UNITED
STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON,
D.C. 20549
FORM
10-K
(Mark
One)
x ANNUAL REPORT PURSUANT TO SECTION 13 OR
15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For
the fiscal year ended December 31, 2008
OR
o TRANSITION REPORT PURSUANT TO SECTION
13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from _______________ to _______________
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Commission file
number: 01-32665
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BOARDWALK
PIPELINE PARTNERS, LP
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(Exact
name of registrant as specified in its charter)
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DELAWARE
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(State
or other jurisdiction of incorporation or organization)
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20-3265614
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(I.R.S.
Employer Identification No.)
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9
Greenway Plaza, Suite 2800
Houston,
Texas 77046
(866)
913-2122
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(Address
and Telephone Number of Registrant’s Principal Executive
Office)
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Securities
registered pursuant to Section 12(b) of the Act:
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Title
of each class
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Name
of each exchange on which registered
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Common
Units Representing Limited Partner Interests
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New
York Stock Exchange
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Securities registered pursuant
to Section 12(g) of the Act: NONE
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Indicate
by check mark if the registrant is a well-known seasoned issuer, as defined in
Rule 405 of the Securities Act. Yes x No o
Indicate
by check mark if the registrant is not required to file reports pursuant to
Section 13 or Section 15(d) of the Act. Yes o No x
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 x Noo
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. x
Indicate
by check mark whether the registrant is a large accelerated filer, an
accelerated filer, a non-accelerated filer or a smaller reporting
company. See the definitions of “large accelerated filer,”
“accelerated filer” and “smaller reporting company” in Rule 12b-2 of the
Exchange Act. (Check one)
Large
accelerated filer x Accelerated
filer o Non-accelerated
filer o Smaller
reporting company o
Indicate
by check mark whether the registrant is a shell company (as defined in Rule
12b-2 of the Act). Yes ¨ No x
The
aggregate market value of the common units of the registrant held by
non-affiliates as of June 30, 2008, was approximately $1.1 billion. As of
February 13, 2009, the registrant had 154,934,609 common units outstanding and
22,866,667 Class B units outstanding.
Documents
incorporated by reference. None.
TABLE
OF CONTENTS
2008
FORM 10-K
BOARDWALK
PIPELINE PARTNERS, LP
Item
1B. Unresolved Staff Comments 22
Item
3. Legal Proceedings 22
Item
4. Submission of Matters to a Vote of Security Holders 22
Item
5. Market for Registrant's Common Equity, Related Stockholder Matters
and Issuer Purchases of Equity Securities 23
Item
6. Selected Financial Data 26
Item
7. Management's Discussion and Analysis of Financial Condition
and Results of Operations 28
Item
7A. Quantitative and Qualitative Disclosures About Market
Risk 40
Item
8. Financial Statements and Supplementary Data 42
Item
9. Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure 82
Item
9A. Controls and Procedures 82
Item
9B. Other Information 84
Item
10. Directors and Executive Officers of the Registrant 85
Item
11. Executive Compensation 89
Item
12. Security Ownership of Certain Beneficial Owners and Management 101
Item
13. Certain Relationships and Related Transactions, and Director
Independence 102
Item
14. Principal Accounting Fees and Services 103
Item
15. Exhibits and Financial Statement Schedules 104
Introduction
We are a Delaware limited partnership formed in 2005. Our business is conducted
by our subsidiary, Boardwalk Pipelines, LP (Boardwalk Pipelines) and its
subsidiaries, Gulf Crossing Pipeline Company LLC (Gulf Crossing), Gulf South
Pipeline Company, LP (Gulf South) and Texas Gas Transmission, LLC (Texas Gas).
Boardwalk Pipelines Holding Corp. (BPHC), a wholly-owned subsidiary of Loews
Corporation (Loews), owns 107.5 million of our common units, all 22.9 million of
our class B units and, through Boardwalk GP, LP, an indirect wholly-owned
subsidiary of BPHC, holds the 2% general partner interest and all of our
incentive distribution rights (IDRs). The common units, class B units and
general partner interest owned by BPHC represent approximately 74% of our equity
interests, excluding the IDRs. Our Partnership Interests, in
Item 5 contains more information on how we calculate BPHC’s equity ownership.
Our common units are traded under the symbol “BWP” on the New York Stock
Exchange (NYSE).
Our
Business
Through
our subsidiaries, we own and operate three interstate natural gas pipeline
systems including integrated storage facilities. Our pipeline systems originate
in the Gulf Coast region and extend northeasterly to the Midwestern states of
Tennessee, Kentucky, Illinois, Indiana and Ohio. The pipeline portion of the
Gulf Crossing assets was placed in service in January and February
2009.
We serve a broad mix of customers,
including marketers, local distribution companies (LDCs), producers, electric
power generation plants, interstate and intrastate pipelines and direct
industrial users. Our transportation and storage rates and general terms and
conditions of service are established by, and subject to review and revision by,
the Federal Energy Regulatory Commission (FERC). These rates are designed based
upon certain assumptions to allow us the opportunity to recover the cost of
providing our transportation and storage services and earn a reasonable return
on equity. However, it is possible that we may not recover those costs or earn a
reasonable return. Our firm and interruptible storage rates for Gulf South and
the storage services associated with Phase III of the Western Kentucky Storage
Expansion project on Texas Gas are market-based pursuant to authority granted by
FERC.
We provide a significant portion of our
pipeline transportation and storage services through firm contracts under which
our customers pay monthly capacity reservation charges (which are charges owed
regardless of actual pipeline or storage capacity utilization). Other charges
are based on actual utilization of the capacity. For the twelve months ended
December 31, 2008, approximately 66% of our revenues were derived from capacity
reservation charges under firm contracts, approximately 22% of our revenues were
derived from charges based on actual utilization under firm contracts and
approximately 12% of our revenues were derived from interruptible
transportation, interruptible storage, parking and lending (PAL) and other
services.
Our
Pipeline and Storage Systems
Our operating subsidiaries own and
operate approximately 14,000 miles of pipeline, directly serving customers in
twelve states and indirectly serving customers throughout the northeastern and
southeastern United States (U.S.) through numerous interconnections with
unaffiliated pipelines. In 2008, our pipeline systems transported approximately
1.7 trillion cubic feet (Tcf) of gas. Average daily throughput on our pipeline
systems during 2008 was approximately 4.8 billion cubic feet (Bcf). Our natural
gas storage facilities are comprised of eleven underground storage fields
located in four states with aggregate working gas capacity of approximately
160.0 Bcf. We conduct all of our natural gas transportation and integrated
storage operations through our operating subsidiaries as one
segment.
The
principal sources of supply for our pipeline systems are regional supply hubs
and market centers located in the Gulf Coast region, including offshore
Louisiana, the Perryville, Louisiana area, the Henry Hub in Louisiana, and Agua
Dulce and Carthage, Texas. The Gulf Crossing Expansion and Fayetteville and
Greenville Laterals will provide us access to unconventional Mid-Continent
supplies such as the Caney Woodford Shale in southeast Oklahoma and the
Fayetteville Shale in Arkansas. Carthage, Texas, provides access to
natural gas supplies from the Bossier Sands, Barnett Shale and other gas
producing regions in eastern Texas. The Henry Hub serves as the designated
delivery point for natural gas futures contracts traded on the New York
Mercantile Exchange. We also access wellhead supplies in northern and southern
Louisiana and Mississippi, imported liquefied natural gas (LNG) through several
Gulf Coast LNG terminals, one of which is directly connected to our pipeline
systems, and Canadian natural gas through an unaffiliated pipeline interconnect
at Whitesville, Kentucky.
Our
Gulf Crossing System
In the
first quarter 2009, we placed in service the pipeline portion of our Gulf
Crossing Project consisting of approximately 350 miles of 42-inch pipeline
originating near Sherman, Texas, and proceeding to the Perryville, Louisiana
area. We expect Gulf Crossing’s initial compression facilities to be placed in
service during the first quarter 2009. Gulf Crossing’s supply sources are mainly
unconventional gas sources in the Barnett Shale and Caney Woodford Shale. The
end markets for Gulf Crossing are in the Midwest, Northeast, Southeast and
Florida through interconnections with Texas Gas, Gulf South and unaffiliated
pipelines. See Expansion Projects for more information regarding our Gulf
Crossing Project.
Our
Gulf South System
Our Gulf
South pipeline system is located along the Gulf Coast in the states of Texas,
Louisiana, Mississippi, Alabama and Florida. This system is composed
of:
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approximately
7,700 miles of pipeline, having a peak-day delivery capacity of
approximately 5.0 Bcf per day;
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38
compressor stations having an aggregate of approximately 378,900
horsepower; and
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two
natural gas storage fields located in Louisiana and Mississippi, having
aggregate storage capacity of approximately 131.0 Bcf of gas, of which
approximately 83.0 Bcf is designated as working
gas.
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The
on-system markets directly served by the Gulf South system are generally located
in eastern Texas, Louisiana, southern Mississippi, southern Alabama, and the
Florida panhandle. These markets include LDCs and municipalities across the
system, including New Orleans, Louisiana; Jackson, Mississippi; Mobile, Alabama;
and Pensacola, Florida, and end-users located across the system, including the
Baton Rouge to New Orleans industrial corridor and Lake Charles, Louisiana. Gulf
South also has indirect access to off-system markets through numerous
interconnections with other interstate and intrastate pipelines and storage
facilities. These pipeline interconnections provide access to markets throughout
the northeastern and southeastern U.S.
Gulf South’s Bistineau, Louisiana, gas
storage facility has approximately 78.0 Bcf of working gas storage capacity,
with a maximum injection rate of 480 million cubic feet (MMcf) per day and a
maximum withdrawal rate of 870 MMcf per day. Gulf South currently sells firm and
interruptible storage services at Bistineau under FERC-approved market-based
rates. Gulf South’s Jackson, Mississippi, gas storage facility has approximately
5.0 Bcf of working gas storage capacity, with a maximum injection rate of 100
MMcf per day and a maximum withdrawal rate of 250 MMcf per day. The Jackson gas
storage facility is used for operational purposes and its capacity is not
offered for sale to the market.
Our
Texas Gas System
Our Texas
Gas pipeline system originates in Louisiana and in East Texas and runs north and
east through Louisiana, Arkansas, Mississippi, Tennessee, Kentucky, Indiana, and
into Ohio, with smaller diameter lines extending into Illinois. This system is
composed of:
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approximately
5,950 miles of pipeline, having a peak-day delivery capacity of
approximately 3.8 Bcf per day which includes deliveries to pipeline
interconnects in southern
Louisiana;
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31
compressor stations having an aggregate of approximately 552,700
horsepower; and
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nine
natural gas storage fields located in Indiana and Kentucky, having
aggregate storage capacity of approximately 180.0 Bcf of gas, of which
approximately 77.0 Bcf is designated as working
gas.
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The market area directly served by
Texas Gas encompasses eight states in the South and Midwest and includes the
Memphis, Tennessee; Louisville, Kentucky; Cincinnati and Dayton, Ohio; and
Evansville and Indianapolis, Indiana metropolitan areas. Texas Gas also has
indirect market access to the Northeast through interconnections with
unaffiliated pipelines.
Texas Gas owns a majority of the gas in its storage fields which it uses to meet
the operational requirements of its transportation and storage customers and the
requirements of its no-notice transportation service (NNS), which allows
customers to draw from storage gas during the winter season to be repaid in-kind
during the following summer season. A large portion of the gas delivered by the
Texas Gas system is used for heating, resulting in higher daily requirements
during winter months. Texas Gas also offers summer no-notice transportation
service (SNS) designed primarily to meet the needs of electrical power
generation facilities during the summer season.
Expansion
Projects
Pipeline
Expansion Projects:
The
following paragraphs describe in more detail each of our recently completed and
ongoing pipeline expansion projects:
Southeast Expansion. We have
constructed and placed in service 111 miles of 42-inch pipeline and related
compression assets, originating near Harrisville, Mississippi, and extending to
an interconnect with Transcontinental Pipe Line Company (Transco) in Choctaw
County, Alabama (Transco Station 85). The pipeline currently has 1.8 Bcf of
peak-day transmission capacity. We have applied to the Pipelines and Hazardous
Materials Safety Administration (PHMSA) for authority to operate under a special
permit that would allow the pipeline to be operated at higher operating
pressures, thereby increasing the peak-day transmission capacity to 1.9 Bcf per
day. Customers have contracted at fixed rates for substantially all of the
operational capacity of this pipeline, with such contracts having a
weighted-average term of approximately 9.3 years (including a capacity lease
agreement with Gulf Crossing ). In February 2009, we placed in service the
remaining compression assets related to this project and construction on this
project is complete.
Gulf Crossing Project. In
January and February 2009, we completed construction and placed in service the
pipeline portion of the assets associated with our Gulf Crossing Project, which
consists of approximately 357 miles of 42-inch pipeline that begins near
Sherman, Texas, and proceeds to the Perryville, Louisiana area. We expect the
initial compression to be placed in service during the first quarter 2009,
providing Gulf Crossing with a peak-day transmission capacity of 1.2 Bcf per
day. We have applied to PHMSA for authority to operate under a special permit
that would allow the pipeline to be operated at higher operating pressures,
thereby increasing its peak-day transmission capacity to 1.4 Bcf per day. The
peak-day transmission capacity would increase from 1.4 Bcf per day to 1.7 Bcf
per day following the construction of additional compression facilities which we
expect to place in service in the first quarter 2010, subject to FERC approval.
Customers have contracted at fixed rates for substantially all of the
operational capacity of this pipeline, with such contracts having a
weighted-average term of approximately 9.5 years.
Fayetteville and Greenville
Laterals. We are constructing two laterals on our Texas Gas pipeline
system to transport gas from the Fayetteville Shale area in Arkansas to markets
directly and indirectly served by our existing interstate pipelines. The
Fayetteville Lateral will originate in Conway County, Arkansas, and proceed
southeast through the Bald Knob, Arkansas area, to an interconnect with the
Texas Gas mainline in Coahoma County, Mississippi, consisting of approximately
165 miles of 36-inch pipeline. The Greenville Lateral will originate at the
Texas Gas mainline near Greenville, Mississippi, and proceed east to the
Kosciusko, Mississippi area, consisting of approximately 95 miles of 36-inch
pipeline. The Greenville Lateral will provide customers access to additional
markets, located primarily in the Midwest, Northeast and Southeast. In December
2008, we placed in service the header, or first 66 miles, of the Fayetteville
Lateral. In January 2009, we placed in service a portion of the Greenville
Lateral which originates at our Texas Gas mainline and continues to an
interconnect with the Tennessee 800 line in Holmes County, Mississippi. Included
in the Fayetteville header is a section of 18-inch pipeline under the Little Red
River in Arkansas which will be replaced with 36-inch pipeline once a new
horizontal directional drill is completed under the river. We expect the 36-inch
pipeline installation to be completed in the second quarter 2009. The initial
peak-day transmission capacity of each of these laterals is approximately 0.8
Bcf per day.
During
2008, we executed contracts for additional capacity that will require us to add
compression to increase the peak-day transmission capacity of these laterals to
approximately 1.3 Bcf per day for the Fayetteville Lateral and 1.0 Bcf per day
for the Greenville Lateral. To meet this requirement we will add compression
facilities to this project and we have applied to PHMSA for authority to operate
under a special permit that would allow the Fayetteville Lateral to be operated
at higher operating pressures, in addition to replacing the section of 18-inch
pipeline noted above. We expect the new compression to be in service during
2010, subject to FERC approval. Customers have contracted at fixed rates for
substantially all of the operational capacity of these laterals, with such
contracts having a weighted-average term of approximately 9.9
years.
Prior to
placing a new pipeline or lateral in service, we conduct extensive tests to
ensure that the pipeline can operate safely at normal operating pressures.
Further, to operate at higher operating pressures under the PHMSA special
permits discussed above, we design, build and conduct additional stringent tests
to ensure the pipeline’s integrity. In performing such tests on one of our
pipeline expansions we discovered some anomalies in a small number of pipe
segments installed on the East Texas to Mississippi segment of our Gulf South
pipeline system (the East Texas Pipeline). As a result, and as a prudent
operator, we elected to reduce operating pressures on this pipeline to 20% below
its previous operating level, which was below the pipeline’s maximum non-special
permit operating pressures, while we investigate further and replace the
affected pipe segments where necessary. We have notified PHMSA of these
anomalies and our ongoing testing and remediation plans and we will keep them
informed as our activities progress. For a further discussion, see Item 1A,
Risk Factors and Item
7, MD&A – Factors that Impact our Results of
Operations.
Storage
Expansion Project:
We are
also engaged in the following storage expansion project:
Western Kentucky Storage Expansion
Phase III. We are developing 8.3 Bcf of new working gas capacity at our
Midland storage facility, for which FERC has granted us market-based rate
authority. This expansion is supported by 10-year precedent agreements for 5.1
Bcf of storage capacity. In the fourth quarter 2008, we placed in service
approximately 5.4 Bcf of storage capacity. We are in discussion with potential
customers for the remaining capacity which we expect to place in service in the
fourth quarter 2009.
Nature
of Contracts
We
contract with our customers to provide transportation services and storage
services on a firm and interruptible basis. We also provide combined firm
transportation and storage services, which we refer to as NNS and SNS. In
addition, we provide interruptible PAL services.
Transportation Services. We
offer transportation services on both a firm and interruptible basis. Our
customers choose, based upon their particular needs, the applicable mix of
services depending upon availability of pipeline capacity, price of service and
the volume and timing of the customer’s requirements. Firm transportation
customers reserve a specific amount of pipeline capacity at specified receipt
and delivery points on our system. Firm customers generally pay fees based on
the quantity of capacity reserved regardless of use, plus a commodity and fuel
charge paid on the volume of gas actually transported. Capacity reservation
revenues derived from a firm service contract are generally consistent during
the contract term, but can be higher in winter periods than the rest of the
year, especially related to NNS agreements. Firm transportation contracts
generally range in term from one to ten years, although firm transportation
contracts can be offered for terms less than one year. In providing
interruptible transportation service, we agree to transport gas for a customer
when capacity is available. Interruptible transportation service customers pay a
commodity charge only for the volume of gas actually transported, plus a fuel
charge. Interruptible transportation agreements have terms ranging from
day-to-day to multiple years, with rates that change on a daily, monthly or
seasonal basis.
Storage Services. We offer
customers storage services on both a firm and interruptible basis. Firm storage
customers reserve a specific amount of storage capacity, including injection and
withdrawal rights, while interruptible customers receive storage capacity and
injection and withdrawal rights when it is available. Similar to firm
transportation customers, firm storage customers generally pay fees based on the
quantity of capacity reserved plus an injection and withdrawal fee. Firm storage
contracts typically range in term from one to ten years. Interruptible storage
customers pay for the volume of gas actually stored plus injection and
withdrawal fees. Generally, interruptible storage agreements are for monthly
terms. Unlike most FERC-regulated pipelines, Gulf South is authorized to charge
market-based rates for its firm and interruptible storage and Texas Gas is
authorized to charge market-based rates for the firm and interruptible storage
services associated with Phase III of its Western Kentucky Storage Expansion
project.
No-Notice Service and Summer
No-Notice Service. NNS and SNS consist of a combination of firm
transportation and storage services that allow customers to withdraw gas from
storage with little or no notice. Customers pay a reservation charge based upon
the capacity reserved plus a commodity and fuel charge based on the volume of
gas actually transported. In accordance with its tariff, Texas Gas loans stored
gas to its no-notice customers who are obligated to repay the gas
in-kind.
Parking and Lending Service.
PAL is an interruptible service offered to customers providing them the ability
to park (inject) or borrow (withdraw) gas into or out of our pipeline systems at
a specific location for a specific period of time. Customers pay for PAL service
in advance or on a monthly basis depending on the terms of the
agreement.
Customers
and Markets Served
We
transport natural gas for a broad mix of customers, including marketers, LDCs,
producers, electric power generators, intrastate and interstate pipelines and
direct industrial users located throughout the Gulf Coast, Midwest and Northeast
regions of the U.S. Our Gulf Crossing system moves gas from mainly
unconventional gas sources, the Barnett and Caney Woodford Shales, to the
midwest, northeast, southeast and Florida through interconnects with Texas Gas
and Gulf South as well as other interstate pipelines. Customers on our Gulf
South system are located throughout its service area and indirect customers are
accessed through numerous interconnects on unaffiliated pipeline systems. Our
Texas Gas system primarily moves gas for its customers in a northeasterly
direction to serve markets directly connected to its system and also serves
indirect customer markets through interconnects with other interstate
pipelines.
We
contract directly with end-use customers and with marketers, producers and other
third parties who provide transportation and storage services to end-users.
Based on 2008 revenues, our customer mix was as follows: marketers (49%), LDCs
(21%), producers (16%), power generators (6%), pipelines (3%) and industrial
users and others (5%). Based upon 2008 revenues, our deliveries were as follows:
pipeline interconnects (43%), LDCs (27%), storage activities (9%), power plants
(6%), industrial end-users (5%) and other (10%). There were no customers that
made up more than 10% of our 2008 operating revenues; however, as our remaining
expansion projects are completed in 2009 and 2010, we expect that our customer
mix will change. Please refer to Item 1A, Risk Factors, regarding risks
associated with our customers and changing customer mix.
Marketers. Natural gas
marketing companies utilize our services to provide services to our other
customer groups as well as to customer groups in off-system markets. The
services may include combined gas supply management, transportation and storage
services to support the needs of the other customer groups. Some of the
marketers are sponsored by LDCs and, to a lesser extent, producers.
LDCs. Most of our LDC
customers use firm transportation services, including NNS. We serve
approximately 185 LDCs located across our pipeline systems. The demand of these
customers peaks during the winter heating season.
Producers. Producers of
natural gas use our services to transport gas supplies from producing areas,
primarily shale plays in Texas, Oklahoma and Arkansas, to supply pools and to
the other customer groups, both on and off of our systems. Producers
contract with us for storage services to store excess production and optimize
the ultimate sales prices for their gas.
Power Generators. We have the
ability to serve major electrical power generators in ten states. We are
directly connected to several large natural gas-fired power generation
facilities, some of which are also directly connected to other pipelines. The
demand of the power generating customers peaks during the summer cooling season
which is counter to the winter season peak demands of the LDCs. Most of our
power-generating customers use a combination of SNS, firm and interruptible
transportation services.
Pipelines (off-system). Our
pipeline systems serve as feeder pipelines for long-haul interstate pipelines
serving markets throughout the midwestern, northeastern and southeastern
portions of the U.S. We have numerous interconnects with third-party interstate
and intrastate pipelines.
Industrial End Users. We
provide industrial facilities with a combination of firm and interruptible
transportation services. Our systems are directly connected to industrial
facilities in the Baton Rouge to New Orleans industrial corridor; Lake Charles,
Louisiana; Mobile, Alabama and Pensacola, Florida. We can also access the
Houston Ship Channel through third-party pipelines.
Competition
We
compete with numerous interstate and intrastate pipelines throughout our service
territory to provide transportation and storage services for our customers.
Competition is particularly strong in the Midwest and Gulf Coast states where we
compete with numerous existing pipelines and will compete with several new
pipeline projects that are under construction, including the Rockies Express
Pipeline that will transport natural gas from northern Colorado to eastern Ohio
and the Mid-Continent Express Pipeline that would transport gas from Texas to
Alabama. The principal elements of competition among pipelines are available
capacity, rates, terms of service, access to supply and flexibility and
reliability of service. We compete with these pipelines to maintain current
business levels and to serve new demand and markets. We also compete with other
pipelines for contracts with producers that would support new growth projects
such as our pipeline expansion projects discussed elsewhere in this report. In
addition, regulators’ continuing efforts to increase competition in the natural
gas industry have increased the natural gas transportation options of our
traditional customers. As a result of the regulators’ policies, segmentation and
capacity release have created an active secondary market which increasingly
competes with our pipeline services, particularly on our Texas Gas system.
Additionally, natural gas competes with other forms of energy available to our
customers, including electricity, coal, and fuel oils. To the extent usage of
natural gas decreases due to competition from other fuel sources, throughput on
our system may decrease and the need for customers to contract for our services
may decrease. Despite these competitive conditions, substantially all of the
operating capacity on our pipeline systems, including our expansion projects, is
sold out with a weighted-average contract life of over 6 years.
Seasonality
Our
revenues can be seasonal in nature, affected by weather and natural gas price
volatility. Weather impacts natural gas demand for power generation and heating
needs, which in turn influences the short-term value of transportation and
storage across our pipeline systems. Colder than normal winters or warmer than
normal summers typically result in increased pipeline transportation revenues.
Peak demand for natural gas typically occurs during the winter months, driven by
heating needs. Excluding the impact of our expansion projects that went into
service in 2008, during 2008 approximately 54% of our total operating revenues
were recognized in the first and fourth calendar quarters. The effects of
seasonality on our revenues have been mitigated over the past several years due
to the increased use of gas-fired power generation in the summer months to meet
cooling needs, primarily in the Southeast and Midwest. Generally, revenues from
our expansion projects will be less seasonal in nature due to the structure of
the contracts and the fact that the capacity is held primarily by producers, who
are seeking a market for their production. We expect the impact of seasonality
to further decline in coming years as the full impact of revenues from our
expansion projects is taken into account.
Government
Regulation
FERC
regulates our pipelines under the Natural Gas Act of 1938 (NGA) and the Natural
Gas Policy Act of 1978. FERC regulates, among other things, the rates and
charges for the transportation and storage of natural gas in interstate commerce
and the extension, enlargement or abandonment of facilities under its
jurisdiction. Where required, our operating subsidiaries hold certificates of
public convenience and necessity issued by FERC covering certain of their
facilities, activities and services. FERC also prescribes accounting treatment
for our pipelines which is separately reported pursuant to forms filed with
FERC. The regulatory books and records and other activities of our pipelines may
be periodically audited by FERC.
The
maximum rates that may be charged by Gulf Crossing, Gulf South and Texas Gas for
gas transportation are established through FERC's cost-of-service rate-making
process. The maximum rates that may be charged by us for storage services on
Texas Gas, with the exception of Phase III of the Western Kentucky Storage
Expansion, are also established through FERC's cost-of-service rate-making
process. Key determinants in the cost-of-service rate-making process are the
costs of providing service, the allowed rate of return, throughput assumptions,
the allocation of costs and the rate design. Texas Gas is prohibited
from placing new rates into effect prior to November 1, 2010, and neither Gulf
South nor Texas Gas has an obligation to file a new rate case. Gulf Crossing
will have to either file a rate case or justify its initial firm transportation
rates within three years after the pipeline is fully placed in
service.
We are
also regulated by the U.S. Department of Transportation (DOT) under the Natural
Gas Pipeline Safety Act of 1968, as amended by Title I of the Pipeline Safety
Act of 1979, which regulates safety requirements in the design, construction,
operation and maintenance of interstate natural gas pipelines. In addition, we
will require authority from PHMSA to operate our expansion pipelines, under a
special permit, at higher operating pressures in order to transport all of the
volumes we have contracted for with customers on our expansion
projects.
Our
operations are also subject to extensive federal, state, and local laws and
regulations relating to protection of the environment. Such regulations impose,
among other things, restrictions, liabilities and obligations in connection with
the generation, handling, use, storage, transportation, treatment and disposal
of hazardous substances and waste and in connection with spills, releases and
emissions of various substances into the environment. Environmental regulations
also require that our facilities, sites and other properties be operated,
maintained, abandoned and reclaimed to the satisfaction of applicable regulatory
authorities. These laws include, for example:
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the
Clean Air Act and analogous state laws which impose obligations related to
air emissions;
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the
Water Pollution Control Act, commonly referred to as the Clean Water Act,
and analogous state laws which regulate discharge of wastewaters from our
facilities into state and federal
waters;
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the
Comprehensive Environmental Response, Compensation and Liability Act,
commonly referred to as CERCLA, or the Superfund law, and analogous state
laws which regulate the cleanup of hazardous substances that may have been
released at properties currently or previously owned or operated by us or
locations to which we have sent wastes for disposal;
and
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the
Resource Conservation and Recovery Act, and analogous state laws which
impose requirements for the handling and discharge of solid and hazardous
waste from our facilities.
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Item 1A,
Risk Factors, includes
further discussion regarding our environmental risk factors.
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Effects
of Compliance with Environmental
Regulations
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Note 3 in Item 8 of this Report
contains information regarding environmental compliance.
Employee
Relations
At December 31, 2008, we had 1,128
employees, approximately 90 of whom are covered by a collective bargaining
agreement which expires in April 2011. A satisfactory relationship continues to
exist between management and labor. We maintain various defined contribution
plans covering substantially all of our employees and various other plans which
provide regular active employees with group life, hospital, and medical
benefits, as well as disability benefits. We also have a non-contributory,
defined benefit pension plan and a postretirement medical plan which covers
Texas Gas employees hired prior to certain dates. Note 10 in Item 8 of this
Report contains further discussion of our employee benefits.
Available
Information
Our website is located at www.bwpmlp.com. We make
available free of charge through our website our annual reports on Form 10-K,
which include our audited financial statements, quarterly reports on Form 10-Q,
current reports on Form 8-K and amendments to those reports filed or furnished
pursuant to Section 13(a) or 15(d) of the Exchange Act as soon as we
electronically file such material with the Securities and Exchange Commission
(SEC). These documents are also available at the SEC’s website at www.sec.gov. Additionally,
copies of these documents, excluding exhibits, may be requested at no cost by
contacting Investor Relations, Boardwalk Pipeline Partners, LP, 9 Greenway
Plaza, Suite 2800, Houston, TX 77046.
We also
make available free of charge within the “Governance” section of our website,
and in print to any unitholder who requests, our corporate governance
guidelines, the charter of our Audit Committee, and our Code of Business Conduct
and Ethics. Requests for copies may be directed in writing to: Boardwalk
Pipeline Partners, LP, 9 Greenway Plaza, Suite 2800, Houston, TX 77046,
Attention: Corporate Secretary.
Interested parties may contact the
chairpersons of any of our Board committees, our Board’s independent directors
as a group or our full Board in writing by mail to Boardwalk Pipeline Partners,
LP, 9 Greenway Plaza, Suite 2800, Houston, TX 77046, Attention: Corporate
Secretary. All such communications will be delivered to the director or
directors to whom they are addressed.
Our
business faces many risks. We have described below some of the more material
risks which we and our subsidiaries face. There may be additional risks that we
do not yet know of or that we do not currently perceive to be material that may
also impact our business or the business of our subsidiaries.
Each of
the risks and uncertainties described below could lead to events or
circumstances that may have a material adverse effect on our business, financial
condition, results of operations and cash flows, including our ability to make
distributions to our unitholders.
All of
the information included in this report and any subsequent reports we may file
with the SEC or make available to the public should be carefully considered and
evaluated before investing in any securities issued by us.
Business
Risks
We
are undertaking large, complex expansion projects which involve significant
risks that may adversely affect our business.
We are
currently undertaking several large, complex pipeline and storage expansion
projects, as discussed under Business – Expansion Projects, and we may also
undertake additional expansion projects in the future. In pursuing these and
previous projects, we experienced significant cost overruns and we may
experience cost increases in the future. We also experienced construction delays
and may experience additional delays in the future. Delays in construction could
result from a variety of factors and have resulted in penalties under customer
contracts such as liquidated damage payments and could in the future result in
similar losses. In some cases, certain customers could have the right to
terminate their transportation agreements if the related expansion project is
not completed by a date specified in their precedent agreements.
The cost overruns and construction
delays we experienced have resulted from a variety of factors, including the
following:
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delays
in obtaining regulatory approvals;
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difficult
construction conditions, including adverse weather conditions and
encountering higher density rock formations than
anticipated;
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delays
in obtaining key materials; and
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shortages
of qualified labor and escalating costs of labor and materials resulting
from the high level of construction activity in the pipeline
industry.
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In
pursuing current or future expansion projects, we could experience additional
delays or cost increases for the reasons described above or as a result of other
factors. We may not be able to complete our current or future expansion projects
on the expected terms, cost or schedule, or at all. In addition, we cannot be
certain that, if completed, these projects will perform in accordance with our
expectations. Other areas of our business may suffer as a result of the
diversion of our management’s attention and other resources from our other
business concerns to our expansion projects. Any of these factors could
have a material adverse effect on our ability to realize the anticipated
benefits from our expansion projects. See Business – Expansion Projects for more
information regarding our expansion projects.
Completion
of our expansion projects will require us to raise significant amounts of debt
and equity financing. Ongoing disruption of the credit and capital
markets may hinder or prevent us and our customers from meeting future capital
needs.
Global
financial markets and economic conditions have been, and continue to be,
experiencing extraordinary disruption and volatility following adverse changes
in global capital markets. Recently, market conditions have resulted in numerous
bankruptcies, insolvencies, forced sales of financial institutions as well as
market intervention by governments around the globe. The debt and equity
capital markets are exceedingly distressed and banks and other commercial
lenders have substantially curtailed their lending activities as a result of,
among other things, significant write-offs in the financial services sector, the
re-pricing of credit risk and current weak economic conditions. These
circumstances continue to make it difficult to obtain funding.
As a
result, the cost of raising money in the debt and equity capital markets and
commercial credit markets has increased substantially while the availability of
funds from those markets has diminished significantly. Many lenders and
institutional investors have increased interest rates, enacted tighter lending
standards, refused to refinance existing debt at maturity – at all or on terms
similar to the debt being refinanced – and reduced and in some cases ceased to
provide funding to borrowers. In some cases, lenders under existing revolving
credit facilities have been unwilling or unable to meet their funding
obligations, including one lender under our revolving credit facility. If
additional lenders under our credit facility were to fail to fund their share of
the credit facility, our borrowing capacity could be further reduced. Although
Loews has indicated that it is willing to invest additional capital in us to
finance our expansion projects to the extent the public markets remain
unavailable on acceptable terms, we have not committed to any transaction at
this time and any additional investment by Loews would be subject to agreement
by Loews and to review and approval by our independent Conflicts Committee. Due
to these factors, we cannot be certain that new debt or equity financing will be
available on acceptable terms or that we will be able to continue to access the
full amount of the remaining commitments under our revolving credit facility in
the future.
These
circumstances have impacted our business, or may impact our business in a number
of ways including but not limited to:
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limiting
the amount of capital available to us to fund new growth capital projects
and acquisitions, which would limit our ability to grow our business, take
advantage of business opportunities, respond to competitive pressures and
increase distributions to our
unitholders;
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adversely
affecting our ability to refinance outstanding indebtedness at maturity on
favorable or fair terms or at all;
and
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weakening
the financial strength of certain of our customers, increasing the credit
risk associated with those customers and/or limiting their ability to grow
which could affect their ability to pay for our services or prompt them to
reduce throughput or contracted capacity on our
pipelines.
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Our
revolving credit agreement contains operating and financial covenants that
restrict our business and financing activities.
Our revolving credit agreement contains
operating and financial covenants that may restrict our ability to finance
future operations or capital needs or to expand or pursue our business
activities. For example, our credit agreement limits our ability to make loans
or investments, make material changes to the nature of our business, merge,
consolidate or engage in asset sales, or grant liens or make negative pledges.
The agreement also requires us to maintain a ratio of consolidated debt to
consolidated earnings before interest, taxes, depreciation and amortization (as
defined in the agreement) of no more than five to one, which limits the amount
of additional indebtedness we can incur. Future financing agreements we may
enter into may contain similar or more restrictive covenants.
Our
ability to comply with the covenants and restrictions contained in our credit
agreement may be affected by events beyond our control, including prevailing
economic, financial and industry conditions. If market or other economic
conditions or our financial performance deteriorate, our ability to comply with
these covenants may be impaired. If we are not able to incur additional
indebtedness we may need to sell additional equity securities to raise needed
capital, which would be dilutive to our existing equity holders. If we default
under our credit agreement or another financing agreement, significant
additional restrictions may become applicable, including a restriction on our
ability to make distributions to unitholders. In addition, a default could
result in a significant portion of our indebtedness becoming immediately due and
payable, and our lenders could terminate their commitment to make further loans
to us. In such event, we would not have, and may not be able to obtain,
sufficient funds to make these accelerated payments.
A
portion of the expected maximum daily capacity of our pipeline expansion
projects is contingent on our receiving and maintaining authority from PHMSA to
operate at higher operating pressures.
Our ability to transport a portion of
the expected maximum capacity on each of our expansion project pipelines is
contingent on our receipt of authority to operate these pipelines at higher
operating pressures under special permits issued by PHMSA. The ability to
operate at higher operating pressures increases the transportation capacity of
the pipelines. We have received both the special permit and the authority to
operate from PHMSA for the East Texas Pipeline, which was completed in 2008. We
have also received the special permits for our Southeast, Gulf Crossing and
Fayetteville and Greenville Laterals, but we have not received authority from
PHMSA to operate under these permits. Absent such authority, we will not be able
to transport all of the contracted for quantities of natural gas on these
pipelines. PHMSA retains discretion as to whether to grant, or to maintain in
force, authority to operate a pipeline at higher operating pressures. To the
extent PHMSA does not grant us authority to operate any of our expansion
pipelines under a special permit or withdraws previously granted authority, our
transportation capacity made available to the market and our transportation
revenues would be reduced.
We have
discovered anomalies in a small number of pipe segments on the East Texas
Pipeline. As a result, and as a prudent operator, we have elected to reduce
operating pressures on this pipeline to 20% below its previous operating level,
which was below the pipeline’s maximum non-special permit operating pressures.
We do not expect to return to normal operating pressures, or to operate at
higher pressures under the special permit, until after we have completed our
investigation and remediation measures, as appropriate, and PHMSA has concurred
with our determination to increase operating pressures. Operating at lower
pressures reduces the amount of gas that can flow through a pipeline and
therefore will reduce our expected revenues and cash flow from the affected
pipeline. In addition, we will incur costs to replace defective pipe segments on
the East Texas Pipeline and expect to temporarily shut down the East Texas
Pipeline when performing the necessary remedial measures, up to and including
replacing certain pipe segments. We cannot determine at this time the amount of
costs we will incur or when we might raise the operating pressures on this
pipeline. We have not completed testing all of our expansion pipelines and could
find anomalies on other pipelines which could have similar impacts with respect
to those pipelines. We will not receive
authority from PHMSA to operate any of our expansion pipelines at higher
pressures under special permits until we have fully tested and, as needed,
remediated any anomalies on each such pipeline.
We
are exposed to credit risk relating to nonperformance by our
customers.
Credit
risk relates to the risk of loss resulting from the nonperformance by a customer
of its contractual obligations. Our exposure generally relates to receivables
for services provided, future performance under firm agreements and volumes of
gas owed by customers for imbalances or gas loaned by us to them under certain
NNS and PAL services. If any of our significant customers have credit or
financial problems which result in a delay or failure to pay for services
provided by us or contracted for with us, or to repay the gas they owe us, it
could have a material adverse effect on our business. In addition, our FERC gas
tariffs only allow us to require limited credit support in the event that our
transportation customers are unable to pay for our services. As contracts
expire, the failure of any of our customers could also result in the non-renewal
of contracted capacity. Item 7A of this Report contains more information on
credit risk arising from gas loaned to customers.
Upon
completion of our expansion projects, our customer mix will have changed,
leading to changes in credit risk.
Historically,
the customers accounting for the majority of our throughput and revenues have
been gas marketers and LDCs with investment grade ratings. After completion of
our current expansion projects, producers of natural gas as a group will
comprise a significantly larger portion of our throughput and revenues. We
expect one producer to represent over 10% of our 2009
revenues. Historically, producers have had lower credit ratings than LDCs
and marketers. Therefore the expected change in our customer base could result
in higher total credit risk. The loss of access to credit for any of our major
customers, or a systemic loss of access to credit for any customer group in the
aggregate, could reduce our receipt of payment for services rendered or
otherwise reduce the level of services required by our customers.
We
depend on certain key customers for a significant portion of our revenues. The
loss of any of these key customers could result in a decline in our
revenues.
We rely
on a limited number of customers for a significant portion of revenues. We may
be unable to negotiate extensions or replacements of contracts and key customers
on favorable terms. The loss of all or even a portion of the contracted volumes
of these customers, as a result of competition, creditworthiness or otherwise,
could have a material adverse effect on our business, unless we are able to
contract for comparable volumes from other customers at favorable
rates.
Increased
competition could result in lower contracted capacity on our pipelines,
decreased rates for our services and reduced revenues.
We
compete primarily with other interstate and intrastate pipelines in the
transportation and storage of natural gas. Competition is particularly strong in
the Midwest and Gulf Coast states where we compete with numerous existing
pipelines and will compete with several new pipeline projects that are under
construction, such as the Rockies Express Pipeline and the Mid-Continent Express
Pipeline. We also compete with other pipelines for contracts with producers that
would support new growth projects such as our pipeline expansion projects.
Natural gas also competes with other forms of energy available to our customers,
including electricity, coal and fuel oils. The principle elements of competition
among pipelines are availability of capacity, rates, terms of service, access to
gas supplies, flexibility and reliability. FERC’s policies promote competition
in gas markets by increasing the number of gas transportation options available
to our customer base. Increased competition could reduce the volumes of gas
transported by our pipeline systems or, in instances where we do not have
long-term contracts with fixed rates, could force us to decrease our
transportation or storage rates. Competition could intensify the negative impact
of factors that could significantly decrease demand for natural gas in the
markets served by our pipeline systems, such as a recession or adverse economic
conditions, weather, higher fuel costs and taxes or other governmental or
regulatory actions that directly or indirectly increase the cost or limit the
use of natural gas. Our ability to renew or replace existing contracts at rates
sufficient to maintain current revenues and cash flows could be adversely
affected by competition.
The
regulatory program that applies to interstate pipelines is different than the
regulatory program that applies to many of our competitors that are not
regulated interstate pipelines. This difference in regulatory oversight can
result in longer lead times to develop and complete a project when it is
regulated at the federal level. We compete against a number of intrastate
pipelines which have significant regulatory advantages over us because of the
absence of FERC regulation. In view of potential rate advantages and
construction and service flexibility available to intrastate pipelines, we may
lose customers and throughput to intrastate competitors.
Significant
changes in energy prices could affect supply and demand, reduce system
throughput and adversely affect our revenues and available cash.
Due to
the natural decline in traditional gas production connected to our system, our
success depends on our ability to obtain access to new sources of natural gas,
which is dependent on factors beyond our control including the price level of
natural gas. In general terms, the price of natural gas fluctuates in response
to changes in supply and demand, market uncertainty and a variety of additional
factors that are beyond our control. These factors include:
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worldwide
economic conditions;
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weather
conditions, seasonal trends and hurricane disruptions;
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the
relationship between the available supplies and the demand for natural
gas;
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the
availability of LNG;
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the
availability of adequate transportation
capacity;
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storage
inventory levels;
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the
price and availability of alternative fuels;
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the
effect of energy conservation measures;
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the
nature and extent of, and changes in, governmental regulation and
taxation; and
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the
anticipated future prices of natural gas, LNG and other
commodities.
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Since the
summer of 2008, the price level of natural gas has dropped substantially. It is
difficult to predict future changes in gas prices, however the recent global
economic slowdown would generally indicate a bias toward downward pressure on
prices rather than an increase. Further downward movement in gas prices could
negatively impact producers in nontraditional supply areas such as the Barnett
Shale, the Bossier Sands, the Caney Woodford Shale and the Fayetteville Shale,
including producers who have contracted for capacity on our expansion projects.
Significant financial difficulties experienced by our producer customers could
impact their ability to pay for services rendered or otherwise reduce their
demand for our services.
High
natural gas prices may result in a reduction in the demand for natural gas. A
reduced level of demand for natural gas could reduce the utilization of capacity
on our systems, reduce the demand for our services and could result in the
non-renewal of contracted capacity as contracts expire.
Our
natural gas transportation and storage operations are subject to FERC’s
rate-making policies which could limit our ability to recover the full cost of
operating our pipelines, including earning a reasonable return.
We are
subject to extensive regulations relating to the rates we can charge for our
transportation and storage operations. For the cost-based services we offer,
FERC establishes both the maximum and minimum rates we can charge. The basic
elements that FERC considers are the cost of providing the service, the volumes
of gas being transported, how costs are allocated between services and the rate
of return a pipeline is permitted to earn. While neither Gulf South nor Texas
Gas has an obligation to file a rate case, our Gulf Crossing pipeline has an
obligation to file either a rate case or a cost-and-revenue study within three
years of being placed in service to justify its rates. Customers of our
subsidiaries or FERC can challenge the existing rates on any of our pipelines.
