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, 2007
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. o
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, 2007 was approximately $1.1 billion. As
of February 15, 2008, the registrant had 90,656,122 common units
outstanding.
Documents
incorporated by reference. None.
TABLE
OF CONTENTS
2007
FORM 10-K
BOARDWALK
PIPELINE PARTNERS, LP
PART
I ...................................................................................................................................................................................................................................................................................................3
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Item
1. Business................................................................................................................................................................................................................................................................................3
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Item
1A. Risk
Factors....................................................................................................................................................................................................................................................................11
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Item
1B. Unresolved Staff
Comments..........................................................................................................................................................................................................................................26
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Item
2. Properties............................................................................................................................................................................................................................................................................26
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Item
3. Legal
Proceedings.............................................................................................................................................................................................................................................................26
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PART
II ................................................................................................................................................................................................................................................................................................27
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Item
6. Selected Financial
Data....................................................................................................................................................................................................................................................30
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Item
9A. Controls and
Procedures..............................................................................................................................................................................................................................................83
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Item
9B. Other
Information..........................................................................................................................................................................................................................................................83
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PART
III ..............................................................................................................................................................................................................................................................................................84
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Item
11. Executive
Compensation................................................................................................................................................................................................................................................87
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Item
14. Principal Accounting Fees and
Services...................................................................................................................................................................................................................99
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PART
IV ..........................................................................................................................................................................................................................................................................................101
Introduction
We
are a Delaware limited partnership formed in 2005 to own and operate the
business conducted by Boardwalk Pipelines, LP (Boardwalk Pipelines) and its
subsidiaries, Gulf South Pipeline Company, LP (Gulf South) and Texas Gas
Transmission, LLC (Texas Gas) (together, operating
subsidiaries). Boardwalk Pipelines Holding Corp. (BPHC), a
wholly-owned subsidiary of Loews Corporation (Loews), owns 53.3 million of our
common units and 33.1 million of our subordinated units, constituting
approximately 68.0% of our equity. Boardwalk GP, LP (Boardwalk GP),
an indirect, wholly-owned subsidiary of BPHC, is our general partner and holds a
2.0% general partner interest and all of our incentive distribution
rights. Our common units are traded under the symbol “BWP” on the New
York Stock Exchange (NYSE).
Our
Business
We are engaged in the interstate
transportation and storage of natural gas. We own and operate two
natural gas pipeline systems which we use to transport and store natural gas for
a broad mix of customers, including local distribution companies (LDCs),
municipalities, interstate and intrastate pipelines, direct industrial users,
electric power generation plants, marketers and producers. Our transportation
and storage rates and general terms and conditions of service (tariff) 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 our costs and earn a
reasonable return on equity, however there can be no assurance that we will
recover those costs or earn a reasonable return. Our firm and interruptible
storage rates for Gulf South are market-based pursuant to authority granted by
the 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) as well as other
charges based on actual utilization of the capacity. For the year
ended December 31, 2007, approximately 65.0% of our revenues were derived from
capacity reservation charges under firm contracts, approximately 17.0% of our
revenues were derived from other charges based on actual utilization under firm
contracts and approximately 18.0% of our revenues were derived from
interruptible transportation, interruptible storage, parking and lending (PAL)
and other services.
We are
currently undertaking several significant pipeline and storage expansion
projects.
Our
Pipeline and Storage Systems
Our operating subsidiaries own and
operate approximately 13,550 miles of pipeline, directly serving customers in
eleven states and indirectly serving customers throughout the northeastern and
southeastern United States through numerous interconnections with unaffiliated
pipelines. In 2007, our pipeline systems transported approximately 1.3 trillion
cubic feet (Tcf) of gas. Average daily throughput on our pipeline systems during
2007 was approximately 3.6 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 155.0
Bcf. We conduct all of our natural gas transportation and 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, Perryville, Louisiana area, Henry Hub in Louisiana, Agua Dulce and
Carthage, Texas. Carthage, Texas provides access to natural gas
supplies from the Bossier Sands and Barnett Shale gas producing regions in East
Texas. The Henry Hub serves as the designated delivery point for natural gas
futures contracts traded on the New York Mercantile Exchange (NYMEX). We also
access wellhead supplies in eastern Texas, northern and southern Louisiana and
Mississippi. We also have access to imported liquefied natural gas (LNG) through
the Lake Charles, Louisiana LNG terminal, to mid-continent gas production
through several third-party pipeline interconnects, and to Canadian natural gas
through a pipeline interconnect with Midwestern Gas Transmission Company at
Whitesville, Kentucky.
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 4.5 Bcf per day;
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30
compressor stations having an aggregate of approximately 253,600
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
numbers shown above include 242 miles of large diameter pipeline and one
compressor station from our East Texas to Mississippi expansion
project. See Expansion Projects for more information regarding the
East Texas to Mississippi expansion project.
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 United States.
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
5,850 miles of pipeline, having a peak-day delivery capacity of
approximately 3.8 Bcf per day which includes deliveries to pipeline
interconnects in South Louisiana;
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31
compressor stations having an aggregate of approximately 552,000
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 72.0 Bcf is designated as working
gas.
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The
numbers shown above include 9.0 Bcf of working gas capacity from Phase II of our
Western Kentucky storage expansion project. See Expansion Projects
for more information regarding the Western Kentucky storage expansion
project.
The direct market area for Texas Gas
encompasses eight states in the southern and midwestern United States 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 balancing needs on its system, to meet the operational requirements
of its firm and interruptible 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 substantially 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:
East Texas to Mississippi
Expansion. On June 18, 2007, the FERC granted us the authority
to construct, own and operate a pipeline expansion consisting of approximately
242 miles of 42-inch pipeline from DeSoto Parish in western Louisiana to near
Harrisville, Mississippi and approximately 110,000 horsepower of new
compression, having approximately 1.7 Bcf of new peak-day transmission
capacity. Customers have contracted at fixed rates for 1.4 Bcf per
day of firm transportation capacity on a long-term basis (with a weighted
average term of approximately 6.8 years) from Carthage, Texas, which represents
substantially all of the normal operating capacity. The pipeline
facilities from Keatchie, Louisiana in DeSoto Parish to interconnects with Texas
Gas near Bosco, Louisiana, and Columbia Gulf Transmission pipeline at Delhi,
Louisiana began flowing gas on December 31, 2007. The remaining
pipeline facilities from Delhi, Louisiana to Harrisville, Mississippi, began
flowing gas during January 2008. Currently, the three compressor
units at our Carthage compressor station are operational and we are making all
of our primary firm contractual deliveries into the Delhi, Louisiana area and a
substantial percentage of our primary firm contractual deliveries to markets in
Mississippi. We are in the process of commissioning the remaining
compression facilities associated with this project, which we expect to be
completed during the second quarter 2008.
Gulf Crossing Project. We are
pursuing construction of a new interstate pipeline that will begin near Sherman,
Texas and proceed to the Perryville, Louisiana area. The project will
be owned by Gulf Crossing Pipeline Company, LLC (Gulf Crossing), our newly
formed interstate pipeline subsidiary, and will consist of approximately 357
miles of 42-inch pipeline having up to approximately 1.7 Bcf of peak-day
transmission capacity. Additionally, Gulf Crossing has entered into,
subject to regulatory approval: (i) an operating lease for up to 1.4 Bcf per day
of capacity on our Gulf South pipeline system (including capacity on the
Southeast Expansion and capacity on a portion of the East Texas to Mississippi
Expansion) to make deliveries to an interconnect with Transcontinental Pipe Line
Company (Transco) in Choctaw County, Alabama (Transco 85); and (ii) an operating
lease with Enogex, a third-party intrastate pipeline, which will bring certain
gas supplies to our system. Customers have contracted at fixed rates
for 1.1 Bcf per day of long-term firm transportation capacity (with a weighted
average term of approximately 9.5 years). The certificate application
for this project was filed with the FERC on June 19, 2007, and we expect this
project to be in service by the first quarter 2009.
Southeast
Expansion. On September 28, 2007, the FERC granted us the
authority to construct, own and operate a pipeline expansion originating near
Harrisville, Mississippi and extending to an interconnect with Transco 85. This
expansion will initially consist of approximately 112 miles of 42-inch pipeline
having approximately 1.2 Bcf of peak-day transmission capacity. To
accommodate volumes expected to come from the Gulf Crossing leased capacity
discussed above, this project will be expanded to 2.2 Bcf of peak-day
transmission capacity. In addition, the FERC approved our 260 MMcf
per day operating lease with Destin Pipeline Company which will provide us
enhanced access to markets in Florida. Customers have contracted at
fixed rates for 660 MMcf per day of firm transportation capacity on a long-term
basis (with a weighted-average term of 8.7 years), in addition to the capacity
leased to Gulf Crossing discussed above. Construction has commenced
and we expect this project to be in service during the second quarter
2008.
Fayetteville and Greenville
Laterals. We are pursuing the construction of two
laterals connected to 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 and consist of approximately 165 miles of 36-inch pipeline
with an initial design of approximately 0.8 Bcf of peak-day transmission
capacity. 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 pipeline with an
initial design capacity of approximately 0.8 Bcf of peak-day transmission
capacity. The Greenville Lateral will allow customers to access
additional markets, primarily in the Midwest, Northeast and
Southeast. Customers have contracted at fixed rates for 575 MMcf per
day of initial capacity, with options for additional capacity that, if
exercised, could add 325 MMcf per day of capacity. The certificate
application for this project was filed with the FERC on July 11,
2007. We expect the first 60 miles of the Fayetteville Lateral to be
in service during the third quarter 2008 and the remainder of the Fayetteville
and Greenville Laterals to be in service during the first quarter
2009.
Pipeline Expansion Project Costs and
Timing. We currently estimate that the total cost of the
pipeline expansion projects discussed above will be approximately $4.5 billion,
of which approximately $2.0 billion was spent or committed to material that was
on order as of December 31, 2007. Our total estimated cost assumes
that we will receive the necessary regulatory approvals to commence construction
by June 1, 2008 on Gulf Crossing and the Fayetteville and Greenville Laterals
and that we will receive the regulatory approvals to operate the pipelines on
certain of our projects at higher pressures, which will allow us to utilize a
higher percentage of the pipeline capacity. Delays in receipt of any
of these approvals will result in higher costs and additional delays in our
expected in-service dates, which would also result in delays of revenues we
would have received had these delays not occurred, and in certain instances will
result in the payment of penalties to certain customers.
The
increase in our estimated total costs and delays reflects, among other things,
higher costs due to scope changes, adverse weather conditions, delays in the
receipt of regulatory approvals, and the effects of the strong demand for and
limited supply of qualified contractors, labor and materials and equipment which
has occurred as a result of the number of large, complex pipeline construction
projects being constructed in 2007 and 2008. These difficult market
conditions have resulted in higher contractor costs, higher costs for labor,
materials, construction equipment and other equipment and parts, as well as
shortages of skilled labor. These conditions are expected to persist
and it is possible that they could result in further cost increases and delays,
which could have a material adverse impact on our financial condition, results
of operations and cash flows.
Storage
Expansion Projects:
Western Kentucky Storage Expansion
Phase II. In December 2006, the FERC issued a certificate
approving the Phase II storage expansion project which expanded the working gas
capacity in our western Kentucky storage complex by approximately 9.0
Bcf. This project is supported by binding commitments from customers
to contract on a long-term basis (with a weighted-average term of 8.3 years) for
the full additional capacity at the Texas Gas maximum applicable
rate. The project was placed in service in November
2007.
Western Kentucky Storage Expansion
Phase III. We have signed 10-year precedent agreements for 5.1
Bcf of storage capacity for our Phase III storage project. The
certificate application for this project was filed with the FERC on June 25,
2007, seeking approval to develop up to 8.3 Bcf of new storage capacity if Texas
Gas is granted market-based rate authority for the new storage capacity being
proposed. The cost of this project will be dependent on the ultimate
size of the expansion. We expect 5.4 Bcf of storage capacity to be in
service in 2008.
Magnolia Storage Facility. 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 will be unable to place the cavern in service as
expected. As a result, we have elected to abandon that cavern and are
exploring the possibility of securing a new site on which a new cavern could be
developed.
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 firm 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 (including NNS) are generally
consistent during the contract term, but can be higher in winter peak periods,
especially related to NNS agreements, than off-peak periods. Firm
transportation contracts generally range in term from one to ten years, although
short-term firm transportation services can be offered for any term ranging from
one day to 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, and applicable injection and withdrawal fees. Generally, interruptible
storage agreements are for monthly terms. Unlike most FERC-regulated
pipelines, including Texas Gas, Gulf South is authorized to charge market-based
rates for its firm and interruptible storage services. Texas Gas
filed for the ability to charge market-based rates on capacity 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 and require a reservation of a specified amount
of storage and transportation capacity. Customers pay a reservation charge based
upon the capacity reserved plus a commodity and fuel charge based on the volume
of gas actually transported. NNS and SNS provide customers with additional
flexibility over traditional firm transportation and storage
services. 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 LDCs,
municipalities, intrastate and interstate pipelines, direct industrial users,
electric power generators, marketers and producers located throughout the Gulf
Coast, Midwest and Northeast regions of the United States. Customers
on our Gulf South system are located throughout its service area and elsewhere
or are accessed through numerous interconnects on unaffiliated pipeline systems.
In contrast, 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.
Based
upon 2007 revenues, our customer mix was comprised as follows: LDCs (32.0%),
pipeline interconnects (34.0%), storage (13.0%), industrial end-users (7.0%),
power plants (6.0%) and other (8.0%). We contract directly with end-use
customers and with marketers, producers and other third parties who provide
transportation and storage services to end users. One customer, Atmos
Energy accounted for approximately 10.0% of our 2007 operating
revenues.
LDCs. Most of our LDC
customers use firm transportation services, including NNS. These customers
operate under contracts having a weighted-average contract term of approximately
four years as of December 31, 2007. We serve approximately 190 LDCs located
across our pipeline systems. The demand of these customers peaks during the
winter heating season.
Pipeline Interconnects (off
system). Our pipeline systems serve as feeder pipelines for long-haul
interstate pipelines serving markets throughout the northeastern and
southeastern United States. We have numerous interconnects with third-party
interstate and intrastate pipelines.
Storage. We provide storage
services to a broad mix of customers including LDCs, marketers and producers.
Typically, LDCs use storage under their NNS contracts to manage winter gas
supplies, marketers and producers use storage to facilitate trading
opportunities, and producers also use storage to ensure their ability to produce
on a consistent basis.
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.
Power Plants. We 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.
Competition
We
compete with numerous intrastate and interstate 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 several new pipeline projects that
are under way, including the Rockies Express Pipeline that will transport
natural gas from northern Colorado to eastern Ohio; the Heartland Gas Pipeline
currently in operation in Indiana; the Southeast Header Supply System that is
currently being constructed and will transport gas from Perryville, Louisiana to
markets in Florida; and the proposed Mid-Continent Express Pipeline that would
transport gas from Texas to Alabama. The principal elements of
competition among pipelines are rates, terms of service, access to supply and
flexibility and reliability of service. 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. Our business is, in part, dependent on the
volumes of natural gas consumed in the United States. Our competitors
attempt to attract new supply to their pipelines including those that are
currently connected to markets served by us. We compete with these
entities to maintain current business levels and to serve new demand and
markets. Additionally, natural gas competes with other forms of
energy available to our customers, including electricity, coal, and fuel
oils.
Seasonality
Our
revenues are seasonal in nature and are affected by weather and natural gas
price volatility. Weather impacts natural gas demand for power generation and
heating purposes, which in turn influences the 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.
Natural gas prices are also volatile, influencing drilling and production which
can affect the value of our storage and PAL services. Peak demand for natural
gas occurs during the winter months, caused by the heating
load. During 2007, approximately 56.0% of our total operating
revenues were recognized in the first and fourth calendar quarters.
Government
Regulation
The FERC
regulates pipelines under the Natural Gas Act of 1938 (NGA) and the Natural Gas
Policy Act of 1978. The FERC regulates, among other things, the rates and
charges for the transportation and storage of natural gas in interstate
commerce, the extension, enlargement or abandonment of jurisdictional
facilities, and the financial accounting of certain regulated pipeline
companies. We are also regulated by the United States 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.
Where
required, our operating subsidiaries hold certificates of public convenience and
necessity issued by the FERC covering certain of their facilities, activities,
and services. The FERC also prescribes accounting treatment for
regulatory purposes. The books and records of the operating
subsidiaries may be periodically audited by the FERC.
The
maximum rates that may be charged by us for gas transportation and in the case
of Texas Gas, for storage services, are established through the FERC
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 on capital investments, 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 of our
operating subsidiaries has an obligation to file a new rate case.
Our
operations are also subject to extensive federal, state, and local laws and
regulations relating to protection of the environment. These laws include, for
example:
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(a)
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the
Clean Air Act and analogous state laws which impose obligations related to
air emissions;
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(b)
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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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(c)
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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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(d)
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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. 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, 2007, we had 1,084
employees, approximately 85 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 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 which covers Texas Gas employees
hired prior to November 1, 2006. Note 9 in Item 8 of this Report
contains further discussion of our employee benefits.
Available
Information
Our internet website is located at
www.bwpmlp.com. We
make available free of charge, through our website, our annual reports on Form
10-K, 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 reasonably practicable after 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 before investing in any securities
issued by us should be carefully considered and evaluated.
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 expansion projects, as
discussed above under Business – Expansion Projects, and we may also consider
additional expansion projects in the future. In pursuing these
projects, we have experienced significant cost overruns, including penalties to
contractors, and we may experience additional cost increases in the
future. We have also experienced construction delays and may
experience additional delays in the future. Delays in construction
have resulted in reduced transportation rates and liquidated damage payments to
customers, as well as lost revenue opportunities and could, in the future result
in similar losses or, in some cases, provide customers the right to terminate
their transportation agreements relating to the delayed project.
These
cost overruns and construction delays have resulted from a variety of factors,
including the following:
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delays
in obtaining regulatory approvals;
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adverse
weather conditions;
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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 terms, at the cost, or under the schedule that we
anticipate, or at all. In addition, we cannot be certain that, if
completed, these projects will perform in accordance with our expectations and
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. Any of these factors could materially adversely affect our
ability to realize the anticipated benefits from expansion projects which could
have a material adverse effect on our business, financial condition, results of
operations and cash flows. See also Item 1 – Expansion Projects.
Completion
of our expansion projects will require significant amounts of debt and equity
financing which may not be available to us on acceptable terms, or at
all.
We
plan to fund our expansion capital expenditures with proceeds from sales of our
debt and equity securities and borrowings under our revolving credit facility;
however, we cannot be certain that we will be able to issue our debt and equity
securities on terms or in the proportions that we expect, or at all,
particularly in light of the cost increases and construction delays we have
experienced to date on our expansion projects, current credit market disruptions
surrounding sub-prime residential mortgage concerns and the impact that those
factors and other events are having and may have on the public securities
markets generally and on the market for our securities in
particular. Future sales of our equity securities would be dilutive
to existing securityholders. A significant increase in our
indebtedness, or an increase in our indebtedness that is proportionately greater
than our issuances of equity, as well as the project cost increases and credit
market conditions discussed above could negatively impact our credit ratings or
our ability to remain in compliance with the financial covenants under our
revolving credit agreement which could have a material adverse effect on our
financial condition, results of operations and cash flows. If we are unable to
finance our expansion projects as expected, we could be required to seek
alternative financing, the terms of which may not be attractive to us, or to
revise or cancel our expansion plans.
Our
revolving credit agreement contains operating and financial covenants that
restrict our business and financing activities.
The operating and financial covenants
in our revolving credit agreement 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 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.
Our
natural gas transportation, gathering and storage operations are subject to
Federal Energy Regulatory Commission’s rate-making policies that could have an
adverse impact on our ability to establish rates that would allow us to recover
the full cost of operating our pipelines including a reasonable
return.
Action by
the FERC on currently pending matters as well as matters arising in the
future could adversely affect our ability to establish reasonable rates, or 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 cover current
costs, including a reasonable return. We cannot make assurances that
we will 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, financial
condition and results of operations.
In 2005, FERC established a policy
regarding the ability of a regulated entity to collect an allowance for income
taxes in its cost of service. Generally, FERC has stated it will
permit a pipeline that is a partnership (or other pass-through entity) to
include in its cost-of-service an income tax allowance to the extent that its
partners have an actual or potential income tax liability on the jurisdictional
income generated by the partnership (or other pass-through
entity). FERC will review pipelines’ ability to include such an
income tax allowance in their costs of service on a case-by-case basis, and the
burden is on the pipelines to show that it had such actual or potential income
tax liability. That policy has been further refined in 2006 and 2007
through a series of FERC orders and decisions issued by the United States Court
of Appeals for the District of Columbia Circuit. Most recently,
FERC’s income tax allowance policy was upheld on all issues subject to appeal by
the United States Court of Appeals for the District of Columbia Circuit in a
decision issued in May 2007. In December 2007, FERC issued an order
that again affirmed its income tax allowance policy and further clarified the
implementation of that policy. If the FERC were to change its income
tax allowance policy in the future, such changes could materially and adversely
impact the rates we are permitted to charge as future rates are approved for our
interstate transportation services.
In a
related interstate oil pipeline proceeding, FERC noted that the tax deferral
features of a publicly traded partnership may cause some investors to receive,
for some indeterminate duration, cash distributions in excess of their taxable
income, which FERC characterized as a “tax savings.” FERC stated a
concern that this creates an opportunity for those investors to earn an
additional equity return funded by ratepayers. Responding to this
concern, FERC adjusted the pipeline’s equity rate of return downward based on
the percentage by which the publicly traded partnership’s cash flow exceeded
taxable income assumed in the methodology for calculating the rate of
return. A rehearing request is pending before FERC on this
issue. If FERC establishes a policy of lowering a regulated entities’
equity rate of return to compensate for what it considers to be a “tax savings,”
it is also likely that the level of maximum lawful rates would decrease from
current levels.
If our subsidiaries were to file a rate
case or if we were to be required to defend our rates, we would be required to
establish pursuant to the income tax policy that the inclusion of an income tax
allowance in our cost of service was just and reasonable. To establish that our
income tax allowance is just and reasonable, our general partner may elect to
require owners of our units to recertify their status as being
subject to United States 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 that we will be able to provide (including the
information the general partner may require in the certification and
recertification process) will be sufficient to establish that its unitholders,
or its unitholders’ owners, are subject to United States federal income tax
liability on the income generated by our jurisdictional pipelines. If we are
unable to establish that our unitholders, or our unitholders’ owners, incur
actual or potential income tax liability on the income generated by our
jurisdictional pipelines, FERC could disallow a substantial portion of our
regulated pipelines’ income tax allowance. If FERC were to disallow a
substantial portion of our regulated pipelines’ income tax allowance, it is
likely that the level of maximum lawful rates would decrease from current
levels.
Our natural gas transportation and
storage operations are subject to extensive regulation by the FERC in addition
to the FERC rules and regulations related to the rates we can charge for our
services.
The FERC’s regulatory authority also
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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The
FERC’s action in any of these areas or modifications of its current regulations
can adversely impact our ability to compete for business, the costs we incur in
our operations, the construction of new facilities or our ability to recover the
full cost of operating our pipelines. Another example is the time the FERC takes
to approve the construction of new facilities, which could give our
non-regulated competitors time to offer alternative projects or raise the costs
of our projects to the point where they are no longer economical.
The FERC
has authority to review pipeline contracts. If the FERC determines that a term
of any such contract deviates in a material manner from a pipeline’s tariff, the
FERC typically will order the pipeline to remove the term from the contract and
execute and re-file a new contract with the FERC, or alternatively, amend its
tariff to include the deviating term, thereby offering it to all shippers. If
the FERC audits a pipeline’s contracts and finds material deviations that appear
to be unduly discriminatory, the FERC could conduct a formal enforcement
investigation, resulting in serious penalties and/or onerous ongoing compliance
obligations.
Should
we fail to comply with all applicable FERC administered statutes, rules,
regulations and orders, we could be subject to substantial penalties and fines.
Under the recently enacted Energy Policy Act of 2005, the FERC has civil penalty
authority under NGA to impose penalties for current violations of up to
$1,000,000 per day for each violation.
Finally,
we cannot give any assurance regarding the future regulations under which we
will operate our natural gas transportation and storage businesses, or the
effect such regulation could have on our financial condition, results of
operations and cash flows.
The
outcome of certain FERC proceedings involving FERC policy statements is
uncertain and could affect the level of return on equity that the Partnership
may be able to achieve in any future rate proceeding.
In an effort to provide some guidance
and to obtain further public comment on FERC’s policies concerning return on
equity determinations, on July 19, 2007, FERC issued its Proposed Proxy Policy
Statement, Composition of
Proxy Groups for Determining Gas and Oil Pipeline Return on
Equity. In the Proposed Proxy Policy Statement, FERC proposes
to permit inclusion of publicly traded partnerships in the proxy group analysis
relating to return on equity determinations in rate proceedings, provided that
the analysis be limited to actual publicly traded partnership distributions
capped at the level of the pipeline’s earnings and that evidence be provided in
the form of multiyear analysis of past earnings demonstrating a publicly traded
partnership’s ability to provide stable earnings over time.
In a
decision issued shortly after FERC issued its Proposed Proxy Policy Statement,
the D.C. Circuit vacated FERC’s orders in a proceeding involving High Island Offshore System
and Petal Gas
Storage. The Court determined that FERC had failed to
adequately reflect risks of interstate pipeline operations both in populating
the proxy group (from which a range of equity returns was determined) with
entities the record indicated had lower risk, while excluding publicly traded
partnerships primarily engaged in interstate pipeline operations, and in the
placement of the pipeline under review in each proceeding within that range of
equity returns. Although the Court accepted for the sake of argument
FERC’s rationale for excluding publicly traded partnerships from the proxy group
(i.e., publicly traded partnership distributions may exceed earnings) it
observed this proposition was “not self-evident.”
The
ultimate outcome of these proceedings is not certain and may result in new
policies being established at FERC that would not allow the full use of publicly
traded partnership distributions to unitholders in any proxy group comparisons
or other negative adjustments used to determine return on equity in future rate
proceedings. In addition, the FERC may adopt other policies or
institute other proceedings that could adversely affect our ability to achieve a
reasonable level of return on equity in any future rate proceeding.
Catastrophic
losses are unpredictable.
