
||||||||
|
5.90% Notes
due April 2017
|
$ | 500 | $ | 500 | ||||
|
7.35% Notes
due February 2031
|
153 | 153 | ||||||
|
8.0% Notes
due March 2032
|
258 | 258 | ||||||
| 911 | 911 | |||||||
|
Less:
Unamortized discount
|
1 | 1 | ||||||
|
Total
long-term debt, less current maturities
|
$ | 910 | $ | 910 | ||||
In March 2009, we,
Southern Natural Issuing Corporation (SNIC), El Paso and certain other El Paso
subsidiaries filed a registration statement on Form S-3 under which we and SNIC
may co-issue debt securities in the future. SNIC is a wholly owned finance
subsidiary of us and is the co-issuer of certain of our outstanding debt
securities. SNIC has no material assets, operations, revenues or cash flows
other than those related to its service as a co-issuer of our debt securities.
Accordingly, it has no ability to service obligations on our debt
securities.
Under our
indentures, we are subject to a number of restrictions and covenants. The most
restrictive of these include limitations on the incurrence of liens. For the
year ended December 31, 2009, we were in compliance with our debt-related
covenants. Our long-term debt contains cross-acceleration provisions, the most
restrictive of which is a $10 million cross-acceleration clause. If triggered,
repayment of the long-term debt that contains these provisions could be
accelerated.
7.
Commitments and Contingencies
Legal
Proceedings
Gas Measurement Cases. We and
a number of our affiliates were named defendants in actions that generally
allege mismeasurement of natural gas volumes and/or heating content resulting in
the underpayment of royalties. These cases were 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 of Appeals affirmed the
dismissals and in October 2009, the plaintiff’s appeal to the United States
Supreme court was denied.
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 adjust our accruals
accordingly, and these adjustments could be material. At December 31,
2009, we accrued approximately $2 million for our outstanding legal
matters.
Environmental
Matters
We are subject to
federal, state and local laws and regulations governing environmental quality
and pollution control. These laws and regulations require us to remove or remedy
the effect on the environment of the disposal or release of specified substances
at current and former operating sites. At both December 31, 2009 and 2008, we
had accrued approximately $1 million for expected remediation costs and
associated onsite, offsite and groundwater technical studies.
It is possible that
new information or future developments could require us to reassess our
potential exposure related to environmental matters. We may incur significant
costs and liabilities in order to comply with existing environmental laws and
regulations. It is also possible that other developments, such as increasingly
strict environmental laws, regulations and orders of regulatory agencies, as
well as claims for damages to property and the environment or injuries to other
persons resulting from our current or past operations, could result in
substantial costs and liabilities in the future. As this information becomes
available, or other relevant developments occur, we will adjust our accrual
amounts accordingly. While there are still uncertainties related to the ultimate
costs we may incur, based upon our evaluation and experience to date, we believe
our reserves are adequate.
Rates
and Regulatory Matters
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.
Rate Case. In January 2010,
the FERC approved our settlement in which we (i) increased our base tariff rates
effective September 1, 2009, (ii) implemented a volume tracker for gas used in
operations, (iii) agreed to file our next general rate case to be effective
after August 31, 2012 but no later than September 1, 2013, and (iv)
extended the vast majority of our firm transportation contracts until August 31,
2013.
Other
Commitments
Commercial Commitments. At December 31, 2009, we entered into unconditional purchase
obligations for products and services totaling approximately $95 million
primarily related to the South System III project and the Southest Supply Header
project. Our annual obligations under these agreements are $71
million in 2010 and $24 million in 2011. In addition, we have other planned
capital and investment projects that are discretionary in nature, with no
substantial contractual capital commitments made in advance of the actual
expenditures.
Operating Leases. We lease
property, facilities and equipment under various operating leases. Our primary
commitment under operating leases is the lease of our office space in
Birmingham, Alabama. El Paso guarantees our obligations under these lease
agreements. Future minimum annual rental commitments under our operating leases
at December 31, 2009, were as follows:
|
Year
Ending
December 31,
|
|||||
| (In millions) | |||||
|
2010
|
$ | 3 | |||
|
2011
|
3 | ||||
|
2012
|
3 | ||||
|
2013
|
3 | ||||
|
2014
|
3 | ||||
|
Thereafter
|
8 | ||||
|
Total
|
$ | 23 | |||
Rent expense on our
lease obligations for the years ended December 31, 2009, 2008 and 2007 was less
than $1 million, $4 million, and less than $1 million. These amounts include our
share of rent allocated to us from El Paso.
Other Commercial Commitments.
We hold cancelable easements or rights-of-way arrangements from landowners
permitting the use of land for the construction and operation of our pipeline
system. Currently, our obligations under these easements are not material to the
results of our operations. During 2009, we entered into a $57 million letter of
credit associated with our projected construction costs related to the Southeast
Supply Header project.
Guarantees. We are or have
been involved in various ownership and other contractual arrangements that
sometimes require us to provide additional financial support that results in the
issuance of performance guarantees that are not recorded in our financial
statements. In a performance guarantee, we provide assurance that the guaranteed
party will execute on the terms of the contract. As of December 31, 2009, we
have a performance guarantee related to contracts held by SLNG, an entity
formerly owned by us, with a maximum exposure of $225 million and a
performance guarantee related to contracts held by Elba Express, an entity
formerly owned by us, with no stated maximum limit. We estimate our potential
exposure related to these guarantees is approximately $93 million, which is
based on their remaining estimated obligations under the contracts.
8.
Retirement Benefits
Pension and Retirement Savings
Plans. El Paso maintains a pension plan and a retirement savings plan
covering substantially all of its U.S. employees, including our former
employees. The benefits under the pension plan are determined under a cash
balance formula. Under its retirement savings plan, El Paso matches 75 percent
of participant basic contributions up to six percent of eligible compensation
and can make additional discretionary matching contributions depending on its
performance relative to its peers. El Paso is responsible for benefits accrued
under its plans and allocates the related costs to its affiliates.
Postretirement Benefits Plan.
We provide postretirement medical benefits for a closed group of
retirees. These benefits may be subject to deductibles, co-payment provisions,
and other limitations and dollar caps on the amount of employer costs and El
Paso reserves the right to change these benefits. Employees in this
group who retire after June 30, 2000 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 $4 million to our postretirement
benefit plan in 2010.
Accumulated Postretirement Benefit
Obligation, Plan Assets and Funded Status. In accounting for our
postretirement benefit plan under the accounting standards related to other
postretirement plans, we record an asset or liability for our postretirement
benefit plan based on its over funded or under funded status. In March 2007, the
FERC issued guidance requiring regulated pipeline companies to record a
regulatory asset or liability for any deferred amounts related to unrecognized
gains and losses or changes in actuarial assumptions that would otherwise be
recorded in accumulated other comprehensive income for non-regulated entities.
Upon adoption of this FERC guidance, we reclassified $5 million from accumulated
other comprehensive income to a regulatory liability.
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
|
$ | 61 | $ | 62 | ||||
|
Interest
cost
|
4 | 4 | ||||||
|
Participant
contributions
|
1 | 1 | ||||||
|
Actuarial
(gain) loss
|
(1 | ) | 1 | |||||
|
Benefits
paid(1)
|
(6 | ) | (7 | ) | ||||
|
Accumulated
postretirement benefit obligation - end of period
|
$ | 59 | $ | 61 | ||||
|
Change in
plan assets:
|
||||||||
|
Fair value of
plan assets - beginning period
|
$ | 46 | $ | 66 | ||||
|
Actual return
on plan assets
|
8 | (17 | ) | |||||
|
Employer
contributions
|
4 | 4 | ||||||
|
Participant
contributions
|
— | 1 | ||||||
|
Benefits
paid
|
(6 | ) | (8 | ) | ||||
|
Fair value of
plan assets - end of period
|
$ | 52 | $ | 46 | ||||
|
Reconciliation
of funded status:
|
||||||||
|
Fair value of
plan assets
|
$ | 52 | $ | 46 | ||||
|
Less:
accumulated postretirement benefit obligation
|
59 | 61 | ||||||
|
Net liability
at December 31
|
$ | (7 | ) | $ | (15 | ) | ||
____________
|
(1)
|
Amounts shown
net of a subsidy of less than $1 million and approximately $1 million
for the years ended December 31, 2009 and 2008 related to the
Medicare Prescription Drug, Improvement, and Modernization Act of
2003.
|
Plan Assets. The primary
investment objective of our plan is to ensure that, over the long-term life of
the plan, an adequate pool of sufficiently liquid assets exists to meet the
benefit obligations to retirees and beneficiaries. Investment objectives are
long-term in nature covering typical market cycles. Any shortfall of investment
performance compared to investment objectives is generally the result of
economic and capital market conditions. Although actual allocations
vary from time to time from our targeted allocations, the target allocations of
our postretirement plan’s assets are 65 percent equity and 35 percent fixed
income securities. We may invest assets in a manner that replicates, to the
extent feasible, the Russell 3000 Index and the Barclays Capital Aggregate Bond
Index to achieve equity and fixed income diversification,
respectively.
We use various
methods to determine the fair values of the assets in our other postretirement
benefit plans, which are impacted by a number of factors, including the
availability of observable market data over the contractual term of the
underlying assets. We separate these assets into three levels (Level
1, 2 and 3) based on our assessment of the availability of this market data and
the significance of non-observable data used to determine the fair value of
these assets. As of December 31, 2009, our assets are comprised of an
exchange-traded mutual fund with a fair value of $2 million and
common/collective trusts with a fair value of $50 million. Our
exchange-traded mutual fund invests primarily in dollar-denominated securities,
and its fair value (which is considered a Level 1 measurement) is determined
based on the price quoted for the fund in actively traded markets. Our
common/collective trusts are invested in approximately 65 percent equity and 35
percent fixed income securities, and their fair values (which are considered
Level 2 measurements) are determined primarily based on the net asset value
reported by the issuer, which is based on similar assets in active
markets. We may adjust the fair value of our common/collective
trusts, when necessary, for factors such as liquidity or risk of nonperformance
by the issuer. We do not have any assets that are considered Level 3
measurements. The methods described above may produce a fair value
that may not be indicative of net realizable value or reflective of future fair
values, and there have been no changes in the methodologies used at December 31,
2009 and 2008.
Expected Payment of Future Benefits.
As of December 31, 2009, we expect the following benefit payments under
our plan:
|
Year
Ending
December 31,
|
Expected
Payments(1)
|
||||
|
(In
millions)
|
|||||
|
2010
|
$ | 5 | |||
|
2011
|
5 | ||||
|
2012
|
5 | ||||
|
2013
|
5 | ||||
|
2014
|
5 | ||||
|
2015 -
2019
|
22 | ||||
_______
|
(1)
|
Includes a reduction of approximately $1
million in each of the years 2010 – 2014 and approximately $4 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
|
5.51 | 6.00 | 6.05 | |||||||||
|
Assumptions
related to benefit costs at December 31:
|
||||||||||||
|
Discount
rate
|
6.00 | 6.05 | 5.50 | |||||||||
|
Expected
return on plan assets(1)
|
8.00 | 8.00 | 8.00 | |||||||||
_______
|
(1)
|
The expected
return on plan assets is
a pre-tax rate of return based on our targeted portfolio of investments.
Our postretirement benefit plan’s investment earnings are subject to
unrelated business income taxes at a rate of 35%. The expected
return on plan assets for our postretirement benefit plan is calculated
using the after-tax rate of
return.
|
Actuarial estimates
for our postretirement benefits plan assumed a weighted average annual rate of
increase in the per capita costs of covered health care benefits of 8.0 percent,
gradually decreasing to 5.0 percent by the year 2015. Assumed health care cost
trends can have a significant effect on the amounts reported for our
postretirement benefit plan. A one-percentage point change would not have had a
significant effect on interest costs in 2009 or 2008. A one-percentage point
change in assumed health care cost trends would have the following effect as of
December 31, 2009 and 2008:
|
2009
|
2008
|
|||||||
|
(In
millions)
|
||||||||
|
One
percentage point increase:
|
||||||||
|
Accumulated
postretirement benefit obligation
|
$ | 5 | $ | 5 | ||||
|
One
percentage point decrease:
|
||||||||
|
Accumulated
postretirement benefit obligation
|
$ | (4 | ) | $ | (5 | ) | ||
Components of Net Benefit Cost.
For each of the years ended December 31, the components of net benefit
cost are as follows:
|
|
2009
|
2008
|
2007
|
|||||||||
|
(In
millions)
|
||||||||||||
|
Interest
cost
|
$ | 3 | $ | 4 | $ | 4 | ||||||
|
Expected
return on plan assets
|
(2 | ) | (3 | ) | (3 | ) | ||||||
|
Amortization
of net actuarial gain
|
— | (1 | ) | — | ||||||||
|
Net benefit
cost
|
$ | 1 | $ | — | $ | 1 | ||||||
9.
Transactions with Major Customers
The following table
shows revenues from our major customers for each of the three years ended
December 31:
|
|
2009
|
2008
|
2007
|
|||||||||
|
(In
millions)
|
||||||||||||
|
SCANA
Corporation(1)
|
$ | 83 | $ | 79 | $ | 77 | ||||||
|
Southern
Company Services
|
58 | 55 | 54 | |||||||||
_______
|
(1)
|
A significant
portion of revenues received from a subsidiary of SCANA Corporation
resulted from firm capacity released by Atlanta Gas Light Company under
terms allowed by our
tariff.
|
10.
Supplemental Cash Flow Information
The following table
contains supplemental cash flow information from continuing operations for each
of the three years ended December 31:
|
|
2009
|
2008
|
2007
|
|||||||||
|
(In
millions)
|
||||||||||||
|
Interest
paid, net of capitalized interest
|
$ | 61 | $ | 75 | $ | 97 | ||||||
|
Income tax
payments
|
— | — | 374 | (1) | ||||||||
|
(1)
|
Includes
amounts related to the settlement of current and deferred tax balances due
to the conversion to a partnership in November 2007 (see Notes 3 and
11).
|
11.
Investments in Unconsolidated Affiliates and Transactions with
Affiliates
Investments
in Unconsolidated Affiliates
Citrus. Prior to its transfer
to El Paso in November 2007 in conjunction with the formation of EPB, we had a
50 ownership percent interest in Citrus, which owns the FGT pipeline system.
CrossCountry Energy, LLC, a subsidiary of Southern Union Company, owns the other
50 percent of Citrus. During 2007, we received $103 million in dividends
from Citrus.
Bear Creek Storage Company, LLC
(Bear Creek). We have a 50 percent ownership interest in Bear Creek, a
joint venture with Tennessee Gas Pipeline 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 of our proportionate share of our unconsolidated
affiliates as of and for the years ended December 31 is presented as
follows:
|
|
2009
|
2008
|
2007
|
|||||||||
|
(In
millions)
|
||||||||||||
|
Operating
results data:(1)
|
||||||||||||
|
Operating
revenues
|
$ | 18 | $ | 20 | $ | 267 | ||||||
|
Operating
expenses
|
7 | 8 | 115 | |||||||||
|
Income from
continuing operations and net income
|
11 | 13 | 92 | (2) | ||||||||
|
|
2009
|
2008
|
||||||
|
(In
millions)
|
||||||||
|
Financial
position data:
|
||||||||
|
Current
assets
|
$ | 28 | $ | 27 | ||||
|
Non-current
assets
|
52 | 55 | ||||||
|
Other current
liabilities
|
1 | 1 | ||||||
|
Equity in net
assets
|
79 | 81 | ||||||
____________
|
(1)
|
Includes
Citrus results for the entire year ended December 31, 2007. Our share of
Citrus’ net income prior to the distribution of this investment in
November 2007 was $75 million, adjusted for the excess purchase price
amortization.
|
|
(2)
|
The difference
between our proportionate share of our equity investments’ net income and
our earnings from unconsolidated affiliates in 2007 is due primarily to
the excess purchase price amortization related to Citrus and differences
between the estimated and actual equity earnings on our
investments.
|
Transactions
with Affiliates
Contributions/Distributions.
On November 21, 2007, in conjunction with the formation of EPB, we made a
distribution of our 50 percent ownership in Citrus and our wholly owned
subsidiaries SLNG and Elba Express (described in Note 1) with a book value of
approximately $850 million to El Paso and El Paso made a capital contribution of
approximately $536 million to us.
We are required to
make distributions of available cash as defined in our partnership agreement on
a quarterly basis to our partners. During 2009 and 2008, we paid cash
distributions of approximately $171 million and $200 million to our
partners. We did not make any distributions to our partners during 2007. In
addition, in January 2010 we paid a cash distribution to our partners of
approximately $83 million.
Cash Management Program. We
participate in El Paso’s cash management program which matches short-term cash
surpluses and needs of participating affiliates, thus minimizing total
borrowings from outside sources. El Paso uses the cash management program to
settle intercompany transactions between participating affiliates. We have
historically advanced cash to El Paso in exchange for an affiliated note
receivable that is due upon demand. At December 31, 2009 and 2008, we had a
note receivable from El Paso of $154 million and $136 million. We classified $42
million and $41 million of this receivable as current on our balance sheets at
December 31, 2009 and 2008, based on the net amount we anticipate using in the
next twelve months considering available cash sources and needs. The interest
rate on our note at December 31, 2009 and 2008 was 1.5 % and 3.2%.
