**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, 2006**
 OR
 
 **o** **** **TRANSITION
        REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF
        1934**
 **** **For the transition period from _______________ to
        _______________**
 
 *Commission
                  file number:*01-32665**BOARDWALK
                  PIPELINE PARTNERS, LP***(Exact
                  name of registrant as specified in its charter)***DELAWARE***(State
                  or other jurisdiction of incorporation or
                  organization)***20-3265614***(I.R.S.
                  Employer Identification No.)***3800
                  Frederica********Street,
                  Owensboro, Kentucky 42301**
                **(270)
                  926-8686***(Address
                  and Telephone Number of Registrant’s Principal Executive
                  Office)**Securities
                  registered pursuant to Section 12(b) of the Act:**Title
                  of each class*
              
              *Name
                  of each exchange on which registered***Common
                  Units Representing Limited Partner Interests**
              
              **New
                  York Stock Exchange***Securities
                  registered pursuant to Section 12(g) of the Act:***NONE**
 
 Indicate
        by check mark if the registrant is a well-known seasoned issuer, as defined
        in
        Rule 405 of the Securities Act.
 Yes 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 No o
 
 Indicate
        by check mark if disclosure of delinquent filers pursuant to Item 405 of
        Regulation S-K is not contained herein, and will not be contained, to the
        best
        of registrant’s knowledge, in definitive proxy or information statements
        incorporated by reference in Part III of this Form 10-K or any amendment
        to this
        Form 10-K. x
 
 Indicate
        by check mark whether the registrant is a large accelerated filer, an
        accelerated filer, or a non-accelerated filer.
 (See
        definition of “Accelerated filer and large accelerated filer” in Rule 12b-2 of
        the Exchange Act.) (check one)
 Large
        accelerated filer o   Accelerated filer x   Non-accelerated
        filer 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, 2006 was approximately $367,350,000. As of
        February 9, 2007, the registrant had 75,156,122 common units outstanding.
 
 Documents
        incorporated by reference. None.
  
  **TABLE
        OF CONTENTS**
 
 **2006
        FORM 10-K**
 
 **BOARDWALK
        PIPELINE PARTNERS, LP**
 
 
 
 **Part
        I**
 **Item 1. Business**
 **Item 1A. Risk Factors**
 **Item
        1B.  Unresolved Staff
        Comments**
 **Item
        2. Properties**
 **Item 3. Legal Proceedings**
 **Item 4. Submission of Matters to a Vote of Security
        Holders**
  **Part
        II**
 **Item 5. Market for Registrant's Common Equity, Related
        Stockholder Matters and Issuer Purchases of Equity
        Securities**
 **Item
        6. Selected Financial Data**
 **Item 7. Management's Discussion and Analysis of Financial
        Condition and Results of Operations**
 **Item
        7A. Quantitative and Qualitative Disclosures About
        Market Risk**
 **Item 8. Financial Statements and Supplementary
        Data**
 **Item 9. Changes in and Disagreements with Accountants on
        Accounting and Financial Disclosure**
 **Item
        9A. Controls and Procedures**
 **Item
        9B. Other Information**
 ****
 **Part
        III**
 **Item 10. Directors and Executive Officers of the
        Registrant**
 **Item 11. Executive Compensation**
 **Item
        12. Security Ownership of Certain Beneficial
        Owners and Management**
 **Item 13. Certain Relationships and Related
        Transactions**
 **Item
        14. Principal Accounting Fees and
        Services**
 ****
 **Part
        IV**
 **Item 15. Exhibits, Financial Statement
        Schedules**
 ****
 
 ****
 
 
 2
 
 **PART
        I**
 
 
 **Item
        1. Business**
 
 **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,
        Texas Gas Transmission, LLC (Texas Gas) and Gulf South Pipeline Company,
        LP
        (Gulf South) (together, operating subsidiaries). We completed our initial
        public
        offering (IPO) of 15.0 million common units in November 2005 and, in the
        fourth
        quarter 2006, we sold 6.9 million common units in a follow-on public offering.
        The common units sold in our IPO and follow-on offerings represent approximately
        19.8% of partners’ capital which includes common units, subordinated units and a
        2% general partner interest. All of our common and subordinated units, other
        than the common units sold in the public offerings, are held by Boardwalk
        Pipelines Holding Corp. (BPHC), a wholly-owned subsidiary of Loews Corporation
        (Loews). Boardwalk GP, LP (Boardwalk GP), an indirect wholly-owned subsidiary
        of
        BPHC, holds the 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
        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 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. For the year ended December 31, 2006, approximately 62% of our
        revenues were derived from capacity reservation charges under firm contracts,
        approximately 17% of our revenues were derived from other charges based on
        actual utilization under firm contracts and approximately 21% of our revenues
        were derived from interruptible transportation, interruptible storage and
        parking and lending (PAL) and other services.
 
 
 ***Our
        Pipeline and Storage Systems***
 
 We
        own
        and operate two interstate natural gas pipeline systems, with approximately
        13,400 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
        2006,
        our pipeline systems transported approximately 1,340 billion cubic feet (Bcf)
        of
        gas. Average daily throughput on our pipeline systems during 2006 was
        approximately 3.7 Bcf. Our natural gas storage facilities are comprised of
        eleven underground storage fields located in four states with aggregate working
        gas capacity of approximately 146 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 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.
 
 3
  ***Our
        Texas Gas System***
  The
        Texas
        Gas pipeline system originates in the Louisiana Gulf Coast area 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:
  ·
            approximately
                5,900 miles of pipeline, having a peak-day delivery capacity of
                approximately 3.2 Bcf per day which includes deliveries to pipeline
                interconnects in South Louisiana;  ·
            31
                compressor stations having an aggregate of approximately 536,000
                horsepower; and  ·
            nine
                natural gas storage fields located in Indiana and Kentucky, having
                aggregate storage capacity of approximately 178.0 Bcf of gas, of
                which
                approximately 63.0 Bcf is designated as working
                gas. 
 Texas
        Gas’s direct market area 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 Texas Gas’s 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.
 
  ***Our
        Gulf South System***
  The
        Gulf
        South pipeline system is located entirely in the Gulf Coast states of Texas,
        Louisiana, Mississippi, Alabama and Florida. This system is composed of:
 
 ·
            approximately
                7,500 miles of pipeline, having a peak-day delivery capacity of
                approximately 3.5 Bcf per day; 
 ·
            29
                compressor stations having an aggregate of approximately 225,000
                horsepower; and  ·
            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.  The
        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 LDC and municipality load serving
        communities 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.
 
 4
 
 ***Expansion
        Projects***
 
 *Carthage
        to Keatchie Loop* .
        We have
        constructed a 20.5 mile segment of 42-inch pipeline from Carthage, Texas
        to
        Keatchie, Louisiana which was placed in service in December 2006. The current
        capacity of this loop is 120 MMcf per day.
 
 *East
        Texas to Mississippi Expansion.* We are
        pursuing a pipeline expansion project consisting of 242 miles of 42-inch
        pipeline from DeSoto Parish in western Louisiana to near Harrisville,
        Mississippi and approximately 110,000 horsepower of new compression. The
        expansion would add approximately 1.7 Bcf per day of new transmission capacity
        to our Gulf South pipeline system. The natural gas to be transported on this
        expansion will originate primarily from the Barnett Shale and Bossier Sands
        producing regions of East Texas. The expansion will transport natural gas
        to new
        interstate pipeline interconnects in the Perryville, Louisiana area and existing
        pipeline interconnects with other pipelines east of the Mississippi River.
        This
        project is supported by binding precedent agreements with customers who have
        contracted, on a long-term basis (with a weighted average term of approximately
        7 years), for 1.3 Bcf per day from Carthage, Texas with an option for an
        additional 100 MMcf per day. On September 1, 2006, we filed a certificate
        application relating to this project with the FERC. We expect this project
        to be
        in service during the fall of 2007.
 
 *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 a new subsidiary, Gulf Crossing Pipeline Company LLC (Gulf Crossing),
        and
        will consist of approximately 355 miles of 42-inch pipeline having capacity
        of
        up to approximately 1.6 Bcf per day. Additionally, Gulf Crossing will enter
        into: (i) a lease for at least 1.1 Bcf per day of capacity on our Gulf South
        pipeline system (including on the Southeast Expansion and 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;
        and
        (ii) a lease with a third-party intrastate pipeline which will bring certain
        gas
        supplies to our system. This project is supported by binding agreements with
        customers who have contracted for 1.1 Bcf per day of capacity under firm
        contracts having terms of 5 to 10 years (with a weighted average term of
        approximately 9.8 years), and options with certain of these customers for
        an
        additional 350 MMcf per day of capacity. We anticipate making the required
        filings with the FERC by July 2007 and for the project to be in service during
        the fourth quarter of 2008. We are in negotiations with one of the foundation
        shippers supporting this project concerning the purchase of 49.0% of the
        equity
        of Gulf Crossing.
 
 *Southeast
        Expansion* .
        We are
        pursuing a pipeline expansion extending our Gulf South pipeline system from
        near
        Harrisville, Mississippi to an interconnect with Transco in Choctaw County,
        Alabama which will enhance our ability to deliver gas to the Northeast through
        other pipeline interconnects. This expansion will consist of approximately
        112
        miles of 42-inch pipeline having initial capacity of approximately 1.2 Bcf
        per
        day, expandable to as much as 2.0 Bcf per day to accommodate volumes expected
        to
        come from the Gulf Crossing leased capacity discussed above. In addition,
        Gulf
        South has executed a lease with Destin Pipeline Company to access markets
        in
        Florida. This project is supported by binding agreements with customers who
        have
        contracted for 660 MMcf per day of capacity under firm contracts having terms
        of
        5 to 10 years (with a weighted-average term of 9.2 years), as well as the
        capacity leased to Gulf Crossing discussed above. The certificate filing
        was
        made with the FERC in December 2006 and the project is anticipated to be
        in
        service during first quarter 2008.
 
 *Fayetteville
        Shale* .
        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 Texas Gas. The Fayetteville Lateral,
        consisting of approximately 165 miles of 36-inch pipeline, is anticipated
        to
        have an initial design capacity of 800 MMcf per day and a maximum design
        capacity of 1.1 Bcf per day. This lateral will originate in Conway County,
        Arkansas and proceed southeast through the Bald Knob, Arkansas area to an
        interconnect with Texas Gas’s mainline in Coahoma County, Mississippi. The
        Greenville Lateral, consisting of approximately 95 miles of pipeline with
        an
        initial design capacity of 750 MMcf per day, will originate at Texas Gas’s
        mainline near Greenville, Mississippi and proceed east to the Kosciusko,
        Mississippi area. The Greenville Lateral will allow customers to access
        additional markets, primarily in the Midwest, Northeast and Southeast, including
        the Henry Hub. Construction of both laterals is supported by a binding precedent
        agreement with Southwestern Energy Services Company, a wholly-owned subsidiary
        of Southwestern Energy Company. In December 2006, the FERC granted Texas
        Gas’s
        request to initiate the pre-filing process for this project and we anticipate
        making the required certificate filings with the FERC in June 2007. We expect
        the project to be in service during the first quarter 2009.
 
 The
        total
        cost of the pipeline expansion projects discussed above is expected to be
        approximately $3.3 billion (before taking into account equity that would
        be
        contributed by the purchaser of a 49.0% interest in Gulf Crossing Pipeline
        referred to above).  We constantly seek to optimize these projects to
        reduce the overall cost. However the actual cost to complete these projects
        may
        exceed our current estimate as a result of, among other things, higher labor
        and
        materials costs due to the large number of pipeline projects under way
        throughout the industry or our need to expand pipeline capacity if we contract
        for additional volumes. For a further discussion of the risks associated
        with
        these projects, see the section on Risk Factors in Item 1A of this
        Report.
 
 *Western
        Kentucky Storage Expansion.* In
        December 2006, the FERC issued a certificate approving Texas Gas’s Phase II
        storage expansion project which will expand the working gas capacity in its
        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
        for the full additional capacity at Texas Gas’s maximum applicable rate. We
        expect this project to cost approximately $40.7 million and to be in service
        by
        November 2007. In December 2006, Texas Gas commenced an open season related
        to a
        potential third expansion of its storage facilities. Texas Gas has signed
        one
        precedent agreement for 2.0 Bcf of capacity. The ultimate size of the Phase
        III
        storage expansion will be determined, in part, by the open season. The Phase
        III
        storage expansion is subject to the FERC approvals, including potential
        market-based rate authority for the additional new storage capacity being
        created. Phase I of this project which expanded working gas capacity by
        approximately 8.0 Bcf was completed and in service in November
        2005.
 
 *Magnolia
        Storage Facility.* We
        are
        currently developing an additional storage cavern near Napoleonville, Louisiana.
        During mining operations, certain issues have arisen causing the mining of
        the
        cavern to be suspended. We are continuing to conduct operational integrity
        tests
        on the caverns. The tests are on-going but have been delayed due to lack
        of
        equipment availability needed to complete the testing. If the test results
        are
        favorable, we expect the storage facilities to be in service perhaps as early
        as
        2008 with working gas capacity of 2.0 Bcf, reduced from 6.0 Bcf as originally
        designed. If the test results are not favorable, we will consider the options
        it
        has available, including developing a new cavern, or the sale or abandonment
        of
        the project.
 
 5
 
 ***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 three months to ten
        years,
        although short-term firm transportation services can be offered with daily
        terms. 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. Generally, interruptible transportation
        agreements have terms of thirty days or less.
  *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 five years. Interruptible
        storage customers pay for the volume of gas actually stored. Generally,
        interruptible storage agreements range from one to twelve months. Unlike
        most
        other FERC-regulated pipelines, including Texas Gas, Gulf South is authorized
        to
        charge market-based rates for its firm and interruptible storage
        services.
  *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 pull 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.
  *PAL
        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 pipelines 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. Gulf South’s
        customers are located throughout its service area and elsewhere or are accessed
        through numerous interconnects on unaffiliated pipeline systems. In contrast,
        the Texas Gas system primarily moves gas for its customers in a northeasterly
        direction to serve markets directly connected to the Texas Gas system and
        also
        serves indirect customer markets through interconnects with other interstate
        pipelines.
  Based
        upon 2006 revenues, our customer mix was comprised as follows: LDCs (35%),
        pipeline interconnects (33%), storage (14%), industrial end-users (6%), power
        plants (6%) and miscellaneous other (6%). We contract directly with customers
        connected to our system and with marketers, producers and other third parties
        who provide transportation and storage services to end users not directly
        connected with our system.
  *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, 2006. 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 use storage to facilitate trading opportunities,
        and producers 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.
 
 6
 
 ***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 proposed Rockies Express Pipeline that would
        transport natural gas from northern Colorado to eastern Ohio; the Heartland
        Gas
        Pipeline currently being constructed in Indiana; the proposed Mid-Continent
        Express Pipeline that would transport gas from Texas to Alabama; and the
        proposed Southeast Header Supply System that would transport gas from
        Perryville, Louisiana to markets in Florida. 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,
        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 2006,
        approximately 57% of our total operating revenues were recognized in the
        first
        and fourth calendar quarters.
  7
 ***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 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 FERC rate-making
        process. Key determinants in the rate-making process are the costs of providing
        service, the allowed rate of return on capital investments, volume throughput
        assumptions, the allocation of costs and the rate design. The allowed rate
        of
        return must be approved by the FERC in each rate case. Texas Gas filed a
        rate
        case in 2005, which was settled in the second quarter of 2006. Texas Gas
        has no
        obligation to file a new rate case and is prohibited from placing new rates
        into effect prior to November 1, 2010. Gulf South has no 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:
 
 (a)
            the
                Clean Air Act and analogous state laws which impose obligations related
                to
                air emissions; 
 (b)
            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; 
 (c)
            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 
 (d)
            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.   ***Effects
        of Compliance with Environmental Regulations***
 
 Note
        3 in
        Item 8 of this Report contains information regarding environmental
        compliance.
 