The nature and location of our
business, particularly with regard to our assets in the Gulf Coast region, may
make us susceptible to catastrophic losses especially from hurricanes or named
storms. Various other events can cause catastrophic losses, including
windstorms, earthquakes, hail, explosions, and severe winter weather and
fires. The frequency and severity of these events are inherently
unpredictable. The extent of losses from catastrophes is a function
of both the total amount of insured exposures in the affected areas and the
severity of the events themselves. Although
we carry insurance, in the event of a loss the coverage could be insufficient or
there could be a material delay in the receipt of the insurance
proceeds.
We
are subject to laws and regulations relating to the environment which may expose
us to significant costs, liabilities and loss of revenues.
The risk
of substantial environmental costs and liabilities is inherent in natural gas
transportation and storage. 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.
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. 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. For example, the federal government and several states have recently
proposed increased environmental regulation of many industrial activities,
including increased regulation of air quality, water quality and solid waste
management. In addition, government action to reduce greenhouse gas emissions
and other government actions that may have the effect of requiring or
encouraging reduced consumption or production of natural gas, could adversely
impact our business, financial condition, results of operations and cash
flows.
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. The steps we may be required to
take to bring certain of our facilities into compliance could be prohibitively
expensive and we may be required to shut down or alter the operation of those
facilities, which might cause us to incur losses. Further, 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. The costs of complying with environmental
regulation in the future could have a material adverse effect on our business,
financial condition, results of operations and cash flows.
Our operations are subject to
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, all of
which could cause substantial financial losses. 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 revenue
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 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. Moreover,
after Hurricanes Katrina and Rita, there can be no assurance that we will be
able to obtain the levels or types of insurance we would otherwise have obtained
prior to these market changes, or that the insurance coverage we do obtain will
not contain large deductibles or fail to cover certain hazards or all potential
losses. The occurrence of any operating risks not fully covered by
insurance could have a material adverse effect on our business, financial
condition, results of operations and cash flows.
Pipeline
safety integrity programs and repairs may impose significant costs and
liabilities on us.
The
United States DOT Pipeline and Hazardous Materials Safety Administration (PHMSA)
has issued a final rule requiring pipeline operators to develop integrity
management programs to comprehensively evaluate certain areas along their
pipelines and take additional measures to protect pipeline segments located in
what the rule refers to as high consequence areas (HCAs) where a leak or rupture
could potentially do the most harm.
Operators
are required to (1) perform ongoing assessments of pipeline integrity, (2)
identify and characterize applicable threats to pipeline segments that could
impact a HCA, (3) improve data collection, integration and analysis, (4) repair
and remediate the pipeline as necessary and (5) implement preventive and
mitigating actions. In compliance with the rule, we have initiated pipeline
integrity testing programs that are intended to assess pipeline integrity. At
this time, we cannot predict all of the effects this rule will have on us.
However, the rule 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. Should we
fail to comply with PHMSA rules and related regulations and orders, we could be
subject to penalties and fines.
We
are subject to strict regulations at many of our facilities regarding employee
safety.
The
workplaces associated with our pipelines are 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. The failure to comply with OSHA requirements or general industry
standards, keep adequate records or monitor occupational exposure to regulated
substances could have a material adverse effect on our business, financial
condition, results of operations and cash flows.
Increased
competition could have a significant financial impact on us.
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 way, including the Rockies Express Pipeline that will transport
natural gas from northern Colorado to eastern Ohio, the Heartland Gas Pipeline
currently in operation in Indiana, the proposed Mid-Continent Express Pipeline
that would transport gas from Texas to Alabama and the Southeast Header Supply
System that is under construction and will transport gas from Perryville,
Louisiana to markets in Florida. 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 rates, terms of
service, access to gas supplies, flexibility and reliability. The FERC’s
policies promoting competition in gas markets are having the effect of
increasing the gas transportation options for our traditional customer base.
Increased competition could reduce the volumes of gas transported by our
pipeline systems or, in cases where we do not have long-term fixed rate
contracts, could force us to lower our transportation or storage rates.
Competition could intensify the negative impact of factors that significantly
decrease demand for natural gas in the markets served by our pipeline systems,
such as competing or alternative forms of energy, a recession or other 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 the activities of our competitors. We also compete against a number
of intrastate pipelines which have significant regulatory advantages over us and
other interstate pipelines because of the absence of FERC regulation. In view of
potential rate increases, construction and service flexibility available to
intrastate pipelines, we may lose customers and throughput to intrastate
competitors. All of these competitive pressures could have a material adverse
effect on our business, financial condition, results of operations and cash
flows.
Because
of the natural decline in gas production from existing wells, our success
depends on our ability to obtain access to new sources of natural gas and this
is dependent on factors beyond our control. Any decrease in supplies of natural
gas in our supply areas could adversely affect our business and operating
results.
For the
years 2003 to 2006, gas production from the Gulf Coast region, which supplies
the majority of our throughput, has declined on average approximately 13.0% per
year according to the Energy Information Administration. A large part of this
decline was due to the effects of Hurricanes Katrina and Rita (hurricanes) in
2005. We cannot give any assurance regarding the gas production
industry’s ability to find new sources of domestic supply. Production from
existing wells and gas supply basins connected to our pipelines will naturally
decline over time, which means that our cash flows associated with the gathering
or transportation of gas from these wells and basins will also decline over
time. The amount of natural gas reserves underlying these wells may also be less
than we anticipate, or the rate at which production from these reserves declines
may be greater than we anticipate. Accordingly, to maintain or increase
throughput levels on our pipelines, we must continually obtain access to new
supplies of natural gas. The primary factors affecting our ability to obtain new
sources of natural gas to our pipelines include: (1) the level of successful
drilling activity near our pipelines, (2) our ability to compete for these
supplies, (3) the successful completion of new LNG facilities near our
pipelines, and (4) our gas quality requirements.
The level
of drilling activity is dependent on economic and business factors beyond our
control. The primary factor that impacts drilling decisions is the price of oil
and natural gas. A sustained decline in natural gas prices could result in a
decrease in exploration and development activities in the fields served by our
pipelines, which would lead to reduced throughput levels on our pipelines. Other
factors that impact production decisions include producers’ capital budget
limitations, the ability of producers to obtain necessary drilling and other
governmental permits, the availability and cost of drilling rigs and other
drilling equipment, and regulatory changes. Because of these factors, even if
new natural gas reserves were discovered in areas served by our pipelines,
producers may choose not to develop those reserves or may connect them to
different pipelines.
Imported
LNG is expected to be a significant component of future natural gas supply to
the United States. Much of this increase in LNG supply is expected to be
imported through new LNG facilities to be developed over the next decade. We
cannot predict which, if any, of these projects will be constructed. We
anticipate benefiting from some of these new projects and the additional gas
supply they will bring to the Gulf Coast region. If a significant number of
these new projects fail to be developed with their announced capacity, or there
are significant delays in such development, or if they are built in locations
where they are not connected to our systems or they do not influence sources of
supply on our systems, we may not realize expected increases in future natural
gas supply available for transportation through our systems.
If we are
not able to obtain new supplies of natural gas to replace the natural decline in
volumes from existing supply basins, or if the expected increase in natural gas
supply through imported LNG is not realized, throughput on our pipelines would
decline which could have a material adverse effect on our business, financial
condition, results of operations and cash flows.
Capacity
leaving our Lebanon, Ohio terminus is limited.
The
northeastern terminus of our Texas Gas pipeline system is in Lebanon, Ohio,
where it connects with other interstate natural gas pipelines delivering to East
Coast and Midwest metropolitan areas and other indirect markets. Pipeline
capacity into Lebanon is approximately 48.0% greater than pipeline capacity
leaving that point, creating a bottleneck for supply into areas of high demand.
As of December 31, 2007, approximately 13.0% of our long-term contracts with
firm deliveries to Lebanon will expire or have the ability to terminate by the
end of 2008. While demand for natural gas from our Lebanon, Ohio terminus and
other interconnects in that region has remained strong in the past, there can be
no assurance regarding continued demand for gas from the Gulf Coast region,
including East Texas, in the face of other sources of natural gas for our
various indirect markets, including pipelines from Canada, the anticipated
completion of the Rockies Express pipeline in late 2009 or early 2010, and new
LNG facilities proposed to be constructed along the East Coast.
Successful
development of LNG import terminals in the eastern United States could reduce
the demand for our services.
Development
of new, or expansion of existing, LNG facilities on the East Coast could reduce
the need for customers in the northeastern United States to transport natural
gas from the Gulf Coast and other supply basins connected to our pipelines. This
could reduce the amount of gas transported by our pipelines for delivery
off-system to other interstate pipelines serving the Northeast. If we are not
able to replace these volumes with volumes to other markets or other regions,
throughput on our pipelines would decline which could have a material adverse
effect on our financial condition, results of operations and cash
flows.
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,
2007, approximately 25.0% of the firm contract load on our pipeline systems,
excluding agreements related to the expansion projects, was due to expire on or
before December 31, 2008. 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 is the basis
differential, 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 basis differentials, or market price spreads between two points on
our pipelines;
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whether
our business strategy continues to be successful; and
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the effects of state regulation
on customer contracting
practices.
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Any failure to extend or replace a
significant portion of our existing contracts may have a material adverse effect
on our business, financial condition, results of operations and cash
flows.
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. For the
year ended December 31, 2007, Atmos Energy accounted for approximately 10.0% of
our total operating revenues. We may be unable to negotiate extensions or
replacements of these contracts and those with other 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 financial condition, results of operations and
cash flows, unless we are able to contract for comparable volumes from other
customers at favorable rates.
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, as well as volumes owed by customers for imbalances or
gas lent by us to them, generally under PAL and NNS services. If any
significant customer of ours should have credit or financial problems resulting
in a delay or failure to repay the gas they owe us, it could have a material
adverse effect on our financial condition, results of operations and cash
flows. Item 7A of this Report contains more information on credit
risk arising from gas loaned to customers.
If
third-party pipelines and other facilities interconnected 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 can deliver approximately 500 MMcf per
day to Texas Eastern at Kosciusko, Mississippi. 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 facility, lack of capacity or any
other reason, our ability to continue shipping natural gas to end markets could
be restricted, thereby reducing our revenues. Any temporary or permanent
interruption at any key pipeline interconnect which caused a material reduction
in volumes transported on our pipelines or stored at our facilities could have a
material adverse effect on our business, financial condition, results of
operations and cash flows.
Significant
changes in natural gas prices could affect supply and demand, reducing system
throughput and adversely affecting our revenues and available cash.
Higher
natural gas prices could result in a decline in the demand for natural gas, and
therefore, in the throughput on our pipelines. In addition, reduced price
volatility could reduce the revenues generated by our PAL and storage services
and could have a material adverse effect on our financial condition, results of
operations and cash flows.
In
general terms, the price of natural gas fluctuates in response to changes in
supply, changes in 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 and seasonal trends;
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levels
of domestic production and consumer demand;
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the
availability of LNG;
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a
material decrease in the price of natural gas could have an adverse effect
on the shippers who have contracted for capacity on our planned expansion
projects;
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the
availability of adequate transportation capacity;
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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 governmental regulation and taxation; and
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the
anticipated future prices of natural gas, LNG and other
commodities.
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We
do not own all of the land on which our pipelines and facilities are located,
which could disrupt our operations.
We do not
own all of the land on which our pipelines and facilities are located, and we
are, therefore, subject to the risk of increased costs to maintain necessary
land use. 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. Our loss of these rights, through our inability
to renew right-of-way contracts or otherwise, or increased costs to renew such
rights, could have a material adverse effect on our financial condition, results
of operations and cash flows.
Mergers
among our customers and/or competitors could result in lower volumes being
shipped on our pipelines, thereby reducing the amount of cash we
generate.
Mergers
among our existing customers and/or competitors could provide strong economic
incentives for the combined entities to utilize systems other than ours and we
could experience difficulty in replacing lost volumes and revenues. A
reduction in volumes would result not only in a reduction of revenues, but also
a decline in net income and cash flows of a similar magnitude, which could
reduce our ability to meet our financial obligations.
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 United States 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 energy assets, there is no assurance
that we can 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.
Our
general partner and its affiliates own a controlling interest in us and have
conflicts of interest and limited fiduciary duties, which may permit them to
favor their own interests.
At
December 31, 2007, 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 Loews.
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 Loews 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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Loews
and its affiliates may engage in competition with
us.
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Neither
our partnership agreement nor any other agreement requires Loews or its
affiliates (other than our general partner) to pursue a business strategy
that favors us. Directors and officers of Loews and its affiliates have a
fiduciary duty to make decisions in the best interest of Loews
shareholders, which may be contrary to our
interests.
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Our
general partner is allowed to take into account the interests of parties
other than us, such as Loews 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, while also restricting the remedies
available to our unitholders for actions that, without these limitations,
might constitute breaches of fiduciary duty. By purchasing common units,
unitholders are deemed to have consented 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 and the ability of the subordinated units
to convert to common units.
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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 a distribution on the subordinated units, to
make incentive distributions or to accelerate the expiration of the
subordination period.
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Our
general partner determines which costs, including allocated overhead,
incurred by it and its affiliates are reimbursable by
us.
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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 the FERC
for rate-making purposes and past business practices is deemed fair and
reasonable to us.
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Our
general partner intends to limit its liability regarding our contractual
obligations.
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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
80.0% of the outstanding common units or (2) all of our equity
securities (including common units) if it and its affiliates own more than
50.0% in the aggregate of the outstanding common units, subordinated 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.
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Our
general partner controls the enforcement of obligations owed to us by it
and its affiliates.
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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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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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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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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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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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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.
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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 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 the common units
depends largely on our being treated as a partnership 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 35.0%, 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 the common units.
Current
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 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. Members of Congress are considering
substantive changes to the existing U.S. tax laws that affect certain publicly
traded partnerships. Although the currently proposed legislation would not
appear to affect our tax treatment as a partnership, we are unable to
predict whether any of these changes, or other proposals, 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. Prior distributions to our unitholders in excess of the total net taxable
income our unitholders were allocated for a common unit, which decreased such
unitholders’ tax basis in that common unit, will, in effect, become taxable
income to such unitholders if the common unit is sold at a price greater than
the tax basis in that common unit, even if the price our unitholders receive is
less than their original cost. A substantial portion of the amount realized,
whether or not representing gain, may be ordinary income to our unitholders. In
addition, upon a unitholders’ sale of units, such unitholder may incur a tax
liability in excess of the amount of cash it receives 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 individual retirement accounts (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 United States 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 50.0% 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 eleven
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 and Gulf South are headquartered in
approximately 103,000 square feet of leased office space located in Houston,
Texas. Texas Gas has its headquarters in approximately 108,000 square feet of
office space in Owensboro, Kentucky in a building that it owns. Our
operating subsidiaries own their respective pipeline systems in fee. 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.
Item 1. “Our Business–Our
Pipeline and Storage Systems,” 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.
Market
Information
As of February 15, 2008, we had
90,656,122 common units outstanding held of record by approximately 36 holders.
BPHC owns 53,256,122 of our common units and all of our subordinated
units. 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 last reported sales price of our common
units on the NYSE on February 15, 2008 was $29.44 per unit.
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Sales
Price Range per Common Unit
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High
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Low
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Cash
Distributions per Unit
(a)
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Year
ended December 31, 2007:
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Fourth
quarter
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$ |
33.33 |
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$ |
29.76 |
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$ |
0.46 |
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Third
quarter
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|
37.79 |
|
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|
28.80 |
|
|
|
0.45 |
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Second
quarter
|
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|
37.46 |
|
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|
32.65 |
|
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|
0.44 |
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First
quarter
|
|
|
39.20 |
|
|
|
30.13 |
|
|
|
0.43 |
|
|
|
|
|
|
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|
|
|
|
|
|
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Year
ended December 31, 2006:
|
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|
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Fourth
quarter
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|
$ |
31.64 |
|
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$ |
25.25 |
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|
$ |
0.415 |
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Third
quarter
|
|
|
29.00 |
|
|
|
23.63 |
|
|
|
0.40 |
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Second
quarter
|
|
|
25.18 |
|
|
|
20.90 |
|
|
|
0.38 |
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First
quarter
|
|
|
22.00 |
|
|
|
17.98 |
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|
0.36 |
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(a)
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Represents
cash distributions attributable to the quarter and declared and paid to
common and subordinated unitholders within 60 days after quarter end. We
also paid cash distributions to our general partner with respect to its
2.0% 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.
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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, to unitholders 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
Incentive
distribution rights represent the right to receive an increasing percentage of
quarterly distributions of available cash from operating surplus after the
minimum quarterly distribution and the subsequent target distribution levels
have been achieved. Our general partner currently holds all of our incentive
distribution rights, but may transfer these rights separately from its general
partner interest, subject to restrictions in our partnership
agreement.
Assuming we do not issue any additional
classes of units and our general partner maintains its 2.0% interest, if we make
distributions to our unitholders from operating surplus in an amount equal to
the minimum quarterly distribution for any quarter, assuming no arrearages, then
we will distribute any additional available cash from operating surplus for that
quarter among the unitholders and our general partner as follows:
|
|
|
Total
Quarterly Distribution
|
|
Marginal Percentage Interest in
Distributions
|
|
Target
Amount
|
Common
and
Subordinated
Unitholders
|
|
General Partner
|
|
Minimum
Quarterly Distribution
|
|
$0.3500
|
|
98.0%
|
|
2.0%
|
|
First
Target Distribution
|
|
up to $0.4025
|
|
98.0%
|
|
2.0%
|
|
Second
Target Distribution
|
|
above $0.4025 up to $0.4375
|
|
85.0%
|
|
15.0%
|
|
Third
Target Distribution
|
|
above
$0.4375 up to $0.5250
|
|
75.0%
|
|
25.0%
|
|
Thereafter
|
|
above
$0.5250
|
|
50.0%
|
|
50.0%
|
Subordination
Period
During
the subordination period, holders of our common units will have the right to
receive distributions of available cash from operating surplus in an amount
equal to $0.35 per unit per quarter, which we refer to as the “minimum quarterly
distribution,” plus any arrearages, before any distributions of available cash
from operating surplus may be made on the subordinated units. No arrearages will
be paid on the subordinated units. Assuming there are no arrearages
in payment of the minimum quarterly distribution, the subordination period will
end, and all subordinated units will convert to common units, at such time as we
have made distributions from operating surplus on the common and subordinated
units at least equal to the minimum quarterly distribution for each of the
immediately preceding three consecutive, non-overlapping four-quarter periods;
provided also that the “adjusted operating surplus” (as defined in our
partnership agreement) generated during such periods equaled or exceeded the sum
of the minimum quarterly distributions on all of our units during such periods.
Alternatively, assuming there are no arrearages, the subordination period will
end at such time as we have made distributions from operating surplus on the
common and subordinated units at least equal to 150.0% of the minimum quarterly
distribution for the immediately preceding four-quarter period; provided also
that the adjusted operating surplus generated during such period equaled or
exceeded 150.0% of the minimum quarterly distributions on all of our units
during such period. The subordination period will also end, and each
subordinated unit will convert into one common unit, if unitholders remove our
general partner other than for cause and no units held by our general partner
and its affiliates are voted in favor of such removal. We have made
distributions from operating surplus on our common and subordinated units in
excess of the minimum quarterly distribution for the previous two consecutive,
non-overlapping four-quarter periods preceding the date of this
Report.
For
information about our equity compensation, please see Part III, Item 12 –
“Securities Authorized for Issuance under Equity Compensation
Plans.”
Common
Unit Repurchases
On February 27, 2007, our general
partner purchased 1,500 of our common units in the open market at a price of
$36.61 per unit. These units were granted to our independent
directors on March 5, 2007, as part of their director
compensation. For information about our director compensation, please
see Part III, Item 11 – “Director Compensation.”
The
following table presents summary historical financial and operating data for us
and our predecessors, Boardwalk Pipelines and Texas Gas, 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. Boardwalk Pipelines was formed in April 2003 to
acquire all of the outstanding capital stock of Texas Gas, the acquisition of
which was completed on May 16, 2003 (the
TG-Acquisition). Boardwalk Pipelines had no assets or operations
prior to the TG-Acquisition; therefore, we refer to Texas Gas as their
predecessor.
The
TG-Acquisition was accounted for using the purchase method of accounting and,
accordingly, the post-acquisition financial information included below reflects
the allocation of the purchase price resulting from the acquisition. As a
result, the financial statements of Texas Gas for the periods prior to
May 16, 2003 are not directly comparable to our financial statements
subsequent to that date. The consolidated financial and operating data shown
below have been separated by a bold black line delineating our predecessor’s
financial data from ours.
The
acquisition of Gulf South by Boardwalk Pipelines in December 2004 was also
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 ended December 31, 2004,
and prior periods are not readily comparable with our results of operations for
the years ended December 31, 2007, 2006 and 2005.
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
and charge-in-lieu of 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 United States of America (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 thousands, except Earnings per common and
subordinated unit):
|
|
|
Boardwalk
Pipeline Partners, LP
|
|
|
Predecessor
|
|
|
|
|
|
|
|
For
the Period May 17, 2003 through
December
31,
2003
|
|
|
For
the Period
January 1, 2003
through
May
16,
2003
|
|
|
|
|
|
|
For
the Year Ended December 31,
|
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
Total
operating revenues
|
|
$ |
643,268 |
|
|
$ |
607,642 |
|
|
$ |
560,466 |
|
|
$ |
263,621 |
|
|
$ |
142,860 |
|
|
$ |
113,447 |
|
|
Net
income
|
|
|
227,756 |
|
|
|
197,550 |
|
|
|
100,925 |
|
|
|
48,825 |
|
|
|
22,451 |
|
|
|
34,474 |
|
|
Total
assets
|
|
|
4,157,306 |
|
|
|
2,951,299 |
|
|
|
2,465,491 |
|
|
|
2,472,140 |
|
|
|
1,238,627 |
|
|
|
N/A |
|
|
Long-term
debt
|
|
|
1,847,914 |
|
|
|
1,350,920 |
|
|
|
1,101,290 |
|
|
|
1,106,135 |
|
|
|
548,115 |
|
|
|
N/A |
|
|
Earnings
per common and
subordinated
unit
|
|
$ |
1.87 |
|
|
$ |
1.85 |
|
|
|
* |
|
|
|
N/A |
|
|
|
N/A |
|
|
|
N/A |
|
|
EBITDA**
|
|
$ |
349,839 |
|
|
$ |
331,468 |
|
|
$ |
289,002 |
|
|
$ |
144,489 |
|
|
$ |
77,241 |
|
|
$ |
78,380 |
|
* Our net
income was $35,992, or $0.35 per common and subordinated unit, for the period
from November 15, 2005, the closing date of our IPO, through December 31,
2005.
**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 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 the most directly comparable GAAP financial
measures, on a historical basis, as applicable, for each of the periods
presented below (in thousands):
|
|
|
Boardwalk
Pipeline Partners, LP
|
|
|
Predecessor
|
|
|
|
|
For
the Year Ended December 31,
|
|
|
For
the Period
May
17, 2003
through
December 31,
|
|
|
For
the Period January 1, 2003 through
May
16,
|
|
|
|
|
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
2004
|
|
|
2003
|
|
|
2003
|
|
|
Net
income
|
|
$ |
227,756 |
|
|
$ |
197,550 |
|
|
$ |
100,925 |
|
|
$ |
48,825 |
|
|
$ |
22,451 |
|
|
$ |
34,474 |
|
|
Income
taxes and charge-in-lieu
of income
taxes
|
|
|
769 |
|
|
|
253 |
|
|
|
49,494 |
|
|
|
32,333 |
|
|
|
15,104 |
|
|
|
22,387 |
|
|
Elimination
of cumulative
deferred
taxes
|
|
|
- |
|
|
|
- |
|
|
|
10,102 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
Depreciation
and amortization
|
|
|
81,824 |
|
|
|
75,771 |
|
|
|
72,078 |
|
|
|
33,977 |
|
|
|
20,544 |
|
|
|
16,092 |
|
|
Interest
expense
|
|
|
61,023 |
|
|
|
62,123 |
|
|
|
60,067 |
|
|
|
30,081 |
|
|
|
19,368 |
|
|
|
7,392 |
|
|
Interest
income
|
|
|
(21,489 |
) |
|
|
(4,202 |
) |
|
|
(1,478 |
) |
|
|
(352 |
) |
|
|
(205 |
) |
|
|
- |
|
|
Interest
income from affiliates, net
|
|
|
(44 |
) |
|
|
(27 |
) |
|
|
(2,186 |
) |
|
|
(375 |
) |
|
|
(21 |
) |
|
|
(1,965 |
) |
|
EBITDA
|
|
$ |
349,839 |
|
|
$ |
331,468 |
|
|
$ |
289,002 |
|
|
$ |
144,489 |
|
|
$ |
77,241 |
|
|
$ |
78,380 |
|
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
We are a Delaware limited partnership
formed to own and operate the business conducted by our operating subsidiaries,
including the interstate transportation and storage of natural
gas. We own and operate pipeline systems in the Gulf Coast states of
Texas, Louisiana, Mississippi, Alabama, and Florida and which extend
northeasterly through Arkansas to the Midwestern states of Tennessee, Kentucky,
Illinois, Indiana, and Ohio.
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 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, 2007, the percentage of our Total operating revenues
associated with firm contracts was approximately 81.7%.
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 does affect our results of operations. We deliver
to a broad mix of customers including LDCs, municipalities, interstate and
intrastate pipelines, direct industrial users, electric power generation plants,
marketers and producers. In addition to serving directly connected
markets, our pipeline systems have indirect market access to the northeastern
and southeastern United States through interconnections with unaffiliated
pipelines.
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 affects our
transportation revenues, and spreads in natural gas prices across time (for
example summer to winter), which primarily affects our PAL and storage
revenues. High natural gas prices in recent years have helped to
drive increased production levels in producing locations such as the Bossier
Sands and Barnett Shale gas producing regions in East Texas, which has resulted
in additional supply being available on the west side of our
system. This has resulted in widened west-to-east basis differentials
which 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 being undertaken by
us. Wide spreads in natural gas prices between time periods during
the past two to three years, for example fall 2006 to spring 2007, were
favorable for our PAL and interruptible storage services during that
period. These spreads decreased substantially in 2007, which resulted
in reduced PAL and interruptible storage revenues. We cannot predict
future time period spreads or basis differentials.
Critical
Accounting Policies and Estimates
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.
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 contractual participation rights which are incentive
distribution rights in accordance with the partnership agreement 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, 2007 and 2006, were adjusted to take into account an
assumed incremental allocation to the general partner's incentive distribution
rights. Payments made on account of the incentive distribution rights are
determined in relation to actual declared distributions.