Income Taxes. Effective
November 1, 2007, we converted into a general partnership as discussed in Note 1
and settled our then existing current and deferred tax balances of approximately
$334 million pursuant to our tax sharing agreement with El Paso with recoveries
of note receivables from El Paso under its cash management program. During 2007,
we also settled $20 million with El Paso through its cash management program for
certain tax attributes previously reflected as deferred income taxes in our
financial statements. These settlements are reflected as operating activities in
our statement of cash flows.
Accounts Receivable Sales Program.
We sell certain accounts receivable to a QSPE whose purpose is solely to
invest in our receivables, which are short-term assets that generally settle
within 60 days. During the year ended December 31, 2009 and 2008, we received
net proceeds in both periods of $0.5 billion related to sales of receivables to
the QSPE and changes in our subordinated beneficial interests, and recognized
losses of less than $1 million on these transactions. As of December 31, 2009
and 2008, we had approximately $50 million and $48 million of receivables
outstanding with the QSPE, for which we received cash of approximately $30
million and $24 million and received subordinated beneficial interests of
approximately $19 million and $23 million. The QSPE also issued senior
beneficial interests on the receivables sold to a third party financial
institution, which totaled $30 million and $25 million as of December 31, 2009
and 2008. We reflect the subordinated interest in receivables sold at their fair
value on the date they are issued. These amounts (adjusted for subsequent
collections), are recorded as accounts receivable from affiliate in our balance
sheets. Our ability to recover our carrying value of our subordinated beneficial
interests is based on the collectability of the underlying receivables sold to
the QSPE. We reflect accounts receivable sold under this program and changes in
the subordinated beneficial interests as operating cash flows in our statement
of cash flows. Under these agreements, we earn a fee for servicing the
receivables and performing all administrative duties for the QSPE which is
reflected as a reduction of operation and maintenance expense in our income
statement. The fair value of these servicing and administrative agreements as
well as the fees earned were not material to our financial statements for the
years ended December 31, 2009 and 2008.
In January 2010, we
ceased selling accounts receivable to the QSPE and began selling those
receivables directly to a third party financial institution. In return, the
third party financial institution pays a certain amount of cash up front for the
receivables, and pays the remaining amount owed over time as cash is collected
from the receivables.
Affiliate Revenues and Expenses.
We enter into transactions with our affiliates within the ordinary course
of business and the services are based on the same terms as non-affiliates,
including natural gas transportation services to affiliates under long-term
contracts.
We do not have
employees. Following our reorganization in November 2007, our former employees
continue to provide services to us through an affiliated service company owned
by our general partner, El Paso. We are managed and operated by officers of El
Paso, our general partner. We have an omnibus agreement with El Paso and its
affiliates under which we reimburse El Paso for the provision of various general
and administrative services for our benefit and for direct expenses incurred by
El Paso on our behalf. El Paso bills us directly for certain general and
administrative costs and allocates a portion of its general and administrative
costs to us. In addition to allocations from El Paso, we are allocated costs
from Tennessee Gas Pipeline Company, our affiliate, associated with our pipeline
services. These allocations are based on the estimated level of effort devoted
to our operations and the relative size of our EBIT, gross property and
payroll.
The following table
shows overall revenues and charges from our affiliates for each of the three
years ended December 31:
|
|
2009
|
2008
|
2007
|
|||||||||
|
(In
millions)
|
||||||||||||
|
Revenues from
affiliates
|
$ | 6 | $ | 6 | $ | 7 | ||||||
|
Operation and
maintenance expenses from affiliates
|
125 | 120 | 69 | |||||||||
|
Reimbursement
of operating expenses charged to affiliates
|
14 | 13 | — | |||||||||
12.
Supplemental Selected Quarterly Financial Information (Unaudited)
Our financial
information by quarter is summarized below. Due to the seasonal nature of our
business, information for interim periods may not be indicative of our results
of operations for the entire year.
|
|
Quarters Ended
|
|
||||||||||||||||||
|
|
March 31
|
June 30
|
September 30
|
December 31
|
Total
|
|||||||||||||||
|
(In
millions)
|
||||||||||||||||||||
|
2009
|
||||||||||||||||||||
|
Operating
revenues
|
$ | 126 | $ | 119 | $ | 124 | $ | 141 | $ | 510 | ||||||||||
|
Operating
income
|
64 | 57 | 57 | 77 | 255 | |||||||||||||||
|
Net
income
|
48 | 48 | 45 | 67 | 208 | |||||||||||||||
|
2008
|
||||||||||||||||||||
|
Operating
revenues
|
$ | 163 | $ | 125 | $ | 123 | $ | 129 | $ | 540 | ||||||||||
|
Operating
income
|
101 | 61 | 54 | 55 | 271 | |||||||||||||||
|
Net
income
|
95 | 53 | 44 | 43 | 235 | |||||||||||||||
SCHEDULE
II
SOUTHERN
NATURAL GAS COMPANY
VALUATION
AND QUALIFYING ACCOUNTS
Years
Ended December 31, 2009, 2008 and 2007
(In
millions)
|
Description
|
Balance
at
Beginning
of Period
|
Charged
to
Costs
and
Expenses
|
Deductions
|
Charged
to
Other
Accounts
|
Balance
at End
of Period
|
|||||||||||||||
|
2009
|
||||||||||||||||||||
|
Legal
reserves
|
$ | 2 | $ | — | $ | — | $ | — | $ | 2 | ||||||||||
|
Environmental
reserves
|
1 | — | — | — | 1 | |||||||||||||||
|
2008
|
||||||||||||||||||||
|
Legal
reserves
|
$ | 2 | $ | — | $ | — | $ | — | $ | 2 | ||||||||||
|
Environmental
reserves
|
1 | — | — | — | 1 | |||||||||||||||
|
2007(1)
|
||||||||||||||||||||
|
Valuation
allowance on deferred tax assets
|
$ | 1 | $ | — | $ | — | $ | (1 | ) | $ | — | |||||||||
|
Legal
reserves
|
2 | — | — | — | 2 | |||||||||||||||
|
Environmental
reserves
|
1 | — | — | — | 1 | |||||||||||||||
____________
|
(1)
|
Amounts
reflect the reclassification of certain entities as discontinued
operations.
|
None.
Evaluation
of Disclosure Controls and Procedures
As of December 31,
2009, we carried out an evaluation under the supervision and with the
participation of our management, including our President and Chief Financial
Officer, as to the effectiveness, design and operation of our disclosure
controls and procedures. This evaluation considered the various processes
carried out under the direction of our disclosure committee in an effort to
ensure that information required to be disclosed in the SEC reports we file or
submit under the Exchange Act is accurate, complete and timely. Our management,
including our President and Chief Financial Officer, does not expect that our
disclosure controls and procedures or our internal controls will prevent and/or
detect all errors and all fraud. A control system, no matter how well conceived
and operated, can provide only reasonable, not absolute, assurance that the
objectives of the control system are met. Further, the design of a control
system must reflect the fact that there are resource constraints, and the
benefits of controls must be considered relative to their costs. Because of the
inherent limitations in all control systems, no evaluation of controls can
provide absolute assurance that all control issues and instances of fraud, if
any, within a company have been detected. Our disclosure controls and procedures
are designed to provide reasonable assurance of achieving their objective and
our President and Chief Financial Officer concluded that our disclosure controls
and procedures (as defined in the Exchange Act Rules 13a-15(e) and 15d-15 (e))
were effective as of December 31, 2009. See Item 8, Financial Statements
and Supplementary Data under Management’s Annual Report on Internal Control Over
Financial Reporting.
Changes
in Internal Control Over Financial Reporting
There were no
changes in our internal control over financial reporting during the fourth
quarter of 2009 that have materially affected or are reasonably likely to
materially affect our internal control over financial reporting.
This annual report
does not include an attestation report of our independent registered public
accounting firm regarding internal control over financial reporting.
Management’s report was not subject to attestation by our independent registered
public accounting firm pursuant to temporary rules of the Securities and
Exchange Commission that permit us to provide only management’s report in this
annual report. See Item 8, Financial Statements and Supplementary Data, under
Management’s Annual Report on Internal Control Over Financial
Reporting.
None.
Management
Committee and Executive Officers
We are a Delaware
general partnership with two partners, the first of which is a wholly owned
subsidiary of El Paso (the “El Paso Partner”), and the second of which is a
wholly owned subsidiary of EPB (the “EPB Partner”). The El Paso Partner owns a
75 percent interest in our partnership, and the EPB Partner owns our remaining
25 percent interest. A general partnership agreement governs our ownership and
management. Although our management is vested in our partners, the partners have
agreed to delegate our management to a management committee. Decisions of or
actions taken by the management committee are binding on us. The management
committee is composed of four representatives, with three representatives being
designated by the El Paso Partner and one representative being designated by the
EPB Partner. Each member of the management committee has full authority to act
on behalf of the partner that designated such member with respect to matters
pertaining to us. Each member of the management committee is entitled to one
vote on each matter submitted for a vote of the management committee, and the
vote of a majority of the members of the management committee constitutes action
of the management committee, except for certain actions specified in the general
partnership agreement that require unanimous approval of the management
committee. Our officers are appointed by the management committee.
The following
provides biographical information for each of our executive officers and
management committee members as of February 26, 2010.
There are no family
relationships among any of our executive officers or management committee
members, and, unless described herein, no arrangement or understanding exists
between any executive officer and any other person pursuant to which he was or
is to be selected as an officer.
|
Name
|
Age
|
Position
|
|
James C.
Yardley
|
58
|
President and
Management Committee Member
|
|
John R.
Sult
|
50
|
Senior Vice
President and Chief Financial Officer
|
|
Daniel B.
Martin
|
53
|
Senior Vice
President and Management Committee Member
|
|
Norman G.
Holmes
|
53
|
Senior Vice
President, Chief Commercial Officer and Management Committee
Member
|
|
Michael J.
Varagona
|
54
|
Vice
President, Business Development and Management Committee
Member
|
James C. Yardley. Mr. Yardley
has been a member of the Management Committee of Southern Natural Gas Company
since November 2007 and President since May 1998. Mr. Yardley previously
served as Chairman of the Board of Southern Natural Gas Company from May 2005 to
November 2007 and a director from November 2001 to November 2007. He has been
Executive Vice President of our parent El Paso with responsibility for the
regulated pipeline business unit since August 2006. Mr. Yardley is currently a
member of the board of directors of Scorpion Offshore Ltd. He also serves on the
Board of Interstate Natural Gas Association of America and previously served as
its chairman. Mr. Yardley also serves as Director, President and Chief
Executive Officer of El Paso Pipeline GP Company, L.L.C., the
general partner of El Paso Pipeline Partners, L.P.
John R. Sult. Mr. Sult has
been Senior Vice President and Chief Financial Officer of Southern Natural Gas
Company since November 2009. Mr. Sult previously served as Senior Vice
President, Chief Financial Officer and Controller from November 2005 to November
2009. Mr. Sult also serves as Senior Vice President and Chief Financial Officer
of our parent El Paso and as Senior Vice President and Chief Financial Officer
of our affiliates El Paso Natural Gas Company, Colorado Interstate Gas Company,
and Tennessee Gas Pipeline Company. Mr. Sult previously served as Senior Vice
President and Controller of El Paso from November 2005 to November
2009. Mr. Sult held the position of Vice President and
Controller at Halliburton Energy Services Company from August 2004 until joining
El Paso in October 2005. Mr. Sult also serves as Director, Senior
Vice President and Chief Financial Officer of El Paso Pipeline GP Company,
L.L.C., the general partner of El Paso Pipeline Partners, L.P.
Daniel
B. Martin. Mr. Martin has been a member of the Management Committee
of Southern Natural Gas Company since November 2007 and Senior Vice President
since June 2000. He previously served as a director of Southern Natural Gas
Company from May 2005 to November 2007. Mr. Martin has been a director of our
affiliates El Paso Natural Gas Company and Tennessee Gas Pipeline Company since
May 2005. Mr. Martin has been Senior Vice President of Tennessee Gas Pipeline
Company since June 2000 and Senior Vice President of El Paso Natural Gas Company
since February 2000. He served as a director of ANR Pipeline Company from May
2005 through February 2007 and Senior Vice President of ANR Pipeline Company
from January 2001 to February 2007. Mr. Martin also serves as Senior Vice
President of El Paso Pipeline GP Company, L.L.C., the general partner of El Paso
Pipeline Partners, L.P.
Norman
G. Holmes. Mr. Holmes has been a member of the Management Committee of
Southern Natural Gas Company since November 2007 and Senior Vice President and
Chief Commercial Officer since August 2006. He previously served as a director
of Southern Natural Gas Company from November 2005 to November 2007. Mr.
Holmes served as Vice President, Business Development of Southern Natural Gas
Company from 1999 to 2006 and as Vice President and Controller from 1995 to
1999. Mr. Holmes also serves as Senior Vice President of El Paso Pipeline GP
Company, L.L.C., the general partner of El Paso Pipeline Partners,
L.P.
Michael
J. Varagona. Mr. Varagona has been a member of the Management Committee
of Southern Natural Gas Company since November 2007 and Vice President of
Business Development since January 2007. Mr. Varagona served as Director,
Business Development from January 2004 to December 2006.
Audit
Committee, Compensation Committee and Code of Ethics
As a majority owned
subsidiary of El Paso, we rely on El Paso for certain support services. As a
result, we do not have a separate corporate audit committee or audit committee
financial expert, or a separate compensation committee. Also, we have not
adopted a separate code of ethics. However, our executives are subject to El
Paso’s code of ethics, referred to as the “Code of Business Conduct”. The Code
of Business Conduct is a value-based code that is built on five core values:
stewardship, integrity, safety, accountability and excellence. In addition to
other matters, the Code of Business Conduct establishes policies to deter
wrongdoing and to promote honest and ethical conduct, including ethical handling
of actual or apparent conflicts of interest, compliance with applicable laws,
rules and regulations, full, fair, accurate, timely and understandable
disclosure in public communications and prompt internal reporting of violations
of the Code of Business Conduct. A copy of the Code of Business Conduct is
available for your review at El Paso’s website, www.elpaso.com.
All of our
executive officers are officers or employees of El Paso or one of its non-SNG
subsidiaries and devote a substantial portion of their time to El Paso or such
other subsidiaries. None of these executive officers receives any compensation
from SNG or its subsidiaries. The compensation of our executive officers is set
by El Paso, and we have no control over the compensation determination process.
Our executive officers and former employees participate in employee benefit
plans and arrangements sponsored by El Paso. We have not established separate
employee benefit plans and we have not entered into employment agreements with
any of our executive officers.
The members of our
management committee are also officers or employees of El Paso or one of its
non-SNG subsidiaries and do not receive additional compensation for their
service as a member of our management committee.
SNG is a Delaware
general partnership. SNG is owned 75 percent indirectly through a wholly-owned
subsidiary of El Paso, and is owned 25 percent by EPPP SNG GP Holdings, L.L.C.,
a subsidiary of EPB. The address of each of El Paso and EPB is 1001 Louisiana
Street, Houston, Texas 77002.
The following table
sets forth, as of February 12, 2010, the number of shares of common stock of El
Paso owned by each of our executive officers and management committee members
and all of our management committee members and executive officers as a
group.
|
Name of Beneficial Owner
|
Shares
of
Common
Stock
Owned
Directly
or
Indirectly
|
Shares
Underlying
Options
Exercisable
Within
60 Days(1)
|
Total
Shares
of
Common
Stock
Beneficially
Owned
|
Percentage
of
Total
Shares
of
Common
Stock
Beneficially
Owned(2)
|
|||||||||||
|
James C.
Yardley
|
274,233 | 477,421 | 751,654 | * | |||||||||||
|
John R.
Sult
|
85,588 | 149,985 | 235,573 | * | |||||||||||
|
Daniel B.
Martin
|
151,068 | 242,662 | 393,730 | * | |||||||||||
|
Norman G.
Holmes
|
57,989 | 164,512 | 222,501 | * | |||||||||||
|
Michael J.
Varagona
|
38,076 | 66,874 | 104,950 | * | |||||||||||
|
All
management committee members and executive officers as a group (5
persons)
|
606,954 | 1,101,454 | 1,708,408 | * | |||||||||||
____________
* Less
than 1%.
|
(1)
|
The shares
indicated represent stock options granted under El Paso’s current or
previous stock option plans, which are currently exercisable or which will
become exercisable within 60 days of February 12, 2010. Shares subject to
options cannot be voted.
|
|
(2)
|
Based on
701,314,549 shares outstanding as of February 12,
2010.
|
We are a general
partnership presently owned 75 percent indirectly through a wholly owned
subsidiary of El Paso and 25 percent through a wholly owned subsidiary of
EPB.