Such a challenge could adversely affect our ability to establish reasonable
transportation rates, to charge rates that would cover future increases in our
costs or even to continue to collect rates to maintain our current revenue
levels that are designed to permit a reasonable opportunity to recover current
costs and depreciation and earn a reasonable return. Additionally, FERC can
propose changes or modifications to any of its existing rate-related
policies.
If our subsidiaries were to file a rate
case or if we have to defend our rates in a proceeding commenced by a customer
or FERC, we would be required, among other things, to establish that the
inclusion of an income tax allowance in our cost of service is just and
reasonable. Under current FERC policy, since we are a limited partnership and do
not pay U.S. federal income taxes, this would require us to show that our
unitholders (or their ultimate owners) are subject to federal income taxation.
To support such a showing our general partner may elect to require owners of our
units to re-certify their status as being subject to U.S. federal income
taxation on the income generated by our subsidiaries or we may attempt to
provide other evidence. We can provide no assurance that the evidence we might
provide to FERC will be sufficient to establish that our unitholders (or their
ultimate owners) are subject to U.S. federal income tax liability on the income
generated by our jurisdictional pipelines. If we are unable to make such a
showing, FERC could disallow a substantial portion of the income tax allowance
included in the determination of the maximum rates that may be charged by our
pipeline subsidiaries, which could result in a reduction of such maximum rates
from current levels.
We may
not be able to recover all of our costs through existing or future rates. An
adverse determination in any future rate proceeding brought by or against any of
our subsidiaries could have a material adverse effect on our
business.
Our natural gas transportation and
storage operations are subject to extensive regulation by FERC in addition to
FERC rules and regulations related to the rates we can charge for our
services.
FERC’s regulatory authority
extends to:
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operating
terms and conditions of service;
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the
types of services we may offer to our customers;
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construction
of new facilities;
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creation,
extension or abandonment of services or
facilities;
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accounts
and records; and
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relationships
with certain types of affiliated companies involved in the natural gas
business.
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FERC’s
action in any of these areas or modifications of its current regulations can
adversely impact our ability to compete for business, to construct new
facilities, offer new services or to recover the full cost of operating our
pipelines. This regulatory oversight can result in longer lead times to develop
and complete an expansion project. The federal regulatory approval and
compliance process could raise the costs of such projects to the point where
they are no longer sufficiently timely or cost competitive when compared to
competing projects that are not subject to the federal regulatory
regime.
FERC
regulates the type of services we can offer, the terms and conditions of those
services and has authority to review pipeline contracts to ensure that the
services, rates and charges are just and reasonable and not unduly
discriminatory. FERC has various regulatory policies upon which it relies to
protect against undue discrimination. One such policy is to monitor the terms
and conditions of transportation service contracts for any material deviation
from the pipeline’s tariff. If FERC determines that a term of any such contract,
at the time it is entered into or during the term of that agreement, deviates in
a material manner from a pipeline’s tariff, FERC can, among other potential
remedies, order the pipeline to remove the term from the contract and execute
and re-file a new contract with FERC, or alternatively, amend its tariff to
include the deviating term, thereby offering it to all shippers. If FERC audits
a pipeline’s contracts or other aspects of our pipeline business and finds
material deviations or other violation, FERC could conduct a formal enforcement
investigation, resulting in penalties and/or ongoing compliance
obligations.
Should
we fail to comply with all applicable statutes, rules, regulations and orders
administered or issued by FERC, we could be subject to substantial penalties and
fines. Under the Energy Policy Act of 2005, the FERC has civil penalty authority
under the NGA to impose penalties for current violations of up to $1.0 million
per day for each violation.
Capacity
leaving our Lebanon, Ohio terminus is limited.
The
northeastern terminus of our pipeline systems is in Lebanon, Ohio, where it
connects with other interstate natural gas pipelines delivering gas to
Northeast, Midwest and East Coast markets. Pipeline capacity into Lebanon is
significantly greater than pipeline capacity leaving that point, creating a
bottleneck for supply into areas of high demand. This situation may be
compounded when the Rockies Express pipeline reaches Lebanon later in 2009 while
the remaining segments of that pipeline downstream of Lebanon are still under
construction. As of December 31, 2008, approximately 55% of our long-term
contracts with firm deliveries to Lebanon will expire or have the ability to
terminate by the end of 2010. Supply volumes from the Rocky Mountains, Canada
and LNG import terminals may compete with and displace volumes from the Gulf
Coast and Mid-Continent in order to serve the Northeast, Midwest and East Coast
markets.
We
may not be able to maintain or replace expiring gas transportation and storage
contracts at favorable rates.
Our
primary exposure to market risk occurs at the time existing transportation
contracts expire and are subject to renegotiation. As of December 31, 2008,
approximately 17% of the contracts for firm transportation capacity on our
pipeline systems, excluding agreements related to the expansion projects not yet
in service, was due to expire on or before December 31, 2009. Upon expiration,
we may not be able to extend contracts with existing customers or obtain
replacement contracts at favorable rates or on a long-term basis. A key
determinant of the value that customers can realize from firm transportation on
a pipeline and the price they are willing to pay for transportation is the price
differential between physical locations, which can be affected by, among other
things, the availability of supply, available capacity, storage inventories,
weather and general market demand in the respective areas.
The
extension or replacement of existing contracts depends on a number of factors
beyond our control, including:
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existing
and new competition to deliver natural gas to our markets;
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the
growth in demand for natural gas in our markets;
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whether
the market will continue to support long-term contracts;
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the
current price differentials, or market price spreads between two points on
our pipelines; and
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the effects of state regulation
on customer contracting
practices.
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If
third-party pipelines and other facilities connected to our pipelines and
facilities become unavailable to transport natural gas our revenues could be
adversely affected.
We depend
upon third-party pipelines and other facilities that provide delivery options to
and from our pipelines. For example, we are contractually committed to deliver
approximately 1.8 Bcf per day to Transco Station 85. If this or any other
significant pipeline connection were to become unavailable for current or future
volumes of natural gas due to repairs, damage to the facilities, lack of
capacity or any other reason, our ability to continue shipping natural gas to
end markets could be restricted, thereby reducing our revenues.
We
are subject to laws and regulations relating to the environment which may expose
us to significant costs, liabilities and loss of revenues.
Our
operations are subject to extensive federal, state and local laws and
regulations relating to protection of the environment. These laws include, for
example the Clean Air Act; the Water Pollution Control Act, commonly referred to
as the Clean Water Act; CERCLA or the Superfund law; the Resource Conservation
and Recovery Act and analogous state laws. The existing environmental
regulations could be revised or reinterpreted in the future and new laws and
regulations could be adopted or become applicable to our operations or
facilities. In addition, government action may be initiated to reduce greenhouse
gas emissions along with other government actions that may have the effect of
requiring or encouraging reduced consumption or production of natural
gas.
Compliance
with current or future environmental regulations could require significant
expenditures and the failure to comply with current or future regulations might
result in the imposition of fines and penalties. Current rate structures,
customer contracts and prevailing market conditions might not allow us to
recover the additional costs incurred to comply with new environmental
requirements and we might not be able to obtain or maintain all required
environmental regulatory approvals for certain projects. If there is a delay in
obtaining any required environmental regulatory approvals or if we fail to
obtain and comply with them, we may be required to shut down certain facilities
or become subject to additional costs.
We
do not own all of the land on which our pipelines and facilities are located,
which could disrupt our operations or result in increased costs.
We obtain
the rights to construct and operate certain of our pipelines and related
facilities on land owned by third parties and governmental agencies for a
specific period of time. As a result, we are subject to the risk of increased
costs to maintain necessary use of land in accordance with the agreements that
convey to us those rights. Additionally, if we do not comply with the terms of
those agreements our rights could be restricted which could disrupt our
operations.
We
are subject to strict safety regulations which may impose significant costs and
liabilities on us.
Under
PHMSA regulations, we are required to develop and maintain integrity management
programs to comprehensively evaluate certain areas along our pipelines and take
additional measures to protect pipeline segments located in what are referred to
as high consequence areas where a leak or rupture could potentially do the most
harm. The regulations or an increase in public expectations for pipeline safety
may require additional reporting, the replacement of some of our pipeline
segments, the addition of monitoring equipment and more frequent inspection or
testing of our pipeline facilities. Any repair, remediation, preventative or
mitigating actions may require significant capital and operating
expenditures.
We are
also subject to the requirements of the Occupational Safety and Health Act
(OSHA) and comparable state statutes that regulate the protection of the health
and safety of workers. In addition, the OSHA hazard communication standard
requires that we maintain information about hazardous materials used or produced
in our operations and that we provide this information to employees, state and
local governmental authorities and local residents.
Should we
fail to comply with PHMSA regulations, or OSHA, state statutes and general
industry standards regulating the protection of the health and safety of
workers, keep adequate records or monitor pipeline integrity or occupational
exposure to regulated substances we could be subject to penalties and fines
and/or otherwise incur significant costs to restore compliance.
Our operations are subject to
catastrophic losses, operational hazards and unforeseen interruptions for which
we may not be adequately insured.
There are
a variety of operating risks inherent in our natural gas transportation and
storage operations such as leaks, explosions and mechanical
problems. Additionally, the nature and location of our business may make us
susceptible to catastrophic losses from hurricanes or other named storms,
particularly with regard to our assets in the Gulf Coast region, windstorms,
earthquakes, hail, explosions, severe winter weather and fires. Any of
these or other similar occurrences could result in the disruption of our
operations, substantial repair costs, personal injury or loss of human life,
significant damage to property, environmental pollution, impairment of our
operations and substantial financial losses. The location of pipelines near
populated areas, including residential areas, commercial business centers and
industrial sites, could significantly increase the level of damages resulting
from some of these risks.
We
currently possess property, business interruption and general liability
insurance, but proceeds from such insurance coverage may not be adequate for all
liabilities or expenses incurred or revenues lost. Moreover, such insurance may
not be available in the future at commercially reasonable costs and terms.
Recent changes in the insurance markets have made it more difficult for us to
obtain certain types of coverage. The insurance coverage we do obtain may
contain large deductibles or fail to cover certain hazards or all potential
losses.
Possible
terrorist activities or military actions could adversely affect our
business.
The
continued threat of terrorism and the impact of retaliatory military and other
action by the U.S. and its allies might lead to increased political, economic
and financial market instability and volatility in prices for natural gas, which
could affect the markets for our natural gas transportation and storage
services. While we are taking steps that we believe are appropriate to increase
the security of our assets, we may not be able to completely secure our assets,
completely protect them against a terrorist attack or obtain adequate insurance
coverage for terrorist acts at reasonable rates. These developments have
subjected our operations to increased risks and could have a material adverse
effect on our business. In particular, we might experience increased capital or
operating costs to implement increased security.
We
face risks associated with global climate change.
There is
a growing belief that emissions of greenhouse gases, most notably carbon
dioxide, may be linked to global climate change, which has been associated with
extreme weather events and other risks. While there is currently no federal
regulation of greenhouse gas emissions in the U.S., some states have adopted
such laws and it is anticipated that federal legislation, likely consisting of a
cap and trade system, will be enacted in the U.S. in the near future. In
addition, the U.S. Environmental Protection Agency may regulate certain carbon
dioxide and other greenhouse gas emissions and some greenhouse gases may be
regulated as “air pollutants” under the Clean Air Act. Depending on the
particular regulation adopted, we could be required to purchase and surrender
allowances for greenhouse gas emissions resulting from our operations (e.g., our
compressor units). In addition, compliance with any new federal or state laws
and regulations requiring adoption of greenhouse gas control programs or
imposing restrictions on emissions of carbon dioxide in areas of the U.S. in
which we conduct business could adversely affect the demand for and the cost to
produce and transport natural gas which would adversely affect our
business.
Our
general partner and its affiliates own a controlling interest in us, have
conflicts of interest and owe us only limited fiduciary duties, which may permit
them to favor their own interests.
At
December 31, 2008, BPHC, a subsidiary of Loews, owned a majority of our limited
partner interests and owns and controls our general partner, which controls us.
Although our general partner has a fiduciary duty to manage us in a manner
beneficial to us and our unitholders, the directors and officers of our general
partner have a fiduciary duty to manage our general partner in a manner
beneficial to BPHC. Furthermore, certain directors and officers of our general
partner are also directors or officers of affiliates of our general partner.
Conflicts of interest may arise between BPHC and its subsidiaries, including our
general partner, on the one hand, and us and our unitholders, on the other hand.
In resolving these conflicts, our general partner may favor its own interests
and the interests of its affiliates over the interests of our unitholders. These
potential conflicts include, among others, the following situations:
|
·
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BPHC
and its affiliates may engage in competition with
us.
|
|
·
|
Neither
our partnership agreement nor any other agreement requires BPHC or its
affiliates (other than our general partner) to pursue a business strategy
that favors us. Directors and officers of BPHC and its affiliates have a
fiduciary duty to make decisions in the best interest of BPHC
shareholders, which may be contrary to our
interests.
|
|
·
|
Our
general partner is allowed to take into account the interests of parties
other than us, such as BPHC and its affiliates, in resolving conflicts of
interest, which has the effect of limiting its fiduciary duty to our
unitholders.
|
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·
|
Some
officers of our general partner who provide services to us may devote time
to affiliates of our general partner and may be compensated for services
rendered to such affiliates.
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|
·
|
Our
partnership agreement limits the liability and reduces the fiduciary
duties of our general partner and the remedies available to our
unitholders for actions that, without these limitations, might constitute
breaches of fiduciary duty. By purchasing common units, unitholders are
consenting to some actions and conflicts of interest that might otherwise
constitute a breach of fiduciary or other duties under applicable
law.
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|
·
|
Our
general partner determines the amount and timing of asset purchases and
sales, borrowings, repayments of indebtedness, issuances of additional
partnership securities and cash reserves, each of which can affect the
amount of cash that is available for distribution to our
unitholders.
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|
·
|
Our
general partner determines the amount and timing of any capital
expenditures and whether an expenditure is for maintenance capital, which
reduces operating surplus, or a capital improvement expenditure, which
does not. Such determination can affect the amount of cash that is
distributed to our unitholders.
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|
·
|
In
some instances, our general partner may cause us to borrow funds in order
to permit the payment of cash distributions, even if the purpose or effect
of the borrowing is to make incentive
distributions.
|
|
·
|
Our
general partner determines which costs, including allocated overhead,
incurred by it and its affiliates are reimbursable by
us.
|
|
·
|
Our
partnership agreement does not restrict our general partner from causing
us to pay it or its affiliates for any services rendered on terms that are
fair and reasonable to us or entering into additional contractual
arrangements with any of these entities on our behalf, and provides that
reimbursement to Loews for amounts allocable to us consistent with
accounting and allocation methodologies generally permitted by FERC for
rate-making purposes and past business practices is deemed fair and
reasonable to us.
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·
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Our
general partner controls the enforcement of obligations owed to us by it
and its affiliates.
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·
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Our
general partner intends to limit its liability regarding our contractual
obligations.
|
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·
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Our
general partner decides whether to retain separate counsel, accountants or
others to perform services for us.
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·
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Our
general partner may exercise its rights to call and purchase (1) all
of our common units if at any time it and its affiliates own more than 80%
of the outstanding common units or (2) all of our equity securities
(including common units) if it and its affiliates own more than 50% in the
aggregate of the outstanding common units and any other classes of equity
securities and it receives an opinion of outside legal counsel to the
effect that our being a pass-through entity for tax purposes has or is
reasonably likely to have a material adverse effect on the maximum
applicable rates we can charge our
customers.
|
Our
partnership agreement limits our general partner’s fiduciary duties to
unitholders and restricts the remedies available to unitholders for actions
taken by our general partner that might otherwise constitute breaches of
fiduciary duty.
Our partnership agreement contains
provisions that reduce the standards to which our general partner would
otherwise be held by state fiduciary duty law. For example, our partnership
agreement:
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·
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permits
our general partner to make a number of decisions in its individual
capacity, as opposed to its capacity as our general partner. This entitles
our general partner to consider only the interests and factors that it
desires, and it has no duty or obligation to give any consideration to any
interest of, or factors affecting us, our affiliates or any limited
partner. Decisions made by our general partner in its individual capacity
will be made by a majority of the owners of our general partner, and not
by the board of directors of our general partner. Examples of these kinds
of decisions include the exercise of its call rights, its voting rights
with respect to the units it owns and its registration rights and the
determination of whether to consent to any merger or consolidation of the
partnership;
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·
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provides
that our general partner shall not have any liability to us or our
unitholders for decisions made in its capacity as general partner so long
as it acted in good faith, meaning it believed that the decisions were in
the best interests of the partnership;
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·
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generally
provides that affiliate transactions and resolutions of conflicts of
interest not approved by the conflicts committee of the board of directors
of our general partner and not involving a vote of unitholders must be on
terms no less favorable to us than those generally provided to or
available from unrelated third parties or be “fair and reasonable” to us
and that, in determining whether a transaction or resolution is “fair and
reasonable,” our general partner may consider the totality of the
relationships between the parties involved, including other transactions
that may be particularly advantageous or beneficial to us; and
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·
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provides
that our general partner and its officers and directors will not be liable
for monetary damages to us, our limited partners or assignees for any acts
or omissions unless there has been a final and non-appealable judgment
entered by a court of competent jurisdiction determining that the general
partner or those other persons acted in bad faith or engaged in fraud or
willful misconduct.
|
We
have a holding company structure in which our subsidiaries conduct our
operations and own our operating assets, which may affect our ability to make
distributions.
We are a partnership holding company
and our operating subsidiaries conduct all of our operations and own all of our
operating assets. We have no significant assets other than the ownership
interests in our subsidiaries. As a result, our ability to make distributions to
our unitholders depends on the performance of our subsidiaries and their ability
to distribute funds to us. The ability of our subsidiaries to make distributions
to us may be restricted by, among other things, the provisions of existing and
future indebtedness, applicable state partnership and limited liability company
laws and other laws and regulations, including FERC policies.
Tax
Risks
Our
tax treatment depends on our status as a partnership for federal income tax
purposes, as well as our not being subject to a material amount of entity-level
taxation by individual states. If the Internal Revenue Service (IRS) were to
treat us as a corporation for federal income tax purposes or if we were to
become subject to additional amounts of entity-level taxation for state tax
purposes, then our cash distributions to our unitholders could be substantially
reduced.
The
anticipated after-tax economic benefit of an investment in our common units
depends largely on our being treated as a partnership for federal income tax
purposes.
Despite
the fact that we are a limited partnership under Delaware law, it is possible in
certain circumstances for a partnership such as ours to be treated as a
corporation for federal income tax purposes. If we were treated as a corporation
for federal income tax purposes, we would pay federal income tax on our taxable
income at the corporate tax rate, which is currently a maximum of 35%, and would
likely pay additional state income tax at varying rates. Distributions to our
unitholders would generally be taxed again as corporate distributions, and no
income, gains, losses, deductions or credits would flow through to our
unitholders. Because a tax would be imposed upon us as a corporation, our cash
available for distribution to our unitholders would be substantially reduced.
Thus, treatment of us as a corporation would result in a material reduction in
the anticipated cash flow and after-tax return to our unitholders, likely
causing a substantial reduction in the value of our common units.
Current
tax law may change, causing us to be treated as a corporation for federal income
tax purposes or otherwise subjecting us to additional amounts of entity-level
taxation for state tax purposes. For example, several states are evaluating ways
to subject partnerships to entity-level taxation through the imposition of state
income, franchise or other forms of taxation. Imposition of such a tax on us
would reduce the cash available for distribution to unitholders.
Our
partnership agreement provides that if a law is enacted or existing law is
modified or interpreted in a manner that subjects us to taxation as a
corporation or otherwise subjects us to a material amount of entity-level
taxation for federal, state or local income tax purposes, then the minimum
quarterly distribution amount and the target distribution amounts will be
adjusted to reflect the impact of that law on us.
The
tax treatment of publicly traded partnerships or an investment in our common
units is subject to potential legislative, judicial or administrative changes
and differing interpretations, possibly on a retroactive basis.
The
present federal income tax treatment of publicly traded partnerships, including
us, or an investment in our common units may be modified by legislative,
judicial or administrative changes and differing interpretations at any time.
Any modification to the federal income tax laws and interpretations thereof may
or may not be applied retroactively. Recently, members of Congress have
considered substantive changes to the existing U.S. tax laws that would affect
certain publicly traded partnerships. Although it does not appear that the
legislation considered would have affected our tax treatment as a
partnership, we are unable to predict whether any of these changes, or other
proposals, will be reconsidered or will ultimately be enacted. Any such changes
could negatively impact the value of an investment in our common
units.
If
the IRS contests the federal income tax positions we take, the market for our
common units may be adversely impacted, and the costs of any contest will reduce
our cash distributions to our unitholders.
We have not requested any ruling from
the IRS with respect to our treatment as a partnership for federal income tax
purposes or any other matter affecting us. The IRS may adopt positions that
differ from the positions that we take. Therefore, it may be necessary to resort
to administrative or court proceedings to sustain some or all of the positions
we take and even then a court may not agree with some or all of the positions we
take. Any contest with the IRS may materially and adversely impact the market
for our common units and the price at which they trade. In addition, because the
costs of any contest with the IRS will be borne indirectly by our unitholders
and our general partner, any such contest will result in a reduction in cash
available for distribution.
Our
unitholders may be required to pay taxes on their share of our income even if
such unitholders do not receive any cash distributions from us.
Our unitholders will be treated as
partners to whom we will allocate taxable income and who will be required to pay
federal income taxes and, in some cases, state and local income taxes on their
share of our taxable income, whether or not such unitholders receive cash
distributions from us. Our unitholders may not receive cash distributions from
us equal to such unitholders’ share of our taxable income or even equal to the
actual tax liability that results from such unitholders’ share of our taxable
income.
Tax
gain or loss on the disposition of our common units could be different than
expected.
If our unitholders sell their common
units, such unitholders will recognize gain or loss equal to the difference
between the amount realized and such unitholders’ tax basis in those common
units. Distributions in excess of our unitholders’ allocable share of our net
taxable income decrease their tax basis in their common units. Accordingly, to
the extent a unitholder’s distributions have exceeded such unitholder’s
allocable share of our net taxable income, the sale of units by such unitholder
will produce taxable income to them if they sell such units at a price greater
than their tax basis in those units, even if the price they receive is less than
their original cost. Furthermore, a substantial portion of the amount realized,
whether or not representing a gain, may be taxed as ordinary income due to
potential recapture items, including depreciation recapture. In addition,
because the amount realized includes a unitholder’s share of our nonrecourse
liabilities, if our unitholders sell their units, they may incur a tax liability
in excess of the amount of cash they receive from the sale.
Tax-exempt
entities and non-U.S. persons face unique tax issues from owning our common
units that may result in adverse tax consequences to them.
Investment in common units by
tax-exempt entities, such as employee benefit plans and individual retirement
accounts (known as IRAs) and non-U.S. persons, raises issues unique to them. For
example, virtually all of our income allocated to organizations that are exempt
from federal income tax, including IRAs and other retirement plans, will be
unrelated business taxable income and could be taxable to them. Distributions to
non-U.S. persons will be reduced by withholding taxes at the highest applicable
effective tax rate, and non-U.S. persons will be required to file U.S. federal
tax returns and pay tax on their share of our taxable income. If you are a tax
exempt entity or a non-U.S. person, you should consult your tax advisor before
investing in our common units.
We
will treat each purchaser of common units as having the same tax benefits
without regard to the common units purchased. The IRS may challenge this
treatment, which could result in a decrease in the value of the common
units.
Because we cannot match transferors and
transferees of common units we will adopt depreciation and amortization
positions that may not conform with all aspects of existing Treasury
Regulations. A successful IRS challenge to those positions could decrease the
amount of tax benefits available to our unitholders. It also could affect the
timing of these tax benefits or the amount of gain from any sale of common units
and could have a negative impact on the value of our common units or result in
audit adjustments to our unitholders tax returns.
We
prorate our items of income, gain, loss and deduction between transferors and
transferees of our units each month based upon the ownership of our units on the
first business day of each month, instead of on the basis of the date a
particular unit is transferred. The IRS may challenge this treatment, which
could change the allocation of items of income, gain, loss and deduction among
our unitholders.
We prorate our items of income, gain,
loss and deduction between transferors and transferees of our units each month
based upon the ownership of our units on the first business day of each month,
instead of on the basis of the date a particular unit is transferred. The use of
this proration method may not be permitted under existing Treasury Regulations.
If the IRS were to challenge this method or new Treasury Regulations were
issued, we may be required to change the allocation of items of income, gain,
loss and deduction among our unitholders.
A
unitholder whose units are loaned to a “short seller” to cover a short sale of
units may be considered as having disposed of those units. If so, the unitholder
would no longer be treated for tax purposes as a partner with respect to those
units during the period of the loan and may recognize gain or loss from the
disposition.
Because a
unitholder whose units are loaned to a “short seller” to cover a short sale of
units may be considered as having disposed of the loaned units, the unitholder
may no longer be treated for tax purposes as a partner with respect to those
units during the period of the loan to the short seller and the unitholder may
recognize gain or loss from such disposition. Moreover, during the period of the
loan to the short seller, any of our income, gain, loss or deduction with
respect to those units may not be reportable by the unitholder and any cash
distributions received by the unitholder as to those units could be fully
taxable as ordinary income. Unitholders desiring to assure their status as
partners and avoid the risk of gain recognition from a loan to a short seller
are urged to modify any applicable brokerage account agreements to prohibit
their brokers from borrowing their units.
We
have adopted certain valuation methodologies that may result in a shift of
income, gain, loss and deduction between the general partner and the
unitholders. The IRS may challenge this treatment, which could adversely affect
the value of the common units.
When we
issue additional units or engage in certain other transactions, we determine the
fair market value of our assets and allocate any unrealized gain or loss
attributable to our assets to the capital accounts of our unitholders and our
general partner. Our methodology may be viewed as understating the value of our
assets. In that case, there may be a shift of income, gain, loss and deduction
between certain unitholders and the general partner, which may be unfavorable to
such unitholders. Moreover, under our valuation methods, subsequent purchasers
of common units may have a greater portion of their Internal Revenue Code
Section 743(b) adjustment allocated to our tangible assets and a lesser portion
allocated to our intangible assets. The IRS may challenge our valuation methods,
or our allocation of the Section 743(b) adjustment attributable to our tangible
and intangible assets, and allocations of income, gain, loss and deduction
between the general partner and certain of our unitholders.
A
successful IRS challenge to these methods or allocations could adversely affect
the amount of taxable income or loss being allocated to our unitholders. It also
could affect the amount of gain from our unitholders’ sale of common units and
could have a negative impact on the value of the common units or result in audit
adjustments to our unitholders’ tax returns without the benefit of additional
deductions.
The
sale or exchange of 50% or more of our capital and profit interests during any
twelve-month period will result in the termination of our partnership for
federal income tax purposes.
We will be considered terminated for
federal income tax purposes if there is a sale or exchange of 50% or more of the
total interests in our capital and profits within a twelve-month period. Our
termination would, among other things, result in the closing of our taxable year
which would require us to file two tax returns (and could result in our
unitholders receiving two Schedules K-1) for one fiscal year, and could result
in a deferral of depreciation deductions allowable in computing our taxable
income. In the case of a unitholder reporting on a taxable year other than a
fiscal year ending December 31, the closing of our taxable year may also result
in more than twelve months of our taxable income or loss being includable in
such unitholder’s taxable income for the year of termination. Our termination
currently would not affect our classification as a partnership for federal
income tax purposes. We would be treated as a new partnership for tax purposes
and would be required to make new tax elections and could be subject to
penalties if we were unable to determine in a timely manner that a termination
occurred.
Our
unitholders may be subject to state and local taxes and return filing
requirements as a result of investing in our common units.
In addition to federal income taxes,
unitholders will likely be subject to other taxes, including state and local
taxes, unincorporated business taxes and estate, inheritance or intangible taxes
that are imposed by the various jurisdictions in which we do business or own
property now or in the future, even if our unitholders do not reside in any of
those jurisdictions. Our unitholders will likely be required to file state and
local income tax returns and pay state and local income taxes in some or all of
these various jurisdictions. Further, unitholders may be subject to penalties
for failure to comply with those requirements. We conduct business in twelve
states. We may own property or conduct business in other states or foreign
countries in the future. It is our unitholders’ responsibility to file all
federal, state and local tax returns.
None.
We are headquartered in approximately
103,000 square feet of leased office space located in Houston, Texas. We also
have approximately 108,000 square feet of office space in Owensboro, Kentucky,
in a building that we own. Our operating subsidiaries own their respective
pipeline systems in fee. However, a substantial portion of these systems is
constructed and maintained on property owned by others pursuant to
rights-of-way, easements, permits, licenses or consents.
Our Pipeline and Storage
Systems, in Item 1 of this Report contains additional information on our
material property, including our pipelines and storage facilities.
For a discussion of certain of our
current legal proceedings, please read Note 3 in Item 8 of this
Report.
None.
Securities
Our
Partnership Interests
As of December 31, 2008, we had
outstanding 154.9 million common units, 22.9 million class B units, a 2% general
partner interest and incentive distribution rights (IDRs). The common units and
class B units together represent all of our limited partner interests and 98% of
our total ownership interests, in each case excluding our IDRs. As discussed
below under Our Cash
Distribution Policy—Incentive Distribution Rights, the IDRs represent the
right for the holder to receive varying percentages of quarterly distributions
of available cash from operating surplus in excess of certain specified target
quarterly distribution levels. As such, the IDRs cannot be expressed as a
constant percentage of our total ownership interests.
BPHC, a wholly-owned subsidiary of
Loews, owns 107.5 million of our common units, all 22.9 million of our class B
units and, through Boardwalk GP, LP, an indirect wholly-owned subsidiary of
BPHC, holds the 2% general partner interest and all of the IDRs. The common
units, class B units and general partner interest held by BPHC represent
approximately 74% of our equity interests. The additional interest represented
by the IDRs is not included in such ownership percentage because, as noted
above, the IDRs cannot be expressed as a constant percentage of our
ownership.
Market
Information
As of February 13, 2009, we had 154.9
million common units outstanding held by approximately 60 holders of record.
BPHC owns 107.5 million of our common units and all of our class B units, for
which there is no established public trading market. Our common units are traded
on the NYSE under the symbol “BWP.”
The following table sets forth, for the
periods indicated, the high and low sales prices for our common units, as
reported on the NYSE Composite Transactions Tape, and information regarding our
quarterly distributions. The closing sales price of our common units on the NYSE
on February 13, 2009, was $22.44 per unit.
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Sales
Price Range per
Common
Unit
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Cash
Distributions
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|
|
|
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High
|
|
|
Low
|
|
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per
Common Unit
(a)
(b)
|
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Year
ended December 31, 2008:
|
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|
|
|
|
|
|
|
|
|
Fourth
quarter
|
|
$ |
25.97 |
|
|
$ |
14.00 |
|
|
$ |
0.480 |
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Third
quarter
|
|
|
24.96 |
|
|
|
17.11 |
|
|
|
0.475 |
|
|
Second
quarter
|
|
|
28.65 |
|
|
|
23.34 |
|
|
|
0.470 |
|
|
First
quarter
|
|
|
32.25 |
|
|
|
21.24 |
|
|
|
0.465 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year
ended December 31, 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fourth
quarter
|
|
$ |
33.33 |
|
|
$ |
29.76 |
|
|
$ |
0.46 |
|
|
Third
quarter
|
|
|
37.79 |
|
|
|
28.80 |
|
|
|
0.45 |
|
|
Second
quarter
|
|
|
37.46 |
|
|
|
32.65 |
|
|
|
0.44 |
|
|
First
quarter
|
|
|
39.20 |
|
|
|
30.13 |
|
|
|
0.43 |
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|
(a)
|
Represents
cash distributions attributable to the quarter and declared and paid to
limited partner unitholders within 60 days after quarter end.
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(b)
|
We
also paid cash distributions to our general partner with respect to its 2%
general partner interest and, with respect to that portion of the
distribution in excess of $0.4025 per unit, its incentive distribution
rights described below. The class B unitholder participates in
distributions on a pari passu basis with our common units up to $0.30 per
quarter, beginning with the distribution attributable to the third quarter
2008. The class B units do not participate in quarterly distributions
above $0.30 per unit.
|
Our
Cash Distribution Policy
Our cash distribution policy is consistent with the terms of our partnership
agreement which requires us to distribute our “available cash,” as that term is
defined in our partnership agreement, on a quarterly basis. However,
there is no guarantee that unitholders will receive quarterly distributions from
us. Our distribution policy may be changed at any time and is subject to certain
restrictions or limitations, including, among others, our general partner’s
broad discretion to establish reserves which could reduce cash available for
distributions, FERC regulations which place restrictions on various types of
cash management programs employed by companies in the energy industry, including
our operating subsidiaries, the requirements of applicable state partnership and
limited liability company laws, and the requirements of our revolving credit
facility which would prohibit us from making distributions to unitholders if an
event of default were to occur. In addition, we may lack sufficient cash to pay
distributions to unitholders due to a number of factors, including those
described in Item 1A, Risk
Factors, of this Report.
Incentive
Distribution Rights
IDRs represent the right to receive an increasing percentage of quarterly
distributions of available cash from operating surplus after the target
distribution levels have been achieved, as defined in our partnership agreement.
Our general partner currently holds all of our IDRs, but may transfer these
rights separately from its general partner interest, subject to restrictions in
our partnership agreement. In 2008 and 2007, we paid $7.5 million and $2.5
million in distributions on behalf of our IDRs. There were no amounts paid
on behalf of our IDRs in 2006.
Assuming we do not issue any additional
classes of units and our general partner maintains its 2% general partner
interest, we will distribute any available cash from operating surplus for that
quarter among the unitholders and our general partner as follows:
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Total
Quarterly Distribution
|
|
Marginal Percentage Interest in
Distributions
|
|
Target
Amount
|
Limited
Partner
Unitholders
(1)
|
|
General Partner
|
|
First
Target Distribution
|
|
up to $0.4025
|
|
98%
|
|
2%
|
|
Second
Target Distribution
|
|
above $0.4025 up to $0.4375
|
|
85%
|
|
15%
|
|
Third
Target Distribution
|
|
above
$0.4375 up to $0.5250
|
|
75%
|
|
25%
|
|
Thereafter
|
|
above
$0.5250
|
|
50%
|
|
50%
|
|
(1)
|
Distributions
to our limited partner unitholders include distributions on behalf of our
class B units as described under Issuance of Class B
Units.
|
Issuance
of Class B Units
In June
2008, we issued and sold to BPHC, approximately 22.9 million class B units
representing limited partner interests for $30.00 per class B unit. The class B
units share in quarterly distributions of available cash from operating surplus
on a pari passu basis with our common units, until each common unit and class B
unit has received a quarterly distribution of $0.30. The class B units do not
participate in quarterly distributions above $0.30 per unit. The class B units
began sharing in income allocations and distributions with respect to the third
quarter 2008.
The class
B units have the same voting rights as if they were outstanding common units and
are entitled to vote as a separate class on any matters that materially
adversely affect the rights or preferences of the class B units in relation to
other classes of partnership interests or as required by law. The class B units
will be convertible into common units upon demand by the holder on a one-for-one
basis at any time after June 30, 2013.
Conversion
of Subordinated Units
In
November 2008, we satisfied the last of the earnings and distributions tests
contained in our partnership agreement for the conversion of all the 33.1
million outstanding subordinated units held by BPHC into common units on a
one-for-one basis. The last of these requirements was met coincident with
payment of the quarterly distribution paid in the fourth quarter 2008. Two days
following this quarterly distribution to unitholders, all of the subordinated
units converted to common units.
Equity
Compensation Plans
For
information about our equity compensation, see Securities Authorized for
Issuance under Equity Compensation Plans in Item 12 of this Report.
Issuer
Purchases of Equity Securities
None.
The
following table presents summary historical financial and operating data for us
and our predecessor Boardwalk Pipelines, as of the dates and for the periods
indicated. In connection with the consummation of our initial public offering
(IPO), BPHC contributed all of the equity interests in Boardwalk Pipelines to
us. This contribution was accounted for as a transfer of assets between entities
under common control in accordance with Statement of Financial Accounting
Standards (SFAS) No. 141,
Business Combinations. Therefore, the results of Boardwalk Pipelines
prior to November 15, 2005, have been combined with our results subsequent
to November 15, 2005, as our consolidated results for 2005.
The
acquisition of Gulf South by Boardwalk Pipelines in December 2004 was accounted
for using the purchase method of accounting. Accordingly, the post-acquisition
financial information included below reflects the purchase. As a result, our
results of operations for the year 2004 are not readily comparable with our
results of operations for the years subsequent to 2004.
Prior to
its converting to a limited partnership on November 15, 2005, Boardwalk
Pipelines’ taxable income was included in the consolidated federal income tax
return of Loews and Boardwalk Pipelines recorded a charge-in-lieu of income
taxes pursuant to a tax-sharing agreement with Loews. The tax-sharing agreement
required Boardwalk Pipelines to remit to Loews on a quarterly basis any federal
income taxes as if it were filing a separate return. Boardwalk Pipelines and its
subsidiaries were also included in the state franchise tax filings of BPHC. The
franchise taxes were charged to, and recorded by, Boardwalk Pipelines and its
subsidiaries pursuant to the companies’ tax sharing policy. Following our IPO,
we no longer record certain state franchise taxes incurred by BPHC and no longer
participate in a tax-sharing agreement with Loews. Our subsidiaries directly
incur some income-based state taxes, which are shown as Income taxes on the
Consolidated Statements of Income.
As used herein, EBITDA means earnings
before interest, income taxes, and depreciation and amortization. This measure
is not calculated or presented in accordance with accounting principles
generally accepted in the U.S. (GAAP). We explain this measure below and
reconcile it to its most directly comparable financial measures calculated and
presented in accordance with GAAP in “***Non-GAAP Financial Measure.” The
financial data below should be read in conjunction with the consolidated
financial statements and notes thereto included in this Report (in millions,
except Earnings per common and subordinated unit, Earnings per class B unit and
Distributions per common unit):
|
|
|
Boardwalk
Pipeline Partners, LP
|
|
|
|
|
For
the Year Ended December 31,
|
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
Total
operating revenues
|
|
$ |
784.8 |
|
|
$ |
643.2 |
|
|
$ |
607.6 |
|
|
$ |
560.5 |
|
|
$ |
263.6 |
|
|
Net
income
|
|
|
294.0 |
|
|
|
227.7 |
|
|
|
197.6 |
|
|
|
100.9 |
|
|
|
48.8 |
|
|
Total
assets (a)
|
|
|
6,721.6 |
|
|
|
4,122.0 |
|
|
|
2,909.2 |
|
|
|
2,437.9 |
|
|
|
2,443.8 |
|
|
Long-term
debt
|
|
|
2,889.4 |
|
|
|
1,847.9 |
|
|
|
1,350.9 |
|
|
|
1,101.3 |
|
|
|
1,106.1 |
|
|
Earnings
per common and
subordinated
unit **
|
|
$ |
1.98 |
|
|
$ |
1.87 |
|
|
$ |
1.85 |
|
|
|
* |
|
|
|
N/A |
|
|
Earnings
per class B unit **
|
|
$ |
0.60 |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
|
|
N/A |
|
|
Distributions
per common unit
|
|
$ |
1.87 |
|
|
$ |
1.74 |
|
|
$ |
1.32 |
(b) |
|
$ |
- |
|
|
|
N/A |
|
|
EBITDA***
|
|
$ |
474.6 |
|
|
$ |
349.8 |
|
|
$ |
331.5 |
|
|
$ |
289.0 |
|
|
$ |
144.5 |
|
|
(a)
|
Total
assets for the periods prior to 2008 were revised to conform with the 2008
presentation which reflects a change in accounting policy regarding
recording customer-owned gas held in storage to the more preferable method
of not recording the gas on the balance sheet. As a result, Total assets
decreased $35.3 million, $42.1 million, $27.6 million and $28.3 million,
in 2007, 2006, 2005 and 2004. Note 2 in Item 8 contains more information
regarding this change.
|
|
(b)
|
The
first quarter 2006 distribution represented a prorated portion of the
$0.35 per unit “minimum quarterly distribution” (as defined in our
partnership agreement) for the period November 15, 2005 through December
31, 2005.
|
* Our net
income was $36.0 million, or $0.35 per common and subordinated unit, for the
period from November 15, 2005, the closing date of our initial public offering,
through December 31, 2005.
** Earnings per
Unit
We
calculate net income per limited partner unit in accordance with Emerging Issues
Task Force (EITF) Issue No. 03-6, Participating Securities
and the Two-Class Method under FASB Statement No. 128. In Issue 3 of
EITF No. 03-6, the EITF reached a consensus that undistributed earnings for a
period should be allocated to a participating security based on the
contractual participation rights of the security to share in those earnings as
if all of the earnings for the period had been distributed. Our general
partner holds all of our IDRs which are contractual participation rights as
described in Item 5 of this Report under Incentive Distribution
Rights. The amounts reported for net income per limited partner
unit on the Consolidated Statements of Income for the years ended
December 31, 2008, 2007 and 2006, were adjusted to take into account an
assumed incremental allocation to the general partner's IDRs. Payments made on
account of the IDRs are determined in relation to actual declared
distributions.
In June
2008, we issued and sold approximately 22.9 million class B units. These class B
units began sharing in earnings allocations on July 1, 2008. In November 2008,
all of the 33.1 million subordinated units converted to common
units.
***Non-GAAP
Financial Measure
EBITDA
is used as a supplemental financial measure by management and by external users
of our financial statements, such as investors, commercial banks, research
analysts and rating agencies, to assess:
|
·
|
our
financial performance without regard to financing methods, capital
structure or historical cost
basis;
|
|
·
|
our
ability to generate cash sufficient to pay interest on our indebtedness
and to make distributions to our
partners;
|
|
·
|
our
operating performance and return on invested capital as compared to those
of other companies in the natural gas transportation, gathering and
storage business, without regard to financing methods and capital
structure; and
|
|
·
|
the
viability of acquisitions and capital expenditure
projects.
|
EBITDA
should not be considered an alternative to, or more meaningful than, net income,
operating income, cash flow from operating activities or any other measure of
financial performance or liquidity presented in accordance with GAAP, or as an
indicator of our operating performance or liquidity. Certain items excluded from
EBITDA are significant components in understanding and assessing a company’s
financial performance, such as a company’s cost of capital and tax structure, as
well as historic costs of depreciable assets. We have included information
concerning EBITDA because EBITDA provides additional information as to our
ability to meet our fixed charges and is presented solely as a supplemental
measure. However, viewing EBITDA as an indicator of our ability to make cash
distributions on our common units should be done with caution, as we might be
required to conserve funds or to allocate funds to business or legal purposes
other than making distributions. EBITDA is not necessarily comparable to a
similarly titled measure of another company.
The following table presents a
reconciliation of EBITDA to net income, the most directly comparable GAAP
financial measures for each of the periods presented below (in
millions):
|
|
|
Boardwalk
Pipeline Partners, LP
|
|
|
|
|
For
the Year Ended December 31,
|
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
Net
income
|
|
$ |
294.0 |
|
|
$ |
227.7 |
|
|
$ |
197.6 |
|
|
$ |
100.9 |
|
|
$ |
48.8 |
|
|
Income
taxes and charge-in-lieu of income taxes
|
|
|
1.0 |
|
|
|
0.8 |
|
|
|
0.2 |
|
|
|
49.5 |
|
|
|
32.3 |
|
|
Elimination
of cumulative deferred taxes
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
10.1 |
|
|
|
- |
|
|
Depreciation
and amortization
|
|
|
124.8 |
|
|
|
81.8 |
|
|
|
75.8 |
|
|
|
72.1 |
|
|
|
34.0 |
|
|
Interest
expense
|
|
|
57.7 |
|
|
|
61.0 |
|
|
|
62.1 |
|
|
|
60.1 |
|
|
|
30.1 |
|
|
Interest
income
|
|
|
(2.9 |
) |
|
|
(21.5 |
) |
|
|
(4.2 |
) |
|
|
(1.5 |
) |
|
|
(0.3 |
) |
|
Interest
income from affiliates, net
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(2.2 |
) |
|
|
(0.4 |
) |
|
EBITDA
|
|
$ |
474.6 |
|
|
$ |
349.8 |
|
|
$ |
331.5 |
|
|
$ |
289.0 |
|
|
$ |
144.5 |
|
The following discussion and analysis
of financial condition and results of operations should be read in conjunction
with our consolidated financial statements and the related notes thereto,
included in Item 8, and with Item 1A, Risk Factors.