Regulation
Under
the FERC’s 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 considering regulatory
proceedings, advice of counsel and estimated risk-adjusted total exposure, as
well as other factors. At December 31, 2007 and 2006, there were no
liabilities for any open rate case recorded on our Consolidated Balance
Sheets. Currently, neither of our operating subsidiaries is involved
in an open general rate case.
SFAS No. 71, Accounting for the Effects of
Certain Types of Regulation, requires rate-regulated public utilities to
account for and report assets and liabilities consistent with the economic
effect of the manner in which independent third-party regulators establish
rates. In applying SFAS No. 71, Texas Gas records certain costs and benefits as
regulatory assets and liabilities, respectively, in order to provide for
recovery from or refund to customers in future periods. Gulf South does not
apply SFAS No. 71, because certain services provided by it are priced using
market-based rates and competition in its market area can result in discounts
from the maximum allowable cost-based rates being granted to customers, such
that the application of SFAS No. 71 is not appropriate.
The storage facilities operated by our
operating subsidiaries store gas that is owned by them as well as gas owned by
customers. Due to its method of accounting for storage, volumes held
on behalf of others by Gulf South are not reflected on the Consolidated Balance
Sheets. Consistent with the method of storage accounting elected by
Texas Gas and the risk-of-loss provisions included in its tariff, Texas Gas
reflects an equal and offsetting receivable and payable for certain
customer-owned gas in its facilities for certain storage and related
services. For further discussion of our gas in storage, please see
Note 2 in Item 8 of this Report.
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, 2007, we had accrued
approximately $17.0 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, the 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
At June
30, 2007, the carrying value of our Magnolia storage expansion project was
tested for impairment. As a result of the impairment test, we
recognized a $14.7 million impairment charge representing the carrying value of
the storage cavern. In determining that the fair value of the cavern
was zero, estimates and assumptions were made regarding the cash flows
associated with the storage cavern disposal through sale or
abandonment. Certain costs remain inestimable related to potential
regulatory or contractual obligations associated with abandonment of the storage
cavern. We believe that alternative uses for the storage cavern may
be possible in the hands of a third-party, and will pursue these options with
the lessor, however, we have assumed no future cash flows related to these
options in our impairment analysis. In assessing the carrying value
of the other associated facilities which include pipeline, compressors and other
equipment and facilities, we assumed that the facilities would be used in
conjunction with a replacement storage cavern to be developed. Our
expected cash flows related to the other facilities include the cost of
developing a new cavern and revenues from the sale of storage services to
third-parties over the useful life of the asset. If storage spreads
were to compress appreciably or significant difficulties were to arise in the
development of the cavern, the actual cash flows could differ materially from
the expected cash flows used in assessing the carrying value of the facilities
which could result in the recognition of an additional impairment
charge. If it is determined in the future that the assets cannot be
used in conjunction with a new cavern, we may be required to record an
additional impairment charge at the time that determination is
made.
Jackson
Storage Gas Loss
Our
Jackson, Mississippi aquifer storage facility has a working gas capacity of
approximately 5.0 Bcf and is primarily used for operational
purposes. In the fourth quarter 2007, it was determined that, based
upon tests used to estimate the amount of gas stored in the facility, gas loss
had occurred in the range of 1.3 to 1.7 Bcf. As a result of the
estimated gas loss, we recognized a charge of $0.7 million to Operation and
maintenance expense in the fourth quarter 2007. This amount was
determined by applying the carrying value of gas in the facility of $0.53 per
million British thermal units (MMBtu), to the low end of the range of estimated
gas loss of 1.3 Bcf. An assessment is underway to determine whether
the gas will need to be replaced in order to operate the facility and support
pipeline operations. A more comprehensive test of the field will be
performed in the second quarter 2008. If the pending test results
indicate that the actual gas loss is greater than the estimated 1.3 Bcf, this
could result in a future adjustment to the estimate.
Goodwill
As of December 31, 2007, 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, 2007, 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 United States 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 9 in Item 8 of this
Report.
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. Item 1, Nature of Contracts, contains more
information about the nature of our revenues. Our operating costs and
expenses typically do not vary significantly based upon the amount of gas
transported, with the exception of fuel consumed at Gulf South’s compressor
stations, which is part of Operation and maintenance expenses. We
charge shippers for fuel in accordance with each pipeline’s individual tariff
guidelines and Gulf South’s fuel recoveries are included as part of Gas
transportation revenues. The following analysis discusses our
financial results of operations for the years 2007, 2006 and 2005.
2007
Compared with 2006
Our net
income for the year ended December 31, 2007, increased $30.2 million, or 15.3%,
from 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 storage gas associated with a storage expansion project, which was
accounted for as a reduction of operating expenses.
Total
operating revenues increased $35.7 million, or 5.9%, to $643.3 million for the
year ended December 31, 2007, compared to $607.6 million for the year ended
December 31, 2006, primarily due to:
|
·
|
$23.4
million increase in gas transportation fees due to higher reservation
rates, including $8.9 million from new contracts associated with the
Carthage, Texas to Keatchie, Louisiana pipeline expansion which was in
service for all of 2007;
|
|
·
|
$11.9
million increase in fuel revenues due to increased retained volumes from
higher system utilization including amounts associated with pipeline
expansion; and
|
|
·
|
$4.1
million increase from the settlement of a claim related to a firm
transportation agreement in the Calpine bankruptcy
proceeding.
|
Operating
costs and expenses increased $23.5 million, or 6.6%, to $377.2 million for the
year ended December 31, 2007, compared to $353.7 million for the year ended
December 31, 2006, primarily due to:
|
·
|
$14.7
million loss from impairment of the Magnolia storage facility in the
second quarter 2007;
|
|
·
|
$9.3
million in charges associated with offshore pipeline assets in the South
Timbalier Bay area, offshore Louisiana, including $4.8 million related to
re-covering the pipeline and a $4.5 million impairment
charge;
|
|
·
|
$6.9
million increase in fuel costs due to an increase in gas
usage;
|
|
·
|
$6.0
million increase in depreciation and amortization from increases in our
asset base;
|
|
·
|
$5.0
million increase in property and other taxes due to increases in the
valuation of our asset base;
|
|
·
|
$3.8
million increase related to termination of an agreement with a
construction contractor on the Southeast expansion project;
and
|
|
·
|
$22.0
million decrease from a 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 33.2%, to $37.5 million for the
year ended December 31, 2007, compared to $56.1 million for the year ended
December 31, 2006. The decline is 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.
2006
Compared with 2005
Our net
income for the year ended December 31, 2006 increased $96.6 million or 95.7%
from 2005. The primary drivers for the increase were higher PAL, gas
storage and gas transportation revenues and a change in tax status concurrent
with our IPO in November 2005, as a result of which we ceased recording a
charge-in-lieu of income taxes in our results of operations.
Total
operating revenues increased $47.2 million, or 8.4%, to $607.6 million for the
year ended December 31, 2006, compared to $560.4 million for the year ended
December 31, 2005, primarily due to:
|
·
|
$38.5
million increase in gas storage and PAL revenues mainly due to favorable
natural gas price spreads and volatility in forward natural gas
prices;
|
|
·
|
$26.0
million increase in firm transportation revenues, excluding fuel,
primarily due to higher reservation rates and additional capacity reserved
by shippers due to increased production in the East Texas region;
and
|
|
·
|
$5.3
million increase due mainly to hurricane insurance recoveries received in
2006 and gas lost in 2005 related to
hurricanes.
|
The
increases were partly offset by:
|
·
|
$10.5
million decrease in interruptible transportation revenues due in part to
customers shifting to firm services and supply disruptions caused by the
hurricanes;
|
|
·
|
$7.1
million decrease in fuel retained due to lower realized natural gas prices
and reduced throughput; and
|
|
·
|
$5.5
million decrease in revenues from the amortization of acquired executory
contracts.
|
Operating
costs and expenses increased by $8.7 million, or 2.5%, to $353.7 million for the
year ended December 31, 2006, compared to $345.0 million for the year ended
December 31, 2005. This increase is primarily due to:
|
·
|
$12.6
million increase in outside services and overheads mainly due to growth in
operations and regulatory
compliance;
|
|
·
|
$12.2
million from the sale of storage gas related to Phase I of our Western
Kentucky storage expansion project reported in Net gain on disposal of
operating assets and related contracts in
2005;
|
|
·
|
$10.2
million higher employee benefits costs comprised mainly of $6.3 million
from the amortization of a regulatory asset for postretirement benefits as
a result of the Texas Gas rate case settlement and $3.5 million from a
special termination benefit charge recorded as a result of the early
retirement incentive program; and
|
|
·
|
$3.7
million from an increase in depreciation and amortization due to increases
in our asset base and $2.6 million increased expense from the lease of
third-party pipeline capacity.
|
The
increases were partly offset by:
|
·
|
$18.2
million decrease in hurricane-related costs from $7.3 million of
hurricane-related insurance recoveries recognized in 2006 and a reduction
in hurricane-related operating expenses from amounts incurred in
2005;
|
|
·
|
$14.9
million decrease in company-used gas due to operational efficiencies,
lower natural gas prices and reduced throughput resulting in decreased
usage.
|
Total
other deductions increased by $1.2 million, or 2.2%, of which $2.1 million is
primarily due to interest expense related to borrowings under our revolving
credit facility and the issuance of new debt in November 2006, offset by an
increase in interest income.
Liquidity
and Capital Resources
We are a partnership holding company
and derive all of our operating cash flow from our operating subsidiaries. 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.
Our operating subsidiaries participate
in a 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.
Maintenance Capital
Expenditures
Maintenance
capital expenditures were $47.1 million, $41.7 million and $52.9 million in
2007, 2006 and 2005. We expect to fund our 2008 maintenance capital
expenditures of approximately $60.0 million from our operating cash
flows.
Expansion
Capital Expenditures
Expansion
capital expenditures were $1,162.7 million, $158.6 million and $30.1 million in
2007, 2006 and 2005. As discussed above in Item 1, Business –
Expansion Projects, we have undertaken significant capital expansion projects,
substantially all of which have been or are expected to be funded with proceeds
from equity and debt financings.
Since our
IPO through December 31, 2007, we have raised $726.0 million through issuances
of equity limited partnership units and contributions from our general partner
and $743.6 million through issuances of unsecured notes by us and our
subsidiaries, as described below under Equity and Debt Financing, and in Note 7
to the consolidated financial statements contained in Item 8 of this
Report. At December 31, 2007, we had approximately $317.3
million in cash and $814.4 million of borrowing capacity available under our
$1.0 billion revolving credit facility discussed below.
We expect
to incur expansion capital expenditures of approximately $3.1 billion in 2008
and approximately $0.2 billion in 2009 to complete our pipeline expansion
projects, based upon our current cost estimates. However, as noted
elsewhere in this report, we have experienced cost increases in these projects
and various factors could cause our costs to exceed that amount. We
expect to finance our remaining pipeline expansion capital costs through equity
financings and the incurrence of debt, including sales of debt by us and our
subsidiaries, and borrowings under our revolving credit facility, as well as
available operating cash flow in excess of our operating
needs. However, the impact of the cost increases we have experienced
and may experience in the future to complete our expansion capital projects
could adversely impact our financing costs, which could have a material adverse
affect on our results of operations, financial condition and cash
flows. See Item 1A, Risk Factors – We are undertaking large, complex
expansion projects which involve significant risks that may adversely affect our
business. See also Item 1 – Pipeline Expansion Projects.
Equity
and Debt Financing
In
November 2007, we completed an offering of 7.5 million of our common units at a
price of $30.90 per unit. The offering resulted in net proceeds of
$232.8 million, after deducting underwriting discounts and offering expenses of
$3.7 million and including $4.7 million received from our general partner to
maintain its 2.0% interest in us. After the offering, we have 90.7
million common units and 33.1 million subordinated units issued and outstanding,
of which 37.4 million common units are held by the public.
In August 2007, we sold $225.0 million
of 5.75% senior unsecured notes of Gulf South due August 15, 2012, and $275.0
million of 6.30% senior unsecured notes of Gulf South due August 15, 2017. We
received net proceeds of approximately $495.3 million after deducting initial
purchaser discounts and offering expenses of $4.7 million.
In March
2007, we completed a public offering of 8.0 million of our common units at a
price of $36.50 per unit. We received proceeds of approximately
$293.8 million, net of underwriting discounts and offering expenses of $4.2
million and including approximately $6.0 million from the general partner to
maintain its 2.0% general partner interest.
The
proceeds of these offerings have been and will be primarily used to fund capital
expenditures associated with our expansion projects.
In August
2007, we 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
reference rate on the Treasury rate lock was 4.74%. On February 1,
2008, we paid the counterparty approximately $15.0 million to settle the rate
lock. The Treasury lock was designated as a cash flow hedge in
accordance with SFAS No. 133, Accounting for Derivative
Instruments and Hedging Activities, as amended; therefore the loss will
be recognized in Interest expense over the term of the related debt to be
issued.
Credit
Facility
We
maintain a $1.0 billion revolving credit facility, which was increased from
$700.0 million in November 2007, under which Boardwalk Pipelines, Gulf South and
Texas Gas each may borrow funds, up to applicable sub-limits. 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 (LIBOR) or
a base rate defined as the greater of the prime rate or the Federal funds rate
plus 50 basis points. Under the terms of the agreement, each of the borrowers
must maintain a minimum ratio, as of the last day of each fiscal quarter, of
consolidated total debt to consolidated earnings before income taxes,
depreciation and amortization (as defined in the agreement), measured for the
preceding twelve months, of not more than five to one. As of December
31, 2007, we were in compliance with all the covenant requirements under our
credit agreement and no funds were drawn under this
facility. However, at December 31, 2007, we had outstanding letters
of credit under the facility for $185.6 million to support certain obligations
associated with the Fayetteville Lateral and Gulf Crossing expansion projects
which reduced the available capacity under the facility by such
amount. The revolving credit facility has a maturity date of June 29,
2012.
Contractual
Obligations
The following table summarizes
significant contractual cash payment obligations as of December 31, 2007, 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
|
|
$ |
1,860.0 |
|
|
|
- |
|
|
|
- |
|
|
$ |
225.0 |
|
|
$ |
1,635.0 |
|
|
Interest
on long-term debt
|
|
|
963.7 |
|
|
$ |
103.6 |
|
|
$ |
207.4 |
|
|
|
207.4 |
|
|
|
445.3 |
|
|
Capital
commitments
|
|
|
851.1 |
|
|
|
834.7 |
|
|
|
16.4 |
|
|
|
- |
|
|
|
- |
|
|
Lease
commitments
|
|
|
36.7 |
|
|
|
6.7 |
|
|
|
10.8 |
|
|
|
6.0 |
|
|
|
13.2 |
|
|
Total
|
|
$ |
3,711.5 |
|
|
$ |
945.0 |
|
|
$ |
234.6 |
|
|
$ |
438.4 |
|
|
$ |
2,093.5 |
|
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. The above table
does not reflect commitments we have made after December 31, 2007, relating to
our expansion projects. For information on these projects, please
read “Capital Expenditures” above.
Changes
in cash flow from operating activities
Net cash
provided by operating activities increased $26.2 million, or 10.3%, to $281.7
million for the year ended December 31, 2007, compared to $255.5 million for the
comparable 2006 period, primarily due to:
|
·
|
$16.0
million increase in cash due to gas purchases made in
2006;
|
|
·
|
$8.5
million increase in cash due to the timing of expenditures;
and
|
|
·
|
$3.0
million increase in cash from the change in net income, excluding non-cash
items such as depreciation and amortization, impairment charges and
recognition of previously deferred
revenues.
|
Changes
in cash flow from investing activities
Net cash
used in investing activities increased $988.8 million to $1.2 billion for the
year ended December 31, 2007, compared to $191.5 million for the comparable 2006
period, primarily due to an increase in capital expenditures mainly for our
expansion projects.
Changes
in cash flow from financing activities
Net cash
provided by financing activities increased $547.7 million to $816.9 million for
the year ended December 31, 2007, compared to $269.2 million for the comparable
2006 period, primarily due to:
|
·
|
$327.2
million increase in net proceeds from the sale of common units and related
general partner capital
contributions;
|
|
·
|
$157.0
million increase in net proceeds from the issuance of long term debt;
and
|
|
·
|
$132.1
million decrease in cash used from the payment of notes and other long
term debt in 2006.
|
These
increases were partly offset by $68.6 million increase in cash distributions to
unitholders and the general partner.
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 and
maintenance costs. 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, limit our ability to price jurisdictional services or
products to ensure recovery of inflation’s effect on costs.
Off-Balance
Sheet Arrangements
At December 31, 2007, 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.
Recent
Accounting Pronouncements
For a discussion regarding recent
accounting pronouncements, please read Note 15 in Item 8 of this
Report.
Calpine
Energy Services (Calpine) Settlement
In 2002
and 2003, Calpine entered into two 20-year transportation agreements with Gulf
South. In December 2005, Calpine filed for Chapter 11 Bankruptcy
protection and in early 2006 discontinued making payments on one of the
transportation agreements. Gulf South continued to invoice Calpine
under the transportation agreements and fully reserved the revenues associated
with the contract on which Calpine was not making payments. In
December 2007, Gulf South and Calpine filed a stipulation and agreement with the
Bankruptcy court, which was approved in January 2008, to terminate the firm
transportation agreement on which Calpine was delinquent, and to settle all of
Gulf South’s claims in the Bankruptcy proceedings for approximately $16.5
million. The claim was to be paid in the form of Calpine stock, along
with other general creditors having claims in the Bankruptcy
proceeding. In January 2008, we sold the Bankruptcy claim to a third
party and received a cash payment of approximately $15.3 million. The
assignment is with recourse subject to the issuance of Calpine stock in the full
amount of the claim. As a result of the settlement, in 2007 we
recognized $4.1 million in Gas transportation revenues related to invoiced
amounts past due, which were previously reserved. The remainder of
the settlement amount will be recognized upon full payment of the settlement
amount by Calpine.
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 project,
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, weather,
difficulties or delays in obtaining regulatory approvals or denied
applications, land owner opposition, the lack of adequate materials, labor
difficulties or shortages, expansion costs that are higher than
anticipated and numerous other factors beyond our
control.
|
|
·
|
We
may not complete any future debt or equity financing
transaction.
|
|
·
|
The
gas transmission and storage operations of our subsidiaries are subject to
rate-making policies and actions by the FERC or customers that could have
an adverse impact on the rates we charge and our ability to recover our
income tax allowance, our full cost of operating our pipelines and 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
could negatively 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.
|
|
·
|
Successful
development of LNG import terminals in the eastern or northeastern United
States could reduce the demand for our
services.
|
|
·
|
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.
Our debt has been issued at fixed
rates, therefore interest expense would not be impacted by changes in interest
rates. Total long-term debt at
December 31, 2007, had a carrying value of $1.8 billion and a fair value of $1.8
billion. A 100 basis point increase in interest rates on our
fixed rate debt would result in a decrease in fair value of approximately $118.8
million at December 31, 2007. A 100 basis point decrease would result
in an increase in fair value of approximately $129.3 million at December 31,
2007. The
weighted-average interest rate of our long-term debt was 5.82% at December 31,
2007.
In August
2007, we 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 reference rate on the rate lock was 4.74%. On
February 1, 2008, we paid the counterparty approximately $15.0 million to settle
the rate lock. The Treasury lock was designated as a cash flow hedge
in accordance with SFAS No. 133, therefore the loss will be recognized in
Interest expense over the term of the related debt to be issued.
Certain
volumes of our gas stored underground are available for sale and subject to
commodity price risk. At December 31, 2007, approximately $16.3 million of gas
stored underground, which we own and carry as current Gas stored underground, is
exposed to commodity price risk. We utilize derivatives to hedge
certain exposures to market price fluctuations on the anticipated operational
sales of gas.
In the
second quarter 2007, we 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 our Gulf Crossing and Southeast expansion projects, approximately
1.3 Bcf of which remained outstanding at December 31, 2007. The
derivatives were not designated as hedges in accordance with SFAS No. 133 and
were marked to fair value through earnings resulting in a loss of $1.0 million
for the year ended December 31, 2007. Changes in the fair value of the
derivatives will be recognized in earnings each quarter until
settlement. When the gas is purchased, the ultimate cost will be
recorded to Property, Plant and Equipment and recognized in earnings as the
property is depreciated. A $1.00 increase in the price of NYMEX
natural gas futures would result in the recognition of a $1.3 million gain in
earnings. Conversely, a $1.00 decrease would result in the
recognition of a $1.3 million loss.
With the
exception of the derivatives related to line pack gas purchases referred to
above, the derivatives related to the sale or purchase of natural gas, cash for
fuel reimbursement and debt issuance 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 contracts designated as cash flow
hedges are deferred as a component of accumulated other comprehensive
income. The deferred gains and losses are recognized in the
Consolidated Statements of Income when the anticipated transactions affect
earnings. Generally, for gas sales and cash for fuel reimbursement,
any gains and losses on the related derivatives would be recognized in Operating
Revenues. 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 we measure 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.
We are
exposed to credit risk relating 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, as well as volumes owed
by customers for imbalances or gas lent by us to them, generally under PAL and
NNS. We maintain credit policies intended to minimize credit risk and actively
monitor these policies. Natural gas price volatility has increased
dramatically in recent years, which has materially increased credit risk related
to gas loaned to customers. As of December 31, 2007, the amount of gas loaned
out by our subsidiaries was 12.7 trillion British thermal units (TBtu) and,
assuming an average market price during December 2007 of $7.13 per MMBtu, the
market value of gas loaned out at December 31, 2007, would have been
approximately $90.6 million. 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, 2007, our cash and cash equivalents were invested primarily in
mutual funds. Due to the short-term nature and type of our
investments, a hypothetical 10.0% increase in interest rates would not have a
material effect on the fair market value of our portfolio. Since we have the
ability to liquidate this portfolio, we do not expect our Consolidated
Statements of Income or Cash Flows to be materially impacted by the effect of a
sudden change in market interest rates on our investment portfolio.
During
2007, we began investing in short-term investments such as 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 owed
by the counterparty. We had no investments under repurchase
agreements at December 31, 2007, however since then we have reinitiated our
program of investing in short-term repurchase agreements.
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, 2007 and
2006, and the related consolidated statements of income, member’s equity and
partners’ capital, comprehensive income, and cash flows for each of the three
years in the period ended December 31, 2007. 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, 2007 and 2006, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 2007, in conformity with 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.
As
discussed in Note 1 to the consolidated financial statements, the accompanying
financial statements reflect a change in the Partnership’s tax
status.
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, 2007, 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 26, 2008 expressed an
unqualified opinion on the Partnership's internal control over financial
reporting.
DELOITTE
& TOUCHE LLP
Chicago,
Illinois
February
26, 2008
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, 2007, 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 Annual 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, 2007, 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, 2007 of
the Partnership and our report dated February 26, 2008 expressed an unqualified
opinion on those financial statements and financial statement schedule and
included an explanatory paragraph regarding a change in the Partnership’s tax
status.
DELOITTE
& TOUCHE LLP
Chicago,
Illinois
February
26, 2008
BOARDWALK
PIPELINE PARTNERS, LP
CONSOLIDATED
BALANCE SHEETS
(Thousands
of Dollars)
|
|
|
December
31,
|
|
|
ASSETS
|
|
2007
|
|
|
2006
|
|
|
Current
Assets:
|
|
|
|
|
|
|
|
Cash
and cash equivalents
|
|
$ |
317,319 |
|
|
$ |
399,032 |
|
|
Receivables:
|
|
|
|
|
|
|
|
|
|
Trade,
net
|
|
|
60,661 |
|
|
|
54,082 |
|
|
Other
|
|
|
12,748 |
|
|
|
12,759 |
|
|
Gas
Receivables:
|
|
|
|
|
|
|
|
|
|
Transportation
and exchange
|
|
|
12,467 |
|
|
|
9,115 |
|
|
Storage
|
|
|
1,266 |
|
|
|
11,704 |
|
|
Inventories
|
|
|
16,581 |
|
|
|
14,110 |
|
|
Costs
recoverable from customers
|
|
|
6,358 |
|
|
|
11,236 |
|
|
Gas
stored underground
|
|
|
16,322 |
|
|
|
14,001 |
|
|
Prepaid
expenses and other current assets
|
|
|
11,927 |
|
|
|
22,117 |
|
|
Total
current assets
|
|
|
455,649 |
|
|
|
548,156 |
|
|
|
|
|
|
|
|
|
|
|
|
Property,
Plant and Equipment:
|
|
|
|
|
|
|
|
|
|
Natural
gas transmission plant
|
|
|
2,392,503 |
|
|
|
1,832,006 |
|
|
Other
natural gas plant
|
|
|
223,952 |
|
|
|
213,926 |
|
|
|
|
|
2,616,455 |
|
|
|
2,045,932 |
|
|
Less—accumulated
depreciation and amortization
|
|
|
262,477 |
|
|
|
187,412 |
|
|
|
|
|
2,353,978 |
|
|
|
1,858,520 |
|
|
Construction
work in progress
|
|
|
951,433 |
|
|
|
165,916 |
|
|
Property,
plant and equipment, net
|
|
|
3,305,411 |
|
|
|
2,024,436 |
|
|
|
|
|
|
|
|
|
|
|
|
Other
Assets:
|
|
|
|
|
|
|
|
|
|
Goodwill
|
|
|
163,474 |
|
|
|
163,474 |
|
|
Gas
stored underground
|
|
|
172,438 |
|
|
|
161,537 |
|
|
Costs
recoverable from customers
|
|
|
15,870 |
|
|
|
19,767 |
|
|
Other
|
|
|
44,464 |
|
|
|
33,929 |
|
|
Total
other assets
|
|
|
396,246 |
|
|
|
378,707 |
|
|
|
|
|
|
|
|
|
|
|
|
Total
Assets
|
|
$ |
4,157,306 |
|
|
$ |
2,951,299 |
|
The
accompanying notes are an integral part of these consolidated financial
statements.