SNG
Guarantee of Elba Island Expansion
We formerly owned
Southern LNG Inc. (SLNG), which owns and operates a LNG receiving and
regasification terminal on Elba Island near Savannah, Georgia. SLNG is now a
subsidiary of El Paso. In connection with an ongoing expansion of the Elba
Island LNG terminal (Elba III), we have guaranteed necessary funds (up to a
defined limit) to permit the construction of the Elba III
expansion.
SNG
Guarantee of Elba Express Expansion
SNG formerly owned
Elba Express Pipeline Company, LLC (EEC), which is in the process of
constructing a 191-mile pipeline primarily in Georgia that is expected to be
placed into service in March 2010. EEC is now a subsidiary of El Paso. We have
agreed to provide, at our election, either all necessary funds to Elba Express
(up to a defined limit) or a guarantee in the form of a performance bond (up to
a defined limit) to permit the construction of the Elba Express
pipeline.
El
Paso Guarantee of SNG Lease
El Paso has
guaranteed our obligations with respect to our leased headquarters.
Other
Agreements and Transactions
In addition, we
currently have and will have in the future other routine agreements with El Paso
or one of its subsidiaries that arise in the ordinary course of business,
including agreements for services and other transportation and exchange
agreements and interconnection and balancing agreements with other El Paso
pipelines.
For a description
of certain additional affiliate transactions, see Part II, Item 8, Financial
Statements and Supplementary Data, Note 11.
Audit
Fees
The audit fees for
the years ended December 31, 2009 and 2008 of $792,000 and $751,000,
respectively, were primarily for professional services rendered by Ernst &
Young LLP for the audits of the consolidated financial statements of Southern
Natural Gas Company and its subsidiaries as well
as the review of documents filed with the SEC and related
consent.
All
Other Fees
No other
audit-related, tax or other services were provided by our independent registered
public accounting firm for the years ended December 31, 2009 and
2008.
Policy
for Approval of Audit and Non-Audit Fees
We are
substantially owned by El Paso and its subsidiaries and do not have a separate
audit committee. El Paso’s Audit Committee has adopted a pre-approval policy for
audit and non-audit services. For a description of El Paso’s pre-approval
policies for audit and non-audit related services, see El Paso Corporation’s
proxy statement for its 2010 Annual Meeting of Stockholders.
(a) The following
consolidated financial statements are included in Part II, Item 8 of this
report:
1. Financial
statements
|
|
Page
|
|
Southern
Natural Gas Company
|
|
|
Report of
Independent Registered Public Accounting Firm
|
26
|
|
Consolidated
Statements of Income and Comprehensive Income
|
27
|
|
Consolidated
Balance Sheets
|
28
|
|
Consolidated
Statements of Cash Flows
|
29
|
|
Consolidated
Statements of Partners’ Capital/Stockholder’s Equity
|
30
|
|
Notes to
Consolidated Financial Statements
|
31
|
|
2. Financial
statement schedules
|
|
|
Schedule
II — Valuation and Qualifying Accounts
|
46
|
|
All other
schedules are omitted because they are not applicable, or the required
information is disclosed in the financial statements or accompanying
notes.
|
|
|
3. and (b).
Exhibits
|
|
|
The Exhibit
Index, which follows the signature page to this report and is hereby
incorporated herein by reference, sets forth a list of those exhibits
filed herewith, and includes and identifies contracts or arrangements
required to be filed as exhibits to this Form 10-K by Item 601(b)(10)(iii)
of Regulation S-K.
|
|
|
The
agreements included as exhibits to this report are intended to provide
information regarding their terms and not to provide any other factual or
disclosure information about us or the other parties to the agreements.
The agreements may contain representations and warranties by the parties
to the agreements, including us, solely for the benefit of the other
parties to the applicable agreement and:
• should not in
all instances be treated as categorical statements of fact, but rather as
a way of allocating the risk to one of the parties if those statements
prove to be inaccurate;
• may have been
qualified by disclosures that were made to the other party in connection
with the negotiation of the applicable agreement, which disclosures are
not necessarily reflected in the agreement;
• may apply
standards of materiality in a way that is different from what may be
viewed as material to certain investors; and
• were made
only as of the date of the applicable agreement or such other date or
dates as may be specified in the agreement and are subject to more recent
developments.
Accordingly,
these representations and warranties may not describe the actual state of
affairs as of the date they were made or at any other time.
Undertaking
We hereby
undertake, pursuant to Regulation S-K, Item 601(b), paragraph (4)(iii), to
furnish to the U.S. SEC upon request all constituent instruments defining
the rights of holders of our long-term debt and our consolidated
subsidiaries not filed as an exhibit hereto for the reason that the total
amount of securities authorized under any of such instruments does not
exceed 10 percent of our total consolidated assets.
|
|
(c) Financial
Statements of 50-Percent-Or-Less-Owned Investees:
|
|
|
Citrus
Corp.
|
|
|
Report of
Independent Registered Public Accounting Firm
|
54
|
|
Consolidated
Balance Sheets
|
55
|
|
Consolidated
Statements of Income
|
56
|
|
Consolidated
Statements of Stockholders’ Equity
|
57
|
|
Consolidated
Statements of Comprehensive Income
|
57
|
|
Consolidated
Statements of Cash Flows
|
58
|
|
Notes to
Consolidated Financial Statements
|
59
|
Report
of Independent Registered Public Accounting Firm
To the Board of
Directors and Stockholders of Citrus Corp.:
In our opinion, the
accompanying consolidated balance sheets and the related consolidated statements
of income, of stockholders’ equity, of comprehensive income and of cash flows
present fairly, in all material respects, the financial position of Citrus Corp.
and subsidiaries (the “Company”) at December 31, 2007 and 2006, and the results
of their operations and their cash flows for each of the three years in the
period ended December 31, 2007 in conformity with the accounting principles
generally accepted in the United States of America. These consolidated financial
statements are the responsibility of the Company’s management. Our
responsibility is to express an opinion on these financial statements based on
our audits. We conducted our audits of these statements in accordance with the
standards of the Public Company Accounting Oversight Board (United States).
Those standards require that we plan and perform the audit to obtain reasonable
assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements, assessing the
accounting principles used and significant estimates made by management, and
evaluating the overall financial statement presentation. We believe that our
audits provide a reasonable basis for our opinion.
As discussed in
Notes 2 and 6 to the consolidated financial statements, the Company adopted the
recognition and disclosure provisions of FASB Statement No. 158 “Employers’
Accounting for Defined Pension and Other Postretirement Plans — an amendment of
FASB Statements No. 87, 88, 106 and 132(R),” as of December 31,
2006.
/s/
PricewaterhouseCoopers LLP
Houston,
Texas
February 25,
2008
CITRUS
CORP. AND SUBSIDIARIES
CONSOLIDATED
BALANCE SHEETS
|
|
December
31,
2007
|
December
31,
2006
|
||||||
|
(In
thousands)
|
||||||||
|
ASSETS
|
||||||||
|
Current
Assets
|
||||||||
|
Cash and cash
equivalents
|
$ | 3,572 | $ | 15,267 | ||||
|
Accounts
receivable, billed and unbilled, less allowances of $18 and $282,
respectively
|
39,350 | 45,049 | ||||||
|
Materials and
supplies
|
12,745 | 2,954 | ||||||
|
Exchange gas
receivable
|
1,729 | — | ||||||
|
Other
|
2,248 | 1,025 | ||||||
|
Total Current
Assets
|
59,644 | 64,295 | ||||||
|
Property,
Plant and Equipment
|
||||||||
|
Plant in
service
|
4,265,844 | 4,163,082 | ||||||
|
Construction
work in progress
|
150,742 | 85,746 | ||||||
| 4,416,586 | 4,248,828 | |||||||
|
Less
accumulated depreciation and amortization
|
1,401,638 | 1,304,133 | ||||||
|
Property,
Plant and Equipment, Net
|
3,014,948 | 2,944,695 | ||||||
|
Other
Assets
|
||||||||
|
Unamortized
debt expense
|
4,221 | 4,687 | ||||||
|
Regulatory
assets
|
19,207 | 31,007 | ||||||
|
Other
|
10,838 | 76,429 | ||||||
|
Total Other
Assets
|
34,266 | 112,123 | ||||||
|
Total
Assets
|
$ | 3,108,858 | $ | 3,121,113 | ||||
|
LIABILITIES
AND STOCKHOLDERS’ EQUITY
|
||||||||
|
Current
Liabilities
|
||||||||
|
Current
portion of long-term debt
|
$ | 44,000 | $ | 84,000 | ||||
|
Accounts
payable — trade and other
|
33,422 | 25,070 | ||||||
|
Accounts
payable — affiliated companies
|
8,416 | 2,823 | ||||||
|
Accrued
interest
|
14,251 | 14,805 | ||||||
|
Accrued
income taxes
|
7,599 | 2,375 | ||||||
|
Accrued
taxes, other than income
|
5,437 | 9,332 | ||||||
|
Exchange gas
payable
|
22,547 | 24,225 | ||||||
|
Capital
accruals
|
22,636 | 22,185 | ||||||
|
Dividends
payable
|
42,600 | — | ||||||
|
Other
|
7,600 | 6,526 | ||||||
|
Total Current
Liabilities
|
208,508 | 191,341 | ||||||
|
Deferred
Credits
|
||||||||
|
Deferred
income taxes, net
|
763,364 | 777,404 | ||||||
|
Regulatory
liabilities
|
14,842 | 14,256 | ||||||
|
Other
|
9,202 | 8,129 | ||||||
|
Total
Deferred Credits
|
787,408 | 799,789 | ||||||
|
Long-Term
Debt
|
909,810 | 836,882 | ||||||
|
Commitments
and contingencies (Note 14)
|
||||||||
|
Stockholders’
Equity
|
||||||||
|
Common stock,
$1 par value; 1,000 shares authorized, issued and
outstanding
|
1 | 1 | ||||||
|
Additional
paid-in capital
|
634,271 | 634,271 | ||||||
|
Accumulated
other comprehensive loss
|
(7,885 | ) | (10,524 | ) | ||||
|
Retained
earnings
|
576,745 | 669,353 | ||||||
|
Total
Stockholders’ Equity
|
1,203,132 | 1,293,101 | ||||||
|
Total
Liabilities and Stockholders’ Equity
|
$ | 3,108,858 | $ | 3,121,113 | ||||
The accompanying
notes are an integral part of these consolidated financial
statements.
55
CITRUS
CORP. AND SUBSIDIARIES
CONSOLIDATED
STATEMENTS OF INCOME
|
|
Year
Ended
December
31,
2007
|
Year
Ended
December
31,
2006
|
Year
Ended
December
31,
2005
|
|||||||||
|
(In
thousands)
|
||||||||||||
|
Operating
Revenues
|
||||||||||||
|
Transportation
of natural gas
|
$ | 495,513 | $ | 485,189 | $ | 476,049 | ||||||
|
Total
Operating Revenues
|
495,513 | 485,189 | 476,049 | |||||||||
|
Operating
Expenses
|
||||||||||||
|
Operations
and maintenance
|
82,058 | 77,941 | 78,829 | |||||||||
|
Depreciation
and amortization
|
100,634 | 98,653 | 91,125 | |||||||||
|
Taxes, other
than income taxes
|
29,618 | 34,765 | 34,306 | |||||||||
|
Total
Operating Expenses
|
212,310 | 211,359 | 204,260 | |||||||||
|
Operating
Income
|
283,203 | 273,830 | 271,789 | |||||||||
|
Other
Income (Expenses)
|
||||||||||||
|
Interest
expense and related charges, net
|
(73,871 | ) | (76,428 | ) | (79,290 | ) | ||||||
|
Other,
net
|
39,984 | 4,633 | 6,531 | |||||||||
|
Total Other
Income (Expenses), net
|
(33,887 | ) | (71,795 | ) | (72,759 | ) | ||||||
|
Income
Before Income Taxes
|
249,316 | 202,035 | 199,030 | |||||||||
|
Federal and
State Income Tax Expense
|
92,224 | 75,960 | 75,086 | |||||||||
|
Net
Income
|
$ | 157,092 | $ | 126,075 | $ | 123,944 | ||||||
The accompanying
notes are an integral part of these consolidated financial
statements.
56
CITRUS
CORP. AND SUBSIDIARIES
CONSOLIDATED
STATEMENTS OF STOCKHOLDERS’ EQUITY
|
|
Year
Ended
December
31,
2007
|
Year
Ended
December
31,
2006
|
Year
Ended
December
31,
2005
|
|||||||||
|
(In
thousands)
|
||||||||||||
|
Common
Stock
|
||||||||||||
|
Balance,
beginning and end of period
|
$ | 1 | $ | 1 | $ | 1 | ||||||
|
Additional
Paid-in Capital
|
||||||||||||
|
Balance,
beginning and end of period
|
634,271 | 634,271 | 634,271 | |||||||||
|
Accumulated
Other Comprehensive Loss
|
||||||||||||
|
Balance,
beginning of period
|
(10,524 | ) | (13,162 | ) | (15,800 | ) | ||||||
|
Recognition
in earnings of previously deferred net losses related to derivative
instruments used as cash flow hedges
|
2,639 | 2,638 | 2,638 | |||||||||
|
Balance, end
of period
|
(7,885 | ) | (10,524 | ) | (13,162 | ) | ||||||
|
Retained
Earnings
|
||||||||||||
|
Balance,
beginning of period
|
669,353 | 668,678 | 665,934 | |||||||||
|
Net
income
|
157,092 | 126,075 | 123,944 | |||||||||
|
Dividends
(1)
|
(249,700 | ) | (125,400 | ) | (121,200 | ) | ||||||
|
Balance, end
of period
|
576,745 | 669,353 | 668,678 | |||||||||
|
Total
Stockholders’ Equity
|
$ | 1,203,132 | $ | 1,293,101 | $ | 1,289,788 | ||||||
CONSOLIDATED
STATEMENTS OF COMPREHENSIVE INCOME
|
|
Year
Ended
December
31,
2007
|
Year
Ended
December
31,
2006
|
Year
Ended
December
31,
2005
|
|||||||||
|
(In
thousands)
|
||||||||||||
|
Net
income
|
$ | 157,092 | $ | 126,075 | $ | 123,944 | ||||||
|
Recognition
in earnings of previously deferred net losses related to derivative
instruments used as cash flow hedges
|
2,639 | 2,638 | 2,638 | |||||||||
|
Total
Comprehensive Income
|
$ | 159,731 | $ | 128,713 | $ | 126,582 | ||||||
____________
|
(1)
|
Includes
$42.6 million in Dividends Payable, declared in December 2007, payable in
January, 2008 and which was paid on January 18, 2008. (See Note 7 —
Related Party Transaction)
|
The accompanying
notes are an integral part of these consolidated financial
statements.
57
CITRUS
CORP. AND SUBSIDIARIES
CONSOLIDATED
STATEMENTS OF CASH FLOWS
|
|
Year
Ended
December
31,
2007
|
Year
Ended
December
31,
2006
|
Year
Ended
December
31,
2005
|
|||||||||
|
(In
thousands)
|
||||||||||||
|
Cash
flows provided by operating activities
|
||||||||||||
|
Net
income
|
$ | 157,092 | $ | 126,075 | $ | 123,944 | ||||||
|
Adjustments
to reconcile net income to net cash provided by operating
activities:
|
||||||||||||
|
Depreciation
and amortization
|
100,634 | 98,653 | 91,125 | |||||||||
|
Amortization
of hedge loss in other comprehensive income
|
2,639 | 2,638 | 2,638 | |||||||||
|
Amortization
of discount and swap hedge loss in long term debt
|
528 | 527 | 530 | |||||||||
|
Amortization
of regulatory assets and other deferred charges
|
1,250 | 3,274 | 3,380 | |||||||||
|
Amortization
of debt costs
|
994 | 1,048 | 1,053 | |||||||||
|
Deferred
income taxes
|
(12,277 | ) | 18,629 | 12,740 | ||||||||
|
Allowance for
funds used during construction
|
(4,683 | ) | (1,630 | ) | (1,441 | ) | ||||||
|
Gain on sale
of assets
|
— | — | (1,236 | ) | ||||||||
|
Changes in
operating assets and liabilities:
|
||||||||||||
|
Accounts
receivable
|
5,699 | (3,327 | ) | 403 | ||||||||
|
Accounts
payable
|
11,950 | (3,316 | ) | (10,567 | ) | |||||||
|
Accrued
interest
|
(554 | ) | (286 | ) | (324 | ) | ||||||
|
Accrued
income tax
|
5,224 | 3,247 | (7,204 | ) | ||||||||
|
Other current
assets and liabilities
|
(8,944 | ) | 18,749 | 3,234 | ||||||||
|
Other
long-term assets and liabilities
|
74,668 | (24,627 | ) | 36,140 | ||||||||
|
Net
cash provided by operating activities
|
334,220 | 239,654 | 254,415 | |||||||||
|
Cash
flows used in investing activities
|
||||||||||||
|
Capital
expenditures
|
(175,370 | ) | (106,023 | ) | (37,610 | ) | ||||||
|
Allowance for
funds used during construction
|
4,683 | 1,630 | 1,441 | |||||||||
|
Proceeds from
sale of assets
|
— | — | 1,715 | |||||||||
|
Net
cash used in investing activities
|
(170,687 | ) | (104,393 | ) | (34,454 | ) | ||||||
|
Cash
flows used in financing activities
|
||||||||||||
|
Dividends
paid
|
(207,100 | ) | (125,400 | ) | (121,200 | ) | ||||||
|
Net
(payments) borrowings on the revolving credit facilities
|
76,400 | (2,000 | ) | (75,000 | ) | |||||||
|
Long-term
debt finance costs
|
(528 | ) | — | — | ||||||||
|
Payments on
long-term debt
|
(44,000 | ) | (14,000 | ) | (14,000 | ) | ||||||
|
Net
cash used in financing activities
|
(175,228 | ) | (141,400 | ) | (210,200 | ) | ||||||
|
Net
increase (decrease) in cash and cash equivalents
|
(11,695 | ) | (6,139 | ) | 9,761 | |||||||
|
Cash
and cash equivalents, beginning of period
|
15,267 | 21,406 | 11,645 | |||||||||
|
Cash
and cash equivalents, end of period
|
$ | 3,572 | $ | 15,267 | $ | 21,406 | ||||||
|
Supplemental
disclosure of cash flow information
|
||||||||||||
|
Interest paid
(net of amounts capitalized)
|
$ | 72,439 | $ | 72,067 | $ | 74,714 | ||||||
|
Income tax
paid
|
$ | 103,589 | $ | 56,814 | $ | 66,954 | ||||||
The accompanying
notes are an integral part of these consolidated financial
statements.