Overview
Through our subsidiaries, Gulf
Crossing, Gulf South and Texas Gas, we own and operate three interstate natural
gas pipeline systems including integrated storage facilities. Our pipeline
systems originate in the Gulf Coast region and extend northeasterly to the
Midwestern states of Tennessee, Kentucky, Illinois, Indiana and
Ohio.
Our
pipeline systems contain approximately 14,000 miles of pipeline, directly
serving customers in twelve states and indirectly serving customers throughout
the northeastern and southeastern U.S. through numerous interconnections with
unaffiliated pipelines. In 2008, our pipeline systems transported approximately
1.7 Tcf of gas resulting in average daily throughput of approximately 4.8 Bcf.
Our natural gas storage facilities are comprised of eleven underground storage
fields located in four states with aggregate working gas capacity of
approximately 160.0 Bcf. We conduct all of our natural gas transportation and
integrated storage operations through our operating subsidiaries operating as
one segment.
Our
transportation services consist of firm transportation, whereby the customer
pays a capacity reservation charge to reserve pipeline capacity at certain
receipt and delivery points along our pipeline systems, plus a commodity and
fuel charge on the volume of natural gas actually transported, and interruptible
transportation, whereby the customer pays to transport gas only when capacity is
available and used. We offer firm storage services in which the customer
reserves and pays for a specific amount of storage capacity, including injection
and withdrawal rights, and interruptible storage and PAL services where the
customer receives and pays for capacity only when it is available and used. Some
PAL agreements are paid for at inception of the service and revenues for these
agreements are recognized as service is provided over the term of the agreement.
For the year ended December 31, 2008, the percentage of our total operating
revenues associated with firm contracts was approximately 88%.
We are not in the business of buying
and selling natural gas other than for system management purposes, but changes
in the price of natural gas can affect the overall supply and demand of natural
gas, which in turn can affect our results of operations. Our business is
affected by trends involving natural gas price levels and natural gas price
spreads, including spreads between physical locations on our pipeline system,
which affect our transportation revenues, and spreads in natural gas prices
across time (for example summer to winter), which primarily affect our storage
and PAL revenues.
Recent
Events
As of
February 18, 2009, we have substantially completed our announced expansion
projects, including recently placing the following assets in
service:
|
·
|
Phase
III of our Western Kentucky Storage
Expansion;
|
|
·
|
the
first 66 miles of our Fayetteville Lateral, which includes a temporary
river crossing;
|
|
·
|
the
remaining compression related to our Southeast
Expansion;
|
|
·
|
the
pipeline portion of our Gulf Crossing Project;
and
|
|
·
|
a
portion of our Greenville Lateral.
|
For more
information regarding our expansion projects see Expansion Projects in Item 1 of
this Report.
We
recently signed precedent agreements for 0.2 Bcf per day of capacity that will
support expanding our system from the Haynesville production area in northwest
Louisiana to Perryville, Louisiana. This project will consist of adding
compression to our Gulf South system at an estimated cost of up to $105
million. We expect to finance this project with additional debt and expect
to place this project in service in the fourth quarter 2010, subject to
regulatory approvals.
On
February 5, 2009, we announced a quarterly distribution of $0.48 per unit,
payable on February 23, 2009 to unitholders of record as of February 16,
2009.
In
January 2009, we borrowed the remaining unfunded commitments under our revolving
credit facility, which increased borrowings under the facility to $953.5
million.
Factors
that Impact our Results of Operations
A
significant portion of our operating revenues is derived from reservation
charges under multi-year firm contracts, therefore the risk of revenue
fluctuations due to near-term changes in natural gas supply and demand
conditions, competition and price volatility is significantly mitigated. For the
year ended December 31, 2008, 66% of our operating revenues were associated with
reservation charges under firm contracts which do not vary based on capacity
utilization. Excluding contracts associated with our expansion projects
currently under construction, the weighted average contract life of our
contracts is approximately 4.1 years. Regardless of these factors, our business
can be impacted by shifts in supply and demand dynamics, the mix of services
requested by customers and by competition and regulatory requirements,
particularly when accompanied by downturns or sluggishness in the economy,
especially over a longer term.
Changing
Customer Mix and Credit Profile
After
completion of our expansion projects, producers will comprise a larger portion
of our revenues, both as a group and separately. We expect producers as a group
to contribute a much more significant portion of our future revenues, and one
producer to represent over 10% of our 2009 revenues. Historically producers
have had lower credit ratings than LDCs and LDC-sponsored marketing companies,
which have typically accounted for a large portion of our revenues.
Therefore the expected change in our customer base could result in higher total
credit risk.
Current
economic conditions also indicate that many of our customers may encounter
increased credit risk in the near term. We actively monitor the credit status of
our counterparties and to date have not had any significant credit defaults
associated with our transactions. However, given the current volatility in the
financial markets, we cannot be certain that we will not experience such losses
in the future. Item 1A, Risk Factors, of this Report
contains more information regarding the risks related to our customer
base.
Competition
and Contract Renewals
We
compete primarily with other interstate and intrastate pipelines in the
transportation and storage of natural gas, particularly in the Midwest and Gulf
Coast states where we compete with numerous existing pipelines and will compete
with pipelines under construction such as the Rockies Express Pipeline and the
Mid-Continent Express Pipeline. We compete for renewals of expiring
transportation and storage contracts, as well as new transportation contracts
that will support growth projects.
Despite
these competitive conditions, substantially all of the operating capacity on our
expansion projects is sold out and our legacy systems are supported by long-term
contracts having an average remaining life of 4.1 years. However, as of December
31, 2008, approximately 17% of the firm contract load on our pipeline systems,
excluding agreements related to the expansion projects not yet in service, was
due to expire on or before December 31, 2009. In addition, approximately 55% of
our long-term contracts with firm deliveries to Lebanon, Ohio, the northeastern
terminus of our pipeline system, will expire or become terminable by the
customer by the end of 2010. In 2008, we were successful in remarketing and
renewing the approximately 25% of our firm contract load that was due to expire
during that year, in many cases obtaining favorable rates and extended contract
terms. Notwithstanding that success, however, the 2009 and 2010 contract
expirations and termination rights create uncertainty as we cannot give
assurances that we will successfully remarket this capacity. Our ability to
remarket available capacity will be impacted by additional competition from
newly constructed pipelines, fluctuating commodity prices, a recessionary
economy which could impact demand for and supply of natural gas and numerous
other factors beyond our control. Item 1A, Risk Factors, contains more
information regarding the risks related to competition in our
industry.
Natural
Gas Prices
High
natural gas prices in recent years have driven increased production levels in
producing locations such as the Bossier Sands and Barnett Shale gas producing
regions in East Texas, which have resulted in widened basis differentials on our
systems and have benefited our transportation revenues. The high natural gas
prices have also driven increased production in regions such as the Fayetteville
Shale in Arkansas and the Caney Woodford Shale in Oklahoma, which, together with
the higher production levels in East Texas, have formed the basis for several
pipeline expansion projects including those constructed and being undertaken by
us.
The price
for natural gas has declined since its peak in the late summer 2008, although
average prices continue to remain at elevated levels from those seen
historically. Many of our customers have been negatively impacted by these
recent declines in natural gas prices as well as current conditions in the
capital markets, which factors have caused several of our producer customers to
announce plans to decrease drilling levels and, in some cases, to consider
shutting in natural gas production from some producing wells, which could
adversely affect the volumes of natural gas we transport. While the majority of
our revenue is derived from capacity reservation charges that are not impacted
by the volume of natural gas transported; a significant portion of our revenue,
approximately 34% in 2008, is derived from charges based on actual volumes
transported under firm and interruptible services. As a result, lower volumes of
natural gas transported would result in lower revenues from natural gas
transportation operations. Based on the significant level of revenue we receive
from reservation capacity charges under long-term contracts and our review of
the recent announcements of drilling plans by our customers, we do not expect
the current level of natural gas prices to have a significant adverse effect on
our operating results. However, we cannot give assurances that this will be the
case, or that commodity prices will not decline further, which could result in a
further reduction in drilling activities by our customers.
In
addition, spreads in natural gas prices between time periods, such as winter to
summer, impact our PAL and interruptible storage revenues. These period to
period price spreads, which were favorable for our PAL and interruptible storage
services during 2006 and early 2007, decreased substantially in 2007 and
continued to decrease into 2008, which resulted in reduced PAL and interruptible
storage revenues for those periods. We cannot predict future time period spreads
or basis differentials.
Reduction
of Operating Pressures on Expansion Pipelines; Applications for Special Permits
from PHMSA
As
discussed elsewhere in this report, we have discovered anomalies in a small
number of pipe segments on our East Texas Pipeline. As a result, and as a
prudent operator, we have elected to reduce operating pressures on that pipeline
to 20% below its previous operating level, which was below the pipeline’s
maximum non-special permit operating pressures. Operating at lower pressures
reduces the amount of gas that can flow through a pipeline and therefore will
reduce our expected revenues and cash flow. We do not expect to return to normal
operating pressures, or to operate at higher pressures under the special permit
discussed below, until after we have completed our investigation and remediation
measures, as appropriate, and PHMSA has concurred with our determination to
increase pressures. We will also incur costs to replace defective pipe segments
on the East Texas Pipeline, some of which may be reimbursable from vendors, and
expect to temporarily shut down that pipeline when performing the necessary
remedial measures, up to and including replacing certain pipe segments. We will
work with PHMSA to return the East Texas Pipeline to its previous status under
the special permit after we have completed our investigation and
remediation. We
cannot determine at this time the amount of costs we will incur or when we might
raise operating pressures. We have not completed testing on all of
our expansion pipelines and could find anomalies on other pipelines which could
have similar impacts with respect to those pipelines.
Our
ability to transport a portion of the expected maximum capacity on each of our
expansion project pipelines is contingent upon our receipt of authority to
operate these pipelines at higher operating pressures under special permits
issued by PHMSA. We have received authority to operate the East Texas Pipeline
under a special permit and have received the special permits for our Southeast,
Gulf Crossing and Fayetteville and Greenville Laterals, but we have not received
authority to operate under these permits. PHMSA retains discretion as to whether
to grant, or to maintain in force, authority to operate any of our pipelines at
higher operating pressures. Absent such authority, we will not be able to
transport all of the contracted for quantities of natural gas on these
pipelines. To the extent that PHMSA does not grant us authority to operate
any of our expansion pipelines under a special permit or withdraws previously
granted authority to operate under a special permit, transportation capacity
made available to the market and our transportation revenues and cash flows
would be reduced.
For
additional information, see Item 1 – Business – Expansion Projects and Item
1A – Risk Factors –
A portion of the expected
maximum daily capacity of our pipeline expansion projects is subject to our
obtaining and maintaining authority from PHMSA to operate under higher operating
pressures.
Credit
and Capital Markets Disruption
Current
economic conditions have made it difficult for companies to obtain funding in
either the debt or equity markets. The current constraints in the capital
markets may affect our ability to obtain funding through new borrowings or the
issuance of equity in the public markets. In addition, we expect that, to the
extent we are successful in arranging new debt financing, we will incur
increased costs associated with these debt financings. As of December 31, 2008,
in addition to $312.7 million of cash on hand and short-term investments, we had
available capacity under our credit facility of $161.5 million which we
subsequently fully borrowed against. We expect to utilize these resources, along
with cash from operations and proceeds from debt and equity offerings, to fund
our growth capital expenditures and working capital needs during 2009. See Liquidity and Capital
Resources – Expansion
Capital Expenditures below for a discussion of our financing plans for
our current expansion projects.
Financial
Analysis of Operations
We derive our revenues primarily from
the interstate transportation and storage of natural gas for third parties.
Transportation and storage services are provided under firm and interruptible
service agreements. Our operating costs and expenses typically do not vary
significantly based upon the amount of gas transported, with the exception of
fuel consumed at our compressor stations, which is included in Fuel and gas
transportation expenses on our Consolidated Statements of Income. The following
analysis discusses our financial results of operations for the years 2008, 2007
and 2006.
2008
Compared with 2007
Our net
income for the year ended December 31, 2008 increased $66.3 million, or 29%, to
$294.0 million compared to $227.7 million for the year ended December 31, 2007.
The primary drivers for the increase were higher revenues from services
associated with our expansion projects and gains from the disposition of coal
reserves, gas sales associated with our storage expansion and the settlement of
a contract claim. The favorable drivers were partly offset by lower PAL revenues
due to unfavorable natural gas price spreads and higher depreciation and
property tax expense due to an increase in our asset base from expansion. The
2007 period was unfavorably impacted by a $14.7 million impairment charge
related to the Magnolia storage facility.
Operating
revenues for the year ended December 31, 2008 increased $141.6 million, or 22%,
to $784.8 million, compared to $643.2 million for the year ended December 31,
2007. Gas transportation revenues, excluding fuel, increased $112.1 million,
primarily from our expansion projects and higher no-notice and interruptible
services on our existing assets. Fuel revenues increased $43.9 million due to
expansion-related throughput and higher natural gas prices. Gas storage revenues
increased $12.1 million related to an increase in storage capacity associated
with our Western Kentucky Storage Expansion. These increases were partially
offset by lower PAL revenues of $26.5 million due to unfavorable natural gas
price spreads.
Operating
costs and expenses for the year ended December 31, 2008 increased $61.0 million,
or 16%, to $438.2 million, compared to $377.2 million for the year ended
December 31, 2007. The primary drivers were increased depreciation and other
taxes, comprised primarily of property taxes, of $56.3 million associated with
an increase in our asset base, increased fuel costs of $50.2 million mainly from
providing service on our expansion projects and higher natural gas prices and
$5.8 million of third party transportation costs associated with providing
customers of our expansion projects access to off-system markets. Administrative
and general expenses increased $5.4 million due to increased outside services
mainly due to legal matters, information technology-related expenses from
infrastructure improvements, corporate services, higher property insurance
from an increase in rates and asset base and a bad debt recovery that favorably
impacted the 2007 period. The increases to operating expenses were offset by
gains of $16.5 million from the disposition of coal reserves, $12.4 million on
the sale of gas related to our Western Kentucky Storage Expansion and $11.2
million from the settlement of a contract claim. Additionally, in the fourth
quarter 2008, we changed our employee paid time-off benefits, resulting in a
reduction in operation and maintenance expenses of $4.9 million and a reduction
of administrative and general expenses of $2.3 million. The 2007 period was
unfavorably impacted by a $14.7 million impairment charge related to our
Magnolia storage project.
Total
other deductions increased by $14.1 million, or 38%, to $51.6 million for the
year ended December 31, 2008, compared to $37.5 million for the 2007 period,
primarily as a result of $18.6 million of decreased interest income due to lower
average cash balances available for investment, partly offset by a $3.3 million
reduction in interest expense from higher capitalized interest associated with
our expansion projects.
2007
Compared with 2006
Our net
income for the year ended December 31, 2007 increased $30.1 million, or 15%, to
$227.7 million compared to $197.6 million for the year ended December 31, 2006.
The primary drivers for the increase were higher revenues from strong demand for
firm transportation services, including pipeline system expansion and related
fuel revenues. Higher operating expenses driven by a variety of factors, mainly
charges for impairment and remediation costs associated with certain assets,
increased fuel and higher depreciation and amortization were substantially
offset by higher interest income. The 2007 results were also favorably impacted
by a gain on the sale of gas associated with a storage expansion project, which
was accounted for as a reduction of operating expenses.
Total
operating revenues increased $35.6 million, or 6%, to $643.2 million for the
year ended December 31, 2007, compared to $607.6 million for the year ended
December 31, 2006. Gas transportation revenues increased $23.4 million due to
higher firm transportation rates, including $8.9 million from new contracts
associated with a pipeline expansion which was in service for all of 2007. Fuel
revenues increased $11.9 million due to increased retained volumes from higher
system utilization including amounts associated with pipeline
expansion.
Operating
costs and expenses increased $23.5 million, or 7%, to $377.2 million for the
year ended December 31, 2007, compared to $353.7 million for the year ended
December 31, 2006. The primary drivers were impairment charges of $14.7 million
related to the Magnolia storage facility and $4.5 million associated with
offshore pipeline assets in the South Timbalier Bay area, and an $11.0 million
increase in depreciation and other taxes associated with an increase in our
asset base from expansion. Other increases included fuel costs of $6.9 million
due to an increase in gas usage, a $4.8 million charge related to re-covering
offshore assets and a $3.8 million charge related to the termination of an
agreement with a construction contractor on the Southeast Expansion project.
These increases were offset by a $22.0 million gain on the sale of gas
associated with the Western Kentucky Storage Expansion project which was
reported in Net gain on disposal of operating assets and related
contracts.
Total
other deductions declined by $18.6 million, or 33%, to $37.5 million for the
year ended December 31, 2007, compared to $56.1 million for the year ended
December 31, 2006. The reduction was primarily due to an increase in interest
income of $17.3 million as a result of higher levels of invested cash which we
accumulated through sales of our debt and equity to finance the cost of our
expansion projects.
Liquidity
and Capital Resources
We are a partnership holding company
and derive all of our operating cash flow from our operating subsidiaries. Our
principal sources of liquidity include cash generated from operating activities,
our revolving credit facility, debt issuances and sales of limited partner
units. Our operating subsidiaries use funds from their respective operations to
fund their operating activities and maintenance capital requirements, service
their indebtedness and make advances or distributions to Boardwalk Pipelines.
Boardwalk Pipelines uses cash provided from the operating subsidiaries and, as
needed, borrowings under its revolving credit facility discussed below, to
service its outstanding indebtedness and, when available, make distributions or
advances to us to fund our distributions to unitholders. We have no material
guarantees of debt or other similar commitments to unaffiliated
parties.
Our operating subsidiaries participate
in an intercompany cash management program to the extent they are permitted
under FERC regulations. Under the cash management program, depending on whether
a participating subsidiary has short-term cash surpluses or cash requirements,
Boardwalk Pipelines either provides cash to them or they provide cash to
Boardwalk Pipelines.
Beginning
in 2007 and continuing in 2008, the capital markets have been impacted by
macroeconomic, liquidity, credit and recessionary concerns. During this
period, we have continued to have access to the majority of our credit facility
to fund our short-term liquidity needs. In 2008, we issued common units and
class B units and received additional contributions from our general partner. We
also received net proceeds of $247.2 million from the issuance of long-term debt
in March 2008. See discussion below under Equity and Debt Financing. Our ability to
continue to access capital markets for debt and equity financing under
reasonable terms depends on our financial condition, credit ratings and market
conditions. We anticipate that our existing capital resources, ability to obtain
financing and cash flow generated from future operations will enable us to
maintain our current level of operations and our planned operations, including
capital expenditures, for 2009.
Maintenance
Capital Expenditures
Maintenance capital expenditures were
$50.5 million, $47.1 million and $41.7 million in 2008, 2007 and 2006. We expect
to fund our 2009 maintenance capital expenditures of approximately $67.8 million
from our operating cash flows.
Expansion
Capital Expenditures
We are
currently engaged in several pipeline expansion projects, described in Item I,
Our Business – Expansion
Projects, of this Report and expect the estimated total cost of these
projects to be as follows (in millions):
|
|
|
Estimated
Total Cost
(1)
|
|
|
Cash
Invested through
December
31,
2008
|
|
|
Southeast
Expansion
|
|
$ |
775 |
|
|
$ |
707.3 |
|
|
Gulf
Crossing Project
|
|
|
1,800 |
|
|
|
1,403.5 |
|
|
Fayetteville
and Greenville Laterals
|
|
|
1,290 |
|
|
|
684.2 |
|
|
Total
|
|
$ |
3,865 |
|
|
$ |
2,795.0 |
|
|
(1)
|
Our
cost estimates are based on internally developed financial models and
timelines. Factors in the estimates include, but are not limited to, those
related to pipeline costs based on mileage, size and type of pipe,
materials and construction and engineering
costs.
|
Based
upon our current cost estimates, we expect to incur capital expenditures of
approximately $1.0 billion in 2009 and 2010 to complete our pipeline expansion
projects. The majority of the expenditures are expected to occur during the
first half of 2009, with the remaining costs associated with the construction of
additional compression facilities for the Gulf Crossing Project and the
Fayetteville and Greenville Laterals to be incurred in the latter half of 2009
and into 2010.
We are
also engaged in the Western Kentucky Storage Expansion project. The cost of this
project is expected to be approximately $87.7 million. Through December 31,
2008, we spent $48.0 million related to this project.
Our cost
and timing estimates for these projects are subject to a variety of risks and
uncertainties, including obtaining regulatory approvals; adverse weather
conditions; delays in obtaining key materials; shortages of qualified labor and
escalating costs of labor and materials. As the announced expansion projects
move toward completion, the risks and uncertainties associated with the
expansion projects are decreasing. However, certain risks remain, primarily
involving river crossings and receipt of regulatory authority to operate the
pipelines at higher operating pressures.
We have
financed our expansion capital costs through the issuance of equity and debt,
including sales of debt by us and our subsidiaries, borrowings under our
revolving credit facility and available operating cash flow in excess of our
operating needs. We anticipate we will need to finance an additional $500.0
million to complete our expansion projects. Our largest unitholder, Loews, has
advised us that it is willing to provide the capital we need to complete the
expansion projects to the extent the public markets remain unavailable on
acceptable terms. We have not committed to any transaction at this time,
however, and any additional financing provided by Loews would be subject to
review and approval, as to fairness, by our independent Conflicts Committee.
Item 1A, Risk Factors,
contains more information regarding risks associated with our expansion projects
and the related financing.
Equity
and Debt Financing
In 2008,
we received net cash proceeds of approximately $1.7 billion from the following
equity and debt issuances which proceeds were used to fund a portion of the
costs of our ongoing expansion projects and to repay amounts borrowed under our
revolving credit facility (in millions, except issue price):
|
Month
of Issuance
|
|
Net
Cash Proceeds Received
|
|
Number
of Units
|
|
Issue
Price
|
|
Type
of Issuance
|
|
October
|
|
$
|
500.0
(a)
|
|
21.2
|
|
$
|
23.13
|
|
Private
placement of common units to BPHC
|
|
June
|
|
|
700.0
(b)
|
|
22.9
|
|
|
30.00
|
|
Private
placement of class B units to BPHC
|
|
June
|
|
|
248.8
(c)
|
|
10.0
|
|
|
25.30
|
|
Public
offering of common units
|
|
March
|
|
|
247.2
|
|
N/A
|
|
|
N/A
|
|
Public
offering of debt securities
|
|
(a)
|
Includes
a $10.0 million contribution received from our general partner to maintain
its 2% general partner interest.
|
|
(b)
|
Includes
a $14.0 million contribution received from our general partner to maintain
its 2% general partner interest.
|
|
(c)
|
Includes
a $5.2 million contribution received from our general partner to maintain
its 2% general partner interest.
|
We also
borrowed under our revolving credit facility, to the extent necessary, to
finance our expansion projects. As discussed in Expansion Capital
Expenditures we have a committed sponsor in Loews who has agreed to
finance up to the remaining amount necessary to complete our expansion projects
to the extent that the capital markets are not available on acceptable
terms. We do not have an immediate need to refinance any of our
long-term debt, including borrowings under our revolving credit facility, as the
earliest maturity date of such indebtedness is in 2012. We believe that our cash
flow from operations will be sufficient to support our ongoing operations and
maintenance capital requirements.
Credit
Facility
We
maintain a revolving credit facility which has aggregate lending commitments of
$1.0 billion, under which Boardwalk Pipelines, Gulf South and Texas Gas each may
borrow funds, up to applicable sub-limits. A financial institution which has a
$50.0 million commitment under the revolving credit facility filed for
bankruptcy protection in the third quarter 2008 and has not funded its portion
of our borrowing requests since that time. Interest on amounts drawn under the
credit facility is payable at a floating rate equal to an applicable spread per
annum over the London Interbank Offered Rate or a base rate defined as the
greater of the prime rate or the Federal funds rate plus 50 basis points. The
revolving credit facility has a maturity date of June 29, 2012.
As of
December 31, 2008, we had $792.0 million of loans outstanding under the
revolving credit facility with a weighted-average interest rate on the
borrowings of 3.43% and had no letters of credit issued. We were in compliance
with all covenant requirements under our credit facility at December 31,
2008. Subsequent to December 31, 2008, we borrowed all of the
remaining unfunded commitments under the credit facility (excluding the unfunded
commitment of the bankrupt lender noted above) which increased borrowings to
$953.5 million.
Our
revolving credit facility contains customary negative covenants, including,
among others, limitations on the payment of cash dividends and other restricted
payments, the incurrence of additional debt, sale-leaseback transactions and
transactions with our affiliates. The facility also contains a financial
covenant that requires us and our subsidiaries to maintain a ratio of total
consolidated debt to consolidated earnings before income taxes, depreciation and
amortization (as defined in the credit agreement), measured for the preceding
twelve months, of not more than five to one. Although we do not believe that
these covenants have had, or will have, a material impact on our business and
financing activities or our ability to obtain the financing to maintain
operations and continue our capital investments, they could restrict us in some
circumstances as stated in Item 1A, Risk Factors. In particular,
maintaining compliance with the financial covenant may limit our ability to
incur additional indebtedness to finance our growth projects, which could limit
our growth opportunities or require the issuance of more equity securities by us
than previously anticipated.
Contractual
Obligations
The following table summarizes
significant contractual cash payment obligations under firm commitments as of
December 31, 2008, by period (in millions):
|
|
|
Total
|
|
|
Less
than 1 Year
|
|
|
1-3
Years
|
|
|
4-5
Years
|
|
|
More
than 5 Years
|
|
|
Principal
payments on long-term debt (1)
|
|
$ |
2,902.0 |
|
|
|
- |
|
|
|
- |
|
|
$ |
1,267.0 |
|
|
$ |
1,635.0 |
|
|
Interest
on long-term debt (2)
|
|
|
921.9 |
|
|
$ |
117.5 |
|
|
$ |
234.9 |
|
|
|
214.4 |
|
|
|
355.1 |
|
|
Capital
commitments (3)
|
|
|
198.7 |
|
|
|
195.8 |
|
|
|
2.9 |
|
|
|
- |
|
|
|
- |
|
|
Pipeline
capacity agreements (4)
|
|
|
102.8 |
|
|
|
12.6 |
|
|
|
22.5 |
|
|
|
20.5 |
|
|
|
47.2 |
|
|
Operating
lease commitments
|
|
|
25.7 |
|
|
|
3.3 |
|
|
|
6.2 |
|
|
|
6.0 |
|
|
|
10.2 |
|
|
Total
|
|
$ |
4,151.1 |
|
|
$ |
329.2 |
|
|
$ |
266.5 |
|
|
$ |
1,507.9 |
|
|
$ |
2,047.5 |
|
|
(1)
|
This
includes our senior unsecured notes, having maturity dates from 2012 to
2027 and $792.0 million of loans outstanding under our revolving credit
facility, having a maturity date of June 29,
2012.
|
|
(2)
|
Interest
obligations represent interest due on our senior unsecured notes at fixed
rates. Future interest obligations under our revolving credit facility are
uncertain, due to the variable interest rate and fluctuating balances.
Based on a 3.43% weighted-average interest rate on amounts outstanding
under our revolving credit facility as of December 31, 2008, $27.2
million, $54.3 million and $13.6 million would be due under the credit
facility in less than one year, 1-3 years, and 4-5
years.
|
|
(3)
|
Capital
commitments represent binding commitments under purchase orders for
materials ordered but not received and firm commitments under binding
construction service agreements existing at December 31, 2008. The amounts
shown do not reflect commitments we have made after December 31, 2008. For
information on these projects, please read Expansion Capital
Expenditures.
|
|
(4)
|
The
amounts shown are associated with various pipeline capacity agreements on
third-party pipelines that allow our operating subsidiaries to transport
gas to off-system markets on behalf of our
customers.
|
Pursuant to the settlement of the Texas
Gas rate case in 2006, we are required to annually fund an amount to the Texas
Gas pension plan equal to the amount of actuarially determined net periodic
pension cost, including a minimum of $3.0 million. In 2009, we expect to
fund approximately $5.0 million to the Texas Gas pension plan.
Cash
and Cash Equivalents and Short-term Investments
At
December 31, 2008, we had $137.7 million of cash and cash equivalents invested
primarily in Treasury funds and $175.0 million of short-term investments. In
December 2008, we began investing a portion of our cash and cash equivalents in
U.S. Government securities, primarily Treasury notes, under repurchase
agreements. Generally, we have engaged in overnight repurchase transactions
where purchased securities are sold back to the counterparty the following
business day. Pursuant to the master repurchase agreements, we take actual
possession of the purchased securities. In the event of default by the
counterparty under the agreement, the repurchase would be deemed immediately to
occur and we would be entitled to sell the securities in the open market, or
give the counterparty credit based on the market price on such date, and apply
the proceeds (or deemed proceeds) to the aggregate unpaid repurchase amounts and
any other amounts owing by the counterparty. Note 14 in Item 8 of this Report
contains more information about our short-term investments.
Changes
in cash flow from operating activities
Net cash
provided by operating activities increased $68.6 million to $350.3 million for
the year ended December 31, 2008, compared to $281.7 million for the comparable
2007 period, primarily due to a $78.8 million increase in cash from the change
in net income, excluding non-cash items such as depreciation and amortization
and the recognition of income previously deferred. This increase was offset
by an $11.0 million decrease in cash due to the settlement of
derivatives.
Changes
in cash flow from investing activities
Net cash
used in investing activities increased $1,577.1 million to $2,757.4 million for
the year ended December 31, 2008, compared to $1,180.3 million for the
comparable 2007 period, primarily due to a $1,442.7 million increase in capital
expenditures related to our expansion projects and a $175.0 million purchase of
short-term investments in 2008. These increases in the use of cash from
investing activities were offset by $35.1 million in net proceeds from the sale
of gas related to our storage expansion projects and the sale of an investment
in coal reserves.
Changes
in cash flow from financing activities
Net cash
provided by financing activities increased $1,410.6 million to $2,227.5 million
for the year ended December 31, 2008, compared to $816.9 million for the
comparable 2007 period. An increase of $922.2 million resulted from net proceeds
received from the issuance of common and class B units, including related
general partner capital contributions. Net proceeds from the issuance of
long-term debt and borrowings under our revolving credit facility increased
$543.9 million. These increases in cash from financing activities were partially
offset by a $55.5 million increase in distributions to our
partners.
Impact
of Inflation
We have experienced increased costs in
recent years due to the effect of inflation on the cost of labor, benefits,
materials and supplies, and property, plant and equipment (PPE). A portion of
the increased labor and materials and supplies costs have directly affected
income through increased operating costs and depreciation expense. The
cumulative impact of inflation over a number of years has resulted in increased
costs for current replacement of productive facilities. The majority of our PPE
and materials and supplies is subject to rate-making treatment, and under
current FERC practices, recovery is limited to historical costs. Amounts in
excess of historical cost are not recoverable unless a rate case is filed.
However, cost-based regulation, along with competition and other market factors,
may limit our ability to price jurisdictional services to ensure recovery of
inflation’s effect on costs.
Off-Balance
Sheet Arrangements
At December 31, 2008, we had no
guarantees of off-balance sheet debt to third parties, no debt obligations that
contain provisions requiring accelerated payment of the related obligations in
the event of specified levels of declines in credit ratings, and no other
off-balance sheet arrangements.
Critical
Accounting Policies
Certain
amounts included in or affecting our consolidated financial statements and
related disclosures must be estimated, requiring us to make certain assumptions
with respect to values or conditions that cannot be known with certainty at the
time the financial statements are prepared. These estimates and assumptions
affect the amounts we report for assets and liabilities and our disclosure of
contingent assets and liabilities in our financial statements. We evaluate these
estimates on an ongoing basis, utilizing historical experience, consultation
with third parties and other methods we consider reasonable. Nevertheless,
actual results may differ significantly from our estimates. Any effects on our
business, financial position or results of operations resulting from revisions
to these estimates are recorded in the periods in which the facts that give rise
to the revisions become known.
Regulation
Pursuant
to FERC regulations certain revenues that we collect may be subject to possible
refunds to our customers. Accordingly, during an open rate case, estimates of
rate refund reserves are recorded based on regulatory proceedings, advice of
counsel and estimated risk-adjusted total exposure, as well as other factors. At
December 31, 2008 and 2007, there were no liabilities for any open rate case
recorded on our Consolidated Balance Sheets. Currently, neither Gulf South nor
Texas Gas is involved in an open general rate case, however Gulf Crossing will
either have to file a rate case or justify its initial firm transportation rates
within three years after the pipeline is fully placed in service.
Our subsidiaries are regulated by FERC.
SFAS No. 71, Accounting for
the Effects of Certain Types of Regulation, requires certain
rate-regulated entities to account for and report assets and liabilities
consistent with the economic effect of the manner in which independent
third-party regulators establish rates. SFAS No. 71 is applicable to operations
of our Texas Gas subsidiary which record certain costs and benefits as
regulatory assets and liabilities, respectively, in order to provide for
recovery from or refund to customers in future periods. The provisions of SFAS
No. 71 are not applicable to operations associated with the Texas Gas
Fayetteville and Greenville Laterals project and Phase III of the Western
Kentucky Storage Expansion project due to the regulatory treatment and
contractual rates associated with the projects. The provisions of SFAS No. 71
are not applicable to Gulf Crossing due to discounts under negotiated rate
agreements, or Gulf South because competition in the market areas of Gulf South
has resulted in discounts from the maximum allowable cost-based rates being
granted to customers and certain services provided by Gulf South are priced
using market-based rates, such that the application of the standard would not be
appropriate.
We monitor the regulatory and
competitive environment in which we operate to determine that any regulatory
assets continue to be probable of recovery. If we were to determine that all or
a portion of our regulatory assets no longer met the criteria for recognition as
regulatory assets under SFAS No. 71, that portion which was not recoverable
would be written off, net of any regulatory liabilities. Note 6 in Item 8 of
this Report contains more information regarding our regulatory assets and
liabilities.
In the course of providing
transportation and storage services to customers, the pipelines may receive
different quantities of gas from shippers and operators than the quantities
delivered by the pipelines on behalf of those shippers and operators. This
results in transportation and exchange gas receivables and payables, commonly
known as imbalances, which are primarily settled through the receipt or delivery
of gas in the future or with cash. Settlement of imbalances requires agreement
between the pipelines and shippers or operators as to allocations of volumes to
specific transportation contracts and timing of delivery of gas based on
operational conditions. The receivables and payables are valued at market price
for operations where SFAS No. 71 is not applicable and are valued at the
historical value of gas in storage for operations where SFAS No. 71 is
applicable, consistent with the regulatory treatment and the settlement
history.
Environmental
Liabilities
Our environmental liabilities are based
on management’s best estimate of the undiscounted future obligation for probable
costs associated with environmental assessment and remediation of our operating
sites. These estimates are based on evaluations and discussions with counsel and
operating personnel and the current facts and circumstances related to these
environmental matters. At December 31, 2008, we had accrued approximately $16.8
million for environmental matters. Our environmental accrued liabilities could
change substantially in the future due to factors such as the nature and extent
of any contamination, changes in remedial requirements, technological changes,
discovery of new information, and the involvement of and direction taken by the
Environmental Protection Agency, FERC and other governmental authorities on
these matters. We continue to conduct environmental assessments and are
implementing a variety of remedial measures that may result in increases or
decreases in the total estimated environmental costs.
Impairment
of Long-Lived Assets
We
periodically evaluate whether the carrying value of long-lived assets has been
impaired when circumstances indicate the carrying value of those assets may not
be recoverable in accordance with SFAS No. 144, Accounting for the Impairment or
Disposal of Long-Lived Assets. This evaluation is based on undiscounted
cash flow projections expected to be realized over the remaining useful life of
the asset. The carrying amount is not recoverable if it exceeds the undiscounted
sum of cash flows expected to result from the use and eventual disposition of
the asset. If the carrying value is not recoverable, the impairment loss is
measured as the excess of the asset’s carrying value over its fair
value.
In 2008,
we completed a review of our non-contiguous offshore assets and provided notice
to the other interest holders of our intent to discontinue any use of our
portion of the capacity available to us as a result of our investment in the
assets. As a result, we reviewed the assets for recoverability and recorded an
impairment charge of approximately $3.0 million representing the book value of
the assets.
We were
developing a salt dome storage cavern near Napoleonville,
Louisiana. Operational tests, which were completed in July 2007, indicated
that due to geological and other anomalies that could not be corrected, we would
be unable to place the cavern in service as expected. As a result, we
elected to abandon that cavern and are exploring the possibility of securing a
new site on which a new cavern could be developed. In accordance with the
requirements of SFAS No. 144, the carrying value of the cavern and related
facilities was tested for recoverability. In the second quarter 2007, we
recognized an impairment charge to earnings of approximately $14.7 million,
representing the carrying value of the cavern, the fair value of which was
determined to be zero based on discounted expected future cash flows. We expect
to use the other assets associated with the project, which include pipeline,
compressors, and other equipment and facilities, in conjunction with a
replacement storage cavern to be developed. If we determine in the future that
the assets cannot be used in conjunction with a new cavern or a new cavern
cannot be secured in the same area, we may be required to record an additional
impairment charge at the time that determination is made. Additional costs to
abandon the impaired cavern may be incurred due to regulatory or contractual
obligations; however, the amounts are inestimable at this time.
Goodwill
As of December 31, 2008, we had $163.5
million of goodwill recorded as an asset on our Consolidated Balance Sheets.
SFAS No. 142, Goodwill and
Other Intangible Assets, requires the evaluation of goodwill for
impairment at least annually or more frequently if events and circumstances
indicate that the asset might be impaired.
An impairment test performed in
accordance with SFAS No. 142 requires that a reporting unit’s fair value be
estimated. We used a discounted cash flow model to estimate the fair
value of the reporting unit, and that estimated fair value was compared to the
carrying amount, including goodwill. The estimated fair value was in excess of
the carrying amount at December 31, 2008, and accordingly no impairment was
recognized. Judgments and assumptions were used in management’s estimate of
discounted future cash flows used to calculate the fair value of the reporting
unit, including our five-year financial plan operating results, the long-term
outlook for growth in natural gas demand in the U.S. and systematic or
diversifiable risk used in the calculation of the applied discount rate under
the capital asset pricing model. The use of alternate judgments and/or
assumptions could result in the recognition of an impairment charge in the
financial statements.
Defined
Benefit Plans
We are required to make a significant
number of assumptions in order to estimate the liabilities and costs related to
our pension and postretirement benefit obligations to employees under our
benefit plans. The assumptions that have the most impact on pension costs are
the discount rate, the expected return on plan assets and the rate of
compensation increases. These assumptions are evaluated relative to current
market factors in the U.S. such as inflation, interest rates and fiscal and
monetary policies, as well as our policies regarding management of the plans
such as the allocation of plan assets among investment options. Changes in these
assumptions can have a material impact on pension obligations and pension
expense.
In determining the discount rate
assumption, we utilize current market information and liability information
provided by our plan actuaries, including a discounted cash flow analysis of our
pension and postretirement obligations. In particular, the basis for our
discount rate selection was the yield on indices of highly rated fixed income
debt securities with durations comparable to that of our plan liabilities. The
Moody’s Aa Corporate Bond Index is consistently used as the basis for the change
in discount rate from the last measurement date with this measure confirmed by
the yield on other broad bond indices. Additionally, we supplement our discount
rate decision with a yield curve analysis. The yield curve is applied to
expected future retirement plan payments to adjust the discount rate to reflect
the cash flow characteristics of the plans. The yield curve is developed by the
plans’ actuaries and is a hypothetical AA/Aa yield curve represented by a series
of annualized discount rates reflecting bond issues having a rating of Aa or
better by Moody’s Investors Service, Inc. or a rating of AA or better by
Standard & Poor’s.
Further information on our pension and
postretirement benefit obligations is included in Note 10 in Item 8 of this
Report.
Recent
Accounting Pronouncements
For a discussion regarding recently
issued accounting pronouncements or accounting pronouncements adopted in 2008,
please read Notes 2, 9 and 18 in Item 8 of this Report.
Forward-Looking
Statements
Investors are cautioned that certain
statements contained in this Report, as well as some statements in periodic
press releases and some oral statements made by our officials and our
subsidiaries during presentations about us, are “forward-looking.”
Forward-looking statements include, without limitation, any statement that may
project, indicate or imply future results, events, performance or achievements,
and may contain the words “expect,” “intend,” “plan,” “anticipate,” “estimate,”
“believe,” “will likely result,” and similar expressions. In addition, any
statement made by our management concerning future financial performance
(including future revenues, earnings or growth rates), ongoing business
strategies or prospects, and possible actions by our partnership or its
subsidiaries, are also forward-looking statements.
Forward-looking statements are based on
current expectations and projections about future events and are inherently
subject to a variety of risks and uncertainties, many of which are beyond our
control that could cause actual results to differ materially from those
anticipated or projected. These risks and uncertainties include, among
others:
|
·
|
We
may not complete projects, including growth or expansion projects, that we
have commenced or will commence, or we may complete projects on materially
different terms, cost or timing than anticipated and we may not be able to
achieve the intended economic or operational benefits of any such
projects, if completed.
|
|
·
|
The
successful completion, timing, cost, scope and future financial
performance of our expansion projects could differ materially from our
expectations due to availability of contractors or equipment, ground
conditions, weather, difficulties or delays in obtaining regulatory
approvals or denied applications, land owner opposition, the lack of
adequate materials, labor difficulties or shortages and numerous other
factors beyond our control.
|
|
·
|
Global
financial markets and economic conditions have been, and continue to be,
experiencing extraordinary disruption and volatility following adverse
changes in global capital markets. The cost of raising money in the debt
and equity capital markets and commercial credit markets has increased
substantially while the availability of funds from those markets has
diminished significantly.
|
|
·
|
A
portion of the transportation capacity on each of our expansion project
pipelines that we expect will ultimately be available is contingent upon
our receipt of authority to operate each of these pipelines at higher
operating pressures under a special permit issued by PHMSA. To the extent
that PHMSA does not grant us authority to operate any of our expansion
pipelines under a special permit or withdraws previously granted authority
to operate under a special permit, transportation capacity made available
to the market and transportation revenues received in the future could be
reduced.
|
|
·
|
Our
FERC gas tariffs only allow us to require limited credit support in the
event that our transportation customers are unable to pay for our
services. If any of our significant customers have credit or financial
problems which result in a delay or failure to pay for services provided
by us, or contracted for with us, or repay the gas they owe us, it
could adversely affect our business, financial condition and results
of operations.
|
|
·
|
The
gas transmission and storage operations of our subsidiaries are subject to
rate-making policies and actions by FERC or customers that could have an
adverse impact on the services we offer and the rates we charge and our
ability to recover the full cost of operating our pipelines, including
earning a reasonable return.
|
|
·
|
We
are subject to laws and regulations relating to the environment and
pipeline operations which may expose us to significant costs, liabilities
and loss of revenues. Any changes in such regulations or their application
generally or through enforcement actions could adversely affect our
business, financial condition and results of
operations.
|
|
·
|
Our
operations are subject to operational hazards and unforeseen interruptions
for which we may not be adequately
insured.
|
|
·
|
The
cost of insuring our assets may increase
dramatically.
|
|
·
|
Because
of the natural decline in gas production connected to our system, our
success depends on our ability to obtain access to new sources of natural
gas, which is dependent on factors beyond our control. Any decrease in
supplies of natural gas in our supply areas could adversely affect our
business, financial condition and results of
operations.
|
|
·
|
We
may not be able to maintain or replace expiring gas transportation and
storage contracts at favorable
rates.
|
|
·
|
Significant
changes in natural gas prices could affect supply and demand, reducing
system throughput and adversely affecting our
revenues.
|
Developments in any of these areas
could cause our results to differ materially from results that have been or may
be anticipated or projected. Forward-looking statements speak only as of the
date of this Report and we expressly disclaim any obligation or undertaking to
update these statements to reflect any change in our expectations or beliefs or
any change in events, conditions or circumstances on which any forward-looking
statement is based.