 
 ***Employee
        Relations***
 
 At
        December 31, 2006, we had approximately 1,150 employees, approximately 90
        of
        which are covered by a collective bargaining agreement, which will expire
        on
        April 30, 2007. A satisfactory relationship continues to exist between
        management and labor. Approximately 100 employees, included in the total
        employee count at December 31, 2006, elected to retire under an early retirement
        incentive program (ERIP) offered to approximately 240 employees at Texas
        Gas.
        Most of the retirements were effective January 1, 2007, and the remainder
        will
        be effective by the end of 2007. 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 substantially all Texas Gas employees. Note 9 in
        Item
        8 of this Report contains further discussion of our employee
        benefits.
 
 
 **Available
        Information**
 
 Our
        internet website is located at *www.boardwalkpipelines.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,
        3800
        Frederica Street, Owensboro, Kentucky, 42301.
 
 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, 3800 Frederica St., Owensboro, KY 42301, 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, 3800 Frederica St., Owensboro, KY 42301,
        Attention: Corporate Secretary. All such communications will be delivered
        to the
        director or directors to whom they are addressed.
  8
  **Item
        1A. Risk Factors**
  Our
        business faces many risks. We have described below some of the more significant
        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 significant
        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.
 
 
 ***We
        may not complete expansion projects that we commence, or we may complete
        projects on materially different terms or timing than initially anticipated
        and
        we may not be able to achieve the intended benefits of any such project,
        if
        completed.***
  We
        have
        announced significant expansion projects and may consider additional expansion
        projects in the future. We anticipate that we will be required to seek
        additional financing in the future to fund our current and future expansion
        projects and we may not be able to secure such financing on favorable terms,
        or
        at all. In addition, we may not be able to complete the expansion projects
        on
        time as a result of weather conditions, delays in obtaining or failure to
        obtain
        regulatory approvals, delays in obtaining key materials, labor difficulties
        and
        land owner opposition, difficulties with partners or potential partners or
        other
        factors beyond our control. If we do not meet designated schedules for approval
        and construction of our expansion projects, certain of our customers may
        have
        the right to terminate their precedent agreements relating to the expansion
        projects. Certain customers may also have the right to receive liquidated
        damages. Even if expansion projects are completed, the total costs of the
        expansion projects may be higher than anticipated and the performance of
        our
        business following the expansion projects may not meet expectations. Further,
        we
        may not be able to timely and effectively integrate the expansion projects
        into
        our operations, such integration may result in unforeseen operating difficulties
        or unanticipated costs and the expansion projects might divert the attention
        of
        management from our other business concerns. Any of these or other factors
        could
        adversely affect our ability to realize the anticipated benefits from the
        expansion projects and thus have a material adverse effect on our business,
        financial condition, results of operations and cash flows.
 
 
 ***Our
        natural gas transportation, gathering and storage operations are subject
        to FERC
        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.***
  Action
        by
        the FERC on currently pending matters as well as matters arising in the future
        could adversely affect our ability to establish rates, or to charge rates
        that
        would cover future increases in our costs, or even to continue to collect
        rates
        that cover current costs. 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 Texas Gas
        or
        Gulf South could have a material adverse effect on our business, financial
        condition, results of operations and cash flows.
  On
        July 20, 2004, the United States Court of Appeals for the District of
        Columbia Circuit (D.C. Circuit) issued its opinion in *BP
        West Coast Products, LLC v. FERC (BP West Coast)* and
        vacated the portion of the FERC’s decision applying the FERC’s *Lakehead* policy
        to determine an allowance for income taxes in the regulated cost of service.
        In
        its *Lakehead* decision,
        the FERC allowed an oil pipeline limited partnership to include in its cost
        of
        service an income tax allowance to the extent that its unitholders were
        corporations subject to income tax. The D.C. Circuit emphasized that a regulated
        pipeline’s cost of service should include only “appropriate cost[s]” and
        compared income taxes paid by owners of equity interests in a pipeline to
        the
        costs of bookkeeping paid by such owners, indicating the court’s belief that
        such costs paid by an entity other than the regulated entity would not be
        recoverable in the rates of the pipeline. In May and June 2005, the FERC
        issued
        a statement of general policy and an order on remand of *BP
        West Coast* ,
        respectively, in which the FERC stated it will permit pipelines to include
        in
        cost-of-service a tax allowance to reflect actual or potential tax liability
        on
        their public utility income attributable to all partnership or limited liability
        company interests, if the ultimate owner of the interest has an actual or
        potential income tax liability on such income. Whether a pipeline’s owners have
        such actual or potential income tax liability will be reviewed by the FERC
        on a
        case-by-case basis. Although the new policy is generally favorable for pipelines
        that are organized as pass-through entities, it still entails risk due to
        the
        case-by-case review requirement. In December 2005, the FERC issued a
        case-specific review of the income tax allowance issue in the *SFPP,
        L.P.* proceeding. The FERC ruled favorably to SFPP, L.P. on all income tax issues
        and
        set forth guidelines regarding the type of evidence necessary for the pipeline
        to determine its income tax allowance. The FERC’s *BP
        West Coast* remand
        decision, the new tax allowance policy, and the December 2005 order have
        been
        appealed to the D.C. Circuit. As a result, the ultimate outcome of these
        proceedings is not certain and could result in changes to the FERC’s treatment
        of income tax allowances in cost of service. If the FERC were to change its
        tax
        allowance policies in the future, or if current policy was reversed or changed
        on appeal by a court, such changes could materially and adversely impact
        the
        rates we are permitted to charge as future rates are approved for our interstate
        transportation services.
  9
  ***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:
 ·
            operating
                terms and conditions of service; ·
            the
                types of services we may offer to our customers; ·
            construction
                of new facilities; ·
            creation,
                extension or abandonment of services or facilities; ·
            accounts
                and records; and ·
            relationships
                with certain types of affiliated companies involved in the natural
                gas
                business.  The
        FERC
        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.
 
 
 ***Catastrophic
        losses are unpredictable.***
 
 Catastrophic
        losses may be an inevitable part of our business. Various events can cause
        catastrophic losses, including hurricanes, windstorms, earthquakes, hail,
        explosions, and severe winter weather and fires, the frequency and severity
        of
        these events are inherently unpredictable. Although we carry insurance, the
        coverage could be insufficient.
  
 ***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.
  10
 
 ***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.
        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 Office of Pipeline Safety (OPS) 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.
  The
        final
        rule requires operators 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 OPS 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.
  11
  ***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 several new pipeline projects that are under way, including
        the
        proposed Rockies Express Pipeline that would transport natural gas from northern
        Colorado to eastern Ohio, the Heartland Gas Pipeline currently being constructed
        in Indiana, the proposed Mid-Continent Express Pipeline that would transport
        gas
        from Texas to Alabama and the proposed Southeast Header Supply System that
        would
        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 could adversely affect our business and operating results.***
  For
        the
        years 2003 to 2005, gas production from the Gulf Coast region, which supplies
        the majority of our throughput, has declined on average approximately 11%
        per
        year according to the Energy Information Administration (EIA). A large part
        of
        this decline was due to the effects of Hurricanes Katrina and Rita 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.
  12
 
 ***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% greater than pipeline capacity
        leaving that point, creating a bottleneck for supply into areas of high demand.
        As of December 31, 2006, approximately 21% of our long-term contracts with
        firm
        deliveries to Lebanon expire by the end of 2007. 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, a new proposed pipeline from the Rockies, 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, 2006,
        approximately 14% of the firm contract load on our pipeline systems was due
        to
        expire on or before December 31, 2007. 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:
 
 ·
            existing
                and new competition to deliver natural gas to our markets; 
 ·
            the
                growth in demand for natural gas in our markets; 
 ·
            whether
                the market will continue to support long-term contracts; 
 ·
            the
                current basis differentials, or market price spreads between two
                points on
                our pipelines; 
 ·
            whether
                our business strategy continues to be successful; and 
 ·
            the
                effects of state regulation on customer contracting practices. 
  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.
  13
  ***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, 2006, ProLiance Energy, LLC and Atmos Energy accounted
        for approximately 18.35% 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, our Gulf South pipeline can deliver
        approximately 500 MMcf per day to Texas Eastern at Kosciusko, Mississippi.
        If
        this or any other 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:
 
 ·
            worldwide
                economic conditions; 
 ·
            weather
                conditions and seasonal trends; 
 ·
            levels
                of domestic production and consumer demand; 
 ·
            the
                availability of LNG; 
 ·
            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; 
 ·
            the
                availability of adequate transportation capacity; 
 ·
            the
                price and availability of alternative fuels; 
 ·
            the
                effect of energy conservation measures; 
 ·
            the
                nature and extent of governmental regulation and taxation; and 
 ·
            the
                anticipated future prices of natural gas, LNG and other commodities. 
 
 14
  ***Expansion
        projects and acquisitions involve risks that may adversely affect our
        business.***
  A
        principal focus of our strategy is to continue to grow our business through
        acquisitions, expansion of existing assets and construction of new assets.
        Any
        acquisition, expansion or new construction involves potential risks, including:
 
 ·
            performance
                of our business following the acquisition, expansion or construction
                of
                assets that does not meet expectations; 
 ·
            a
                significant increase in our indebtedness and working capital requirements,
                which could, among other things, have an adverse impact on our credit
                ratings; 
 ·
            the
                inability to timely and effectively integrate into our operations
                the
                operations of newly acquired, expanded or constructed assets; 
 ·
            the
                incurrence of substantial unforeseen environmental and other liabilities,
                including liabilities arising from the operation of an acquired business
                or asset prior to our acquisition for which we are not indemnified
                or for
                which the indemnity is inadequate; 
 ·
            diversion
                of our management’s attention from other business concerns; and 
 ·
            regulatory
                risks created by the nature or location of acquired businesses. 
 Any
        of
        these factors could adversely affect our ability to realize the anticipated
        benefits from newly acquired, expanded or constructed assets and meet our
        debt
        service requirements. The process of integrating newly acquired, expanded
        or
        constructed assets into our operations may result in unforeseen operating
        difficulties or unanticipated costs that could have a material adverse effect
        on
        our business, financial condition, results of operations and cash
        flows.
  
 ***If
        we do not complete expansion projects or make acquisitions on economically
        acceptable terms, our future growth may be limited.***
  Our
        ability to grow depends on our ability to complete expansion and construction
        projects and make acquisitions. We may be unable to complete successful
        expansion and construction projects or make accretive acquisitions for any
        of
        the following reasons:
 
 ·
            we
                are unable to identify attractive expansion projects or acquisition
                candidates or we are outbid by competitors; 
 ·
            we
                are unable to obtain necessary governmental approvals; 
 ·
            we
                are unable to raise financing for such expansions or acquisitions
                on
                economically acceptable terms; or 
 ·
            we
                are unable to secure adequate customer commitments to use the expanded
                or
                acquired facilities. 
 Recently,
        competition from other buyers for natural gas pipelines and related assets
        and
        businesses has intensified. This competition may reduce our acquisition
        opportunities or cause us to pay a higher price than we might otherwise pay.
        If
        any of these events occurred, our future growth could be limited.
  
 ***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.
  15
 
 ***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.***
 
 A
        subsidiary of Loews owns 78.2% of the limited partner interests in us and
        will
        continue to own and control 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:
 
 ·
            Loews
                and its affiliates may engage in competition with
                us. 
 ·
            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. 
 ·
            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. 
 ·
            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. 
 ·
            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. 
 ·
            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. 
 ·
            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. 
 ·
            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. 
 ·
            Our
                general partner determines which costs, including allocated overhead,
                incurred by it and its affiliates are reimbursable by
                us. 
 ·
            Our
                partnership agreement does not restrict our general partner from
                causing
                us to pay it or its affiliates for any services rendered on terms
                that are
                fair and reasonable to us or entering into additional contractual
                arrangements with any of these entities on our behalf, and provides
                that
                reimbursement to Loews for amounts allocable to us consistent with
                accounting and allocation methodologies generally permitted by the
                FERC
                for rate-making purposes and past business practices is deemed fair
                and
                reasonable to us. 
 ·
            Our
                general partner intends to limit its liability regarding our contractual
                obligations. 
 ·
            Our
                general partner may exercise its rights to call and purchase (1) all
                of our common units if at any time it and its affiliates own more
                than 80%
                of the outstanding common units or (2) all of our equity securities
                (including common units) if it and its affiliates own more than 50%
                in the
                aggregate of the outstanding common units, 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. 
 ·
            Our
                general partner controls the enforcement of obligations owed to us
                by it
                and its affiliates. 
 ·
            Our
                general partner decides whether to retain separate counsel, accountants
                or
                others to perform services for us. 
 
 16
  ***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:
 
 ·
            permits
                our general partner to make a number of decisions in its individual
                capacity, as opposed to in 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;  ·
            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; 
 ·
            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 
 ·
            provides
                that our general partner and its officers and directors will not
                be liable
                for monetary damages to us, our limited partners or assignees for
                any acts
                or omissions unless there has been a final and non-appealable judgment
                entered by a court of competent jurisdiction determining that the
                general
                partner or those other persons acted in bad faith or engaged in fraud
                or
                willful misconduct. 
 
 ***We
        have a holding company structure in which our subsidiaries conduct our
        operations and own our operating assets, which may affect our ability to
        make
        distributions.***
  We
        are a
        partnership holding company and our operating subsidiaries conduct all of
        our
        operations and own all of our operating assets. We have no significant assets
        other than the ownership interests in our subsidiaries. As a result, our
        ability
        to make distributions to our unitholders depends on the performance of our
        subsidiaries and their ability to distribute funds to us. The ability of
        our
        subsidiaries to make distributions to us may be restricted by, among other
        things, the provisions of existing and future indebtedness, applicable state
        partnership and limited liability company laws and other laws and regulations,
        including FERC policies.
  ***Our
        credit agreement contains operating and financial restrictions that may limit
        our business and financing activities.***
  The
        operating and financial restrictions and covenants in our credit agreement
        and
        any future financing agreements could restrict our ability to finance future
        operations or capital needs or to expand or pursue our business activities.
        For
        example, our credit agreement restricts or limits our ability to:
  ·
            make
                certain loans or investments;  ·
            make
                any material change to the nature of our business, including
                consolidations, liquidations or
                dissolutions;  ·
            enter
                into a merger, consolidation, sale and leaseback transaction or sale
                of
                assets;  ·
            make
                distributions if any default or event of default
                occurs;  ·
            incur
                additional indebtedness or guarantee other indebtedness;
                or  ·
            grant
                liens or make certain negative pledges. 
  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 deteriorate, our ability to comply with these covenants may be
        impaired. If we violate any of the restrictions, covenants, ratios or tests
        in
        our credit agreement, a significant portion of our indebtedness may become
        immediately due and payable, and our lenders’ commitment to make further loans
        to us may terminate. We might not have, or be able to obtain, sufficient
        funds
        to make these accelerated payments.
 
 
 17
  **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 a material amount
        of entity-level taxation for state tax purposes, then our cash distributions
        to
        our unitholders would 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%, and would likely pay 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 a material amount of entity-level
        taxation. In addition, several states are evaluating ways to subject
        partnerships to entity-level taxation through the imposition of state income,
        franchise or other form of taxation. Imposition of such a tax on us will
        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.
 
 
 ***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 our tax counsel’s conclusions. It
        may be necessary to resort to administrative or court proceedings to sustain
        some or all of our tax counsel’s conclusions or the positions we take. A court
        may not agree with some or all of our tax counsel’s conclusions or 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.
  
 18
  ***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 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 foreign 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
        (known as IRAs), and non-U.S. persons raises issues unique to them. For example,
        virtually all of our income allocated to organizations that are exempt from
        federal income tax, including IRAs and other retirement plans, will be unrelated
        business taxable income and will 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 foreign 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.
  
 ***The
        sale or exchange of 50% or more of our capital and profit interests during
        any
        twelve-month period will result in the termination of our partnership for
        federal income tax purposes.***
  We
        will
        be considered terminated for federal income tax purposes, if there is a sale
        or
        exchange of 50% or more of the total interests in our capital and profits
        within
        a twelve-month period. ****** Our
        termination would, among other things, result in the closing of our taxable
        year
        for all unitholders and could result in a deferral of depreciation deductions
        allowable in computing our taxable income.
   ***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.
        Our counsel has not rendered an opinion on the state or local tax consequences
        of an investment in the common units.
 
  19
  **Item
        1B. Unresolved Staff Comments**
 
 None.
 