58
CITRUS
CORP. AND SUBSIDIARIES
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
|
(1)
|
Corporate
Structure
|
Citrus Corp.
(Citrus, the Company), a holding company formed in 1986, owns 100 percent of the
membership interest in Florida Gas Transmission Company, LLC (Florida Gas), and
100 percent of the stock of Citrus Trading Corp. (Trading) and Citrus Energy
Services, Inc. (CESI), collectively the Company. At December 31, 2007, the
stock of Citrus was owned 50 percent by El Paso Citrus Holdings, Inc. (EPCH), a
wholly-owned subsidiary of El Paso Corporation (El Paso), and 50 percent by
CrossCountry Citrus, LLC (CCC), a wholly-owned subsidiary of CrossCountry
Energy, LLC (CrossCountry). In November 2007, Southern Natural Gas Company
(Southern), whose parent is El Paso, distributed EPCH to El Paso. CrossCountry
was a wholly-owned subsidiary of Enron
Corp. (Enron) and certain of its subsidiary companies. Effective November 17,
2004, CrossCountry became a wholly-owned subsidiary of CCE Holdings, LLC (CCE
Holdings), which was a joint venture owned by subsidiaries of Southern Union
Company (Southern Union) (50 percent), GE Commercial Finance Energy Financial
Services (GE) (approximately 30 percent) and four minority interest owners
(approximately 20 percent in the aggregate).
On December 1,
2006, a series of transactions were completed which resulted in Southern Union
increasing its indirect ownership interest in Citrus from 25 percent to 50
percent. On September 14, 2006, Energy Transfer Partners, L.P. (Energy
Transfer), an unaffiliated company, entered into a definitive purchase agreement
to acquire the 50 percent interest in CCE Holdings from GE and other investors.
At the same time, Energy Transfer and CCE Holdings entered into a definitive
redemption agreement, pursuant to which Energy Transfer’s 50 percent ownership
interest in CCE Holdings would be redeemed in exchange for 100 percent of the
equity interest in Transwestern Pipeline Company, LLC (TW) (Redemption
Agreement). Upon closing of the Redemption Agreement on December 1, 2006,
Southern Union became the indirect owner of 100 percent of CCE Holdings, whose
principal remaining asset was its 50 percent interest in Citrus, with the
remaining 50 percent of Citrus continuing to be owned by EPCH.
Florida Gas, an
interstate natural gas pipeline extending from South Texas to South Florida, is
engaged in the interstate transmission of natural gas and is subject to the
jurisdiction of the Federal Energy Regulatory Commission (FERC).
On September 1,
2006, Florida Gas converted its legal entity type from a corporation to a
limited liability company, pursuant to the Delaware Limited Liability Company
Act.
|
(2)
|
Significant
Accounting Policies
|
Basis
of Presentation — The Company’s consolidated financial statements have
been prepared in accordance with accounting principles generally accepted in the
United States of America (GAAP).
Regulatory
Accounting —
Florida Gas’ accounting policies generally conform to Financial
Accounting Standards Board (FASB)
Statement No. 71, Accounting
for the Effects of Certain Types of Regulation
(Statement No. 71). Accordingly, certain assets and liabilities that
result from the regulated ratemaking process are recorded that would not be
recorded under GAAP for non-regulated entities.
Revenue
Recognition — Revenues consist primarily of fees earned from gas
transportation services. Reservation revenues are based on contracted rates and
capacity reserved by the customers and are recognized monthly. For interruptible
or volumetric based services, commodity revenues are recorded upon the delivery
of natural gas to the agreed upon delivery point. Revenues for all services are
generally based on the thermal quantity of gas delivered or subscribed at a rate
specified in the contract.
Because Florida Gas is subject to
FERC regulations, revenues collected during the pendency of a rate proceeding
may be required by the FERC to be refunded in the final order. Florida Gas
establishes reserves for such potential refunds, as appropriate. There
were no reserves for potential rate refund at December 31, 2007 and 2006,
respectively.
Derivative
Instruments — The Company follows FASB Statement No. 133, Accounting for Derivative
Instruments and Hedging Activities, as amended, (Statement No. 133) to
account for derivative and hedging activities. In accordance with this
statement, all derivatives are recognized on the Consolidated Balance Sheets at
their fair value. On the date the derivative contract is entered into, the
Company designates the derivative as (i) a hedge of the fair value of a
recognized asset or liability or of an unrecognized firm commitment (a fair value hedge); (ii) a hedge of
a forecasted transaction or the variability of cash flows to be received or paid
in conjunction with a recognized asset or liability (a cash flow hedge); or (iii)
an instrument that is held for trading or non-hedging purposes (a trading or non-hedging
instrument). For derivatives treated as a fair value hedge, the effective
portion of changes in fair value is recorded as an adjustment to the hedged
item. The ineffective portion of a fair value hedge is recognized in earnings if
the short cut method of assessing effectiveness is not used. Upon termination of
a fair value hedge of a debt instrument, the resulting gain or loss is amortized
to earnings through the maturity date of the debt instrument. For derivatives
treated as a cash flow hedge, the effective portion of changes in fair value is
recorded in Accumulated Other
Comprehensive Loss until the related hedge items impact earnings. Any
ineffective portion of a cash flow hedge is reported in current period earnings.
For derivatives treated as trading or non-hedging instruments, changes in fair
value are reported in current-period earnings. Fair value is determined based
upon quoted market prices and mathematical models using current and historical
data. As of December 31, 2007, the Company does not have any hedges in place as
it is only amortizing previously terminated hedges.
Property,
Plant and Equipment — Property, Plant and Equipment consists primarily of
natural gas pipeline and related facilities and is recorded at its original
cost. Florida Gas capitalizes direct costs, such as labor and materials, and
indirect costs, such as overhead and cost of funds, both interest and an equity
return component (see third following paragraph). Costs of replacements and
renewals of units of property are capitalized. The original cost of units of
property retired are charged to accumulated depreciation, net of salvage and
removal costs. Florida Gas charges to maintenance expense the costs of repairs
and renewal of items determined to be less than units of property.
The Company
amortized that portion of its investment in Florida Gas property which is in
excess of historical cost (acquisition adjustment) on a straight-line basis at
an annual composite rate of 1.6 percent based upon the estimated remaining
useful life of the pipeline system.
Florida Gas has
provided for depreciation of assets, on a straight-line basis, at an annual
composite rate of 2.77 percent, 2.78 percent and 2.56 percent for the years
ended December 31, 2007, 2006 and 2005, respectively.
The recognition of
an allowance for funds used during construction (AFUDC) is a utility accounting
practice with calculations under guidelines prescribed by the FERC and
capitalized as part of the cost of utility plant. It represents the cost of
capital invested in construction work-in-progress. AFUDC has been segregated
into two component parts — borrowed funds and equity funds. The allowance for
borrowed and equity funds used during construction, including related gross up,
totaled $10.3 million, $3.4 million and $1.4 million for the years ended
December 31, 2007, 2006 and 2005, respectively. AFUDC borrowed is included in
Interest Expense and AFUDC equity is included in Other Income in the
accompanying statements of income.
Asset
Retirement Obligations — The Company applies the provisions of FASB Statement No. 143, Accounting
for Asset Retirement Obligations to record a liability for the estimated
removal costs of assets where there is a legal obligation associated with
removal. Under this standard, the liability is recorded at its fair value, with
a corresponding asset that is depreciated over the remaining useful life of the
long-lived asset to which the liability relates. An ongoing expense will also be
recognized for changes in the value of the liability as a result of the passage
of time.
FASB Interpretation No. 47,
Accounting for Conditional Asset Retirement Obligations (FIN No. 47)
issued by the FASB in March 2005 clarifies that the term “conditional
asset retirement obligation” as used in FASB Statement No. 143, Accounting for Asset Retirement
Obligations, refers to a legal obligation to perform an asset retirement
activity in which the timing and/or method of settlement are conditional on a
future event that may or may not be within the control of the entity.
Accordingly, an entity is required to recognize a liability for the fair value
of a conditional asset retirement obligation (ARO) when incurred, if the fair
value of the liability can be reasonably estimated. FIN No. 47 provides guidance
for assessing whether sufficient information is available to record an estimate.
This interpretation was effective for the Company beginning on December 31,
2005. Upon adoption of FIN No. 47, Florida Gas recorded an increase in plant in
service and a liability for an ARO of $0.5 million. This new asset and liability
related to obligations associated with the removal and disposal of asbestos and
asbestos containing materials on Florida Gas’ pipeline system. The ARO asset at
December 31, 2007 had a net book value of $0.5 million.
The table below
provides a reconciliation of the carrying amount of the ARO liability for the
period indicated:
|
|
Year Ended
December
31, 2007
|
Year Ended
December
31, 2006
|
Year Ended
December
31, 2005
|
|||||||||
|
(In
thousands)
|
||||||||||||
|
Beginning
balance
|
$ | 481 | $ | 493 | $ | — | ||||||
|
Incurred
|
— | — | 493 | |||||||||
|
Settled
|
(37 | ) | (36 | ) | — | |||||||
|
Accretion
Expense
|
27 | 24 | — | |||||||||
|
Ending
balance
|
$ | 471 | $ | 481 | $ | 493 | ||||||
Asset
Impairment — The Company applies the provisions of FASB No. 144, Accounting for the Impairment or
Disposal of Long-Lived Assets, to account for impairments on long-lived
assets. Impairment losses are recognized for long-lived assets used in
operations when indicators of impairment are present and the undiscounted cash
flows are not sufficient to recover the assets’ carrying value. The amount of
impairment is measured by comparing the fair value of the asset to its carrying
amount.
Exchange
Gas — Gas imbalances occur as a result of differences in volumes of gas
received and delivered by a pipeline system. These imbalances due to or from
shippers and operators are valued at an appropriate index price. Imbalances are
settled in cash or made up in-kind subject to terms of Florida Gas’ tariff, and
generally do not impact earnings.
Environmental
Expenditures (Note 12) — Expenditures that relate to an existing
condition caused by past operations, and do not contribute to current or future
generation, are expensed. Environmental expenditures relating to current or
future revenues are expensed or capitalized as appropriate based on the nature
of the cost incurred. Liabilities are recorded when environmental assessments
and/or clean ups are probable and the cost can be reasonably estimated.
Remediation obligations are not discounted because the timing of future cash
flow streams is not predictable.
Cash and
Cash Equivalents — Cash equivalents consist of highly liquid investments
with original maturities of three months or less. The carrying amount of cash
and cash equivalents approximates fair value because of the short maturity of
these investments.
Materials
and Supplies — Materials and supplies are valued at the lower of cost or
market value. Materials transferred out of warehouses are priced at average
cost. Materials and supplies include spare parts which are critical to the
pipeline system operations and are valued at the lower of cost or
market.
Fuel
Tracker — A liability is recorded for net volumes of gas owed to
customers collectively. Whenever fuel is due from customers from prior under
recovery based on contractual and specific tariff provisions an asset is
recorded. Gas owed to or from customers is valued at market. Changes in the
balances have no effect on the consolidated income of the Company.
Income
Taxes (Note 4) — Income taxes are accounted for under the asset and
liability method in accordance with the provisions of FASB Statement No. 109,
Accounting for Income
Taxes. Under this method, deferred tax assets and liabilities are
recognized for the estimated future tax consequences attributable to differences
between the financial statement carrying amounts of existing assets and
liabilities and their respective tax basis. Deferred tax assets and liabilities
are measured using enacted tax rates in effect for the year in which those
temporary differences are expected to be recovered or settled. The effect on
deferred tax assets and liabilities of a change in tax rate is recognized in
income in the period that includes the enactment date. Valuation allowances are
established when necessary to reduce deferred tax assets to the amounts more
likely than not to be realized.
The determination
of the Company’s provision for income taxes requires significant judgment, use
of estimates, and the interpretation and application of complex tax laws.
Significant judgment is required in assessing the timing and amounts of
deductible and taxable items. Reserves are established when, despite
management’s belief that the Company’s tax return positions are fully
supportable, management believes that certain positions may be successfully
challenged. When facts are circumstances change, these reserves are adjusted
through the provision for income taxes.
Accounts
Receivable — The
Company establishes an allowance for doubtful accounts on accounts receivable
based on the expected ultimate recovery of these receivables. The Company
considers many factors including historical customer collection experience,
general and specific economic trends and known specific issues related to
individual customers, sectors and transactions that might impact collectibility.
Unrecovered accounts receivable charged against the allowance for doubtful
accounts were $0.3 million, nil and nil in the years ended December 31, 2007,
2006 and 2005, respectively.
Pensions
and Postretirement Benefits — Effective December 31, 2006, the Company
adopted the recognition and disclosure provisions of FASB Statement No. 158,
“Employers’ Accounting for
Defined Benefit Pension and Other Postretirement Plans — an amendment
of FASB Statements No. 87, 88, 106, and 132(R)” (Statement No. 158).
Statement No. 158 requires employers to recognize in their balance sheets the
overfunded or underfunded status of defined benefit postretirement plans,
measured as the difference between the fair value of the plan assets and the
benefit obligation. Each overfunded plan is recognized as an asset and each
underfunded plan is recognized as a liability. Employers must recognize the
change in the funded status of the plan in the year in which the change occurs
through Accumulated Other
Comprehensive Loss in stockholders’ equity. Effective for years beginning
after December 15, 2008 (with early adoption permitted), Statement No. 158 also
requires plan assets and benefit obligations to be measured as of the employers’
balance sheet date. The Company has not yet adopted the measurement provisions
of Statement No. 158.
Prior to adoption
of the recognition provisions of Statement No. 158, the Company accounted for
its defined benefit postretirement plans under FASB Statement No. 106, “Employers’ Accounting for
Postretirement Benefits Other Than Pensions (Statement No. 106).”
Statement No. 106 required that the liability recorded should represent
the actuarial present value of all future benefits attributable to an employee’s
service rendered to date. Under Statement No. 106, changes in the funded status
were not immediately recognized; rather they were deferred and recognized
ratably over future periods. Upon adoption of the recognition provisions of
Statement No. 158, the Company recognized the amounts of these prior changes in
the funded status of its postretirement benefit plans. The Company’s plan is in
an overfunded position as of December 31, 2007. As the plan assets are derived
through rates charged to customers, under Statement No. 71, to the extent the
Company has collected amounts in excess of what is required to fund the plan,
the Company has an obligation to refund the excess amounts to customers through
rates. As such, the Company recorded the previously unrecognized changes in the
funded status (i.e., actuarial gains) as a regulatory liability and not as an
adjustment to Accumulated
Other Comprehensive Loss.
Use of
Estimates — The
preparation of financial statements in conformity with GAAP requires management
to make estimates and assumptions that affect the reported amounts of assets and
liabilities and disclosures of contingent assets and liabilities at the date of
the financial statements and the reported amounts of revenues and expenses
during the reporting period. Actual results could differ from those
estimates.
New
Accounting Principles
Accounting
Principles Not Yet Adopted.