Interest
rate risk:
With the
exception of our revolving credit facility, for which the interest rate is reset
each quarter, our debt has been issued at fixed rates. For fixed rate debt,
changes in interest rates affect the fair value of the debt instruments but do
not directly affect earnings or cash flows. The following table presents market
risk associated with our fixed-rate long-term debt at December 31 (in millions,
except interest rates):
|
|
|
2008
|
|
|
2007
|
|
|
Carrying
value of debt
|
|
$ |
2,097.4 |
|
|
$ |
1,847.9 |
|
|
Fair
value of debt
|
|
$ |
1,863.3 |
|
|
$ |
1,834.2 |
|
|
100
basis point increase in interest rates and resulting debt
decrease
|
|
$ |
117.1 |
|
|
$ |
118.8 |
|
|
100
basis point decrease in interest rates and resulting debt
increase
|
|
$ |
126.1 |
|
|
$ |
129.3 |
|
|
Weighted-average
interest rate
|
|
|
5.89 |
% |
|
|
5.82 |
% |
At
December 31, 2008, we had $792.0 million outstanding under our revolving credit
agreement at a weighted- average interest rate of 3.43%, which rate is reset
each quarter. A 1% increase or decrease in interest rates would increase or
reduce our cash payments for interest on the credit facility by $8.0 million on
an annual basis. No amounts were borrowed under our revolving credit facility at
December 31, 2007.
At
December 31, 2008, $137.7 million of our undistributed cash, shown on the
balance sheets as Cash and cash equivalents, was invested in Treasury fund
accounts and $175.0 million was invested in U.S. Treasury notes under repurchase
agreements and shown as Short-term investments. At December 31, 2007, all of our
cash was invested in Treasury fund accounts. Due to the short-term nature of the
Treasury fund accounts, a hypothetical 10% increase or decrease in interest
rates would not have a material effect on the fair market value of our Cash and
cash equivalents. Since our investments under repurchase agreements are
liquidated the following day at an established price, a hypothetical 10%
increase or decrease in interest rates would not have a material effect on the
fair market value of our short-term investments.
Commodity
risk:
Certain
volumes of our gas stored underground are available for sale and subject to
commodity price risk. At December 31, 2008 and 2007, approximately $0.2 million
and $16.3 million of gas stored underground, which we own and carry as current
Gas stored underground, was available for sale and exposed to commodity price
risk. We utilize derivatives to hedge certain exposures to market price
fluctuations on the anticipated operational sales of gas. Our pipelines do not
take title to the natural gas which they transport and store in rendering
traditional firm and interruptible storage services, therefore they do not
assume the related natural gas commodity price risk associated with that
gas.
The
derivatives related to the sale of natural gas and cash for fuel reimbursement
generally qualify for cash flow hedge accounting under SFAS No. 133 and are
designated as such. The effective component of related gains and losses
resulting from changes in fair values of the derivatives contracts designated as
cash flow hedges are deferred as a component of Accumulated other comprehensive
(loss) income. The deferred gains and losses are recognized in earnings when the
anticipated transactions affect earnings. Generally, for gas sales and retained
fuel, any gains and losses on the related derivatives would be recognized in
Operating Revenues.
Credit
risk:
We are
exposed to credit risk relating to the risk of loss resulting from the
nonperformance by a customer of its contractual obligations. We have established
credit policies in the pipeline tariffs which are intended to minimize credit
risk in accordance with FERC policies and actively monitor this portion of our
business. Our credit exposure generally relates to receivables for services
provided, as well as volumes owed by customers for imbalances or gas lent by us
to them, generally under PAL and no-notice services. Natural gas price
volatility has increased dramatically in recent years, which has materially
increased credit risk related to gas loaned to customers. If any significant
customer of ours should have credit or financial problems resulting in a delay
or failure to repay the gas they owe to us, this could have a material adverse
effect on our financial condition, results of operations and cash
flows.
As of
December 31, 2008, the amount of gas loaned out by our subsidiaries or owed to
our subsidiaries due to gas imbalances was approximately 34.4 trillion British
thermal units (TBtu). Assuming an average market price during December 2008 of
$5.85 per million British thermal units (MMBtu), the market value of this gas at
December 31, 2008, would have been approximately $201.2 million. As of December
31, 2007, the amount of gas loaned out by our subsidiaries or owed to our
subsidiaries due to gas imbalances was approximately 15.2 TBtu. Assuming an
average market price during December 2007 of $7.13 per MMBtu, the market value
of this gas at December 31, 2007, would have been approximately $108.4
million.
More than
85% of our revenues are derived from gas marketers, LDCs and producers, the
majority of which have investment grade ratings. Although nearly all of our
customers pay for our services on a timely basis, we actively monitor the credit
exposure to our customers. We include in our ongoing assessments amounts due
pursuant to services we render plus the value of any gas we have lent to a
customer through no-notice or PAL services and the value of gas due to us under
a transportation imbalance. Our pipeline tariffs contain language that allow us
to require a customer that does not meet certain credit criteria to provide cash
collateral, post a letter of credit or provide a guarantee from a credit-worthy
entity in an amount equaling up to three months of capacity reservation charges.
For certain agreements associated with our expansion projects, we have included
contractual provisions that require additional credit support should the credit
ratings of those customers fall below investment grade.
After
completion of our expansion projects, producers will comprise a larger portion
of our revenues, both in aggregate as a group and separately. We expect
producers as a group to contribute a more significant portion of our future
revenues and one producer to represent over 10% of our total
revenues. Historically producers have had lower credit ratings than LDCs
and LDC-sponsored marketing companies, therefore the expected change in our
customer base could result in higher total credit risk. We will continue to
actively monitor the credit risks associated with our customer
base.
Market
risk:
Our primary exposure to market risk
occurs at the time our existing transportation and storage contracts expire and
are subject to termination or renegotiation. In addition, we have
market risk exposure if one of our transportation or storage customers defaults
on a service agreement and we are unable to resell the capacity at the same or
higher rate. As a result of competition in the industry, we actively
monitor future expiration dates associated with our contract portfolio. As of
December 31, 2008, approximately 17% of the firm contract load on our pipeline
systems, excluding agreements related to the expansion projects not yet in
service, was due to expire on or before December 31, 2009. As of December 31,
2007, the firm contract load due to expire within one year was 25%. Many of the
contracts comprising the 25% were renewed or remarketed at favorable terms and
for extended terms, increasing our weighted-average contract term.
REPORT
OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the
Board of Directors of Boardwalk GP, LLC
and the
Partners of Boardwalk Pipeline Partners, LP
We have
audited the accompanying consolidated balance sheets of Boardwalk Pipeline
Partners, LP and subsidiaries (the “Partnership”) as of December 31, 2008 and
2007, and the related consolidated statements of income, changes in partners’
capital, comprehensive income, and cash flows for each of the three years in the
period ended December 31, 2008. Our audits also included the financial statement
schedule included in the Index at Item 15. These financial statements and
financial statement schedule are the responsibility of the Partnership's
management. Our responsibility is to express an opinion on the financial
statements and financial statement schedule based on our audits.
We
conducted our audits in accordance with the standards of the Public Company
Accounting Oversight Board (United States). Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our
opinion, such consolidated financial statements present fairly, in all material
respects, the financial position of Boardwalk Pipeline Partners, LP and
subsidiaries as of December 31, 2008 and 2007, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 2008, in conformity with accounting principles generally accepted
in the United States of America. Also, in our opinion, such financial statement
schedule, when considered in relation to the basic consolidated financial
statements taken as a whole, presents fairly in all material respects the
information set forth therein.
We have
also audited, in accordance with the standards of the Public Company Accounting
Oversight Board (United States), the Partnership's internal control over
financial reporting as of December 31, 2008, based on the criteria established
in Internal Control—Integrated
Framework issued by the Committee of Sponsoring Organizations of the
Treadway Commission and our report dated February 24, 2009 expressed an
unqualified opinion on the Partnership's internal control over financial
reporting.
DELOITTE
& TOUCHE LLP
Houston,
Texas
February
24, 2009
BOARDWALK
PIPELINE PARTNERS, LP
CONSOLIDATED
BALANCE SHEETS
(Millions)
|
|
|
December
31,
|
|
|
ASSETS
|
|
2008
|
|
|
2007
|
|
|
Current
Assets:
|
|
|
|
|
|
|
|
Cash
and cash equivalents
|
|
$ |
137.7 |
|
|
$ |
317.3 |
|
|
Short-term
investments
|
|
|
175.0 |
|
|
|
- |
|
|
Receivables:
|
|
|
|
|
|
|
|
|
|
Trade,
net
|
|
|
67.3 |
|
|
|
60.7 |
|
|
Other
|
|
|
18.0 |
|
|
|
12.7 |
|
|
Gas
Receivables:
|
|
|
|
|
|
|
|
|
|
Transportation
and exchange
|
|
|
13.5 |
|
|
|
12.5 |
|
|
Storage
|
|
|
- |
|
|
|
1.3 |
|
|
Inventories
|
|
|
2.6 |
|
|
|
16.6 |
|
|
Costs
recoverable from customers
|
|
|
5.4 |
|
|
|
6.3 |
|
|
Gas
stored underground
|
|
|
0.2 |
|
|
|
16.3 |
|
|
Prepayments
|
|
|
17.3 |
|
|
|
7.9 |
|
|
Other
current assets
|
|
|
14.8 |
|
|
|
4.0 |
|
|
Total
current assets
|
|
|
451.8 |
|
|
|
455.6 |
|
|
|
|
|
|
|
|
|
|
|
|
Property,
Plant and Equipment:
|
|
|
|
|
|
|
|
|
|
Natural
gas transmission plant
|
|
|
3,871.0 |
|
|
|
2,392.5 |
|
|
Other
natural gas plant
|
|
|
215.2 |
|
|
|
224.0 |
|
|
|
|
|
4,086.2 |
|
|
|
2,616.5 |
|
|
Less—accumulated
depreciation and amortization
|
|
|
382.4 |
|
|
|
262.5 |
|
|
|
|
|
3,703.8 |
|
|
|
2,354.0 |
|
|
Construction
work in progress
|
|
|
2,196.4 |
|
|
|
951.4 |
|
|
Property,
plant and equipment, net
|
|
|
5,900.2 |
|
|
|
3,305.4 |
|
|
|
|
|
|
|
|
|
|
|
|
Other
Assets:
|
|
|
|
|
|
|
|
|
|
Goodwill
|
|
|
163.5 |
|
|
|
163.5 |
|
|
Gas
stored underground
|
|
|
124.8 |
|
|
|
137.1 |
|
|
Costs
recoverable from customers
|
|
|
15.4 |
|
|
|
15.9 |
|
|
Other
|
|
|
65.9 |
|
|
|
44.5 |
|
|
Total
other assets
|
|
|
369.6 |
|
|
|
361.0 |
|
|
|
|
|
|
|
|
|
|
|
|
Total
Assets
|
|
$ |
6,721.6 |
|
|
$ |
4,122.0 |
|
The
accompanying notes are an integral part of these consolidated financial
statements.
BOARDWALK
PIPELINE PARTNERS, LP
CONSOLIDATED
BALANCE SHEETS
(Millions)
|
|
|
December
31,
|
|
|
LIABILITIES
AND PARTNERS’ CAPITAL
|
|
2008
|
|
|
2007
|
|
|
Current
Liabilities:
|
|
|
|
|
|
|
|
Payables:
|
|
|
|
|
|
|
|
Trade
|
|
$ |
216.4 |
|
|
$ |
190.6 |
|
|
Affiliates
|
|
|
1.8 |
|
|
|
1.3 |
|
|
Other
|
|
|
7.4 |
|
|
|
5.1 |
|
|
Gas
Payables:
|
|
|
|
|
|
|
|
|
|
Transportation
and exchange
|
|
|
11.6 |
|
|
|
17.8 |
|
|
Accrued
taxes, other
|
|
|
35.2 |
|
|
|
20.2 |
|
|
Accrued
interest
|
|
|
40.1 |
|
|
|
30.8 |
|
|
Accrued
payroll and employee benefits
|
|
|
16.3 |
|
|
|
22.3 |
|
|
Construction
retainage
|
|
|
76.3 |
|
|
|
32.2 |
|
|
Deferred
income
|
|
|
1.8 |
|
|
|
7.2 |
|
|
Other
current liabilities
|
|
|
27.1 |
|
|
|
26.5 |
|
|
Total
current liabilities
|
|
|
434.0 |
|
|
|
354.0 |
|
|
|
|
|
|
|
|
|
|
|
|
Long
–Term Debt
|
|
|
2,889.4 |
|
|
|
1,847.9 |
|
|
|
|
|
|
|
|
|
|
|
|
Other
Liabilities and Deferred Credits:
|
|
|
|
|
|
|
|
|
|
Pension
liability
|
|
|
35.7 |
|
|
|
17.2 |
|
|
Asset
retirement obligation
|
|
|
18.0 |
|
|
|
16.1 |
|
|
Provision
for other asset retirement
|
|
|
45.6 |
|
|
|
42.4 |
|
|
Payable
to affiliate
|
|
|
20.6 |
|
|
|
- |
|
|
Other
|
|
|
33.3 |
|
|
|
41.4 |
|
|
Total
other liabilities and deferred credits
|
|
|
153.2 |
|
|
|
117.1 |
|
|
|
|
|
|
|
|
|
|
|
|
Commitments
and Contingencies
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Partners’
Capital:
|
|
|
|
|
|
|
|
|
|
Common
units – 154.9 and 90.7 common units issued and outstanding as of December
31, 2008 and 2007
|
|
|
2,504.8 |
|
|
|
1,473.9 |
|
|
Class
B units – 22.9 units issued and outstanding as of December 31,
2008
|
|
|
692.8 |
|
|
|
- |
|
|
Subordinated
units –33.1 units issued and outstanding
as of December 31, 2007
|
|
|
- |
|
|
|
291.7 |
|
|
General
partner
|
|
|
62.9 |
|
|
|
33.2 |
|
|
Accumulated
other comprehensive (loss) income, net of tax
|
|
|
(15.5 |
) |
|
|
4.2 |
|
|
Total
partners’ capital
|
|
|
3,245.0 |
|
|
|
1,803.0 |
|
|
Total
Liabilities and Partners’ Capital
|
|
$ |
6,721.6 |
|
|
$ |
4,122.0 |
|
The
accompanying notes are an integral part of these consolidated financial
statements.
BOARDWALK
PIPELINE PARTNERS, LP
CONSOLIDATED
STATEMENTS OF INCOME
(Millions,
except per unit amounts)
|
|
For
the Year Ended December 31,
|
|
|
|
2008
|
|
2007
|
|
2006
|
|
|
Operating
Revenues:
|
|
|
|
|
|
|
|
|
|
|
Gas
transportation
|
|
$ |
698.2 |
|
|
$ |
529.7 |
|
|
$ |
508.2 |
|
|
Parking
and lending
|
|
|
16.3 |
|
|
|
42.8 |
|
|
|
49.2 |
|
|
Gas
storage
|
|
|
51.5 |
|
|
|
39.4 |
|
|
|
32.4 |
|
|
Other
|
|
|
18.8 |
|
|
|
31.3 |
|
|
|
17.8 |
|
|
Total
operating revenues
|
|
|
784.8 |
|
|
|
643.2 |
|
|
|
607.6 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
Costs and Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fuel
and gas transportation
|
|
|
102.4 |
|
|
|
46.4 |
|
|
|
39.9 |
|
|
Operation
and maintenance
|
|
|
119.9 |
|
|
|
127.4 |
|
|
|
121.4 |
|
|
Administrative
and general
|
|
|
106.0 |
|
|
|
97.0 |
|
|
|
97.3 |
|
|
Depreciation
and amortization
|
|
|
124.8 |
|
|
|
81.8 |
|
|
|
75.8 |
|
|
Contract
settlement gain
|
|
|
(11.2 |
) |
|
|
- |
|
|
|
- |
|
|
Asset
impairment
|
|
|
3.0 |
|
|
|
19.2 |
|
|
|
- |
|
|
Net
gain on disposal of operating assets and related contracts
|
|
|
(49.2 |
) |
|
|
(23.8 |
) |
|
|
(4.8 |
) |
|
Taxes
other than income taxes
|
|
|
42.5 |
|
|
|
29.2 |
|
|
|
24.1 |
|
|
Total
operating costs and expenses
|
|
|
438.2 |
|
|
|
377.2 |
|
|
|
353.7 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
income
|
|
|
346.6 |
|
|
|
266.0 |
|
|
|
253.9 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Deductions (Income):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
expense
|
|
|
57.7 |
|
|
|
61.0 |
|
|
|
62.1 |
|
|
Interest
income
|
|
|
(2.9 |
) |
|
|
(21.5 |
) |
|
|
(4.2 |
) |
|
Miscellaneous
other income, net
|
|
|
(3.2 |
) |
|
|
(2.0 |
) |
|
|
(1.8 |
) |
|
Total
other deductions
|
|
|
51.6 |
|
|
|
37.5 |
|
|
|
56.1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
before income taxes
|
|
|
295.0 |
|
|
|
228.5 |
|
|
|
197.8 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
taxes
|
|
|
1.0 |
|
|
|
0.8 |
|
|
|
0.2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
income
|
|
$ |
294.0 |
|
|
$ |
227.7 |
|
|
$ |
197.6 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Calculation
of limited partners’ interest in Net income:
|
For
the Year Ended December 31,
|
|
|
|
2008
|
|
2007
|
|
2006
|
|
|
Net
income
|
|
$ |
294.0 |
|
|
$ |
227.7 |
|
|
$ |
197.6 |
|
|
Less
general partner’s interest in Net income
|
|
|
13.3 |
|
|
|
7.0 |
|
|
|
4.0 |
|
|
Limited
partners’ interest in Net income
|
|
$ |
280.7 |
|
|
$ |
220.7 |
|
|
$ |
193.6 |
|
|
Basic
and diluted net income per limited partner unit:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common
units
|
|
$ |
1.98 |
|
|
$ |
1.87 |
|
|
$ |
1.85 |
|
|
Class
B units
|
|
$ |
0.60 |
|
|
$ |
- |
|
|
$ |
- |
|
|
Subordinated
units (a)
|
|
$ |
1.98 |
|
|
$ |
1.87 |
|
|
$ |
1.85 |
|
|
Cash
distribution to common and subordinated unitholders (a)
|
|
$ |
1.87 |
|
|
$ |
1.74 |
|
|
$ |
1.32 |
|
|
Cash
distribution to class B units (b)
|
|
$ |
0.30 |
|
|
$ |
- |
|
|
$ |
- |
|
|
Weighted-average
number of limited partners units outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common
units (a)
|
|
|
104.2 |
|
|
|
82.5 |
|
|
|
69.0 |
|
|
Class
B units (b)
|
|
|
22.9 |
|
|
|
- |
|
|
|
- |
|
|
Subordinated
units (a)
|
|
|
28.7 |
|
|
|
33.1 |
|
|
|
33.1 |
|
|
(a)
All of the 33.1 million subordinated units converted to common units on a
one-for-one basis in November 2008.
(b)
The number of class B units shown is weighted from July 1, 2008, which is
the date they became eligible to participate in earnings.
The class B units do not participate in quarterly distributions above
$0.30 per unit.
|
|
The
accompanying notes are an integral part of these consolidated financial
statements.
BOARDWALK
PIPELINE PARTNERS, LP
CONSOLIDATED
STATEMENTS OF CASH FLOWS
(Millions)
| |
For
the Year Ended December 31,
|
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
OPERATING
ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
Net
income
|
|
$ |
294.0 |
|
|
$ |
227.7 |
|
|
$ |
197.6 |
|
|
Adjustments
to reconcile to cash provided by operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation
and amortization
|
|
|
124.8 |
|
|
|
81.8 |
|
|
|
75.8 |
|
|
Amortization
of deferred costs
|
|
|
9.0 |
|
|
|
8.3 |
|
|
|
8.7 |
|
|
Amortization
of acquired executory contracts
|
|
|
(0.2 |
) |
|
|
(1.1 |
) |
|
|
(4.0 |
) |
|
Asset
impairment
|
|
|
3.0 |
|
|
|
19.2 |
|
|
|
- |
|
|
Net
gain on disposal of operating assets and related contracts
|
|
|
(49.2 |
) |
|
|
(23.8 |
) |
|
|
(4.8 |
) |
|
Changes
in operating assets and liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Trade
and other receivables
|
|
|
(16.6 |
) |
|
|
(4.1 |
) |
|
|
(0.4 |
) |
|
Gas
receivables and storage assets
|
|
|
61.5 |
|
|
|
40.7 |
|
|
|
63.5 |
|
|
Costs
recoverable from customers
|
|
|
0.9 |
|
|
|
3.6 |
|
|
|
(4.0 |
) |
|
Inventories
|
|
|
(8.8 |
) |
|
|
(2.5 |
) |
|
|
1.8 |
|
|
Other
assets
|
|
|
(30.5 |
) |
|
|
(13.3 |
) |
|
|
(17.4 |
) |
|
Trade
and other payables
|
|
|
9.5 |
|
|
|
(15.9 |
) |
|
|
9.1 |
|
|
Gas
payables
|
|
|
(50.4 |
) |
|
|
(53.2 |
) |
|
|
(87.2 |
) |
|
Accrued
liabilities
|
|
|
7.0 |
|
|
|
12.9 |
|
|
|
(8.1 |
) |
|
Other
liabilities
|
|
|
(3.7 |
) |
|
|
1.4 |
|
|
|
24.9 |
|
|
Net
cash provided by operating activities
|
|
|
350.3 |
|
|
|
281.7 |
|
|
|
255.5 |
|
|
INVESTING
ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital
expenditures
|
|
|
(2,652.5 |
) |
|
|
(1,209.8 |
) |
|
|
(200.3 |
) |
|
Proceeds
from sale of operating assets, net
|
|
|
63.8 |
|
|
|
28.7 |
|
|
|
3.6 |
|
|
Proceeds
from insurance reimbursements and other recoveries
|
|
|
4.7 |
|
|
|
1.7 |
|
|
|
5.9 |
|
|
Advances
to affiliates, net
|
|
|
1.6 |
|
|
|
(0.9 |
) |
|
|
(0.7 |
) |
|
Purchases
of short-term investments
|
|
|
(175.0 |
) |
|
|
- |
|
|
|
- |
|
|
Net
cash used in investing activities
|
|
|
(2,757.4 |
) |
|
|
(1,180.3 |
) |
|
|
(191.5 |
) |
|
FINANCING
ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payments
of notes payable
|
|
|
- |
|
|
|
- |
|
|
|
(42.1 |
) |
|
Proceeds
from long-term debt, net of issuance costs
|
|
|
247.2 |
|
|
|
495.3 |
|
|
|
338.3 |
|
|
Proceeds
from borrowings on revolving credit agreement
|
|
|
1,484.0 |
|
|
|
- |
|
|
|
- |
|
|
Repayment
of borrowings on revolving credit agreement
|
|
|
(692.0 |
) |
|
|
- |
|
|
|
(90.0 |
) |
|
Distributions
|
|
|
(260.5 |
) |
|
|
(205.0 |
) |
|
|
(136.4 |
) |
|
Proceeds
from sale of common units, net of related
transaction
costs
|
|
|
733.6 |
|
|
|
515.9 |
|
|
|
195.2 |
|
|
Proceeds
from sale of class B units
|
|
|
686.0 |
|
|
|
- |
|
|
|
- |
|
|
Capital
contribution from general partner
|
|
|
29.2 |
|
|
|
10.7 |
|
|
|
4.2 |
|
|
Net
cash provided by financing activities
|
|
|
2,227.5 |
|
|
|
816.9 |
|
|
|
269.2 |
|
|
(Decrease)
increase in cash and cash equivalents
|
|
|
(179.6 |
) |
|
|
(81.7 |
) |
|
|
333.2 |
|
|
Cash
and cash equivalents at beginning of period
|
|
|
317.3 |
|
|
|
399.0 |
|
|
|
65.8 |
|
|
Cash
and cash equivalents at end of period
|
|
$ |
137.7 |
|
|
$ |
317.3 |
|
|
$ |
399.0 |
|
The
accompanying notes are an integral part of these consolidated financial
statements.
BOARDWALK
PIPELINE PARTNERS, LP
CONSOLIDATED
STATEMENTS OF CHANGES IN
PARTNERS’
CAPITAL
(Millions)
|
|
|
Common
Units
|
|
|
Class
B
Units
|
|
|
Subordinated Units
|
|
|
General
Partner
|
|
|
Accumulated Other
Comp (Loss) Income
|
|
|
Total
Partners’ Capital
|
|
|
Balance
January 1, 2006
|
|
$ |
705.6 |
|
|
$ |
- |
|
|
$ |
266.6 |
|
|
$ |
16.7 |
|
|
$ |
(0.2 |
) |
|
$ |
988.7 |
|
|
Add
(deduct):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
income
|
|
|
131.0 |
|
|
|
- |
|
|
|
62.6 |
|
|
|
4.0 |
|
|
|
- |
|
|
|
197.6 |
|
|
Distributions
paid
|
|
|
(90.0 |
) |
|
|
- |
|
|
|
(43.6 |
) |
|
|
(2.8 |
) |
|
|
- |
|
|
|
(136.4 |
) |
|
Sale
of common units, net of
related
transaction costs
(6.9
units)
|
|
|
195.2 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
195.2 |
|
|
Capital
contribution from general
partner
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
4.2 |
|
|
|
- |
|
|
|
4.2 |
|
|
Other
comprehensive income,
net
of tax
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
8.4 |
|
|
|
8.4 |
|
|
Adjustment
to initially apply
SFAS
No. 158, net of tax
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
14.8 |
|
|
|
14.8 |
|
|
Balance
December 31, 2006
|
|
$ |
941.8 |
|
|
$ |
- |
|
|
$ |
285.6 |
|
|
$ |
22.1 |
|
|
$ |
23.0 |
|
|
$ |
1,272.5 |
|
|
Add
(deduct):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
income
|
|
|
157.2 |
|
|
|
- |
|
|
|
63.5 |
|
|
|
7.0 |
|
|
|
- |
|
|
|
227.7 |
|
|
Distributions
paid
|
|
|
(141.0 |
) |
|
|
- |
|
|
|
(57.4 |
) |
|
|
(6.6 |
) |
|
|
- |
|
|
|
(205.0 |
) |
|
Sale
of common units, net of
related
transaction costs
(15.5 units)
|
|
|
515.9 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
515.9 |
|
|
Capital
contribution from
general
partner
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
10.7 |
|
|
|
- |
|
|
|
10.7 |
|
|
Other
comprehensive loss, net of tax
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(18.8 |
) |
|
|
(18.8 |
) |
|
Balance
December 31, 2007
|
|
$ |
1,473.9 |
|
|
$ |
- |
|
|
$ |
291.7 |
|
|
$ |
33.2 |
|
|
$ |
4.2 |
|
|
$ |
1,803.0 |
|
|
Add
(deduct):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
income
|
|
|
207.4 |
|
|
|
13.7 |
|
|
|
59.7 |
|
|
|
13.2 |
|
|
|
- |
|
|
|
294.0 |
|
|
Distributions
paid
|
|
|
(179.0 |
) |
|
|
(6.9 |
) |
|
|
(61.9 |
) |
|
|
(12.7 |
) |
|
|
- |
|
|
|
(260.5 |
) |
|
Sale
of common units, net of
related
transaction costs
(31.2
million common units)
|
|
|
713.0 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
713.0 |
|
|
Sale
of class B units
(22.9
million class B units)
|
|
|
- |
|
|
|
686.0 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
686.0 |
|
|
Conversion
of subordinated units
to
common units (33.1 million
units)
|
|
|
289.5 |
|
|
|
- |
|
|
|
(289.5 |
) |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
Capital
contribution from
general
partner
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
29.2 |
|
|
|
- |
|
|
|
29.2 |
|
|
Other
comprehensive loss, net of
tax
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(19.7 |
) |
|
|
(19.7 |
) |
|
Balance
December 31, 2008
|
|
$ |
2,504.8 |
|
|
$ |
692.8 |
|
|
$ |
- |
|
|
$ |
62.9 |
|
|
$ |
(15.5 |
) |
|
$ |
3,245.0 |
|
The
accompanying notes are an integral part of these consolidated financial
statements.
BOARDWALK
PIPELINE PARTNERS, LP
CONSOLIDATED
STATEMENTS OF COMPREHENSIVE INCOME
(Millions)
| |
|
For
the Year Ended December 31,
|
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
income
|
|
$ |
294.0 |
|
|
$ |
227.7 |
|
|
$ |
197.6 |
|
|
Other
comprehensive (loss) income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Loss)
gain on cash flow hedges
|
|
|
(16.7 |
) |
|
|
(9.8 |
) |
|
|
19.4 |
|
|
Reclassification
adjustment transferred to Net income from
cash flow hedges
|
|
|
24.9 |
|
|
|
(7.3 |
) |
|
|
(11.0 |
) |
|
Pension
and other postretirement benefits costs
|
|
|
(27.9 |
) |
|
|
(1.7 |
) |
|
|
- |
|
|
Total
comprehensive income
|
|
$ |
274.3 |
|
|
$ |
208.9 |
|
|
$ |
206.0 |
|
These
accompanying notes are an integral part of these consolidated financial
statements.
BOARDWALK
PIPELINE PARTNERS, LP
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
Note
1: Corporate Structure
Boardwalk Pipeline Partners, LP (the
Partnership) is a Delaware limited partnership formed to own and operate the
business conducted by our subsidiary, Boardwalk Pipelines, LP (Boardwalk
Pipelines), and its subsidiaries, Gulf South Pipeline Company, LP (Gulf South)
and Texas Gas Transmission, LLC (Texas Gas) (together, the operating
subsidiaries), and Gulf Crossing Pipeline Company, LLC (Gulf Crossing) a new
interstate pipeline, of which the pipeline portion of the assets were placed in
service in January and February 2009. As of December 31, 2008, Boardwalk
Pipelines Holding Corp. (BPHC) a wholly-owned subsidiary of Loews Corporation
(Loews) owns 107.5 million of the Partnership’s common units, all 22.9 million
of the Partnership’s class B units and, through Boardwalk GP, LP (Boardwalk GP),
an indirect wholly-owned subsidiary of BPHC, holds the 2% general partner
interest and all of the incentive distribution rights (IDRs). The common units,
class B units and general partner interest owned by BPHC represent approximately
74% of our equity interests, excluding the IDRs, further described in Note
12. The Partnership is traded under the symbol “BWP” on the New York Stock
Exchange (NYSE).
Basis
of Presentation
The accompanying consolidated financial
statements of the Partnership were prepared in accordance with accounting
principles generally accepted in the United States of America
(GAAP).
Note
2: Accounting Policies
Principles
of Consolidation
The consolidated financial statements
include the Partnership’s accounts and those of its wholly-owned subsidiaries,
Boardwalk Pipelines, Gulf Crossing, Gulf South and Texas Gas, after elimination
of intercompany transactions.
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, liabilities, revenues, expenses and
disclosure of contingent assets and liabilities. On an ongoing basis, the
Partnership evaluates its estimates, including but not limited to those related
to bad debts, materials and supplies obsolescence, investments, goodwill,
property and equipment and other long-lived assets, property taxes, pensions and
other postretirement and postemployment benefits, share-based and other
incentive compensation, contingent liabilities and revenues subject to refund.
The Partnership bases its estimates on historical experience and on various
other assumptions that are believed to be reasonable under the circumstances,
the results of which form the basis for making judgments about the carrying
values of assets and liabilities that are not readily apparent from other
sources. Actual results could differ from such estimates.
Segment
Information
The Partnership operates in one
reportable segment – the operation of interstate natural gas pipeline systems
including integrated storage facilities. This segment consists of interstate
natural gas pipeline systems originating in the Gulf Coast area and running
north and east through Texas, Louisiana, Arkansas, Mississippi, Alabama,
Florida, Tennessee, Kentucky, Indiana, Ohio, Illinois and Oklahoma.
Reclassifications
Certain prior year balances have been
reclassified to conform to the current year presentation. Prepayments and Other
current assets were separately identified on the Consolidated Balance Sheets due
to the materiality of those items at the end of 2008. Fuel and gas
transportation expenses were displayed separately from Operation and maintenance
expenses on the Consolidated Statements of Income to provide improved
transparency related to our Operating Costs and Expenses.
Regulatory
Accounting
The operating subsidiaries are
regulated by the Federal Energy Regulatory Commission (FERC). Statement of
Financial Accounting Standards (SFAS) No. 71, Accounting for the Effects of
Certain Types of Regulation, requires certain rate-regulated entities to
account for and report assets and liabilities consistent with the economic
effect of the manner in which independent third-party regulators establish
rates. SFAS No. 71 is applicable to operations of the Partnership’s Texas Gas
subsidiary which record certain costs and benefits as regulatory assets and
liabilities, respectively, in order to provide for recovery from or refund to
customers in future periods. The provisions of SFAS No. 71 are not applicable to
operations associated with the Texas Gas Fayetteville and Greenville Laterals
project due to rates charged under negotiated rate agreements and Phase III of
the Western Kentucky Storage Expansion project due to the regulatory treatment
associated with the rates charged under the project. The provisions of SFAS No.
71 are not applicable to the Partnership’s Gulf Crossing subsidiary due to
discounts under negotiated rate agreements, or Gulf South because competition in
its market area has resulted in discounts from the maximum allowable cost-based
rates being granted to customers and certain services provided by Gulf South are
priced using market-based rates, such that the application of the standard would
not be appropriate.
The Partnership monitors the regulatory
and competitive environment in which it operates to determine that any
regulatory assets continue to be probable of recovery. If the Partnership were
to determine that all or a portion of its regulatory assets no longer met the
criteria for recognition as regulatory assets under SFAS No. 71, that portion
which was not recoverable would be written off, net of any regulatory
liabilities. Note 6 contains more information regarding the Partnership’s
regulatory assets and liabilities.
Cash
and Cash Equivalents
Cash equivalents are highly liquid
investments with an original maturity of three months or less and are stated at
cost plus accrued interest, which approximates fair value. The Partnership had
no restricted cash at December 31, 2008 and 2007.
Cash
Management
The operating subsidiaries participate
in an intercompany cash management program to the extent they are permitted
under FERC regulations. Under the cash management program, depending on whether
a participating subsidiary has short-term cash surpluses or cash requirements,
Boardwalk Pipelines either provides cash to them or they provide cash to
Boardwalk Pipelines. The transactions are represented by demand notes and are
stated at historical carrying amounts. Interest income and expense is recognized
on an accrual basis when collection is reasonably assured. The interest rate on
intercompany demand notes is London Interbank Offered Rate (LIBOR) plus one
percent and is adjusted every three months.
Short-Term
Investments
Short-term investments consist of
United States (U.S.) Government securities, primarily Treasury notes, under
repurchase agreements. Generally, the Partnership has engaged in overnight
repurchase transactions where purchased securities are sold back to the
counterparty the following business day. The amount invested under
repurchase agreements is stated at fair value. Certain short-term investments,
for example those held overnight, result in significant cumulative inflows and
outflows of cash. In accordance with SFAS No. 95, Statement of Cash Flows, the
Partnership reflects these activities on a net basis in the Investing Activities
section of the Consolidated Statements of Cash Flows.
Trade
and Other Receivables
Trade and other receivables are stated
at their historical carrying amount, net of allowances for doubtful accounts or
write-offs. The Partnership establishes an allowance for doubtful accounts on a
case-by-case basis when it believes the required payment of specific amounts
owed is unlikely to occur. Uncollectible receivables are written off when a
settlement is reached for an amount that is less than the outstanding historical
balance or a receivable amount is deemed otherwise unrealizable.
Gas
Stored Underground and Gas Receivables and Payables
The operating subsidiaries have
underground gas in storage which is utilized for system management and
operational balancing, as well as for services including firm and interruptible
storage associated with certain no-notice and parking and lending (PAL)
services. Certain of these volumes are a result of providing storage services
which allow third parties to store their own natural gas in the pipelines’
underground facilities.
Gas stored underground includes the historical cost of natural gas volumes owned
by the operating subsidiaries, at times reduced by certain operational
encroachments upon that gas. Current gas stored underground represents net
retained fuel remaining after providing transportation and storage services and
excess working gas which is available for resale and is valued at the lower of
weighted-average cost or market.
The
Partnership previously recorded an asset for customer-owned gas held at the
Texas Gas storage facilities and an equal and offsetting liability for
customer-owned gas held at the Texas Gas storage facilities. At December 31,
2008, the Partnership changed its accounting policy for customer-owned storage
gas and no longer records customer-owned gas held at the Texas Gas storage
facilities on its Consolidated Balance Sheets. The Partnership desired to
conform the accounting of Texas Gas and Gulf South in this regard and believes
the new policy is preferable given the lack of title transfer in connection with
storage services offered to customers. The Consolidated Balance Sheet for
December 31, 2007 has been adjusted to reflect the change in policy resulting in
a corresponding reduction of $35.3 million to Gas stored underground (included
in non-current Other Assets) and Gas Payables. The Partnership held for storage
approximately 63.8 trillion British thermal units (TBtu) and 67.4 TBtu of gas
owned by third parties as of December 31, 2008 and 2007.
In the course of providing
transportation and storage services to customers, the pipelines may receive
different quantities of gas from shippers and operators than the quantities
delivered on behalf of those shippers and operators. This results in
transportation and exchange gas receivables and payables, commonly known as
imbalances, which are settled in cash or the receipt or delivery of gas in the
future. Settlement of imbalances requires agreement between the pipelines and
shippers or operators as to allocations of volumes to specific transportation
contracts and timing of delivery of gas based on operational conditions. The
receivables and payables are valued at market price for operations where SFAS
No. 71 is not applicable and are valued at the historical value of gas in
storage for operations where SFAS No. 71 is applicable, consistent with the
regulatory treatment and the settlement history.
Inventories
Inventories consisting of materials and
supplies are carried at average cost, less an allowance for obsolescence. The
Partnership has recorded $2.6 million of inventory expected to be used within
one year of the balance sheet date as Current Assets and $22.9 million was
recorded in Other Assets.
Property,
Plant and Equipment
Property, plant and equipment (PPE) is
recorded at its original cost of construction or fair value of assets purchased.
Construction costs and expenditures for major renewals and improvements which
extend the lives of the respective assets are capitalized. Construction work in
progress is included in the financial statements as a component of
PPE.
Depreciation
of PPE related to operations for which SFAS No. 71 is not applicable is provided
for using the straight-line method of depreciation over the estimated useful
lives of the assets, which range from 3 to 35 years. The ordinary sale or
retirement of PPE for these assets could result in a gain or loss. Depreciation
of PPE related to operations for which SFAS No. 71 is applicable is provided
primarily on the straight-line method at FERC-prescribed rates over estimated
useful lives of 5 to 62 years. Reflecting the application of composite
depreciation, gains and losses from the ordinary sale and retirement of PPE for
these assets are not recognized in earnings and generally do not impact PPE,
net. Note 4 contains more information regarding the Partnership’s
PPE.
Impairment
of Long-lived Assets
The Partnership evaluates long-lived
assets for impairment when, in management’s judgment, events or changes in
circumstances indicate that the carrying value of such assets may not be
recoverable. When such a determination has been made, management’s estimate of
undiscounted future cash flows attributable to remaining economic useful life of
the asset is compared to the carrying value of the asset to determine whether an
impairment has occurred. If an impairment of the carrying value has occurred,
the amount of impairment recognized in the consolidated financial statements is
determined by estimating the fair value of the assets and recording a loss for
the amount that the carrying value exceeds the estimated fair
value.
Repair
and Maintenance Costs
The operating subsidiaries account for
repair and maintenance costs in accordance with FERC regulations, which is
consistent with GAAP. FERC identifies installation, construction and replacement
costs that are to be capitalized. All other costs are expensed as
incurred.
Capitalized
Interest and Allowance for Funds Used During Construction (AFUDC)
Capitalized interest represents the
cost of borrowed funds used to finance construction activities. The
Partnership records capitalized interest in connection with construction
activities for operations where SFAS No. 71 is not applicable. AFUDC
represents the cost of funds, including equity funds, applicable to the
regulated natural gas transmission plant under construction as permitted by FERC
regulatory practices. The Partnership records AFUDC in connection with the
Partnership’s operations where SFAS No. 71 is applicable. Capitalized interest
and the allowance for borrowed funds used during construction are recognized as
a reduction to Interest expense and the allowance for equity funds used during
construction is included in Miscellaneous other income within the Consolidated
Statements of Income. The following table summarizes capitalized interest and
the allowance for borrowed funds and allowance for equity funds used during
construction (in millions):
| |
|
For
the Year Ended December 31,
|
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
Capitalized
interest and allowance for borrowed funds used during
construction
|
|
$ |
71.1 |
|
|
$ |
27.1 |
|
|
$ |
2.3 |
|
|
Allowance
for equity funds used during construction
|
|
|
0.2 |
|
|
|
3.0 |
|
|
|
1.2 |
|
Goodwill
SFAS No. 142, Goodwill and Other Intangible
Assets, requires an evaluation of goodwill for impairment at least
annually or more frequently if events and circumstances indicate that the asset
might be impaired. The impairment test for goodwill is performed annually at
December 31. No impairment of goodwill was recorded during 2008, 2007 or
2006.
Income
Taxes
The Partnership is not a taxable entity
for federal income tax purposes. As such, it does not directly pay
federal income tax. The Partnership’s taxable income or loss, which may vary
substantially from the net income or loss reported in the Consolidated
Statements of Income, is includable in the federal income tax returns of each
partner. The aggregate difference in the basis of the Partnership’s net assets
for financial and income tax purposes cannot be readily determined as the
Partnership does not have access to the information about each partner’s tax
attributes related to the Partnership. The subsidiaries of the Partnership
directly incur some income-based state taxes which are presented in
Income taxes on the Consolidated Statements of Income. Note 13 contains more
information regarding the Partnership’s income taxes.
Revenue
Recognition
The maximum rates that may be charged
by the operating subsidiaries for their services are established through FERC's
cost-based rate-making process. Rates charged by the operating subsidiaries may
be less than those allowed by FERC. Revenues from the transportation of gas are
recognized in the period the service is provided based on contractual terms and
the related volumes transported. Revenues from storage services are recognized
over the term of the contracts. In connection with certain PAL agreements, cash
is received at inception of the service period resulting in the recording of
deferred revenues which are recognized in revenues over the period the services
are provided. The Partnership had deferred revenues of $1.8 million and $7.2
million at December 31, 2008 and 2007. The deferred revenues were
related to PAL services to be provided mainly in the subsequent
year.
Retained fuel is recognized in revenues
at market prices in the month of retention for operations where SFAS No. 71 is
not applicable. The related fuel consumed in providing transportation services
is recorded in Fuel and gas transportation expenses at market prices in the
month consumed. Customers may elect to pay cash for fuel, instead of having fuel
retained in-kind. Transportation revenues recognized from retained fuel for the
years ended December 31, 2008, 2007 and 2006 were $134.9 million, $73.0 million
and $73.2 million.
Under FERC’s regulations, certain
revenues that the operating subsidiaries collect may be subject to possible
refunds to their customers. Accordingly, during a rate case, estimates of rate
refund reserves are recorded considering regulatory proceedings, advice of
counsel and estimated risk-adjusted total exposure, as well as other factors. At
December 31, 2008 and 2007, there were no liabilities for any open rate case
recorded on the Consolidated Balance Sheets.
Acquired
Executory Contracts
As a result of the acquisition of Gulf
South in December 2004, the Partnership recorded certain shipper contracts at
fair value. These deferred credits were amortized over the lives of the
shipper contracts ranging from three months to three years and were fully
amortized at December 31, 2008. Amortization for 2008, 2007 and 2006 was $0.2
million, $1.1 million and $4.0 million.
Asset
Retirement Obligations
SFAS No. 143, Accounting for Asset Retirement
Obligations, addresses accounting and reporting for existing legal
obligations associated with the future retirement of long-lived assets. SFAS No.