BOARDWALK
PIPELINE PARTNERS, LP
CONSOLIDATED
BALANCE SHEETS
(Thousands
of Dollars, except number of units)
|
|
|
December
31,
|
|
|
LIABILITIES
AND PARTNERS’ CAPITAL
|
|
2007
|
|
|
2006
|
|
|
Current
Liabilities:
|
|
|
|
|
|
|
|
Payables:
|
|
|
|
|
|
|
|
Trade
|
|
$ |
190,639 |
|
|
$ |
56,604 |
|
|
Affiliates
|
|
|
1,292 |
|
|
|
3,014 |
|
|
Other
|
|
|
5,089 |
|
|
|
14,459 |
|
|
Gas
Payables:
|
|
|
|
|
|
|
|
|
|
Transportation
and exchange
|
|
|
17,849 |
|
|
|
15,485 |
|
|
Storage
|
|
|
35,250 |
|
|
|
42,127 |
|
|
Accrued
taxes, other
|
|
|
20,164 |
|
|
|
16,082 |
|
|
Accrued
interest
|
|
|
30,801 |
|
|
|
19,376 |
|
|
Accrued
payroll and employee benefits
|
|
|
22,337 |
|
|
|
18,198 |
|
|
Construction
retainage
|
|
|
32,195 |
|
|
|
2,336 |
|
|
Deferred
income
|
|
|
7,235 |
|
|
|
22,147 |
|
|
Other
current liabilities
|
|
|
26,459 |
|
|
|
18,590 |
|
|
Total
current liabilities
|
|
|
389,310 |
|
|
|
228,418 |
|
|
|
|
|
|
|
|
|
|
|
|
Long
–Term Debt
|
|
|
1,847,914 |
|
|
|
1,350,920 |
|
|
|
|
|
|
|
|
|
|
|
|
Other
Liabilities and Deferred Credits:
|
|
|
|
|
|
|
|
|
|
Pension
and postretirement benefits
|
|
|
17,211 |
|
|
|
15,761 |
|
|
Asset
retirement obligation
|
|
|
16,059 |
|
|
|
14,307 |
|
|
Provision
for other asset retirement
|
|
|
42,380 |
|
|
|
39,644 |
|
|
Other
|
|
|
41,430 |
|
|
|
29,742 |
|
|
Total
other liabilities and deferred credits
|
|
|
117,080 |
|
|
|
99,454 |
|
|
|
|
|
|
|
|
|
|
|
|
Commitments
and Contingencies
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Partners’
Capital:
|
|
|
|
|
|
|
|
|
|
Common
units - 90,656,122 and 75,156,122 common units issued and outstanding as
of December 31, 2007 and 2006
|
|
|
1,473,924 |
|
|
|
941,792 |
|
|
Subordinated
units - 33,093,878 units issued and
outstanding
as of December 31, 2007 and 2006
|
|
|
291,662 |
|
|
|
285,543 |
|
|
General
partner
|
|
|
33,204 |
|
|
|
22,060 |
|
|
Accumulated
other comprehensive income, net of tax
|
|
|
4,212 |
|
|
|
23,112 |
|
|
Total
partners’ capital
|
|
|
1,803,002 |
|
|
|
1,272,507 |
|
|
Total
Liabilities and Partners’ Capital
|
|
$ |
4,157,306 |
|
|
$ |
2,951,299 |
|
The
accompanying notes are an integral part of these consolidated financial
statements.
BOARDWALK
PIPELINE PARTNERS, LP
CONSOLIDATED
STATEMENTS OF INCOME
(Thousands
of Dollars, except earnings per unit and number of units)
|
|
|
For
the Year Ended December 31,
|
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
Operating
Revenues:
|
|
|
|
|
|
|
|
|
|
|
Gas
transportation
|
|
$ |
529,717 |
|
|
$ |
508,241 |
|
|
$ |
505,148 |
|
|
Parking
and lending
|
|
|
42,793 |
|
|
|
49,163 |
|
|
|
21,426 |
|
|
Gas
storage
|
|
|
39,429 |
|
|
|
32,396 |
|
|
|
21,667 |
|
|
Other
|
|
|
31,329 |
|
|
|
17,842 |
|
|
|
12,225 |
|
|
Total
operating revenues
|
|
|
643,268 |
|
|
|
607,642 |
|
|
|
560,466 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
Costs and Expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operation
and maintenance
|
|
|
173,759 |
|
|
|
161,279 |
|
|
|
174,641 |
|
|
Administrative
and general
|
|
|
97,039 |
|
|
|
97,298 |
|
|
|
78,752 |
|
|
Depreciation
and amortization
|
|
|
81,824 |
|
|
|
75,771 |
|
|
|
72,078 |
|
|
Taxes
other than income taxes
|
|
|
29,162 |
|
|
|
24,175 |
|
|
|
27,361 |
|
|
Asset
impairment
|
|
|
19,218 |
|
|
|
- |
|
|
|
- |
|
|
Net
gain on disposal of operating assets and related contracts
|
|
|
(23,767 |
) |
|
|
(4,829 |
) |
|
|
(7,846 |
) |
|
Total
operating costs and expenses
|
|
|
377,235 |
|
|
|
353,694 |
|
|
|
344,986 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating
income
|
|
|
266,033 |
|
|
|
253,948 |
|
|
|
215,480 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Deductions (Income):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
expense
|
|
|
61,023 |
|
|
|
62,123 |
|
|
|
60,067 |
|
|
Interest
income
|
|
|
(21,489 |
) |
|
|
(4,202 |
) |
|
|
(1,478 |
) |
|
Interest
income from affiliates, net
|
|
|
(44 |
) |
|
|
(27 |
) |
|
|
(2,186 |
) |
|
Miscellaneous
other income, net
|
|
|
(1,982 |
) |
|
|
(1,749 |
) |
|
|
(1,444 |
) |
|
Total
other deductions
|
|
|
37,508 |
|
|
|
56,145 |
|
|
|
54,959 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
before income taxes
|
|
|
228,525 |
|
|
|
197,803 |
|
|
|
160,521 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
taxes and charge-in-lieu of income taxes *
|
|
|
769 |
|
|
|
253 |
|
|
|
49,494 |
|
|
Elimination
of cumulative deferred taxes *
|
|
|
- |
|
|
|
- |
|
|
|
10,102 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
income *
|
|
$ |
227,756 |
|
|
$ |
197,550 |
|
|
$ |
100,925 |
|
*Results
of operations for the year ended December 31, 2005, reflect a change in the tax
status associated with Boardwalk Pipeline Partners, LP and Boardwalk Pipelines
coincident with the IPO. Boardwalk Pipeline Partners, LP recorded a
charge-in-lieu of income taxes and certain state franchise taxes for the period
January 1, 2005 through the date of the offering. Pursuant to the
change in tax status, Boardwalk Pipeline Partners, LP also eliminated its
balance of accumulated deferred income taxes at the date of the offering (as
presented in line item “Elimination of cumulative deferred
taxes”). The subsidiaries of Boardwalk Pipeline Partners, LP directly
incur some income-based state taxes following the date of the offering. See Note
1 to the consolidated financial statements for additional
information.
|
Calculation
of limited partners’ interest in Net income:
|
|
For
the Year Ended December 31,
|
|
|
For
the Period
November
15, 2005
through
December
31,
|
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
Net
income
|
|
$ |
227,756 |
|
|
$ |
197,550 |
|
|
$ |
35,992 |
|
|
Less
general partner’s interest in Net income
|
|
|
7,030 |
|
|
|
3,951 |
|
|
|
720 |
|
|
Limited
partners’ interest in Net income
|
|
$ |
220,726 |
|
|
$ |
193,599 |
|
|
$ |
35,272 |
|
|
Basic
and diluted net income per limited partner unit:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common
and subordinated units
|
|
$ |
1.87 |
|
|
$ |
1.85 |
|
|
$ |
0.35 |
|
|
Cash
distribution to common and subordinated unitholders
|
|
$ |
1.74 |
|
|
$ |
1.32 |
|
|
|
- |
|
|
Weighted-average
number of limited partners units outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common
units
|
|
|
82,510,917 |
|
|
|
68,977,766 |
|
|
|
68,256,122 |
|
|
Subordinated
units
|
|
|
33,093,878 |
|
|
|
33,093,878 |
|
|
|
33,093,878 |
|
The
accompanying notes are an integral part of these consolidated financial
statements.
BOARDWALK
PIPELINE PARTNERS, LP
CONSOLIDATED
STATEMENTS OF CASH FLOWS
(Thousands
of Dollars)
|
|
|
For
the Year Ended December 31,
|
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
OPERATING
ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
Net
income
|
|
$ |
227,756 |
|
|
$ |
197,550 |
|
|
$ |
100,925 |
|
|
Adjustments
to reconcile to cash provided by operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation
and amortization
|
|
|
81,824 |
|
|
|
75,771 |
|
|
|
72,078 |
|
|
Amortization
of deferred costs
|
|
|
8,319 |
|
|
|
8,758 |
|
|
|
1,313 |
|
|
Amortization
of acquired executory contracts
|
|
|
(1,098 |
) |
|
|
(3,997 |
) |
|
|
(9,630 |
) |
|
Provision
for deferred income taxes
|
|
|
(17 |
) |
|
|
(39 |
) |
|
|
54,682 |
|
|
Asset
impairment
|
|
|
19,218 |
|
|
|
- |
|
|
|
- |
|
|
Gain
on disposal of operating assets and related contracts
|
|
|
(23,767 |
) |
|
|
(4,829 |
) |
|
|
(7,846 |
) |
|
Changes
in operating assets and liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Trade
and other receivables
|
|
|
(4,141 |
) |
|
|
(436 |
) |
|
|
(27,257 |
) |
|
Gas
receivables and storage assets
|
|
|
5,446 |
|
|
|
21,451 |
|
|
|
(25,474 |
) |
|
Costs
recoverable from customers
|
|
|
3,598 |
|
|
|
(3,968 |
) |
|
|
(8,215 |
) |
|
Other
assets
|
|
|
(15,816 |
) |
|
|
(15,583 |
) |
|
|
32,259 |
|
|
Trade
and other payables
|
|
|
(15,960 |
) |
|
|
9,117 |
|
|
|
(7,461 |
) |
|
Gas
payables
|
|
|
(17,935 |
) |
|
|
(45,066 |
) |
|
|
35,567 |
|
|
Accrued
liabilities
|
|
|
12,929 |
|
|
|
(8,091 |
) |
|
|
21,467 |
|
|
Other
liabilities
|
|
|
1,347 |
|
|
|
24,850 |
|
|
|
(13,694 |
) |
|
Net
cash provided by operating activities
|
|
|
281,703 |
|
|
|
255,488 |
|
|
|
218,714 |
|
|
INVESTING
ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital
expenditures
|
|
|
(1,209,848 |
) |
|
|
(200,330 |
) |
|
|
(82,955 |
) |
|
Proceeds
from sale of operating assets
|
|
|
28,741 |
|
|
|
3,646 |
|
|
|
4,725 |
|
|
Proceeds
from insurance reimbursements and other recoveries
|
|
|
1,726 |
|
|
|
5,928 |
|
|
|
4,177 |
|
|
Advances
to affiliates, net
|
|
|
(945 |
) |
|
|
(696 |
) |
|
|
(28,252 |
) |
|
Net
cash used in investing activities
|
|
|
(1,180,326 |
) |
|
|
(191,452 |
) |
|
|
(102,305 |
) |
|
FINANCING
ACTIVITIES:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proceeds
from notes payable
|
|
|
- |
|
|
|
- |
|
|
|
42,100 |
|
|
Payments
of notes payable
|
|
|
- |
|
|
|
(42,100 |
) |
|
|
(250,000 |
) |
|
Proceeds
from long-term debt, net of issuance costs
|
|
|
495,271 |
|
|
|
338,307 |
|
|
|
569,369 |
|
|
Payment
of long-term debt
|
|
|
- |
|
|
|
(90,000 |
) |
|
|
(575,000 |
) |
|
Distributions
|
|
|
(204,950 |
) |
|
|
(136,388 |
) |
|
|
(131,686 |
) |
|
Proceeds
from sale of common units, net of related
transaction
costs
|
|
|
515,900 |
|
|
|
195,209 |
|
|
|
271,398 |
|
|
Capital
contribution from parent and general partner
|
|
|
10,689 |
|
|
|
4,176 |
|
|
|
6,684 |
|
|
Net
cash provided by (used in) financing activities
|
|
|
816,910 |
|
|
|
269,204 |
|
|
|
(67,135 |
) |
|
(Decrease)
increase in cash and cash equivalents
|
|
|
(81,713 |
) |
|
|
333,240 |
|
|
|
49,274 |
|
|
Cash
and cash equivalents at beginning of period
|
|
|
399,032 |
|
|
|
65,792 |
|
|
|
16,518 |
|
|
Cash
and cash equivalents at end of period
|
|
$ |
317,319 |
|
|
$ |
399,032 |
|
|
$ |
65,792 |
|
The
accompanying notes are an integral part of these consolidated financial
statements.
BOARDWALK
PIPELINE PARTNERS, LP
CONSOLIDATED
STATEMENTS OF CHANGES IN
MEMBER’S
EQUITY AND PARTNERS’ CAPITAL
(Thousands
of Dollars, except units)
|
|
|
Paid
in Capital
|
|
|
Retained
Earnings
|
|
|
Accumulated Other
Comp Income (Loss)
|
|
|
Common
Units
|
|
|
Subordinated Units
|
|
|
General
Partner
|
|
|
Total
Partners’ Capital
|
|
|
Balance January
1, 2005
|
|
$ |
1,071,651 |
|
|
$ |
21,276 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
Add
(deduct):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
- |
|
|
Net
income
|
|
|
- |
|
|
|
64,933 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
Capital
contribution
|
|
|
6,684 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
Dividends
paid
|
|
|
- |
|
|
|
(233,087 |
) |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
Other
comprehensive
income,
net
of tax
|
|
|
- |
|
|
|
- |
|
|
$ |
287 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
Elimination
of deferred
taxes
on accumulated
other
comprehensive
income
|
|
|
- |
|
|
|
- |
|
|
|
64 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
Balance November
15, 2005
|
|
$ |
1,078,335 |
|
|
$ |
(146,878 |
) |
|
$ |
351 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
Boardwalk Pipeline Partners, LP
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Add
(deduct):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital
contribution,
including
assumption
of
debt
of
$250.0
million
|
|
|
- |
|
|
|
- |
|
|
$ |
351 |
|
|
$ |
410,456 |
|
|
$ |
255,061 |
|
|
$ |
15,941 |
|
|
$ |
681,809 |
|
|
(53,256,122
common
units, 33,093,878
subordinated
units
and
2% general
partner
interest)
|
|
Sale
of common units,
net
of related
transaction
costs
(15,000,000
units)
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
271,398 |
|
|
|
- |
|
|
|
- |
|
|
|
271,398 |
|
|
Other
comprehensive
loss,
net of tax
|
|
|
- |
|
|
|
- |
|
|
|
(525 |
) |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(525 |
) |
|
Net
income
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
23,755 |
|
|
|
11,517 |
|
|
|
720 |
|
|
|
35,992 |
|
|
Balance
December 31, 2005
|
|
|
- |
|
|
|
- |
|
|
$ |
(174 |
) |
|
$ |
705,609 |
|
|
$ |
266,578 |
|
|
$ |
16,661 |
|
|
$ |
988,674 |
|
|
Add
(deduct):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
income
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
130,990 |
|
|
|
62,609 |
|
|
|
3,951 |
|
|
|
197,550 |
|
|
Distributions
paid
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(90,016 |
) |
|
|
(43,644 |
) |
|
|
(2,728 |
) |
|
|
(136,388 |
) |
|
Sale
of common units,
net
of related
transaction
costs
(6,900,000
units)
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
195,209 |
|
|
|
- |
|
|
|
- |
|
|
|
195,209 |
|
|
Capital
contribution
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
4,176 |
|
|
|
4,176 |
|
|
Other
comprehensive
income, net
of tax
|
|
|
- |
|
|
|
- |
|
|
|
8,483 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
8,483 |
|
|
Adjustment
to initially
apply SFAS
No. 158,
net
of tax
|
|
|
- |
|
|
|
- |
|
|
|
14,803 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
14,803 |
|
|
Balance
December 31, 2006
|
|
|
- |
|
|
|
- |
|
|
$ |
23,112 |
|
|
$ |
941,792 |
|
|
$ |
285,543 |
|
|
$ |
22,060 |
|
|
$ |
1,272,507 |
|
|
Add
(deduct):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
income
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
157,189 |
|
|
|
63,537 |
|
|
|
7,030 |
|
|
|
227,756 |
|
|
Distributions
paid
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(140,957 |
) |
|
|
(57,418 |
) |
|
|
(6,575 |
) |
|
|
(204,950 |
) |
|
Sale
of common units,
net
of related
transaction costs
(15,500,000 units)
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
515,900 |
|
|
|
- |
|
|
|
- |
|
|
|
515,900 |
|
|
Capital
contribution
from general
partner
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
10,689 |
|
|
|
10,689 |
|
|
Other
comprehensive
loss,
net of tax
|
|
|
- |
|
|
|
- |
|
|
|
(18,900 |
) |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(18,900 |
) |
|
Balance
December 31, 2007
|
|
|
- |
|
|
|
- |
|
|
$ |
4,212 |
|
|
$ |
1,473,924 |
|
|
$ |
291,662 |
|
|
$ |
33,204 |
|
|
$ |
1,803,002 |
|
The
accompanying notes are an integral part of these consolidated financial
statements.
BOARDWALK
PIPELINE PARTNERS, LP
CONSOLIDATED
STATEMENTS OF COMPREHENSIVE INCOME
(Thousands
of Dollars)
|
|
|
For
the Year Ended December 31,
|
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
Net
income
|
|
$ |
227,756 |
|
|
$ |
197,550 |
|
|
$ |
100,925 |
|
|
Other
comprehensive (loss) income:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Loss)
gain on cash flow hedges
|
|
|
(9,864 |
) |
|
|
19,405 |
|
|
|
(2,735 |
) |
|
Reclassification
adjustment transferred to Net income
from
cash flow hedges
|
|
|
(7,336 |
) |
|
|
(10,922 |
) |
|
|
2,561 |
|
|
Pension
and other postretirement benefits costs
|
|
|
(1,700 |
) |
|
|
- |
|
|
|
- |
|
|
Total
comprehensive income
|
|
$ |
208,856 |
|
|
$ |
206,033 |
|
|
$ |
100,751 |
|
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 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). Boardwalk Pipelines Holding Corp. (BPHC) a
wholly-owned subsidiary of Loews Corporation (Loews) owns 53.3 million common
units and 33.1 million subordinated units constituting approximately 70.0% of
the Partnership’s equity. Boardwalk GP, LP (Boardwalk GP), an
indirect wholly-owned subsidiary of BPHC is the Partnership’s general partner
and holds a 2.0% general partner interest and all of the incentive distribution
rights, further described in Note 10. 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).
In connection with the consummation of
the Partnership’s initial public offering (IPO), BPHC contributed all of the
equity interests of Boardwalk Pipelines to the Partnership. 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 the results of the
Partnership subsequent to November 15, 2005, as the consolidated results of the
Partnership.
Results of operations for the year
ended December 31, 2005, reflect a change in the tax status associated with the
Partnership and Boardwalk Pipelines, coincident with the IPO. Prior
to 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. Accordingly,
the Partnership recorded a charge-in-lieu of income taxes of $49.5 million for
the period January 1, 2005, through the date of the
offering. Pursuant to the change in tax status, the Partnership also
eliminated its balance of accumulated deferred income taxes at the date of the
offering as presented in Elimination of cumulative deferred taxes on the
Consolidated Statements of Income. The subsidiaries of the
Partnership directly incur some income-based state taxes which are presented in
Income taxes and charge-in-lieu of income taxes on the Consolidated Statements
of Income.
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 South, Texas Gas and Gulf Crossing Pipeline Company,
LLC (Gulf Crossing) 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, revenues subject to refund, and
prior to converting to a limited partnership, charge-in-lieu of income taxes.
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. 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 and Illinois, with 13,550 miles of pipelines and integrated
storage fields.
Cash
and Cash Equivalents
Cash equivalents are highly liquid
investments with an original maturity of three months or less. Cash
equivalents are stated at cost plus accrued interest, which approximates 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. The Partnership had no
restricted cash at December 31, 2007 and 2006.
Cash
Management and Advances to Affiliates
The operating subsidiaries participate
in a cash management program to the extent they are permitted under Federal
Energy Regulatory Commission (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 Partnership also
periodically pays for certain taxes on behalf of BPHC. The
obligations to repay these amounts 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.
Inventories
Inventories consisting of materials and
supplies are carried at the lower of average cost or market, less an allowance
for obsolescence.
Gas
in Storage and Gas Receivables/Payables
Both operating subsidiaries have
underground gas in storage which is utilized for system management and
operational balancing, as well as for certain tariff services including firm,
interruptible and no-notice (NNS) storage 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.
The
accompanying consolidated financial statements reflect the balance of
underground gas in storage recorded at historical cost, as well as the resulting
activity relating to the storage services and balancing activity. Gas
stored underground includes natural gas volumes owned by the pipelines, at times
reduced by certain operational encroachments upon that gas. Current
gas stored underground represents retained fuel and excess working gas which is
available for resale and is valued at the lower of weighted-average cost or
market. Retained fuel is a component of Gulf South’s tariff structure
and is recognized as transportation revenue at market prices in the month of
retention. Customers can pay Gulf South’s fuel rate by physically
delivering gas or making a cash payment.
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 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. For Gulf South, these receivables and payables are valued
at market price. For Texas Gas, these amounts are valued at the
historical value of gas in storage, consistent with the regulatory treatment and
the settlement history.
Due to the method of storage accounting
elected by Gulf South, the Partnership does not reflect volumes held by Gulf
South on behalf of others on its Consolidated Balance Sheets. As of
December 31, 2007 and 2006, Gulf South held 52.0 trillion British thermal units
(TBtu) and 61.0 TBtu of gas owned by shippers, and had loaned 0.2 TBtu of gas to
shippers as of December 31, 2007. No gas was loaned by Gulf South to shippers as
of December 31, 2006. Consistent with the method of storage
accounting elected by Texas Gas and the risk-of-loss provisions included in its
tariff, Texas Gas reflects an equal and offsetting receivable and payable for
customer-owned gas in its facilities for storage and related services. The
amount reflected in Gas Payables on the Consolidated Balance Sheets is valued at
a historical cost of gas of $36.6 million and $45.7 million at December 31, 2007
and 2006.
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
the Consolidated Statements of Income 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.
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.
Gulf
South depreciates assets 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 property in the Gulf South
system could result in a gain or loss. Depreciation at Texas Gas 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
Texas Gas generally do not impact PPE, net.
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 the assets is compared to the
carrying value of the assets 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. Note 4 contains more
information regarding the Partnership’s PPE.
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 2007, 2006 or 2005.
Regulatory
Accounting
The operating subsidiaries are
regulated by FERC. SFAS No. 71, Accounting for the Effects of
Certain Types of Regulation, requires that rate-regulated entities that
meet certain specified criteria account for and report assets and liabilities
consistent with the economic effect of the manner in which independent
third-party regulators establish rates. Gulf South does not apply
SFAS No. 71. Certain services provided by Gulf South are market-based
and competition in its market area has often resulted in discounts from the
maximum allowable cost-based rates being granted to customers, such that SFAS
No. 71 has not been appropriate. Therefore, Gulf South does not
record any regulatory assets or liabilities. Texas Gas applies SFAS
No. 71. Therefore, certain costs and benefits are recorded as
regulatory assets and liabilities based on expected recovery from customers or
refund to customers in future periods.
The Partnership monitors the regulatory
and competitive environment in which it operates to determine that the
regulatory assets continue to be probable of recovery. If the
Partnership were to determine that all or a portion of these 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.
Acquired
Executory Contracts
As a result of the Gulf South
acquisition in December 2004, the Partnership recorded certain shipper contracts
at fair value. The below-market valuation balance of $0.2 million and $1.3
million as of December 31, 2007 and 2006 was included as a component of Other
current liabilities At the date of acquisition, these deferred
credits were to be amortized over the life of the shipper contracts ranging from
three months to three years. Amortization for 2007, 2006 and 2005 was $1.1
million, $4.0 million and $9.6 million and is expected to be $0.2 million for
2008.
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 (ARO) 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 the 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 is remeasured
each reporting period until settlement, and recognizes it as compensation
expense over the period the employee is required to provide service in exchange
for the award, usually the vesting period. 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 9 contains additional information regarding the
Partnership’s unit-based compensation.
The maximum rates that may be charged
by the operating subsidiaries for their gas transportation and storage services
are established through the FERC cost-based rate-making
process. Rates charged by the operating subsidiaries may be less than
those allowed by the 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 $7.2 million at December 31, 2007, related to PAL services
to be provided mainly in 2008. At December 31, 2006, the Partnership
had deferred revenues of $22.4 million.
Retained fuel is a component of Gulf
South’s tariff structure and is recognized in revenues at market prices in the
month of retention. The related fuel consumed in providing
transportation services is recorded as a component of Operation and maintenance
expense 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, 2007, 2006 and 2005 were $73.0 million, $73.2
million and $86.7 million.
Under the 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, 2007 and 2006, there were no liabilities for
any open rate case recorded on the Consolidated Balance
Sheets. Currently, neither of the operating subsidiaries is involved
in an open general rate case.
Trade
and Other Receivables
Trade and other receivables are stated
at the 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.
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 Gulf South
construction activities. 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. In accordance with SFAS No. 71, the Partnership records
AFUDC in connection with Texas Gas construction
activities. 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,
|
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
Capitalized
interest and allowance for borrowed funds used during
construction
|
|
$ |
27.1 |
|
|
$ |
2.3 |
|
|
$ |
0.7 |
|
|
Allowance
for equity funds used during construction
|
|
|
3.0 |
|
|
|
1.2 |
|
|
|
1.4 |
|
Partner
Capital Accounts
For purposes of maintaining the 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 incentive distribution rights.
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 and charge-in-lieu of income taxes on the Consolidated Statements
of Income. Note 11 contains more information regarding the Partnership’s income
taxes.
Reclassifications
Certain reclassifications have
been made to the 2006 and 2005 financial statements to conform to the 2007
presentation, primarily related to individual amounts and captions within the
Operating Activities section of the Consolidated Statements of Cash
Flows.
Note
3: Commitments and Contingencies
Calpine
Energy Services (Calpine) Settlement
In 2002
and 2003, Calpine entered into two 20-year transportation agreements with Gulf
South. In December 2005, Calpine filed for Chapter 11 Bankruptcy
protection and in early 2006 discontinued making payments on one of the
transportation agreements. Gulf South continued to invoice Calpine
under the transportation agreements and fully reserved the revenues associated
with the contract on which Calpine was not making payments. In
December 2007, Gulf South and Calpine filed a stipulation and agreement with the
Bankruptcy court, which was approved in January 2008, to terminate the firm
transportation agreement on which Calpine was delinquent, and to settle all of
Gulf South’s claims in the Bankruptcy proceedings for approximately $16.5
million. The claim was to be paid in the form of Calpine stock, along
with other general creditors having claims in the Bankruptcy
proceeding. In January 2008, Boardwalk sold the Bankruptcy
claim to a third party and received a cash payment of approximately $15.3
million. The assignment is with recourse subject to the issuance of
Calpine stock in the full amount of the claim. As a result of the
settlement, in 2007 Boardwalk recognized $4.1 million in Gas transportation
revenues related to invoiced amounts past due, which were previously
reserved. The remainder of the settlement amount will be recognized
upon full payment of the settlement amount by Calpine.