FIN 48,”
Accounting for Uncertainty in Income Taxes — an Interpretation of FASB
Statement
109” (FIN 48 or the Interpretation): Issued by the FASB in June 2006,
this Interpretation clarifies the accounting for uncertainty in income taxes
recognized in an enterprise’s financial statements in accordance with FASB
Statement No. 109, Accounting
for Income Taxes. FIN 48 prescribes a recognition and measurement
threshold attributable for the financial statement recognition and measurement
of a tax position taken or expected to be taken in a tax return. FIN 48 also
provides guidance on derecognition, classification, interest and penalties,
accounting in interim periods, disclosures and transition. FIN 48 is effective
for fiscal years beginning after December 15, 2006, for public enterprises and
December 15, 2007, for nonpublic enterprises, such as Citrus. The Company has
determined the implementation of this Statement will not have a material impact
on its consolidated financial statements.
FSP No. FIN 48-1,
“Definition of ‘Settlement’ in FASB Interpretation No. 48” (FIN 48-1):
Issued by the FASB in May 2007, FIN 48-1 provides guidance on how an
enterprise should determine whether a tax position is effectively settled for
the purpose of recognizing previously unrecognized tax benefits.
FASB Statement
No. 157, “Fair Value Measurements” (FASB Statement No. 157 or the
Statement):
Issued by the FASB in September 2006, this Statement defines fair value,
establishes a framework for measuring fair value, and expands disclosures about
fair value measurements. Where applicable, this Statement simplifies and
codifies related guidance within GAAP. Except for certain non financial assets
and liabilities more fully discussed in FSP No. FAS 157-2, “Effective Date of FASB Statement No.
157” (FSP No. FAS
157-2) which was issued by the FASB in February 2008, this Statement is
effective for financial statements issued for fiscal years beginning after
November 15, 2007, and interim periods within those fiscal years. For those non
financial assets and liabilities deferred pursuant to FSP No. FAS 157-2, this
Statement is effective for financial statements for fiscal years beginning after
November 15, 2008. The Company is currently evaluating the impact of this
Statement on its consolidated financial statements.
FASB Statement
No. 159, “The Fair Value Option for Financial Assets and Financial
Liabilities — Including an Amendment of FASB Statement No. 115”: Issued
by the FASB in February 2007, this Statement permits entities to choose to
measure many financial instruments and certain other items at fair value that
are not currently required to be measured at fair value. Unrealized gains and
losses on items for which the fair value option has been elected are reported in
earnings. The Statement does not affect any existing accounting literature that
requires certain assets and liabilities to be carried at fair value. The
Statement is effective for fiscal years beginning after November 15, 2007. At
January 1, 2008, the Company did not elect the fair value option under the
Statement and, therefore, there was no impact to the Company’s consolidated
financials statements.
FASB Statement No. 141 (revised),
“Business
Combinations”. Issued by the FASB in December 2007, this Statement
changes the accounting for business combinations including the measurement of
acquirer shares issued in consideration for a business combination, the
recognition of contingent consideration, the accounting for preacquisition gain
and loss contingencies, the recognition of capitalized in-process research and
development costs, the accounting for acquisition-related restructuring cost
accruals, the treatment of acquisition related transaction costs and the
recognition of changes in the acquirer’s income tax valuation allowance. The
Statement is effective for fiscal years beginning after December 15, 2008, with
early adoption prohibited.
FASB Statement No. 160, “Noncontrolling
Interests in Consolidated Financial Statements, an
amendment of ARB No. 51”. Issued by the FASB in
December 2007, this Statement changes the accounting for noncontrolling
(minority) interests in consolidated financial statements including the
requirements to classify noncontrolling interests as a component of consolidated
stockholders’ equity, and the elimination of minority interest accounting in
results of operations with earnings attributable to noncontrolling interests
reported as part of consolidated earnings. Additionally, the Statement revises
the accounting for both increases and decreases in a parent’s controlling
ownership interest. The Statement is effective for fiscal years beginning
after December 15, 2008, with early adoption prohibited. The Company is
currently evaluating the impact of this statement on its consolidated financial
statements.
|
(3)
|
Long Term
Debt
|
The table below
sets forth the long-term debt of the Company as of the dates
indicated:
|
|
Years
|
December 31, 2007
|
December 31, 2006
|
|||||||||||||||||
|
|
Due
|
Book Value
|
Fair Value
|
Book Value
|
Fair Value
|
|||||||||||||||
|
(In
thousands)
|
||||||||||||||||||||
|
Citrus
|
||||||||||||||||||||
|
8.490% Senior
Notes
|
2007-2009 | $ | 60,000 | $ | 63,572 | $ | 90,000 | $ | 95,011 | |||||||||||
|
Revolving
Credit Agreement Citrus
|
2012 | 62,400 | 62,400 | — | — | |||||||||||||||
|
FGT
|
||||||||||||||||||||
|
9.750% Senior
B Notes
|
1999-2008 | 6,500 | 6,736 | 13,000 | 13,663 | |||||||||||||||
|
10.110%
Senior C Notes
|
2009-2013 | 70,000 | 82,282 | 70,000 | 82,773 | |||||||||||||||
|
9.190% Senior
Notes
|
2005-2024 | 127,500 | 158,843 | 135,000 | 167,004 | |||||||||||||||
|
7.625% Senior
Notes
|
2010 | 325,000 | 353,352 | 325,000 | 348,137 | |||||||||||||||
|
7.000% Senior
Notes
|
2012 | 250,000 | 277,281 | 250,000 | 271,893 | |||||||||||||||
|
Revolving
Credit Agreement FGT
|
2007 | — | — | 40,000 | 40,000 | |||||||||||||||
|
Revolving
Credit Agreement FGT
|
2012 | 54,000 | 54,000 | — | — | |||||||||||||||
|
Total debt
outstanding
|
$ | 955,400 | $ | 1,058,466 | $ | 923,000 | $ | 1,018,481 | ||||||||||||
|
Current
portion of long-term debt
|
(44,000 | ) | (84,000 | ) | ||||||||||||||||
|
Unamortized
Debt Discount and Swap Loss
|
(1,590 | ) | (2,118 | ) | ||||||||||||||||
|
Total
long-term debt
|
$ | 909,810 | $ | 836,882 | ||||||||||||||||
Annual maturities
of long-term debt outstanding as of the date indicated were as
follows:
|
|
December
31,
2007
|
|||
|
Year
|
(In
thousands)
|
|||
|
2008
|
$ | 44,000 | ||
|
2009
|
51,500 | |||
|
2010
|
346,500 | |||
|
2011
|
21,500 | |||
|
2012
|
387,900 | |||
|
Thereafter
|
104,000 | |||
| $ | 955,400 | |||
On August 13, 2004
Florida Gas entered into a Revolving Credit Agreement (“2004 Revolver”) with an
initial commitment level of $50 million, subsequently increased by $125 million
to $175 million. Since that time, Florida Gas has routinely utilized the 2004
Revolver to fund working capital needs. On December 31, 2006, the amount drawn
under the 2004 Revolver was $40 million, with a weighted average interest rate
of 6.08 percent (based on LIBOR plus 0.70 percent). Additionally, a commitment
fee of 0.15 percent is payable quarterly on the unused portion of the commitment
balance. The 2004 Florida Gas Revolver terminated in August 2007 and was
replaced by a new revolving credit agreement at Florida Gas in the amount of
$300 million (“2007 Florida Gas Revolver”), which will mature on August 16,
2012. The 2007 Florida Gas Revolver requires interest based on LIBOR plus a
margin tied to the debt rating of the Company’s senior unsecured debt, currently
0.28 percent, and has a facility fee of 0.07 percent. As of December 31, 2007,
the amount drawn under the 2007 Florida Gas Revolver was $54 million with a
weighted average interest rate of 5.30 percent (based on LIBOR plus 0.28
percent).
Also on August 16,
2007, Citrus entered into a revolving credit facility in the amount of $200
million (“2007 Citrus Revolver”), which will mature on August 16, 2012. This
facility will enable Citrus to meet its funding needs and repay its debt
maturities. As of December 31, 2007, the amount drawn under the 2007 Citrus
Revolver was $62.4 million with a weighted average interest rate of 5.22 percent
(based on LIBOR plus 0.28 percent), and has a facility fee of 0.07 percent.
Issuance costs for the 2007 Florida Gas Revolver and 2007 Citrus Revolver were
$0.3 million and $0.2 million, respectively at December 31, 2007.
The book value of
the 2004 Revolver, 2007 Florida Gas Revolver, and 2007 Citrus Revolver
approximates their market value given the variable rate of interest. Estimated
fair value amounts of other long-term debt were obtained from independent
parties, and are based upon market quotations of similar debt at interest rates
currently available. Judgment is required in interpreting market data to develop
the estimates of fair value. Accordingly, the estimates determined as of
December 31, 2007 and 2006 are not necessarily indicative of the amounts the
Company could have realized in current market exchanges.
The agreements
relating to Florida Gas’ debt include, among other things, restrictions as to
the payment of dividends and maintaining certain restrictive financial
covenants, including a required ratio of consolidated funded debt to total
capitalization.
Under the terms of
its debt agreements, Florida Gas may incur additional debt to refinance maturing
obligations if the refinancing does not increase aggregate indebtedness, and
thereafter, if Citrus’ and Florida Gas’ consolidated debt does not exceed
specific debt to total capitalization ratios, as defined in certain debt
instruments. Incurrence of additional indebtedness to refinance the current
maturities would not result in a debt to capitalization ratio exceeding these
limits.
All of the debt
obligations of Citrus and Florida Gas have events of default that contain
commonly used cross-default provisions. An event of default by either Citrus or
Florida Gas on any of their borrowed money obligations, in excess of certain
thresholds which is not cured within defined grace periods, would cause the
other debt obligations of Citrus and Florida Gas to be accelerated.
|
(4)
|
Income
Taxes
|
The principal
components of the Company’s net deferred income tax liabilities as of the dates
indicated were as follows:
|
|
December 31,
|
December 31,
|
||||||
|
|
2007
|
2006
|
||||||
|
(In
thousands)
|
||||||||
|
Deferred
income tax asset
|
||||||||
|
Regulatory
and other reserves
|
$ | 5,554 | $ | 8,595 | ||||
| 5,554 | 8,595 | |||||||
|
Deferred
income tax liabilities
|
||||||||
|
Depreciation
and amortization
|
759,576 | 742,566 | ||||||
|
Deferred
charges and other assets
|
— | 27,981 | ||||||
|
Regulatory
costs
|
4,717 | 9,298 | ||||||
|
Other
|
4,625 | 6,154 | ||||||
| 768,918 | 785,999 | |||||||
|
Net deferred
income tax liabilities
|
$ | 763,364 | $ | 777,404 | ||||
Total income tax
expense for the periods indicated was as follows:
|
|
Year
Ended
December
31,
2007
|
Year
Ended
December
31,
2006
|
Year
Ended
December
31,
2005
|
|||||||||
|
(In
thousands)
|
||||||||||||
|
Current Tax
Provision
|
||||||||||||
|
Federal
|
$ | 99,083 | $ | 52,135 | $ | 53,526 | ||||||
|
State
|
5,418 | 5,196 | 8,820 | |||||||||
| 104,501 | 57,331 | 62,346 | ||||||||||
|
Deferred Tax
Provision
|
||||||||||||
|
Federal
|
(14,531 | ) | 15,863 | 11,079 | ||||||||
|
State
|
2,254 | 2,766 | 1,661 | |||||||||
| (12,277 | ) | 18,629 | 12,740 | |||||||||
|
Total income
tax expense
|
$ | 92,224 | $ | 75,960 | $ | 75,086 | ||||||
The differences
between taxes computed at the U.S. federal statutory rate of 35 percent and the
Company’s effective tax rate for the periods indicated are as
follows:
|
|
Year
Ended
December
31,
2007
|
Year
Ended
December
31,
2006
|
Year
Ended
December
31,
2005
|
|||||||||
|
(In
Thousands)
|
||||||||||||
|
Statutory
federal income tax provision
|
$ | 87,261 | $ | 70,712 | $ | 69,661 | ||||||
|
State income
taxes, net of federal benefit
|
4,986 | 5,176 | 6,813 | |||||||||
|
Other
|
(23 | ) | 72 | (1,388 | ) | |||||||
|
Income tax
expense
|
$ | 92,224 | $ | 75,960 | $ | 75,086 | ||||||
|
Effective Tax
Rate
|
37.0 | % | 37.6 | % | 37.7 | % | ||||||
The Company files a
consolidated federal income tax return separate from that of its
stockholders.
|
(5)
|
Employee Benefit
Plans
|
The employees of
the Company were covered under Enron’s employee benefit plans until November
2004.
Enron maintained a
pension plan that was a noncontributory defined benefit plan, the Enron Corp.
Cash Balance Plan (the Cash Balance Plan), covering certain Enron employees in
the United States and certain employees in foreign countries. The basic benefit
accrual was 5 percent of eligible annual base pay. In 2003 the Company
recognized its portion of the expected Cash Balance Plan settlement by recording
a $9.6 million current liability, which was cash settled in 2005 (Note 7), and a
charge to operating expense. In 2004, with the settlement of the rate case (Note
8), Florida Gas recognized a regulatory asset for its portion, $9.3 million,
with a reduction to operating expense. Per the rate case settlement Florida Gas
will amortize, over five years retroactive to April 1, 2004, its allocated
share of costs to fully fund and terminate the Cash Balance Plan. Amortization
recorded was $1.9 million, $1.8 million and $1.9 million for the years ended
December 31, 2007, 2006 and 2005, respectively. At December 31, 2007 and 2006
the remaining regulatory asset balance was $2.3 million and $4.2 million,
respectively (Note 10).
Effective November
1, 2004 all employees of the Company were transferred to an affiliated entity,
CrossCountry Energy Services, LLC (CCES) and during November 2004, employee
insurance coverage migrated (without lapse) from Enron plans to new CCES welfare
and benefit plans. Effective March 1, 2005 essentially all such employees were
transferred to Florida Gas and became eligible at that time to participate in
employee welfare and benefit plans adopted by Florida Gas.
Effective March 1,
2005 Florida Gas adopted the Florida Gas Transmission Company 401(k) Savings
Plan (the Plan). All employees of Florida Gas are eligible to participate and,
within one Plan, may contribute up to 50 percent of pre-tax compensation,
subject to IRS limitations. This Plan allows additional “catch-up” contributions
by participants over age 50, and allows Florida Gas to make discretionary profit
sharing contributions for the benefit of all participants. Florida Gas matched
50 percent of participant contributions under this Plan up to a maximum of four
percent of eligible compensation through December 31, 2007. The matching was
increased effective January 1, 2008 to 100 percent of the first two percent and
50 percent of the next three percent of the participant’s compensation paid into
the Plan. Participants vest in such matching and any profit sharing
contributions at the rate of 20 percent per year, except that participants with
five years of service at the date of adoption of the Plan were immediately
vested. Administrative costs of the Plan and certain asset management fees are
paid from Plan assets. Florida Gas’ expensed its contribution of $0.3 million,
$0.4 million, and $0.3 million for the years ended December 31, 2007, 2006, and
2005 respectively.
Other
Post — Employment Benefits
Prior to December
1, 2004 Florida Gas was a participating employer in the Enron Gas Pipelines
Employee Benefit Trust (the Trust), a voluntary employees’ beneficiary
association (VEBA) under Section 501(c)(9) of the Internal Revenue Code of 1986,
as amended (Tax Code), which provided certain post-retirement medical, life
insurance and dental benefits to employees of Florida Gas and certain other
Enron affiliates pursuant to the Enron Corp. Medical Plan and the Enron Corp.
Medical Plan for Inactive Participants. Enron has made the determination that it
will partition the Trust and distribute the assets and liabilities of the Trust
among the participating employers of the Trust on a pro rata basis according to
the contributions and liabilities associated with each participating employer.
The Trust Committee has final approval on allocation methodology for the Trust
assets. It is estimated that Florida Gas will receive approximately $6.8 million
from the Trust, including an estimated investment return as early as first
quarter 2008. Enron filed a motion in the Enron bankruptcy proceedings on July
22, 2003 which was stayed and then refiled and amended on June 17, 2005 and
again refiled and amended on December 1, 2006 which provides that each
participating employer
expressly
assumes liability for its allocable portion of retiree benefits and releases
Enron from any liability with respect to the Trust in order to receive the
assets of the Trust. On June 7, 2005 a class action suit captioned Lou Geiler et al v. Robert W.
Jones, et al.,
was filed in United States District Court for the District of Nebraska
by, among others, former employees of Northern Natural Gas Company (Northern) on
behalf of the participants in the Northern Medical and Dental Plan for Retirees
and Surviving Spouses against former and present members of the Trust Committee,
the Trustee and the participating employers of the Trust, including Florida Gas,
claiming the Trust Committee and the Trustee have violated their fiduciary
duties under ERISA and seeking a declaration from the Court binding on all
participating employers of an accounting and distribution of the assets held in
the Trust and a complete and accurate listing of the individuals properly
allocated to Northern from the Enron Plan. On the same date essentially the same
group filed a motion in the Enron bankruptcy proceedings to strike the Enron
motion from further consideration. On February 6, 2006 the Nebraska action was
dismissed. The plaintiffs filed an appeal of the dismissal on March 8, 2006. An
agreement was reached on the conditions of the partition of the Trust among the
VEBA participating employers, Enron and the Trust Committee and approved by the
Enron bankruptcy court on December 21, 2006. As a result, the Nebraska action
appeal was dismissed on January 25, 2007.