 
 **Item
        2. Properties**
 
 We
        and
        Texas Gas are headquartered in approximately 108,000
        square feet of office space in Owensboro, Kentucky in a building that is
        owned
        by Texas Gas. Gulf South has its headquarters in approximately 55,000 square
        feet of leased office space located in Houston, Texas. The lease for our
        Houston
        offices expires in May 2007 and, accordingly, we have signed a ten-year lease
        for approximately 74,000 square feet of office space in a new location in
        Houston, Texas. 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.
 
 
 **Item
        3. Legal Proceedings******
  For
        a
        discussion of certain of our current legal proceedings, please read Note
        3 in
        Item 8 of this Report.
 
 
 **Item
        4. Submission of Matters to a Vote of Security
        Holders**
 
 None.
 
  20
  **PART
        II******
 
 
 **Item
        5. Market for Registrant's Common Equity, Related Stockholder
        Matters and Issuer Purchases of Equity Securities**
 
 
 **Market
        Information**
 
 As
        of
        February 9, 2007, we had 75,156,122 common units
        outstanding, held of record by approximately 27 holders, BPHC owns
        52,356,122 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 9, 2007 was $35.46
        per
        unit.
 
 
 Sales
                  Price Range per Common Unit
              
              Cash
                  Distributions per Unit
                (a)High
              
              LowYear
                  ended December 31, 2006Fourth
                  quarter
              
              $
              31.64
              
              $
              25.25
              
              $
              0.415Third
                  quarter
              
              
              29.00
              
              
              23.63
              
              
              0.40Second
                  quarter
              
              
              25.18
              
              
              20.90
              
              
              0.38First
                  quarter
              
              
              22.00
              
              
              17.98
              
              
              0.36Year
                  ended December 31, 2005Fourth
                  quarter (b)
              
              
              19.23
              
              
              17.58
              
              
              0.179
                  (c
              )
 
 (a)
              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.(b)
              For
                  the period from November 15, 2005, the date of our IPO, through
                  December 31, 2005.(c)
              The
                  distribution for the fourth quarter 2005 represents a pro-rated
                  distribution of $0.35 per common and subordinated unit for the
                  period from
                  November 15, 2005 through December 31,
                  2005.
 
 
 **Our
        Cash Distribution Policy** ******
 
 Our
        cash
        distribution policy reflects a basic judgment that our unitholders will be
        better served by our distributing our available cash surplus rather than
        retaining it. 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.
 
 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, the 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.
 
  21
  ***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% interest, if we have made 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%
                2%First
                    Target Distribution
                
                up to $0.4025
                
                98%
                2%Second
                    Target Distribution
                
                above $0.4025 up to $0.4375
                
                85%
                15%Third
                    Target Distribution
                
                above
                    $0.4375 up to $0.5250
                
                75%
                25%Thereafter
                
                above
                    $0.5250
                
                50%
                50%
 ***Subordination
          Period***
 
 During
        the subordination period, 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% 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%
        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 four quarter period 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
        March
        23, 2006, our general partner purchased 1,000 of our common units in the
        open
        market at a price of $21.38 per unit. These units were granted to our
        independent directors on March 24, 2006, as part of their director compensation.
        See Executive Compensation - Director Compensation in Item 11 of this
        Report.
 
 
 22
  **Item
        6. Selected Financial Data******
 
 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 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
        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 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
        are not readily comparable with our results of operations for the years ended
        December 31, 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 a charge-in-lieu of income taxes or certain state franchise
        taxes incurred by BPHC and no longer participate in a tax-sharing agreement
        with
        Loews or tax sharing policy with BPHC. One of our subsidiaries directly incurs
        some income-based state taxes which are shown as Income taxes and charge-in-lieu
        of income taxes on the 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):
  **Boardwalk
                      Pipeline Partners**
                  
                  **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,**
                  
                  **For
                      the Year Ended**
                    **December
                      31,**(expressed
                      in thousands)
                  
                  **2006**
                  
                  **2005**
                  
                  **2004**
                  
                  **2003**
                  
                  **2003**
                  
                  **2002**Total
                      operating revenues
                  
                  $
                  607,642
                  
                  $
                  560,466
                  
                  $
                  263,621
                  
                  $
                  142,860
                  
                  $
                  113,447
                  
                  $
                  266,674Net
                      income
                  
                  
                  197,550
                  
                  
                  100,925
                  
                  
                  48,825
                  
                  
                  22,451
                  
                  
                  34,474
                  
                  
                  56,099Total
                      assets
                  
                  
                  2,951,299
                  
                  
                  2,465,491
                  
                  
                  2,472,140
                  
                  
                  1,238,627
                  
                  
                  N/A
                  
                  
                  1,412,148Long-term
                      debt
                  
                  
                  1,350,920
                  
                  
                  1,101,290
                  
                  
                  1,106,135
                  
                  
                  548,115
                  
                  
                  N/A
                  
                  
                  249,781Earnings
                      per common and subordinated unit
                  
                  $
                  1.85
                  
                  
                  *
                  
                  
                  N/A
                  
                  
                  N/A
                  
                  
                  N/A
                  
                  
                  N/AEBITDA**
                  
                  $
                  331,468
                  
                  $
                  289,002
                  
                  $
                  144,489
                  
                  $
                  77,241
                  
                  $
                  78,380
                  
                  $
                  149,569
  *
        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.
 
 23
  ****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 net income, operating income,
        cash
        flow from operating activities or any other measure of financial performance
        or
        liquidity presented in accordance with GAAP. 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 should not be considered as an alternative to, or more
        meaningful than, net income or cash flow as determined in accordance with
        generally accepted accounting principles or as an indicator of our operating
        performance or liquidity. 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**
                  
                  **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,**
                  
                  **For
                      the Year Ended**
                    **December
                      31,****2006**
                  
                  **2005**
                  
                  **2004**
                  
                  **2003**
                  
                  **2003**
                  
                  **2002**Net
                      income
                  
                  $
                  197,550
                  
                  $
                  100,925
                  
                  $
                  48,825
                  
                  $
                  22,451
                  
                  $
                  34,474
                  
                  $
                  56,099Income
                      taxes and charge-in-lieu of income taxes
                  
                  
                  253
                  
                  
                  49,494
                  
                  
                  32,333
                  
                  
                  15,104
                  
                  
                  22,387
                  
                  
                  36,647Elimination
                      of cumulative deferred taxes
                  
                  
                  -
                  
                  
                  10,102
                  
                  
                  -
                  
                  
                  -
                  
                  
                  -
                  
                  
                  -Depreciation
                      and amortization
                  
                  
                  75,771
                  
                  
                  72,078
                  
                  
                  33,977
                  
                  
                  20,544
                  
                  
                  16,092
                  
                  
                  37,806Interest
                      expense
                  
                  
                  62,123
                  
                  
                  60,067
                  
                  
                  30,081
                  
                  
                  19,368
                  
                  
                  7,392
                  
                  
                  20,490Interest
                      income
                  
                  
                  (4,202
                  )
                  
                  (1,478
                  )
                  
                  (352
                  )
                  
                  (205
                  )
                  
                  -
                  
                  
                  (5
                  )Interest
                      income from affiliates, net
                  
                  
                  (27
                  )
                  
                  (2,186
                  )
                  
                  (375
                  )
                  
                  (21
                  )
                  
                  (1,965
                  )
                  
                  (1,468
                  )EBITDA
                  
                  $
                  331,468
                  
                  $
                  289,002
                  
                  $
                  144,489
                  
                  $
                  77,241
                  
                  $
                  78,380
                  
                  $
                  149,569
  24
  **Item
        7. Management's Discussion and Analysis of Financial Condition
        and Results of Operations**
  *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 northward
        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 when capacity
        is
        available. 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 in advance of the service. Revenues for these agreements
        are
        recognized as service is provided over the term of the agreement. For the
        year
        ended December 31, 2006, the percentage of our total operating revenues
        associated with firm contracts was approximately 79.0%.
 
 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.
 
 
 **Trends
        and Uncertainties**
 
 The
        following trends and uncertainties have had, and are likely to continue to
        have,
        a material impact on our results of operations and liquidity:
 ·
            increasing
                competition for the transportation and storage of available gas supplies
                originating in a number of our supply
                areas; ·
            increasing
                competition from new and proposed pipelines providing natural gas
                to our
                market areas from other supply areas; ·
            the
                success of pipeline expansion in areas such as the Barnett Shale
                and
                Fayetteville Shale is dependent on natural gas prices being sufficiently
                high to support continued development in those
                areas; ·
            the
                likelihood that LNG from the Gulf Coast region will become an increasingly
                important source of supply for our
                customers; ·
            a
                change in the price of natural gas at different locations (basis
                differentials), which means that the value of the transportation
                services
                we offer may change over time based upon macro economic
                conditions. 
 We
        believe the collective impact of the trends and uncertainties described in
        the
        first two bullet points above may result in an increasingly competitive gas
        transportation market. This could result in reduced rates on many of our
        contracts, adversely affecting revenue and cash flows. We believe that the
        impact of the factors described in the third and fourth bullet points above
        may
        provide us with growth opportunities. The last bullet point may result in
        reduced rates or provide growth opportunities based upon the level of basis
        differentials. The last three bullets also result in the need for increasing
        amounts of capital expenditures to take advantage of opportunities to bring
        new
        supplies of natural gas into our systems to maintain or possibly increase
        our
        transportation volumes.
 
 25
  **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 at the date of 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 period in which the
        facts
        that give rise to the revision become known.
 
 
 ***Earnings
        per Unit***
 
 We
        calculate net income per limited partner unit in accordance with Emerging
        Issues
        Task Force Issue No. 03-6 (EITF No. 03-6), *Participating Securities and the Two-Class Method under Financial Accounting
        Standards Board (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 amount
        reported for net income per limited partner unit on the Consolidated
        Statements of Income for the year ended December 31, 2006 was reduced 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 and not
        based
        on the assumed allocation required by EITF No. 03-6.
  
 ***Regulation***
 
 Certain
        revenues collected may be subject to possible refunds. Accordingly, estimates
        of
        rate refund reserves are recorded considering regulatory proceedings, advice
        of
        counsel and estimated risk-adjusted total exposure, as well as other factors.
        For instance, Texas Gas filed a general rate case with the FERC on April
        29,
        2005, and implemented new rates on November 1, 2005, subject to refund. As
        of
        December 31, 2005, an estimated refund liability of approximately $5.0 million
        related to the Texas Gas rate case was recorded on our Consolidated Balance
        Sheets. The outcome of the rate case was determined in the second quarter
        2006,
        and the refund liability was reduced to zero by the amount of cash refunds
        paid
        to customers on June 30, 2006. The refund totaling approximately $6.6 million
        consisted of $6.4 million in principal and $0.2 million in interest. At December
        31, 2006, there was no liability for any open rate case recorded on our
        Consolidated Balance Sheets. Currently, neither Texas Gas nor Gulf South
        are
        involved in an open general rate case.
  Statement
        of Financial Accounting Standards (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 Gulf South are priced using market-based rates
        and
        competition in Gulf South’s market area can result in discounts from the maximum
        allowable cost-based rates 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. 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.
        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. 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 independent consultants and
        the
        current facts and circumstances related to these environmental matters. At
        December 31, 2006, we had accrued approximately $18.4 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 (EPA), 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.
 
 26
  ***Goodwill***
  As
        of
        December 31, 2006, 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, 2006, 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. The use of alternate judgments and/or assumptions
        could result in the recognition of different levels of impairment charges
        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
        supplemented our discount rate decision with a yield curve analysis. The
        yield
        curve was applied to expected future retirement plan payments to adjust the
        discount rate to reflect the cash flow characteristics of the plans. The
        yield
        curve was 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 operating 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 transportation revenues.
 
 The
        following analysis discusses our financial results of operations for the
        years
        2006, 2005 and 2004. The acquisition of Gulf South was consummated on December
        29, 2004. Three days of activity are included in the 2004 Consolidated
        Statements of Income and Cash Flows. The financial activity of Gulf South
        for
        those three days is considered immaterial and does not impact discussions
        below.
 
 
 27
  ***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 Katrina and Rita
                (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 that occurred 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
                an
                increase 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.
 
 28
 
 ***2005
        Compared with 2004***
 
 Our ****** Net
        income for the year ended December 31, 2005, increased $52.1 million or 106.7%
        from 2004. The primary driver for the increase was the acquisition of Gulf
        South
        on December 29, 2004.
 
 Total
        operating revenues increased $296.8 million, or 112.6%, to $560.4 million
        for
        the year ended December 31, 2005 compared to $263.6 million for the year
        ended
        December 31, 2004, primarily due to:
 
 ·
            $259.8
                million increase in transportation revenues, substantially all of
                which
                was attributable to Gulf South, and increased interruptible revenues
                due
                to supply disruptions caused by the hurricanes. Lower revenues from
                contract renewals and related discounting at the Lebanon terminus
                of our
                Texas Gas system were partially offset by new rates, subject to refund,
                implemented by Texas Gas on November 1, 2005, and by new projects
                including transportation agreements related to our market area storage
                expansion project in Western Kentucky and increased capacity from
                Carthage, Texas by leasing capacity on a third-party pipeline. 
 ·
            $27.6
                million increase in PAL and gas storage revenues of which $29.2 million
                was attributable to Gulf South. Storage revenues at Texas Gas were
                lower
                by $2.0 million primarily as a result of unusually high interruptible
                storage revenue generated in 2004 due to favorable market conditions;
                and 
 ·
            $9.4
                million increase in Other revenues of which $11.1 million was attributable
                to Gulf South. 
 Operating
        costs and expenses increased by $191.1 million, or 124.2%, to $345.0 million
        for
        the year ended December 31, 2005, compared to $153.9 million for the year
        ended
        December 31, 2004. This increase is partially due to:
  ·
            $207.4
                million increase attributable to Gulf South, $12.9 million of which
                was
                due to casualty losses recognized as a result of the
                hurricanes.. 
 This
        increase was partly offset by:
 
 ·
            $12.2
                million decrease due to the sale of storage gas related to Phase
                I of our
                Western Kentucky storage expansion project, partially offset by asset
                retirements. 
 Total
        other deductions increased by $26.4 million, or 92.0%, of which $28.9 million
        is
        due to higher interest expense primarily related to debt incurred in 2004
        to
        fund the acquisition of Gulf South.
 
 
 29
  **Recent
        Expansion Projects**
 
 We
        are
        currently engaged in several major pipeline and storage expansion projects
        that
        we expect will require the investment of approximately $3.3 billion of capital
        from 2007 to 2009 (before taking into account equity that would be contributed
        by the purchaser of a 49% interest in Gulf Crossing Pipeline). The pipeline
        expansion projects will transport natural gas supplies from the Bossier Sands,
        Barnett Shale, Fayetteville Shale and the Caney/Woodford Shale areas in East
        Texas, Arkansas and Oklahoma to our existing or new assets and third-party
        interstate pipeline interconnects in Alabama and Mississippi. For more
        information on our expansion projects, please see “Recent Expansion Projects” in
        Item 1 of this Report.
 
 
 **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, as discussed above.
 
 
 ***Capital
        Expenditures***
 
 Capital
        expenditures, net of amounts received for salvage and accrued amounts, for
        2006,
        2005 and 2004 were as follows (in millions):
 
 **December
                  31, 2006**
              
              **December
                  31, 2005**
              
              **December
                  31, 2004**Expansion
                  capital
              $
                  158.6
              
              $
                  30.1
              
              $
                  7.7Maintenance
                  capital
              41.7
              
              52.9
              
              34.2Total
              $
                  200.3
              
              $
                  83.0
              
              $
                  41.9
 
 For
        the
        year ending December 31, 2007, we expect to make capital expenditures of
        approximately $1.7 billion, of which we expect approximately $1.6 billion
        to be
        for the expansion projects discussed in Item 1 and approximately $60.0 million
        to be for maintenance capital. The amount of expansion capital we expend
        in 2007
        could vary significantly depending on the progress made with these projects,
        the
        number and types of other capital projects we decide to pursue, the timing
        of
        any of those projects and numerous other factors beyond our control.
 