Jackson
Storage Gas Loss
The
Partnership’s Jackson, Mississippi aquifer storage facility has a working gas
capacity of approximately 5.0 billion cubic feet (Bcf) and is
primarily used for operational purposes. In the fourth quarter 2007,
it was determined that, based upon tests used to estimate the amount of gas
stored in the facility, gas loss had occurred in the range of 1.3 to 1.7
Bcf. As a result of the estimated gas loss, the Partnership
recognized a charge of $0.7 million to Operation and maintenance expense in the
fourth quarter 2007. This amount was determined by applying the
carrying value of gas in the facility of $0.53 per million British thermal units
(MMBtu), to the low end of the range of estimated gas loss of 1.3
Bcf. An assessment is underway to determine whether the gas will need
to be replaced in order to operate the facility and support pipeline
operations. A more comprehensive test of the field will be performed
in the second quarter 2008. If the pending test results indicate that
the actual gas loss is greater than the estimated 1.3 Bcf, this could result in
a future adjustment to the estimate.
Impact
of Hurricanes Katrina and Rita
In August
and September 2005, Hurricanes Katrina and Rita (hurricanes), and related storm
activity caused extensive and catastrophic physical damage to the offshore,
coastal and inland areas in the Gulf Coast region of the United
States. A substantial portion of the Partnership’s assets are located
in the area directly impacted by the hurricanes. The remediation work
related to the hurricanes was completed in 2007.
The
Partnership reduced its liability for estimated costs associated with the
hurricanes by $0.4 million in 2007 and increased the liability by $0.1 million
in 2006. The Partnership recorded charges related to the hurricanes
of $12.9 million in 2005, $2.0 million of which was recorded to Operating
revenues and $10.9 million of which was recorded to Operating costs and
expenses. The accrued liability for the hurricanes was zero at
December 31, 2007, and $1.0 million at December 31, 2006.
In the
third quarter 2007, the Partnership accrued estimated insurance proceeds of $5.1
million for claims related to Hurricane Rita which represented the minimum
amount of insurance proceeds that were probable of recovery. This
amount resulted in a reduction of Operating Costs and Expenses. In
2006, the Partnership recognized $10.7 million of insurance recoveries
associated with Hurricane Katrina, $7.4 million of which was recorded to
Operating Costs and Expenses and $3.3 million of which was recorded to Operating
Revenues. The Partnership received a cash payment of $6.0 million in
the fourth quarter 2006 and the remaining $4.7 million was recorded as a
receivable at December 31, 2006. In the first quarter 2007, the
Partnership received a final cash payment of $6.2 million of insurance proceeds
related to damages incurred during Hurricane Katrina, $4.7 million of which was
applied against the receivable and $1.5 million of which was recognized in Gas
transportation revenues. Through December 31, 2007, the Partnership
has received a total of approximately $12.2 million in insurance proceeds
related to Hurricane Katrina, and will continue to pursue additional recovery of
insurance proceeds related to Hurricane Rita.
Legal
Proceedings
Napoleonville
Salt Dome Matter
In
December 2003, natural gas leaks were observed near two natural gas storage
caverns that were being leased and operated by Gulf South for natural gas
storage in Napoleonville, Louisiana. Gulf South commenced remediation efforts
immediately and ceased using those storage caverns. Two class action lawsuits
were filed relating to this incident and were converted to individual actions.
Several individual actions have been filed against Gulf South and other
defendants by local residents and businesses. In addition, the lessor of the
property has filed an affirmative claim against Gulf South in an action filed
against the lessor by one of Gulf South's insurers. Gulf South continues to
vigorously defend each of these actions, however it is not possible to predict
the outcome of this litigation as the cases remain in discovery. Litigation is
subject to many uncertainties, and it is possible these actions could be decided
unfavorably. Gulf South has settled many of the cases filed against it and may
enter into discussions in an attempt to settle other cases if Gulf South
believes it is appropriate to do so.
The
remediation work related to the incident was completed in November
2006. Gulf South incurred $8.9 million for remediation costs, root
cause investigation, and legal fees. Gulf South has made demand for
reimbursement from its insurance carriers and will continue to pursue recoveries
of the remaining expenses, including legal expenses. To date the insurance
carriers have not taken any definitive coverage positions on all of the issues
raised in the various lawsuits. During 2007, Gulf South has received $0.3
million of insurance reimbursements for legal expenses and root cause
investigation.
Other
Legal Matters
In connection with the acquisition of
Texas Gas, 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
East Texas to Mississippi
Expansion. On June 18, 2007, the FERC granted the Partnership
the authority to construct, own and operate a pipeline expansion consisting of
approximately 242 miles of 42-inch pipeline from DeSoto Parish in western
Louisiana to near Harrisville, Mississippi and approximately 110,000 horsepower
of new compression having approximately 1.7 Bcf of new peak-day transmission
capacity. Customers have contracted at fixed rates for 1.4 Bcf per
day of firm transportation capacity on a long-term basis (with a weighted
average term of approximately 6.8 years) from Carthage, Texas, which represents
substantially all of the normal operating capacity. The pipeline
facilities from Keatchie, Louisiana in DeSoto Parish to interconnects with Texas
Gas near Bosco, Louisiana, and Columbia Gulf Transmission pipeline at Delhi,
Louisiana began flowing gas on December 31, 2007. The remaining
pipeline facilities from Delhi, Louisiana to Harrisville, Mississippi, began
flowing gas during January 2008. Currently, the three compressor
units at the Carthage compressor station are operational and the Partnership is
making all of its primary firm contractual deliveries into the Delhi, Louisiana
area and a substantial percentage of its primary firm contractual deliveries to
markets in Mississippi. The Partnership is in the process of
commissioning the remaining compression facilities associated with this project,
which the Partnership expects to be completed during the second quarter
2008.
Gulf Crossing Project. The
Partnership is pursuing construction of a new interstate pipeline that will
begin near Sherman, Texas and proceed to the Perryville, Louisiana
area. The project will be owned by Gulf Crossing, the Partnership’s
newly formed interstate pipeline subsidiary, and will consist of approximately
357 miles of 42-inch pipeline having up to approximately 1.7 Bcf of peak-day
transmission capacity. Additionally, Gulf Crossing has entered into,
subject to regulatory approval: (i) an operating lease for up to 1.4 Bcf per day
of capacity on the Partnership’s Gulf South pipeline system (including capacity
on the Southeast Expansion and capacity on a portion of the East Texas to
Mississippi Expansion) to make deliveries to an interconnect with
Transcontinental Pipe Line Company (Transco) in Choctaw County, Alabama (Transco
85); and (ii) an operating lease with Enogex, a third-party intrastate pipeline,
which will bring certain gas supplies to the Partnership’s
system. Customers have contracted at fixed rates for 1.1
Bcf per day of long-term firm transportation capacity (with a weighted average
term of approximately 9.5 years). The certificate application for
this project was filed with the FERC on June 19, 2007, and the Partnership
expects this project to be in service by the first quarter 2009.
Southeast
Expansion. On September 28, 2007, the FERC granted the
Partnership the authority to construct, own and operate a pipeline expansion
originating near Harrisville, Mississippi and extending to an interconnect with
Transco 85. This expansion will initially consist of approximately 112 miles of
42-inch pipeline having approximately 1.2 Bcf of peak-day transmission
capacity. To accommodate volumes expected to come from the Gulf
Crossing leased capacity discussed above, this project will be expanded to 2.2
Bcf of peak-day transmission capacity. In addition, the FERC approved
the Partnership’s 260 million cubic feet (MMcf) per day operating lease with
Destin Pipeline Company which will provide the Partnership enhanced access to
markets in Florida. Customers have contracted at fixed rates for 660
MMcf per day of firm transportation capacity on a long-term basis (with a
weighted-average term of 8.7 years), in addition to the capacity leased to Gulf
Crossing discussed above. Construction has commenced and the
Partnership expects this project to be in service during the second quarter
2008.
Fayetteville and Greenville
Laterals. The Partnership is pursuing the construction
of two laterals connected to 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 and consist of approximately
165 miles of 36-inch pipeline with an initial design of approximately 0.8 Bcf of
peak-day transmission capacity. 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 pipeline
with an initial design capacity of approximately 0.8 Bcf of peak-day
transmission capacity. The Greenville Lateral will allow customers to
access additional markets, primarily in the Midwest, Northeast and
Southeast. Customers have contracted at fixed rates for 575 MMcf per
day of initial capacity, with options for additional capacity that, if
exercised, could add 325 MMcf per day of capacity. The certificate
application for this project was filed with the FERC on July 11,
2007. The Partnership expects the first 60 miles of the Fayetteville
Lateral to be in service during the third quarter 2008 and the remainder of the
Fayetteville and Greenville Laterals to be in service during the first quarter
2009.
Pipeline Expansion Project Costs and
Timing. The total capital expenditures for the pipeline
expansion projects through December 31, 2007 were $1.2 billion.
Storage
Expansion Projects
Western Kentucky Storage Expansion
Phase II. In December 2006, the FERC issued a certificate
approving the Phase II storage expansion project which expanded the working gas
capacity in the Partnership’s western Kentucky storage complex by approximately
9.0 Bcf. This project is supported by binding commitments from
customers to contract on a long-term basis (with a weighted-average term of 8.3
years) for the full additional capacity at the Texas Gas maximum applicable
rate. The project was placed in service in November
2007.
Western Kentucky Storage Expansion
Phase III. The Partnership has signed 10-year precedent
agreements for 5.1 Bcf of storage capacity for its Phase III storage
project. The certificate application for this project was filed with
the FERC on June 25, 2007, seeking approval to develop up to 8.3 Bcf of new
storage capacity if Texas Gas is granted market-based rate authority for the new
storage capacity being proposed. The cost of this project will be
dependent on the ultimate size of the expansion. The Partnership expects 5.4 Bcf
of storage capacity to be in service in 2008.
Magnolia Storage Facility.
The Partnership was 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, the Partnership will be unable to place the cavern in service as
expected. As a result, the Partnership has elected to abandon that
cavern and is 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, Accounting for
the Impairment or Disposal of Long-Lived Assets, the carrying value of
the cavern and related facilities of approximately $45.1 million was tested for
recoverability. In the second quarter 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. The Partnership expects 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
it is determined in the future that the assets cannot be used in conjunction
with a new cavern, 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.
Pipeline
Integrity
The
Partnership expenses all costs incurred in the development of its integrity
management program, as defined by the Pipeline and Hazardous Materials Safety
Administration (PHMSA), and the ongoing inspecting, testing and reporting on the
condition of the pipeline system except costs incurred to replace segments of
pipeline or install software or equipment which are capitalized to the extent
they meet the requirements of the Partnership’s capitalization policy for those
types of expenditures. As of December 31, 2007, the Partnership has
invested approximately $12.3 million to develop and implement integrity
management program computer systems that allow it to dynamically assess various
pipeline risks on an integrated basis. The Partnership has
systematically used smart, in-line inspection tools to verify the integrity of
certain of its pipelines.
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 the agencies.
As
of December 31, 2007 and 2006, the Partnership had an accrued liability of
approximately $17.0 million and $18.4 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 approximately 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,
2007 and 2006, approximately $2.7 million and $3.5 million were recorded in
Other current liabilities. As of December 31, 2007 and 2006,
approximately $14.3 million and $14.9 million were recorded in Other Liabilities
and Deferred Credits.
On
October 20, 2006, Texas Gas received notice from the Environmental Protection
Agency (EPA) that Texas Gas is a potentially responsible party under the
Comprehensive Environmental Response, Compensation, and Liability Act 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.
On November 2, 2005, Texas Gas received
notice from the EPA that it has been identified as a de minimis settlement waste
contributor at a Mercury Refining Superfund Site located at the Towns of Colonie
and Guilderland, Albany County, New York. A de minimis party is one which
sent less than 1.0% of the total mercury and/or mercury bearing materials to the
site. As a de
minimis party, Texas Gas was offered participation in a settlement
agreement. The settlement amount for Texas Gas is approximately $0.1
million. The EPA held a 30-day public comment period regarding the
settlement, but has not acted on
it. In November 2007, Texas Gas received a notice from the EPA that
it was withdrawing its settlement offer and would be issuing a new settlement
offer in the future. Based upon the EPA’s notice it appears that
Texas Gas will still be considered a de minimis party, and it is
not expected that the new settlement will have a material effect on our
financial condition, results of operations or cash flows.
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 Partnership presently operates two
facilities in areas affected by non-attainment requirements for the current
ozone standard (eight-hour standard). As of December 31, 2007, the Partnership
had incurred costs of approximately $13.7 million for emission control
modifications of compression equipment located at facilities required to comply
with current CAA provisions, the Amendments and state implementation plans for
nitrogen oxide reductions. These costs are being recorded as
additions to PPE as the modifications are added. 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, however the Partnership is unable at this time to estimate
with any certainty the cost of any additions that may be required.
In June
2007, the EPA proposed to lower the 8-hour ozone standard relevant to
non-attainment areas. If adopted, new non-attainment areas will
likely be identified which may require additional emission controls for
compliance at as many as 14 facilities operated by the Partnership. The
anticipated effective date for compliance with the proposed standard if adopted
in its current state, is between 2013 and 2016.
In addition, the EPA and the State of
Texas promulgated new rules regarding hazardous air pollutants which required
additional controls or equipment modifications at seven Partnership
facilities. The Partnership has substantially complied and has
incurred costs of $2.6 million at these facilities.
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.
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. The actual
costs incurred will depend on the actual amount and extent of contamination
discovered, the final cleanup standards mandated by the EPA or other
governmental authorities and other factors.
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.
Lease
Commitments
The Partnership has various operating
lease commitments extending through the year 2018 generally covering offices and
equipment. Total lease expenses for the years ended December 31,
2007, 2006 and 2005 were approximately $7.3 million, $4.7 million and $4.2
million. The following table summarizes minimum future commitments
related to these items at December 31, 2007 (in millions):
|
2008
|
|
$ |
6.7 |
|
|
2009
|
|
|
5.5 |
|
|
2010
|
|
|
5.3 |
|
|
2011
|
|
|
3.0 |
|
|
2012
|
|
|
3.0 |
|
|
Thereafter
|
|
|
13.2 |
|
|
Total
|
|
$ |
36.7 |
|
Commitments
for Construction
The Partnership incurred $1.2 billion
of capital expenditures in 2007. The Partnership’s future capital
commitments as of December 31, 2007, for contracts already authorized are
expected to approximate the following amounts (in millions):
|
Less
than 1 year
|
|
$ |
834.7 |
|
|
1-3
years
|
|
|
16.4 |
|
|
4-5
years
|
|
|
- |
|
|
More
than 5 years
|
|
|
- |
|
|
Total
|
|
$ |
851.1 |
|
Note
4: Property, Plant and Equipment
On
December 31, 2007, the Partnership placed in service a portion of its East Texas
to Mississippi expansion project from Keatchie, Louisiana in DeSoto Parish to
its interconnects with Texas Gas near Bosco, Louisiana and Columbia Gulf
Transmission pipeline at Delhi, Louisiana. As a result, approximately
$476.0 million was transferred from construction work in progress to depreciable
PPE. The assets will generally be depreciated over a term of 35
years. The remaining pipeline to Harrisville, Mississippi was placed
in service during January 2008 and the related compression at one of the three
compressor stations went in service in January and February 2008.
In
November 2007, the Partnership placed in service Phase II of its Western
Kentucky storage expansion project which increased the working gas capacity of
its Texas Gas system by 9.0 Bcf, resulting in reclassification of approximately
$50.0 million from construction work in progress to depreciable
PPE. As a result of the expansion, approximately 4.0 Bcf of base gas
was sold in 2007, resulting in a total gain of $22.0 million including gains on
the settlement of related derivatives.
In
conjunction with a review of its offshore pipeline assets in the South Timbalier
Bay area, offshore Louisiana, the Partnership discovered that approximately 6 to
7 miles of offshore pipeline did not have adequate cover. In 2007,
the Partnership entered into an agreement to sell for a nominal amount the
offshore pipeline assets in their current condition 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 the liability to re-cover
the pipeline and other maintenance issues. The total charge for 2007
related to the remediation payment and impairment charge was $9.3 million, $4.8
million of which was recorded to Operation and maintenance expense and the
remainder to Asset impairment. The Partnership expects the sale to be
completed in 2008.
In 2006,
the Partnership received $4.0 million in settlement of a lawsuit concerning the
parties’ rights and obligations under a lease for a platform being
decommissioned in the Eugene Island area in the Gulf of Mexico. The
proceeds were used to offset the costs of rebuilding certain offshore
facilities. Also, in 2006, the Partnership received $2.5 million for
the sale of offshore transmission facilities in the Gulf of Mexico at West
Cameron 294. The sale of the facilities was considered a normal retirement. In
accordance with the composite method of accounting for PPE, the proceeds and the
related book value of the plant were recorded to accumulated depreciation which
is classified within PPE, net on the Consolidated Balance
Sheets.
The
following table presents the Partnership’s PPE as of December 31, 2007 and 2006
(in thousands):
|
Category
|
|
2007
Class Amount
|
|
|
Weighted-Average
Useful Lives (Years)
|
|
|
2006
Class Amount
|
|
|
Weighted-Average
Useful Lives (Years)
|
|
|
Depreciable
plant:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Intangible
|
|
$ |
24,897 |
|
|
|
9
|
|
|
$ |
18,901 |
|
|
|
9
|
|
|
Gathering
|
|
|
92,828 |
|
|
|
19
|
|
|
|
90,787 |
|
|
|
19
|
|
|
Storage
|
|
|
198,110 |
|
|
|
49
|
|
|
|
163,323 |
|
|
|
48
|
|
|
Transmission
|
|
|
2,125,864 |
|
|
|
43
|
|
|
|
1,601,064 |
|
|
|
45
|
|
|
General
|
|
|
79,605 |
|
|
|
15
|
|
|
|
63,698 |
|
|
|
16
|
|
|
Total
utility depreciable plant
|
|
|
2,521,304 |
|
|
|
41
|
|
|
|
1,937,773 |
|
|
|
43
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-depreciable:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Land
|
|
|
9,643 |
|
|
|
|
|
|
|
9,386 |
|
|
|
|
|
|
Storage
|
|
|
71,182 |
|
|
|
|
|
|
|
85,392 |
|
|
|
|
|
|
Construction
work in progress
|
|
|
951,433 |
|
|
|
|
|
|
|
165,916 |
|
|
|
|
|
|
Other
|
|
|
14,326 |
|
|
|
|
|
|
|
13,381 |
|
|
|
|
|
|
Total
other
|
|
|
1,046,584 |
|
|
|
|
|
|
|
274,075 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
PPE
|
|
|
3,567,888 |
|
|
|
|
|
|
|
2,211,848 |
|
|
|
|
|
|
Less: accumulated
depreciation
|
|
|
262,477 |
|
|
|
|
|
|
|
187,412 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
PPE, net
|
|
$ |
3,305,411 |
|
|
|
|
|
|
$ |
2,024,436 |
|
|
|
|
|
The non-transmission assets have
weighted-average useful lives of 33 years and 32 years as of December 31, 2007
and 2006 and depreciable asset values of $395.4 million and $336.7 million as of
December 31, 2007 and 2006. 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, particularly the
Bistineau storage facility of which the Partnership owns 91.7%, the Mobile Bay
Pipeline of which the Partnership owns 50.0%, offshore pipeline assets, onshore
pipeline and gathering assets, in each of 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. As of December 31, 2007, the gross investment in PPE related
to these assets was $87.5 million, approximately $57.0 million, $12.8 million
and $11.2 million of which was due to the Bistineau storage, offshore assets and
Mobile Bay Pipeline interests. The accumulated depreciation was $17.4
million, approximately $5.0 million, $10.4 million and $1.0 million of which was
due to the Bistineau storage, offshore assets and Mobile Bay Pipeline
interests.
Note
5: Asset Retirement Obligations
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 when
removed from certain compressor stations and meter station
buildings. 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. Abatement of asbestos consists of removal, transportation and
disposal. Legal obligations exist for certain other Partnership assets; however,
the fair value of the obligations cannot be determined because the end of the
system life is potentially indefinite and therefore 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 AROs (in
thousands):
|
|
|
2007
|
|
|
2006
|
|
|
Balance
at beginning of year
|
|
$ |
14,307 |
|
|
$ |
14,074 |
|
|
Liabilities
recorded
|
|
|
1,529 |
|
|
|
(366 |
) |
|
Liabilities
settled
|
|
|
(499 |
) |
|
|
- |
|
|
Accretion
expense
|
|
|
722 |
|
|
|
599 |
|
|
Balance
at end of year
|
|
$ |
16,059 |
|
|
$ |
14,307 |
|
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 of years between 2112 through
2162. The Partnership believes that the spray-applied asbestos can be
maintained, in place, undisturbed, indefinitely, 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.
Depreciation rates for utility plant at
Texas Gas, as approved by the FERC are comprised of two components: one based on
economic service life (capital recovery) and one based on net costs of removal
(negative salvage). Texas Gas accrues and collects in its rates
estimated net costs of removal of long-lived assets through negative salvage
expense, which does not represent an existing legal obligation. The
Partnership has classified $42.4 million and $39.6 million as of December 31,
2007 and 2006, in the accompanying Consolidated Balance Sheets as Provision for
other asset retirement.
Note
6: Regulatory Assets and Liabilities
The amounts recorded as regulatory
assets and liabilities in the Consolidated Balance Sheets as of December 31,
2007 and 2006, 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 change in Boardwalk Pipelines’ tax status. 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. None of the regulatory assets shown
below were earning a return as of December 31, 2007 and 2006 (in
thousands):
|
|
|
2007
|
|
|
2006
|
|
|
Regulatory
Assets:
|
|
|
|
|
|
|
|
Pension
|
|
$ |
9,490 |
|
|
$ |
7,820 |
|
|
Tax
effect of AFUDC equity
|
|
|
6,381 |
|
|
|
6,794 |
|
|
Unamortized
debt expense and premium on reacquired debt
|
|
|
10,705 |
|
|
|
11,703 |
|
|
Postretirement
benefits other than pension
|
|
|
5,414 |
|
|
|
10,569 |
|
|
Fuel
tracker
|
|
|
943 |
|
|
|
5,783 |
|
|
Imbalances/storage
valuation tracker
|
|
|
- |
|
|
|
37 |
|
|
Total
regulatory assets
|
|
$ |
32,933 |
|
|
$ |
42,706 |
|
|
Regulatory
Liabilities:
|
|
|
|
|
|
|
|
System
management/cashout tracker
|
|
$ |
242 |
|
|
|
- |
|
|
Provision
for asset retirement
|
|
|
42,380 |
|
|
$ |
39,644 |
|
|
Unamortized
discount on long-term debt
|
|
|
(1,677 |
) |
|
|
(1,851 |
) |
|
Postretirement
benefits other than pension
|
|
|
12,448 |
|
|
|
- |
|
|
Total
regulatory liabilities
|
|
$ |
53,393 |
|
|
$ |
37,793 |
|
Note
7: Financing
Offerings
of Common Units
In
addition to its IPO in November 2005, the Partnership has completed three
follow-on public equity offerings. The proceeds of the follow-on
offerings have been and will be used to finance the Partnership’s expansion
activities discussed in Note 3. In addition to funds received from
the public, the general partner has concurrently contributed amounts to maintain
its 2.0% interest in the Partnership. The following table shows the
key information related to the follow-on public equity offerings (in millions,
except the offering price):
|
Month
of Offering
|
|
Number
of Common Units
|
|
|
Offering
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
|
|
|
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
|
|
The
Partnership completed its IPO in November 2005, resulting in net proceeds of
approximately $271.4 million. After the IPO, the Partnership had 68.3
million common units issued and outstanding, of which 15.0 million were held by
the public. In
connection with the IPO, the Partnership and its affiliates effected a number of
transactions, including among others:
|
·
|
the
distribution by Boardwalk Pipelines of $126.4 million of cash, receivables
and other working capital assets to
BPHC;
|
|
·
|
the
contribution, directly and indirectly, by BPHC of all the equity interests
of Boardwalk Pipelines to the
Partnership;
|
|
·
|
the
Partnership’s reimbursement to BPHC for $42.1 million of capital
expenditures it incurred in connection with the acquisition of Gulf
South;
|
|
·
|
the
assumption by the Partnership of $250.0 million of indebtedness to Loews
from BPHC;
|
|
·
|
the
issuance by the Partnership of limited partner interest in the Partnership
to BPHC; and
|
|
·
|
the
issuance by the Partnership of a 2.0% general partner interest and all of
its incentive distribution rights to Boardwalk
GP.
|
Senior
Unsecured Debt
On August
17, 2007, the Partnership received net proceeds of approximately $495.3 million
after deducting initial purchaser discounts and offering expenses of $4.7
million from the sale of $225.0 million of 5.75% senior unsecured notes of Gulf
South due August 15, 2012, and $275.0 million of 6.30% senior unsecured notes of
Gulf South due August 15, 2017. Interest on the notes will be payable
on February 15 and August 15 of each year, beginning on February 15,
2008.
On
November 21, 2006, Boardwalk Pipelines received net proceeds of approximately
$248.3 million after deducting underwriting discounts and commissions and
offering expenses of $1.7 million from its offering of $250.0 million of 5.88%
senior unsecured notes, which are guaranteed by the
Partnership. Interest on the notes will be payable on May 15 and
November 15 of each year, beginning on May 15, 2007. The notes will
mature on November 15, 2016.
The Gulf
South and Boardwalk Pipelines notes are redeemable, in whole or in part, at the
Partnership’s option at any time, at a redemption price equal to the greater of
100.0% 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 Treasury rate plus 20 basis
points in the case of the 2012 Gulf South notes and 2016 Boardwalk Pipelines
notes, or 25 basis points in the case of the 2017 Gulf South notes, plus accrued
and unpaid interest, if any. Other customary covenants apply,
including those concerning events of default.