During the period
December 1, 2004 through February 28, 2005, following Florida Gas’ November 17,
2004 acquisition by CCE Holdings, coverage to eligible employees and their
eligible dependents was provided by CrossCountry Energy Retiree Health Plan,
which provides only medical benefits. Florida Gas continues to provide certain
retiree benefits through employer contributions to a qualified contribution
plan, with the amounts generally varying based on age and years of service.
Effective March 1, 2005 such benefits are provided under an identical plan
sponsored by Florida Gas as a single employer post-retirement benefit
plan.
With regard to its
sponsored plan, Florida Gas has entered into a VEBA trust (the “VEBA Trust”)
agreement with JPMorgan Chase Bank Trust Company as trustee. The VEBA Trust has
established or adopted plans to provide certain post-retirement life, health,
accident and other benefits. The VEBA Trust is a voluntary employees’
beneficiary association under Section 501(c)(9) of the Tax Code, which provides
benefits to employees of the Company. Florida Gas contributed $0.5 million and
$1.2 million to the VEBA Trust for the years ended December 31, 2007 and 2006,
respectively. Upon settlement of the Trust, the anticipated distribution of
assets to Florida Gas from the Trust will be contributed to the VEBA
Trust.
Prior to 2005,
Florida Gas’ general policy was to fund accrued post-retirement health care
costs as allocated by Enron. As a result of Florida Gas’ change in 2005 from a
participant in a multi employer plan to a single employer plan, Florida Gas now
accounts for its OPEB liability and expense on an actuarial basis, recording its
health and life benefit costs over the active service period of employees to the
date of full eligibility for the benefits. At December 31, 2005 Florida Gas
recognized its OPEB liability by recording a deferred credit of $2.2 million and
a corresponding regulatory asset of $2.2 million.
The Company has
postretirement health care plans which cover substantially all employees. The
health care plans generally provide for cost sharing in the form of retiree
contributions, deductibles, and coinsurance between the Company and its
retirees, and a fixed cost cap on the amount the Company pays annually to
provide future retiree health care coverage under certain of these
plans.
67
CITRUS
CORP. AND SUBSIDIARIES
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
The following table
summarizes the impact of adopting Statement No. 158 on the Company’s
postretirement plan reported in the Consolidated Balance Sheet at December 31,
2006:
|
|
Pre-FASB 158
|
FASB
158
adoption
adjustment
|
Post-FASB 158
|
|||||||||
|
(In
Thousands)
|
||||||||||||
|
Prepaid
postretirement benefit cost (non-current) (Note 10)
|
$ | (721 | ) | $ | 3,423 | $ | 2,702 | |||||
|
Regulatory
asset
|
1,951 | (1,951 | ) | — | ||||||||
|
Regulatory
liability
|
— | (1,472 | ) | (1,472 | ) | |||||||
The adoption of
Statement No. 158 had no effect on the Consolidated Statements of Income for the
years ended December 31, 2007 and December 31, 2006, or for any prior period
presented, has not negatively impacted any financial covenants, and is not
expected to affect the Company’s operating results in future
periods.
Postretirement
benefit liabilities are accrued on an actuarial basis during the years an
employee provides services. The following table represents a reconciliation of
Florida Gas’ OPEB plan for the periods indicated:
|
|
Year
Ended
December
31,
2007
|
Year
Ended
December
31,
2006
|
||||||
|
(In
thousands)
|
||||||||
|
Change in
Benefit Obligation
|
||||||||
|
Benefit
obligation at the beginning of period
|
$ | 5,795 | $ | 6,665 | ||||
|
Service
cost
|
37 | 46 | ||||||
|
Interest
cost
|
296 | 312 | ||||||
|
Actuarial
gain
|
(320 | ) | (691 | ) | ||||
|
Retiree
premiums
|
415 | 427 | ||||||
|
Benefits
paid
|
(1,029 | ) | (964 | ) | ||||
|
CMS Medicare
Part D Subsidies Received
|
108 | — | ||||||
|
Benefit
obligation at end of year
|
5,302 | 5,795 | ||||||
|
Change in
Plan Assets
|
||||||||
|
Fair value of
plan assets at the beginning of period
|
8,497 | 7,840 | ||||||
|
Return on
plan assets
|
336 | (37 | ) | |||||
|
Employer
contributions
|
380 | 1,231 | ||||||
|
Retiree
premiums
|
415 | 427 | ||||||
|
Benefits
paid
|
(1,029 | ) | (964 | ) | ||||
|
Fair value of
plan assets at end of year (1)
|
8,599 | 8,497 | ||||||
|
Funded Status
Funded status at the end of the year
|
$ | 3,297 | $ | 2,702 | ||||
|
Amount
recognized in the Consolidated Balance Sheets
|
||||||||
|
Other assets
— other (Note 10)
|
$ | 3,297 | $ | 2,702 | ||||
|
Regulatory
liability (Note 11)
|
(3,390 | ) | (1,472 | ) | ||||
|
Net asset
(liability) recognized
|
$ | (93 | ) | $ | 1,230 | |||
____________
|
(1)
|
Plan assets at
December 31, 2007 and 2006 include the amounts of assets expected to be
received from the Enron Trust of $6.8 million and $6.5 million,
respectively, including a 5 percent annual investment return based on
estimate.
|
The
weighted-average assumptions used to determine Florida Gas’ benefit obligations
for the periods indicated were as follows:
|
|
Year
Ended
December
31,
2007
|
Year
Ended
December
31,
2006
|
Year
Ended
December
31,
2005
|
|||||||||
|
Discount
rate
|
6.09 | % | 5.68 | % | 5.50 | % | ||||||
|
Health care
cost trend rates
|
10.00 | % | 11.00 | % | 12.00 | % | ||||||
|
graded to
5.20
|
% |
graded to
4.85
|
% |
graded to
4.65
|
% | |||||||
|
by 2017
|
by 2013
|
by 2012
|
||||||||||
Florida Gas’ net
periodic (benefit) costs for the periods indicated consisted of the
following:
|
|
Year
Ended
December
31,
2007
|
Year
Ended
December
31,
2006
|
Year
Ended
December
31,
2005
|
|||||||||
|
(In
thousands)
|
||||||||||||
|
Service
cost
|
$ | 37 | $ | 46 | $ | 71 | ||||||
|
Interest
cost
|
296 | 312 | 490 | |||||||||
|
Expected
return on plan assets
|
(414 | ) | (402 | ) | (352 | ) | ||||||
|
Recognized
actuarial gain
|
(230 | ) | (223 | ) | (174 | ) | ||||||
|
Net periodic
(benefit) cost
|
$ | (311 | ) | $ | (267 | ) | $ | 35 | ||||
The
weighted-average assumptions used to determine Florida Gas’ net periodic benefit
costs for the periods indicated were as follows:
|
|
Year Ended
December 31,
2007
|
Year Ended
December 31,
2006
|
Year Ended
December 31,
2005
|
|||||||||
|
Discount
rate
|
5.68 | % | 5.50 | % | 5.75 | % | ||||||
|
Rate of
compensation increase
|
N/A | N/A | N/A | |||||||||
|
Expected
long-term return on plan assets
|
5.00 | % | 5.00 | % | 5.00 | % | ||||||
|
Health care
cost trend rates
|
11.00 | % | 12.00 | % | 12.00 | % | ||||||
|
graded to
4.85
|
% |
graded to
4.65
|
% |
graded to
4.75
|
% | |||||||
|
by 2013
|
by 2012
|
by 2012
|
||||||||||
Florida Gas employs
a building block approach in determining the expected long-term rate on return
on plan assets. Historical markets are studied and long-term historical
relationships between equities and fixed-income are preserved consistent with
the widely accepted capital market principle that assets with higher volatility
generate a greater return over the long run. Current market factors such as
inflation and interest rates are evaluated before long-term market assumptions
are determined. The long-term portfolio return is established via a building
block approach with proper consideration of diversification and rebalancing.
Peer data and historical returns are reviewed to check for reasonability and
appropriateness.
Assumed health care
cost trend rates have a significant effect on the amounts reported for health
care plans. A one-percentage-point change in assumed health care cost trend
rates would have the following effects:
|
|
One
Percentage
Point Increase
|
One
Percentage
Point Decrease
|
||||||
|
(In
thousands)
|
||||||||
|
Effect on
total service and interest cost components
|
$ | 15 | $ | (13 | ) | |||
|
Effect on
postretirement benefit obligation
|
$ | 240 | $ | (215 | ) | |||
Discount
Rate Selection — The
discount rate for each measurement date has been determined consistent with the
discount rate selection guidance in Statement No. 106 (as amended by Statement
No. 158) using the Citigroup Pension Discount Curve as published on the Society
of Actuaries website as the hypothetical portfolio of high-quality debt
instruments that would provide the necessary cash flows to pay the benefits when
due.
Plan
Asset Information —
The plan assets shall be invested in accordance with sound investment
practices that emphasize long-term investment fundamentals. An investment
objective of income and growth for the plan has been adopted. This investment
objective: (i) is a risk-averse balanced approach that emphasizes a stable and
substantial source of current income and some capital appreciation over the
long-term; (ii) implies a willingness to risk some declines in value over the
short-term, so long as the plan is positioned to generate current income and
exhibits some capital appreciation; (iii) is expected to earn long-term returns
sufficient to keep pace with the rate of inflation over most market cycles (net
of spending and investment and administrative expenses), but may lag inflation
in some environments; (iv) diversifies the plan in order to provide
opportunities for long-term growth and to reduce the potential for large losses
that could occur from holding concentrated positions; and (iv)
recognizes that investment results over the long-term may lag those of a typical
balanced portfolio since a typical balanced portfolio tends to be more
aggressively invested. Nevertheless, this plan is expected to earn a long-term
return that compares favorably to appropriate market indices.
It is expected that
these objectives can be obtained through a well-diversified portfolio structure
in a manner consistent with the investment policy.
Florida Gas’ OPEB
weighted-average asset allocation by asset category for the $1.8 million and
$2.0 million of assets actually in the VEBA Trust at December 31, 2007 and 2006,
respectively, were approximately as follows:
|
|
December
31,
2007
|
December
31,
2006
|
||||||
|
Equity
securities
|
31 | % | 0 | % | ||||
|
Debt
securities
|
69 | % | 0 | % | ||||
|
Cash and cash
equivalents
|
0 | % | 100 | % | ||||
|
Total
|
100 | % | 100 | % | ||||
Based on the
postretirement plan objectives, asset allocations should be maintained as
follows: equity of 25 percent to 35 percent, fixed income of 65 percent to 75
percent, and cash and cash equivalents of 0 percent to 10 percent.
The above
referenced asset allocations for postretirement benefits are based upon
guidelines established by Florida Gas’ Investment Policy and is monitored by the
Investment Committee of the board of directors in conjunction with an external
investment advisor.
Florida Gas expects
to contribute approximately $1.1 million to its post-retirement benefit plan in
2008 and approximately $1.1 million annually thereafter until modified by rate
case proceedings.
The estimated
employer portion of benefit payments, which reflect expected future service, as
appropriate, that are projected to be paid are as follows:
|
Years
|
Expected
Benefits
Before Effect
of
Medicare Part D
|
Payments
Medicare
Part D
|
Net
|
|||||||||
|
(In
thousands)
|
||||||||||||
|
2008
|
$ | 551 | $ | 96 | $ | 455 | ||||||
|
2009
|
594 | 99 | 495 | |||||||||
|
2010
|
614 | 101 | 513 | |||||||||
|
2011
|
625 | 101 | 524 | |||||||||
|
2012
|
624 | 100 | 524 | |||||||||
|
2013 —
2017
|
2,935 | 454 | 2,481 | |||||||||
The Medicare
Prescription Drug Act was signed into law December 8, 2003. The Act introduces a
prescription drug benefit under Medicare (Medicare Part D) as well as a
federal subsidy, which is not taxable, to sponsors of retiree healthcare benefit
plans that provide a prescription drug benefit that is at least actuarially
equivalent to Medicare Part D.
|
(6)
|
Major Customers and
Concentration of Credit Risk
|
Revenues from
individual third party and affiliate customers exceeding 10 percent of total
revenues for the periods indicated were approximately as listed below, and in
total represented 56%, 58% and 54% of total revenue, respectively.
|
|
Year
Ended
December
31,
2007
|
Year
Ended
December
31,
2006
|
Year
Ended
December
31,
2005
|
|||||||||
|
(In
thousands)
|
||||||||||||
|
Florida Power
& Light Company
|
$ | 195,622 | $ | 200,592 | $ | 181,486 | ||||||
|
TECO Energy,
Inc.
|
80,815 | 80,192 | 76,059 | |||||||||
The Company had the
following transportation receivables from these customers at the dates
indicated:
|
|
December
31,
2007
|
December
31,
2006
|
||||||
|
(In
thousands)
|
||||||||
|
Florida Power
& Light Company
|
$ | 15,130 | $ | 15,065 | ||||
|
TECO Energy,
Inc.
|
6,201 | 6,161 | ||||||
The Company has a
concentration of customers in the electric and gas utility industries. These
concentrations of customers may impact the Company’s overall exposure to credit
risk, either positively or negatively, in that the customers may be similarly
affected by changes in economic or other conditions. Credit losses incurred on
receivables in these industries compare favorably to losses experienced in the
Company’s receivable portfolio as a whole. The Company also has a concentration
of customers located in the southeastern United States, primarily within the
state of Florida. Receivables are generally not collateralized. From time to
time, specifically identified customers having perceived credit risk are
required to provide prepayments, deposits, or other forms of security to the
Company. Florida Gas sought additional assurances from customers due to credit
concerns, and had customer deposits totaling $1.6 million and $1.6 million, and
prepayments of $43,000 and $0.2 million at December 31, 2007 and 2006,
respectively. The Company’s management believes that the portfolio of Florida
Gas’ receivables, which includes regulated electric utilities, regulated local
distribution companies, and municipalities, is of minimal credit
risk.
|
(7)
|
Related Party
Transactions
|
In December 2001
Enron and certain of its subsidiaries filed voluntary petitions for Chapter 11
reorganization with the U.S. Bankruptcy court. At December 31, 2004 Florida Gas
and Trading had aggregate outstanding claims with the Bankruptcy Court against
Enron and affiliated bankrupt companies of $220.6 million. Of these claims,
Florida Gas and Trading filed claims totaling $68.1 and $152.5 million,
respectively. Florida Gas and Trading claims pertaining to contracts rejected by
ENA were $21.4 and $152.3 million, respectively. In March 2005, ENA filed
objections to Trading’s claim. In September 2006 the judge issued an order
rejecting certain of Trading’s arguments and ruling that a contract under which
ENA had an in the money position against Trading may be offset against a related
contract under which Trading had an in the money position against ENA. The
result of the order was a reduction in the allowable amount of Trading’s initial
claim to $22.7 million. The parties reached a settlement which was approved by
the Bankruptcy Court in March 2007 (See Note 14).
Florida Gas’ claims
against ENA on transportation contracts were reduced by approximately $21.2
million when a third party took assignment of ENA’s transportation contracts. In
2004 Florida Gas settled the amount of all of its claims against Enron and a
subsidiary debtor. Total allowed claims (including debtor set-offs) were $13.3
million. After approval of the settlement by the Bankruptcy Court, in June 2005
Florida Gas sold its claims, received $3.4 million and recorded Other Income of
$0.9 million.
Florida Gas had a
construction reimbursement agreement with ENA under which amounts owed to
Florida Gas were delinquent. These obligations totaled approximately $7.4
million and were included in Florida Gas’ filed bankruptcy claims. These
receivables were fully reserved by Florida Gas prior to 2003. Under the
Settlement filed by Florida Gas on August 13, 2004 and approved by the FERC on
December 21, 2004 Florida Gas will recover the under-recovery on this obligation
by rolling in the costs of the facilities constructed, less the recovery from
ENA, in its tariff rates (see Note 8). As part of the June 2005 sale of its
claims, Florida Gas received $2.1 million for this part of the
claim.
The Company
provided natural gas sales and transportation services to El Paso affiliates at
rates equal to rates charged to non-affiliated customers in the same class of
service. Revenues related to these transportation services were approximately
nil, $1.0 million and $4.5 million in the years ended December 31, 2007, 2006
and 2005, respectively. The Company’s gas sales were immaterial in the years
ended December 31, 2007, 2006 and 2005. Florida Gas also purchased
transportation services from Southern in connection with its Phase III Expansion
completed in early 1995. Florida Gas contracted for firm capacity of 100,000
Mcf/day on Southern’s system for a primary term of 10 years, to be continued for
successive terms of one year each year thereafter unless cancelled by either
party, by giving 180 days notice to the other party prior to the end of the
primary term or any yearly extension thereof. The amount expensed for these
services totaled $6.8 million, $6.6 million and $6.3 million in the years ended
December 31, 2007, 2006 and 2005, respectively.