 We
        expect
        to fund our expansion capital expenditures for 2007 and beyond with proceeds
        from sales of our debt and equity securities, borrowings under our revolving
        credit facility and operating cash flows, though we have not made any
        determination with regard to such financing. We expect to fund our maintenance
        capital expenditures from operating cash flows.
 
 30
 
 ***Equity
        and Debt Offerings***
 
 During
        the fourth quarter 2006, we completed an offering of 6,900,000 of our common
        units at a price of $29.65 per unit. The offering resulted in net proceeds
        of
        $199.4 million, after deducting underwriting discounts and offering expenses
        of
        $9.4 million and including $4.2 million received from our general partner
        to
        maintain its 2.0% interest in us.
 
 Also
        during the fourth quarter of 2006, we completed an offering of $250.0 million
        of
        5.88% senior notes due 2016. We received net proceeds of approximately $248.3
        million after deducting underwriting discounts and commissions and offering
        expenses of $1.7 million.
 
 The
        proceeds of these offerings will be used to finance our expansion activities.
        We
        used $90.0 million of the proceeds to repay outstanding borrowings under
        our
        revolving credit facility which were used to finance expansion
        activities.
 
 To
        hedge
        the risk attributable to changes in the risk-free component of forward 10-year
        interest rates through December 1, 2006, on October 5, 2006 we entered into
        a
        Treasury rate lock for a notional amount of $250.0 million of principal.
        The
        reference rate on the Treasury rate lock was 4.60%. The Treasury rate lock
        was
        settled at the time of the closing of our debt offering in November 2006.
        We
        received $0.9 million from the counterparty as a result of the settlement
        of the
        Treasury rate lock, which has been recorded as a component of accumulated
        other
        comprehensive income. The amount of the credit in accumulated other
        comprehensive income will be recognized in income as a reduction to interest
        expense on a straight-line basis over the 10-year term of the 5.88% senior
        notes, resulting in an effective rate of 5.92%, including the effects of
        the
        discounts and offering expenses.
 
 In
        August
        2006, we 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 those Treasury rate locks were 5.00%
        and
        4.96%. See Item 7A for more information regarding the Treasury rate locks
        and
        interest rate risk.
 
 
 ***Credit
        Facility***
 
 We
        maintain a $400.0 million revolving credit facility under which Boardwalk
        Pipelines, Texas Gas and Gulf South 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, 2006, we were in compliance with all the covenant requirements
        under our credit agreement and no funds were drawn under this facility. The
        revolving credit facility has a maturity date of June 29, 2011.
 
 ***Contractual
        Obligations***
  The
        following table summarizes significant contractual cash payment obligations
        as
        of December 31, 2006, by period (in millions):
  **Payments
                  due by Period****Total**
              
              **Less than**
                **1
                  Year**
              
              **1-3 Years**
              
              **4-5 Years**
              
              **More than**
                **5
                  Years**Lease
                  commitments
              
              $
              34.8
              
              $
              5.9
              
              $
              14.3
              
              $
              4.1
              
              $
                  10.5Interest
                  on long-term debt
              
              
              811.1
              
              
              72.6
              
              
              220.2
              
              
              146.8
              
              371.5Capital
                  commitments
              
              
              409.1
              
              
              403.8
              
              
              5.2
              
              
              0.1
              
              -Principal
                  payments on long-term debt
              
              
              1,360.0
              
              
              -
              
              
              -
              
              
              -
              
              1,360.0Total
              
              $
              2,615.0
              
              $
              482.3
              
              $
              239.7
              
              $
              151.0
              
              $
                  1,742.0
 
 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, 2006 relating to our expansion projects. For information on
        these
        projects please read “Capital Expenditures” above.
 
 
 31
  ***Changes
        in cash flow from operating activities***
  Net
        cash
        provided by operating activities increased $36.8 million, or 16.8%, to $255.5
        million for the year ended December 31, 2006, compared to $218.7 million
        for the
        year ended December 31, 2005, primarily due to:
 
 ·
            $54.2
                million increase in net income before noncash adjustments for depreciation
                and amortization, provision for deferred income taxes and gain on
                disposal
                of operating assets; ·
            $17.4
                million increase in cash from a reduction in operating assets net
                of
                operating liabilities mainly from increases in payables and deferred
                income on PAL agreements, and decreases in receivables, partly offset
                by
                an increase in other current assets primarily from the recognition
                of
                unrealized gains on derivatives; and ·
            $34.8
                million decrease in cash from a reduction in other noncurrent liabilities
                net of noncurrent assets. 
 
 ***Changes
        in cash flow from investing activities***
  Net
        cash
        used in investing activities increased $89.2 million, or 87.2%, to $191.5
        million for the year ended December 31, 2006, compared to $102.3 million
        for the
        year ended December 31, 2005, primarily due to:
 
 ·
            $117.4
                 million increase in capital expenditures mainly related to our
                expansion projects; and ·
            $27.5
                million reduction in advances to
                affiliates. 
 
 ***Changes
        in cash flow from financing activities***
  Net
        cash
        provided by (used in) financing activities increased $336.3 million to $269.2
        million provided by financing activities for the year ended December 31,
        2006,
        compared to a use of $67.1 million for the year ended December 31, 2005,
        primarily due to:
 
 ·
            $419.7
                million decrease in cash used from the payment of notes and other
                long-term debt in 2005 slightly offset by payment in 2006 of interim
                financing borrowed in 2005 for capital expenditures incurred in connection
                with the acquisition of Gulf South; and ·
            $76.2
                million decrease in cash provided from public offerings of common
                units. 
 
 ***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. While
        amounts in excess of historical cost are not recoverable under current FERC
        practices, we believe we may be allowed to recover and earn a return based
        on
        the increased actual costs incurred when existing facilities are replaced.
        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, 2006, 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.
 
 32
  ***Recent
        Accounting Pronouncements***
 
 For
        a
        discussion regarding recent accounting pronouncements, please read Note 15
        in
        Item 8 of this Report.
 
 **Forward-Looking
        Statements**
 
 Investors
        are cautioned that certain statements contained in this report as well as
        some
        statements in periodic press releases and some oral statements made by our
        officials and our subsidiaries during presentations about us, are
“forward-looking” statements within the meaning of the Private Securities
        Litigation Reform Act of 1995 (Act). 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 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, which may be provided by management, are also forward-looking
        statements as defined by the Act.
 
 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
                commence, or we may complete projects on materially different terms
                or
                timing than anticipated and we may not be able to achieve the intended
                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 weather, untimely regulatory approvals or denied
                applications, land owner opposition, the lack of adequate materials,
                labor
                difficulties, difficulties we may encounter with partners or potential
                partners, expansion cost higher than anticipated and numerous other
                factors beyond our control. 
 ·
            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 from existing wells, 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.
 
 
  33
  **Item
        7A. Quantitative and Qualitative Disclosures About Market
        Risk**
  Our
        long-term debt is subject to interest rate risk. Total long-term debt at
        December 31, 2006, had a carrying value of $1.4 billion and a fair value
        of $1.3
        billion. The weighted-average interest rate of our long-term debt was 5.40%
        at
        December 31, 2006.
 
 In
        August
        2006, we 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 are 5.00% and 4.96%.
        Under
        the terms of the rate locks, the counterparties would pay us settlement amounts
        if the 10-year Treasury rate is greater than the reference rates at October
        1,
        2007. Conversely, we would pay the counterparties settlement amounts if the
        10-year Treasury rate is less than the reference rates. A 10 basis point
        decrease in the 10-year Treasury rate would result in a $1.6 million favorable
        change in the value of the rate locks. Conversely, a 10 basis point increase
        in
        the 10-year Treasury rate would result in a $1.6 million unfavorable change
        in
        the value of the rate locks. The Treasury rate locks were designated as cash
        flow hedges in accordance with SFAS No. 133. As of December 31, 2006, we
        reported a liability of $4.3 million, and a reduction in Accumulated other
        comprehensive income in an equal and offsetting amount less ineffectiveness
        recognized of less than $0.1 million, for the fair values of the August 2007
        rate locks.
 
 Certain
        volumes of our gas stored underground are available for sale and subject
        to
        commodity price risk. At December 31, 2006 and 2005, approximately $14.0
        million
        and $6.5 million, of our gas stored underground, which we own and carry as
        current Gas stored underground, is exposed to commodity price risk.
        Additionally, as a result of the
        Western Kentucky storage expansion project, approximately 4.8 Bcf of gas
        stored
        underground with a book value of $11.3 million is subject to forward sales
        agreements which base the ultimate sales price on the price of NYMEX natural
        gas
        futures, to be determined in March 2007. Our operating subsidiaries utilize
        derivatives to hedge certain exposures to market price fluctuations on the
        anticipated operational sales of gas and also for cash received for fuel
        reimbursement.
 
 The
        derivatives related to the sale of natural gas and cash for fuel reimbursement
        generally qualify for cash flow hedge accounting under SFAS No. 133 and are
        designated as such. The 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
        (loss). The deferred gains and losses are recognized in the Consolidated
        Statements of Income when the hedged anticipated purchases or sales affect
        earnings.
 
 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 the Consolidated Statements of Income.
 
 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, 2006, the amount of gas loaned
        out by our subsidiaries was approximately 15.1 Trillion British thermal units
        (TBtu) and, assuming an average market price during December 2006 of $6.81
        per
        MMBtu, the market value of gas loaned out at December 31, 2006 would have
        been
        approximately $102.8 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, 2006, our cash equivalents were invested primarily in money
        market
        investments. Due to the short-term nature and type of our investments, a
        hypothetical 10% 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 affected by the effect of a sudden change in market
        interest rates on our investment portfolio.
 
  34
  **Item
        8. Financial Statements and Supplementary
        Data**
 
 
 **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, 2006 and
        2005, 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, 2006. 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, 2006 and 2005, and the results of their
        operations and their cash flows for each of the three years in the period
        ended
        December 31, 2006, 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. As
        discussed in Note 15 to the consolidated financial statements, in 2006, the
        Partnership adopted the provisions of Statement of Financial Accounting
        Standards No. 158, Employers’ Accounting for Defined Benefit Pension and Other
        Postretirement Plans - an amendment of FASB Statements No. 87, 88, 106 and
        132(R).
 
 We
        have
        also audited, in accordance with the standards of the Public Company Accounting
        Oversight Board (United States), the effectiveness of the Partnership's internal
        control over financial reporting as of December 31, 2006, 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 22, 2007 expressed an unqualified opinion on management's assessment
        of
        the effectiveness of the Partnership's internal control over financial reporting
        and an unqualified opinion on the effectiveness of the Partnership’s internal
        control over financial reporting.
 
 
 
 DELOITTE
        & TOUCHE LLP
 Chicago,
        Illinois
 February
        22, 2007
 
 
  35
  **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 management's assessment, included in the accompanying Management’s
        Annual Report on Internal Control over Financial Reporting, included at Item
        9A,
        that Boardwalk Pipeline Partners, LP and subsidiaries (the "Partnership")
        maintained effective internal control over financial reporting as of December
        31, 2006, 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. Our responsibility is to express
        an
        opinion on management's assessment and an opinion on the effectiveness of
        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, evaluating management's assessment, testing and evaluating
        the design and operating effectiveness of internal control, and performing
        such
        other procedures as we considered necessary in the circumstances. We believe
        that our audit provides a reasonable basis for our opinions.
 
 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, management's assessment that Boardwalk Pipeline Partners, LP maintained
        effective internal control over financial reporting as of December 31, 2006,
        is
        fairly stated, in all material respects, based on the criteria established
        in
        Internal Control—Integrated Framework issued by the Committee of Sponsoring
        Organizations of the Treadway Commission. Also in our opinion, Boardwalk
        Pipeline Partners, LP maintained, in all material respects, effective internal
        control over financial reporting as of December 31, 2006, 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, 2006
        of
        the Partnership and our report dated February 22, 2007 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 and the adoption of FASB Statement No. 158.
 
 
 
 DELOITTE
        & TOUCHE LLP
 Chicago,
        Illinois
 February
        22, 2007
  36
  **BOARDWALK
        PIPELINE PARTNERS, LP**
 
 **CONSOLIDATED
        BALANCE SHEETS**
 (Thousands
        of Dollars)
 
 
 
 **December
                  31,****ASSETS**
              
              **2006**
              
              **2005**Current
                  Assets:Cash
                  and cash equivalents
              
              $
              399,032
              
              $
              65,792Receivables:Trade,
                  net
              
              
              54,082
              
              
              59,115Other
              
              
              12,759
              
              
              5,564Gas
                  Receivables:Transportation
                  and exchange
              
              
              9,115
              
              
              29,557Storage
              
              
              11,704
              
              
              12,576Inventories
              
              
              14,110
              
              
              15,881Costs
                  recoverable from customers
              
              
              11,236
              
              
              3,560Gas
                  stored underground
              
              
              14,001
              
              
              6,500Prepaid
                  expenses and other current assets
              
              
              22,117
              
              
              7,720Total
                  current assets
              
              
              548,156
              
              
              206,265Property,
                  Plant and Equipment:Natural
                  gas transmission plant
              
              
              1,997,922
              
              
              1,772,483Other
                  natural gas plant
              
              
              213,926
              
              
              213,1362,211,848
              
              
              1,985,619Less—accumulated
                  depreciation and amortization
              
              
              187,412
              
              
              118,213Property,
                  plant and equipment, net
              
              
              2,024,436
              
              
              1,867,406Other
                  Assets:Goodwill
              
              
              163,474
              
              
              163,474Gas
                  stored underground
              
              
              161,537
              
              
              169,177Costs
                  recoverable from customers
              
              
              19,767
              
              
              43,960Other
              
              
              33,929
              
              
              15,209Total
                  other assets
              
              
              378,707
              
              
              391,820Total
                  Assets
              
              $
              2,951,299
              
              $
              2,465,491
 
 
 The
        accompanying notes are an integral part of these consolidated financial
        statements.
  37
  **BOARDWALK
        PIPELINE PARTNERS, LP**
 
 **CONSOLIDATED
        BALANCE SHEETS**
 (Thousands
        of Dollars)
 
 **December
                  31,****LIABILITIES
                  AND PARTNERS’ CAPITAL**
              
              **2006**
              
              **2005**Current
                  Liabilities:Payables:Trade
              
              $
              56,604
              
              $
              20,433Affiliates
              
              
              3,014
              
              
              835Other
              
              
              14,459
              
              
              3,681Gas
                  Payables:Transportation
                  and exchange
              
              
              15,485
              
              
              14,710Storage
              
              
              42,127
              
              
              27,559Other
                  accrued taxes
              
              
              16,082
              
              
              16,004Accrued
                  interest
              
              
              19,376
              
              
              17,996Accrued
                  payroll and employee benefits
              
              
              18,198
              
              
              29,028Current
                  note payable
              
              
              -
              
              
              42,100Deferred
                  income
              
              
              22,147
              
              
              1,025Other
                  current liabilities
              
              
              20,926
              
              
              28,916Total
                  current liabilities
              
              
              228,418
              
              
              202,287Long
                  -Term Debt
              
              
              1,350,920
              
              
              1,101,290Other
                  Liabilities and Deferred Credits:Pension
                  and postretirement benefits
              
              
              15,761
              
              
              32,413Asset
                  retirement obligation
              
              
              14,307
              
              
              14,074Provision
                  for other asset retirement
              
              
              39,644
              
              
              33,212Other
              
              
              29,742
              
              
              93,541Total
                  other liabilities and deferred credits
              
              
              99,454
              
              
              173,240Commitments
                  and ContingenciesPartners’
                  Capital:Common
                  units - 75,156,122 and 68,256,122 common units issued and outstanding
                  as
                  of December 31, 2006 and 2005
              
              
              941,792
              
              
              705,609Subordinated
                  units - 33,093,878 units issued and outstanding as of
                December
                  31, 2006 and 2005
              
              
              285,543
              
              
              266,578General
                  partner
              
              
              22,060
              
              
              16,661Accumulated
                  other comprehensive income (loss), net of tax
              
              
              23,112
              
              
              (174
              )Total
                  partners’ capital
              
              
              1,272,507
              
              
              988,674Total
                  Liabilities and Partners’ Capital
              
              $
              2,951,299
              
              $
              2,465,491
 
 
 The
        accompanying notes are an integral part of these consolidated financial
        statements.
  38
  **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,****2006**
              