The following table represents all
long-term debt issues outstanding (in thousands):
|
|
|
December
31,
|
|
|
|
|
2007
|
|
|
2006
|
|
|
Boardwalk
Pipelines
|
|
|
|
|
|
|
|
5.88%
Notes due 2016
|
|
$ |
250,000 |
|
|
$ |
250,000 |
|
|
5.20%
Notes due 2018
|
|
|
185,000 |
|
|
|
185,000 |
|
|
5.50%
Notes due 2017
|
|
|
300,000 |
|
|
|
300,000 |
|
|
|
|
|
|
|
|
|
|
|
|
Gulf
South
|
|
|
|
|
|
|
|
|
|
6.30%
Notes due 2017
|
|
|
275,000 |
|
|
|
- |
|
|
5.75%
Notes due 2012
|
|
|
225,000 |
|
|
|
- |
|
|
5.05%
Notes due 2015
|
|
|
275,000 |
|
|
|
275,000 |
|
|
|
|
|
|
|
|
|
|
|
|
Texas
Gas
|
|
|
|
|
|
|
|
|
|
7.25%
Debentures due 2027
|
|
|
100,000 |
|
|
|
100,000 |
|
|
4.60%
Notes due 2015
|
|
|
250,000 |
|
|
|
250,000 |
|
|
|
|
|
1,860,000 |
|
|
|
1,360,000 |
|
|
Unamortized
debt discount
|
|
|
(12,086 |
) |
|
|
(9,080 |
) |
|
Total
long-term debt
|
|
$ |
1,847,914 |
|
|
$ |
1,350,920 |
|
As of December 31, 2007 and 2006, the
weighted-average interest rate of the Partnership’s long-term debt was 5.82% and
5.40%.
The long-term debt has 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. The Partnership relies on distributions
and advances from the operating subsidiaries to fulfill its debt
obligations. All debt obligations are unsecured. At
December 31, 2007, Boardwalk Pipelines and the operating subsidiaries were in
compliance with their debt covenants.
Revolving
Credit Facility
The Partnership maintains a $1.0
billion revolving credit facility, which was increased from $700.0 million in
November 2007, under which Boardwalk Pipelines, Gulf South and Texas Gas each
may borrow funds, up to applicable sub-limits. Interest on amounts drawn under
the credit facility is payable at a floating rate equal to an applicable spread
per annum over LIBOR or a base rate defined as the greater of the prime rate or
the Federal funds rate plus 50 basis points. Under the terms of the agreement,
each of the borrowers must maintain a minimum ratio, as of the last day of each
fiscal quarter, of consolidated total debt to consolidated earnings before
interest, income taxes and depreciation and amortization (as defined in the
agreement), measured for the preceding twelve months, of not more than five to
one. The revolving credit facility has a maturity date of June 29,
2012.
As of
December 31, 2007, no funds were drawn under the facility, however, the
Partnership had outstanding letters of credit under the facility for $185.6
million to support certain obligations associated with the Fayetteville and
Greenville Lateral and Gulf Crossing expansion projects which reduced the
available capacity under the facility by such amount. As of December
31, 2007, the Partnership was in compliance with all the covenant requirements
under the credit agreement. During 2006, the Partnership had borrowed
and repaid $90.0 million under this credit facility. The interest
rates on the borrowings were 5.55% to 5.73%.
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.
Certain
volumes of gas stored underground are available for sale and subject to
commodity price risk. At December 31, 2007 and December 31, 2006, approximately
$16.3 million and $14.0 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.
As a
result of the approval of Phase II of the Western Kentucky storage expansion
project, approximately 4.8 Bcf of gas stored underground with a book value of
$11.3 million became available for sale, although it was subsequently determined
that 0.8 Bcf of the gas would be used for line pack for the Partnership’s
Fayetteville and Greenville Lateral expansion project. The
Partnership entered into derivatives to hedge the price exposure related to 3.0
Bcf of the storage gas sold under forward sales agreements, which were
designated as cash flow hedges during February 2007, concurrent with the
designation of the forward sales agreements as normal sales. The derivatives
were settled in March 2007, when the sales price was determined. The
Partnership entered into derivatives related to the remaining 1.0 Bcf of storage
gas available for sale which were not designated as cash flow hedges and have
been marked to fair value through earnings. In the third and fourth
quarters 2007, all of the storage gas available for sale was sold and the
related derivatives were settled resulting in a gain of $22.0
million. The gain was included in Net gain on disposal of operating
assets and related contracts on the Consolidated Statements of
Income.
In the
second quarter 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 the Partnership’s Gulf Crossing and Southeast
Expansion projects, approximately 1.3 Bcf of which remained outstanding at
December 31, 2007. The derivatives were not designated as hedges and
were marked to fair value through earnings resulting in a loss of $1.0 million
for the year ended December 31, 2007.
In August
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 reference rate on the rate lock was 4.74%. Under the terms
of the rate lock, the counterparty would pay the Partnership a settlement amount
if the 10-year Treasury rate is greater than the reference rate on February 1,
2008. Conversely, the Partnership would pay the counterparty a settlement amount
if the 10-year Treasury rate is less than the reference rate. 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
income for the fair value of the rate lock. On February 1, 2008, the
Partnership paid the counterparty approximately $15.0 million to settle the rate
lock. The effective portion of the loss will be recognized in
Interest expense over the term of the related debt to be issued.
In August
2006, the Partnership entered into Treasury rate locks with two counterparties
each for a notional amount of $100.0 million of principal to hedge the risk
attributable to changes in the risk-free component of forward 10-year interest
rates through August 1, 2007. The reference rates on the rate locks were 5.00%
and 4.96%. The rate locks were designated as cash flow hedges in
accordance with SFAS No. 133. In August 2007, the rate locks were
settled resulting in payments to the counterparties of approximately $3.9
million. The effective amount of the hedge, of approximately $3.4
million is being amortized to interest expense over the 10-year term of the
related notes which were issued in August 2007.
With the
exception of the derivatives related to storage gas volumes and line pack gas
purchases referred to above, the derivatives related to the sale or purchase of
natural gas, cash for fuel reimbursement and debt issuance 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 contracts designated as cash flow
hedges are deferred as a component of Accumulated other comprehensive
income. The deferred gains and losses are recognized in the
Consolidated Statements of Income when the anticipated transactions affect
earnings. 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 project, 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 fair
values of derivatives existing as of December 31, 2007 and 2006, were included
in the following captions in the Consolidated Balance Sheets (in
millions):
|
|
|
December
31, 2007
|
|
|
December
31, 2006
|
|
|
Prepaid
expenses and other current assets
|
|
$ |
2.2 |
|
|
$ |
13.7 |
|
|
Other
current liabilities
|
|
|
9.4 |
|
|
|
5.1 |
|
|
Accumulated
other comprehensive (loss) income
|
|
|
(8.9 |
) |
|
|
8.3 |
|
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. 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. No ineffectiveness
was recorded during 2005. The Partnership did not discontinue any cash flow
hedges during the years ended December 31, 2007 and 2006.
Note
9: 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 will be 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. During
2006, the Partnership funded approximately $18.0 million to the Texas Gas
retirement plan including approximately $11.4 million of additional funding that
the Partnership elected to provide to immediately improve the funded status of
the plan. Due to the additional funding, the Partnership was not required to
fund any amount to the Texas Gas retirement plan in 2007 and does not expect to
fund any amount in 2008. Through December 31, 2007, 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 Pensions (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 $0.9 million, $0.3 million
and $3.9 million to the plan in 2007, 2006 and 2005. 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 2008.
In May
2006, as part of an overall cost reduction program, Texas Gas announced to its
employees and retirees a plan to make changes to its postretirement benefits
plan beginning January 1, 2007. Under the amended plan, Texas Gas will cap its
contributions toward medical benefit coverage for retirees younger than age 65
to the amount contributed for each retiree in 2006. For retirees age 65 and
older, Texas Gas will cap its contribution at three times the 2006 amount. In
addition, Texas Gas will no longer cover prescription drug costs for retirees
age 65 and older. The changes resulted in an estimated reduction in
the accumulated postretirement benefit obligation (APBO) of approximately $75.3
million. For the year ended December 31, 2006, the change resulted in
a reduction to net periodic benefit cost of $9.0 million from the amount that
would otherwise have been recognized.
Due to
the Texas Gas rate case settlement in the first quarter 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. Texas Gas
is precluded from seeking future recovery of additional amounts for PBOP
costs.
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 would provide
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, 2007 and 2006, were as follows (in
thousands):
|
|
|
Retirement
Plans
|
|
|
PBOP
|
|
|
|
|
For
the Year Ended
December
31,
|
|
|
For
the Year Ended
December
31,
|
|
|
|
|
2007
|
|
|
2006
|
|
|
2007
|
|
|
2006
|
|
|
Change
in benefit obligation:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Benefit
obligation at beginning of period
|
|
$ |
136,886 |
|
|
$ |
116,931 |
|
|
$ |
65,341 |
|
|
$ |
134,188 |
|
|
Service
cost
|
|
|
3,929 |
|
|
|
4,432 |
|
|
|
608 |
|
|
|
1,319 |
|
|
Interest
cost
|
|
|
6,599 |
|
|
|
6,695 |
|
|
|
3,274 |
|
|
|
5,147 |
|
|
Plan
participants’ contributions
|
|
|
- |
|
|
|
- |
|
|
|
828 |
|
|
|
1,509 |
|
|
Actuarial
(gain) loss
|
|
|
(2,197 |
) |
|
|
6,326 |
|
|
|
(9,343 |
) |
|
|
4,902 |
|
|
Benefits
paid
|
|
|
(575 |
) |
|
|
(3,576 |
) |
|
|
(4,083 |
) |
|
|
(7,633 |
) |
|
Retirement
/ PBOP plan amendment
|
|
|
3 |
|
|
|
73 |
|
|
|
- |
|
|
|
(75,271 |
) |
|
Settlement
|
|
|
(36,141 |
) |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
Special
termination benefits (ERIP)
|
|
|
- |
|
|
|
6,005 |
|
|
|
- |
|
|
|
884 |
|
|
Retiree
drug subsidy
|
|
|
- |
|
|
|
- |
|
|
|
309 |
|
|
|
296 |
|
|
Benefit
obligation at end of period
|
|
$ |
108,504 |
|
|
$ |
136,886 |
|
|
$ |
56,934 |
|
|
$ |
65,341 |
|
|
Change
in plan assets:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair
value of plan assets at beginning of period
|
|
$ |
121,125 |
|
|
$ |
96,193 |
|
|
$ |
80,218 |
|
|
$ |
79,462 |
|
|
Actual
return on plan assets
|
|
|
6,489 |
|
|
|
10,468 |
|
|
|
6,381 |
|
|
|
6,539 |
|
|
Benefits
paid
|
|
|
(575 |
) |
|
|
(3,576 |
) |
|
|
(4,082 |
) |
|
|
(7,633 |
) |
|
Company
contributions
|
|
|
395 |
|
|
|
18,040 |
|
|
|
883 |
|
|
|
341 |
|
|
Plan
participants’ contributions
|
|
|
- |
|
|
|
- |
|
|
|
828 |
|
|
|
1,509 |
|
|
Settlement
|
|
|
(36,141 |
) |
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
Fair
value of plan assets at end of period
|
|
$ |
91,293 |
|
|
$ |
121,125 |
|
|
$ |
84,228 |
|
|
$ |
80,218 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Funded
status
|
|
$ |
(17,211 |
) |
|
$ |
(15,761 |
) |
|
$ |
27,294 |
|
|
$ |
14,877 |
|
|
Items
not yet recognized as components of net periodic cost:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Prior
service cost
|
|
$ |
71 |
|
|
$ |
73 |
|
|
$ |
(62,984 |
) |
|
$ |
(70,744 |
) |
|
Net
actuarial loss
|
|
|
11,731 |
|
|
|
17,967 |
|
|
|
10,658 |
|
|
|
22,316 |
|
|
Total
|
|
$ |
11,802 |
|
|
$ |
18,040 |
|
|
$ |
(52,326 |
) |
|
$ |
(48,428 |
) |
The Partnership does not anticipate
that any plan assets will be returned to the Partnership during
2008. At December 31, 2007 and 2006, the following aggregate
information relates only to the underfunded retirement plan (in
thousands):
|
|
|
For
the Year Ended December 31,
|
|
|
|
|
2007
|
|
|
2006
|
|
|
Projected
benefit obligation
|
|
$ |
108,504 |
|
|
$ |
136,886 |
|
|
Accumulated
benefit obligation
|
|
|
94,590 |
|
|
|
118,147 |
|
|
Fair
value of plan assets
|
|
|
91,293 |
|
|
|
121,125 |
|
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, 2007,
2006 and 2005 were the following (in thousands):
|
|
|
Retirement
Plans
|
|
|
PBOP
|
|
|
|
|
For
the Year Ended December 31,
|
|
|
For
the Year Ended December 31,
|
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
Service
cost
|
|
$ |
3,929 |
|
|
$ |
4,432 |
|
|
$ |
4,067 |
|
|
$ |
608 |
|
|
$ |
1,319 |
|
|
$ |
2,076 |
|
|
Interest
cost
|
|
|
6,599 |
|
|
|
6,695 |
|
|
|
6,283 |
|
|
|
3,274 |
|
|
|
5,147 |
|
|
|
7,222 |
|
|
Expected
return on plan assets
|
|
|
(7,146 |
) |
|
|
(7,131 |
) |
|
|
(6,859 |
) |
|
|
(4,734 |
) |
|
|
(4,653 |
) |
|
|
(4,632 |
) |
|
Amortization
of prior service credit
|
|
|
5 |
|
|
|
- |
|
|
|
- |
|
|
|
(7,760 |
) |
|
|
(4,527 |
) |
|
|
- |
|
|
Amortization
of unrecognized net loss
|
|
|
242 |
|
|
|
713 |
|
|
|
300 |
|
|
|
668 |
|
|
|
1,112 |
|
|
|
362 |
|
|
Settlement
charge
|
|
|
4,454 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
Special
termination benefit (ERIP)
|
|
|
- |
|
|
|
6,005 |
|
|
|
- |
|
|
|
- |
|
|
|
884 |
|
|
|
- |
|
|
Regulatory
asset (increase) decrease
|
|
|
(1,669 |
) |
|
|
(3,979 |
) |
|
|
(3,713 |
) |
|
|
5,415 |
|
|
|
7,337 |
|
|
|
- |
|
|
Net
periodic pension expense
|
|
$ |
6,414 |
|
|
$ |
6,735 |
|
|
$ |
78 |
|
|
$ |
(2,529 |
) |
|
$ |
6,619 |
|
|
$ |
5,028 |
|
The decrease in the regulatory asset
for PBOP was due primarily to the amortization of costs incurred in prior
years. 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 thousands):
|
|
|
Retirement
Plans
|
|
|
PBOP
|
|
|
2008
|
|
$ |
3,397 |
|
|
$ |
4,693 |
|
|
2009
|
|
|
3,633 |
|
|
|
4,499 |
|
|
2010
|
|
|
5,783 |
|
|
|
4,294 |
|
|
2011
|
|
|
7,140 |
|
|
|
4,282 |
|
|
2012
|
|
|
9,391 |
|
|
|
4,116 |
|
|
2013-2017
|
|
|
67,556 |
|
|
|
19,997 |
|
Weighted
–Average Assumptions
The Partnership’s weighted-average
asset allocations at December 31, 2007 and 2006, for both the qualified
retirement plan and PBOP trusts by category were as follows:
|
|
|
Retirement
Plans
|
|
|
PBOP
|
|
|
|
|
December
31, 2007
|
|
|
December
31, 2006
|
|
|
December
31, 2007
|
|
|
December
31, 2006
|
|
|
Debt
securities
|
|
|
45.5
|
% |
|
|
49.1 |
% |
|
|
40.4 |
% |
|
|
46.6 |
% |
|
Equity
securities
|
|
|
22.7
|
% |
|
|
27.1 |
% |
|
|
22.1 |
% |
|
|
29.2 |
% |
|
Limited
partnerships
|
|
|
13.3
|
% |
|
|
9.3 |
% |
|
|
25.2 |
% |
|
|
23.6 |
% |
|
Comingled
funds
|
|
|
12.5
|
% |
|
|
9.4 |
% |
|
|
- |
|
|
|
- |
|
|
Cash,
short-term investments and other
|
|
|
6.0
|
% |
|
|
5.1 |
% |
|
|
12.3 |
% |
|
|
0.6 |
% |
|
Total
|
|
|
100.0 |
% |
|
|
100.0 |
% |
|
|
100.0 |
% |
|
|
100.0 |
% |
The Partnership employs a total-return
approach whereby a mix of equities and fixed income investments is used to
maximize the long-term return of 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 Partnership’s goal for 2007 was
to allocate between 30.0% and 50.0% 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/liability studies and quarterly
investment portfolio reviews.
Weighted-average
assumptions used to determine benefit obligations for the years ended December
31, 2007 and 2006 were the following:
| |
|
Retirement
Plans
|
|
|
PBOP
|
|
| |
|
For
the Year Ended
December
31,
|
|
|
For
the Year Ended
December
31,
|
|
| |
|
2007
|
|
|
2006
|
|
|
2007
|
|
|
2006
|
|
|
Discount
rate
|
|
|
6.00 |
% |
|
|
5.75 |
% |
|
|
6.00 |
% |
|
|
5.75 |
% |
|
Rate
of compensation increase
|
|
|
4.00 |
% |
|
|
5.50 |
% |
|
|
- |
|
|
|
- |
|
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,
|
|
|
2007
|
2006
|
2005
|
|
2007
|
2006
|
2005
|
|
Discount
rate
|
5.94%
|
5.63%
|
5.88%
|
|
5.75%
|
5.63%
to
5.75%
|
5.88%
|
|
Expected
return on plan assets
|
7.50%
|
7.50%
|
7.50%
|
|
5.00%
to
6.15%
|
5.00%
to
6.15%
|
5.00%
to
6.15%
|
|
Rate
of compensation increase
|
5.50%
|
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 health care-cost-trend rates would have
had the following effects on amounts reported for the year ended December 31,
2007 (in thousands):
|
Effect of 1% Increase:
|
|
2007
|
|
|
Benefit
obligation at end of year
|
|
$ |
1,212 |
|
|
Total
of service and interest costs for year
|
|
|
81 |
|
|
Effect of 1% Decrease:
|
|
|
|
|
Benefit
obligation at end of year
|
|
$ |
(1,481 |
) |
|
Total
of service and interest costs for year
|
|
|
(102 |
) |
For
measurement purposes, at December 31, 2007, health care costs for the plans were
assumed to increase 9.0% for 2008-2009 grading down to 5.0% in 0.5% annual
increments for participants not eligible for Medicare and 10.0% grading down to
5.0% in 0.5% annual increments for participants eligible for
Medicare. For December 31, 2006, measurement purposes, health care
costs for the plans were assumed to increase 9.0% for 2007-2008, grading down to
5.0% in 0.5% annual increments for participants not eligible for Medicare and
10.5% grading down to 5.0% 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 $5.3 million, $5.1 million and $3.9 million for the
years ended December 31, 2007, 2006 and 2005.
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, 2007 and 2006, and
changes during the years ended December 31, 2007 and 2006, is presented
below:
|
|
|
Phantom
GP Units
|
|
|
Total
Fair Value
(in
thousands)
|
|
|
Weighted-Average
Vesting Period
(in
years)
|
|
|
Granted 7/15/2006
(a)
|
|
|
125 |
|
|
$ |
3,398 |
|
|
|
3.5 |
|
|
Granted
12/20/2006 (a)
|
|
|
125 |
|
|
|
6,250 |
|
|
|
4.0 |
|
|
Outstanding
@ 12/31/2006 (b)
|
|
|
250 |
|
|
|
12,500 |
|
|
|
3.5 |
|
|
Granted
(a)
|
|
|
116 |
|
|
|
5,800 |
|
|
|
4.0 |
|
|
Forfeited
|
|
|
(5 |
) |
|
|
- |
|
|
|
- |
|
|
Outstanding
@ 12/31/2007 (b)
|
|
|
361 |
|
|
|
18,050 |
|
|
|
3.0 |
|
|
(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 $3.3
million and $0.8 million in Administrative and general expenses during 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, 2007, of
$13.9 million will be recognized over the average remaining vesting period of
approximately 3.0 years. Approximately 139 Phantom GP Units were
available for grant under the plan at December 31, 2007.
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 has
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 50.0% on the second
anniversary of the grant date and 50.0% 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 and unit appreciation rights
under the plan.
A summary
of the status of the Partnership’s LTIP as of December 31, 2007, 2006 and 2005,
and changes during the years ended December 31, 2007 and 2006, is presented
below:
|
|
|
Phantom
Common Units
|
|
|
Total
Fair Value
(in
thousands)
|
|
|
Weighted-Average
Vesting Period
(in
years)
|
|
|
Outstanding
@ 12/31/2005 (a)
|
|
|
29,177 |
|
|
$ |
525 |
|
|
|
2.3 |
|
|
Granted
(b)
|
|
|
49,387 |
|
|
|
1,537 |
|
|
|
2.5 |
|
|
Forfeited
|
|
|
(3,479 |
) |
|
|
- |
|
|
|
- |
|
|
Outstanding
@ 12/31/2006 (a)
|
|
|
75,085 |
|
|
|
2,413 |
|
|
|
2.2 |
|
|
Granted
(b)
|
|
|
49,966 |
|
|
|
1,530 |
|
|
|
2.5 |
|
|
Vested
(c)
|
|
|
(14,431 |
) |
|
|
- |
|
|
|
- |
|
|
Forfeited
|
|
|
(2,099 |
) |
|
|
- |
|
|
|
- |
|
|
Outstanding
@ 12/31/2007 (a)
|
|
|
108,521 |
|
|
|
3,493 |
|
|
|
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.
|
|
(c)
|
Represents
cash paid for vested awards.
|
The fair
value of the awards at the date of grant was based on the formula contained in
the LTIP. 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 and $0.4 million in
Administrative and general expenses during 2007 and 2006 for the ratable
recognition of the Phantom Common Unit awards fair value. Amounts
recognized in 2005 were immaterial. The total estimated remaining
unrecognized compensation expense related to the Phantom Common Units
outstanding at December 31, 2007, of $2.0 million will be recognized over the
average remaining vesting period of approximately 1.8 years.
On
February 27, 2007, the general partner purchased 1,500 of the Partnership’s
common units in the open market at a price of $36.61 per unit and on March 23,
2006, the general partner purchased 1,000 common units in the open market at a
price of $21.38 per unit. These units were granted under the LTIP to
the independent directors as part of their director compensation. At
December 31, 2007, 3,522,500 units were available for grants under
LTIP.
Note
10: 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 contractual participation rights which
are incentive distribution rights (IDRs) in accordance with the partnership
agreement as follows:
|
|
|
|
|
|
|
|
|
|
|
|
Total
Quarterly Distribution
|
|
Marginal Percentage
Interest in
Distributions
|
|
|
Target
Amount
|
Common
and
Subordinated
Unitholders
|
|
General
Partner
|
|
Minimum
Quarterly Distribution
|
|
$0.3500
|
|
98.0%
|
2.0%
|
|
First
Target Distribution
|
|
up to $0.4025
|
|
98.0%
|
2.0%
|
|
Second
Target Distribution
|
|
above $0.4025 up to $0.4375
|
|
85.0%
|
15.0%
|
|
Third
Target Distribution
|
|
above
$0.4375 up to $0.5250
|
|
75.0%
|
25.0%
|
|
Thereafter
|
|
above
$0.5250
|
|
50.0%
|
50.0%
|
The amounts
reported for net income per limited partner unit on the Consolidated
Statements of Income for the years ended December 31, 2007, 2006 and 2005,
were adjusted to take into account an assumed allocation to the general
partner's incentive distribution rights. Payments made on account of the
incentive distribution rights 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 thousands, except weighted average units
and per unit data):
|
|
|
|
|
|
|
|
|
|
|
For
the Year Ended
December
31,
|
|
|
For
the Period November 15, 2005
through
December
31,
|
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
Limited
partners' interest in net income
|
|
$ |
220,726 |
|
|
$ |
193,599 |
|
|
$ |
35,272 |
|
|
Less
assumed allocation to incentive distribution rights
|
|
|
4,323 |
|
|
|
5,187 |
|
|
|
- |
|
|
Net
income available to limited partners
|
|
|
216,403 |
|
|
|
188,412 |
|
|
|
35,272 |
|
|
Less
assumed allocation to subordinated units
|
|
|
61,949 |
|
|
|
61,087 |
|
|
|
11,382 |
|
|
Net
income available to common units
|
|
$ |
154,454 |
|
|
$ |
127,325 |
|
|
$ |
23,890 |
|
|
Weighted
average common units
|
|
|
82,510,917 |
|
|
|
68,977,766 |
|
|
|
68,256,122 |
|
|
Weighted
average subordinated units
|
|
|
33,093,878 |
|
|
|
33,093,878 |
|
|
|
33,093,878 |
|
|
Net
income per limited partner unit –
common
and subordinated units
|
|
$ |
1.87 |
|
|
$ |
1.85 |
|
|
$ |
0.35 |
|
The Partnership has declared quarterly
distributions per unit to unitholders of record, including common and
subordinated units and the 2.0% general partner interest and IDRs held by its
general partner as follows (in thousands, except distribution per
unit):
|
Payable
Date
|
|
Distribution
per Unit
|
|
|
Amount
Paid to Common and Subordinated Unitholders
|
|
|
Amount
Paid to General Partner (Including IDRs)
|
|
|
February
25, 2008
|
|
$ |
0.46 |
|
|
$ |
56,925 |
|
|
$ |
2,709 |
|
|
November
12, 2007
|
|
|
0.45 |
|
|
|
52,313 |
|
|
|
2,158 |
|
|
August
13, 2007
|
|
|
0.44 |
|
|
|
51,150 |
|
|
|
1,770 |
|
|
May
14, 2007
|
|
|
0.43 |
|
|
|
49,988 |
|
|
|
1,519 |
|
|
February
27, 2007
|
|
|
0.415 |
|
|
|
44,924 |
|
|
|
1,128 |
|
|
November
6, 2006
|
|
|
0.40 |
|
|
|
40,540 |
|
|
|
827 |
|
|
August
18, 2006
|
|
|
0.38 |
|
|
|
38,513 |
|
|
|
786 |
|
|
May
19, 2006
|
|
|
0.36 |
|
|
|
36,486 |
|
|
|
745 |
|
|
February
23, 2006
|
|
|
0.179 |
* |
|
|
18,121 |
|
|
|
370 |
|
|
*Distribution
represented a prorated portion of the $0.35 per unit “minimum quarterly
distribution” (as defined in the Partnership’s partnership agreement) for
the period November 15, 2005 through December 31,
2005.
|
Note
11: Income Tax
Results of operations for the year
ended December 31, 2005, reflect a change in the tax status associated with the
Partnership and Boardwalk Pipelines, coincident with the
IPO. Accordingly, the Partnership recorded a charge-in-lieu of income
taxes for the period January 1, 2005, through the date of the
offering. Pursuant to the change in tax status, the Partnership also
eliminated its balance of accumulated deferred income taxes at the date of the
offering. The subsidiaries of the Partnership directly incur some
income-based state taxes which are accrued as Income taxes and charge-in-lieu of
income taxes on the Consolidated Statements of Income.