71
CITRUS
CORP. AND SUBSIDIARIES
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
Effective April 1,
2004 services previously provided by bankrupt Enron affiliates to the Company
pursuant to the allocation methodology ordered by the Bankruptcy Court were
covered and charged under the terms of the Transition Services Agreement /
Transition Supplemental Services Agreement (TSA/TSSA). This agreement between
Enron and CrossCountry was administered by CrossCountry Energy Services, LLC
(CCES), a subsidiary of CCE Holdings, which allocated to the Company its share
of total costs. Effective November 17, 2004 an Amended TSA/TSSA agreement
was put into effect. This agreement expired on July 31, 2005. The total
costs are not materially different from those previously charged. The amount
expensed for the seven month-period ended July 31, 2005 was approximately
$1.5 million.
On November 5,
2004, CCE Holdings entered into an Administrative Services Agreement (ASA) with SU Pipeline
Management LP (Manager), a Delaware limited partnership and a wholly-owned
subsidiary of Southern Union. Pursuant to the ASA, Manager was responsible for
the operations and administrative functions of the enterprise, CCE Holdings and
Manager shared certain operations of Manager and its affiliates, and CCE
Holdings was obligated to bear its share of costs of Manager and its affiliates.
Costs are allocated by Manager and its affiliates to the operating subsidiaries
and investees, based on relevant criteria, including time spent, miles of pipe,
total assets, labor allocations, or other appropriate methods. Manager provided
services to CCE Holdings from November 17, 2004 to December 1, 2006. Following
the closing of the Redemption Agreement on December 1, 2006, services continue
to be provided by Southern Union affiliates to Florida Gas, and costs allocated
using allocation methods consistent with past practices.
The Company has
related party activities for operational and administrative services performed
by CCES, Panhandle Eastern Pipe Line Company, LP (PEPL), an indirect
wholly-owned subsidiary of Southern Union, and other related parties, on behalf
of the Company, and corporate service charges from Southern Union. Expenses are
generally charged based on either actual usage of services or allocated based on
estimates of time spent working for the benefit of the various affiliated
companies. Amounts expensed by the Company were $21.5 million, $20.6 million and
$20.2 million in the years ended December 31, 2007, 2006 and 2005, respectively,
and included corporate service charges from Southern Union of $5.9 million, $4.0
million and $1.6 million in the years ended December 31, 2007, 2006 and 2005,
respectively. Additionally, the Company receives allocated costs of certain
shared business applications from PEPL and Southern Union. At December 31, 2007
and 2006, the Company had current accounts payable to affiliated companies of
$8.4 million and $2.8 million, respectively, relating to these
services.
In 2005, the
Company paid a subsidiary of CCE Holdings $9.6 million to settle the Cash
Balance Plan obligation, which CCE Holdings effectively paid in conjunction with
the 2004 acquisition of the Company.
The Company paid
cash dividends to its shareholders of $207.1 million, $125.4 million and $121.2
million in the years ended December 31, 2007, 2006, and 2005, respectively. The
Company also declared a dividend in December 2007 of $42.6 million, payable in
January, 2008 and which was paid on January 18, 2008.
|
(8)
|
Regulatory
Matters
|
On August 13, 2004
Florida Gas filed a Stipulation and Agreement of Settlement (“Rate Case
Settlement”) in its Section 4 rate proceeding in Docket No. RP04-12, which
established settlement rates and resolved all issues. The settlement rates were
approved and became effective on April 1, 2004 for all Florida Gas services and
again on April 1, 2005 for Rate Schedule FTS-2 when the basis for rates on
Florida Gas incremental facilities changed from a levelized cost of service to a
traditional cost of service.
On December 15, 2003 the U.S. Department of Transportation issued
a Final Rule requiring pipeline operators to develop integrity management
programs to comprehensively evaluate their pipelines, and take measures to
protect pipeline segments located in what the regulation defines as “high
consequence areas” (“HCA”). This rule resulted from the enactment of the
Pipeline Safety Improvement Act of 2002. The rule requires operators to identify
HCAs along their pipelines by December 2004 and to have begun baseline integrity
assessments, comprised of in-line inspection (smart pigging), hydrostatic
testing, or direct assessment, by June 2004. Operators were required to rank the
risk of their pipeline segments containing HCAs and to complete assessments on
at least 50 percent of the segments using one or more of these methods by
December 2007. Assessments will generally be conducted on the higher risk
segments first with the balance being completed by December 2012. As of December
31, 2007, Florida Gas completed 62 percent of the risk assessments. In addition,
some system modifications will be necessary to accommodate the in-line
inspections. All systems operated by the Company will be compliant with the
rule; however, while identification and location of all the HCAs has been
completed, it is impossible to determine with certainty the total scope of
required remediation activities prior to completion of the assessments and
inspections. The required modifications and inspections are currently estimated
to be in the range of approximately $21 million to $28 million per year through
2012. Pursuant to the August 13, 2004 Rate Case Settlement, Florida Gas has the
right to make limited sections 4 filings to recover, via a surcharge during the
settlement’s term, depreciation and return on up to approximately $40 million of
such costs, as well as security, and Florida Turnpike relocation and
modification costs. A reservation surcharge of $0.02 per MMBtu has been in
effect since April 1, 2007, subject to refund and further review by the FERC.
In June 2005 FERC
issued an order Docket No. AI05-1-000 that expands on the accounting guidance in
the proposed accounting release issued in November 2004 on mandated pipeline
integrity programs. The order interprets the FERC’s existing accounting rules
and standardizes classifications of expenditures made by pipelines in connection
with an integrity management program. The order is effective for integrity
management expenditures incurred on or after January 1, 2006. Florida Gas
capitalizes all pipeline assessment costs pursuant to its August 13, 2004 Rate
Case Settlement. The Rate Case Settlement contained no reference to the FERC
Docket No. AI05-1-000 regarding pipeline assessment costs and provided that the
final FERC order approving the Rate Case Settlement constituted final approval
of all necessary authorizations to effectuate its provisions. The Rate Case
Settlement provisions became effective on March 1, 2005 and new tariff sheets to
implement these provisions were filed on March 15, 2005. FERC issued an order
accepting the tariff sheets on May 20, 2005. In the years ended December 31,
2007 and 2006, Florida Gas completed and capitalized $9.5 million and $6.7
million, respectively on pipeline assessment projects, as part of the integrity
programs.
On October 5, 2005
Florida Gas filed an application with FERC for the Company’s proposed Phase VII
expansion project. The project will expand Florida Gas’ existing pipeline
infrastructure in Florida and provide the growing Florida energy market access
to additional natural gas supply from the Southern LNG Elba Island liquefied
natural gas import terminal near Savannah, Georgia. The Phase VII project calls
for Florida Gas to build approximately 17 miles of 36-inch diameter pipeline
looping in several segments along an existing right of way and install 9,800
horsepower of compression in a first phase with the possibility of a future
second phase. The expansion as currently planned will provide about 100 million
cubic feet per day (MMcf/d) of additional capacity to transport natural gas from
a connection with Southern Natural Gas Company’s Cypress Pipeline project in
Clay County, Florida. The FERC issued an order approving the project on June 15,
2006 and construction commenced on November 6, 2006. The first phase was
partially placed in service in May 2007 while certain modifications at
compressor station 26 are expected to be in service by the end of March, 2008.
The updated estimated cost of the expansion is approximately $62 million,
including AFUDC. Approximately $12.6 million and $39.3 million is recorded in
the line item Construction work in progress at December 31, 2007 and December
31, 2006, respectively.
On October 20,
2005, Florida Gas filed an application with FERC for the Company’s State Road 91
Relocation Project. The proposed project will consist of the abandonment of
approximately 11.15 miles of 18-inch diameter pipeline and 10.75 miles of
24-inch diameter pipeline in Broward, County Florida. The replacement pipeline
will consist of approximately 11.15 miles of 36-inch diameter pipeline. The
abandonment and replacement is being performed to accommodate the widening of
State Road 91 by the Florida Department of Transportation/Florida Turnpike
Enterprise (FDOT/FTE). The estimated cost of the pipeline relocation project is
estimated at $110 million, including AFUDC, and Florida Gas is seeking recovery
of the construction costs from the FDOT/FTE. The FERC issued an order approving
the project on May 3, 2006. Florida Gas notified the FERC that construction
commenced on April 25, 2007.
Florida Gas plans
to seek FERC approval to construct an expansion to increase its natural gas
capacity into Florida by approximately 800 MMcf/d (Phase VIII Expansion). The
Phase VIII Expansion includes construction of approximately 500 miles of
additional large diameter pipeline and the installation of approximately 170,000
horsepower of additional compression. Pending FERC approval, which is expected
in 2009, Florida Gas anticipates an in-service date of 2011, at an approximate
cost of $2 billion. Florida Gas has signed a 25-year agreement with Florida
Power and Light Company, (FPL), a wholly-owned
subsidiary of FPL Group, Inc., for 400 MMcf/d of capacity.
|
(9)
|
Property, Plant and
Equipment
|
The principal
components of the Company’s property, plant and equipment at the dates indicated
were as follows:
|
|
December
31,
2007
|
December
31,
2006
|
||||||
|
(In
thousands)
|
||||||||
|
Transmission
plant
|
$ | 2,970,560 | $ | 2,859,920 | ||||
|
General
plant
|
28,540 | 24,970 | ||||||
|
Intangibles
|
31,196 | 25,726 | ||||||
|
Construction
work-in-progress
|
133,824 | 85,746 | ||||||
|
Acquisition
adjustment
|
1,252,466 | 1,252,466 | ||||||
| 4,416,586 | 4,248,828 | |||||||
|
Less:
Accumulated depreciation and amortization
|
(1,401,638 | ) | (1,304,133 | ) | ||||
|
Property,
Plant and Equipment, net
|
$ | 3,014,948 | $ | 2,944,695 | ||||
|
(10)
|
Other
Assets
|
The principal
components of the Company’s regulatory assets at the dates indicated were as
follows:
|
|
December
31,
2007
|
December
31,
2006
|
||||||
|
(In
thousands)
|
||||||||
|
Ramp-up
assets, net (1)
|
$ | 11,616 | $ | 11,928 | ||||
|
Fuel
Tracker
|
2,295 | 11,747 | ||||||
|
Cash balance
plan settlement (Note 5)
|
2,326 | 4,185 | ||||||
|
Environmental
non-PCB clean-up cost (Note 12)
|
1,147 | 1,000 | ||||||
|
Other
miscellaneous
|
1,823 | 2,147 | ||||||
|
Total
Regulatory Assets
|
$ | 19,207 | $ | 31,007 | ||||
____________
|
(1)
|
Ramp-up
assets are regulatory assets which Florida Gas was specifically allowed to
establish in the FERC certificates authorizing the Phase IV and V
Expansion projects.
|
The principal
components of the Company’s other assets at the dates indicated were as
follows:
|
|
December
31,
2007
|
December
31,
2006
|
||||||
|
(In
thousands)
|
||||||||
|
Long-term
receivables (Note 14)
|
$ | 2,859 | $ | 71,648 | ||||
|
Other post
employment benefits (Note 5)
|
3,297 | 2,702 | ||||||
|
Preliminary
survey & investigation
|
3,021 | 996 | ||||||
|
FERC ACA
fee
|
1,061 | 839 | ||||||
|
Other
miscellaneous
|
600 | 244 | ||||||
|
Total Other
Assets — other
|
$ | 10,838 | $ | 76,429 | ||||
|
(11)
|
Deferred
Credits
|
The principal
components of the Company’s regulatory liabilities at the dates indicated were
as follows:
|
|
December
31,
2007
|
December
31,
2006
|
||||||
|
(In
thousands)
|
||||||||
|
Balancing
tools (1)
|
$ | 11,413 | $ | 12,154 | ||||
|
Other post
employment benefits (Note 5)
|
3,390 | 1,472 | ||||||
|
Other
miscellaneous
|
39 | 630 | ||||||
|
Total
Regulatory liabilities
|
$ | 14,842 | $ | 14,256 | ||||
____________
|
(1)
|
Balancing tools are a regulatory
method by which Florida Gas recovers the costs of operational balancing of
the pipeline’s system. The balance can be a deferred charge or credit,
depending on timing, rate changes and operational
activities.
|
The principal
components of the Company’s other deferred credits at the dates indicated were
as follows:
|
|
December
31,
2007
|
December
31,
2006
|
||||||
|
(In
thousands)
|
||||||||
|
Post
construction mitigation costs
|
$ | 1,686 | $ | 2,073 | ||||
|
Deferred
compensation
|
889 | 1,090 | ||||||
|
Environmental
non-PCB clean-up cost reserve (Note 12)
|
1,337 | 1,423 | ||||||
|
Taxes
Payable
|
3,116 | 1,664 | ||||||
|
Asset
retirement obligation (Note 2)
|
471 | 481 | ||||||
|
Other
miscellaneous
|
1,703 | 1,398 | ||||||
|
Total
Deferred Credits — other
|
$ | 9,202 | $ | 8,129 | ||||
|
(12)
|
Environmental
Reserve
|
The Company is
subject to extensive federal, state and local environmental laws and
regulations. These laws and regulations require expenditures in connection with
the construction of new facilities, the operation of existing facilities and for
remediation at various operating sites. The implementation of the Clean Air Act
Amendments resulted in increased operating expenses. These increased operating
expenses did not have a material impact on the Company’s consolidated financial
statements.
Florida Gas
conducts assessment, remediation, and ongoing monitoring of soil and groundwater
impact which resulted from its past waste management practices at its Rio
Paisano and Station 11 facilities. The anticipated costs over the next five
years are: 2008 — $0.3 million, 2009 - $0.1 million, 2010 — $0.2 million, 2011 —
$0.3 million and 2012 — $0.1 million. The expenditures thereafter are estimated
to be $0.6 million for soil and groundwater remediation. The liability is
recognized in other current liabilities and in other deferred credits and in
total amounted to $1.6 million and $1.6 million at December 31, 2007 and 2006,
respectively. Costs of $0.2 million, $0.1 million and $0.8 million were expensed
during the years ended December 31, 2007, 2006 and 2005, respectively. Florida
Gas recorded the estimated costs of remediation to be spent after April 1, 2010
of $1.1 million and $1.0 million at December 31, 2007 and 2006, respectively
(Note 10), as a regulatory asset based on the probability of recovery in rates
in its next rate case.
Prior to December
31, 2005, no such liability was recognized since it was previously estimated to
be less than $1.0 million, and therefore, considered not to be material. Amounts
incurred for environmental assessment and remediation were expensed as
incurred.
|
(13)
|
Accumulated Other Comprehensive
Loss
|
Deferred gains and
losses in connection with the termination of the following derivative
instruments which were previously accounted for as cash flow hedges form part of
other comprehensive income. Such amounts are being amortized over the terms of
the hedged debt.
The table below
provides an overview of comprehensive income for the periods
indicated:
|
|
Year
Ended
December
31,
2007
|
Year
Ended
December
31,
2006
|
Year
Ended
December
31,
2005
|
|||||||||
|
(In
thousands)
|
||||||||||||
|
Interest rate
swap loss on 7.625%$325 million note due 2010
|
$ | 1,873 | $ | 1,872 | $ | 1,872 | ||||||
|
Interest rate
swap loss on 7.0%$250 million note due 2012
|
1,228 | 1,228 | 1,228 | |||||||||
|
Interest rate
swap gain on 9.19%$150 million note due 2005-2024
|
(462 | ) | (462 | ) | (462 | ) | ||||||
|
Total
|
$ | 2,639 | $ | 2,638 | $ | 2,638 | ||||||
The table below
provides an overview of the components in accumulated other comprehensive loss
at the dates indicated:
|
|
Termination
Date
|
Amortization
Period
|
Original
Gain/(Loss)
|
December
31,
2007
|
December
31,
2006
|
||||||||||
|
(In
thousands)
|
|||||||||||||||
|
Interest rate
swap loss on 7.625% $325 million note due 2010
|
December
2000
|
10
years
|
$ | (18,724 | ) | $ | (5,461 | ) | $ | (7,334 | ) | ||||
|
Interest rate
swap loss on 7.0% $250 million note due 2012
|
July
2002
|
10
years
|
(12,280 | ) | (5,579 | ) | (6,807 | ) | |||||||
|
Interest rate
swap gain on 9.19% $150 million note due 2005-2024
|
November
1994
|
20
years
|
9,236 | 3,155 | 3,617 | ||||||||||
|
Total
|
$ | (7,885 | ) | $ | (10,524 | ) | |||||||||
|
(14)
|
Commitments and
Contingencies
|
From time to time,
in the normal course of business, the Company is involved in litigation, claims
or assessments that may result in future economic detriment. Where appropriate,
Citrus has made accruals in accordance with FASB Statement No. 5, Accounting
for Contingencies,
in order to provide for such matters. Management believes the final
disposition of these matters will not have a material adverse effect on the
Company’s’ results of operations or financial position.