143 requires entities to record the fair value of a liability for an asset
retirement obligation in the period during which the liability is incurred. The
liability is initially recognized at fair value and is increased with the
passage of time as accretion expense is recorded, until the liability is
ultimately settled. Corresponding retirement costs are capitalized as part of
the carrying amount of the related long-lived asset and depreciated over the
useful life of that asset. Note 5 contains more information regarding the
Partnership’s asset retirement obligations.
Unit-Based
Compensation
The Partnership provides awards
of phantom units to certain employees under its Long-Term Incentive Plan and
Strategic Long-Term Incentive Plan. Pursuant to SFAS No. 123(R), Share-Based Payment, the
Partnership measures the cost of an award issued in exchange for employee
services based on the grant-date fair value of the award, which for an award
classified as a liability is remeasured each reporting period until settlement.
The related compensation expense is recognized over the period the employee is
required to provide service in exchange for the award, usually the vesting
period. Based on the terms of outstanding awards, to the extent forfeitures of
awards occur during a period due to employee terminations, cumulative
compensation expense previously recognized is reversed in the period of
forfeiture. Note 10 contains additional information regarding the Partnership’s
unit-based compensation.
Partner
Capital Accounts
For purposes of maintaining capital
accounts, items of income and loss of the Partnership are allocated among the
partners in each taxable year, or portion thereof in accordance with the
partnership agreement. Generally, net income for each period is allocated among
the partners based on their respective ownership interests after deducting any
priority allocations in the form of cash distributions paid to the general
partner as the holder of IDRs.
Derivative
Financial Instruments
Subsidiaries of the Partnership use
futures, swaps, and option contracts (collectively, derivatives) to hedge
exposure to various risks, including natural gas commodity and interest rate
risk. These hedge contracts are reported at fair value in accordance with SFAS
No. 133, Accounting for
Derivative Instruments and Hedging Activities, as amended. The effective
portion of the related unrealized gains and losses resulting from changes in
fair values of the derivatives contracts designated as cash flow hedges are
deferred as a component of accumulated other comprehensive income. The deferred
gains and losses are recognized in earnings when the hedged anticipated
transactions affect earnings. Changes in fair value of derivatives that are not
designated as cash flow hedges in accordance with SFAS No. 133 are recognized in
earnings in the periods that those changes in fair value occur. Note 8 contains
more information regarding the Partnership’s derivative financial
instruments.
In 2008,
the Partnership began applying the provisions of FASB Staff Position No. FIN
39-1, Amendment of FASB Interpretation No.
39, which permitted a company to change its accounting policy to offset
or not offset fair value amounts recognized for derivative instruments under
master netting arrangements. The Partnership changed its policy to not offset
fair value amounts recognized for its derivatives in its Consolidated Balance
Sheets and revised its 2007 presentation to conform to the new
policy.
In
accordance with the contracts governing the Partnership’s derivatives, the
counterparty or the Partnership may be required to post cash collateral. As of
December 31, 2008, the Partnership held as cash collateral $5.4 million related
to its outstanding derivatives, which was recorded in Other current liabilities.
No amounts were received or paid as cash collateral related to the Partnership’s
outstanding derivatives at December 31, 2007.
Note
3: Commitments and Contingencies
Contractual
Release
In December 2008, the Partnership
received notice of dissolution of the Alaskan Northwest Natural Gas
Transportation Company which was formed in the 1970s and in which Texas Gas was
an inactive investor. Along with the notice of dissolution, Texas Gas received a
full release from any obligations associated with its equity method investment.
As a result, the Partnership reversed the remainder of its liability for
estimated obligations associated with the investment and recognized $3.3 million
of income in Miscellaneous other deductions (income), net on the Consolidated
Statements of Income. The book value of the investment was zero at December 31,
2008.
Calpine
Energy Services (Calpine) Settlement
In 2007,
Gulf South and Calpine filed a stipulation and agreement in Calpine’s Chapter 11
Bankruptcy proceedings to settle, for approximately $16.5 million, Gulf South’s
claim against Calpine related to Calpine’s non-payment under a transportation
agreement. The claim, which was approved in 2008, was paid in the form of
Calpine stock. In 2007, the Partnership recognized $4.1 million of revenues
related to previously reserved amounts invoiced to Calpine for transportation
services previously rendered. In 2008, the Partnership sold the entire claim to
a third party and received a cash payment of approximately $15.3 million. The
transfer of the claim was deemed a sale and any recourse related to the sale
expired in 2008. As a result, in 2008 the Partnership recorded a net gain of
$11.2 million related to the realization of the unrecognized portion of the
claim which was reported as Contract settlement gain on the Consolidated
Statements of Income. The matter is considered settled and the Partnership does
not expect to receive additional amounts related to the claim.
Impact
of Hurricane Rita
In 2005,
Hurricane Rita caused physical damage to a portion of the Partnership’s assets
for which the related remediation work was completed in 2007. In 2008, the
Partnership received insurance proceeds of $5.7 million as final settlement,
$4.7 million of which was applied against a receivable for probable recoveries
that was established in 2007 and $1.0 million of which was recognized as a
reduction to Operation and maintenance expense.
Legal
Proceedings
Napoleonville
Salt Dome Matter
Following the December 2003 accidental
release of natural gas from storage in a salt dome cavern operated by Gulf South
at the Dow Hydrocarbon and Resources, Inc. (Dow Hydrocarbon), Grand Bayou
facility in Belle Rose, Louisiana, several suits were filed, including two that
were initially filed as class actions. One of the cases initially filed as a
class action was settled in 2008.
A lawsuit entitled Crystal Aucoin,
et al. v. Gulf South Pipeline Company, LP, et al., No. 28,157 was filed
on February 12, 2004, in the 23rd
Judicial District Court for the Parish of Assumption, State of Louisiana. The
suit was initially filed as a class action. The defendants at the trial were
Gulf South, Dow Chemical Company (Dow Chemical), Dow Hydrocarbon and one of Gulf
South’s insurers, Oil Insurance Limited (OIL). The plaintiffs voluntarily
dismissed their class action allegations on February 2, 2006. Since that time
the case has proceeded in the same court as a mass joinder of approximately
1,200 individual claims. The plaintiffs seek damages for alleged inconvenience
and emotional distress arising from being forced to drive on a detour around a
road closed due to the gas release. A trial was held in August 2008 on damages
for a sample group of 23 plaintiffs. In January 2009, the court awarded damages
to these plaintiffs of less than $0.1 million in the aggregate. Gulf South and
the other defendants are considering whether to appeal the ruling. Pursuant to
an agreement among defendants, Gulf South is responsible for one half of the
judgment, subject to final determination of Gulf South’s claim for
indemnification from Dow Chemical. Any judgment amounts paid would be
covered by insurance.
On September 29, 2005, OIL filed suit
against Dow Chemical and Dow Hydrocarbon, No. 29,217, in the 23rd
Judicial District Court for the Parish of Assumption, State of Louisiana, Oil Insurance
Limited v. Dow Chemical Company, et al. OIL seeks indemnification from
Dow Hydrocarbon for amounts of insurance paid to Gulf South. Dow Hydrocarbon has
filed a demand against OIL and a third-party claim against Gulf South. Dow
Hydrocarbon’s allegations against Gulf South include contractual violations and
liability due to negligence and strict liability. Dow Hydrocarbon seeks recovery
for property damage, damages arising from the loss of use of certain
wells/caverns and damages incurred responding to and remediating the natural gas
leak. The case is ongoing and no trial date has been set.
Litigation is subject to many
uncertainties, and it is possible these actions could be decided unfavorably.
The Partnership expects claims in each of these cases to be covered by insurance
that was in place at the time of the incident. For the years ended December
2008, 2007 and 2006 the Partnership received $4.7 million, $0.3 million and $0.8
million in insurance proceeds related to previously incurred litigation and
remediation costs, which were recorded as reductions to Operating Costs and
Expenses.
Other
Legal Matters
In October 2008, FERC issued an order
with respect to an interstate natural gas pipeline not affiliated with the
Partnership. Among other things, the order redefined what types of changes to a
contract within FERC’s jurisdiction will be viewed by FERC as a material
deviation, thereby requiring that the contract be filed with and approved by
FERC. As a result, in the fall 2008, the Partnership initiated a systematic
review of its transportation and storage contracts for both Gulf South and Texas
Gas in order to verify compliance with the order. Based upon the preliminary
findings of this review, the Partnership has self-reported to FERC that certain
of its transportation and storage contracts may not be in compliance with the
requirements of the order. The Partnership is continuing its review and is
scheduled to meet with FERC staff in the first quarter 2009 to review its
findings and discuss additional steps to be taken, if any. Although
this matter is in a preliminary stage, the Partnership does not expect the
outcome to have a material impact on its financial condition, results of
operations or cash flows.
In connection with the acquisition of
Texas Gas in 2003, The Williams Companies, Inc. (Williams) agreed to indemnify
Boardwalk Pipelines for any liabilities or obligations in connection with
certain litigation or potential litigation. Williams continues to defend the
Partnership and Texas Gas and has retained responsibility for these claims.
Therefore these claims are not expected to have a material effect upon the
Partnership’s future financial condition, results of operations or cash
flows.
The
Partnership's subsidiaries are parties to various other legal actions arising in
the normal course of business. Management believes the disposition of all known
outstanding legal actions will not have a material adverse impact on the
Partnership's financial condition, results of operations or cash
flows.
Regulatory
and Rate Matters
Pipeline
Expansion Projects
The
Partnership is engaged in several pipeline expansion projects as
follows:
|
|
|
Pipeline
Mileage
(unaudited)
|
|
Pipeline
Diameter
(unaudited)
|
|
Peak-day
Transmission
Capacity
(unaudited)
|
|
In
Service Date
(unaudited)
|
|
Southeast
Expansion
|
|
111
miles
|
|
42-inch
|
|
1.9
Bcf (a)
|
|
First
quarter 2009
|
|
Gulf
Crossing Project
|
|
357
miles
|
|
42-inch
|
|
1.7
Bcf (a),(b)
|
|
First
quarter 2009
|
|
Fayetteville
Lateral
|
|
165
miles
|
|
36-inch
|
|
1.3
Bcf (a),(b)
|
|
First
quarter 2009
|
|
Greenville
Lateral
|
|
95
miles
|
|
36-inch
|
|
1.0
Bcf (b)
|
|
First
quarter 2009
|
|
(a)
|
The
indicated peak-day transmission capacity (shown in billion cubic feet
(Bcf)) is subject to the receipt of authority from the Pipelines and
Hazardous Materials Safety Administration (PHMSA) to operate the pipelines
at higher operating pressures.
|
|
(b)
|
The
indicated peak-day transmission capacity is subject to the construction of
additional compression facilities which, subject to FERC approval, are
expected to be placed in service in
2010.
|
Southeast
Expansion. In February 2009, the Partnership placed in service
the remaining compression related to this project and construction on this
project is complete. Customers have contracted at fixed rates for substantially
all of the operational capacity (with a weighted-average term of approximately
9.3 years, including a capacity lease agreement with Gulf Crossing). Through
December 31, 2008, the Partnership spent $707.3 million related to this
project.
Gulf Crossing Project. In
January and February 2009, the Partnership completed construction and placed in
service the pipeline portion of the assets associated with the Gulf Crossing
project, which consists of approximately 357 miles of 42-inch pipeline that
begins near Sherman, Texas, and proceeds to the Perryville, Louisiana area.
Customers have contracted at fixed rates for substantially all of the
operational capacity, with a weighted-average term of approximately 9.5 years.
The Partnership expects the initial compression to be placed in service during
the first quarter 2009. The pipeline will initially be operating at a reduced
capacity until authority to operate under a special permit from PHMSA is
received that will allow the pipeline to operate at higher operating pressures.
The remaining compression is expected to be fully in service in 2010. Through
December 31, 2008, the Partnership spent $1.4 billion related to this
project.
Fayetteville and Greenville
Laterals. The Partnership is constructing two laterals on its Texas Gas
pipeline system to transport gas from the Fayetteville Shale area in Arkansas to
markets directly and indirectly served by the Partnership’s existing interstate
pipelines. The Fayetteville Lateral will originate in Conway County, Arkansas,
and proceed southeast through the Bald Knob, Arkansas area, to an interconnect
with the Texas Gas mainline in Coahoma County, Mississippi. The Greenville
Lateral will originate at the Texas Gas mainline near Greenville, Mississippi,
and proceed east to the Kosciusko, Mississippi area. The Greenville Lateral will
provide customers access to additional markets, located primarily in the
Midwest, Northeast and Southeast. In December 2008, the Partnership placed in
service the header of the Fayetteville Lateral. In January 2009, the Partnership
placed in service a portion of the Greenville Lateral which originates at the
Texas Gas mainline and continues to an interconnect with the Tennessee 800 line
in Holmes County, Mississippi. The Fayetteville header includes a section of
18-inch pipeline under the Little Red River in Arkansas which will be replaced
with 36-inch pipeline once a new horizontal directional drill is completed under
the river. The Partnership expects the 36-inch pipeline installation to be
completed in the second quarter 2009.
During
2008, the Partnership executed contracts for additional capacity that will
require it to add compression to increase the peak-day transmission capacity of
the laterals. Customers have contracted at fixed rates for substantially all of
the operational capacity of these laterals, with a weighted-average term of
approximately 9.9 years. The Partnership made additional filings with FERC
regarding the new compression required to increase the peak-day transmission
capacity, and expects the compression to be in service during 2010. Through
December 31, 2008, the Partnership spent $684.2 million related to the
Fayetteville and Greenville Laterals.
Storage
Expansion Project
The
Partnership is also engaged in the following storage expansion
project:
Western Kentucky Storage Expansion
Phase III. The Partnership is developing new working gas
capacity at its Midland storage facility for which FERC has granted the
Partnership market-based rate authority. Through December 31, 2008, the
Partnership spent $48.0 million related to this project.
Environmental
and Safety Matters
The
operating subsidiaries are subject to federal, state, and local environmental
laws and regulations in connection with the operation and remediation of various
operating sites. The Partnership accrues for environmental expenses resulting
from existing conditions that relate to past operations when the costs are
probable and can be reasonably estimated. In addition to federal and state
mandated remediation requirements, the Partnership often enters into voluntary
remediation programs with regulatory agencies. Depending on the results of
on-going assessments and review of any data collected, the Partnership’s
liabilities for environmental remediation are updated based on new facts and
circumstances. The actual costs incurred will depend on the actual amount and
extent of contamination discovered, the final cleanup standards mandated by the
Environmental Protection Agency (EPA) or other governmental authorities and
other factors.
As of December 31, 2008 and 2007,
the Partnership had an accrued liability of approximately $16.8 million and
$17.0 million related to assessment and/or remediation costs associated with the
historical use of polychlorinated biphenyls, petroleum hydrocarbons and mercury,
enhancement of groundwater protection measures and other costs. The expenditures
are expected to occur over the next ten years. The accrual represents
management’s estimate of the undiscounted future obligations based on
evaluations and discussions with counsel and operating personnel and the current
facts and circumstances related to these matters. As of December 31, 2008 and
2007, approximately $3.5 million and $2.7 million were recorded in Other current
liabilities and approximately $13.3 million and $14.3 million were recorded in
Other Liabilities and Deferred Credits. The Partnership considers environmental
assessment, remediation costs and costs associated with compliance with
environmental standards to be recoverable through base rates, as they are
prudent costs incurred in the ordinary course of business and, therefore, no
regulatory asset has been recorded to defer these costs. For further discussion
of the Partnership's environmental exposure included in the calculation of its
asset retirement obligations, see Note 5 of these Notes to Consolidated
Financial Statements.
Comprehensive
Environmental Response, Compensation, and Liability Act (CERCLA)
In
2006, Texas Gas received notice from the EPA that Texas Gas is a potentially
responsible party under the CERCLA of 1980 with respect to the LWD, Inc.
Superfund Site in Calvert City, Kentucky. The Partnership is unable to estimate
with any certainty at this time any potential liability it may incur related to
this notice but does not expect the outcome to have a material effect on its
financial condition, results of operations or cash flows.
In 2005, Texas Gas received notice from
the EPA that it has been identified as a de minimis settlement waste
contributor at the Mercury Refining Superfund Site located at the Towns of
Colonie and Guilderland, Albany County, New York, and was offered and accepted
participation in a settlement. In January 2009, Texas Gas and Gulf South
received a revised notice from the EPA identifying both parties as de minimis waste contributors
at the site. Based upon the EPA’s notice, the proposed total settlement amount
for both subsidiaries is approximately $0.1 million. The proposed settlement is
subject to a 30 day public notice period before it can be
finalized.
Clean
Air Act
The Partnership’s pipelines are subject
to the Clean Air Act (CAA) and the CAA Amendments of 1990 (Amendments) which
added significant provisions to the CAA. The Amendments require the EPA to
promulgate new regulations pertaining to mobile sources, air toxins, areas of
ozone non-attainment and acid rain. The operating subsidiaries presently operate
two facilities in areas affected by non-attainment requirements for the current
ozone standard (eight-hour standard). If the EPA designates additional new
non-attainment areas or promulgates new air regulations where the Partnership
operates, the cost of additions to PPE is expected to increase. The Partnership
has assessed the impact of the CAA on its facilities and does not believe
compliance with these regulations will have a material impact on the results of
continuing operations or cash flows. If the EPA designates additional new
non-attainment areas or promulgates new air regulations applicable to the
Partnership’s operating subsidiaries, the cost of additions to PPE is expected
to increase.
In March
2008, the EPA adopted regulations lowering the 8-hour ozone standard relevant to
non-attainment areas. Under the regulation, new non-attainment areas will be
identified which may require additional emission controls for compliance at as
many as 12 facilities operated by the operating subsidiaries. The mandated
compliance dates for this standard are between 2013 and 2016. The Partnership is
currently evaluating its potentially affected facilities to determine the cost
necessary to become compliant with this standard.
Lease
Commitments
The Partnership has various operating
lease commitments extending through the year 2018 generally covering office
space and equipment rentals. Total lease expense for the years ended December
31, 2008, 2007 and 2006 were approximately $4.4 million, $5.0 million and $2.4
million. The following table summarizes minimum future commitments related to
these items at December 31, 2008 (in millions):
|
2009
|
|
$ |
3.3 |
|
|
2010
|
|
|
3.2 |
|
|
2011
|
|
|
3.0 |
|
|
2012
|
|
|
3.0 |
|
|
2013
|
|
|
3.0 |
|
|
Thereafter
|
|
|
10.2 |
|
|
Total
|
|
$ |
25.7 |
|
Commitments
for Construction
The Partnership incurred $2.7 billion
and $1.2 billion of capital expenditures in 2008 and 2007. The Partnership’s
future capital commitments are comprised of binding commitments under purchase
orders for materials ordered but not received and firm commitments under binding
construction service agreements existing at December 31, 2008. The commitments
as of December 31, 2008 were approximately (in millions):
|
Less
than 1 year
|
|
$ |
195.8 |
|
|
1-3
years
|
|
|
2.9 |
|
|
4-5
years
|
|
|
- |
|
|
More
than 5 years
|
|
|
- |
|
|
Total
|
|
$ |
198.7 |
|
Pipeline
Capacity Agreements
The
Partnership’s subsidiaries have entered into pipeline capacity agreements with
third-party pipelines that allow the subsidiaries to transport gas to off-system
markets on behalf of customers. The Partnership incurred expenses of $6.4
million, $2.3 million and $2.3 million related to pipeline capacity agreements
for the years ended December 31, 2008, 2007 and 2006. The future commitments
related to pipeline capacity agreements as of December 31, 2008 were (in
millions):
|
Less
than 1 year
|
|
$ |
12.6 |
|
|
1-3
years
|
|
|
22.5 |
|
|
4-5
years
|
|
|
20.5 |
|
|
More
than 5 years
|
|
|
47.2 |
|
|
Total
|
|
$ |
102.8 |
|
Note
4: Property, Plant and Equipment
In 2008,
the Partnership placed in service the remaining pipeline assets and related
compression associated with the East Texas to Mississippi Expansion project from
Delhi, Louisiana to Harrisville, Mississippi. The Partnership also placed in
service the pipeline assets and two compressor stations related to the Southeast
Expansion project, the pipeline assets associated with the first 66 miles of the
Fayetteville Lateral and Phase III of the Western Kentucky Storage Expansion.
Approximately $1.5 billion was transferred from Construction work in progress to
Property, plant and equipment during 2008 as a result of these assets being
placed in service. The assets will generally be depreciated over a term of 35
years.
The following table presents the
Partnership’s PPE as of December 31, 2008 and 2007 (in millions):
|
Category
|
|
2008
Class Amount
|
|
|
Weighted-Average
Useful Lives (Years)
|
|
|
2007
Class Amount
|
|
|
Weighted-Average
Useful Lives (Years)
|
|
|
Depreciable
plant:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Transmission
|
|
$ |
3,537.2 |
|
|
|
39 |
|
|
$ |
2,125.9 |
|
|
|
43 |
|
|
Storage
|
|
|
248.9 |
|
|
|
47 |
|
|
|
198.1 |
|
|
|
49 |
|
|
Gathering
|
|
|
91.4 |
|
|
|
19 |
|
|
|
92.8 |
|
|
|
19 |
|
|
General
|
|
|
88.3 |
|
|
|
15 |
|
|
|
79.6 |
|
|
|
15 |
|
|
Rights
of way and other
|
|
|
36.9 |
|
|
|
24 |
|
|
|
24.9 |
|
|
|
9 |
|
|
Total
utility depreciable plant
|
|
|
4,002.7 |
|
|
|
39 |
|
|
|
2,521.3 |
|
|
|
41 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-depreciable:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Construction
work in progress
|
|
|
2,196.4 |
|
|
|
|
|
|
|
951.4 |
|
|
|
|
|
|
Storage
|
|
|
61.6 |
|
|
|
|
|
|
|
71.2 |
|
|
|
|
|
|
Land
|
|
|
13.3 |
|
|
|
|
|
|
|
9.7 |
|
|
|
|
|
|
Other
|
|
|
8.6 |
|
|
|
|
|
|
|
14.3 |
|
|
|
|
|
|
Total
other
|
|
|
2,279.9 |
|
|
|
|
|
|
|
1,046.6 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
PPE
|
|
|
6,282.6 |
|
|
|
|
|
|
|
3,567.9 |
|
|
|
|
|
|
Less: accumulated depreciation
|
|
|
382.4 |
|
|
|
|
|
|
|
262.5 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
PPE, net
|
|
$ |
5,900.2 |
|
|
|
|
|
|
$ |
3,305.4 |
|
|
|
|
|
The non-transmission assets have
weighted-average useful lives of 35 years and 33 years as of December 31, 2008
and 2007 and depreciable asset values of $465.5 million and $395.4 million as of
December 31, 2008 and 2007. The non-depreciable assets and construction work in
progress were not included in the calculation of the weighted-average useful
lives.
The
Partnership holds undivided interests in certain assets, including the Bistineau
storage facility of which the Partnership owns 92%, the Mobile Bay Pipeline of
which the Partnership owns 64% and offshore and other assets, comprised of
pipeline and gathering assets in which the Partnership holds various ownership
interests. The proportionate share of investment associated with these interests
has been recorded as PPE on the Consolidated Balance Sheets. The Partnership
records its portion of direct operating expenses associated with the assets in
Operation and maintenance expense. The following table presents the gross PPE
investment and related accumulated depreciation for the Partnership’s undivided
interests as of December 31, 2008 and 2007 (in millions):
|
|
|
2008
|
|
|
2007
|
|
|
|
|
Gross
PPE Investment
|
|
|
Accumulated
Depreciation
|
|
|
Gross
PPE Investment
|
|
|
Accumulated
Depreciation
|
|
|
Bistineau
storage
|
|
$ |
57.1 |
|
|
$ |
6.9 |
|
|
$ |
57.0 |
|
|
$ |
5.2 |
|
|
Mobile
Bay Pipeline
|
|
|
11.2 |
|
|
|
1.4 |
|
|
|
11.2 |
|
|
|
1.0 |
|
|
Offshore
and other assets
|
|
|
19.0 |
|
|
|
11.5 |
|
|
|
19.3 |
|
|
|
11.2 |
|
|
Total
|
|
$ |
87.3 |
|
|
$ |
19.8 |
|
|
$ |
87.5 |
|
|
$ |
17.4 |
|
Asset
Impairments
Non-Contiguous Offshore
Laterals. In 2008, the Partnership completed a review of its
non-contiguous offshore laterals and provided notice to the other interest
holders of its intent to discontinue use of its portion of the available
capacity for some of the assets. As a result, the Partnership reviewed the
assets for recoverability in accordance with SFAS No. 144, Accounting for the Impairment or
Disposal of Long-Lived Assets, and recorded an impairment charge of
approximately $3.0 million representing the net book value of the
assets.
South
Timbalier. In 2007, the Partnership entered into an agreement
to sell offshore pipeline assets in the South Timbalier Bay area, offshore
Louisiana, and recognized an impairment charge of approximately $4.5 million
representing the net book value of the assets. In accordance with the agreement,
the Partnership paid the buyer approximately $4.8 million primarily to settle a
liability to re-cover the pipeline and other maintenance issues which was
recorded to Operation and maintenance expense. The Partnership completed the
sale of these assets in 2008.
Magnolia Storage Facility.
The Partnership was developing a salt dome storage cavern near Napoleonville,
Louisiana. Integrity tests, which were completed in 2007, indicated that due to
geological and other anomalies that could not be corrected, the Partnership
would be unable to place the cavern in service as expected. As a
result, the Partnership elected to abandon that cavern. In accordance with the
requirements of SFAS No. 144, Accounting for the Impairment or
Disposal of Long-Lived Assets, the carrying value of the cavern and
related facilities was tested for recoverability. In 2007, the Partnership
recognized an impairment charge to earnings of approximately $14.7 million,
representing the carrying value of the cavern, the fair value of which was
determined to be zero based on discounted expected future cash flows. The charge
was presented as Asset impairment on the Consolidated Statements of Income in
2007. The Partnership is exploring the possibility of securing a new site in
Napoleonville, Louisiana, on which a new cavern could be developed and expects
to use the other assets associated with the project, which include pipeline,
compressors, and other equipment and facilities, in conjunction with the
replacement storage cavern to be developed. If it is determined in the future
that the assets cannot be used in conjunction with a new cavern or a new cavern
cannot be secured in the same area, the Partnership may be required to record an
additional impairment charge at the time that determination is made. Additional
costs to abandon the impaired cavern may be incurred due to regulatory or
contractual obligations; however, the amounts are inestimable at this
time.
Note
5: Asset Retirement Obligations (ARO)
Pursuant to federal regulations, the
Partnership has a legal obligation to cut and purge any pipeline that will
remain in place after abandonment and to remove offshore platforms after the
related gas flows have ceased. The Partnership has identified and recorded legal
obligations associated with the abandonment of offshore pipeline laterals and
certain onshore facilities as well as abatement of asbestos consisting of
removal, transportation and disposal when removed from certain compressor
stations and meter station buildings. Legal obligations exist for the pipeline
and certain other Partnership assets; however, the fair value of the obligations
cannot be determined because the lives of the assets are indefinite and
therefore cash flows associated with retirement of the assets cannot be
estimated with the degree of accuracy necessary to establish a liability for the
obligations.
The
following table summarizes the aggregate carrying amount of the Partnership’s
ARO (in millions):
|
|
|
2008
|
|
|
2007
|
|
|
Balance
at beginning of year
|
|
$ |
16.1 |
|
|
$ |
14.3 |
|
|
Liabilities
recorded
|
|
|
1.6 |
|
|
|
1.5 |
|
|
Liabilities
settled
|
|
|
(0.5 |
) |
|
|
(0.4 |
) |
|
Accretion
expense
|
|
|
0.8 |
|
|
|
0.7 |
|
|
Balance
at end of year
|
|
$ |
18.0 |
|
|
$ |
16.1 |
|
The Financial Accounting Standards
Board (FASB) Interpretation No. 47, Accounting for Conditional
AROs, clarifies when an entity is required to recognize a liability for
the fair value of a conditional ARO. In light of this interpretation, the
Partnership believes that an ARO exists for the Texas Gas corporate office
building constructed in Owensboro, Kentucky, in 1962. Under the legal
requirements enacted by the EPA during 1973, Texas Gas became legally obligated
to dismantle and remove the asbestos from its corporate office at the end of its
useful life, estimated to be within a range between 2112 through 2162. The
Partnership believes that the spray-applied asbestos can be maintained in place
indefinitely, if undisturbed by following written maintenance procedures. The
Partnership believes that the fair value of any liability relating to future
remediation is not material to its financial position, results of operations or
cash flows and that any costs incurred for this remediation would be recoverable
in its rates.
For the Partnership’s operations where
SFAS No. 71 is applicable, depreciation rates for PPE are comprised of two
components: One component is based on economic service life (capital recovery)
and the other is based on estimated costs of removal (negative salvage) which is
collected in rates and does not represent an existing legal obligation. The
Partnership has reflected $45.6 million and $42.4 million as of December 31,
2008 and 2007, in the accompanying Consolidated Balance Sheets as Provision for
other asset retirement related to the estimated cost of removal collected in
rates.
Note
6: Regulatory Assets and Liabilities
The amounts recorded as regulatory
assets and liabilities in the Consolidated Balance Sheets as of December 31,
2008 and 2007, are summarized in the table below. The table also includes
amounts related to unamortized debt expense and unamortized discount on
long-term debt. While these amounts are not regulatory assets and liabilities as
defined by SFAS No. 71, they are a critical component of the embedded cost of
debt financing utilized in the Texas Gas rate proceedings. The tax effect of the
equity component of AFUDC represents amounts recoverable from rate payers for
the tax effects created prior to the 2005 change in the tax status of Boardwalk
Pipelines and its election to be taxed as a partnership. Certain amounts in the
table are reflected as a negative, or a reduction, to be consistent with the
manner in which Texas Gas records these items in its regulatory books of
account. The period of recovery for the regulatory assets included in rates
varies from one to nineteen years. The remaining period of recovery for
regulatory assets not yet included in rates would be determined in future rate
proceedings. None of the regulatory assets shown below were earning a return as
of December 31, 2008 and 2007 (in millions):
|
|
|
2008
|
|
|
2007
|
|
|
Regulatory
Assets:
|
|
|
|
|
|
|
|
Pension
|
|
$ |
9.5 |
|
|
$ |
9.5 |
|
|
Tax
effect of AFUDC equity
|
|
|
5.9 |
|
|
|
6.4 |
|
|
Unamortized
debt expense and premium on reacquired debt
|
|
|
10.0 |
|
|
|
10.7 |
|
|
Postretirement
benefits other than pension
|
|
|
5.4 |
|
|
|
5.4 |
|
|
Fuel
tracker
|
|
|
- |
|
|
|
0.9 |
|
|
Total
regulatory assets
|
|
$ |
30.8 |
|
|
$ |
32.9 |
|
|
Regulatory
Liabilities:
|
|
|
|
|
|
|
|
Cashout
and fuel tracker
|
|
$ |
2.3 |
|
|
$ |
0.2 |
|
|
Provision for
asset retirement
|
|
|
45.6 |
|
|
|
42.4 |
|
|
Unamortized
discount on long-term debt
|
|
|
(3.5 |
) |
|
|
(1.7 |
) |
|
Postretirement
benefits other than pension
|
|
|
4.7 |
|
|
|
12.5 |
|
|
Total
regulatory liabilities
|
|
$ |
49.1 |
|
|
$ |
53.4 |
|
Note
7: Financing
Issuances
of Common Units
Since its IPO in November 2005, the
Partnership has completed four follow-on public equity offerings and one private
placement of common units. The proceeds of the offerings have been used to
finance the Partnership’s expansion activities discussed in Note 3 or to reduce
borrowings under the Partnership’s revolving credit facility. In addition to
funds received from the offering of common units, the general partner
concurrently contributed amounts to maintain its 2% interest in the Partnership.
The following table shows selected information related to these equity issuances
(in millions, except the issuance price):
|
Month
of Offering
|
|
Number
of Common Units
|
|
|
Issuance
Price
|
|
|
Less
Underwriting Discounts and Expenses
|
|
|
Net
Proceeds
(including
General Partner Contribution)
|
|
|
Common
Units Outstanding
After
Offering
|
|
|
Common
Units Held by the Public
After
Offering
|
|
|
October
2008 (a)
|
|
|
21.2 |
|
|
$ |
23.13 |
|
|
|
- |
|
|
$ |
500.0 |
|
|
|
121.8 |
(b) |
|
|
47.4 |
|
|
June
2008
|
|
|
10.0 |
|
|
|
25.30 |
|
|
$ |
9.4 |
|
|
|
248.8 |
|
|
|
100.7 |
|
|
|
47.4 |
|
|
November
2007
|
|
|
7.5 |
|
|
|
30.90 |
|
|
|
3.7 |
|
|
|
232.8 |
|
|
|
90.7 |
|
|
|
37.4 |
|
|
March
2007
|
|
|
8.0 |
|
|
|
36.50 |
|
|
|
4.2 |
|
|
|
293.8 |
|
|
|
83.2 |
|
|
|
29.9 |
|
|
November
2006
|
|
|
6.9 |
|
|
|
29.65 |
|
|
|
9.4 |
|
|
|
199.4 |
|
|
|
75.2 |
|
|
|
21.9 |
|
|
(a)
|
Sold
to BPHC in a private placement.
|
|
(b)
|
Excludes
the conversion of all of the 33.1 million subordinated units into common
units in November 2008.
|
Class
B Units
In June
2008, the Partnership issued and sold, pursuant to the Class B Unit Purchase
Agreement (the Purchase Agreement), approximately 22.9 million class B units
representing limited partner interests (class B units) to BPHC for $30.00 per
class B unit, or an aggregate purchase price of $686.0 million. The
Partnership’s general partner also contributed $14.0 million to the Partnership
to maintain its 2% interest. The Partnership used the proceeds of $700.0 million
to repay amounts borrowed under its revolving credit facility and to fund a
portion of the costs of its ongoing expansion projects.
The class
B units share in quarterly distributions of available cash from operating
surplus on a pari passu basis with the Partnership’s common units, until each
common unit and class B unit has received a quarterly distribution of $0.30. The
class B units do not participate in quarterly distributions above $0.30 per
unit. The class B units began sharing in income allocations and distributions
with respect to the third quarter 2008.
The class
B units have the same voting rights as if they were outstanding common units and
are entitled to vote as a separate class on any matters that materially
adversely affect the rights or preferences of the class B units in relation to
other classes of partnership interests or as required by law. The class B units
will be convertible into common units upon demand by the holder on a one-for-one
basis at any time after June 30, 2013.
Registration
Rights Agreement
In conjunction with the sale of class B
units and common units to BPHC in 2008, the Partnership entered into a
registration rights agreement with BPHC. Under the terms of the agreement, the
Partnership has agreed to pay the costs of maintaining an effective registration
statement at BPHC's option, including accounting and legal expenses, for the
sale of common units BPHC has acquired as a result of the purchase of common
units in October 2008, or conversion of the class B units into common units. In
addition the Partnership has agreed to pay the underwriting discount on the sale
of the first 21.2 million units by BPHC up to $0.925 per common unit. As a
result, in 2008, the Partnership recorded a liability and reduced Partner’s
Capital by $20.6 million to recognize the contingent obligation to
BPHC.
Conversion of Subordinated
Units
In
November 2008, the Partnership satisfied the last of the earnings and
distribution tests contained in its partnership agreement for the conversion
into common units on a one-for-one basis of all of the 33.1 million then
outstanding subordinated units held by BPHC. The last of these requirements was
met coincident with payment of the quarterly distribution in the fourth quarter
2008. Two days following the distribution, all of the subordinated units
converted to common units.
Long-Term
Debt
The following table presents all
long-term debt issues outstanding (in millions):
|
|
|
December
31,
|
|
|
|
|
2008
|
|
|
2007
|
|
|
Notes
and Debentures:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Boardwalk
Pipelines
|
|
|
|
|
|
|
|
5.88%
Notes due 2016
|
|
$ |
250.0 |
|
|
$ |
250.0 |
|
|
5.20%
Notes due 2018
|
|
|
185.0 |
|
|
|
185.0 |
|
|
5.50%
Notes due 2017
|
|
|
300.0 |
|
|
|
300.0 |
|
|
|
|
|
|
|
|
|
|
|
|
Gulf
South
|
|
|
|
|
|
|
|
|
|
6.30%
Notes due 2017
|
|
|
275.0 |
|
|
|
275.0 |
|
|
5.75%
Notes due 2012
|
|
|
225.0 |
|
|
|
225.0 |
|
|
5.05%
Notes due 2015
|
|
|
275.0 |
|
|
|
275.0 |
|
|
|
|
|
|
|
|
|
|
|
|
Texas
Gas
|
|
|
|
|
|
|
|
|
|
7.25%
Debentures due 2027
|
|
|
100.0 |
|
|
|
100.0 |
|
|
4.60%
Notes due 2015
|
|
|
250.0 |
|
|
|
250.0 |
|
|
5.50%
Notes due 2013
|
|
|
250.0 |
|
|
|
- |
|
|
Total
notes and debentures
|
|
|
2,110.0 |
|
|
|
1,860.0 |
|
|
|
|
|
|
|
|
|
|
|
|
Revolving
Credit Facility:
|
|
|
|
|
|
|
|
|
|
Boardwalk
Pipelines
|
|
|
285.0 |
|
|
|
- |
|
|
Gulf
South
|
|
|
317.0 |
|
|
|
- |
|
|
Texas
Gas
|
|
|
190.0 |
|
|
|
- |
|
|
Total revolving credit facility
|
|
|
792.0 |
|
|
|
- |
|
|
|
|
|
2,902.0 |
|
|
|
1,860.0 |
|
|
Less: unamortized debt discount
|
|
|
(12.6 |
) |
|
|
(12.1 |
) |
|
Total
Long-Term Debt
|
|
$ |
2,889.4 |
|
|
$ |
1,847.9 |
|
Maturities of the Partnership’s
long-term debt for the next five years and in total thereafter are as follows
(in millions):
|
2009
|
|
|
- |
|
|
2010
|
|
|
- |
|
|
2011
|
|
|
- |
|
|
2012
|
|
$ |
1,017.0 |
|
|
2013
|
|
|
250.0 |
|
|
Thereafter
|
|
|
1,635.0 |
|
|
Total
long-term debt
|
|
$ |
2,902.0 |
|
Notes
and Debentures
For the
years ended December 30, 2008 and 2007, the Partnership completed the following
debt issuances of notes and debentures (in millions, except interest
rates):
|
Date
of Issuance
|
|
Issuing
Subsidiary
|
|
Amount
of
Issuance
|
|
|
Purchaser
Discounts
and
Expenses
|
|
|
Net
Proceeds
|
|
|
Interest
Rate
|
|
Maturity
Date
|
Interest
Payable
|
|
March
2008
|
|
Texas
Gas
|
|
$ |
250.0 |
|
|
$ |
2.8 |
|
|
$ |
247.2 |
|
|
|
5.50 |
% |
April
1, 2013
|
April
1 and October 1
|
|
August
2007
|
|
Gulf
South
|
|
|
225.0 |
|
|
|
2.0 |
|
|
|
223.0 |
|
|
|
5.75 |
% |
August
15, 2012
|
February
15 and August 15
|
|
August
2007
|
|
Gulf
South
|
|
|
275.0 |
|
|
|
2.7 |
|
|
|
272.3 |
|
|
|
6.30 |
% |
August
15, 2017
|
February
15 and August 15
|
The
notes are redeemable, in whole or in part, at the Partnership’s option at
any time, at redemption prices equal to the greater of 100% of the principal
amount of the notes to be redeemed or a “make whole” redemption price based on
the remaining scheduled payments of principal and interest discounted to the
date of redemption at a rate equal to the Treasury rate plus 20 to 50 basis
points depending upon the particular issue of notes, plus accrued and unpaid
interest, if any. Other customary covenants apply, including those
concerning events of default. As of December 31, 2008 and 2007, the
weighted-average interest rate of the Partnership’s senior unsecured debt was
5.89% and 5.82%, excluding amounts borrowed under the revolving credit
agreement.
The indentures governing the notes have
restrictive covenants which provide that, with certain exceptions, neither the
Partnership nor any of its subsidiaries may create, assume or suffer to exist
any lien upon any property to secure any indebtedness unless the debentures and
notes shall be equally and ratably secured. All debt obligations are unsecured.
At December 31, 2008, Boardwalk Pipelines and the operating subsidiaries were in
compliance with their debt covenants.
Revolving
Credit Facility
The
Partnership has a revolving credit facility which has aggregate lending
commitments of $1.0 billion. A financial institution which has a $50.0 million
commitment under the revolving credit facility filed for bankruptcy protection
in the third quarter 2008 and has not funded its portion of the Partnership’s
borrowing requests since that time. Borrowings outstanding under the credit
facility as of December 31, 2008, were $792.0 million with a weighted-average
borrowing rate of 3.43%. Subsequent to December 31, 2008, the Partnership
borrowed all of the remaining unfunded commitments under the credit facility
(excluding the unfunded commitment of the bankrupt lender noted above) which
increased borrowings to $953.5 million.
As of
December 31, 2007, no funds were drawn under the credit facility, however, the
Partnership had outstanding letters of credit under the facility for $185.6
million to support certain obligations associated with the pipeline expansion
projects which reduced the available capacity under the facility by such amount.
The letters of credit were reduced to zero as the Partnership met its related
obligations.
The
credit facility contains various restrictive covenants and other usual and
customary terms and conditions, including limitations on the payment of cash
dividends by our subsidiaries and other restricted payments, the incurrence of
additional debt, the sale of assets, and sales-leaseback transactions. The
financial covenants under the credit facility require the Partnership and its
subsidiaries to maintain, among other things, a ratio of total consolidated debt
to consolidated EBITDA (as defined in the credit agreement) measured for the
previous twelve months, of not more than 5.0 to 1.0. The Partnership and its
subsidiaries were in compliance with all covenant requirements under the credit
facility as of December 31, 2008 and 2007.
Note
8: Derivatives
Subsidiaries of the Partnership use
futures, swaps, and option contracts (collectively, derivatives) to hedge
exposure to various risks, including natural gas commodity price risk and
interest rate risk. These hedge contracts are reported at fair value in
accordance with SFAS No. 133, as amended.
Certain
volumes of gas stored underground are available for sale and subject to
commodity price risk. At December 31, 2008 and December 31, 2007, approximately
$0.2 million and $16.3 million of gas stored underground, which the Partnership
owns and carries on its Consolidated Balance Sheets as current Gas stored
underground, was exposed to commodity price risk. The Partnership utilizes
derivatives to hedge certain exposures to market price fluctuations on the
anticipated operational sales of gas.
In 2008,
as a result of Phase III of the Western Kentucky Storage Expansion project
approximately 5.1 Bcf of gas stored underground with a book value of $11.8
million became available for sale. The Partnership entered into derivatives,
which were designated as cash flow hedges, to hedge the price exposure related
to the expected sale of this gas. The gas was subsequently sold and the related
derivatives were settled, resulting in a gain of $34.4 million for the year
ended December 31, 2008, which was reported in Net gain on disposal of operating
assets and related contracts on the Consolidated Statements of Income. In 2007,
approximately 4.0 Bcf of gas related to Phase II of the Western Kentucky Storage
Expansion project was sold and the related derivatives were settled, resulting
in a gain of $22.0 million.
In 2007,
the Partnership entered into natural gas price swaps to hedge exposure to prices
associated with the purchase of 2.1 Bcf of natural gas to be used for line pack
for pipeline expansion projects. The derivatives were not designated as hedges
and were marked to fair value through earnings resulting in a gain of $0.9
million in Miscellaneous other income, net on the Consolidated Statements of
Income for the year ended December 31, 2008 and a loss of $0.9 million for the
year ended December 31, 2007. These derivatives were settled in connection with
the purchase of the gas in 2008.
In 2007,
the Partnership entered into a Treasury rate lock for a notional amount of
$150.0 million of principal to hedge the risk attributable to changes in the
risk-free component of forward 10-year interest rates through February 1, 2008.