              **2005**
              
              **2004**Operating
                  Revenues:Gas
                  transportation
              
              $
              508,241
              
              $
              505,148
              
              $
              245,306Parking
                  and lending
              
              
              49,163
              
              
              21,426
              
              
              8,182Gas
                  storage
              
              
              32,396
              
              
              21,667
              
              
              7,289Other
              
              
              17,842
              
              
              12,225
              
              
              2,844Total
                  operating revenues
              
              
              607,642
              
              
              560,466
              
              
              263,621Operating
                  Costs and Expenses:Operation
                  and maintenance
              
              
              161,279
              
              
              174,641
              
              
              48,336Administrative
                  and general
              
              
              97,298
              
              
              78,752
              
              
              52,535Depreciation
                  and amortization
              
              
              75,771
              
              
              72,078
              
              
              33,977Taxes
                  other than income taxes*
              
              
              24,175
              
              
              27,361
              
              
              19,044Net
                  (gain) on disposal of operating assets
              
              
              (4,829
              )
              
              (7,846
              )
              
              -Total
                  operating costs and expenses
              
              
              353,694
              
              
              344,986
              
              
              153,892Operating
                  income
              
              
              253,948
              
              
              215,480
              
              
              109,729Other
                  (Income) Deductions:Interest
                  expense
              
              
              62,123
              
              
              60,067
              
              
              30,081Interest
                  income
              
              
              (4,202
              )
              
              (1,478
              )
              
              (352
              )Interest
                  income from affiliates, net
              
              
              (27
              )
              
              (2,186
              )
              
              (375
              )Miscellaneous
                  other income, net
              
              
              (1,749
              )
              
              (1,444
              )
              
              (783
              )Total
                  other (income) deductions
              
              
              56,145
              
              
              54,959
              
              
              28,571Income
                  before income taxes
              
              
              197,803
              
              
              160,521
              
              
              81,158Income
                  taxes and charge-in-lieu of income taxes *
              
              
              253
              
              
              49,494
              
              
              32,333Elimination
                  of cumulative deferred taxes *
              
              
              -
              
              
              10,102
              
              
              -Net
                  income *
              
              $
              197,550
              
              $
              100,925
              
              $
              48,825
 *Results
        of operations for the year ended December 31, 2005 reflect a change in the
        tax
        status associated with Boardwalk Pipeline Partners and Boardwalk Pipelines
        coincident with the initial public offering. Boardwalk Pipeline Partners
        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 and has recorded
        no
        charge-in-lieu of income taxes thereafter. Pursuant to the change in tax
        status,
        Boardwalk Pipeline Partners 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”). A subsidiary of Boardwalk Pipeline Partners
        directly incurs 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, 2006**
              
              **For
                  the Period**
                **November
                  15, 2005**
                **through**
                **December
                  31, 2005**Net
                  income
              
              $
              197,550
              
              $
              35,992Less
                  general partner’s interest in Net income
              
              
              3,951
              
              
              720Limited
                  partners’ interest in Net income
              
              $
              193,599
              
              $
              35,272Basic
                  and diluted net income per limited partner unit:Common
                  and subordinated units
              
              $
              1.85
              
              $
              0.35Cash
                  distribution to common and subordinated unitholders and general
                  partner
                  unit equivalents
              
              $
              1.32
              
              
              -Weighted-average
                  number of limited partners units outstanding:Common
                  units
              
              
              68,977,766
              
              
              68,256,122Subordinated
                  units
              
              
              33,093,878
              
              
              33,093,878
 
 The
        accompanying notes are an integral part of these consolidated financial
        statements.
  39
  **BOARDWALK
        PIPELINE PARTNERS, LP**
 
 **CONSOLIDATED
        STATEMENTS OF CASH FLOWS**
 (Thousands
        of Dollars)
  **For
                    the Year Ended December 31,****2006**
                
                **2005**
                
                **2004**OPERATING
                    ACTIVITIES:Net
                    income
                $
                    197,550
                
                $
                    100,925
                
                $
                    48,825Adjustments
                    to reconcile to cash provided from (used in) operations:Depreciation
                    and amortization
                75,771
                
                72,078
                
                33,977Amortization
                    of acquired executory contracts
                (3,997)
                
                (9,630)
                
                -Provision
                    for deferred income taxes
                (39)
                
                54,682
                
                43,428Gain
                    on disposal of operating assets
                (4,829)
                
                (7,846)
                
                -Changes
                    in operating assets and liabilities, net of assets and liabilities
                    acquired:Receivables
                20,878
                
                (21,147)
                
                (9,777)Inventories
                1,772
                
                (1,699)
                
                (217)Affiliates
                2,180
                
                (824)
                
                (341)Other
                    current assets
                (18,058)
                
                (3,669)
                
                6,320Accrued
                    and deferred income taxes
                85
                
                4,908
                
                (10,996)Payables
                    and accrued liabilities
                31,902
                
                43,788
                
                (9,532)Other,
                    including changes in noncurrent assets and liabilities
                (47,663)
                
                (12,852)
                
                2,729Net
                    cash provided by operating activities
                255,552
                
                218,714
                
                104,416INVESTING
                    ACTIVITIES:Capital
                    expenditures, net
                (200,330)
                
                (82,955)
                
                (41,920)Proceeds
                    from sale of operating assets
                3,646
                
                4,725
                
                -Proceeds
                    from insurance reimbursements and other recoveries
                5,928
                
                4,177
                
                -Advances
                    to affiliates, net
                (760)
                
                (28,252)
                
                (32,194)Investment
                    in Gulf South, net of cash and working capital adjustment
                    receivable
                -
                
                -
                
                (1,111,411)Net
                    cash used in investing activities
                (191,516)
                
                (102,305)
                
                (1,185,525)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
                338,307
                
                569,369
                
                575,000Payment
                    of long-term debt
                (90,000)
                
                (575,000)
                
                (17,285)Distributions
                    and dividends
                (136,388)
                
                (131,686)
                
                (30,000)Capital
                    contribution from parent and general partner
                4,176
                
                6,684
                
                550,741Proceeds
                    from sale of common units, net of related transaction
                    costs
                195,209
                
                271,398
                
                -Net
                    cash provided by (used in) financing activities
                269,204
                
                (67,135)
                
                1,078,456Increase
                    (decrease) in cash and cash equivalents
                333,240
                
                49,274
                
                (2,653)Cash
                    and cash equivalents at beginning of period
                65,792
                
                16,518
                
                19,171Cash
                    and cash equivalents at end of period
                $
                    399,032
                
                $
                    65,792
                
                $
                    16,518
  The
        accompanying notes are an integral part of these consolidated financial
        statements.
 
 
  40
  **BOARDWALK
          PIPELINE PARTNERS, LP**
 
 **CONSOLIDATED
          STATEMENTS OF CHANGES IN**
 **MEMBER’S
          EQUITY AND PARTNERS’ CAPITAL**
  **Paid
                      in Capital**
                  
                  **Retained
                      Earnings**
                  
                  **Accumulated
                      Other Comp Income (Loss)**
                  
                  **Common**
                    **Units**
                  
                  **Subordinated
                      Units**
                  
                  **General
                      Partner**
                  
                  **Total
                      Partners’ Capital****Balance
                      January 1, 2004**
                  
                  $
                      520,910
                  
                  $
                      2,451
                  
                  -
                  
                  -
                  
                  -
                  
                  -
                  
                  -Add
                      (deduct):Capital
                      contribution
                  
                  550,741
                  
                  -
                  
                  -
                  
                  -
                  
                  -
                  
                  -
                  
                  -Net
                      income
                  
                  -
                  
                  48,825
                  
                  -
                  
                  -
                  
                  -
                  
                  -
                  
                  -Dividends
                      paid
                  
                  -
                  
                  (30,000)
                  
                  -
                  
                  -
                  
                  -
                  
                  -
                  
                  -**Balance
                      December 31, 2004**
                  
                  $
                      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(53,256,122
                      common units, 33,093,878 subordinated units and 2% general
                      partner
                      interest)
                  
                  -
                  
                  -
                  
                  $
                      351
                  
                  $
                      410,456
                  
                  $
                      255,061
                  
                  $
                      15,941
                  
                  $
                      681,809Sale
                      of common units, net of related transaction costs (15,000,000
                      units)
                  
                  -
                  
                  -
                  
                  -
                  
                  271,398
                  
                  -
                  
                  
                  
                  271,398Other
                      comprehensive loss
                  
                  -
                  
                  -
                  
                  (525)
                  
                  
                  
                  -
                  
                  
                  
                  (525)Net
                      income
                  
                  -
                  
                  -
                  
                  -
                  
                  23,755
                  
                  11,517
                  
                  720
                  
                  35,992**Balance
                      December 31, 2005**
                  
                  -
                  
                  -
                  
                  $
                      (174)
                  
                  $
                      705,609
                  
                  $
                      266,578
                  
                  $
                      16,661
                  
                  $
                      988,674Add
                      (deduct):Net
                      Income
                  
                  -
                  
                  -
                  
                  -
                  
                  130,990
                  
                  62,609
                  
                  3,951
                  
                  197,550Distributions
                      paid
                  
                  -
                  
                  -
                  
                  -
                  
                  (90,016)
                  
                  (43,644)
                  
                  (2,728)
                  
                  (136,388)Sale
                      of common units, net of related transaction costs (6,900,000
                      units)
                  
                  -
                  
                  -
                  
                  -
                  
                  195,209
                  
                  -
                  
                  -
                  
                  195,209Capital
                      contribution
                  
                  -
                  
                  -
                  
                  -
                  
                  -
                  
                  -
                  
                  4,176
                  
                  4,176Other
                      comprehensive income, net of tax
                  
                  -
                  
                  -
                  
                  8,483
                  
                  -
                  
                  -
                  
                  -
                  
                  8,483Adjustment
                      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
 41
  **BOARDWALK
        PIPELINE PARTNERS, LP**
 
 **CONSOLIDATED
        STATEMENTS OF COMPREHENSIVE INCOME**
 (Thousands
        of Dollars)
 
 
 **For
                  the Year**
                **Ended**
                **December
                  31, 2006**
              
              **For
                  the Year Ended December 31, 2005**
              
              **For
                  the Year**
                **Ended**
                **December
                  31, 2004**Net
                  income
              
              $
              197,550
              
              $
              100,925
              
              $
              48,825Other
                  comprehensive income (loss):Gain
                  (loss) on cash flow hedges
              
              
              19,405
              
              
              (2,735
              )
              
              -Reclassification
                  adjustment transferred to Net income
              
              
              (10,922
              )
              
              2,561
              
              
              -Total
                  comprehensive income
              
              $
              206,033
              
              $
              100,751
              
              $
              48,825
  These
        accompanying notes are an integral part of these consolidated financial
        statements.
 
  42
  
 **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, Texas Gas Transmission, LLC (Texas Gas)
        and
        Gulf South Pipeline Company, LP (Gulf South) (together, the operating
        subsidiaries).
 
 In
        the
        fourth quarter 2006, the Partnership sold 6,900,000 common units in a follow-on
        public offering. The
        follow-on offering resulted in net proceeds of approximately $199.4 million,
        after deducting underwriting discounts and offering expenses of $9.4 million,
        and including $4.2 million from the general partner to maintain its 2.0%
        interest in the Partnership. The proceeds of the equity offering will be
        used to
        finance the Partnership’s expansion activities discussed in Note 3. The
        common units sold in the Partnership’s initial public offering (IPO) on November
        15, 2005, and follow-on offering, totaling 21,900,000 common units, represent
        approximately 19.8% of the partners’ capital which includes 75,156,122 common
        units, 33,093,878 subordinated units and a 2.0% general partner interest.
        All of
        the common and subordinated units, other than the common units sold in the
        public offerings, are held by Boardwalk Pipelines Holding Corp. (BPHC) a
        wholly-owned subsidiary of Loews Corporation (Loews). Boardwalk GP, LP
        (Boardwalk GP), an indirect wholly-owned subsidiary of BPHC, holds the 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).
 
 In
        connection with the consummation of the IPO in November 2005, 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 53,256,122 common units, 33,093,878
                subordinated units, representing an 83.5% limited partnership 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. 
 Net
        proceeds in the amount of $271.4 million, from the IPO were used to repay
        the
        $250.0 million of indebtedness that the Partnership assumed from BPHC in
        connection with the contribution of its interest in the Partnership, and
        to
        provide approximately $21.4 million in additional working capital for the
        Partnership.
   **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 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. On December 29, 2004,
        Boardwalk Pipelines acquired Gulf South (GS-Acquisition). The results and
        financial position of Gulf South have been included in the consolidated
        financial statements from the date of the GS-Acquisition.
  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 and has recorded
        no
        charge-in-lieu of income taxes thereafter. 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. One
        of
        the Partnership’s subsidiaries directly incurs some income-based state taxes
        which are presented in Income taxes and charge-in-lieu of income taxes on
        the
        Consolidated Statements of Income.
 
 ***GS-Acquisition***
 
 The
        Partnership made an allocation of the purchase price in connection with the
        GS-Acquisition which was finalized in December 2005. The purchase price was
        assigned to the assets and liabilities of Gulf South, based on their estimated
        fair values using management’s analyses with consideration of external
        valuations as reflected in the following table (in thousands):
 
 Current
                  assets
              
              $
              71,283Property,
                  plant and equipment
              
              
              1,159,251Other
                  non-current assets
              
              
              28,319Current
                  liabilities
              
              
              (84,273
              )Other
                  liabilities and deferred credits
              
              
              (53,153
              )$
              1,121,427
 
 The
        following unaudited pro forma financial information is presented as if Gulf
        South had been acquired as of the beginning of 2004. The pro forma amounts
        include certain adjustments, including depreciation expense based on the
        allocation of the purchase price to property, plant and equipment (PPE);
        adjustment of interest expense to reflect the issuance of debt by Gulf South
        and
        Boardwalk Pipelines; and the related tax effect of these items (in thousands):
 
 **(unaudited)****For
                  the Year**
                **Ended**
                **December
                  31, 2004**Operating
                  revenues
              
              $
              504,471Income
                  before income taxes
              
              
              121,598Net
                  income
              
              
              73,525
 
 The
        pro
        forma information does not necessarily reflect the actual results that would
        have occurred had the companies been combined during the period presented,
        nor
        is it necessarily indicative of future results of operations.
  43
 
 **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, Texas Gas, and Gulf
        South
        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, workers' compensation insurance, pensions and other post retirement
        and
        employment 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.
  
 44
  ***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 13,400 miles of pipelines and
        integrated storage fields.
 
 
 ***Cash
        and Cash Equivalents***
 
 Cash
        equivalents are stated at cost plus accrued interest, which approximates
        fair
        value. Cash equivalents are highly liquid investments with an original maturity
        of three months or less. The Partnership had no restricted cash at December
        31,
        2006 and 2005.
 
 
 ***Cash
        Management***
 
 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.
 
 
 ***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 storage (NNS) and parking
        and lending (PAL) services. Certain of these volumes are necessary to provide
        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 services and balancing activity. Gas stored underground
        includes natural gas volumes owned by the pipelines, reduced by certain
        operational encroachments upon that gas. Current gas stored underground
        represents retained fuel and excess working gas at Gulf South 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 making a cash payment or physically delivering
        gas.
  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 transportation and exchange imbalances, which are primarily repaid
        or
        recovered in cash or through the receipt or delivery of gas in the future.
        Settlement of imbalances requires agreement between the pipelines and shippers
        or operators as to allocations of volumes to specific transportation contracts
        and timing of delivery of gas based on operational conditions. For Texas
        Gas,
        these amounts are valued at the historical value of gas in storage, consistent
        with the regulatory treatment and the settlement history. For Gulf South,
        these
        receivables and payables are valued at market price.
 
 Gas
        receivables and payables reflect amounts of customer-owned gas at the Texas
        Gas
        facilities. 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 gas payables
        amount
        reflected in Gas Payables on the Consolidated Balance Sheets is valued at
        a
        historical cost of gas of $45.7 million and $33.6 million at December 31, 2006
        and 2005. 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, 2006 and 2005, Gulf South
        held 61.0 trillion British thermal units (TBtu) and 32.8 TBtu of gas owned
        by
        shippers, and had loaned 0.2 TBtu of gas to shippers as of December 31, 2005.
        No
        gas was loaned by Gulf South to shippers as of December 31, 2006.
 