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. The Partnership’s tax years 2005 through 2007 remain
subject to examination by the Internal Revenue Service (IRS) and the states in
which it operates.
Following is a summary of the provision
for Income taxes and charge-in-lieu of income taxes for the periods ended
December 31, 2007, 2006 and 2005 (in thousands):
|
|
|
For
the Year Ended December 31,
|
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
Current
expense:
|
|
|
|
|
|
|
|
|
|
|
Federal
|
|
|
- |
|
|
|
- |
|
|
$ |
4,044 |
|
|
State
|
|
$ |
787 |
|
|
$ |
292 |
|
|
|
870 |
|
|
Total
|
|
|
787 |
|
|
|
292 |
|
|
|
4,914 |
|
|
Deferred
provision (benefit):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Federal
|
|
|
- |
|
|
|
- |
|
|
|
36,690 |
|
|
State
|
|
|
(18 |
) |
|
|
(39 |
) |
|
|
7,890 |
|
|
Elimination
of cumulative deferred taxes
|
|
|
- |
|
|
|
- |
|
|
|
10,102 |
|
|
Total
|
|
|
(18 |
) |
|
|
(39 |
) |
|
|
54,682 |
|
|
Income
taxes and charge-in-lieu of income taxes
|
|
$ |
769 |
|
|
$ |
253 |
|
|
$ |
59,596 |
|
Reconciliations from the provision at
the statutory rate to the Income tax and charge-in-lieu of income taxes
provision are as follows (in thousands):
|
|
|
For
the Year Ended December 31,
|
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
Provision
at statutory rate
|
|
|
- |
|
|
|
- |
|
|
$ |
43,583 |
|
|
Increases
in taxes resulting from:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
State
income taxes
|
|
$ |
769 |
|
|
$ |
253 |
|
|
|
5,694 |
|
|
Other,
net
|
|
|
- |
|
|
|
- |
|
|
|
217 |
|
|
Elimination
of deferred taxes
|
|
|
- |
|
|
|
- |
|
|
|
10,102 |
|
|
Income
taxes and charge-in-lieu of income taxes
|
|
$ |
769 |
|
|
$ |
253 |
|
|
$ |
59,596 |
|
As
of December 31, 2007 and 2006, there were no significant deferred income tax
assets or liabilities.
Note
12: 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.
Advances to
Affiliates: Advances to affiliates, which are represented by
demand notes, earn a variable rate of interest, which is adjusted regularly to
reflect current market conditions. Therefore, the carrying amount is
a reasonable estimate of fair value. The interest rate on
intercompany demand notes is LIBOR plus one percent and is adjusted every three
months.
Long-Term
Debt: All long-term debt is publicly traded, except for debt
held by Gulf South. Estimated fair value is based on quoted market
prices and market prices of similar debt, for debt held by Gulf South, at
December 31, 2007 and 2006.
The carrying amount and estimated fair
values of the Partnership’s financial instruments as of December 31, 2007 and
2006 were as follows (in thousands):
|
|
|
2007
|
|
|
2006
|
|
|
Financial
Assets
|
|
Carrying
Amount
|
|
|
Fair
Value
|
|
|
Carrying
Amount
|
|
|
Fair
Value
|
|
|
Cash
and cash equivalents
|
|
$ |
317,319 |
|
|
$ |
317,319 |
|
|
$ |
399,032 |
|
|
$ |
399,032 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financial
Liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term
debt
|
|
$ |
1,847,914 |
|
|
$ |
1,834,161 |
|
|
$ |
1,350,920 |
|
|
$ |
1,318,293 |
|
Note
13: Accumulated Other Comprehensive Income (Loss)
The following table shows the
components of Accumulated other comprehensive income, net of tax which is
included in Partners’ Capital on the Consolidated Balance Sheets (in
thousands):
|
|
|
For
the Year Ended December 31,
|
|
|
|
|
2007
|
|
|
2006
|
|
|
(Loss)
gain on cash flow hedges, net of tax
|
|
$ |
(8,891 |
) |
|
$ |
8,309 |
|
|
Deferred
components of net periodic benefit cost, net of tax
|
|
|
13,103 |
|
|
|
14,803 |
|
|
Total
Accumulated other comprehensive income, net of tax
|
|
$ |
4,212 |
|
|
$ |
23,112 |
|
In 2008, the Partnership will
recognize $8.7 million of the amounts shown
above in earnings. This amount is comprised
of increases to earnings of $1.2 million related to cash flow hedges and $7.5
million related to net periodic benefit cost.
Note
14: Major Customers and Transactions with Affiliates
Major
Customers
Operating revenues received from the
Partnership’s major customer (in thousands) and the percentage of Total
operating revenues were:
|
|
|
For
the Year Ended December 31,
|
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
Customer
|
|
Revenue
|
|
|
%
|
|
|
Revenue
|
|
|
%
|
|
|
Revenue
|
|
|
%
|
|
|
Atmos
Energy
|
|
$ |
63,900
|
|
|
|
10.0
|
% |
|
$ |
56,413
|
|
|
|
9.3
|
% |
|
$ |
61,774
|
|
|
|
11.0
|
% |
Natural
gas price volatility has increased dramatically in recent years, which has
materially increased credit risk related to gas loaned to customers. As of
December 31, 2007, the amount of gas loaned by the operating subsidiaries was
approximately 12.7 TBtu and, assuming an average market price during December
2007 of $7.13 per MMBtu, the market value of that gas was approximately $90.6
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.
Transactions
with Affiliates
Loews provides a variety of corporate
services to the Partnership and its subsidiaries under services agreements.
Services provided by Loews include, among others, information technology, tax,
risk management, internal audit and corporate development services. Loews
charged $12.1 million, $13.0 million, and $9.7 million for the years ended
December 31, 2007, 2006 and 2005 to the Partnership based on the actual time
spent by Loews personnel performing these services, plus related
expenses.
Distributions paid related to common
and subordinated units held by BPHC, 2.0% general partner interest and IDRs held
by Boardwalk GP were $156.4 million during 2007 and $116.6 million during
2006.
The
Partnership pays franchise and certain other taxes on behalf of BPHC and records
a note receivable from BPHC for the amounts paid, which is settled
quarterly. The notes accrue interest at LIBOR plus one
percent. In 2007 and 2006, the Partnership paid $3.4 million and $0.8
million on behalf of BPHC. A note receivable of $1.6 million remained
at December 31, 2007.
Note
15: Recently Issued Accounting Pronouncements
SFAS
No. 157, Fair Value Measurements
On September 15, 2006, the FASB issued
SFAS No. 157, Fair Value
Measurements. Fair value refers to the price that would be
received to sell an asset or paid to transfer a liability in an orderly
transaction between market participants in the market in which the reporting
entity transacts. The standard clarifies the principle that fair value should be
based on the assumptions market participants would use when pricing the asset or
liability. In support of this principle, the standard establishes a fair value
hierarchy that prioritizes the information used to develop those assumptions.
The fair value hierarchy gives the highest priority to quoted prices in active
markets and the lowest priority to unobservable data, for example, the reporting
entity’s own data. Under the standard, fair value measurements would be
separately disclosed by level within the fair value hierarchy. The
Statement is effective for financial statements issued for fiscal years
beginning after November 15, 2007, and interim periods within those fiscal
years. The Partnership is currently evaluating the impact, if any,
that SFAS No. 157 would have on its financial statements.
SFAS
No. 159, The Fair Value Option for Financial Assets and Financial
Liabilities
In February 2007, the FASB issued SFAS
No. 159, The Fair Value Option
for Financial Assets and Financial Liabilities- including an amendment of SFAS
No. 115. SFAS No. 159 allows companies to elect to measure
financial assets and financial liabilities at fair value. Unrealized
gains and losses on items for which the fair value option has been chosen are
reported in earnings. SFAS No. 159 is effective for fiscal years
beginning after November 15, 2007. The effective date for the
Partnership is January 1, 2008. The Partnership is currently
evaluating the impact, if any, of adopting SFAS No. 159 on its financial
statements.
Note 16: Supplemental
Disclosure of Cash Flow Information (in
thousands):
|
|
|
For
the Year Ended December 31,
|
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
Cash
paid during the period for:
|
|
|
|
|
|
|
|
|
|
|
Interest
(net of amount capitalized)
|
|
$ |
46,106 |
|
|
$ |
58,111 |
|
|
$ |
45,357 |
|
|
Income
taxes, net
|
|
|
340 |
|
|
|
215 |
|
|
|
- |
|
|
Non-cash
capital contribution
|
|
|
- |
|
|
|
- |
|
|
|
681,809 |
|
|
Non-cash
dividends
|
|
|
- |
|
|
|
- |
|
|
|
101,401 |
|
Note
17: Selected Quarterly Financial Data (Unaudited)
The Partnership’s operating income may
vary by quarter. Based on the current rate structure, the operating
subsidiaries experience higher income in the first and fourth quarters as
compared to the second and third quarters. The following tables
summarize selected quarterly financial data for 2007 and 2006 for the
Partnership (in thousands, except for earnings per unit):
|
|
|
2007
For
the Quarter Ended:
|
|
|
|
|
December
31
|
|
|
September
30
|
|
|
June
30
|
|
|
March
31
|
|
|
Operating
revenues
|
|
$ |
169,882 |
|
|
$ |
134,732 |
|
|
$ |
150,542 |
|
|
$ |
188,112 |
|
|
Operating
expenses
|
|
|
89,048 |
|
|
|
86,185 |
|
|
|
106,236 |
|
|
|
95,766 |
|
|
Operating
income
|
|
|
80,834 |
|
|
|
48,547 |
|
|
|
44,306 |
|
|
|
92,346 |
|
|
Interest
expense, net
|
|
|
9,704 |
|
|
|
9,003 |
|
|
|
8,567 |
|
|
|
12,216 |
|
|
Other
(income) expense
|
|
|
(1,232 |
) |
|
|
(575 |
) |
|
|
159 |
|
|
|
(334 |
) |
|
Income
before income taxes
|
|
|
72,362 |
|
|
|
40,119 |
|
|
|
35,580 |
|
|
|
80,464 |
|
|
Income
taxes
|
|
|
267 |
|
|
|
140 |
|
|
|
132 |
|
|
|
230 |
|
|
Net
income
|
|
$ |
72,095 |
|
|
$ |
39,979 |
|
|
$ |
35,448 |
|
|
$ |
80,234 |
|
|
Earnings
per unit:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common
units
|
|
$ |
0.56 |
|
|
$ |
0.35 |
|
|
$ |
0.35 |
|
|
$ |
0.61 |
|
|
Subordinated
units
|
|
$ |
0.56 |
|
|
$ |
0.30 |
|
|
$ |
0.17 |
|
|
$ |
0.61 |
|
|
|
|
2006
For
the Quarter Ended:
|
|
|
|
|
December
31
|
|
|
September
30
|
|
|
June
30
|
|
|
March
31
|
|
|
Operating
revenues
|
|
$ |
171,489 |
|
|
$ |
133,045 |
|
|
$ |
128,662 |
|
|
$ |
174,446 |
|
|
Operating
expenses
|
|
|
92,811 |
|
|
|
88,272 |
|
|
|
82,798 |
|
|
|
89,813 |
|
|
Operating
income
|
|
|
78,678 |
|
|
|
44,773 |
|
|
|
45,864 |
|
|
|
84,633 |
|
|
Interest
expense, net
|
|
|
13,882 |
|
|
|
14,414 |
|
|
|
14,510 |
|
|
|
15,088 |
|
|
Other
income
|
|
|
(366 |
) |
|
|
(406 |
) |
|
|
(792 |
) |
|
|
(185 |
) |
|
Income
before income taxes
|
|
|
65,162 |
|
|
|
30,765 |
|
|
|
32,146 |
|
|
|
69,730 |
|
|
Income
taxes
|
|
|
(111 |
) |
|
|
118 |
|
|
|
246 |
|
|
|
- |
|
|
Net
income
|
|
$ |
65,273 |
|
|
$ |
30,647 |
|
|
$ |
31,900 |
|
|
$ |
69,730 |
|
|
Earnings
per unit:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common
units
|
|
$ |
0.57 |
|
|
$ |
0.35 |
|
|
$ |
0.35 |
|
|
$ |
0.58 |
|
|
Subordinated
units
|
|
$ |
0.57 |
|
|
$ |
0.19 |
|
|
$ |
0.22 |
|
|
$ |
0.58 |
|
Note
18: Disposition of Coal Reserves
The
Partnership has begun efforts to sell its investment in certain coal
reserves along the Ohio River in northern Kentucky and southern Indiana that
were originally acquired in the 1970's. A data room has been made
available to prospective buyers. The book value of the assets at
December 31, 2007 and 2006 was zero. The Partnership expects to
complete a sale of the assets in 2008.
Note
19: Guarantee of Securities of Subsidiaries
The Partnership has no independent
assets or operations other than its investment in its
subsidiaries. The Partnership’s operating subsidiaries have issued
securities which have all been fully and unconditionally guaranteed by the
Partnership. 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 and have no restricted assets at December 31,
2007. See Note 7 for additional information.
None.
Disclosure
Controls and Procedures
We
maintain a system of disclosure controls and procedures which is designed to
ensure that information required to be disclosed by us in reports that we file
or submit under the federal securities laws, including this report is recorded,
processed, summarized and reported on a timely basis. These
disclosure controls and procedures include controls and procedures designed to
ensure that information required to be disclosed by us under the federal
securities laws is accumulated and communicated to us on a timely basis to allow
decisions regarding required disclosure.
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,
2007.
Changes
in Internal Control over Financial Reporting
There
were no other changes in our internal control over financial reporting that
occurred during the quarter ended December 31, 2007, 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, 2007. 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, 2007, 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.
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
|
|
54
|
|
Chief
Executive Officer, President and Director
|
|
Jamie
L. Buskill
|
|
43
|
|
Chief
Financial Officer, Senior Vice-President and Treasurer
|
|
Brian
A. Cody
|
|
50
|
|
Senior
Vice President of Marketing and Chief Commercial
Officer
|
|
John
C. Earley Jr.
|
|
45
|
|
Senior
Vice President of Operations
|
|
Michael
E. McMahon
|
|
52
|
|
Senior
Vice President and General Counsel, Secretary
|
|
Arthur
L. Rebell
|
|
67
|
|
Director,
Chairman of the Board
|
|
William
R. Cordes
|
|
59
|
|
Director
|
|
Thomas
E. Hyland
|
|
62
|
|
Director
|
|
Jonathan
E. Nathanson
|
|
46
|
|
Director
|
|
Mark
L. Shapiro
|
|
63
|
|
Director
|
|
Andrew
H. Tisch
|
|
58
|
|
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 to February 2007 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 of BGL since its inception in
2005. Mr. Buskill is also the Vice President, Chief Financial Officer
and Treasurer of Texas Gas. Mr. Buskill has been employed by Texas
Gas in that capacity since Texas Gas was acquired by Boardwalk Pipelines in May
2003. Prior thereto he served in various management roles for Texas Gas and its
affiliates since 1986, including Assistant Treasurer and Financial Reporting
Manager from 1998 until May 2003.
Brian A. Cody— Mr. Cody has
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.
John C. Earley Jr. —Mr. Earley
has been the Senior Vice President of Operations of BGL since March 2007. Prior
thereto he had been Senior Vice President of Operations for Gulf South since
2001. Mr. Earley has held various senior leadership roles prior to 2001 and has
been employed by Gulf South or it predecessors since 1995.
Michael E. McMahon—Mr. McMahon
has been the Senior Vice President and General Counsel 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. 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.
Thomas E. Hyland—Mr. Hyland
was a partner in the global accounting firm of PricewaterhouseCoopers, LLP from
1980 until his retirement in July 2005.
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.
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.
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 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, chief financial officer, principal
accounting officer, and all of the directors, officers and employees of our
subsidiaries. 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 10.0% 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
2007, in a timely manner, other than one late Form 3 filing for each of Messrs.
Cody, Earley and McMahon and one late Form 4 filing for H. Dean Jones II and
each of Messrs. Buskill, Cody, Cordes, Earley, Gafvert, Hyland, McMahon and
Shapiro.
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
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, improve retention of our
executives and appropriately reward their performance both in the long and short
term. In doing so, we may consider the executive compensation
programs of other companies engaged in similar businesses to ours and 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.
As
discussed elsewhere in this Report, our Board does not maintain a Compensation
Committee. Therefore, the compensation for Rolf Gafvert our Chief
Executive Officer (CEO), Jamie L. Buskill our Chief Financial Officer (CFO) and
our three other most highly compensated executive officers (together with our
former President, H. Dean Jones II, who has resigned as an officer and director
in conjunction with his announced retirement that will be effective March 1,
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
discussions with respect to his own compensation. Named Executive
Officers are those officers whose compensation is required to be reported in
accordance with Item 402, Executive Compensation, of
SEC Regulation S-K rules.
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
LTIP;
|
|
·
|
annual
grants of phantom general partner units (Phantom GP Units) under our
SLTIP; and
|
|
·
|
retirement,
medical and related benefits.
|
In
establishing the aggregate amount of compensation for our Named Executive
Officers for a given year, we do not rely on formula-driven plans which could
result in unreasonably high compensation levels. Instead, the primary
factor in setting compensation is an evaluation of the individual's performance
in the context of our overall performance for such year, particularly the
individual’s contribution to our financial performance during the year, as well
as the compensation paid to the individual in prior years. In light
of the shortage of excellent management talent in our industry and our desire to
retain our key executives, we may also review and consider compensation levels
and types in other companies that are engaged in similar businesses to maintain
an understanding of the market for executive talent. Based on these
factors, we determine an overall level of compensation.
Base
Salary
Our
executive compensation policies have emphasized the incentive-based compensation
elements discussed below. As a result, the base salaries of our executive
officers generally have remained unchanged through the end of 2007, with modest
adjustments made from year to year based on merit or other
factors. Each year we review the overall mix of compensation to
determine if we need to vary any one item of an executive’s compensation
package.
Incentive Compensation –
Cash Bonuses and Phantom Common Unit Awards
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 executives to consider long-term results for our unitholders and
providing them with appropriate current cash compensation, we have targeted
these compensation elements as approximately three-fourths cash bonus and
one-fourth as an award of Phantom Common Units for our most senior
executives.
Prior to
the beginning of a year, the CEO proposes to the Board bonus targets including
cash and equity components for the Partnership as a whole, based on meeting
specific financial measures, operating goals and project
milestones. At the end of the year, the CEO makes recommendations to
the Board regarding amounts to pay both Named Executive Officers and other
employees based on whether targets for the year were met and based upon the
Named Executive Officers’ individual performance and contributions to the
Company. The CEO’s compensation is determined by the Board based upon
a similar appraisal of performance and contributions.
Since we
are a limited partnership and our Named Executive Officers are employed by our
operating subsidiaries, the executives would incur significant adverse
individual tax consequences if they would own our units directly; for example by
being taxed as a partner rather than as an employee. Furthermore, the
ownership of units by our executives would negatively impact the tax status of
our benefit plans. As a result, we have chosen to award our
executives equity-based compensation in the form of Phantom Common Units, the
economic value of which is directly tied to the value of our common units, but
which 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 and 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 that 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 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 50.0% on the
second anniversary of the grant date and 50.0% 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. It also
promotes retention because the awards would be forfeited if an employee were to
resign prior to the vesting date.
We
exceeded our financial and operational goals for 2007 and increased our
distributions to unitholders in each quarter. As a result, we awarded the full
amount of incentive compensation we had targeted for 2007 to our key employees
including the Named Executive Officers, of which approximately 75.0% was paid as
annual cash bonuses and 25.0% was awarded as Phantom Common Units. In
making these awards, our Board considered the factors discussed above, with
particular emphasis on the contributions made by the individual executives in
2007 to the success of the expansion projects we have undertaken which are
described elsewhere in this Report, among other strategic goals and
objectives.
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. Since the value of these awards is directly
linked to our performance and the value of our common units and of our general
partner, they further align the interests of our Named Executive Officers with
those of our unitholders.
We
awarded an aggregate of 116 Phantom GP Units in December 2007, which vest in 4.0
years, to 21 of our key employees, of which 65 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 6.0% 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, 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 other 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, nor 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.
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 of Directors 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 2007 or
2006.
Summary
of Executive Compensation
The following table shows a summary of
total compensation earned by our Named Executive Officers during 2007 and
2006:
|
Summary
Compensation Table
|
|
|
Name
and
Position
|
Year
|
|
Salary
|
|
|
Bonus
(1)
|
|
|
Stock
Awards
(2)
|
|
|
Option
Awards
|
|
|
Non-Equity
Incentive Plan
Compensation
(3)
|
|
|
Change
in
Pension
value
and
nonqualified
deferred compensation earnings
|
|
|
All
Other
Compensation
|
|
|
Total
|
|
|
Rolf
A. Gafvert:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CEO
(PEO)
|
2007
|
|
$ |
323,365 |
|
|
$ |
300,000 |
|
|
$ |
175,253 |
|
|
|
- |
|
|
$ |
682,664 |
|
|
|
- |
|
|
$ |
35,360 |
(4) |
|
$ |
1,516,642 |
|
|
|
2006
|
|
|
240,000 |
|
|
|
300,000 |
|
|
|
112,944 |
|
|
|
- |
|
|
|
183,442 |
|
|
|
- |
|
|
|
32,149 |
(4) |
|
|
868,535 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
H.
Dean Jones II: (10)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
|
326,534 |
|
|
|
275,000 |
|
|
|
80,013 |
|
|
|
- |
|
|
|
401,786 |
|
|
$ |
177,404 |
(5) |
|
|
31,099 |
(5) |
|
|
1,291,836 |
|
|
|
2006
|
|
|
325,000 |
|
|
|
195,000 |
|
|
|
59,778 |
|
|
|
- |
|
|
|
110,065 |
|
|
|
154,458 |
(5) |
|
|
24,432 |
(5) |
|
|
868,733 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Jamie
L. Buskill:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CFO
(PFO)
|
2007
|
|
|
225,000 |
|
|
|
225,000 |
|
|
|
36,092 |
|
|
|
- |
|
|
|
302,679 |
|
|
|
46,602 |
(6) |
|
|
14,386 |
(6) |
|
|
849,759 |
|
|
|
2006
|
|
|
225,000 |
|
|
|
100,000 |
|
|
|
26,196 |
|
|
|
- |
|
|
|
87,011 |
|
|
|
40,333 |
(6) |
|
|
14,292 |
(6) |
|
|
492,832 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Brian
A. Cody:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SVPM
|
2007
|
|
|
228,846 |
|
|
|
175,000 |
|
|
|
59,288 |
|
|
|
- |
|
|
|
364,137 |
|
|
|
- |
|
|
|
23,107 |
(7) |
|
|
850,378 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
John
C. Earley Jr.:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SVPO
|
2007
|
|
|
226,154 |
|
|
|
175,000 |
|
|
|
73,447 |
|
|
|
- |
|
|
|
326,116 |
|
|
|
- |
|
|
|
23,681 |
(8) |
|
|
824,398 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Michael
E. McMahon:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SVPGC
|
2007
|
|
|
216,346 |
|
|
|
125,000 |
|
|
|
59,288 |
|
|
|
- |
|
|
|
297,545 |
|
|
|
- |
|
|
|
28,938 |
(9) |
|
|
727,117 |
|
|
(1)
|
Reflects
cash amounts paid in 2008 and 2007 to the Named Executive Officers for
services performed by them during 2007 and
2006.
|
|
(2)
|
Represents
compensation expense accrued for 2007 and 2006 related to Phantom Common
Units granted in 2007, 2006 and 2005. The accruals were made
pursuant to SFAS No. 123(R), Share Based Payments.
See footnote (1) to the Grants of Plan-Based Awards table presented
below.
|
|
(3)
|
Represents
compensation expense accrued for 2007 and 2006 related to Phantom GP Units
granted in 2007 and 2006. The accruals were made pursuant to
SFAS No. 123(R). See footnote (1) to the Grants of Plan-Based Awards table
presented below.
|
|
(4)
|
Includes
for 2007: matching contributions under 401(k) plan ($13,500), employer
contributions to the Gulf South Money Purchase Plan ($9,000), sale of
vacation time ($6,250), club memberships ($4,781), imputed life insurance
premiums, travel clubs and preferred parking; for 2006: matching
contributions under 401(k) plan ($13,200), employer contributions to the
Gulf South Money Purchase Plan ($8,800), club memberships ($6,508),
physical medical examination reimbursement, preferred parking, sporting
event tickets and imputed life insurance
premiums.
|
|
(5)
|
Includes
for 2007: matching contributions under 401(k) plan ($13,500), club
memberships ($7,200), salary continuation plan ($6,124), imputed life
insurance premiums ($2,741) and tax gross-up on spouse travel; for 2006:
matching contributions made under a 401(k) plan ($13,200), club
memberships ($7,200), spouse travel, tax gross-up on spouse travel and
imputed life insurance premiums. The total included in the
change in pension value and nonqualified deferred compensation column for
2007 and 2006 includes the change in qualified retirement plan account
balance ($64,897 and $60,562), interest and pay credits for the
supplemental retirement plan ($101,028 and $83,935) and excess
nonqualified deferred compensation plan earnings ($11,479 and
$9,961).
|
|
(6)
|
Includes
for 2007: matching contributions under 401(k) plan ($13,500) and imputed
life insurance premiums; for 2006: matching contributions made under a
401(k) plan ($13,200), spouse travel and imputed life insurance
premiums. The total included in the change in pension value and
nonqualified deferred compensation column for 2007 and 2006 includes the
change in qualified retirement plan account balance ($31,188 and $28,675)
and interest and pay credits for the supplemental retirement plan ($15,414
and $11,658).
|
|
(7)
|
Includes
for 2007: matching contributions under 401(k) plan ($13,500), employer
contributions to the Gulf South Money Purchase Plan ($8,426), imputed life
insurance premiums, travel clubs and preferred
parking.
|
|
(8)
|
Includes
for 2007: matching contributions under 401(k) plan ($13,500), employer
contributions to the Gulf South Money Purchase Plan ($9,000), imputed life
insurance premiums, travel clubs and preferred
parking.
|
|
(9)
|
Includes
for 2007: matching contributions under 401(k) plan ($8,481), sale of
vacation time ($10,385), employer contributions to the Gulf South Money
Purchase Plan ($8,654), imputed life insurance premiums, travel clubs and
preferred parking.
|
|
(10)
|
H.