The Treasury rate lock was designated as a cash flow hedge in accordance with
SFAS No. 133. As of December 31, 2007, the Partnership recorded a
payable of $8.4 million and a corresponding amount in Accumulated other
comprehensive (loss) income for the fair value of the rate lock. On February 1,
2008, the Partnership settled the rate lock and paid the counterparty
approximately $15.0 million which was deferred as a component of Accumulated
other comprehensive (loss) income. The loss will be amortized to interest
expense over 10 years.
The
derivatives related to the sale of natural gas and cash for fuel reimbursement
generally qualify for cash flow hedge accounting under SFAS No. 133 and are
designated as such. The effective component of related unrealized gains and
losses resulting from changes in fair values of the derivatives designated as
cash flow hedges are deferred as a component of Accumulated other comprehensive
(loss) income. The deferred gains and losses are recognized in the Consolidated
Statements of Income when the anticipated transactions affect earnings. In
situations where continued reporting of a loss in Accumulated other
comprehensive (loss) income would result in recognition of a future loss on the
combination of the derivative and the hedged transaction, SFAS No. 133 requires
that the loss be immediately recognized in earnings for the amount that is not
expected to be recovered. The Partnership reclassified losses of $1.7 million
for the twelve months ended December 31, 2008, from Accumulated other
comprehensive (loss) income to earnings related to amounts that are not expected
to be recovered in future periods from the combination of sales of gas stored
underground and the deferred losses associated with related
derivatives.
Generally,
for gas sales and cash for fuel reimbursement, any gains and losses on the
related derivatives would be recognized in Operating Revenues. For the sale
of gas related to the Western Kentucky Storage Expansion projects, any gains and
losses on the related derivatives were recognized in Net gain on disposal of
operating assets and related contracts. Any gains and losses on the derivatives
related to the line pack gas purchases would be recognized in Miscellaneous
other income, net.
The changes in fair values of the
derivatives designated as cash flow hedges are expected to, and do, have a high
correlation to changes in value of the anticipated transactions. Each reporting
period the Partnership measures the effectiveness of the cash flow hedge
contracts. To the extent the changes in the fair values of the hedge contracts
do not effectively offset the changes in the estimated cash flows of the
anticipated transactions, the ineffective portion of the hedge contracts is
currently recognized in earnings. If the anticipated transactions are deemed no
longer probable to occur, hedge accounting would be terminated and changes in
the fair values of the associated derivative financial instruments would be
recognized currently in earnings. Less than $0.1 million of ineffectiveness
was recorded for the year ended December 31, 2008. Ineffectiveness decreased Net
income by $0.1 million for the year ended December 31, 2007 and increased Net
income by $0.5 million for the year ended December 31, 2006. The Partnership did
not discontinue any cash flow hedges during the years ended December 31, 2008
and 2007. The derivatives existing at December 31, 2008 have settlement dates of
2009 and 2010.
The fair values of derivatives existing
as of December 31, 2008 and 2007, were included in the following captions in the
Consolidated Balance Sheets (in millions):
|
|
|
December
31,
|
|
|
|
|
2008
|
|
|
2007
|
|
|
Other
current assets
|
|
$ |
10.5 |
|
|
$ |
2.2 |
|
|
Other
assets
|
|
|
3.7 |
|
|
|
- |
|
|
Other
current liabilities
|
|
|
(0.1 |
) |
|
|
9.4 |
|
|
Accumulated
other comprehensive loss
|
|
|
(0.7 |
) |
|
|
(8.9 |
) |
Note
9: Fair Value
SFAS
No. 157, Fair Value Measurements
In 2008, the Partnership implemented
the provisions of SFAS No. 157, except for the provisions related to
non-financial assets and liabilities measured at fair value on a non-recurring
basis, which provisions will be applied beginning in 2009. Fair value refers to
the price that would be received to sell an asset or paid to transfer a
liability in an orderly transaction in the principal market in which the
reporting entity transacts based on the assumptions market participants would
use when pricing the asset or liability. SFAS No. 157 establishes a fair value
hierarchy that prioritizes the information used to develop those assumptions
giving priority, from highest to lowest, to quoted prices in active markets for
identical assets and liabilities (Level 1); observable inputs not included in
Level 1, for example, quoted prices for similar assets and liabilities (Level
2); and unobservable data (Level 3), for example, a reporting entity’s own
internal data based on the best information available in the
circumstances.
The
Partnership identified its derivatives and short-term investments as items
governed by the provisions of SFAS No. 157 as of December 31, 2008. The
derivatives in existence at December 31, 2008, were natural gas price swaps and
options, which were recorded at fair value based on New York Mercantile Exchange
(NYMEX) quotes for natural gas futures and options. The NYMEX quotes were deemed
to be observable inputs for similar assets and liabilities and rendered Level 2
inputs for purposes of disclosure. The short-term investments consist of U.S.
Government securities, primarily Treasury notes, under overnight repurchase
agreements. These investments are recorded at fair value based on the quoted
prices in active markets of the securities and rendered Level 1 inputs for
purposes of disclosure. The application of SFAS No. 157 had no effect on the
Partnership’s financial statements.
The fair
values of derivatives and short-term investments existing as of December 31,
2008, were included in the following captions in the Consolidated Balance Sheets
(in millions):
|
|
|
Total
at
December
31, 2008
|
|
|
Quoted
Prices in Active Markets for Identical Assets
Level
1
|
|
|
Significant
Other Observable Inputs
Level
2
|
|
|
Significant
Unobservable Inputs
Level
3
|
|
|
Assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Short-term
investments
|
|
$ |
175.0 |
|
|
$ |
175.0 |
|
|
|
|
|
|
|
|
Other
current assets
|
|
|
10.5 |
|
|
|
- |
|
|
$ |
10.5 |
|
|
|
- |
|
|
Other
assets
|
|
|
3.7 |
|
|
|
-
|
|
|
|
3.7 |
|
|
|
- |
|
|
Total
assets
|
|
$ |
189.2 |
|
|
$ |
175.0 |
|
|
$ |
14.2 |
|
|
|
- |
|
|
Liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
current liabilities
|
|
$ |
(0.1 |
) |
|
|
- |
|
|
$ |
(0.1 |
) |
|
|
- |
|
|
Total
liabilities
|
|
$ |
(0.1 |
) |
|
|
- |
|
|
$ |
(0.1 |
) |
|
|
- |
|
SFAS
No. 159, The Fair Value Option for Financial Assets and Financial
Liabilities
In 2008, the Partnership had the option
to apply the provisions of SFAS No. 159, which allows companies to elect to
measure and record certain financial assets and liabilities at fair value that
would not otherwise be recorded at fair value, such as long-term debt or notes
receivable. Unrealized gains and losses on items for which the fair value option
was chosen would be reported in earnings. The Partnership reviewed its financial
assets and liabilities in existence at January 1, 2008, as well as any financial
assets and liabilities entered into during 2008, and did not elect the fair
value option for any applicable items. Consequently, the application of SFAS No.
159 had no effect on the Partnership’s financial statements.
Note
10: Employee Benefits
Retirement
Plans
Texas Gas employees hired before
November 1, 2006, are covered under a non-contributory, defined benefit pension
plan. The Texas Gas Supplemental Retirement Plan (SRP) provides pension benefits
for the portion of an eligible employee’s pension benefit that becomes subject
to compensation limitations under the Internal Revenue Code. Effective November
1, 2006, the defined benefit pension plan was closed to new participants and new
employees are provided benefits under a defined contribution money purchase
plan. The Partnership uses a measurement date of December 31 for its benefits
plans.
As a
result of its rate case settlement in 2006, the Partnership is required to fund
the amount of the Texas Gas annual net periodic pension cost, including a
minimum of $3.0 million which is the amount included in rates. In 2008, the
Partnership funded $4.6 million to the Texas Gas retirement plan and expects to
fund approximately $5.0 million to the plan in 2009. Through December 31, 2008,
no funding has been provided for the SRP other than the payment of benefits
under the plan, and the Partnership does not expect to fund this plan in the
future until such time as benefits are paid.
The
Partnership recognizes each year the actuarially determined amount of net
periodic pension cost in expense, including a minimum amount of $3.0 million, in
accordance with the rate case settlement. Texas Gas is permitted to seek future
rate recovery for amounts of annual pension costs in excess of $6.0 million and
is precluded from seeking future recovery of annual pension costs between $3.0
and $6.0 million. As a result, the Partnership would recognize a regulatory
asset for amounts of annual pension cost in excess of $6.0 million and would
reduce its regulatory asset to the extent that any amounts of annual pension
cost are less than $3.0 million. Annual pension costs between $3.0 million and
$6.0 million will be charged to expense.
Postretirement
Benefits Other Than Pension (PBOP)
Texas Gas provides postretirement
medical benefits and life insurance to retired employees who were employed full
time, hired prior to January 1, 1996, and have met certain other requirements.
The Partnership contributed $0.8 million, $0.9 million and $0.3 million to the
plan in 2008, 2007 and 2006. Due to plan changes regarding benefits available to
current and future retirees described below, the PBOP plan is currently in an
overfunded status, therefore the Partnership does not expect to make any
contributions to the plan in 2009. Due to the Texas Gas rate case settlement in
2006, the Partnership began to amortize the balance of its regulatory asset for
PBOP of approximately $32.0 million on a straight-line basis over 5 to 6
years.
Early
Retirement Incentive Program
In 2006,
Texas Gas implemented an early retirement incentive program (ERIP) which was
made available to approximately 240 non-executive employees age 52 and older
with at least five years of service. Under the program, Texas Gas provided
eligible employees three additional years for purposes of age-based vesting
under the postretirement medical plan and three additional years of pay credits
under the pension plan. In 2007, all of the approximately 100 employees who
elected to participate in the program retired and the Partnership recognized a
settlement charge of $4.5 million related to the program. The Partnership
recognized a special termination benefit of approximately $6.0 million for
pension and $0.9 million for PBOP in 2006.
Projected
Benefit Obligation, Fair Value of Assets and Funded Status
The projected benefit obligation, fair
value of assets, funded status and the amounts not yet recognized as components
of net periodic pension and postretirement benefits cost for the retirement
plans and PBOP at December 31, 2008 and 2007, were as follows (in
millions):
|
|
|
Retirement
Plans
|
|
|
PBOP
|
|
|
|
|
For
the Year Ended
December
31,
|
|
|
For
the Year Ended
December
31,
|
|
|
|
|
2008
|
|
|
2007
|
|
|
2008
|
|
|
2007
|
|
|
Change
in benefit obligation:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Benefit
obligation at beginning of period
|
|
$ |
108.5 |
|
|
$ |
136.9 |
|
|
$ |
56.9 |
|
|
$ |
65.3 |
|
|
Service
cost
|
|
|
3.7 |
|
|
|
3.9 |
|
|
|
0.6 |
|
|
|
0.6 |
|
|
Interest
cost
|
|
|
6.5 |
|
|
|
6.6 |
|
|
|
3.2 |
|
|
|
3.3 |
|
|
Plan
participants’ contributions
|
|
|
- |
|
|
|
- |
|
|
|
1.1 |
|
|
|
0.8 |
|
|
Actuarial
gain
|
|
|
(3.4 |
) |
|
|
(2.2 |
) |
|
|
(6.2 |
) |
|
|
(9.3 |
) |
|
Benefits
paid
|
|
|
(4.0 |
) |
|
|
(0.6 |
) |
|
|
(3.2 |
) |
|
|
(4.1 |
) |
|
Settlement
|
|
|
(1.4 |
) |
|
|
(36.1 |
) |
|
|
- |
|
|
|
- |
|
|
Retiree
drug subsidy
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
0.3 |
|
|
Benefit
obligation at end of period
|
|
$ |
109.9 |
|
|
$ |
108.5 |
|
|
$ |
52.4 |
|
|
$ |
56.9 |
|
|
Change
in plan assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair
value of plan assets at beginning of period
|
|
$ |
91.3 |
|
|
$ |
121.1 |
|
|
$ |
84.2 |
|
|
$ |
80.2 |
|
|
Actual
return on plan assets
|
|
|
(16.3 |
) |
|
|
6.5 |
|
|
|
(16.2 |
) |
|
|
6.4 |
|
|
Benefits
paid
|
|
|
(4.0 |
) |
|
|
(0.6 |
) |
|
|
(3.2 |
) |
|
|
(4.1 |
) |
|
Company
contributions
|
|
|
4.6 |
|
|
|
0.4 |
|
|
|
0.8 |
|
|
|
0.9 |
|
|
Plan
participants’ contributions
|
|
|
- |
|
|
|
- |
|
|
|
1.1 |
|
|
|
0.8 |
|
|
Settlement
|
|
|
(1.4 |
) |
|
|
(36.1 |
) |
|
|
- |
|
|
|
- |
|
|
Fair
value of plan assets at end of period
|
|
$ |
74.2 |
|
|
$ |
91.3 |
|
|
$ |
66.7 |
|
|
$ |
84.2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Funded
status
|
|
$ |
(35.7 |
) |
|
$ |
(17.2 |
) |
|
$ |
14.3 |
|
|
$ |
27.3 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Items
not recognized as components of net periodic cost:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Prior
service cost (credit)
|
|
$ |
0.1 |
|
|
$ |
0.1 |
|
|
$ |
(55.2 |
) |
|
$ |
(63.0 |
) |
|
Net
actuarial loss
|
|
|
31.0 |
|
|
|
11.7 |
|
|
|
25.6 |
|
|
|
10.7 |
|
|
Total
|
|
$ |
31.1 |
|
|
$ |
11.8 |
|
|
$ |
(29.6 |
) |
|
$ |
(52.3 |
) |
The Partnership does not anticipate
that any plan assets will be returned to the Partnership during
2009. At December 31, 2008 and 2007, the following aggregate
information relates only to the underfunded retirement plan (in
millions):
|
|
For
the Year Ended
December
31,
|
|
|
|
2008
|
|
2007
|
|
|
Projected
benefit obligation
|
|
$ |
109.9 |
|
|
$ |
108.5 |
|
|
Accumulated
benefit obligation
|
|
|
97.4 |
|
|
|
94.6 |
|
|
Fair
value of plan assets
|
|
|
74.2 |
|
|
|
91.3 |
|
Components
of Net Periodic Benefit Cost
Components of net periodic benefit cost
for both the retirement plans and PBOP for the years ended December 31, 2008,
2007 and 2006 were the following (in millions):
|
|
|
Retirement
Plans
|
|
|
PBOP
|
|
|
|
|
For
the Year Ended December 31,
|
|
|
For
the Year Ended December 31,
|
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
Service
cost
|
|
$ |
3.7 |
|
|
$ |
3.9 |
|
|
$ |
4.4 |
|
|
$ |
0.6 |
|
|
$ |
0.6 |
|
|
$ |
1.3 |
|
|
Interest
cost
|
|
|
6.5 |
|
|
|
6.6 |
|
|
|
6.7 |
|
|
|
3.2 |
|
|
|
3.3 |
|
|
|
5.1 |
|
|
Expected
return on plan assets
|
|
|
(6.8 |
) |
|
|
(7.1 |
) |
|
|
(7.1 |
) |
|
|
(5.0 |
) |
|
|
(4.7 |
) |
|
|
(4.6 |
) |
|
Amortization
of prior service credit
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(7.8 |
) |
|
|
(7.8 |
) |
|
|
(4.5 |
) |
|
Amortization
of unrecognized net loss
|
|
|
0.1 |
|
|
|
0.2 |
|
|
|
0.7 |
|
|
|
0.1 |
|
|
|
0.7 |
|
|
|
1.1 |
|
|
Settlement
charge
|
|
|
0.3 |
|
|
|
4.5 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
Special
termination benefit (ERIP)
|
|
|
- |
|
|
|
- |
|
|
|
6.0 |
|
|
|
- |
|
|
|
- |
|
|
|
0.9 |
|
|
Regulatory
asset (increase) decrease
|
|
|
- |
|
|
|
(1.7 |
) |
|
|
(4.0 |
) |
|
|
5.4 |
|
|
|
5.4 |
|
|
|
7.3 |
|
|
Net
periodic pension expense
|
|
$ |
3.8 |
|
|
$ |
6.4 |
|
|
$ |
6.7 |
|
|
$ |
(3.5 |
) |
|
$ |
(2.5 |
) |
|
$ |
6.6 |
|
The decrease in the regulatory asset
for PBOP was due primarily to the amortization of costs incurred in prior years.
In 2007 and 2006, the regulatory asset for the retirement plans was increased
due to the accumulated cost for the year exceeding the expense cap established
in the Texas Gas rate case settlement. In accordance with the rate case
settlement, Texas Gas is permitted to seek future rate recovery for amounts of
annual pension costs in excess of $6.0 million.
Estimated
Future Benefit Payments
The
following table shows benefit payments, which reflect expected future service,
as appropriate, which are expected to be paid for both the retirement plans and
PBOP (in millions):
|
|
|
Retirement
Plans
|
|
|
PBOP
|
|
|
2009
|
|
$ |
4.1 |
|
|
$ |
4.6 |
|
|
2010
|
|
|
4.3 |
|
|
|
4.3 |
|
|
2011
|
|
|
6.0 |
|
|
|
4.3 |
|
|
2012
|
|
|
9.7 |
|
|
|
4.0 |
|
|
2013
|
|
|
9.8 |
|
|
|
3.9 |
|
|
2014-2018
|
|
|
74.3 |
|
|
|
15.6 |
|
Weighted
–Average Assumptions
The Partnership’s asset allocations at
December 31, 2008 and 2007, for both the qualified retirement plan and PBOP
trusts by category were as follows:
|
|
|
Retirement
Plans
|
|
|
PBOP
|
|
|
|
|
For
the Year Ended December 31,
|
|
|
For
the Year Ended December 31,
|
|
|
|
|
2008
|
|
|
2007
|
|
|
2008
|
|
|
2007
|
|
|
Debt
securities
|
|
|
38 |
% |
|
|
46 |
% |
|
|
49 |
% |
|
|
41 |
% |
|
Equity
securities
|
|
|
18 |
% |
|
|
23 |
% |
|
|
15 |
% |
|
|
22 |
% |
|
Limited
partnerships
|
|
|
24 |
% |
|
|
13 |
% |
|
|
26 |
% |
|
|
25 |
% |
|
Comingled
funds
|
|
|
12 |
% |
|
|
12 |
% |
|
|
7 |
% |
|
|
- |
|
|
Cash,
short-term investments and other
|
|
|
8 |
% |
|
|
6 |
% |
|
|
3 |
% |
|
|
12 |
% |
|
Total
|
|
|
100 |
% |
|
|
100 |
% |
|
|
100 |
% |
|
|
100 |
% |
The Partnership employs a total-return
approach whereby a mix of equities and fixed income investments is used to
maximize the long-term return on plan assets for a prudent level of risk. The
intent of this strategy is to minimize plan expenses by outperforming plan
liabilities over the long run. Risk tolerance is established through careful
consideration of the plan liabilities, plan funded status and the financial
conditions of the Partnership. The goal for 2008 was to allocate between 40% and
60% of the investment portfolio to equity and alternative investments, including
limited partnerships, with consideration given to market conditions and target
asset returns. The portion of the portfolio not invested in equity and
alternative investments was invested primarily in fixed income securities,
comingled funds and the remainder in cash and short-term investments.
The investment portfolio contains
a diversified blend of U.S. and non-U.S. fixed income and equity investments.
Alternative investments, including hedge funds, are used judiciously to enhance
risk-adjusted long-term returns while improving portfolio diversification.
Derivatives may be used to gain market exposure in an efficient and timely
manner. Investment risk is measured and monitored on an ongoing basis through
annual liability measurements, periodic asset and liability studies and
quarterly investment portfolio reviews.
Weighted-average
assumptions used to determine benefit obligations for the years ended December
31, 2008 and 2007 were the following:
|
|
Retirement
Plans
|
|
PBOP
|
|
For
the Year Ended
December
31,
|
|
For
the Year Ended
December
31,
|
|
2008
|
|
2007
|
|
2008
|
|
2007
|
|
Discount
rate
|
6.30%
|
|
6.00%
|
|
6.30%
|
|
6.00%
|
|
Rate
of compensation increase
|
4.00%
|
|
4.00%
|
|
-
|
|
-
|
Weighted-average
assumptions used to determine net periodic benefit cost for the periods
indicated were as follows:
|
|
Retirement
Plans
|
|
PBOP
|
|
|
For
the Year Ended December 31,
|
|
For
the Year Ended December
31,
|
|
|
2008
|
2007
|
2006
|
|
2008
|
2007
|
2006
|
|
Discount
rate
|
6.00%
|
5.94%
|
5.63%
|
|
6.00%
|
5.75%
|
5.63%to5.75%
|
|
Expected
return on plan assets
|
7.50%
|
7.50%
|
7.50%
|
|
6.15%to6.15%
|
5.00%to6.15%
|
5.00%to
6.15%
|
|
Rate
of compensation increase
|
4.00%
|
5.50%
|
5.50%
|
|
-
|
-
|
-
|
PBOP
assumed health care cost trends
Assumed health care-cost-trend rates
have a significant effect on the amounts reported for PBOP. A
one-percentage-point change in assumed trend rates for health care costs
would have had the following effects on amounts reported for the year ended
December 31, 2008 (in millions):
|
Effect of 1% Increase:
|
|
2008
|
|
|
Benefit
obligation at end of year
|
|
$ |
1.2 |
|
|
Total
of service and interest costs for year
|
|
|
0.1 |
|
|
Effect of 1% Decrease:
|
|
|
|
|
Benefit
obligation at end of year
|
|
$ |
(1.4 |
) |
|
Total
of service and interest costs for year
|
|
|
(0.1 |
) |
For
measurement purposes, at December 31, 2008, health care costs for the plans were
assumed to increase 9% for 2009-2010 grading down to 5% in 0.5% annual
increments for participants not eligible for Medicare and 9.5% grading down to
5% in 0.5% annual increments for participants eligible for Medicare. For
December 31, 2007, measurement purposes, health care costs for the plans were
assumed to increase 9% for 2008-2009, grading down to 5% in 0.5% annual
increments for participants not eligible for Medicare and 10% grading down to 5%
in 0.5% annual increments for participants eligible for Medicare.
Defined
Contribution Plans
Texas Gas
employees hired on or after November 1, 2006 and Gulf South employees are
provided retirement benefits under a similar defined contribution money purchase
plan. The operating subsidiaries also provide 401(k) plan benefits to their
employees. Costs related to the Partnership’s defined contribution plans were
$5.7 million, $5.3 million and $5.1 million for the years ended December 31,
2008, 2007 and 2006.
Strategic
Long-Term Incentive Plan
In 2006,
Boardwalk GP approved the Partnership’s Strategic Long-Term Incentive Plan
(SLTIP). The SLTIP provides for the issuance of up to 500 phantom general
partner units (Phantom GP Units) to selected employees of the Partnership and
its subsidiaries. The Partnership believes that such awards better align the
interests of the selected employees with those of the general partner and common
unitholders. Each Phantom GP Unit entitles the holder thereof, upon vesting, to
a lump sum cash payment in an amount determined by a formula based on cash
distributions made by the Partnership to its general partner during the four
quarters preceding the vesting date and the implied yield on the Partnership’s
common units, up to a maximum of $50,000 per unit.
A summary
of the status of the Partnership’s SLTIP as of December 31, 2008, 2007 and 2006,
and changes during the years ended December 31, 2008 and 2007, is presented
below:
|
|
|
Phantom
GP Units
|
|
|
Total
Fair Value
(in
millions)
|
|
|
Weighted-Average
Vesting Period
(in
years)
|
|
|
Outstanding
at 12/31/2006 (b)
|
|
|
250 |
|
|
$ |
12.5 |
|
|
|
3.5 |
|
|
Granted
(a)
|
|
|
116 |
|
|
|
5.8 |
|
|
|
4.0 |
|
|
Forfeited
|
|
|
(5 |
) |
|
|
|
|
|
|
- |
|
|
Outstanding
at 12/31/2007 (b)
|
|
|
361 |
|
|
|
18.1 |
|
|
|
3.0 |
|
|
Granted
(a)
|
|
|
125 |
|
|
|
6.3 |
|
|
|
4.0 |
|
|
Paid
|
|
|
(33 |
) |
|
|
(0.4 |
) |
|
|
- |
|
|
Forfeited
|
|
|
(76 |
) |
|
|
|
|
|
|
- |
|
|
Outstanding
at 12/31/2008 (b)
|
|
|
377 |
|
|
|
16.9 |
|
|
|
2.7 |
|
|
(a)
|
Represents
fair value and weighted-average vesting period of awards at grant
date.
|
|
(b)
|
Represents
fair value and remaining weighted-average vesting period of outstanding
awards at the end of the period.
|
The fair
value of the awards at the date of grant was based on the formula contained in
the SLTIP and assumptions made regarding potential future cash
distributions made to the general partner during the four quarters
preceding the vesting date and the future implied yield on the
Partnership's common units. The fair value of the awards will be recognized
ratably over the vesting period and remeasured each quarter until settlement in
accordance with the treatment of awards classified as liabilities prescribed in
SFAS No. 123(R). The Partnership recorded $1.1 million, $3.3 million and $0.8
million in Administrative and general expenses during 2008, 2007 and 2006 for
the ratable recognition of the GP Phantom Unit awards fair value. The total
estimated remaining unrecognized compensation expense related to the GP Phantom
Units outstanding at December 31, 2008, of $12.1 million will be recognized over
the average remaining vesting period of approximately 2.7 years. Approximately
90 Phantom GP Units were available for grant under the plan at December 31,
2008.
Long-Term
Incentive Plan
In 2005, the Partnership adopted the
Long-Term Incentive Plan (LTIP) for the officers and directors of its general
partner and for selected employees of its subsidiaries. The Partnership believes
that such awards better align the interests of the selected employees with those
of the common unitholders. The Partnership reserved 3,525,000 units for grants
of units, restricted units, unit options and unit appreciation rights under the
plan. The Partnership has granted phantom common units under the plan. Each such
grant: includes a tandem grant of Distribution Equivalent Rights (DERs); vests
50% on the second anniversary of the grant date and 50% on the third anniversary
of the grant date; and will be payable to the grantee in cash upon vesting in an
amount equal to the sum of the fair market value of the units (as defined in the
plan) that vest on the vesting date plus the vested amount then credited to the
grantee’s DER account, less applicable taxes. The fair value of the awards will
be recognized ratably over the vesting period and remeasured each quarter until
settlement based on the market price of the Partnership’s common units and
amounts credited under the DERs. The Partnership did not make any grants of
units, restricted units, unit options or unit appreciation rights under the
plan.
A summary
of the status of the Partnership’s LTIP as of December 31, 2008, 2007 and 2006,
and changes during the years ended December 31, 2008 and 2007, is presented
below:
|
|
|
Phantom
Common Units
|
|
|
Total
Fair Value
(in
millions)
|
|
|
Weighted-Average
Vesting Period
(in
years)
|
|
|
Outstanding
at 12/31/2006 (a)
|
|
|
75,085 |
|
|
$ |
2.4 |
|
|
|
2.2 |
|
|
Granted
(b)
|
|
|
49,966 |
|
|
|
1.6 |
|
|
|
2.5 |
|
|
Paid
|
|
|
(14,431 |
) |
|
|
(0.4 |
) |
|
|
- |
|
|
Forfeited
|
|
|
(2,099 |
) |
|
|
|
|
|
|
- |
|
|
Outstanding
at 12/31/2007 (a)
|
|
|
108,521 |
|
|
|
3.5 |
|
|
|
1.8 |
|
|
Granted
(b)
|
|
|
54,033 |
|
|
|
1.1 |
|
|
|
2.5 |
|
|
Paid
|
|
|
(32,907 |
) |
|
|
(0.8 |
) |
|
|
- |
|
|
Forfeited
|
|
|
(21,359 |
) |
|
|
|
|
|
|
- |
|
|
Outstanding
at 12/31/2008 (a)
|
|
|
108,288 |
|
|
|
2.1 |
|
|
|
1.8 |
|
|
(a)
|
Represents fair value and remaining weighted-average vesting period of
outstanding awards at the end of the
period.
|
|
(b)
|
Represents
fair value and weighted-average vesting period of awards at grant
date.
|
The fair
value of the awards at the date of grant was based on the formula contained in
the LTIP, including the closing market price of the Partnership's common units
on December 31, 2008, 2007 and 2006, of $17.78, $30.62 and $31.12 plus the
accumulated value of DERs. The fair value of the awards will be recognized
ratably over the vesting period and remeasured each quarter until settlement in
accordance with the treatment of awards classified as liabilities prescribed in
SFAS No. 123(R). The Partnership recorded $0.4 million $1.1 million and $0.4
million in Administrative and general expenses during 2008, 2007 and 2006 for
the ratable recognition of the Phantom Common Unit awards fair value. The total
estimated remaining unrecognized compensation expense related to the Phantom
Common Units outstanding at December 31, 2008, of $1.4 million will be
recognized over the average remaining vesting period of approximately 1.8
years.
In 2008
and 2007, the general partner purchased 1,500 of the Partnership’s common units
each year in the open market at a price of $23.78 and $36.61 per unit. These
units were granted under the LTIP to the independent directors as part of their
director compensation. At December 31, 2008, 3,521,000 units were available for
grants under LTIP.
Employee
Paid Time-Off Benefits
In fourth quarter 2008, the
Partnership consolidated and changed its employee paid time-off benefits. Under
the previous plan, employees earned paid time-off benefits in the year prior to
the availability of the benefits and allowed some carryover of
unused benefits to subsequent years. Under the new plan, employees must use
all of the paid time-off in the year it is earned, with the exception of a three
year sunset of any carryover existing at December 31, 2008. Due to the nature of
the new plan, in the fourth quarter 2008, the Partnership reversed $7.2 million
of its liability associated with amounts that would otherwise have been
available to employees as of January 1, 2009, resulting in a reduction to
Operation and maintenance expenses of $4.9 million and Administrative and
general expenses of $2.3 million. The remaining liability of $2.1 million, which
is included in Accrued payroll and employee benefits, is comprised of carryover
existing at December 31, 2008.
Note
11: Disposition of Assets
As a
result of Phase III the Western Kentucky Storage Expansion approximately 5.1 Bcf
of gas was sold, resulting in a gain in 2008 of $34.4 million including a loss
on the settlement of the related derivatives. In 2007, the Partnership
recognized a gain of $22.0 million from the sale of 4.0 Bcf of gas related to
sales of base gas from Phase II of the storage expansion project. The gains were
included in Net gain on disposal of operating assets and related contracts in
the Consolidated Statements of Income.
In 2008,
the Partnership completed the sale of its investment in land and coal reserves
along the Ohio River in northern Kentucky and southern Indiana for $16.5
million. These assets had no book value at the time of the sale. As a result,
the Partnership recorded a gain of $16.5 million related to the sale which was
reported in Net gain on disposal of operating assets and related contracts in
the Consolidated Statements of Income.
Note
12: Net Income per Limited Partner Unit and Cash
Distributions
The
Partnership calculates net income per limited partner unit in accordance with
Emerging Issues Task Force (EITF) Issue No. 03-6, Participating Securities and the
Two-Class Method under FASB Statement No. 128. In Issue 3 of EITF
No. 03-6, the EITF reached a consensus that undistributed earnings for a period
should be allocated to a participating security based on the contractual
participation rights of the security to share in those earnings as if all of the
earnings for the period had been distributed. The Partnership's general
partner holds IDRs, which are contractual participation rights as
follows:
|
|
|
|
|
|
|
|
|
|
|
|
Total
Quarterly Distribution
|
|
Marginal Percentage
Interest in
Distributions
|
|
|
Target
Amount
|
Limited
Partner
Unitholders
(1),(2)
|
|
General
Partner
|
|
First
Target Distribution
|
|
up to $0.4025
|
|
98%
|
2%
|
|
Second
Target Distribution
|
|
above $0.4025 up to $0.4375
|
|
85%
|
15%
|
|
Third
Target Distribution
|
|
above
$0.4375 up to $0.5250
|
|
75%
|
25%
|
|
Thereafter
|
|
above
$0.5250
|
|
50%
|
50%
|
|
(1)
|
The
class B unitholders participate in distributions on a pari passu basis
with the Partnership’s common units up to $0.30 per quarter, beginning
with the distribution that was made in the fourth quarter 2008. The class
B units do not participate in quarterly distributions above $0.30 per
unit.
|
|
(2)
|
The
partnership agreement provided that during the subordination period, the
subordinated units would not receive distributions until the common and
class B unitholders received the respective minimum quarterly distribution
($0.35 per quarter in the case of common units and $0.30 in the case of
class B units) plus any arrearages. The subordinated units were not
entitled to arrearages. In November 2008, the subordinated units converted
to common units on a one-for-one
basis.
|
The amounts
reported for net income per limited partner unit on the Consolidated
Statements of Income for the years ended December 31, 2008, 2007 and 2006,
were adjusted to take into account an assumed allocation to the general
partner’s IDRs. Payments made on account of the IDRs are determined in relation
to actual declared distributions. A reconciliation of the limited partners'
interest in net income and net income available to limited partners used in
computing net income per limited partner unit follows (in millions, except per
unit data):
|
|
|
For
the Year Ended December 31,
|
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
Limited
partners' interest in net income
|
|
$ |
280.7 |
|
|
$ |
220.7 |
|
|
$ |
193.6 |
|
|
Less
assumed allocation to IDRs
|
|
|
4.6 |
|
|
|
4.3 |
|
|
|
5.2 |
|
|
Net
income available to limited partners
|
|
|
276.1 |
|
|
|
216.4 |
|
|
|
188.4 |
|
|
Less
assumed allocation to class B units
|
|
|
13.7 |
|
|
|
- |
|
|
|
- |
|
|
Less
assumed allocation to subordinated units
|
|
|
56.6 |
|
|
|
61.9 |
|
|
|
61.1 |
|
|
Net
income available to common units
|
|
$ |
205.8 |
|
|
$ |
154.5 |
|
|
$ |
127.3 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted-average
common units (a)
|
|
|
104.2 |
|
|
|
82.5 |
|
|
|
69.0 |
|
|
Weighted-average
class B units (b)
|
|
|
22.9 |
|
|
|
- |
|
|
|
- |
|
|
Weighted-average
subordinated units (a)
|
|
|
28.7 |
|
|
|
33.1 |
|
|
|
33.1 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
income per limited partner unit – common units
|
|
$ |
1.98 |
|
|
$ |
1.87 |
|
|
$ |
1.85 |
|
|
Net
income per limited partner unit – class B units
|
|
$ |
0.60 |
|
|
$ |
- |
|
|
$ |
- |
|
|
Net
income per limited partner unit – subordinated units
|
|
$ |
1.98 |
|
|
$ |
1.87 |
|
|
$ |
1.85 |
|
|
(a)
|
All
of the 33.1 million subordinated units converted to common units on a
one-for-one basis in November 2008.
|
|
(b)
|
The
number of class B units shown is weighted from July 1, 2008, which is the
date they became eligible to participate in
earnings.
|
As discussed in Note 7, the class B
units were not eligible to participate in income allocations until third quarter
2008. As a result, no income allocations were made to the class B unit equity
accounts and no assumed allocations to the class B units were made pursuant to
EITF No. 03-6 for purpose of computing earnings per unit prior to July 1,
2008.
The Partnership has declared quarterly
distributions per unit to partners of record, including holders of common,
subordinated and class B units and the 2% general partner interest and IDRs held
by its general partner as follows (in millions, except distribution per
unit):
|
Payment
Date
|
|
Distribution
per Unit
|
|
|
Amount
Paid to Common and Subordinated Unitholders
(a)
|
|
|
Amount
Paid to Class B Unitholder
|
|
|
Amount
Paid to General Partner (Including IDRs)
(b)
|
|
|
November
10, 2008
|
|
$ |
0.475 |
|
|
$ |
63.6 |
|
|
$ |
6.9 |
|
|
$ |
3.7 |
|
|
August
11, 2008
|
|
|
0.470 |
|
|
|
62.8 |
|
|
|
- |
|
|
|
3.4 |
|
|
May
12, 2008
|
|
|
0.465 |
|
|
|
57.6 |
|
|
|
- |
|
|
|
2.9 |
|
|
February
25, 2008
|
|
|
0.460 |
|
|
|
56.9 |
|
|
|
- |
|
|
|
2.7 |
|
|
November
12, 2007
|
|
|
0.450 |
|
|
|
52.3 |
|
|
|
- |
|
|
|
2.2 |
|
|
August
13, 2007
|
|
|
0.440 |
|
|
|
51.1 |
|
|
|
- |
|
|
|
1.7 |
|
|
May
14, 2007
|
|
|
0.430 |
|
|
|
50.1 |
|
|
|
- |
|
|
|
1.5 |
|
|
February
27, 2007
|
|
|
0.415 |
|
|
|
44.9 |
|
|
|
- |
|
|
|
1.2 |
|
|
November
6, 2006
|
|
|
0.400 |
|
|
|
40.5 |
|
|
|
- |
|
|
|
0.8 |
|
|
August
18, 2006
|
|
|
0.380 |
|
|
|
38.5 |
|
|
|
- |
|
|
|
0.8 |
|
|
May
19, 2006
|
|
|
0.360 |
|
|
|
36.5 |
|
|
|
- |
|
|
|
0.8 |
|
|
February
23, 2006
|
|
|
0.179 |
(c) |
|
|
18.1 |
|
|
|
- |
|
|
|
0.4 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
|
All
of the 33.1 million subordinated units converted to common units on a
one-for-one basis two days following the November 10, 2008
distribution.
|
|
(b)
|
In
2008 and 2007, the Partnership paid $7.5 million and $2.5 million in
distributions on behalf of IDRs. There were no amounts paid on
behalf of IDRs in 2006.
|
|
(c)
|
Distribution
represented a prorated portion of the $0.350 per unit “minimum quarterly
distribution” (as defined in the Partnership’s partnership agreement) for
the period November 15, 2005 through December 31,
2005.
|
In February 2009, the Partnership
declared a quarterly cash distribution to unitholders of record of $0.48 per
unit.
Note
13: Income Tax
In July
2006, the FASB issued Interpretation No. (FIN) 48, Accounting for Uncertainty in Income
Taxes - An Interpretation of FASB Statement No. 109, which is
effective for the Partnership’s year beginning January 1, 2007. This
interpretation was issued to clarify the accounting for uncertainty in income
taxes recognized in the financial statements by prescribing a comprehensive
model for how a company should recognize, measure, present, and disclose
uncertain tax positions taken or expected to be taken in a tax return. The
Partnership has determined that FIN 48 does not have an impact on its results of
operations.
Following is a summary of the provision
for income taxes for the periods ended December 31, 2008, 2007 and 2006 (in
millions):
|
|
|
For
the Year Ended December 31,
|
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
Current
expense:
|
|
|
|
|
|
|
|
|
|
|
State
|
|
$ |
0.7 |
|
|
$ |
0.8 |
|
|
$ |
0.2 |
|
|
Total
|
|
|
0.7 |
|
|
|
0.8 |
|
|
|
0.2 |
|
|
Deferred
provision:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
State
|
|
|
0.3 |
|
|
|
- |
|
|
|
- |
|
|
Total
|
|
|
0.3 |
|
|
|
- |
|
|
|
- |
|
|
Income
taxes
|
|
$ |
1.0 |
|
|
$ |
0.8 |
|
|
$ |
0.2 |
|
The
Partnership’s tax years 2005 through 2007 remain subject to examination by the
Internal Revenue Service and the states in which it operates. There were no
differences between the provision at statutory rate to the income tax provision
at December 31, 2008, 2007 and 2006. As of December 31, 2008 and 2007, there
were no significant deferred income tax assets or liabilities.
Note
14: Financial Instruments
The following methods and assumptions
were used in estimating the Partnership’s fair-value disclosures for financial
instruments:
Cash and Cash Equivalents:
For cash and short-term financial assets and liabilities, the carrying
amount is a reasonable estimate of fair value due to the short maturity of those
instruments.
Short-term investments: In
December 2008, the Partnership began investing a portion of its undistributed
cash in U.S. Government securities, primarily Treasury notes, under repurchase
agreements. Generally, the Partnership has engaged in overnight repurchase
transactions where purchased securities are sold back to the counterparty the
following business day. Pursuant to the master repurchase agreements, the
Partnership takes actual possession of the purchased securities. In the event of
default by the counterparty under the agreement, the repurchase would be deemed
immediately to occur and the Partnership would be entitled to sell the
securities in the open market, or give the counterparty credit based on the
market price on such date, and apply the proceeds (or deemed proceeds) to the
aggregate unpaid repurchase amounts and any other amounts owing by the
counterparty.
At December 31, 2008, the portfolio
consisted of $175.0 million of Treasury securities with original maturities in
August 2009, held pursuant to overnight repurchase agreements. The amount
invested under repurchase agreements was stated at fair value based on quoted
market prices for the securities.
Long-Term
Debt: Except for debt issued by Gulf South, the debt issued by
Texas Gas in March 2008 and the revolving credit facility, all of the
Partnership’s long-term debt is publicly traded. The estimated fair value of the
Partnership’s publicly traded debt is based on quoted market prices at December
31, 2008 and 2007. The fair market value of the debt that is not publicly traded
and the revolving credit facility is based on market prices of similar debt at
December 31, 2008 and 2007.
The carrying amount and estimated fair
values of the Partnership’s financial instruments as of December 31, 2008 and
2007 were as follows (in millions):
|
|
|
2008
|
|
|
2007
|
|
|
Financial
Assets
|
|
Carrying
Amount
|
|
|
Fair
Value
|
|
|
Carrying
Amount
|
|
|
Fair
Value
|
|
|
Cash
and cash equivalents
|
|
$ |
137.7 |
|
|
$ |
137.7 |
|
|
$ |
317.3 |
|
|
$ |
317.3 |
|
|
Short-term
investments
|
|
|
175.0 |
|
|
|
175.0 |
|
|
|
- |
|
|
|
- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financial
Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term
debt
|
|
$ |
2,889.4 |
|
|
$ |
2,655.3 |
|
|
$ |
1,847.9 |
|
|
$ |
1,834.2 |
|
Note
15: Accumulated Other Comprehensive Income (Loss)
The following table shows the
components of Accumulated other comprehensive (loss) income, net of tax which is
included in Partners’ Capital on the Consolidated Balance Sheets (in
millions):
|
|
For
the Year Ended
December
31,
|
|
|
|
2008
|
|
2007
|
|
|
Loss
on cash flow hedges, net of tax
|
|
$ |
(0.7 |
) |
|
$ |
(8.9 |
) |
|
Deferred
components of net periodic benefit cost, net of tax
|
|
|
(14.8 |
) |
|
|
13.1 |
|
|
Total
Accumulated other comprehensive (loss) income, net of tax
|
|
$ |
(15.5 |
) |
|
$ |
4.2 |
|
In 2009, the Partnership expects to
recognize $13.6 million of the amounts shown
above in earnings. This amount is comprised
of increases to earnings of $9.3 million related to cash flow hedges and $4.3
million related to net periodic benefit cost.
Note
16: Major Customers
Major
Customers
Operating revenues received from the
Partnership’s major customer (in millions) and the percentage of Total operating
revenues earned from that customer were:
|
|
|
For
the Year Ended December 31,
|
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
Customer
|
|
Revenue
|
|
|
%
|
|
|
Revenue
|
|
|
%
|
|
|
Revenue
|
|
|
%
|
|
|
Atmos
Energy
|
|
$ |
73.0 |
|
|
|
9 |
% |
|
$ |
63.9 |
|
|
|
10 |
% |
|
$ |
56.4 |
|
|
|
9 |
% |
Natural
gas price volatility has increased dramatically in recent years, which has
materially increased changes in credit risk related to gas loaned to customers.
As of December 31, 2008, the amount of gas loaned by the operating subsidiaries
or owed to the operating subsidiaries due to gas imbalances was approximately
34.4 TBtu. Assuming an average market price during December 2008 of $5.85 per
million British thermal units, the market value of that gas was approximately
$201.2 million. If any significant customer should have credit or financial
problems resulting in a delay or failure to repay the gas owed to the operating
subsidiaries, this could have a material adverse effect on the Partnership's
financial condition, results of operations and cash flows.