 
 45
  ***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
        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 (loss). The deferred gains and
        losses
        are recognized in the Consolidated Statements of Income when the hedged
        anticipated transactions affect earnings. Note
        8
        contains more information regarding the Partnership’s derivative financial
        instruments.
  
 ***Property,
        Plant and Equipment***
 
 PPE
        is
        recorded at its original cost of construction or fair value of assets acquired.
        Construction costs and expenditures for major renewals and improvements,
        which
        extend the lives of the respective assets, are capitalized.
  Texas
        Gas’s depreciation 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.
        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.
 
 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.
 
 ***Goodwill***
  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. The impairment test for goodwill is performed annually at December
        31.
        No impairment was recorded during 2006, 2005 or 2004.
 
 
 ***Advances
        to Affiliates***
  The
        Partnership makes advances to and receives advances from its subsidiaries
        and
        BPHC. These advances are represented by demand notes. Advances 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.
 
 
 ***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. 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. Gulf South does not apply SFAS No.
        71.
        Certain services provided by Gulf South are market-based and competition
        in Gulf
        South’s market area has often resulted in discounts from the maximum allowable
        cost-based rate such that SFAS No. 71 has not been appropriate. Therefore,
        Gulf
        South does not record any regulatory assets or liabilities.
 
 The
        Partnership monitors the regulatory and competitive environment in which
        it
        operates to determine that the regulatory assets recorded at Texas Gas 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 which would no longer
        be
        deemed refundable.
 
 46
 
 ***Acquired
        Executory Contracts***
 
 As
        a
        result of the GS-Acquisition, the Partnership recorded certain shipper contracts
        at fair value.  The below market valuation balance of $1.3 million as of
        December 31, 2006, included $1.1 million as a component of Other current
        liabilities and $0.2 million as a component of Other Liabilities and Deferred
        Credits.  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 ending in early 2008. Amortization for 2006 and 2005 was $4.0
        million and $9.5 million. Amortization for 2007 and 2008 is expected to be
        $1.1
        million and $0.2 million.
 
 
 ***Asset
        Retirement Obligations***
 
 SFAS
        No.
        143, *Accounting
        for Asset Retirement Obligations* ,
        addresses accounting and reporting for existing legal obligations associated
        with the future retirement of long-lived assets. SFAS No. 143 requires entities
        to record the fair value of a liability for an asset retirement obligation
        (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.
 
 
 ***Unit-Based
        Compensation***
 
 In
        December 2004, the Financial Accounting Standards Board (FASB) issued SFAS
        No. 123(R), *Share-Based
        Payment,* which
        establishes accounting standards for transactions in which an entity exchanges
        its equity instruments for goods or services, primarily focusing on transactions
        where an entity obtains employee services. SFAS No. 123(R) requires a
        public entity to measure the cost of employee services received in exchange
        for
        an award of equity instruments, based on the grant-date fair value of the
        award
        and to recognize it as compensation expense over the period the employee
        is
        required to provide service in exchange for the award, usually the vesting
        period. The Partnership adopted SFAS No. 123(R) during 2005 due to the adoption
        of its Long-Term Incentive Plan in 2005. There were no previous unit-based
        compensation plans.
 
 In
        February 2006, FASB Staff Position (FSP) FAS 123(R)-4 amended SFAS No. 123(R)
        to
        require evaluation of the probability of occurrence of a contingent cash
        settlement event in determining whether the underlying options or similar
        instruments issued as employee compensation should be classified as liabilities
        or equity. The Partnership applied the principles of FSP FAS 123(R)-4 in
        conjunction with the adoption of SFAS No. 123(R) which had no material
        impact on its financial condition, results of operations, or cash flows.
        Note 9
        contains additional information regarding the Partnership’s unit-based
        compensation.
 
  ***Revenue
        Recognition***
 
 The
        maximum rates that may be charged by the operating subsidiaries for their
        gas
        transportation and storage services are established through FERC 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 transported volumes. Revenues from storage services are recognized
        over the term of the contracts. When an entity is involved in a rate case,
        certain revenues collected may be subject to possible refunds pending the
        final
        outcome of the proceedings. An estimate of a potential rate refund liability
        is
        made considering its own and third-party regulatory proceedings, advice of
        counsel and estimated total exposure. Texas Gas filed a rate case in 2005
        which
        was settled in the second quarter 2006. Note 3 contains more information
        regarding the Texas Gas rate case settlement.
 
 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, 2006
        and
        2005 were $73.2 million and $86.7 million. Since only three days of Gulf
        South’s
        2004 results were included in the Partnership’s Consolidated Statements of
        Income, the amount of retained fuel included in transportation revenues was
        negligible.
 
 The
        Partnership had deferred revenue of $22.4 million at December 31, 2006, related
        to PAL services to be provided mainly in 2007 and a minor amount in early
        2008.
        At December 31, 2005, the Partnership had deferred revenue of $1.0 million.
        Revenue deferred at year end will be recognized when the services are provided.
 
 47
 
 ***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.
 
 
 ***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)***
 
 AFUDC
        represents the cost of funds, including equity, applicable to the regulated
        natural gas transmission plant under construction as permitted by FERC
        regulatory practices. The allowance for borrowed funds used during construction
        and capitalized interest 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 the allowance for borrowed funds and capitalized
        interest and the allowance for equity funds used during construction (in
        millions):
 
 **For
                  the Year Ended December 31,****2006**
              
              **2005**
              
              **2004**Allowance
                  for borrowed funds used during construction and capitalized interest
              
              $
              2.3
              
              $
              0.7
              
              $
              0.3Allowance
                  for equity funds used during construction
              
              
              1.2
              
              
              1.4
              
              
              0.8
 
 
 ***Cash
        Flows from Operating Activities***
 
 The
        Partnership uses the indirect method to report cash flows from operating
        activities, which requires adjustments to net income to reconcile to net
        cash
        flows provided by operating activities.
 
 
 ***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. Through December 31, 2006, there have not been any
        distributions paid based on the incentive distribution rights.
 
 
 ***Income
        Taxes***
 
 Boardwalk
        Pipeline Partners is not a taxable entity for federal income tax purposes.
        As
        such, it does not directly pay federal income tax. Boardwalk Pipeline Partners’
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
        Boardwalk Pipeline Partners’ net assets for financial and income tax purposes
        cannot be readily determinable as it does not have access to the information
        about each partner’s tax attributes related to Boardwalk Pipeline Partners. One
        of
        the Partnership’s subsidiaries directly incurs some income-based state taxes
        which are presented in Income taxes and charge-in-lieu of income taxes on
        the
        Consolidated Statements of Income.
 
 
 48
  ***Reclassifications***
 
 Certain
        reclassifications have been made to the 2005 and 2004 financial statements
        to
        conform to the 2006 presentation , primarily
        related to the presentation of PAL revenues and Interest expense
        as separate line items on the Consolidated Statements of
        Income .
 
 **Note
        3: Commitments and Contingencies**
 
 
 **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 Gulf South assets and a smaller portion of the
        Texas
        Gas assets are located in the area directly impacted by the
        hurricanes.
  During
        2006 and 2005, the Partnership recognized charges of $0.1 million and $12.9
        million in the Consolidated Statements of Income for the estimated cost of
        damage from the hurricanes. In 2006, the Partnership recognized $10.7 million
        of
        insurance recoveries associated with Hurricane Katrina, of which $6.0 million
        was received in the fourth quarter 2006. The total impact of the charges
        and
        insurance recoveries was a $10.6 million increase in 2006 earnings and $12.9
        million decrease in 2005 earnings. This was recorded as follows (in
        millions):
 
 **2006**
              
              **2005**Operating
                  Revenues
              $
                  3.3
              
              $
                  (2.0)Operating
                  Costs and Expenses
              7.3
              
              (10.9)Increase/(Decrease)
                  in Net Income
              $
                  10.6
              
              $
                  (12.9)
 
 In
        addition, the Partnership is pursuing recovery of insurance proceeds related
        to
        Hurricane Rita, but no amount has been deemed probable of recovery.  The
        combined remaining liability for both hurricanes was $1.0 million and $5.6
        million as of December 31, 2006 and 2005.
 
 
 **Legal
        Proceedings**
 
 ***Hurricane
        Katrina - Related Class Actions***
  Gulf
        South, along with at least eight other interstate pipelines and major natural
        gas producers, has been named in three Hurricane Katrina-related class action
        lawsuits filed in the United States District Court for the Eastern District
        of
        Louisiana (District Court). The lawsuits allege that the dredging of canals
        caused damage to the marshes and that undamaged marshes would have prevented
        all, or almost all, of the loss of life and destruction of property caused
        by
        Hurricane Katrina. The District Court has dismissed all three cases.
 
 ***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 the early stages of
        discovery. Litigation is subject to many uncertainties, and it is possible
        these
        actions could be decided unfavorably. Gulf South has settled several 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.
        From
        the date of acquisition of Gulf South on December 29, 2004 through November
        2006, Gulf South incurred $7.0 million for remediation costs, root cause
        investigation, and legal fees. At December 31, 2006, there was no remaining
        liability balance. At December 31, 2005, the Partnership had a liability
        balance
        of $1.1 million in Other current liabilities, on the Consolidated Balance
        Sheets
        pertaining to the incident *.* 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 2006,
        Gulf
        South received $0.8 million of insurance reimbursements for legal expenses
        and
        root cause investigation.
 
 49
  ***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
        including, among others, these previously disclosed matters:
 
 ·
            Litigation
                filed by Jack Grynberg alleging that approximately 300 energy companies,
                including Texas Gas, had violated the False Claims Act in connection
                with
                the measurement, royalty valuation and purchase of hydrocarbons.
                In
                October 2006, the United States District Judge issued an order dismissing
                these claims, including the claims against Texas Gas, for lack of
                subject
                matter jurisdiction. That order is, however, subject to appeal;
                and 
 ·
            A
                claim by certain parties for back rental associated with their alleged
                ownership of a partial mineral interest in a tract of land in a gas
                storage field owned by Texas Gas. In December 2003, a lawsuit was
                filed
                against Texas Gas in Muhlenberg County, Kentucky, seeking unspecified
                damages related to this claim. In April 2005, in the first phase
                of this
                lawsuit, the court entered an order granting partial summary judgment
                against Texas Gas related to the vesting of legal title to the disputed
                acreage. However, in January 2007, the court entered an order concluding
                that the plaintiff was estopped by his actions from pursuing his
                claims
                and dismissed the lawsuit. The plaintiff has filed a motion to vacate
                the
                order dismissing the lawsuit and is expected to appeal. 
 Williams
        continues to defend these actions on behalf of the Partnership and Texas
        Gas.
        Williams has retained responsibility for these claims, therefore they 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.
 
 50
 
 **Regulatory
        and Rate Matters**
 
 ***Expansion
        Projects***
  *Carthage
        to Keatchie Loop* .
        The
        Partnership has constructed a 20.5 mile segment of 42-inch pipeline from
        Carthage, Texas to Keatchie, Louisiana which was placed in service in December
        2006. The current capacity of this loop is 120 MMcf per day.
 
 *East
        Texas to Mississippi Expansion.* The
        Partnership is pursuing a pipeline expansion project consisting of 242 miles
        of
        42-inch pipeline from DeSoto Parish in western Louisiana to near Harrisville,
        Mississippi and approximately 110,000 horsepower of new compression. The
        expansion would add approximately 1.7 Bcf per day of new transmission capacity
        to the Partnership’s Gulf South pipeline system. The natural gas to be
        transported on this expansion will originate primarily from the Barnett Shale
        and Bossier Sands producing regions of East Texas. The expansion will transport
        natural gas to new interstate pipeline interconnects in the Perryville,
        Louisiana area and existing pipeline interconnects with other pipelines east
        of
        the Mississippi River. This project is supported by binding precedent agreements
        with customers who have contracted, on a long-term basis (with a weighted
        average term of approximately 7 years), for 1.3 Bcf per day from Carthage,
        Texas
        with an option for an additional 100 MMcf per day. On September 1, 2006,
        the
        Partnership filed a certificate application relating to this project with
        the
        FERC. The Partnership expects this project to be in service during the fall
        of
        2007.
 
 *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 a new subsidiary, Gulf Crossing Pipeline Company
        LLC
        (Gulf Crossing), and will consist of approximately 355 miles of 42-inch pipeline
        having capacity of up to approximately 1.6 Bcf per day. Additionally, Gulf
        Crossing will enter into: (i) a lease for at least 1.1 Bcf per day of capacity
        on the Partnership’s Gulf South pipeline system (including on the Southeast
        Expansion and 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; and (ii) a lease with a third-party intrastate
        pipeline which will bring certain gas supplies to the Partnership’s system. This
        project is supported by binding agreements with customers who have contracted
        for 1.1 Bcf per day of capacity under firm contracts having terms of 5 to
        10
        years (with a weighted average term of approximately 9.8 years), and options
        with certain of these customers for an additional 350 MMcf per day of capacity.
        The Partnership anticipates making the required filings with the FERC by
        July
        2007 and for the project to be in service during the fourth quarter of 2008.
        The
        Partnership is in negotiations with one of the foundation shippers supporting
        this project concerning the purchase of 49.0% of the equity of Gulf Crossing.
 
 *Southeast
        Expansion* .
        The
        Partnership is pursuing a pipeline expansion extending its Gulf South pipeline
        system from near Harrisville, Mississippi to an interconnect with Transco
        in
        Choctaw County, Alabama which will enhance its ability to deliver gas to
        the
        Northeast through other pipeline interconnects. This expansion will consist
        of
        approximately 112 miles of 42-inch pipeline having initial capacity of
        approximately 1.2 Bcf per day, expandable to as much as 2.0 Bcf per day to
        accommodate volumes expected to come from the Gulf Crossing leased capacity
        discussed above. In addition, Gulf South has executed a lease with Destin
        Pipeline Company to access markets in Florida. This project is supported
        by
        binding agreements with customers who have contracted for 660 MMcf per day
        of
        capacity under firm contracts having terms of 5 to 10 years (with a
        weighted-average term of 9.2 years), as well as the capacity leased to Gulf
        Crossing discussed above. The certificate filing was made with the FERC in
        December 2006 and the project is anticipated to be in service during first
        quarter 2008.
 
 *Fayetteville
        Shale* .
        The
        Partnership is pursuing the construction of two laterals connected to the
        Texas
        Gas pipeline system to transport gas from the Fayetteville Shale area in
        Arkansas to markets directly and indirectly served by Texas Gas. The
        Fayetteville Lateral, consisting of approximately 165 miles of 36-inch pipeline,
        is anticipated to have an initial design capacity of 800 MMcf per day and
        a
        maximum design capacity of 1.1 Bcf per day. This lateral will originate in
        Conway County, Arkansas and proceed southeast through the Bald Knob, Arkansas
        area to an interconnect with Texas Gas’s mainline in Coahoma County,
        Mississippi. The Greenville Lateral, consisting of approximately 95 miles
        of
        pipeline with an initial design capacity of 750 MMcf per day, will originate
        at
        Texas Gas’s mainline near Greenville, Mississippi and proceed east to the
        Kosciusko, Mississippi area. The Greenville Lateral will allow customers
        to
        access additional markets, primarily in the Midwest, Northeast and Southeast,
        including the Henry Hub. Construction of both laterals is supported by a
        binding
        precedent agreement with Southwestern Energy Services Company, a wholly-owned
        subsidiary of Southwestern Energy Company. In December 2006, the FERC granted
        Texas Gas’s request to initiate the pre-filing process for this project and the
        Partnership anticipates making the required certificate filings with the
        FERC in
        June 2007. The Partnership expects the project to be in service during the
        first
        quarter 2009.
 
 The
        total
        cost of the pipeline expansion projects discussed above is expected to be
        approximately $3.3 billion (before taking into account equity that would
        be
        contributed by the purchaser of a 49.0% interest in Gulf Crossing Pipeline
        referred to above).  The Partnership is constantly seeking to optimize
        these projects to reduce the overall cost. However the actual cost to complete
        these projects may exceed the current estimate as a result of, among other
        things, higher labor and materials costs due to the large number of pipeline
        projects under way throughout the industry or the need to expand pipeline
        capacity if the Partnership contracts for additional volumes. For a further
        discussion of the risks associated with these projects, see the section on
        Risk
        Factors in Item 1A of this Report.
 