Dean Jones II has resigned as an officer and director in conjunction with
his announced retirement that will be effective March 1,
2008.
|
Grants
of Plan-Based Awards
The following table displays
information regarding grants during 2007 and 2006 to our Named Executive
Officers of plan-based awards, including Phantom GP Unit awards under our
Strategic Long Term Incentive Plan and Phantom Common Unit awards under our Long
Term Incentive Plan:
|
Grants
of Plan-Based Awards
|
|
|
|
|
|
Estimated
future payouts under
non-equity
incentive plan awards
(1)
|
|
|
Estimated
future payouts under equity incentive plan awards
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Name
|
Grant Date |
|
Threshold
($)
|
|
|
Target
($)
|
|
|
Maximum
($)
|
|
|
Threshold
(#)
|
|
|
Target
(#)
|
|
|
Maximum
(#
)
|
|
|
All other stock awards: number
of shares of stock or units (#)
|
|
|
All
other options awards: number of securities underlying options
(#)
|
|
|
Exercise
or base price of option awards ($/sh)
|
|
|
Grant
Date Fair Value of Stock and Option Awards
($)
(2)
|
|
|
Rolf
A. Gafvert:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12/14/07
|
|
|
- |
|
|
|
- |
|
|
|
1,250,000 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
6,532 |
|
|
|
- |
|
|
|
- |
|
|
|
200,000 |
|
|
|
12/20/06
|
|
|
- |
|
|
|
- |
|
|
|
1,250,000 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
6,427 |
|
|
|
- |
|
|
|
- |
|
|
|
200,000 |
|
|
|
7/24/06
|
|
|
- |
|
|
|
- |
|
|
|
1,250,000 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
H.
Dean Jones II:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12/20/06
|
|
|
- |
|
|
|
- |
|
|
|
750,000 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
2,571 |
|
|
|
- |
|
|
|
- |
|
|
|
80,000 |
|
|
|
7/24/06
|
|
|
- |
|
|
|
- |
|
|
|
750,000 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
Jamie
L. Buskill:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12/14/07
|
|
|
- |
|
|
|
- |
|
|
|
600,000 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
12/20/06
|
|
|
- |
|
|
|
- |
|
|
|
500,000 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
1,205 |
|
|
|
- |
|
|
|
- |
|
|
|
37,500 |
|
|
|
7/24/06
|
|
|
- |
|
|
|
- |
|
|
|
600,000 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
Brian
A. Cody:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12/14/07
|
|
|
- |
|
|
|
- |
|
|
|
500,000 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
3,266 |
|
|
|
- |
|
|
|
- |
|
|
|
100,000 |
|
|
John
C. Earley Jr.:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12/14/07
|
|
|
- |
|
|
|
- |
|
|
|
450,000 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
3,266 |
|
|
|
- |
|
|
|
- |
|
|
|
100,000 |
|
|
Michael
E. McMahon:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12/14/07
|
|
|
- |
|
|
|
- |
|
|
|
450,000 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
3,266 |
|
|
|
- |
|
|
|
- |
|
|
|
100,000 |
|
|
(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 14,
2007 Messrs. Gafvert, Buskill, Cody, Earley, and McMahon were awarded 25,
12, 10, 9 and 9 Phantom GP Units that have a 4.0 year vesting
period. On December 20, 2006, Messrs. Gafvert, Jones and
Buskill were awarded 25, 15 and 10 Phantom GP Units that have a 4.0 year
vesting period. Concurrent with the approval of the Plan, on
July 24, 2006, Messrs. Gafvert, Jones and Buskill were awarded 25, 15 and
12 Phantom GP Units that have a 3.5 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 14, 2007 grants,
December 20, 2006 grants and July 24, 2006 grants were $50,000, $50,000
and $27,422, respectively, per GP Phantom Unit. The fair value
of the awards will be recognized ratably over the vesting
period. As of December 31, 2007, the remeasured fair value of
each of the December 14, 2007, December 20, 2006 and July 24, 2006 grants
was $50,000. See footnote (2) to the Outstanding Equity Awards at Fiscal
Year –End table presented below. Note 9 in Item 8 of this
Report contains more information regarding our
SLTIP.
|
|
(2)
|
Reflects
the fair value at the date of grant of Phantom Common Units under our
LTIP. The closing price of our common units on such date on the NYSE for
2007 was $30.62 and for 2006 was $31.12. Each such grant includes a tandem
grant of Distribution Equivalent Rights (DERs); vests 50.0% on the second
anniversary of the grant date and 50.0% on the third anniversary of the
grant date; and will be payable to the grantee in cash upon vesting in an
amount equal to the sum of the fair market value of the units (as defined
in the plan) that vest on the vesting date plus the vested amount then
credited to the grantee’s DER account, less applicable
taxes. Note 9 in Item 8 of this Report contains more
information regarding our LTIP.
|
Outstanding
Equity Awards at Fiscal Year-End
The table displayed below shows the
total outstanding equity awards in the form of Phantom Common Units, awarded
under our LTIP and held by our Named Executive Officers at December 31, 2007 and
2006:
|
|
|
|
Outstanding
Equity Awards at Fiscal Year End
|
|
|
|
|
|
Option
Awards
|
|
|
Stock
Awards
|
|
|
Name
|
Year
|
|
Number
of Securities Underlying Unexercised Options (#)
Exercisable
|
|
|
Number
of Securities Underlying Unexercised Options (#)
Unexercisable
|
|
|
Equity
Incentive Plan Awards: Number of Securities Underlying Unexercised
Unearned Options
(#)
|
|
|
Option
Exercise Price
($)
|
|
|
Option
Expiration Date
|
|
|
Number
of Shares or Units of Stock that Have
Not
Vested (#)(1)
|
|
|
Market Value of Shares or Units
of Stock that Have not Vested ($)(2)
|
|
|
Equity
Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights
that Have Not Vested
(#)
|
|
|
Equity
Incentive Plan Awards: Market or Payout Value of Unearned Shares, Units or
Rights that Have Not Vested
($)
|
|
|
Rolf
A. Gafvert
|
2007
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
16,974 |
|
|
|
541,074 |
|
|
|
- |
|
|
|
- |
|
|
|
2006
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
14,457 |
|
|
|
456,155 |
|
|
|
- |
|
|
|
- |
|
|
H.
Dean Jones II
|
2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4,712 |
|
|
|
152,929 |
|
|
|
- |
|
|
|
- |
|
|
|
2006
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
6,854 |
|
|
|
216,888 |
|
|
|
- |
|
|
|
- |
|
|
Jamie
L. Buskill
|
2007
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,142 |
|
|
|
69,470 |
|
|
|
- |
|
|
|
- |
|
|
|
2006
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
3,079 |
|
|
|
97,366 |
|
|
|
- |
|
|
|
- |
|
|
Brian
A. Cody
|
2007
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
7,148 |
|
|
|
226,112 |
|
|
|
- |
|
|
|
- |
|
|
John
C. Earley Jr.
|
2007
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
7,817 |
|
|
|
248,309 |
|
|
|
- |
|
|
|
- |
|
|
Michael
E. McMahon
|
2007
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
7,148 |
|
|
|
226,112 |
|
|
|
- |
|
|
|
- |
|
|
(1)
|
On
December 14, 2007, Messrs. Gafvert, Cody, Earley and McMahon were awarded
additional grants of Phantom Common Units in the amount of 6,532, 3,266,
3,266 and 3,266. On the December 14, 2007 grant date the
closing sale price on the NYSE was $30.62. On December 20, 2006, Messrs.
Gafvert, Jones and Buskill were awarded additional grants of Phantom
Common Units in the amount of 6,427, 2,571 and 1,205. On the
December 20, 2006 grant date the closing sale price on the NYSE was
$31.12. On December 15, 2005, Phantom Common Units were awarded
to Gafvert, Jones and Buskill in the amount of 8,030, 4,283 and 1,874. The
vesting period is 3.5 years. On the grant date, the closing
sales price on the common units on the NYSE was
$18.68.
|
|
(2)
|
The
market value per share reported in the above table is based on the NYSE
last sale price on December 31, 2007 of $31.10 and December 29, 2006 of
$30.82. Included in the market value is the accumulated
non-vested amounts related to the DER that were tandem grants to the
Phantom Common Units referred to in footnote (1) above. Such
DER amounts for Messrs. Gafvert, Jones, Buskill, Cody, Earley and McMahon
were $13,183, $6,386, $2,854, $3,809, $5,200 and $3,809 in 2007 and for
Messrs. Gafvert, Jones and Buskill were $10,590, $5,648 and $2,471 in
2006
|
Option
Exercises and Stock Vested
All of the equity-based awards granted
to our Named Executive Officers have been in the form of Phantom Common
Units. We have not issued any awards in the form of options on our
units to any employees including Named Executive Officers.
|
|
|
|
Options
Awards
|
|
|
Stock
Awards
(1)
|
|
|
Name
|
Year
|
|
Number
of Shares Acquired on Exercise
(#)
|
|
|
Value
Realized on Exercise
($)
|
|
|
Number
of Shares Acquired on
Vesting
(#)
|
|
|
Value
Received on Vesting
($)
|
|
|
Rolf
A. Gafvert
|
2007
|
|
|
- |
|
|
|
- |
|
|
|
4,015 |
|
|
|
135,200 |
|
|
H.
Dean Jones II
|
2007
|
|
|
|
|
|
|
|
|
|
|
2,142 |
|
|
|
72,129 |
|
|
Jamie
L. Buskill
|
2007
|
|
|
|
|
|
|
|
|
|
|
937 |
|
|
|
31,552 |
|
|
Brian
A. Cody
|
2007
|
|
|
- |
|
|
|
- |
|
|
|
669 |
|
|
|
22,528 |
|
|
John
C. Earley Jr.
|
2007
|
|
|
- |
|
|
|
- |
|
|
|
1,339 |
|
|
|
45,090 |
|
|
Michael
E. McMahon
|
2007
|
|
|
- |
|
|
|
- |
|
|
|
669 |
|
|
|
22,528 |
|
|
(1)
|
All
vested awards were paid out as a lump sum cash payment and at no time were
units issued to or owned by the Named Executive
Officers.
|
Pension
Benefits
The table displayed below shows the
present value of accumulated benefits for our Named Executive
Officers. Pension benefits include both a qualified defined
benefit cash balance plan and a non-qualified defined benefit supplemental cash
balance plan (SRP).
|
Pension
Benefits
|
|
|
Name
|
Year
|
Plan
Name
|
|
Number
of Years Credited Service (#)
|
|
|
Present
Value of Accumulated Benefit
($)
|
|
|
Payments
During 2007
($)
|
|
|
Payments
During 2006
($)
|
|
|
H.
Dean Jones II
|
2007
|
TGRP
|
|
|
27.1 |
|
|
|
535,760 |
|
|
|
- |
|
|
|
- |
|
|
|
|
SRP
|
|
|
27.1 |
|
|
|
677,339 |
|
|
|
- |
|
|
|
- |
|
|
|
2006
|
TGRP
|
|
|
26.1 |
|
|
|
470,863 |
|
|
|
- |
|
|
|
- |
|
|
|
|
SRP
|
|
|
26.1 |
|
|
|
576,311 |
|
|
|
- |
|
|
|
- |
|
|
Jamie
L. Buskill
|
2007
|
TGRP
|
|
|
21.3 |
|
|
|
173,837 |
|
|
|
- |
|
|
|
- |
|
|
|
|
SRP
|
|
|
21.3 |
|
|
|
34,293 |
|
|
|
- |
|
|
|
- |
|
|
|
2006
|
TGRP
|
|
|
20.3 |
|
|
|
142,649 |
|
|
|
- |
|
|
|
- |
|
|
|
|
SRP
|
|
|
20.3 |
|
|
|
18,879 |
|
|
|
- |
|
|
|
- |
|
The Texas Gas Retirement Plan (TGRP) is
a qualified defined benefit cash balance plan. Although this plan was closed to
new participants in November 2006, most of our Texas Gas employees are eligible
to participate in the TGRP. 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. 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. At December 31, 2007, Mr. Jones was eligible for the age 55 early
retirement provisions of the TGRP.
The
credited years of service appearing in the table above are the same as actual
years of service. No payments were made to the Named Executive Officers during
2007 or 2006. The present value of accumulated benefits payable to each of the
Named Executive Officers, including the number of years of service credited to
each Named Executive Officer, is determined using assumptions consistent with
the assumptions used for financial reporting. Interest is credited to
the cash balance at December 31, 2007, commencing in the year 2008, 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,
2007, 2006, and 2005 were 4.79%, 4.85% and 4.47% and for future years, 4.5%,
4.25%, and 4.125%. The future normal retirement date accumulated cash
balance is then discounted using an interest rate at December 31, 2007, 2006 and
2005 of 6.0%, 5.75% and 5.625%. The increase in the present value of
accumulated benefit for the TGRP between December 31, 2007 and 2006 of $64,897
for Mr. Jones and $31,188 for Mr. Buskill is reported as compensation in the
Summary Compensation Table above. The increase in the present value
of accumulated benefit for the TGRP between December 31, 2006 and 2005 of
$60,562 for Mr. Jones and $28,675 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 each Named Executive Officer for earnings that exceed the IRC compensation
limitations for qualified defined benefit plans. The present value of
accumulated benefit is calculated in the same manner as for TGRP. The
increase in the present value of accumulated benefit for the SRP between
December 31, 2007 and 2006 of $101,028 for Mr. Jones and $15,414 for Mr. Buskill
is reported as compensation in the Summary Compensation Table
above. The increase in the present
value of accumulated benefit for the SRP between December 31, 2006 and 2005 of
$83,935 for Mr. Jones and $11,658 for Mr. Buskill is reported as compensation in
the Summary Compensation Table above.
Nonqualified
Deferred Compensation
The following table shows nonqualified
deferred compensation plan information for our Named Executive
Officers. We currently do not have a nonqualified deferred
compensation plan that allows for current or future deferrals of
compensation. The amounts shown in the table are
related to the Texas Gas Salary Continuation Plan that is closed to new
participants and compensation deferrals:
|
Nonqualified
Deferred Compensation (1)
|
|
|
Name
|
Year
|
|
Executive
Contributions
($)
|
|
|
Registrant
Contributions
($)
|
|
|
Aggregate
Earnings
($)
|
|
|
Aggregate
Withdrawals/ Distributions
($)
|
|
|
Aggregate
Balance
($)
|
|
|
H.
Dean Jones II
|
2007
|
|
|
- |
|
|
|
- |
|
|
|
26,313 |
|
|
|
- |
|
|
|
275,969 |
|
|
|
2006
|
|
|
- |
|
|
|
- |
|
|
|
23,524 |
|
|
|
- |
|
|
|
249,656 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
The
Salary Continuation Plan became closed to new participants and
compensation deferrals in 1995. The only activity in the plan
is the addition of earnings on individual account balances and any
withdrawals from account balances. Earnings on the deferred compensation
balances are computed at the prime rate of interest plus 2.0%, compounded
monthly. Aggregate earnings in 2007 include $11,479 and in 2006
include $9,961 reported in the Summary Compensation Table
above.
|
Potential
Payments Upon Termination or Change-in-Control
We
have made grants of Phantom Common Units and Phantom GP Units, subject to
vesting, to each of our Named Executive Officers, as discussed elsewhere in this
Report. Each of the foregoing grants will vest immediately and become
payable to the executive in cash upon a change of control of us, as defined in
the applicable plan, or upon the termination of the executive’s employment with
us and our affiliates by reason of death, disability, retirement or termination
by us other than for cause (as defined in such plans); provided, that with
respect to the vesting of Phantom GP Units, the minimum distribution amount per
unit (as defined in the applicable grant agreements) must have been met for the
four consecutive calendar quarters ending on or immediately preceding such
termination of employment. Assuming that a termination or change of
control event resulting in accelerated vesting had occurred as of December 31,
2007, the Named Executive Officer (i) would be entitled to payment for each
Phantom Common Unit held as of such date in an amount equal to $31.10, being the
closing price of a common unit on such date on the NYSE, plus the distribution
equivalent rights accumulated for such Phantom Common Unit from the date of
grant; and (ii) would not be entitled to any payment on account of Phantom GP
Units since the Minimum Distribution Amount was not met as of such date for any
outstanding Phantom GP Units.
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 is paid an annual cash
retainer of $35,000 ($40,000 for the chair of the Audit Committee), payable in
equal quarterly installments, $1,000 for each Board meeting attended which is
not a regularly scheduled meeting, and an annual grant of 500 of our common
units. Directors who are officers or employees of us, our subsidiaries, our
general partner or an affiliate of our general partner do not receive the
compensation described above. All directors are reimbursed for out-of-pocket
expenses they incur in connection with attending Board and committee meetings
and will be fully indemnified by us for actions associated with being a director
to the extent permitted under Delaware law. The following table
displays information related to director compensation for 2007:
|
Name
|
|
Fees
Earned or Paid in Cash
($) (1)
|
|
|
Stock
Awards
($) (3)
|
|
|
Option
Awards
($)
|
|
|
Non-Equity
Incentive Plan Compensation ($)
|
|
|
Change
in Pension Value and Nonqualified Deferred Compensation
Earnings
|
|
|
All
Other Compensation including perquisites
($)
|
|
|
Total
($)
|
|
|
William
R. Cordes
|
|
|
49,000 |
|
|
|
18,305 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
67,305 |
|
|
Thomas
E. Hyland
|
|
|
56,000 |
(2) |
|
|
18,305 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
74,305 |
|
|
Mark
L. Shapiro
|
|
|
50,000 |
|
|
|
18,305 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
68,305 |
|
(1) Represents amounts paid
in cash for 2007.
(2) Chairman
of Audit Committee.
(3) On
March 5, 2007, Messrs. Cordes, Hyland and Shapiro were each granted 500 common
units. The units were purchased from the NYSE on February 27, 2007 at
a unit price of $36.61.
The
following table sets forth certain information, at February 15, 2008, as to the
beneficial ownership of our common and subordinated units by beneficial holders
of 5.0% 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:
|
Name
of Beneficial Owner
|
|
Common
Units
Beneficially Owned
|
|
|
Percentage of
Common
Units
Beneficially Owned
(1)
|
|
|
Subordinated
Units
Beneficially Owned
|
|
|
Percentage
of
Subordinated
Units Beneficially Owned
(1)
|
|
|
Percentage
of Total Equity Securities Beneficially Owned
|
|
|
Jamie
L. Buskill
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
Brian
A. Cody
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
William
R. Cordes
|
|
|
500 |
|
|
|
* |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
John
C. Earley Jr.
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
Rolf
A. Gafvert
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
Thomas
E. Hyland
|
|
|
6,000 |
|
|
|
* |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
Michael
E. McMahon
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
Jonathan
E. Nathanson
|
|
|
15,000 |
|
|
|
* |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
Arthur
L. Rebell
|
|
|
39,083 |
(2) |
|
|
* |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
Mark
L. Shapiro
|
|
|
11,000 |
|
|
|
* |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
Andrew
H. Tisch
|
|
|
18,550 |
(3) |
|
|
* |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
All
directors and
executive
officers
as
a group
|
|
|
90,133 |
|
|
|
* |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
BPHC
(4)
|
|
|
53,256,122 |
|
|
|
58.75 |
% |
|
|
33,093,878 |
|
|
|
100.00 |
% |
|
|
70.38 |
% |
|
Loews
Corporation (4)
|
|
|
53,256,122 |
|
|
|
58.75 |
% |
|
|
33,093,878 |
|
|
|
100.00 |
% |
|
|
70.38 |
% |
*Represents
less than 1.0% of the outstanding common units
|
(1)
|
As
of February 15, 2008, we had 90,656,122 common units and 33,093,878
subordinated units issued and
outstanding.
|
|
(2)
|
33,083
of these units are owned by Arebell, LLC, a limited liability company
controlled by Mr. Rebell.
|
|
(3)
|
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.
|
|
(4)
|
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.
|
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, 2007, 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
|
|
3,522,500
|
Note 9 in
Item 8 of this Report contains more information regarding our equity
compensation plan.
It is our Board’s 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 Audit Committee. “Related person”
means our general partner and its directors and executive officers, holders of
more than 5.0% 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 Audit 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. See Note 1 and Note 14 in Item 8 of this Report for a
description of certain related party transactions.
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 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 $100,000 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
participates in the firm’s audit, assurance or tax compliance (but not tax
planning) practice 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 2.0% 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, nor do we
maintain a compensation or nominating/corporate governance
committee.
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 2007 and 2006 by category as described in
the notes to the table (in thousands):
|
|
|
2007
|
|
|
2006
|
|
|
|
|
|
|
|
|
|
|
Audit
fees (1)
|
|
$ |
2,216 |
|
|
$ |
1,513 |
|
|
Audit
related fees (2)
|
|
|
514 |
|
|
|
553 |
|
|
Tax
fees (3)
|
|
|
2 |
|
|
|
2 |
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
$ |
2,732 |
|
|
$ |
2,068 |
|
|
(1)
|
Includes
the aggregate fees and expenses for annual financial statement audit and
quarterly financial statements
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, audits of employee benefits plans,
Sarbanes-Oxley implementation and other potential
acquisitions.
|
|
(3)
|
Includes
the aggregate fees and expenses for tax professional education
services.
|
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, 2007 and 2006
Consolidated
Statements of Income for the years ended December 31, 2007, 2006 and
2005
Consolidated
Statements of Cash Flows for the years ended December 31, 2007, 2006 and
2005
Consolidated
Statements of Changes in Member’s Equity and Partners’ Capital for the years
ended December 31, 2007, 2006 and 2005
Consolidated
Statements of Comprehensive Income for the years ended December 31, 2007, 2006
and 2005
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, 2007, 2006 and 2005 and are not
included in specific schedules herein. These amounts have been
deducted from the respective assets on the Consolidated Balance Sheets (in
thousands):
|
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:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
$ |
2,610 |
|
|
$ |
2,706 |
|
|
$ |
(4,657 |
) |
|
$ |
(226 |
) |
|
$ |
433 |
|
|
2006
|
|
|
730 |
|
|
|
2,053 |
|
|
|
- |
|
|
|
(173 |
) |
|
|
2,610 |
|
|
2005
|
|
|
174 |
|
|
|
745 |
|
|
|
(187 |
) |
|
|
(2 |
) |
|
|
730 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Inventory
obsolescence:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007
|
|
$ |
33 |
|
|
$ |
- |
|
|
$ |
86 |
|
|
$ |
(33 |
) |
|
$ |
86 |
|
|
2006
|
|
|
- |
|
|
|
33 |
|
|
|
- |
|
|
|
- |
|
|
|
33 |
|
|
2005
|
|
|
201 |
|
|
|
- |
|
|
|
11 |
|
|
|
(212 |
) |
|
|
- |
|
(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
|
|
Second
Amended and Restated Agreement of Limited Partnership of Boardwalk
Pipeline Partners, LP dated as of September 19, 2006. (Incorporated by
reference to Exhibit 3.1 to Boardwalk Pipeline Partners, LP Current Report
on Form 8-K filed on September 25, 2006).
|
|
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 (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).
|
|
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
|
|
Contribution,
Conveyance and Assumption Agreement, dated as of November 15, 2005, by and
among Boardwalk Pipelines Holding Corp., Boardwalk GP, LLC, Boardwalk
Pipeline Partners, LP, Boardwalk Operating GP, LLC, Boardwalk GP, LP, and
Boardwalk Pipelines, LLC (Incorporated by reference to Exhibit 10.1 to the
Registrant’s Current Report on Form 8-K filed on November 18,
2005).
|
|
10.5
|
|
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).
|
|
10.6
|
|
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).
|
|
10.7
|
|
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).
|
|
10.8
|
|
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).
|
|
10.9
|
|
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).
|
|
10.10
|
|
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).
|
|
10.11
|
|
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).
|
|
10.12
|
|
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).
|
|
10.13
|
|
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)
|
|
10.14
|
|
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).
|
|
10.15
|
|
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).
|
|
10.16
|
|
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).
|
|
10.17
|
|
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).
|
|
10.18
|
|
Letter
Agreement, dated November 10, 2006, between Boardwalk Pipeline Partners,
LP and Enterprise Gas Marketing L.P. (Incorporated by reference to Exhibit
10.1 to the Registrant’s current Report on Form 8-K filed on November 14,
2006).
|
|
*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
(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 26, 2008
|
|
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
26, 2008
|
/s/ Rolf A.
Gafvert
|
|
|
|
Rolf
A. Gafvert
President,
Chief Executive Officer and Director
(principal
executive officer)
|
|
|
Dated: February
26, 2008
|
/s/ Jamie L.
Buskill
|
|
|
|
Jamie
L. Buskill
Senior
Vice-President, Chief Financial Officer and Treasurer
(principal
financial officer)
|
|
|
Dated: February
26, 2008
|
/s/ Steven A.
Barkauskas
|
|
|
|
Steven
A. Barkauskas
Vice
President, Controller and Chief Accounting Officer
(principal
accounting officer)
|
|
|
Dated: February
26, 2008
|
/s/ William R.
Cordes
|
|
|
|
William
R. Cordes
Director
|
|
|
Dated: February
26, 2008
|
/s/ Thomas E.
Hyland
|
|
|
|
Thomas
E. Hyland
Director
|
|
|
Dated: February
26, 2008
|
/s/ Jonathan E.
Nathanson
|
|
|
|
Jonathan
E. Nathanson
Director
|
|
|
Dated: February
26, 2008
|
/s/ Arthur L.
Rebell
|
|
|
|
Arthur
L. Rebell
Director
|
|
|
Dated: February
26, 2008
|
/s/ Mark L.
Shapiro
|
|
|
|
Mark
L. Shapiro
Director
|
|
|
Dated: February
26, 2008
|
/s/ Andrew H.
Tisch
|
|
|
|
Andrew
H. Tisch
Director
|
|