Note
17: Related Party Transactions
Loews provides a variety of corporate
services to the Partnership and its subsidiaries under services agreements which
have been operative since the Partnership’s initial public offering. Services
provided by Loews include, among others, information technology, tax, risk
management, internal audit and corporate development services. Loews charged
$14.5 million, $12.1 million, and $13.0 million for the years ended December 31,
2008, 2007 and 2006 to the Partnership based on the actual time spent by Loews
personnel performing these services, plus related expenses.
Distributions paid related to limited
partner units held by BPHC, the 2% general partner interest and IDRs held by
Boardwalk GP were $181.1 million, $156.4 million and $116.6 million for 2008,
2007 and 2006.
As
discussed in Note 7, the Partnership issued 22.9 million class B units and 21.2
million common units to BPHC in 2008 resulting in net proceeds of $1.2 billion,
including contributions from the general partner to maintain its 2%
interest.
Note
18: Recently Issued Accounting Pronouncements
In March
2008, the FASB approved EITF Issue No. 07-4, Application of the Two-Class Method
under FASB Statement No. 128, Earnings per Share, to Master Limited
Partnerships, which requires that master limited partnerships use the
two-class method of allocating earnings to calculate earnings per
unit. EITF Issue No. 07-4 is effective for fiscal years and interim periods
beginning after December 15, 2008. The Partnership is evaluating the effect
that EITF Issue No. 07-4 will have on its earnings per unit and financial
statements.
Note 19: Supplemental
Disclosure of Cash Flow Information (in
millions):
|
|
|
For
the Year Ended December 31,
|
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
Cash
paid during the period for:
|
|
|
|
|
|
|
|
|
|
|
Interest
(net of amount capitalized)
|
|
$ |
115.4 |
|
|
$ |
46.1 |
|
|
$ |
58.1 |
|
|
Income
taxes, net
|
|
|
0.8 |
|
|
|
0.3 |
|
|
|
0.2 |
|
|
Non-cash
adjustments:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts
payable and PPE
|
|
$ |
86.8 |
|
|
$ |
175.8 |
|
|
$ |
31.9 |
|
|
Accrued
registration rights costs
|
|
|
20.6 |
|
|
|
- |
|
|
|
- |
|
Note
20: Selected Quarterly Financial Data (Unaudited)
The following tables summarize selected
quarterly financial data for 2008 and 2007 for the Partnership (in millions,
except for earnings per unit):
|
|
|
2008
For
the Quarter Ended:
|
|
|
|
|
December
31
|
|
|
September
30
|
|
|
June
30
|
|
|
March
31
|
|
|
Operating
revenues
|
|
$ |
205.6 |
|
|
$ |
191.6 |
|
|
$ |
190.3 |
|
|
$ |
197.3 |
|
|
Operating
expenses
|
|
|
130.3 |
|
|
|
102.8 |
|
|
|
109.3 |
|
|
|
95.8 |
|
|
Operating
income
|
|
|
75.3 |
|
|
|
88.8 |
|
|
|
81.0 |
|
|
|
101.5 |
|
|
Interest
expense, net
|
|
|
10.9 |
|
|
|
8.6 |
|
|
|
17.3 |
|
|
|
18.0 |
|
|
Other
(income) expense
|
|
|
(3.4 |
) |
|
|
6.3 |
|
|
|
(1.2 |
) |
|
|
(4.9 |
) |
|
Income
before income taxes
|
|
|
67.8 |
|
|
|
73.9 |
|
|
|
64.9 |
|
|
|
88.4 |
|
|
Income
taxes
|
|
|
0.2 |
|
|
|
0.3 |
|
|
|
0.2 |
|
|
|
0.3 |
|
|
Net
income
|
|
$ |
67.6 |
|
|
$ |
73.6 |
|
|
$ |
64.7 |
|
|
$ |
88.1 |
|
|
Earnings
per unit:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common
units
|
|
$ |
0.40 |
|
|
$ |
0.47 |
|
|
$ |
0.49 |
|
|
$ |
0.60 |
|
|
Class
B units
|
|
$ |
0.30 |
|
|
$ |
0.30 |
|
|
$ |
- |
|
|
$ |
- |
|
|
Subordinated
units
|
|
$ |
0.40 |
|
|
$ |
0.47 |
|
|
$ |
0.49 |
|
|
$ |
0.60 |
|
|
|
|
2007
For
the Quarter Ended:
|
|
|
|
|
December
31
|
|
|
September
30
|
|
|
June
30
|
|
|
March
31
|
|
|
Operating
revenues
|
|
$ |
169.8 |
|
|
$ |
134.8 |
|
|
$ |
150.5 |
|
|
$ |
188.1 |
|
|
Operating
expenses
|
|
|
89.0 |
|
|
|
86.2 |
|
|
|
106.2 |
|
|
|
95.8 |
|
|
Operating
income
|
|
|
80.8 |
|
|
|
48.6 |
|
|
|
44.3 |
|
|
|
92.3 |
|
|
Interest
expense, net
|
|
|
9.7 |
|
|
|
9.0 |
|
|
|
8.6 |
|
|
|
12.2 |
|
|
Other
(income) expense
|
|
|
(1.3 |
) |
|
|
(0.5 |
) |
|
|
0.1 |
|
|
|
(0.3 |
) |
|
Income
before income taxes
|
|
|
72.4 |
|
|
|
40.1 |
|
|
|
35.6 |
|
|
|
80.4 |
|
|
Income
taxes
|
|
|
0.3 |
|
|
|
0.1 |
|
|
|
0.2 |
|
|
|
0.2 |
|
|
Net
income
|
|
$ |
72.1 |
|
|
$ |
40.0 |
|
|
$ |
35.4 |
|
|
$ |
80.2 |
|
|
Earnings
per unit:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common
units
|
|
$ |
0.56 |
|
|
$ |
0.35 |
|
|
$ |
0.35 |
|
|
$ |
0.61 |
|
|
Subordinated
units
|
|
$ |
0.56 |
|
|
$ |
0.30 |
|
|
$ |
0.17 |
|
|
$ |
0.61 |
|
Note
21: Guarantee of Securities of Subsidiaries
The Partnership has no independent
assets or operations other than its investment in its subsidiaries. The
Partnership’s Boardwalk Pipelines subsidiary has issued securities which have
been fully and unconditionally guaranteed by the Partnership. All of the
subsidiaries of the Partnership are minor other than Boardwalk Pipelines and its
consolidated subsidiaries. The Partnership does have separate partners’ capital
including publicly traded limited partner common units.
The Partnership’s subsidiaries have no
significant restrictions on their ability to pay distributions or make loans to
the Partnership except as noted in the debt covenants and have no restricted
assets at December 31, 2008. Note 7 contains additional information
regarding the Partnership’s debt and related covenants.
None.
Disclosure
Controls and Procedures
Our
principal executive officer (CEO) and principal financial officer (CFO)
undertook an evaluation of our disclosure controls and procedures as of the end
of the period covered by this report. The CEO and CFO have concluded that our
controls and procedures were effective as of December 31, 2008.
Changes
in Internal Control over Financial Reporting
There
were no changes in our internal control over financial reporting that occurred
during the quarter ended December 31, 2008, that have materially affected or
that are reasonably likely to materially affect our internal control over
financial reporting.
Management’s
Report on Internal Control Over Financial Reporting
Our
management is responsible for establishing and maintaining adequate internal
control over financial reporting for us. Our internal control system was
designed to provide reasonable assurance regarding the preparation and fair
presentation of our published financial statements.
There are
inherent limitations to the effectiveness of any control system, however well
designed, including the possibility of human error and the possible
circumvention or overriding of controls. 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. Management must make
judgments with respect to the relative cost and expected benefits of any
specific control measure. The design of a control system also is based in part
upon assumptions and judgments made by management about the likelihood of future
events, and there can be no assurance that a control will be effective under all
potential future conditions. As a result, even an effective system of internal
control over financial reporting can provide no more than reasonable assurance
with respect to the fair presentation of financial statements and the processes
under which they were prepared.
Our
management assessed the effectiveness of our internal control over financial
reporting as of December 31, 2008. In making this assessment, management used
the criteria set forth by the Committee of Sponsoring Organizations of the
Treadway Commission (COSO) in Internal Control – Integrated
Framework. Based on this assessment, our management believes that, as of
December 31, 2008, our internal control over financial reporting was effective.
Deloitte & Touche LLP, the independent registered public accounting firm
that audited our financial statements included in Item 8 of this Report, has
issued a report on our internal control over financial reporting.
REPORT
OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the
Board of Directors of Boardwalk GP, LLC
and the
Partners of Boardwalk Pipeline Partners, LP
We have
audited the internal control over financial reporting of Boardwalk Pipeline
Partners, LP and subsidiaries (the “Partnership”) as of December 31, 2008, based
on criteria established in Internal Control—Integrated
Framework issued by the Committee of Sponsoring Organizations of the
Treadway Commission. The Partnership’s management is responsible for maintaining
effective internal control over financial reporting and for its assessment of
the effectiveness of internal control over financial reporting included in the
accompanying Management’s Report on Internal Control over Financial Reporting.
Our responsibility is to express an opinion on the Partnership's internal
control over financial reporting based on our audit.
We
conducted our audit 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 effective
internal control over financial reporting was maintained in all material
respects. Our audit included obtaining an understanding of internal control over
financial reporting, assessing the risk that a material weakness exists, testing
and evaluating the design and operating effectiveness of internal control based
on the assessed risk, and performing such other procedures as we considered
necessary in the circumstances. We believe that our audit provides a reasonable
basis for our opinion.
A
company's internal control over financial reporting is a process designed by, or
under the supervision of, the company's principal executive and principal
financial officers, or persons performing similar functions, and effected by the
company's board of directors, management, and other personnel 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. A company's internal control over
financial reporting includes those policies and procedures that (1) pertain to
the maintenance of records that, in reasonable detail, accurately and fairly
reflect the transactions and dispositions of the assets of the company; (2)
provide reasonable assurance that transactions are recorded as necessary to
permit preparation of financial statements in accordance with generally accepted
accounting principles, and that receipts and expenditures of the company are
being made only in accordance with authorizations of management and directors of
the company; and (3) provide reasonable assurance regarding prevention or timely
detection of unauthorized acquisition, use, or disposition of the company's
assets that could have a material effect on the financial
statements.
Because
of the inherent limitations of internal control over financial reporting,
including the possibility of collusion or improper management override of
controls, material misstatements due to error or fraud may not be prevented or
detected on a timely basis. Also, projections of any evaluation of the
effectiveness of the internal control over financial reporting to future periods
are subject to the risk that the controls may become inadequate because of
changes in conditions, or that the degree of compliance with the policies or
procedures may deteriorate.
In our
opinion, Boardwalk Pipeline Partners, LP and subsidiaries maintained, in all
material respects, effective internal control over financial reporting as of
December 31, 2008, based on the criteria established in Internal Control—Integrated
Framework issued by the Committee of Sponsoring Organizations of the
Treadway Commission.
We have
also audited, in accordance with the standards of the Public Company Accounting
Oversight Board (United States), the consolidated financial statements and
financial statement schedule as of and for the year ended December 31, 2008 of
the Partnership and our report dated February 24, 2009 expressed an unqualified
opinion on those financial statements and financial statement
schedule.
DELOITTE
& TOUCHE LLP
Houston,
Texas
February
24, 2009
None.
Management
of Boardwalk Pipeline Partners, LP
Boardwalk GP manages our operations and
activities on our behalf. The operations of Boardwalk GP are managed by its
general partner, Boardwalk GP, LLC (BGL). We sometimes refer to Boardwalk GP and
BGL collectively as “our general partner.” Our general partner is not elected by
unitholders and is not subject to re-election on a regular basis in the future.
Unitholders are not entitled to elect the directors of our general partner or
directly or indirectly participate in our management or operation. Our general
partner owes a fiduciary duty to our unitholders. Our general partner is liable,
as general partner, for all of our debts (to the extent not paid from our
assets), except for indebtedness or other obligations that are made specifically
nonrecourse to it. Whenever possible, our general partner intends to cause us to
incur indebtedness or other obligations that are nonrecourse to
it. BGL has a board of directors that oversees our management,
operations and activities. We refer to the board of directors of BGL, the
members of which are appointed by BPHC, as our Board.
Whenever our general partner makes a
determination or takes or declines to take an action in its individual, rather
than representative, capacity, it is entitled to make such determination or to
take or decline to take such other action free of any fiduciary duty or
obligation to any limited partner and is not required to act in good faith or
pursuant to any other standard imposed by our partnership agreement or under any
law. Examples include the exercise of its limited call rights on our units, as
provided in our partnership agreement, its voting rights with respect to the
units it owns, its registration rights and its determination whether or not to
consent to any merger or consolidation of the Partnership, all of which are
described in our partnership agreement. Actions of our general partner which are
made in its individual capacity will be made by BPHC, the sole member of BGL,
rather than by our Board.
Directors
and Executive Officers
The following table shows information
for the directors and executive officers of BGL:
|
Name
|
|
Age
|
|
Position
|
|
Rolf
A. Gafvert
|
|
55
|
|
Chief
Executive Officer, President and Director
|
|
Jamie
L. Buskill
|
|
44
|
|
Chief
Financial Officer, Senior Vice President and Treasurer
|
|
Brian
A. Cody
|
|
51
|
|
Chief
Operating Officer
|
|
Michael
E. McMahon
|
|
53
|
|
Senior
Vice President, General Counsel and Secretary
|
|
Arthur
L. Rebell
|
|
68
|
|
Director,
Chairman of the Board
|
|
William
R. Cordes
|
|
60
|
|
Director
|
|
Thomas
E. Hyland
|
|
63
|
|
Director
|
|
Jonathan
E. Nathanson
|
|
47
|
|
Director
|
|
Mark
L. Shapiro
|
|
64
|
|
Director
|
|
Andrew
H. Tisch
|
|
59
|
|
Director
|
All directors have served since 2005
except for Mr. Cordes who was elected to the Board in October
2006. All directors serve until replaced or upon their voluntary
resignation.
Rolf A. Gafvert—Mr. Gafvert
has been the Chief Executive Officer of BGL since February 2007 and President
since February 2008. Prior thereto he had been the Co-President of BGL since its
inception in 2005. Mr. Gafvert has been the President of Gulf South since 2000
and has been employed by Gulf South or its predecessors since 1993. During that
time he also served in various management roles for affiliates of Gulf South,
including President of Koch Power, Inc., Managing Director of Koch Energy
International and Vice President of Corporate Development for Koch Energy, Inc.
Mr. Gafvert is on the Board of Directors of the Interstate Natural Gas
Association of America.
Jamie L. Buskill—Mr. Buskill
has been the Chief Financial Officer and Treasurer of BGL since its inception in
2005 and served in the same capacity for the predecessor of BGL since May 2003.
He has served in various management roles for Texas Gas since 1986. Mr. Buskill
is a member of the Southern Gas Association Accounting and Finance Committee and
serves on the board of various charitable organizations.
Brian A. Cody—In February
2009, Mr. Cody was appointed Chief Operating Officer of BGL. Prior to the
appointment, Mr. Cody had been the Chief Commercial Officer of BGL since March
2007. Mr. Cody has served in various management roles for Gulf South including:
Vice President of Business Development from 2006 to 2007, Chief Financial
Officer from 2005 to 2006, Vice President of Long-Term Marketing from 2003 to
2005 and Controller from 2000 to 2003. He has been employed by Gulf South or its
predecessors since 1987 and is a Certified Public Accountant.
Michael E. McMahon—Mr. McMahon
has been the Senior Vice President, General Counsel and Secretary of BGL since
February 2007. Prior thereto he served as Senior Vice President and General
Counsel of Gulf South since 2001. Mr. McMahon has been employed by Gulf South or
its predecessors since 1989. Mr. McMahon also serves on the legal committees of
Interstate Natural Gas Association of America and the American Gas
Association.
Arthur L. Rebell—Mr. Rebell is
a Senior Vice President at Loews. He has been employed by Loews in that capacity
since 1998 and has been primarily responsible for investments, corporate
strategy, mergers and acquisitions and corporate finance. Mr. Rebell also serves
as a director for Diamond Offshore Drilling, Inc., a subsidiary of
Loews.
William R. Cordes—Mr. Cordes
retired as President of Northern Border Pipeline Company in April 2007. Prior to
his retirement, he had worked in the natural gas industry for more than 35
years, including as Chief Executive Officer of Northern Border Partners, LP and
President of Northern Natural Gas Company and Transwestern Pipeline Company. Mr.
Cordes is also a member of the Board for the Kayne Anderson Energy Development
Fund. Mr. Cordes is currently a private investor.
Thomas E. Hyland—Mr. Hyland
was a partner in the global accounting firm of PricewaterhouseCoopers, LLP from
1980 until his retirement in July 2005. Mr. Hyland is currently a private
investor.
Jonathan E. Nathanson—Mr.
Nathanson is Vice President—Corporate Development of Loews. He has been employed
by Loews in that capacity since 2001 and is responsible for mergers and
acquisitions and corporate finance.
Mark L. Shapiro—Mr. Shapiro
has been a private investor since 1998. Mr. Shapiro also serves as a director
for W.R.Berkley Corporation.
Andrew H. Tisch—Mr. Tisch has
been Co-Chairman of the Board of Loews since January 2006 and is the Chairman of
the Executive Committee and a member of the Office of the President of Loews. He
has served as a director of Loews since 1985. Mr. Tisch also serves as a
director of CNA Financial Corporation, a subsidiary of Loews, and is Chairman of
the Board of K12 Inc.
Our
Independent Directors
Our Board has determined that Thomas E.
Hyland, Mark L. Shapiro and William R. Cordes are independent directors under
the listing standards of the New York Stock Exchange (NYSE). Our Board
considered all relevant facts and circumstances and applied the independence
guidelines described below in determining that none of these directors has any
material relationship with us, our management, our general partner or its
affiliates or our subsidiaries.
Our Board has established guidelines to
assist it in determining director independence. Under these guidelines, a
director would not be considered independent if any of the following
relationships exists:
|
(i)
|
during
the past three years the director has been an employee, or an immediate
family member has been an executive officer, of
us;
|
|
(ii)
|
the
director or an immediate family member received, during any twelve month
period within the past three years, more than $120,000 in direct
compensation from us, excluding director and committee fees, pension
payments and certain forms of deferred
compensation;
|
|
(iii)
|
the
director is a current partner or employee or an immediate family member is
a current partner of a firm that is our internal or external auditor, or
an immediate family member is a current employee of such a firm and
personally works on our audit, or, within the last three years, the
director or an immediate family member was a partner employee of such a
firm and personally worked on our audit within that
time;
|
|
(iv)
|
the
director or an immediate family member has at any time during the past
three years been employed as an executive officer of another company where
any of our present executive officers at the same time serves or served on
that company’s compensation committee;
or
|
|
(v)
|
the
director is a current employee, or an immediate family member is a current
executive officer, of a company that has made payments to, or received
payments from, us for property or services in an amount which, in any of
the last three years, exceeds the greater of $1.0 million, or 2% of the
other company’s consolidated gross
revenues.
|
Our Board has appointed an Audit
Committee comprised solely of independent directors. The NYSE does not require a
listed limited partnership, or a listed company that is majority-owned by
another listed company, such as us, to have a majority of independent directors
on its board of directors or to maintain a compensation or nominating/corporate
governance committee. In reliance on these exemptions, our Board is not
comprised of a majority of independent directors, and we do not maintain a
compensation or nominating/corporate governance committee.
Audit
Committee
Our Board’s Audit Committee presently
consists of Thomas E. Hyland, Chairman, Mark L. Shapiro and William R. Cordes,
each of whom is an independent director and satisfies the additional
independence and other requirements for Audit Committee members provided for in
the listing standards of the NYSE. The Board of Directors has determined that
Mr. Hyland qualifies as an “audit committee financial expert,” under Securities
and Exchange Commission (SEC) rules.
The primary function of the Audit
Committee is to assist our Board in fulfilling its responsibility to oversee
management’s conduct of our financial reporting process, including review of our
financial reports and other financial information, our system of internal
accounting controls, our compliance with legal and regulatory requirements, the
qualifications and independence of our independent registered public accounting
firm (independent auditors) and the performance of our internal audit function
and independent auditors. The Audit Committee has sole authority to appoint,
retain, compensate, evaluate and terminate our independent auditors and to
approve all engagement fees and terms for our independent auditors.
Conflicts
Committee
Under our partnership agreement, our
Board must have a Conflicts Committee consisting of two or more independent
directors. Our Conflicts Committee presently consists of Mark L. Shapiro,
Chairman, Thomas E. Hyland and William R. Cordes. The primary function of the
Conflicts Committee is to determine if the resolution of any conflict of
interest with our general partner or its affiliates is fair and reasonable. Any
matters approved by the Conflicts Committee will be conclusively deemed to be
fair and reasonable, approved by all of the partners and not a breach by our
general partner of any duties it may owe to our unitholders.
Executive
Sessions of Non-Management Directors
Our Board’s non-management directors,
from time to time as such directors deem necessary or appropriate, meet in
executive sessions without management participation. The Chairman of the Audit
Committee and the Chairman of the Conflicts Committee alternate serving as the
presiding director at these meetings.
Corporate
Governance Guidelines and Code of Conduct
Our Board has adopted Corporate
Governance Guidelines to guide it in its operation and a Code of Business
Conduct and Ethics applicable to all of the officers and directors of BGL,
including the principal executive officer, principal financial officer,
principal accounting officer, and all of the directors, officers and employees
of our subsidiaries. The Corporate Governance Guidelines and Code of Business
Conduct and Ethics can be found on our website. We intend to post changes to or
waivers of this Code for BGL’s principal executive officer, principal financial
officer and principal accounting officer on our website.
Section
16(a) Beneficial Ownership Reporting Compliance
Section 16 of the Exchange Act requires
our directors and executive officers, and persons who own more than 10% of a
registered class of our equity securities, to file initial reports of ownership
and reports of changes in ownership with the SEC. Such persons are required by
SEC regulation to furnish us with copies of all Section 16(a) forms they file.
Based solely on our review of the copies of such forms furnished to us and
written representations from our executive officers and directors, we believe
that all Section 16(a) filing requirements were met during 2008, in a timely
manner.
Compensation
Discussion and Analysis
Overview
The
objective of our executive compensation program is to attract and retain highly
qualified executive officers and motivate them to provide a high level of
performance for the Partnership and our unitholders, including maintaining
current levels of unitholder distributions and taking prudent steps to grow
unitholder distributions. To meet this objective we have established a
compensation policy for our executive officers which combines elements of base
salary and cash and equity-based incentive compensation, as well as retirement
and other benefits. We have selected these elements and otherwise structured our
executive compensation practices to align the interests of our executives with
those of our unitholders and our general partner, retain our executives and
appropriately reward their performance both in the long and short-term. At the
time of our initial public offering in 2005, we considered the executive
compensation programs of various companies engaged in similar businesses with
similar corporate structures in the initial development of our compensation
programs, particularly with regard to the development of our equity-based
compensation plans. We considered those programs to obtain a general
understanding of then-current compensation practices and industry trends. We
also considered the historical compensation policies and practices of our
operating subsidiaries, as well as applicable tax and accounting impacts of
executive compensation, including the tax implications of providing equity-based
compensation to our employees in light of our being a limited partnership. In
developing our compensation plans, no benchmarking of total compensation, or any
element of compensation, was performed against any particular reference group of
companies.
As
discussed elsewhere in this Report, our Board of Directors (Board) does not have
a Compensation Committee. Therefore, the compensation for Rolf Gafvert, our
Chief Executive Officer (CEO) (principal executive officer (PEO)), Jamie L.
Buskill, our Chief Financial Officer (CFO) (principal financial officer (PFO))
and our three other most highly compensated executive officers (together with
our former Senior Vice President of Operations, John C. Earley, Jr., who
resigned as an officer in conjunction with his termination of employment with
the Partnership in May 2008), our “Named Executive Officers,” is reviewed with
and is subject to the approval of our entire Board, with Mr. Gafvert not
participating in those Board discussions with respect to his own
compensation.
The
principal components of compensation for our Named Executive Officers
are:
|
·
|
annual
incentive compensation awards, including cash bonuses and grants of
phantom common units (Phantom Common Units) under our Long-Term Incentive
Plan (LTIP);
|
|
·
|
annual
grants of phantom general partner units (Phantom GP Units) under our
Strategic Long-Term Incentive Plan (SLTIP);
and
|
|
·
|
retirement,
medical and related benefits.
|
As
discussed in more detail below, in setting compensation policies and making
compensation decisions for our Named Executive Officers, our Board typically
considers certain financial measures, operating goals and progress made on key
projects. However, we do not rely on formula-driven plans when determining the
aggregate amount of compensation for each Named Executive Officer. Our Board
considers a number of factors in making its determinations of executive
compensation, including compensation paid in prior years, whether the financial
measures, operating goals and project progress were achieved and the individual
contributions of each executive to our overall business success for the year.
However, the final amount of any payout is discretionary, is based on judgment
and is not generated or calculated by reference to any particular performance
metric.
Base
Salary
Our
executive compensation policies emphasize the incentive-based compensation
elements discussed below. In determining the amount of base salary, the Board
generally takes into consideration the responsibilities of each Named Executive
Officer and determines compensation appropriate for the positions held and
services to be rendered during the year. In 2008, the base salary of Mr. Buskill
was increased approximately 30% reflecting his commitment to relocate his
primary office to Houston, Texas. The base salaries of our other Named Executive
Officers were increased modestly based on individual merit, in amounts ranging
from 1% to 7%. These increases were determined through discussions between Mr.
Gafvert and the Chairman of the Board, and were thereafter presented to and
approved by the Board.
Incentive Compensation –
Cash Bonuses and Phantom Common Unit Awards
Our
incentive compensation programs, and the compensation awarded under them, are
discretionary and are not formulaic in nature. In the context of performance and
past compensation policies and practices, the Board considers individual
performance factors that include the Board’s view of the performance of the
individual, the responsibilities of the individual’s position and the
individual’s contribution to the Partnership and to the financial and
operational performance for the most recently completed fiscal year. There is no
specific weighting given to each factor, but rather the Board considers and
balances these factors in its judgment and discretion.
Cash Bonuses. A significant
portion of the compensation of our Named Executive Officers consists of an
annual incentive compensation award, which is an aggregate dollar amount
determined by our Board that is paid in part as a cash bonus and in part as an
award of Phantom Common Units. In order to balance our goals of motivating our
Named Executive Officers to achieve long-term results for our unitholders and
providing them with appropriate current cash compensation, our general guideline
is to award approximately three-fourths of any annual incentive compensation as
a cash bonus and one-fourth as an award of Phantom Common Units, though the
Board retains discretion in making this determination.
At the
beginning of a year, the Board establishes, based upon a recommendation by the
CEO, a potential bonus pool for our employees as a whole, including the Named
Executive Officers. Certain financial or operating measures are established by
the Board to be used as guidelines in determining, at year end, the final amount
of the pool and individual bonus awards. These measures are not firm targets or
goals that must be achieved in order for payouts from the bonus pool to be made;
rather the Board considers these measures, based upon recommendations by the
CEO, in determining whether to adjust the size of the bonus pool at the end of
the year and in awarding individual payments from the pool. At the end of the
year, the CEO makes recommendations to the Board regarding the size of the final
bonus pool and amounts to pay Named Executive Officers and other employees,
taking into consideration actual results as compared to the measures set at the
beginning of the year, the individual performance and contributions to the
Partnership of each Named Executive Officer and other factors deemed relevant.
The amounts of the bonus pool and any individual awards are discretionary based
on the judgment of the CEO and the Board. Any bonus paid to the CEO is
determined by the Board based upon a similar review of his performance and
contributions.
For 2008,
the financial and operating measures that were established by the Board
were:
|
·
|
Achieving
2008 EBITDA, as defined in Item 6, Non-GAAP Financial
Measure, adjusted for expected unusual items, of $415.8 million and
annual distributions with respect to 2008 of $1.89 per
unit;
|
|
·
|
Operating
a safe, reliable pipeline system;
|
|
·
|
Timely
completion of our announced pipeline expansion projects within budget;
and
|
|
·
|
Contracting
the available capacity of our expansion projects and renegotiating or
replacing expiring contracts on our existing pipelines for longer terms
and at favorable rates.
|
For 2008,
the Board determined that we met most, but not all of our financial and
operational goals. For example, our Gulf Crossing Pipeline project and
Fayetteville and Greenville Laterals were not placed in service when initially
projected. In addition, certain executives who were employed by us at the
beginning of 2008 were no longer employed, and therefore not eligible for
incentive compensation, at the end of the year. As a result, the Board decided
to reduce the bonus pool from the target amount established at the beginning of
the year. In making that decision, our CEO and the Board considered the factors
listed above, with particular emphasis on the contributions made during the year
by the individual Named Executive Officers to the success of the expansion
projects we have undertaken, which are more fully described in Part I, Item I of
this Report. The amounts awarded to the Named Executive Officers are
set forth in the Summary Compensation Table below.
Phantom Common Unit
Awards. We are a limited partnership. If our Named
Executive Officers owned our units directly, they would be subject to
significant adverse individual tax consequences, such as being taxed on all
income as partners rather than employees. Furthermore, the ownership of units by
our executives would negatively impact the tax status of our benefit plans. As a
result, we award our executives equity-based compensation in the form of Phantom
Common Units. The economic value of these awards is directly tied to
the value of our common units, but these awards do not confer any rights of
ownership to the grantee. The value of a Phantom Common Unit is equal to the
value of a common unit plus accumulated distributions made on such common unit
since the award date. That value is paid to the executive by us in cash at the
end of a vesting period if the executive is still employed on the vesting date.
Our Board has discretion to determine the amount, vesting schedule and certain
other terms of awards under our LTIP.
The
number of Phantom Common Units awarded to a Named Executive Officer is
determined by dividing the dollar amount of such executive’s incentive based
compensation that has been allocated to such an award by the closing price of
our common units on the New York Stock Exchange (NYSE) on the date of grant. For
example, if an executive is awarded $250,000 of incentive compensation, of which
$60,000 is designated for an award of Phantom Common Units (the balance being
paid as a cash bonus), and the closing price of our common units on the NYSE on
the grant date is $30.00 per unit, the executive would be awarded 2,000 Phantom
Common Units for that year.
The
Phantom Common Units awarded to our Named Executive Officers vest 50% on the
second anniversary of the grant date and 50% on the third anniversary of the
grant date, and become payable in cash upon vesting. Since the value of the
Phantom Common Units is tied directly to the price of our common units, and the
amount of distributions made on those units during the vesting period, this
element of compensation directly aligns the interests of our Named Executive
Officers with those of our common unitholders and promotes
retention.
Phantom GP Units. Our Board
has also made awards of Phantom GP Units to our Named Executive Officers. These
awards give the grantee an economic interest in the performance of our general
partner, including our general partner’s incentive distribution rights, but do
not confer any right of ownership of our general partner to the grantee. Phantom
GP Units provide the holder with an opportunity, subject to vesting, to receive
a lump sum cash payment in an amount determined under a formula based on the
amount of cash distributions made by us to our general partner during the four
quarters preceding the vesting date and the implied yield on our common units,
up to a maximum of $50,000 per unit.
These
awards recognize and reward our Named Executive Officers based on our long-term
performance and encourage them to continue their employment with us since any
awards would be forfeited if the executive is not employed by us on the vesting
date. They also encourage our Named Executive Officers to carefully focus on
long-term returns to unitholders and our general partner when making management
decisions. The value of these awards is impacted by our performance,
the value of our common units and the distributions made to our general
partner. Therefore, these awards further align the interests of our
Named Executive Officers with those of our unitholders.
We
awarded an aggregate of 125 Phantom GP Units in December 2008, which vest in 4
years, to 21 of our key employees, of which 61 were awarded to our Named
Executive Officers. In making these awards, our Board considered each grantee’s
overall performance, with particular emphasis on the contributions made by the
individual executive to our expansion projects, among other strategic goals and
objectives.
Employee
Benefits
Each
Named Executive Officer participates in benefit programs available generally to
salaried employees of the operating subsidiary which employs such officer,
including health and welfare benefits and a qualified defined contribution
401(k) plan that includes a dollar-for-dollar match on elective deferrals of up
to 6% of eligible compensation within Internal Revenue Code (“IRC”)
requirements. Certain Named Executive Officers participate in a defined
contribution money purchase plan available to employees of Gulf South, while
others participate in a defined benefit cash balance pension plan available to
employees of Texas Gas hired prior to November 1, 2006, which includes a
non-qualified restoration plan for amounts earned in excess of IRC limits for
qualified retirement plans. Certain Named Executive Officers are also eligible
for retiree medical benefits after reaching age 55 as part of a plan offered to
Texas Gas employees.
Equity Ownership
Guidelines
As
discussed above, our executives would suffer significant negative tax
consequences by owning our units directly. As a result, we do not have a policy
or any guidelines regarding ownership of our equity by our management. We
therefore seek to align the interests of management with our unitholders by
granting the Phantom Common Units and Phantom GP Units.
All Other
Compensation
In 2008, Mr. Earley terminated his
employment with the Partnership. In connection with Mr. Earley’s resignation, we
agreed to pay a sum of $1,550,000 including $665,855 relating to our agreement
to accelerate the vesting of equity compensation benefits as consideration for
his covenants, waivers and releases as described in his separation agreement. In
addition, Mr. Earley entered into a consulting services agreement with us for a
period of six months beginning in May 2008, for which we
paid him $16,667 per month. There were no other material perquisites or personal
benefits paid to our Named Executive Officers.
Board
of Directors Report on Executive Compensation
In
fulfilling its responsibilities, our Board has reviewed and discussed the
Compensation Discussion and Analysis with our management. Based on
this review and discussion, the Board recommended that the
Compensation Discussion and Analysis be included in this annual report on
Form 10-K.
By the
members of the Board of Directors:
William
R. Cordes
Rolf
A. Gafvert
Thomas
E. Hyland
Jonathon
E. Nathanson
Arthur
L. Rebell, Chairman
Mark
L. Shapiro
Andrew
H. Tisch
Compensation
Committee Interlocks and Insider Participation
As
discussed above, our Board does not maintain a Compensation Committee. Our
entire Board performs the functions of such a committee. None of our
directors, except Mr. Gafvert, have been or are officers or employees of us
or our subsidiaries. Mr. Gafvert participates in deliberations of our Board
with regard to executive compensation generally, but does not participate in
deliberations or Board actions with respect to his own compensation. None of our
executive officers served as director or member of a compensation committee of
another entity that has or has had an executive officer who served as a member
of our Board during 2008, 2007 or 2006.
Executive
Compensation
Summary
of Executive Compensation
The following table shows a summary of
total compensation earned by our Named Executive Officers during 2008, 2007 and
2006:
Summary
Compensation Table for 2008
|
Name
and
Principal
Position
|
Year
|
|
Salary
|
|
|
Bonus
|
|
|
Stock
Awards
(1)
|
|
|
Change
in
Pension
Value
and
Nonqualified
Deferred Compensation Earnings
|
|
|
All
Other
Compensation
|
|
|
Total
|
|
|
Rolf
A. Gafvert, CEO (PEO)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
$ |
325,000 |
|
|
$ |
300,000 |
|
|
$ |
1,087,140 |
|
|
|
- |
|
|
$ |
33,589 |
(2) |
|
$ |
1,745,729 |
|
|
|
2007
|
|
|
323,365 |
|
|
|
300,000 |
|
|
|
857,917 |
|
|
|
- |
|
|
|
35,360 |
|
|
|
1,516,642 |
|
|
|
2006
|
|
|
240,000 |
|
|
|
300,000 |
|
|
|
296,386 |
|
|
|
- |
|
|
|
32,149 |
|
|
|
868,535 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Jamie
L. Buskill, CFO (PFO)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
292,500 |
|
|
|
150,000 |
|
|
|
461,116 |
|
|
$ |
43,464 |
(3) |
|
|
23,934 |
(4) |
|
|
971,014 |
|
|
|
2007
|
|
|
225,000 |
|
|
|
225,000 |
|
|
|
338,771 |
|
|
|
46,602 |
|
|
|
14,386 |
|
|
|
849,759 |
|
|
|
2006
|
|
|
225,000 |
|
|
|
100,000 |
|
|
|
113,207 |
|
|
|
40,333 |
|
|
|
14,292 |
|
|
|
492,832 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Brian
A. Cody, Chief Commercial Officer
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
240,000 |
|
|
|
200,000 |
|
|
|
496,770 |
|
|
|
- |
|
|
|
27,615 |
(5) |
|
|
964,385 |
|
|
|
2007
|
|
|
228,846 |
|
|
|
175,000 |
|
|
|
423,425 |
|
|
|
- |
|
|
|
23,107 |
|
|
|
850,378 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
John C. Earley, Jr., Senior VP of
Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
92,308 |
|
|
|
- |
|
|
|
153,543 |
|
|
|
- |
|
|
|
1,017,876 |
(6) |
|
|
1,263,727 |
|
|
|
2007
|
|
|
226,154 |
|
|
|
175,000 |
|
|
|
399,563 |
|
|
|
- |
|
|
|
23,681 |
|
|
|
824,398 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Michael
E. McMahon, Senior VP, General Counsel and Secretary
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
|
230,769 |
|
|
|
200,000 |
|
|
|
418,198 |
|
|
|
- |
|
|
|
20,666 |
(7) |
|
|
869,633 |
|
|
|
2007
|
|
|
216,346 |
|
|
|
125,000 |
|
|
|
356,833 |
|
|
|
- |
|
|
|
28,938 |
|
|
|
727,117 |
|
|
(1)
|
Represents
compensation expense accrued for 2008, 2007 and 2006 related to Phantom
Common Units and Phantom GP Units granted in 2008, 2007 and 2006. The
accruals were made pursuant to SFAS No. 123(R), Share Based Payments.
See the Grants of Plan-Based Awards table presented below for further
information.
|
|
(2)
|
Includes
matching contributions under 401(k) plan ($13,800), employer contributions
to the Gulf South Money Purchase Plan, imputed life insurance premiums,
club memberships, spouse travel, preferred parking and sporting event
tickets.
|
|
(3)
|
Includes
the change in qualified retirement plan account balance ($12,272) and
interest and pay credits for the supplemental retirement plan
($31,192).
|
|
(4)
|
Includes
matching contributions under 401(k) plan ($13,800), moving expenses,
imputed life insurance premiums and preferred
parking.
|
|
(5)
|
Includes
matching contributions under 401(k) plan ($13,050), employer contributions
to the Gulf South Money Purchase Plan, imputed life insurance premiums,
spouse travel, preferred parking and travel
clubs.
|
|
(6)
|
Mr.
Earley’s employment terminated on May 7, 2008. His other compensation
includes payment for covenant consideration in connection with his
separation from the Partnership ($884,145), payment for post-employment
consulting services ($100,000), matching contributions under 401(k) plan
($13,800), COBRA coverage, employer contributions to the Gulf South Money
Purchase Plan, spouse travel, imputed life insurance premiums and
preferred parking.
|
|
(7)
|
Includes
employer contributions to the Gulf South Money Purchase Plan, matching
contributions under 401(k) plan, imputed life insurance premiums, spouse
travel, preferred parking, sporting event tickets and travel
clubs.
|
The
following table sets forth the percentage of each Named Executive Officer’s
total compensation that we paid in the form of salary and bonus:
|
Named
Executive Officer
|
|
Year
|
|
Percentage
of Salary and Bonus Paid to Total Compensation
|
|
Rolf
A. Gafvert
|
|
2008
|
|
36%
|
|
|
|
2007
|
|
41%
|
|
|
|
2006
|
|
62%
|
|
Jamie
L. Buskill
|
|
2008
|
|
46%
|
|
|
|
2007
|
|
53%
|
|
|
|
2006
|
|
66%
|
|
Brian
A. Cody
|
|
2008
|
|
44%
|
|
|
|
2007
|
|
47%
|
|
John
C. Earley, Jr.
|
|
2008
|
|
7%
|
|
|
|
2007
|
|
49%
|
|
Michael
E. McMahon
|
|
2008
|
|
47%
|
|
|
|
2007
|
|
47%
|
Grants
of Plan-Based Awards
The following table displays
information regarding grants during 2008 to our Named Executive Officers of
plan-based awards, including Phantom GP Unit awards under our SLTIP and Phantom
Common Unit awards under our LTIP:
|
Grants
of Plan-Based Awards for 2008
|
|
|
Names
|
|
Grant
Date
|
|
|
All
Other Stock Awards: Number of Shares of Stock or Units
(1), (2)
(#)
|
|
|
All
Other Options Awards: Number of Securities Underlying Options
(#)
|
|
|
Exercise
or Base Price of Option Awards
($)
|
|
|
Grant
Date Fair Value of Stock
and
Option
Awards
(1),
(2)
($)
|
|
|
Rolf
A. Gafvert
|
|
12/16/08
|
|
|
|
8,740 |
|
|
|
-
|
|
|
|
- |
|
|
|
1,425,000 |
|
|
Jamie
L. Buskill
|
|
12/16/08
|
|
|
|
3,747 |
|
|
|
- |
|
|
|
- |
|
|
|
675,000 |
|
|
Brian
A. Cody
|
|
12/16/08
|
|
|
|
3,747 |
|
|
|
- |
|
|
|
- |
|
|
|
675,000 |
|
|
John
C. Earley, Jr.
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
166,812 |
(3) |
|
Michael
E. McMahon
|
|
12/16/08
|
|
|
|
2,502 |
|
|
|
- |
|
|
|
- |
|
|
|
650,000 |
|
|
(1)
|
On
July 24, 2006, our SLTIP became effective. The plan provides for the
issuance of up to 500 Phantom GP Units to our key employees. Each Phantom
GP Unit entitles the holder thereof, upon vesting, to a lump sum cash
payment in an amount determined by a formula based on cash distributions
made by us to our general partner during the four quarters preceding the
vesting date and the implied yield on our common units, up to a maximum of
$50,000 per unit. On December 16, 2008, Messrs. Gafvert, Buskill, Cody and
McMahon were awarded 25, 12, 12, and 12 Phantom GP Units that have a 4.0
year vesting period. The fair value of the awards was determined as of the
date of grant and will be remeasured each quarter until settlement in
accordance with the treatment of awards classified as liabilities
prescribed in SFAS No. 123(R). The fair value at grant date of the
December 16, 2008, grants was $50,000 per GP Phantom Unit. The fair value
of the awards will be recognized ratably over the vesting period. See
footnote (2) to the Outstanding Equity Awards at December 31, 2008, table
presented below. Note 10 in Item 8 of this Report contains more
information regarding our SLTIP.
|
|
(2)
|
On
December 16, 2008, Messrs. Gafvert, Buskill, Cody and McMahon were awarded
8,715, 3,735, 3,735 and 2,490 Phantom Common Units. The closing price of
our common units on the date of grant on the NYSE for 2008 was $20.08,
from which the fair value of the units was derived. Each such grant
includes a tandem grant of Distribution Equivalent Rights (DERs); vests
50% on the second anniversary of the grant date and 50% on the third
anniversary of the grant date; and will be payable to the grantee in cash
upon vesting in an amount equal to the sum of the fair market value of the
units (as defined in the plan) that vest on the vesting date plus the
vested amount then credited to the grantee’s DER account, less applicable
taxes. Note 10 in Item 8 of this Report contains more information
regarding our LTIP.
|
|
(3)
|
In
conjunction with Mr. Earley’s resignation, the vesting of equity
compensation benefits was accelerated. This amount represents the
incremental amount recognized in the financial statements in accordance
with SFAS No. 123(R) related to the accelerated
vesting.
|
Narrative
Disclosure to Summary Compensation Table and Grants of Plan-Based Awards
Table
For more
information about the components of compensation reported in the Summary
Compensation Table, please read the “Compensation Discussion and Analysis,”
above. We do not have employment agreements with any of our Named Executive
Officers.