 *Western
        Kentucky Storage Expansion.* In
        December 2006, the FERC issued a certificate approving Texas Gas’s Phase II
        storage expansion project which will expand the working gas capacity in its
        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
        for the full additional capacity at Texas Gas’s maximum applicable rate. The
        Partnership expects this project to cost approximately $40.7 million and
        to be
        in service by November 2007. In December 2006, Texas Gas commenced an open
        season related to a potential third expansion of its storage facilities.
        Texas
        Gas has signed one precedent agreement for 2.0 Bcf of capacity. The ultimate
        size of the Phase III storage expansion will be determined, in part, by the
        open
        season. The Phase III storage expansion is subject to the FERC approvals,
        including potential market-based rate authority for the additional new storage
        capacity being created. Phase I of this project which expanded working gas
        capacity by approximately 8.0 Bcf was completed and in service in November
        2005.
 
 *Magnolia
        Storage Facility.* The
        Partnership is currently developing an additional storage cavern near
        Napoleonville, Louisiana. During mining operations, certain issues have arisen
        causing the mining of the cavern to be suspended. We are continuing to conduct
        operational integrity tests on the caverns. The tests are on-going but have
        been
        delayed due to lack of equipment availability needed to complete the testing.
        If
        the test results are favorable, we expect the storage facilities to be in
        service perhaps as early as 2008 with working gas capacity of 2.0 Bcf, reduced
        from 6.0 Bcf as originally designed. If the test results are not favorable,
        the
        Partnership will consider the options it has available, including developing
        a
        new cavern, or the sale or abandonment of the project. The total book value
        of
        the project at December 31, 2006 was $42.7 million. The Partnership tested
        the
        investment in Magnolia for recoverability in accordance with the requirements
        of
        SFAS No. 144, *Accounting
        for the Impairment or Disposal of Long-Lived Assets* .
        No
        impairment loss has been recognized as a result of the recoverability tests.
  51
  ***Texas
        Gas Rate Case***
 
 Texas
        Gas
        filed a rate case with the FERC on April 29, 2005, and implemented the new
        rates
        on November 1, 2005, subject to refund. As of December 31, 2005, an estimated
        refund liability of approximately $5.0 million related to the rate case was
        recorded on the Consolidated Balance Sheets. The rate case was settled in
        the
        second quarter 2006 and the refund liability was reduced to zero by the amount
        of cash refunds paid to customers on June 30, 2006, consisting of $6.4 million
        in principal and $0.2 million of interest. At December 31, 2006, there was
        no
        liability for any open rate case recorded on the Consolidated Balance Sheets.
        In
        accordance with the terms of the settlement, Texas Gas has no obligation
        to file
        a new rate case and is prohibited from placing new rates into effect prior
        to
        November 1, 2010. Currently, neither Texas Gas nor Gulf South is involved
        in an
        open general rate case.
 
 
 ***Pipeline
        Integrity***
 
 The
        Office of Pipeline Safety (OPS) has issued a final rule that requires natural
        gas pipeline operators to develop integrity management programs. Pursuant
        to the
        rule, pipelines were required to identify high consequence areas (HCAs) on
        their
        systems and develop a written integrity management program providing for
        a
        baseline assessment and periodic reassessments to be completed within specified
        timeframes. The Partnership has complied with these requirements. Its estimated
        costs to comply with the rule during the initial ten-year baseline period
        ending
        in 2012 range from $100.0 to $120.0 million. As of December 31, 2006, the
        Partnership has invested approximately $22.3 million to develop and implement
        integrity management programs 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. **
 
 On
        June
        30, 2005, the FERC issued an order addressing the accounting treatment for
        the
        costs pipeline operators will incur in implementing all aspects of pipeline
        integrity management programs which are required by the OPS. The FERC's
        accounting guidance became effective prospectively, beginning with integrity
        management costs incurred on or after January 1, 2006. Amounts capitalized
        in
        periods prior to January 1, 2006, were permitted to remain as recorded. The
        Partnership applied the accounting guidance order on January 1, 2006. There
        were
        no changes to the Partnership's accounting policy for the pipeline integrity
        management programs as a result of the application of this
        guidance.
 
 
 52
  **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, 2006 and 2005,
        the
        Partnership had an accrued liability of approximately $18.4 million and $20.0
        million related to environmental remediation.
 
 Beginning
        in 2004, as part of the Partnership’s proactive approach and continued
        implementation of environmental remediation efforts, Texas Gas entered into
        agreements, or met with various state agencies, to address remediation issues
        primarily on a voluntary basis. As of December 31, 2006 and 2005, Texas Gas
        had
        an accrued liability of $2.8 million, $1.0 million of which was presented
        in
        Current Liabilities, and $3.5 million, for estimated remaining probable costs
        associated with environmental assessment and remediation, primarily for
        remediation associated with the historical use of polychlorinated biphenyls,
        petroleum hydrocarbons and mercury. This accrual represents management’s
        estimate of the undiscounted future obligation based on evaluations and
        discussions with counsel and independent consultants and the current facts
        and
        circumstances related to these matters. The assumptions are based on a
        substantial number of existing assessments and completed remedial activities
        by
        third-party consultants, including a Texas Gas system-wide assessment and/or
        cleanup of polychlorinated biphenyls, petroleum hydrocarbons, mercury and
        asbestos abatement. Texas Gas is continuing to conduct environmental assessments
        and is implementing a variety of remedial measures that may result in a change
        in the total estimated costs. These costs are expected to occur over
        approximately the next five years.
 
 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, Marshall County,
        Kentucky. The Partnership is unable to estimate with any certainty at this
        time
        any potential liability it may incur related to this notice, however, the
        Partnership does not expect this to have a material effect on its financial
        condition.
 
 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% 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 advantages of the
        settlement agreement are:
 
 (1)
            the
                EPA will not pursue any further action against Texas Gas for EPA
                costs
                related to the site no matter how much the planned remedial action
                ultimately may cost, and 
 (2)
            the
                Super Fund law provides protection from “contribution” suits for parties
                that settle, i.e. suits from other potentially responsible parties
                that
                perform or finance cleanup at the site. 
 Texas
        Gas
        has agreed to the settlement. The EPA held a 30-day public comment period
        regarding Texas Gas’s settlement.  The EPA will notify Texas Gas when
        the settlement is effective and payment of the $0.1 million will be due within
        thirty days of the effective date.
 
 An
        analysis of the environmental contamination and related remediation costs
        at
        sites owned and/or operated by Gulf South was conducted by the Partnership
        in
        conjunction with a third-party consultant. As a result, Gulf South has recorded
        an environmental accrual comprised of estimated future costs associated with identifying and remediating
        contamination from hydrocarbons, mercury and polychlorinated
        biphenyls ;
        enhancement of groundwater protection measures; and other costs.
  The
        non-current portion of this accrual was $13.1 million and $14.0 million as
        of
        December 31, 2006 and 2005, and the current portion of this accrual was $2.5
        million at both December 31, 2006 and 2005. The accruals recorded by Gulf
        South
        were based upon analysis of the findings of the environmental consultant,
        including the assumptions underlying such findings. Those assumptions reflect
        management’s best estimate of the probable remediation costs based on the known
        levels of contamination, the historical experience of individual pipelines
        and
        the expertise of the environmental consultant in remediating such contamination.
        The actual cost of remediation could be impacted by the discovery of additional
        contamination, including for example, groundwater contamination, at one or
        more
        sites as a result of its on-going due diligence review. The Partnership could
        uncover additional information during the course of remediating a particular
        site, as well as by determinations or requests, if any, made by regulatory
        authorities relating to the remediation of any particular site.
 
 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 operates two facilities in areas affected by non-attainment
        requirements for the current ozone standard (eight-hour standard). As of
        December 31, 2006, the Partnership had incurred costs of approximately $14.0
        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 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
        addition, the EPA promulgated new rules regarding hazardous air pollutants
        in
        2004, which will impose additional controls at three facilities at an estimated
        cost of $1.7 million. The effective compliance date for the hazardous air
        pollutants regulations is 2007. The Partnership anticipates continued
        installation of associated controls to meet these new regulations in 2007.
        In
        addition, three of Gulf South’s facilities located in Texas are required to make
        changes to meet additional requirements imposed by the state of Texas in
        regards
        to the CAA. The effective compliance date for such additional Texas requirements
        is March 1, 2007. Gulf South expects to spend approximately $0.4 million
        to meet
        these requirements. 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.
 
 53
 
 **Lease
        Commitments**
 
 The
        Partnership has various operating lease commitments extending through the
        year
        2018 covering storage facilities, offices and equipment. The lease for Gulf
        South’s current office space expires in May 2007 and, accordingly, Gulf South
        signed a new ten-year lease for approximately 74,000 square feet of office
        space
        in a new location in Houston, Texas. Payments due under the lease are
        approximately $1.6 million per year for the first five years and $1.8 million
        per year thereafter. Gulf South will begin moving into the new headquarters
        in
        April 2007. Total lease expenses during 2006 and 2005 were approximately
        $4.7
        million and $4.2 million. Amounts for 2004 were immaterial. The following
        table
        summarizes minimum future commitments related to these items at December
        31,
        2006 (in millions):
 
 2007
              $
                  5.92008
              5.62009
              4.52010
              4.22011
              2.0Thereafter
              12.6Total
              $
                  34.8
 
 
 **Commitments
        for Construction**
 
 The
        Partnership incurred $200.3 million of capital expenditures in 2006, net
        of
        amounts received for salvage and accrued amounts. The Partnership’s future
        capital commitments as of December 31, 2006, for contracts already authorized
        are expected to approximate the following amounts (in millions):
 
 Less
                  than 1 year
              
              $
                  403.81-3
                  years
              
              5.24-5
                  years
              
              0.1More
                  than 5 years
              
              -Total
              
              $
                  409.1
  
 54
  **Note
        4: Property, Plant and Equipment**
 
 In
        2006,
        Texas Gas 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.
 
 In
        June
        2006, Gulf South 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
        will be used to offset the costs of rebuilding certain offshore facilities.
        The
        total cost of the new facilities is not expected to exceed $8.0
        million.
  55
  The
        following table presents the Partnership’s PPE as of December 31, 2006 and 2005
        (in thousands):
 
 **Category**
              
              **2006
                  Class Amount**
              
              **Weighted-Average
                  Useful Lives (Years)**
              
              **2005
                  Class Amount**
              
              **Weighted-Average
                  Useful Lives (Years)**Depreciable
                  plant:Intangible
              
              $
              18,901
              
              
              9
              
              $
              10,776
              
              
              30Gathering
              
              
              90,787
              
              
              19
              
              
              88,852
              
              
              19Storage
              
              
              163,323
              
              
              48
              
              
              155,717
              
              
              46Transmission
              
              
              1,601,064
              
              
              45
              
              
              1,484,901
              
              
              42General
              
              
              63,698
              
              
              16
              
              
              64,548
              
              
              19Total
                  utility depreciable plant
              
              
              1,937,733
              
              
              43
              
              
              1,804,794
              
              
              41Non-depreciable:Land
              
              
              9,386
              
              
              
              
              
              9,470Storage
              
              
              85,392
              
              
              
              
              
              85,393Other
              
              
              179,297
              
              
              
              
              
              85,962Total
                  other
              
              
              274,075
              
              
              
              
              
              180,825Total
                  PPE
              
              
              2,211,848
              
              
              
              
              
              1,985,619Less:
                  accumulated depreciation
              
              
              187,412
              
              
              
              
              
              118,213Total
                  PPE, net
              
              $
              2,024,436
              
              
              
              
              $
              1,867,406
  The
        non-transmission assets have weighted-average useful lives of 32 years as
        of
        December 31, 2006 and 2005. The gross depreciable non-transmission asset
        value
        was $336.7 million and $319.9 million as of December 31, 2006 and 2005. The
        non-depreciable assets and work in progress of $274.1 million and $180.8
        million
        as of December 31, 2006 and 2005, were not included in the calculation of
        the
        weighted-average useful lives. The Partnership’s depreciation and amortization
        expense for the years ended December 31, 2006, 2005, and 2004 was $75.8 million,
        $72.1 million and $34.0 million.
 
 56
 
 **Note
        5: Asset Retirement Obligations**
 
 The
        Partnership has identified and recorded legal obligations associated with
        the
        abandonment of offshore pipeline laterals, the abandonment of certain onshore
        facilities and 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):
 
 **2006**
              
              **2005**Balance
                  at beginning of year
              
              $
              14,074
              
              $
              3,254Liabilities
                  recorded
              
              
              (366
              )
              
              10,593Liabilities
                  settled
              
              
              -
              
              
              (417
              )Accretion
                  expense
              
              
              599
              
              
              644Balance
                  at end of year
              
              $
              14,307
              
              $
              14,074
 
 In
        March
        2005, FASB issued Interpretation No. 47, *Accounting
        for Conditional AROs,* which
        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 Texas Gas’s 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 estimated useful
        life
        was obtained from a study by the original architects performed in 1995, and
        confirmed by Natural Resource Group in 2003, indicating 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.
 
 Texas
        Gas’s depreciation rates for utility plant are approved by the FERC.  The
        approved depreciation rates 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
        $39.6 million and $33.2 million as of December 31, 2006 and 2005, in the
        accompanying Consolidated Balance Sheets as Provision for other asset
        retirement.
 
 57
 
 **Note
        6: Regulatory Assets and Liabilities**
 
 The
        amounts recorded as regulatory assets and liabilities in the Consolidated
        Balance Sheets as of December 31, 2006 and 2005, 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 Texas Gas’s embedded cost of debt financing utilized in its 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, 2006 and 2005 (in
        thousands):
 
 
 **2006**
              
              **2005**Regulatory
                  Assets:Pension
              
              $
              7,820
              
              $
              3,841Tax
                  effect of AFUDC equity
              
              
              6,794
              
              
              7,236Unamortized
                  debt expense and premium on reacquired debt
              
              
              11,703
              
              
              12,701Postretirement
                  benefits other than pension
              
              
              10,569
              
              
              33,156Fuel
                  tracker
              
              
              5,783
              
              
              2,005Imbalances/storage
                  valuation tracker
              
              
              37
              
              
              1,282Total
                  regulatory assets
              
              $
              42,706
              
              $
              60,221
 
 Regulatory
                  Liabilities:Provision
                  for asset retirement
              
              $
              39,644
              
              $
              33,212Unamortized
                  discount on long-term debt
              
              
              (1,851
              )
              
              (2,024
              )Total
                  regulatory liabilities
              
              $
              37,793
              
              $
              31,188
 
 58
 
 **Note
        7: Financing**
 
 *Senior
        Unsecured Debt*
 
 On
        November 21, 2006, Boardwalk Pipelines r eceived
        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
        notes
        will be redeemable, in whole or in part, at the Partnerships’ option at any
        time, at a redemption price equal to the greater of 100% of the principal
        amount
        of the notes to be redeemed or a “make whole” redemption price based on the
        remaining scheduled payments of principal and interest discounted at a Treasury
        rate plus 20 basis points, plus accrued and unpaid interest, if any, to the
        date
        of redemption. If certain events of default occur, either the trustee or
        the
        holders of not less than 25 percent in principal amount of the then outstanding
        notes may declare the entire principal of all of the notes and interest accrued
        thereon to be due and payable immediately. If an event of default due to
        certain
        events of bankruptcy, insolvency and reorganization of the Partnership or
        any
        significant subsidiary shall have occurred and be continuing, the entire
        principal of all of the notes and interest accrued thereon will become
        immediately due and payable without any declaration of acceleration or other
        act
        on the part of the trustee or any holders.
  The
        following table represents all long-term debt issues outstanding (in
        thousands):
 
 **December
                  31,****2006**
              
              **2005****Boardwalk
                  Pipelines**5.88%
                  Notes due 2016
              
              $
              250,000
              
              
              -5.20%
                  Notes due 2018
              
              
              185,000
              
              $
              185,0005.50%
                  Notes due 2017
              
              
              300,000
              
              
              300,000**Texas
                  Gas**7.25%
                  Debentures due 2027
              
              
              100,000
              
              
              100,0004.60%
                  Notes due 2015
              
              
              250,000
              
              
              250,000**Gulf
                  South**5.05%
                  Notes due 2015
              
              
              275,000
              
              
              275,0001,360,000
              
              
              1,110,000Unamortized
                  debt discount
              
              
              (9,080
              )
              
              (8,710
              )Total
                  long-term debt
              
              $
              1,350,920
              
              $
              1,101,290
  As
        of
        December 31, 2006 and 2005, the weighted-average interest rate of the
        Partnership’s long-term debt was 5.40% and 5.29%.
 