Florida Gas plans
to seek FERC approval to construct an expansion to increase its natural gas
capacity into Florida by approximately 800 MMcf/d. The Phase VIII Expansion
includes construction of approximately 500 miles of additional large diameter
pipeline and the installation of approximately 170,000 horsepower of additional
compression. Pending FERC approval, which is expected in 2009, Florida Gas
anticipates an in-service date of 2011, at an approximate cost of $2
billion. Florida Gas has signed a 25-year agreement with FPL for 400 MMcf/d of
capacity.
On February 5,
2008, Citrus entered into a $500 million unsecured construction and term loan
agreement (Citrus Credit
Agreement) with a wholly owned subsidiary of FPL Group Capital Inc.,
which is a wholly-owned subsidiary of FPL Group, Inc. Citrus will contribute the
proceeds of this loan to Florida Gas in order to finance a portion of the Phase
VIII Expansion. The Citrus Credit Agreement provides for a single $500 million
draw after Florida Gas’ receipt of a certificate from the FERC authorizing
construction of the Phase VIII Expansion and Citrus’ satisfaction of customary
conditions precedent. On or before the Phase VIII Expansion in-service date, the
construction loan will convert to an amortizing 20-year term loan with a $300
million balloon payment at maturity. The loan requires semi-annual payments of
principal beginning five years and six months after the conversion to a term
loan. The Citrus Credit Agreement provides for interest on the outstanding
principal amount at the rate of six-month LIBOR plus 535 basis points prior to
conversion to a term loan and at the twenty-year treasury rate plus 535 basis
points after conversion to a term loan. The loan is not guaranteed by Florida
Gas and does not include a prepayment option. The Citrus Credit Agreement
contains certain customary representations, warranties and covenants and
requires the execution of a negative pledge agreement by Florida
Gas.
The Florida
Department of Transportation, Florida’s Turnpike Enterprise (FDOT/FTE) has various
turnpike widening projects that have or may, over time, impact one or more of
Florida Gas’ mainline pipelines co-located in FDOT/FTE rights-of-way. The first
phase of the turnpike project includes replacement of approximately 11.3 miles
of its existing 18- and 24-inch pipelines located in FDOT/FTE right-of-way in
Florida. The estimated cost of such replacement is approximately $110 million,
including AFUDC. Florida Gas is also in discussions with the FDOT/FTE related to
additional projects that may affect Florida Gas’ 18- and 24-inch pipelines
within FDOT/FTE right-of-way. The total miles of pipe that may ultimately be
affected by all of the FDOT/FTE widening projects, and any associated relocation
and/or right-of-way costs, cannot be determined at this time.
Under certain
conditions, existing agreements between Florida Gas and the FDOT/FTE require the
FDOT/FTE to provide any new right-of-way needed for relocation of the pipelines
and for Florida Gas to pay for rearrangement or relocation costs. Under certain
other conditions, Florida Gas may be entitled to reimbursement for the costs
associated with relocation, including construction and right-of-way costs. On
January 25, 2007, Florida Gas filed a complaint against FDOT/FTE in the
Seventeenth Judicial Circuit, Broward County, Florida, to seek relief for three
specific sets of FDOT widening projects in Broward County. The complaint seeks
damages for breach of easement and relocation agreements for the one set of
projects on which construction has already commenced, and injunctive relief as
well as damages for the two other sets of projects upon which construction has
yet to commence. On April 24, 2007 the FDOT/FTE filed a complaint against
Florida Gas in the Ninth Judicial Circuit, Orange County, Florida, to seek a
declaratory judgment that under the existing agreements Florida Gas is liable
for the costs of relocation associated with such projects and is not entitled to
certain other rights. On August 7, 2007 the Orange County Court granted a motion
by Florida Gas to abate and stay the Orange County action. The FDOT/FTE filed an
amended answer and counterclaim against Florida Gas on February 8, 2008 in the
Broward County action. The counterclaim alleges Florida Gas is subject to
estoppel and breach of contract regarding removal from service of the existing
pipelines on the project currently under construction and seeks a declaratory
judgment that Florida Gas is responsible for all relocation costs and is not
entitled to workspace and uniform minimum area precluding FDOT/FTE activity. On
February 14, 2008 the case was transferred to the Broward County Complex
Business Civil Division 07. As a result, the March 10, 2008 hearing on the
motion by Florida Gas for a temporary injunction enjoining the FDOT/FTE
interference with the pipelines of Florida Gas will be rescheduled.
On October 24,
2007, Florida Gas filed a complaint in the US District Court of the Northern
District of Florida, Tallahassee Division, against Stephanie C. Kopelousos
(Kopelousos) in her
official capacity as the Secretary of the Florida Department of Transportation,
seeking to enjoin Kopelousos from violating federal law in connection with
construction of the FDOT/FTE Golden Glades project, a new toll plaza in
Miami-Dade County, Florida. Florida Gas seeks a declaratory judgment that
certain Florida statutes are preempted by federal law to the extent such state
statutes purport to regulate the abandonment or relocation schedule for the
federally regulated pipelines of Florida Gas and prospective preliminary and
permanent injunctive relief enjoining Kopelousos from proceeding with
construction on the Golden Glades project over and around such pipelines.
Kopelousos has filed a motion to dismiss the complaint and Florida Gas has
responded. Based upon representations by the FDOT/FTE that the Golden Glades
project has been moved to 2013, the parties entered into a joint stipulation of
dismissal without prejudice on February 15, 2008.
Should Florida Gas
be denied reimbursement by the FDOT/FTE for any possible relocation expenses,
such costs are expected to be covered by operating cash flows and additional
borrowings. Florida Gas expects to seek rate recovery at FERC for all reasonable
and prudent costs incurred in relocating its pipelines to accommodate the
FDOT/FTE to the extent not reimbursed by the FDOT/FTE. There can be no assurance
that Florida Gas will be successful in obtaining complete reimbursement for any
such relocation costs from the FDOT/FTE or from its customers or that the timing
of reimbursement will fully compensate Florida Gas for its costs.
Florida Gas and
Trading previously filed bankruptcy-related claims against Enron and other
affiliated bankrupt companies totaling $220.6 million. Of these claims, Florida
Gas and Trading filed claims totaling $68.1 and $152.5 million, respectively.
Florida Gas and Enron agreed on the amount of the claim at $13.3 million, and
Florida Gas assigned its claims to a third party and received $3.4 million in
June 2005. Trading’s claim was for rejection damages on two physical/financial
swaps and a gas sales contract, as well as certain delinquent amounts owed
pre-petition. In March 2005, Enron North America Corp. (ENA) filed objections to
Trading’s claim. In September 2006 the judge issued an order which rejected
certain of Trading’s arguments and ruled that a contract under which ENA had an
in the money position against Trading could be offset against a related contract
under which Trading had an in the money position against ENA. The result of the
order was a reduction in the allowable amount of Trading’s initial claim to
$22.7 million. The parties reached a settlement on the amount of the allowed
claim which was approved by the bankruptcy court in March 2007. Citrus fully
reserved for the amounts in 2001 and sold the receivable claim in the second
quarter of 2007 to a third party for a pre-tax gain on $11.4 million. The gain
has been reported in Other,
net in the accompanying Consolidated Statements of Income, which is
consistent with the presentation of the original write-off recorded in
2001.
On March 7, 2003,
Trading filed an action, requesting the court to declare that Duke Energy LNG
Sales, Inc. (Duke) breached a natural gas trading contract by failing to provide
sufficient volumes of gas to Trading. Duke sent Trading a notice of termination
of the contract and answered and filed a counterclaim, arguing that Trading
failed to timely increase the amount of a letter of credit that was required of
Trading under the contract, and that Trading had breached a “resale restriction”
on the gas. On June 2, 2003, Trading notified Duke that, because Duke had
defaulted on the contract and failed to cure, Trading was terminating the
contract effective as of June 5, 2003. On August 8, 2003, Trading sent its final
“termination payment” invoice to Duke in the amount of $187 million, and
recorded a receivable of $75 million (subsequently reduced by $6.5 million to
$68.5 million, reflected in Other Assets at December 31,
2006, to provide for a related settlement, see below). After denying motions for
summary judgment by both parties, the judge ordered the parties to attempt to
narrow the scope of the issues to be tried. Pre-trial conferences were held in
January 2007, a jury was selected and opening arguments were scheduled.
Following the judge’s rulings on certain matters, on January 29, 2007, Trading,
Citrus, Southern Union and El Paso (collectively, Citrus Parties) entered into a
settlement regarding litigation with Spectra Energy LNG Sales, Inc., formerly
known as Duke Energy LNG Sales, Inc. (Duke), and its parent company Spectra
Energy Corporation (collectively, Spectra), whereby Spectra agreed to pay $100
million to Trading, which was received on January 30, 2007. Citrus recorded a
pre-tax gain of $24 million in the first quarter of 2007. This gain has been
reported in Other, net
in the accompanying Consolidated Statements of Income, which is
consistent with the historical results of Trading’s activities.
In June 2004 the
Company recorded an accrual for a contingent obligation of up to $6.5 million to
terminate a gas sales contract with a third party. The contingent obligation was
extinguished with a payment to the third party on February 6, 2007 of $6.5
million from proceeds resulting from the settlement of the Duke
litigation.
Jack Grynberg, an
individual, filed actions for damages against a number of companies, including
Florida Gas and Citrus, now transferred to the U.S. District Court for the
District of Wyoming, alleging mismeasurement of gas volumes and Btu content,
resulting in lower royalties to mineral interest owners. On October 20, 2006,
the District Judge adopted in part the earlier recommendation of the Special
Master in the case and ordered the dismissal of the case against the defendants.
Grynberg is appealing that action to the Tenth Circuit Court of Appeals.
Grynberg’s opening brief was filed on July 31, 2007. Respondents filed their
brief rebutting Grynberg’s arguments on November 21, 2007. Florida Gas believes
that its measurement practices conformed to the terms of its FERC gas tariffs,
which were filed with and approved by FERC. As a result, Florida Gas believes
that it has meritorious defenses to these lawsuits (including FERC-related
affirmative defenses, such as the filed rate/tariff doctrine, the
primary/exclusive jurisdiction of FERC, and the defense that Florida Gas
complied with the terms of its tariffs) and will continue to vigorously defend
against them, including any appeal from the dismissal of the Grynberg case. The
Company does not believe the outcome of this case will have a material adverse
effect on its financial position, results of operations or cash
flows.
Pursuant to the
requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934,
Southern Natural Gas Company has duly caused this report to be signed on its
behalf by the undersigned, thereunto duly authorized on the 26th day
of February 2010.
|
SOUTHERN
NATURAL GAS COMPANY
|
|||
|
|
By:
|
/s/ James C. Yardley | |
|
James C.
Yardley
|
|||
|
President
|
|||
Pursuant to the
requirements of the Securities Exchange Act of 1934, this report has been signed
below by the following persons on behalf of Southern Natural Gas Company and in
the capacities and on the dates indicated:
|
Signature
|
Title
|
Date
|
|
/s/James C.
Yardley
|
President and
Management Committee
|
February 26,
2010
|
|
James C.
Yardley
|
Member
(Principal Executive Officer)
|
|
|
/s/John R.
Sult
|
Senior Vice
President and
|
February 26,
2010
|
|
John R.
Sult
|
Chief
Financial Officer
|
|
|
(Principal
Financial Officer)
|
||
|
/s/ Rosa P.
Jackson
|
Vice
President and Controller
|
February 26,
2010
|
|
Rosa P.
Jackson
|
(Principal
Accounting Officer)
|
|
|
/s/Daniel B.
Martin
|
Senior Vice
President and Management
|
February 26,
2010
|
|
Daniel B.
Martin
|
Committee
Member
|
|
|
/s/Norman G.
Holmes
|
Senior Vice
President,
|
February 26,
2010
|
|
Norman G.
Holmes
|
Chief
Commercial Officer and Management Committee Member
|
|
|
/s/Michael J.
Varagona
|
Vice
President and
|
February 26,
2010
|
|
Michael J.
Varagona
|
Management
Committee Member
|
|
SOUTHERN
NATURAL GAS COMPANY
EXHIBIT
INDEX
December
31, 2009
Each exhibit
identified below is filed as part of this report. Exhibits filed with this
report are designated by “*”. All exhibits not so designated are incorporated
herein by reference to a prior filing as indicated.
|
Exhibit
|
||
|
Number
|
Description
|
|
|
3.A
|
Certificate
of Conversion (Exhibit 3.A to our Current Report on Form 8-K
filed with the SEC on November 7, 2007).
|
|
|
3.B
|
Statement of
Partnership Existence (Exhibit 3.B to our Current Report on
Form 8-K filed with the SEC on November 7, 2007).
|
|
|
3.C
|
General
Partnership Agreement dated November 1, 2007 (Exhibit 3.C to our
Current Report on Form 8-K filed with the SEC on November 7,
2007).
|
|
|
3.D
|
First
Amendment to the General Partnership Agreement of Southern Natural Gas
Company, dated September 30, 2008 (Exhibit 3.A to our Current Report
on Form 8-K filed with the SEC on October 6, 2008).
|
|
|
4.A
|
Indenture
dated June 1, 1987 between Southern Natural Gas Company and
Wilmington Trust Company (as successor to JPMorgan Chase Bank, formerly
known as The Chase Manhattan Bank), as Trustee (Exhibit 4.A to our
Annual Report on Form 10-K for the year ended December 31, 2006,
filed with the SEC on February 28, 2007); First Supplemental Indenture,
dated as of September 30, 1997, between Southern Natural Gas Company
and the Trustee (Exhibit 4.A.1 to our Annual Report on Form 10-K
for the year ended December 31, 2006, filed with the SEC on February 28,
2007); Second Supplemental Indenture dated as of February 13, 2001,
between Southern Natural Gas Company and the Trustee (Exhibit 4.A.2
to our Annual Report on Form 10-K for the year ended December 31,
2006, filed with the SEC on February 28, 2007); Third Supplemental
Indenture dated as of March 26, 2007 between Southern Natural Gas
Company and The Bank of New York Trust Company, N.A., as trustee
(Exhibit 4.A to our Current Report on Form 8-K filed with the
SEC on March 28, 2007); Fourth Supplemental Indenture dated as of
May 4, 2007 among Southern Natural Gas Company, Wilmington Trust
Company (solely with respect to certain portions thereof) and The Bank of
New York Trust Company, N.A. (Exhibit 4.C to our quarterly report on
Form10-Q for the period ended March 31, 2007, filed with the SEC on May 8,
2007); Fifth Supplemental Indenture dated October 15, 2007 by and
among SNG, Wilmington Trust Company, as trustee, and The Bank of New York
Trust Company, N.A., as series trustee, to Indenture dated as of
June 1, 1987 (Exhibit 4.A to our Current Report on Form 8-K
filed with the SEC on October 16, 2007); Sixth Supplemental Indenture
dated November 1, 2007 by and among SNG, Southern Natural Issuing
Corporation, Wilmington Trust Company, as trustee, and The Bank of New
York Trust Company, N.A., as series trustee, to Indenture dated as of
June 1, 1987 (Exhibit 4.A to our Current Report on Form 8-K
filed with the SEC on November 7, 2007).
|
|
|
4.B
|
Form of 5.90%
Note due 2017 (included as Exhibit A to Exhibit 4.A of our
Current Report on Form 8-K filed with the SEC on March 28,
2007).
|
|
|
*4.C
|
Indenture
dated as of March 5, 2003 between Southern Natural Gas Company and
The Bank of New York Trust Company, N.A., successor to The Bank of New
York, as Trustee.
|
|
10.D
|
Registration
Rights Agreement, dated as of March 26, 2007, among Southern Natural
Gas Company and Banc of America Securities LLC, Citigroup Global Markets
Inc., Credit Suisse Securities (USA) LLC, BNP Paribas Securities
Corp., HVB Capital Markets, Inc., Greenwich Capital Markets, Inc., Scotia
Capital (USA) Inc., and SG Americas Securities, LLC
(Exhibit 10.A to our Current Report on Form 8-K filed with the
SEC on March 28, 2007).
|
|
|
*12
|
Ratio of
Earnings to Fixed Charges.
|
|
|
*21
|
Subsidiaries
of Southern Natural Gas Company
|
|
|
*23.A
|
Consent of
Independent Registered Public Accounting Firm Ernst & Young,
LLP.
|
|
| *23.B |
Consent of
Independent Registered Public Accounting Firm PricewaterhouseCoopers,
LLP.
|
|
|
*31.A
|
Certification
of Principal Executive Officer pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002.
|
|
|
*31.B
|
Certification
of Chief Financial Officer pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002.
|
|
|
*32.A
|
Certification
of Principal Executive Officer pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002.
|
|
|
*32.B
|
Certification
of Chief Financial Officer pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002.
|
|
81