Outstanding
Equity Awards at Fiscal Year-End
The table displayed below shows the
total number of outstanding equity awards in the form of Phantom Common Units
awarded under our LTIP and Phantom GP Units awarded under our SLTIP and held by
our Named Executive Officers at December 31, 2008:
|
Outstanding
Equity Awards at December 31, 2008
|
|
|
Stock
Awards
|
|
|
Name
|
|
|
Number
of Shares or Units of Stock that Have
Not
Vested
(1)
(#)
|
|
|
Market
Value of Shares or Units of Stock that Have not Vested
(2)(3)
($)
|
|
|
Equity
Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights
that Have Not Vested
(#)
|
|
|
Equity
Incentive Plan Awards: Market or Payout Value of Unearned Shares, Units or
Rights that Have Not Vested
($)
|
|
|
Rolf
A. Gafvert
|
LTIP
|
|
|
18,460 |
|
|
|
328,219 |
|
|
|
- |
|
|
|
- |
|
|
|
SLTIP
|
|
|
100 |
|
|
|
995,164 |
|
|
|
- |
|
|
|
- |
|
|
Jamie
L. Buskill
|
LTIP
|
|
|
4,337 |
|
|
|
77,112 |
|
|
|
- |
|
|
|
- |
|
|
|
SLTIP
|
|
|
46 |
|
|
|
452,679 |
|
|
|
- |
|
|
|
- |
|
|
Brian
A. Cody
|
LTIP
|
|
|
8,607 |
|
|
|
153,032 |
|
|
|
- |
|
|
|
- |
|
|
|
SLTIP
|
|
|
49 |
|
|
|
490,179 |
|
|
|
- |
|
|
|
- |
|
|
John
C. Earley, Jr. (4)
|
LTIP
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
SLTIP
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
Michael
E. McMahon
|
LTIP
|
|
|
7,362 |
|
|
|
130,896 |
|
|
|
- |
|
|
|
- |
|
|
|
SLTIP
|
|
|
43 |
|
|
|
411,607 |
|
|
|
- |
|
|
|
- |
|
|
(1)
|
On
December 16, 2008, Messrs. Gafvert, Buskill, Cody, and McMahon were
awarded grants of Phantom Common Units under our LTIP of 8,715, 3,735,
3,735 and 2,490 and Phantom GP Units under our SLTIP in the amount of
25, 12, 12, and 12. On December 14, 2007, Messrs. Gafvert, Buskill, Cody,
Earley and McMahon were awarded grants of Phantom Common Units under our
LTIP of 6,532, 0, 3,266, 3,266 and 3,266 and Phantom GP Units under our
SLTIP in the amount of 25, 12, 10, 9 and 12. On December 20, 2006, Messrs.
Gafvert and Buskill were awarded grants of Phantom Common Units under our
LTIP of 6,427 and 1,205 and Phantom GP Units under our SLTIP in the amount
of 25 and 10. On July 24, 2006, Messrs. Gafvert and Buskill were awarded
grants of Phantom GP Units under our SLTIP in the amount of 25 and 12.
Each grant of Phantom Common Units under our LTIP vests 50% on the second
anniversary of the grant date and 50% on the third anniversary of the
grant date. Each grant of Phantom GP Units under our SLTIP vests within 48
months of the grant date, with the exception of the July 2006 grants,
which vest within 42 months of the grant
date.
|
|
(2)
|
The
market value per unit reported in the above table is based on the NYSE
closing market price on December 31, 2008, of
$17.78.
|
|
(3)
|
In
addition to the Phantom Common Units, Messrs. Gafvert, Buskill, Cody and
McMahon have accumulated non-vested amounts related to the DER that are
tandem grants to the Phantom Common Units. Such DER amounts for Messrs.
Gafvert, Buskill, Cody, and McMahon were $23,798, $2,170, $11,897 and
$11,897 in 2008.
|
|
(4)
|
Due
to Mr. Earley’s resignation in May 2008, he did not have any unvested
Phantom Common Units awarded under our LTIP or Phantom GP Units awarded
under our SLTIP at December 31,
2008.
|
Option
Exercises and Stock Vested
The following table presents
information regarding the vesting during 2008 of Phantom Common Units and
Phantom GP Units previously granted to the Named Executive Officers. We have not
issued any awards in the form of options on our units to any employees,
including Named Executive Officers.
|
|
|
Option
Exercise and Stock Vested for 2008
|
|
|
|
|
Stock
Awards
(1)
|
|
|
Name
|
|
Number
of LTIP Shares Acquired on
Vesting
(#)
|
|
|
Value
Received on Vesting
($)
|
|
|
Number
of SLTIP Shares Acquired on
Vesting
(#)
|
|
|
Value
Received on Vesting
($)
|
|
|
Rolf
A. Gafvert
|
|
|
7,229 |
|
|
|
170,361 |
|
|
|
- |
|
|
|
- |
|
|
Jamie
L. Buskill
|
|
|
1,504 |
|
|
|
36,428 |
|
|
|
- |
|
|
|
- |
|
|
Brian
A. Cody
|
|
|
2,276 |
|
|
|
52,650 |
|
|
|
- |
|
|
|
- |
|
|
John
C. Earley, Jr. (2)
|
|
|
7,817 |
|
|
|
218,335 |
|
|
|
33 |
|
|
|
447,520 |
|
|
Michael
E. McMahon
|
|
|
2,276 |
|
|
|
52,650 |
|
|
|
- |
|
|
|
- |
|
|
(1)
|
All
vested awards were paid out as a lump sum cash payment and at no time were
units issued to or owned by the Named Executive
Officers.
|
|
(2)
|
Represents
amounts paid to Mr. Earley upon his resignation related to accelerated
vesting of Phantom Common Units and Phantom GP Units as consideration for
his covenants, waivers and
releases.
|
Pension
Benefits
The table displayed below shows the
present value of accumulated benefits for our Named Executive
Officers. Only employees of our Texas Gas subsidiary hired prior to
November 1, 2006, are eligible to receive the pension benefits discussed
below. Messrs. Gafvert, Cody and McMahon are, and during 2008 were,
employees of our Gulf South subsidiary and are not covered under any Texas Gas
benefit plans. Mr. Earley was also an employee of our Gulf South
subsidiary until his resignation in May 2008. Pension benefits
include both a qualified defined benefit cash balance plan and a non-qualified
defined benefit supplemental cash balance plan (SRP).
|
Pension
Benefits for 2008
|
|
|
Name
|
|
Plan
Name
|
|
Number
of Years Credited Service (#)
|
|
|
Present
Value of Accumulated Benefit
($)
|
|
|
Payments
During Last Fiscal Year
($)
|
|
|
Jamie
L. Buskill
|
|
TGRP
|
|
|
22.3 |
|
|
|
186,109 |
|
|
|
- |
|
|
|
|
SRP
|
|
|
22.3 |
|
|
|
65,485 |
|
|
|
- |
|
The Texas Gas Retirement Plan (TGRP) is
a qualified defined benefit cash balance plan that is eligible to all Texas Gas
employees hired prior to November 1, 2006. Participants in the plan vest after
five years of credited service. One year of vesting service is earned for each
calendar year in which a participant completes 1,000 hours of
service.
Eligible
compensation used in calculating the plan’s annual compensation credits include
total salary and bonus paid. The credit rate on all eligible compensation is
4.5% prior to age 30, 6.0% age 30 through 39, 8.0% age 40 through 49 and 10.0%
age 50 and older up to the Social Security Wage Base. Additional credit rates on
annual pay above Social Security Wage Base is 1.0%, 2.0%, 3.0% and 5.0% for the
same age categories. On April 1, 1998, the TGRP was converted to a cash balance
plan. Credited service up to March 31, 1998 is eligible for a past service
credit of 0.3%. Additionally, participants may qualify for an early retirement
subsidy if their combined age and service at March 31, 1998, totaled at least 55
points. The amount of the subsidy is dependent on the number of points and the
participant’s age of retirement. Upon retirement, the retiree may choose to
receive their benefit from a variety of payment options which include a single
life annuity, joint and survivor annuity options and a lump-sum cash payment.
Joint and survivor benefit elections serve to reduce the amount of the monthly
benefit payment paid during the retiree’s life but the monthly payments continue
for the life of the survivor after the death of the retiree. The TGRP has an
early retirement provision that allows vested employees to retire early at age
55.
The
credited years of service appearing in the table above are the same as actual
years of service. No payment was made to the Named Executive Officer during
2008. The present value of accumulated benefits payable to the Named Executive
Officer, including the number of years of service credited to the Named
Executive Officer, is determined using assumptions consistent with the
assumptions used for financial reporting. Interest will be credited to the cash
balance at December 31, 2008, commencing in 2009, using a quarterly compounding
up to the normal retirement date of age 65. Salary and bonus pay credits, up to
the IRC allowable limits, increase the accumulated cash balance in the year
earned. Credited interest rates used to determine the accumulated cash balance
at the normal retirement date as of December 31, 2008, 2007 and 2006 were 4.27%,
4.79% and 4.85% and for future years, 4.27%, 4.50% and 4.25%. The
future normal retirement date accumulated cash balance is then discounted using
an interest rate at December 31, 2008, 2007 and 2006 of 6.30%, 6.00% and 5.75%.
The increase in the present value of accumulated benefit for the TGRP between
December 31, 2008 and 2007 of $12,272 for Mr. Buskill is reported as
compensation in the Summary Compensation Table above.
The Texas Gas SRP is a non-qualified
defined benefit cash balance plan that provides supplemental retirement benefits
for participating employees for earnings that exceed the IRC compensation
limitations for qualified defined benefit plans. The SRP acts as a supplemental
plan, therefore the eligibility and retirement provisions, the form and timing
of distributions and the manner in which the present value of accumulated
benefits are calculated, are identical to the same provisions as described above
for the TGRP. The increase in the present value of accumulated benefit for the
SRP between years for Mr. Buskill is reported as compensation in the Summary
Compensation Table above.
Potential
Payments Upon Termination or Change of Control
We do not govern the Named Executive
Officer’s employment relationships with formal employment agreements, though
they are eligible to receive accelerated vesting of equity awards under certain
of our compensation plans. We have made grants of Phantom Common Units and
Phantom GP Units to each of our executives subject to specific vesting schedules
and payment limitations, as discussed above. Each of these equity
awards will vest immediately and become payable to the executive in cash upon
the occurrence of certain events, as described below. A termination
of employment may also trigger a distribution of retirement plan accounts from
the TGRP or the SRP. These plan distributions will be no more than
those amounts disclosed in the tables above, and such amounts will be paid only
once in accordance with the terms of the applicable plan; thus, the table below
does not include amounts attributable to the retirement plans disclosed
above.
Long-Term Incentive
Plan. The Phantom Common Units generally vest over a
three-year period; the first 50% will vest upon the second anniversary of the
grant date, while the remaining 50% will vest on the third anniversary of the
grant date. All unvested Phantom Common Units (and all DERs associated with such
Phantom Common Units) will become fully vested upon our “change of
control.” A “change of control” will be deemed to occur under our
LTIP upon one or more of the following events: (a) any person or group, other
than our general partner or its affiliates, becomes the owner of 50% or more of
our equity interests; (b) any person, other than Loews Corporation or its
affiliates, become our general partner; or (c) the sale or other disposition of
all or substantially all of our assets or our general partner’s assets to any
person that is not an affiliate of us or our general
partner. However, in the event that any award granted under our LTIP
is also subject to IRC section 409A, a “change of control” shall have the
definition of such term as found in the treasury regulations with respect to IRC
section 409A.
The
unvested Phantom Common Units (and all DERs associated with such Phantom Common
Units) will also become fully vested upon an executive’s death, disability,
retirement, or termination by us without cause. Our individual form
award agreements define a “disability” as an event that would entitle that
individual to benefits under either our or one of our affiliates’ long-term
disability plans. The award agreements define “retirement” as a
termination on or after age 65 other than for “cause” (as defined below) or a
termination of employment other than for cause, with the consent of our board of
directors, on or after the age of 60. “Cause” will first be defined
as such term is used in any applicable employment agreement between the
executive and us, and in the absence of such an employment agreement, as: (a) a
federal or state felony conviction; (b) dishonesty in the fulfillment of an
executive’s employment or engagement; (c) the executive’s willful and deliberate
failure to perform his employment duties in any material respect; or (d) any
other event that our board of directors, in good faith, determines to constitute
cause.
Strategic Long-Term Incentive
Plan. Phantom GP Units do not provide for distribution
rights as do the Phantom Common Units. Our SLTIP requires a minimum
distribution amount per unit to be met prior to any payment on a Phantom GP
Unit, otherwise the Phantom GP Unit will be forfeited without payment. Phantom
GP Unit payments may be made in amounts equal to the product of the “formula
value” of the units and the number of units held on the vesting
date. The “formula value” under the SLTIP means the lesser of (a) the
product of (1) the quotient of (i) cash distributions made to our general
partner during the four consecutive calendar quarters prior to the vesting date,
divided by (ii) the current yield on the units, multiplied by (2) .0001; or (b)
$50,000. As our general partner met its minimum distribution amount for the 2008
year, the Phantom GP Units held by our Named Executive Officers would be
eligible to receive accelerated vesting and payout upon certain
events.
All
unvested Phantom GP Units will become vested upon our general partner’s change
of control. The SLTIP defines a “Change of Control” as one or more of
the following events: (a) any person or group, other than our general partner’s
affiliates, becomes the owner of 50% or more of our general partner’s equity
interests; (b) any person, other than Loews Inc. or its affiliates, becomes the
general partner of our general partner; or (c) the sale or other disposition of
all or substantially all of our general partner’s, or the general partner of our
general partner’s, assets to any person that is not an affiliate of our general
partner or its general partner. As with the LTIP, if the Phantom GP Units are
subject to IRC section 409A, the Change of Control definition will be the
meaning of such term as found in the treasury regulations with respect to IRC
section 409A.
Unvested
Phantom GP Units will also vest upon a participant’s death, disability,
retirement, or a termination by our general partner other than for
cause. The SLTIP definition for each of these terms is substantially
similar to the definitions for the LTIP terms described above.
Texas Gas Severance
Plan. The Texas Gas Severance Plan was terminated on December
31, 2008. The potential payments that the Named Executive Officers were entitled
to receive under that plan are no longer available as of December 31,
2008.
PTO/Vacation. The Named
Executive Officers will receive the accrued vacation and paid time off that they
accumulated during the 2008 year, up to a three week maximum for employees of
Texas Gas and a one week maximum for Gulf South employees.
Potential
Payments Upon Termination or Change of Control Table
The
following table represents our estimate of the amount each of our Named
Executive Officers would have received upon the applicable termination or change
of control event, if such event had occurred on December 31, 2008. The closing
price of our common units on the NYSE on December 31, 2008, $17.78, was used to
calculate these amounts.
Mr.
Earley is not included in the following table due to his termination of
employment in May 2008. The actual compensation Mr. Earley received
for his employment service in the 2008 year is reported above in the Summary
Compensation Table.
|
Potential
Payments Upon Termination or Change of Control at December 31,
2008
|
|
|
Name
|
|
Plan
Name
|
|
Change
of Control
(1)
|
|
|
Termination
Other Than for Cause
|
|
|
Termination
for Cause, or Voluntary Resignation
|
|
|
Retirement
(2)
|
|
|
Death
or Disability
|
|
|
Rolf
A. Gafvert
|
|
LTIP
(3)
|
|
$ |
352,017 |
|
|
$ |
352,017 |
|
|
$ |
- |
|
|
$ |
352,017 |
|
|
$ |
352,017 |
|
|
|
|
SLTIP
(4)
|
|
|
1,178,583 |
|
|
|
1,178,583 |
|
|
|
- |
|
|
|
1,178,583 |
|
|
|
1,178,583 |
|
|
|
|
PTO/Vacation
(5)
|
|
|
6,250 |
|
|
|
6,250 |
|
|
$ |
6,250 |
|
|
|
6,250 |
|
|
|
6,250 |
|
|
|
|
Total
|
|
|
1,536,850 |
|
|
|
1,536,850 |
|
|
|
6,250 |
|
|
|
1,536,850 |
|
|
|
1,536,850 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Jamie
L. Buskill (6)
|
|
LTIP
(3)
|
|
|
79,282 |
|
|
|
79,282 |
|
|
|
- |
|
|
|
79,282 |
|
|
|
79,282 |
|
|
|
|
SLTIP
(4)
|
|
|
542,148 |
|
|
|
542,148 |
|
|
|
- |
|
|
|
542,148 |
|
|
|
542,148 |
|
|
|
|
PTO/Vacation
(5)
|
|
|
16,875 |
|
|
|
16,875 |
|
|
|
16,875 |
|
|
|
16,875 |
|
|
|
16,875 |
|
|
|
|
Total
|
|
|
638,305 |
|
|
|
638,305 |
|
|
|
16,875 |
|
|
|
638,305 |
|
|
|
638,305 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Brian
A. Cody
|
|
LTIP
(3)
|
|
|
164,930 |
|
|
|
164,930 |
|
|
|
- |
|
|
|
164,930 |
|
|
|
164,930 |
|
|
|
|
SLTIP
(4)
|
|
|
577,506 |
|
|
|
577,506 |
|
|
|
- |
|
|
|
577,506 |
|
|
|
577,506 |
|
|
|
|
PTO/Vacation
(5)
|
|
|
4,615 |
|
|
|
4,615 |
|
|
|
4,615 |
|
|
|
4,615 |
|
|
|
4,615 |
|
|
|
|
Total
|
|
|
747,051 |
|
|
|
747,051 |
|
|
|
4,615 |
|
|
|
747,051 |
|
|
|
747,051 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Michael
E. McMahon
|
|
LTIP
(3)
|
|
|
142,793 |
|
|
|
142,793 |
|
|
|
- |
|
|
|
142,793 |
|
|
|
142,793 |
|
|
|
|
SLTIP
(4)
|
|
|
506,791 |
|
|
|
506,791 |
|
|
|
- |
|
|
|
506,791 |
|
|
|
506,791 |
|
|
|
|
PTO/Vacation
(5)
|
|
|
4,438 |
|
|
|
4,438 |
|
|
|
4,438 |
|
|
|
4,438 |
|
|
|
4,438 |
|
|
|
|
Total
|
|
|
654,022 |
|
|
|
654,022 |
|
|
|
4,438 |
|
|
|
654,022 |
|
|
|
654,022 |
|
|
(1)
|
The
amounts listed under the “Change of Control” column will apply only in the
event that the Change of Control definition for that particular plan has
been triggered.
|
|
(2)
|
Retirement
age is defined under the LTIP and SLTIP as age 65 or older, although a
participant in the plan can become fully vested in outstanding awards at
age 60 with Board approval. Retirement of a participant prior to age 60
would result in the forfeiture of outstanding awards. As of December 31,
2008, none of the named executive officers were eligible for retirement as
defined in the LTIP and the SLTIP.
|
|
(3)
|
LTIP
amounts were determined by multiplying the number of unvested Phantom
Common Units each executive held on December 31, 2008, by the value of our
common units on that date, or $17.78. The resulting number was then added
to the value of the DERs that were associated with the accelerated Phantom
Common Units. As of December 31, 2008, Messrs. Gafvert,
Buskill, Cody and McMahon held Phantom Common Units of 18,460, 4,337,
8,607 and 7,362, respectively. The amount of DERs accrued for
these units were for Messrs. Gafvert, Buskill, Cody and McMahon, $23,798,
$2,170, $11,897 and $11,897,
respectively.
|
|
(4)
|
SLTIP
amounts were determined by multiplying the number of unvested Phantom GP
Units each executive held on December 31, 2008, by the value of each GP
unit on that date ($11,785.83) based upon full vesting of outstanding
awards and valued using the plan formula value assuming cash distributions
made by the Partnership to our general partner for the four consecutive
quarters ending on December 31, 2008, of $12.6 million and an implied
yield on our common units of 10.69% at December 31, 2008. As of
December 31, 2008, Messrs. Gafvert, Buskill, Cody and McMahon held 100,
46, 49, and 43 Phantom GP Units,
respectively.
|
|
(5)
|
Includes
earned but unused vacation at December 31,
2008.
|
|
(6)
|
Mr.
Buskill would also be entitled to receive payment under the SRP six months
after termination for any reason, which amounts are reported in the
Pension Benefits table above.
|
Director
Compensation
Each
director of BGL who is not an officer or employee of us, our subsidiaries, our
general partner or an affiliate of our general partner (an “Eligible Director”)
is paid an annual cash retainer of $43,750 ($50,000 for the chair of the Audit
Committee), payable in equal quarterly installments, $1,000 for each Board
meeting attended which is not a regularly scheduled meeting, and an annual grant
of 500 of our common units. Directors who are not Eligible Directors do not
receive compensation from us for their services as directors. All directors are
reimbursed for out-of-pocket expenses they incur in connection with attending
Board and committee meetings and will be fully indemnified by us for actions
associated with being a director to the extent permitted under Delaware law. The
following table displays information related to compensation paid to our
Eligible Directors for 2008:
|
Director
Compensation for 2008
|
|
|
Name
|
|
Fees
Earned or Paid in Cash
($)
|
|
|
Stock
Awards (1)
($)
|
|
|
Total
($)
|
|
|
William
R. Cordes
|
|
|
56,750 |
|
|
|
12,290 |
|
|
|
69,040 |
|
|
Thomas
E. Hyland (2)
|
|
|
65,000 |
|
|
|
12,290 |
|
|
|
77,290 |
|
|
Mark
L. Shapiro
|
|
|
56,750 |
|
|
|
12,290 |
|
|
|
69,040 |
|
|
(1)
|
On
March 26, 2008, Messrs. Cordes, Hyland and Shapiro were each granted 500
common units. The grant date fair value of each unit award,
based on the closing market price of $24.58, was
$12,290.
|
(2) Chair of the Audit
Committee.
The following table sets forth certain information, at February 13, 2009, as to
the beneficial ownership of our common and class B units by beneficial holders
of 5% or more of either such class of units, each member of our Board, each of
the Named Executive Officers and all of our executive officers and directors as
a group, based on data furnished by them. None of the parties listed in the
table have the right to acquire units within 60 days:
|
Name
of Beneficial Owner
|
|
Common
Units
Beneficially Owned
|
|
|
Percentage of
Common
Units
Beneficially Owned
(1)
|
|
|
Class
B
Units
Beneficially Owned
|
|
|
Percentage
of
Class
B Units Beneficially Owned
(1)
|
|
|
Percentage
of Total Limited Partner Units Beneficially Owned
|
|
|
Jamie L. Buskill
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
Brian A. Cody
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
William R. Cordes
|
|
|
1,000 |
|
|
|
* |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
Rolf A. Gafvert
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
Thomas E. Hyland
|
|
|
6,900 |
(2) |
|
|
* |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
Michael E. McMahon
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
Jonathan E. Nathanson
|
|
|
15,000 |
|
|
|
* |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
Arthur L. Rebell
|
|
|
39,083 |
(3) |
|
|
* |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
Mark L. Shapiro
|
|
|
11,500 |
|
|
|
* |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
Andrew H. Tisch
|
|
|
81,050 |
(4) |
|
|
* |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
All directors and executive
officers as
a group
|
|
|
154,533 |
|
|
|
* |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
BPHC (5)
|
|
|
107,534,609 |
|
|
|
69 |
% |
|
|
22,866,667 |
|
|
|
100 |
% |
|
|
73 |
% |
|
Loews Corporation (5)
|
|
|
107,534,609 |
|
|
|
69 |
% |
|
|
22,866,667 |
|
|
|
100 |
% |
|
|
73 |
% |
*Represents
less than 1% of the outstanding common units
|
(1)
|
As
of February 13, 2009, we had 154,934,609 common units and 22,866,667 class
B units issued and outstanding.
|
|
(2)
|
400
of these units are owned by Mr. Hyland’s
spouse.
|
|
(3)
|
32,984
of these units are owned by ARebell, LLC, a limited liability company
controlled by Mr. Rebell.
|
|
(4)
|
Represents
one quarter of the number of units owned by a general partnership in which
a one-quarter interest is held by a trust of which Mr. Tisch is managing
trustee.
|
|
(5)
|
Loews
Corporation is the parent company of BPHC and may, therefore, be deemed to
beneficially own the units held by BPHC. The address of BPHC is 9 Greenway
Plaza, Suite 2800, Houston, TX 77046. The address of Loews is 667 Madison
Avenue, New York, New York 10065. Boardwalk GP, an indirect, wholly-owned
subsidiary of BPHC, also holds the 2% general partner interest and all of
our incentive distribution rights. Including the general partner interest
but excluding the impact of the incentive distribution rights, Loews
indirectly owns approximately 74% of our total ownership interests. Our Partnership
Interests in Item 5 contains more information regarding our
calculation of BPHC’s equity
ownership.
|
Securities
Authorized for Issuance Under Equity Compensation Plans
In 2005,
our Board adopted the Boardwalk Pipeline Partners, LP Long-Term Incentive Plan.
The following table provides certain information as of December 31, 2008, with
respect to this plan:
|
Plan
category
|
|
Number
of securities to be issued upon exercise of outstanding options, warrants
and rights
|
|
Weighted-average
exercise price of outstanding options, warrants and
rights
|
|
Number
of securities remaining available for future issuance under equity
compensation plan (excluding securities reflected in the first
column)
|
|
Equity
compensation plans approved by security holders
|
|
-
|
|
N/A
|
|
-
|
|
|
|
|
|
|
|
|
|
Equity
compensation plans not approved by security holders
|
|
-
|
|
N/A
|
|
3,521,000
|
Note 10
in Item 8 of this Report contains more information regarding our equity
compensation plan.
It is our Board’s written policy that
any transaction, regardless of the size or amount involved, involving us or any
of our subsidiaries in which any related person had or will have a direct or
indirect material interest shall be reviewed by, and shall be subject to
approval or ratification by our Conflicts Committee. “Related person” means our
general partner and its directors and executive officers, holders of more than
5% of our units, and in each case, their “immediate family members,” including
any child, stepchild, parent, stepparent, spouse, sibling, mother-in-law,
father-in-law, son-in-law, daughter-in-law, brother-in-law, or sister-in-law,
and any person (other than a tenant or employee) sharing their household. In
order to effectuate this policy, our General Counsel reviews all such
transactions and reports thereon to the Conflicts Committee for its
consideration. Our General Counsel also determines whether any such transaction
presents a potential conflict of interest under our partnership agreement and,
if so, presents the transaction to our Conflicts Committee for its
consideration. In the event of a continuing service provided by a related
person, the transaction is initially approved by the Conflicts Committee but may
not be subject to subsequent approval. However, the Board approves the
Partnership’s annual operating budget which separately states the amounts
expected to be charged by related parties or affiliates for the following year.
No new service transactions were reviewed for approval by the Conflicts
Committee during 2008 nor were there any service transactions where the policy
was not followed.
In 2008,
we issued 22.9 million class B units and 21.2 million common units to BPHC
resulting in net proceeds of $1.2 billion. In conjunction with these
transactions, we also entered into a registration rights agreement with BPHC.
These transactions were subject to review and approval by our Board, including
separate approval by our Conflicts Committee. Distributions are approved by the
Board on a quarterly basis prior to declaration. Note 7 and Note 17 in Item 8 of
this Report contain more information regarding our related party
transactions.
See Item
10, Our Independent
Directors for information regarding director independence.
Audit
Fees and Services
The following table presents fees
billed by Deloitte & Touche LLP and its affiliates for professional services
rendered to us and our subsidiaries in 2008 and 2007 by category as described in
the notes to the table (in millions):
|
|
|
2008
|
|
|
2007
|
|
|
|
|
|
|
|
|
|
|
Audit
fees (1)
|
|
$ |
1.9 |
|
|
$ |
2.2 |
|
|
Audit
related fees (2)
|
|
|
0.5 |
|
|
|
0.5 |
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$ |
2.4 |
|
|
$ |
2.7 |
|
|
(1)
|
Includes
the aggregate fees and expenses for annual financial statement audit and
quarterly financial statement
reviews.
|
|
(2)
|
Includes
the aggregate fees and expenses for services that were reasonably related
to the performance of the financial statement audits or reviews described
above and not included under Audit fees above, including, principally,
consents and comfort letters and audits of employee benefits
plans.
|
Auditor
Engagement Pre-Approval Policy
In order to assure the continued independence of our independent auditor,
currently Deloitte & Touche LLP, the Audit Committee has adopted a policy
requiring its pre-approval of all audit and non-audit services performed for us
and our subsidiaries by the independent auditor. Under this policy, the Audit
Committee annually pre-approves certain limited, specified recurring services
which may be provided by Deloitte & Touche, subject to maximum dollar
limitations. All other engagements for services to be performed by Deloitte
& Touche must be specifically pre-approved by the Audit Committee, or a
designated committee member to whom this authority has been
delegated.
Since the formation of the Audit
Committee and its adoption of this policy in November 2005, the Audit Committee,
or a designated member, has pre-approved all engagements by us and our
subsidiaries for services of Deloitte & Touche, including the terms and fees
thereof, and the Audit Committee concluded that all such engagements were
compatible with the continued independence of Deloitte & Touche in serving
as our independent auditor.
(a)
1. Financial Statements
Included
in Item 8 of this report:
Reports
of Independent Registered Public Accounting Firm
Consolidated
Balance Sheets at December 31, 2008 and 2007
Consolidated
Statements of Income for the years ended December 31, 2008, 2007 and
2006
Consolidated
Statements of Cash Flows for the years ended December 31, 2008, 2007 and
2006
Consolidated
Statements of Changes in Partners’ Capital for the years ended December 31,
2008, 2007 and 2006
Consolidated
Statements of Comprehensive Income for the years ended December 31, 2008, 2007
and 2006
Notes to
Consolidated Financial Statements
(a)
2. Financial Statement Schedules
Valuation
and Qualifying Accounts
The
following table presents those accounts that have a reserve as of December 31,
2008, 2007 and 2006 and are not included in specific schedules herein. These
amounts have been deducted from the respective assets on the Consolidated
Balance Sheets (in millions):
|
Description
|
|
Balance
at Beginning of Period
|
|
|
Charged
to Costs and Expenses
|
|
|
Other
Additions (Recoveries)
|
|
|
Deductions
(Write-offs)
|
|
|
Balance
at End of Period
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allowance
for doubtful accounts:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
$ |
0.4 |
|
|
$ |
- |
|
|
$ |
(0.1 |
) |
|
$ |
- |
|
|
$ |
0.3 |
|
|
2007
|
|
|
2.6 |
|
|
|
2.7 |
|
|
|
(4.7 |
) |
|
|
(0.2 |
) |
|
|
0.4 |
|
|
2006
|
|
|
0.7 |
|
|
|
2.1 |
|
|
|
- |
|
|
|
(0.2 |
) |
|
|
2.6 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Inventory
obsolescence:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008
|
|
$ |
0.1 |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
(0.1 |
) |
|
$ |
- |
|
|
2007
|
|
|
- |
|
|
|
- |
|
|
|
0.1 |
|
|
|
- |
|
|
|
0.1 |
|
|
2006
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
(a)
3. Exhibits
The following documents are filed as
exhibits to this report:
|
Exhibit
Number
|
|
|
|
|
Description
|
|
|
|
|
|
3.1
|
|
Certificate
of Limited Partnership of Boardwalk Pipeline Partners, LP (Incorporated by
reference to Exhibit 3.1 to the Registrant’s Registration Statement on
Form S-1, Registration No. 333-127578, filed on August 16,
2005).
|
|
3.2
|
|
Third
Amended and Restated Agreement of Limited Partnership of Boardwalk
Pipeline Partners, LP dated as of June 17, 2008, (Incorporated by
reference to Exhibit 3.1 to the Registrant’s Current Report on Form 8-K
filed on June 18, 2008).
|
|
3.3
|
|
Certificate
of Limited Partnership of Boardwalk GP, LP (Incorporated by reference to
Exhibit 3.3 to the Registrant’s Registration Statement on Form S-1,
Registration No. 333-127578, filed on August 16, 2005).
|
|
3.4
|
|
Agreement
of Limited Partnership of Boardwalk GP, LP (Incorporated by reference to
Exhibit 3.4 to Amendment No. 1 to the Registrant’s Registration Statement
on Form S-1, Registration No. 333-127578, filed on September 22,
2005).
|
|
3.5
|
|
Certificate
of Formation of Boardwalk GP, LLC (Incorporated by reference to Exhibit
3.5 to the Registrant’s Registration Statement on Form S-1, Registration
No. 333-127578, filed on August 16, 2005).
|
|
3.6
|
|
Amended
and Restated Limited Liability Company Agreement of Boardwalk GP, LLC
(Incorporated by reference to Exhibit 3.6 to Amendment No. 4 to
Registrant’s Registration Statement on Form S-1, Registration No.
333-127578, filed on October 31, 2005).
|
|
4.1
|
|
Amended
and Restated Registration Rights Agreement dated November 4, 2008, by and
between Boardwalk Pipeline Partners, LP and Boardwalk Pipelines Holding
Corp. (Incorporated by reference to Exhibit 4.1 to the Registrant’s
Current Report on Form 8-K filed on November 4, 2008).
|
|
4.2
|
|
Indenture
dated July 15, 1997, between Texas Gas Transmission Corporation (now known
as Texas Gas Transmission, LLC) and The Bank of New York, as Trustee
(Incorporated by reference to Exhibit 4.1 to Texas Gas Transmission
Corporation’s Registration Statement on Form S-3, Registration No.
333-27359, filed on May 19, 1997).
|
|
4.3
|
|
Indenture
dated as of May 28, 2003, between TGT Pipeline, LLC and The Bank of New
York, as Trustee (Incorporated by reference to Exhibit 3.6 to TGT
Pipeline, LLC’s (now known as Boardwalk Pipelines, LP) Registration
Statement on Form S-4, Registration No. 333-108693, filed on September 11,
2003).
|
|
4.4
|
|
Indenture
dated as of May 28, 2003, between Texas Gas Transmission, LLC and The Bank
of New York, as Trustee (Incorporated by reference to Exhibit 3.5 to
Boardwalk Pipelines, LLC’s (now known as Boardwalk Pipelines, LP)
Registration Statement on Form S-4, Registration No. 333-108693, filed on
September 11, 2003).
|
|
4.5
|
|
Indenture
dated as of January 18, 2005, between TGT Pipeline, LLC and The Bank of
New York, as Trustee, (Incorporated by reference to Exhibit 10.1 to TGT
Pipeline, LLC’s (now known as Boardwalk Pipelines, LP) Current Report on
Form 8-K filed on January 24, 2005).
|
|
4.6
|
|
Indenture
dated as of January 18, 2005, between Gulf South Pipeline Company, LP and
The Bank of New York, as Trustee (Incorporated by reference to Exhibit
10.2 to Boardwalk Pipelines, LLC’s (now known as Boardwalk Pipelines, LP)
Current Report on Form 8-K filed on January 24, 2005).
|
|
4.7
|
|
Indenture
dated as of November 21, 2006, between Boardwalk Pipelines, LP, as issuer,
the Registrant, as guarantor, and The Bank of New York Trust Company,
N.A., as Trustee (Incorporated by reference to Exhibit 4.1 to the
Registrant’s Current Report on Form 8-K filed on November 22,
2006).
|
|
4.8
|
|
Indenture
dated August 17, 2007, between Gulf South Pipeline Company, LP and the
Bank of New York Trust Company, N.A. therein (Incorporated by reference to
Exhibit 4.1 to the Registrant’s Current Report on Form 8-K filed on August
17, 2007).
|
|
4.9
|
|
Indenture
dated August 17, 2007, between Gulf South Pipeline Company, LP and the
Bank of New York Trust Company, N.A. (Incorporated by reference to Exhibit
4.2 to the Registrant’s Current Report on Form 8-K filed on August 17,
2007).
|
|
4.10
|
|
Indenture
dated March 27, 2008, between Texas Gas Transmission, LLC and the Bank of
New York Trust Company, N.A. (Incorporated by reference to Exhibit 4.1 to
the Registrant’s Current Report on Form 8-K filed on March 27,
2008).
|
|
10.1
|
|
Amended
and Restated Revolving Credit Agreement, dated as of June 29, 2006, among
Boardwalk Pipelines, LP, Boardwalk Pipeline Partners, LP, the several
banks and other financial institutions or entities parties to the
agreement as lenders, the issuers party to the agreement, Wachovia Bank,
National Association, as administrative agent for the lenders and the
issuers, Citibank, N.A., as syndication agent, JPMorgan Chase Bank, N.A.,
Deutsche Bank Securities, Inc. and Union Bank of California, N.A., as
co-documentation agents, and Wachovia Capital Markets LLC and Citigroup
Global Markets Inc., as joint lead arrangers and joint book managers
(Incorporated by reference to Exhibit 10.1 to the Registrant’s Current
Report on Form 8-K filed on July 5, 2006).
|
|
10.2
|
|
Amendment
No. 1 to Amended and Restated Revolving Credit Agreement, dated as of
April 2, 2007, among the Registrant, Boardwalk Pipelines, LP, Texas Gas
Transmission, LLC and Gulf South Pipeline Company, LP, each a wholly-owned
subsidiary of the Registrant, as Borrowers, and the agent and lender
parties identified therein (Incorporated by reference to Exhibit 10.1 to
the Registrant’s Current Report on Form 8-K filed on April 5,
2007).
|
|
10.3
|
|
Amendment
No. 2 to Amended and Restated Revolving Credit Agreement, dated as of
November 27, 2007, among the Registrant, Boardwalk Pipelines, LP, Texas
Gas Transmission, LLC and Gulf South Pipeline Company, LP, and the agent
and lender parties identified therein (Incorporated by reference to
Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed on
November 29, 2007).
|
|
10.4
|
|
Amendment
No. 3 to Amended and Restated Revolving Credit Agreement, dated as of
March 6, 2008, among the Registrant, Boardwalk Pipelines, LP, Texas Gas
Transmission, LLC and Gulf South Pipeline Company, LP, and the agent and
lender parties identified therein. (Incorporated by reference to Exhibit
10.1 to the Registrant’s Quarterly Report on Form 10-Q filed on April 29,
2008).
|
|
**10.5
|
|
Separation
Agreement and General Release between John C. Earley, Jr. and Gulf South
Pipeline Company, LP, Gulf Crossing Pipeline Company LLC, Texas Gas
Transmission, LLC, Boardwalk GP, LLC and Boardwalk Operating GP, LLC.
(Incorporated by reference to Exhibit 10.2 to the Registrant’s Quarterly
Report on Form 10-Q filed on July 29,
2008).
|
|
10.6
|
|
Services
Agreement dated as of May 16, 2003, by and between Loews Corporation
and Texas Gas Transmission, LLC. (Incorporated by reference to Exhibit
10.8 to Amendment No. 3 to the Registrant’s Registration Statement on Form
S-1, Registration No. 333-127578, filed on October 24, 2005).
(1)
|
|
**10.7
|
|
Boardwalk
Pipeline Partners, LP Long-Term Incentive Plan (Incorporated by reference
to Exhibit 10.9 to Amendment No. 4 to the Registrant’s Registration
Statement on Form S-1, Registration No. 333-127578, filed on October 31,
2005).
|
|
**10.8
|
|
Form
of Phantom Unit Award Agreement under the Boardwalk Pipeline Partners, LP
Long-Term Incentive Plan (Incorporated by reference to Exhibit 10.10 to
the Registrant’s 2005 Annual Report on Form 10-K filed on March 16,
2006).
|
|
**10.9
|
|
Boardwalk
Pipeline Partners, LP Strategic Long-Term Incentive Plan (Incorporated by
reference to Exhibits 10.1 and 10.2 to the Registrant’s Current Report on
Form 8-K filed on July 28, 2006).
|
|
**10.10
|
|
Form
of GP Phantom Unit Award Agreement under the Boardwalk Pipeline Partners,
LP Strategic Long-Term Incentive Plan (Incorporated by reference to
Exhibits 10.1 and 10.2 to the Registrant’s Current Report on Form 8-K
filed on July 28, 2006).
|
|
**10.11
|
|
Separation
Agreement and General Release between H. Dean Jones II and Texas Gas
Transmission, LLC, Boardwalk GL, LLC, Boardwalk Pipelines Holding Corp.
and Boardwalk Operating GP, LLC. (Incorporated by reference to Exhibit
10.2 to the Registrant’s Quarterly Report on Form 10-Q filed on April 29,
2008).
|
|
10.12
|
|
Loan
Agreement, dated December 1, 2008, Mississippi Business Finance
Corporation and Gulf South Pipeline Company, LP (Incorporated by reference
to Exhibit 4.2 to the Registrant’s Current Report of Form 8-K filed on
December 9, 2008).
|
|
10.13
|
|
Bond
Purchase Agreement, dated December 1, 2008, among Boardwalk Pipelines, LP,
Mississippi Business Finance Corporation and Gulf South Pipeline Company,
LP (Incorporated by reference to Exhibit 10.1 to the Registrant’s Current
Report of Form 8-K filed on December 9, 2008).
|
|
*18.1
|
|
Preferability
letter, dated February 24, 2009, from Independent Registered Public
Accounting Firm.
|
|
*21.1
|
|
List
of Subsidiaries of the Registrant.
|
|
*23.0
|
|
Consent
Of Independent Registered Public Accounting Firm.
|
|
*31.1
|
|
Certification
of Rolf A. Gafvert, Chief Executive Officer, pursuant to Rule 13a-14(a)
and Rule 15d-14(a).
|
|
*31.2
|
|
Certification
of Jamie L. Buskill, Chief Financial Officer, pursuant to Rule 13a-14(a)
and Rule 15d-14(a).
|
|
*32.1
|
|
Certification
of Rolf A. Gafvert, Chief Executive Officer, pursuant to Section 906 of
the Sarbanes-Oxley Act of 2002.
|
|
*32.2
|
|
Certification
of Jamie L. Buskill, Chief Financial Officer, pursuant to Section 906 of
the Sarbanes-Oxley Act of 2002.
|
|
|
|
|
|
*
Filed herewith
**
Management contract or compensatory plan or arrangement
(1) The
Services Agreements between Gulf South Pipeline Company, LP and Loews
Corporation and between Boardwalk Pipelines, LP (formerly known as
Boardwalk Pipelines, LLC) and Loews Corporation are not filed because they
are identical to exhibit 10.9 except for the identities of Gulf South
Pipeline Company, LP and Boardwalk Pipelines, LLC and the date of the
agreement.
|
SIGNATURE
Pursuant to the requirements of Section
13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly
caused this report to be signed on its behalf by the undersigned, thereunto duly
authorized.
|
|
Boardwalk
Pipeline Partners, LP
|
|
|
|
|
|
|
|
|
|
By:
Boardwalk GP, LP
|
|
|
|
its
general partner
|
|
|
|
|
|
|
|
|
|
By:
Boardwalk GP, LLC
|
|
|
|
its
general partner
|
|
|
|
|
|
|
|
Dated: February 24, 2009
|
|
|
By:
|
/s/ Jamie L.
Buskill
|
|
|
|
|
|
Jamie
L. Buskill
|
|
|
|
|
|
Senior
Vice President, Chief Financial Officer and
Treasurer
|
Pursuant to the requirements of the Securities Exchange Act of 1934, this report
has been signed below by the following persons on behalf of the Registrant and
in the capacities and on the date indicated.
|
Dated: February 24, 2009
|
/s/ Rolf A.
Gafvert
|
|
|
|
Rolf
A. Gafvert
President,
Chief Executive Officer and Director
(principal
executive officer)
|
|
|
Dated: February 24, 2009
|
/s/ Jamie
L.
Buskill
|
|
|
|
Jamie
L. Buskill
Senior
Vice President, Chief Financial Officer and Treasurer
(principal
financial officer)
|
|
|
Dated: February 24, 2009
|
/s/ Steven A.
Barkauskas
|
|
|
|
Steven
A. Barkauskas
Vice
President, Controller and Chief Accounting Officer
(principal
accounting officer)
|
|
|
Dated: February 24, 2009
|
/s/ William R.
Cordes
|
|
|
|
William
R. Cordes
Director
|
|
|
Dated: February 24, 2009
|
/s/ Thomas E.
Hyland
|
|
|
|
Thomas
E. Hyland
Director
|
|
|
Dated: February 24, 2009
|
/s/ Jonathan E.
Nathanson
|
|
|
|
Jonathan
E. Nathanson
Director
|
|
|
Dated: February 24, 2009
|
/s/ Arthur
L.
Rebell
|
|
|
|
Arthur
L. Rebell
Director
|
|
|
Dated: February 24, 2009
|
/s/ Mark L.
Shapiro
|
|
|
|
Mark
L. Shapiro
Director
|
|
|
Dated: February 24, 2009
|
/s/ Andrew
H.
Tisch
|
|
|
|
Andrew
H. Tisch
Director
|
|