 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, 2006, Boardwalk Pipelines and the operating subsidiaries were in compliance
        with their debt covenants.
 
 In
        December 2004, Boardwalk Pipelines borrowed $575.0 million as an interim
        term
        loan in connection with its acquisition of Gulf South. In January 2005,
        Boardwalk Pipelines issued $300.0 million principal amount of 5.50% notes
        due
        2017 and Gulf South issued $275.0 million principal amount of 5.05% notes
        due
        2015. The proceeds from these notes, shown as Proceeds from long-term debt,
        net
        of issuance costs in the Consolidated Statements of Cash Flows together with
        available cash, were used to repay the interim loan. In March 2004, Texas
        Gas
        repaid $17.3 million representing the balance of its 8.625% notes upon final
        maturity with available cash.
 
 
 *Revolving
        Credit Facility*
 
 The
        Partnership maintains a $400.0 million revolving credit facility, under which
        Boardwalk Pipelines, Texas Gas and Gulf South 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. As of December
        31,
        2006, the Partnership was in compliance with all the covenant requirements
        under
        the credit agreement. During 2006, Gulf South had borrowed and repaid $90.0
        million under this credit facility. The interest rates on the borrowings
        were
        5.55% to 5.73%. As of December 31, 2006, no funds were drawn under the facility.
        The revolving credit facility has a maturity date of June 29, 2011.
 
 In
        connection with the IPO, Boardwalk Pipelines borrowed approximately
        $42.1 million against the original credit facility to reimburse BPHC for
        capital expenditures it incurred in connection with the acquisition of Gulf
        South, which was subsequently paid off in February 2006. Interest on the
        credit
        facility was accrued at the 3-month LIBOR rate plus applicable margin (4.68%).
 
 59
 
 **Note
        8: Derivatives**
 
 Boardwalk
        Pipelines entered into a Treasury rate lock October 5, 2006 for a notional
        amount of $250.0 million of principal to hedge the risk attributable to changes
        in the risk-free component of forward 10-year interest rates through the
        expected date of issuance of $250.0 million of senior unsecured notes. The
        reference rate on the Treasury rate lock was 4.60%. The rate lock was settled
        at
        the time of the closing of the debt offering in November 2006. The Partnership
        received $0.9 million from the counterparty as a result of the settlement
        of the
        instrument. The Treasury rate lock was designated as a cash flow hedge in
        accordance with SFAS No. 133. Accordingly, the $0.9 million settlement amount
        was recorded as a component of Accumulated other comprehensive income (loss)
        and
        will be recognized in income as a reduction to interest expense on a
        straight-line basis over the 10-year term of the 5.88% senior
        notes.
  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 are 5.00%
        and 4.96%. Under the terms of the rate locks, the counterparties would pay
        the
        Partnership settlement amounts if the 10-year Treasury rate is greater than
        the
        reference rates on August 1, 2007. Conversely, the Partnership would pay
        the
        counterparties settlement amounts if the 10-year Treasury rate is less than
        the
        reference rates. The Treasury rate locks were designated as cash flow hedges
        in
        accordance with SFAS No. 133. As of December 31, 2006, the Partnership reported
        a liability of $4.3 million, and a reduction in Accumulated other comprehensive
        income (loss) in an equal and offsetting amount less ineffectiveness recognized
        in 2006 of less than $0.1 million, for the fair values of the August 2007
        rate
        locks.
 
 Certain
        volumes of gas stored underground are available for sale and subject to
        commodity price risk. At December 31, 2006 and 2005, approximately $14.0
        million
        and $6.5 million, of Gulf South's gas stored underground, which the Partnership
        owns and carries as current Gas stored underground, is exposed to commodity
        price risk. Gulf South utilizes derivatives to hedge certain exposures to
        market
        price fluctuations on the anticipated operational sales of gas. As a result of the
        Western Kentucky storage expansion project, approximately 4.8 Bcf of gas
        stored
        underground with a book value of $11.3 million at Texas Gas is subject to
        forward sales agreements which base the ultimate sales price, to be determined
        in March 2007, on the price of New York Mercantile Exchange (NYMEX) natural
        gas
        futures. Texas Gas has entered into derivatives to hedge the price exposure
        related to these agreements.
 
 The
        derivatives related to the sale of natural gas and cash for fuel reimbursement
        generally qualify for cash flow hedge accounting under SFAS No. 133 and are
        designated as such. The 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
        (loss). The deferred gains and losses are recognized in the Consolidated
        Statements of Income when the hedged anticipated purchases or sales 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 the the Western Kentucky storage
        expansion project, any gains and losses on the related derivatives would
        be
        recognized in Net (gain) on disposal of operating assets.
 
 The
        fair
        values of derivatives existing as of December 31, 2006 and 2005 were included
        in
        the following captions in the Consolidated Balance Sheets (in
        millions):
 
 **December
                  31, 2006**
              
              **December
                  31, 2005**Prepaid
                  expenses and other current assets
              
              $
              13.7
              
              $
              0.6Other
                  current liabilities
              
              
              5.1
              
              
              0.8Accumulated
                  other comprehensive income (loss)
              
              
              8.5
              
              
              (0.2
              )
 
 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 the Consolidated Statements
        of
        Income.  Ineffectiveness of $0.5 million was recorded during the twelve
        month period ended December 31, 2006. No ineffectiveness was recorded during
        the
        comparable 2005 and 2004 periods.  No cash flow hedges were discontinued
        during the twelve month periods ended December 31, 2006 and 2005.
 
 During
        2007 the Partnership expects to reclassify approximately $11.6 million of
        unrealized gains included in Accumulated other comprehensive income (loss)
        at
        December 31, 2006 into earnings.
 
 Derivatives
        related to the value of company-owned storage capacity and the purchase of
        operational gas for the East Texas and Mississippi pipeline expansion project
        were not designated as hedges in accordance with SFAS No. 133. The changes
        in
        the values of the derivatives were recognized currently in earnings. In 2006,
        the Partnership recognized income of $0.7 million in Gas storage revenues
        and
        $0.5 million in Miscellaneous other income, net related to the change in
        fair
        values associated with the derivatives.
  60
  **Note
        9: Employee Benefits** ****
 
 ***Retirement
        Plans***
 
 Substantially
        all of Texas Gas's current employees are covered under a non-contributory,
        qualified defined-benefit retirement plan. Additionally, 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 (IRC). Texas Gas uses a measurement
        date of December 31 for its retirement plans. Effective in November 2006,
        the
        defined benefit retirement plan was closed to new participants and new employees
        will be provided benefits under a defined contribution money purchase
        plan.
 
 Texas
        Gas
        has not been required to fund the qualified retirement plan since 1986. As
        a
        result of the rate case settlement in 2006, Texas Gas is required to fund
        the
        amount of its 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 Texas Gas’s retirement plan including
        approximately $11.4 million additional funding that the Partnership elected
        to
        provide to immediately improve the funded status of the plan. Due to the
        additional funding, the Partnership does not expect to fund any amount to
        the
        Texas Gas retirement plan in 2007. Through December 31, 2006, no funding
        has
        been provided for the SRP 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. The
        Partnership 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 made an immaterial amount of
        contributions to this plan in 2006, $3.9 million in 2005 and $4.9 million
        in
        2004. Due to plan changes regarding benefits available to current and future
        retirees described below, the plan is currently in an overfunded status and,
        therefore, the Partnership does not expect to make any contributions to the
        Texas Gas PBOP plan in 2007.
 
 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 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. Retirements under the program were generally effective
        January 1, 2007. Approximately 100 of the eligible employees elected to
        participate in the program.
 
 
 As
        a
        result of the ERIP, the Partnership recognized a special termination benefit
        of
        approximately $6.0 million for pension and $0.9 million for PBOP in 2006.
        In
        accordance with the regulatory treatment for Texas Gas's benefits expense,
        $2.6
        million of the special termination benefit for pension and $0.9 million for
        PBOP
        was recognized in Administrative and general expense and the remaining $3.4
        million of the special termination benefit for pensions was deferred as a
        regulatory asset.
 
 
 ***Initial
        Application of SFAS No. 158***
 
 The
        Partnership began applying the provisions of SFAS No. 158, *Employers’
        Accounting for Defined Benefit Pension and Other Postretirement Plans,* for
        the
        year ended December 31, 2006. The following tables are presented in accordance
        with SFAS No. 158. Note 15 contains more information regarding the initial
        application of SFAS No. 158.
 
 
 ***Funded
        Status***
 
 The
        following table presents the funded status and the amounts not yet recognized
        as
        components of net periodic pension cost for both the retirement plans and
        PBOP
        at December 31, 2006 and 2005 (in thousands):
 **Retirement
                    Plans**
                
                **PBOP****For
                    the Year Ended December 31,**
                
                **For
                    the Year Ended December 31,****2006**
                
                **2005**
                
                **2006**
                
                **2005****Funded
                    status:**Projected
                    benefit obligation
                $
                    136,886
                
                $
                    116,931
                
                -
                
                -APBO
                -
                
                -
                
                $
                    65,341
                
                $
                    134,188Plan
                    assets at fair value
                121,125
                
                96,194
                
                80,218
                
                79,463Funded
                    status
                (15,761)
                
                (20,737)
                
                14,877
                
                (54,725)Unrecognized
                    net actuarial loss
                -
                
                15,691
                
                -
                
                20,412Net
                    amount recognized
                $
                    (15,761)
                
                $
                    (5,046)
                
                $
                    14,877
                
                $
                    (34,313)**Items
                    not yet recognized as components of net periodic pension
                    cost:**Prior
                    service cost
                $
                    73
                
                -
                
                $
                    (70,744)
                
                -Net
                    actuarial loss (gain)
                17,967
                
                -
                
                22,316
                
                -Total
                $
                    18,040
                
                -
                
                $
                    (48,428)
                
                -
  61
  ***Projected
        Benefit Obligation***
  The
        projected benefit obligation and fair value of assets of the retirement plans
        and PBOP at December 31, 2006 and 2005 were as follows (in
        thousands):
 **Retirement
                    Plans**
                
                **PBOP****For
                    the Year Ended December 31,**
                
                **For
                    the Year Ended December 31,****2006**
                
                **2005**
                
                **2006**
                
                **2005**Change
                    in benefit obligation:Benefit
                    obligation at beginning of period
                $
                    116,931
                
                $
                    104,412
                
                $
                    134,188
                
                $
                    125,599Service
                    cost
                4,432
                
                4,067
                
                1,319
                
                2,076Interest
                    cost
                6,695
                
                6,283
                
                5,147
                
                7,222Plan
                    participants’ contributions
                -
                
                -
                
                1,509
                
                1,328Actuarial
                    loss
                6,326
                
                6,214
                
                4,902
                
                5,379Benefits
                    paid
                (3,576)
                
                (4,045)
                
                (7,633)
                
                (7,416)Retirement
                    / PBOP plan amendment
                73
                
                -
                
                (75,271)
                
                -Special
                    termination benefits (ERIP)
                6,005
                
                -
                
                884
                
                -Retiree
                    drug subsidy
                -
                
                -
                
                296
                
                -Benefit
                    obligation at end of period
                $
                    136,886
                
                $
                    116,931
                
                $
                    65,341
                
                $
                    134,188Change
                    in plan assets:Fair
                    value of plan assets at beginning of period
                $
                    96,193
                
                $
                    93,056
                
                $
                    79,462
                
                $
                    76,499Actual
                    return on plan assets
                10,468
                
                7,131
                
                6,539
                
                5,164Benefits
                    paid
                (3,576)
                
                (4,045)
                
                (7,633)
                
                (7,416)Company
                    contributions
                18,040
                
                52
                
                341
                
                3,888Plan
                    participants’ contributions
                -
                
                -
                
                1,509
                
                1,328Fair
                    value of plan assets at end of period
                $
                    121,125
                
                $
                    96,194
                
                $
                    80,218
                
                $
                    79,463
 The
        Partnership does not anticipate that any plan assets will be returned to
        the
        Partnership during 2007. At December 31, 2006 and 2005, the following aggregate
        information relates only to the underfunded retirement plan (in
        thousands):
 
 **For
                  the Year Ended December 31,****2006**
              
              **2005**Projected
                  benefit obligation
              
              $
              136,886
              
              $
              116,931Accumulated
                  benefit obligation
              
              
              118,147
              
              
              94,935Fair
                  value of plan assets
              
              
              121,125
              
              
              96,194
 
 
 ***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, 2006, 2005 and 2004 were the following (in
        thousands):
 **Retirement
                  Plans**
              
              **PBOP****For
                  the Year Ended December 31,**
              
              **For
                  the Year Ended December 31,****2006**
              
              **2005**
              
              **2004**
              
              **2006**
              
              **2005**
              
              **2004**Service
                  cost
              
              $
              4,432
              
              $
              4,067
              
              $
              3,531
              
              $
              1,319
              
              $
              2,076
              
              $
              2,095Interest
                  cost
              
              
              6,695
              
              
              6,283
              
              
              5,636
              
              
              5,147
              
              
              7,222
              
              
              5,912Expected
                  return on plan assets
              
              
              (7,131
              )
              
              (6,859
              )
              
              (6,644
              )
              
              (4,653
              )
              
              (4,632
              )
              
              (5,252
              )Amortization
                  of prior service credit
              
              
              -
              
              
              -
              
              
              -
              
              
              (4,527
              )
              
              -
              
              
              -Amortization
                  of unrecognized net loss (gain)
              
              
              713
              
              
              300
              
              
              (20
              )
              
              1,112
              
              
              362
              
              
              (66
              )Special
                  termination benefit (ERIP)
              
              
              6,005
              
              
              -
              
              
              -
              
              
              884
              
              
              -
              
              
              -Regulatory
                  asset decrease (increase)
              
              
              (3,979
              )
              
              (3,713
              )
              
              (2,455
              )
              
              7,337
              
              
              -
              
              
              -Net
                  periodic pension expense
              
              $
              6,735
              
              $
              78
              
              $
              48
              
              $
              6,619
              
              $
              5,028
              
              $
              2,689
 
 The
        decrease in the regulatory asset for PBOP is due to the amortization of costs
        incurred in prior years.
 
 
 62
 
 ***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**2007
              $
                  35,674
              
              $
                  5,5242008
              3,808
              
              5,3932009
              4,286
              
              5,2232010
              6,280
              
              5,0122011
              7,052
              
              4,9622012-2017
              60,973
              
              23,055
 
 
 ***Weighted
        -Average Assumptions***
 
 The
        Partnership’s weighted-average asset allocations at December 31, 2006 and 2005
        for both the qualified retirement plan and PBOP trusts by category were as
        follows:
 
 **Retirement
                  Plan**
              
              **PBOP****December
                  31, 2006**
              
              **December
                  31, 2005**
              
              **December
                  31, 2006**
              
              **December
                  31, 2005**Debt
                  securities
              
              
              37.1
              %
              
              62.5
              %
              
              -
              
              
              -Equity
                  securities
              
              
              27.4
              %
              
              30.9
              %
              
              -
              
              
              -Limited
                  partnership
              
              
              12.1
              %
              
              6.4
              %
              
              -
              
              
              -Other
              
              
              23.4
              %
              
              0.2
              %
              
              -
              
              
              -Fixed
                  income
              
              
              -
              
              
              -
              
              
              46.3
              %
              
              45.2
              %Cash
                  and other
              
              
              -
              
              
              -
              
              
              53.7
              %
              
              54.8
              %Total
              
              
              100.0
              %
              
              100.00
              %
              
              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 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, 2006 and 2005 were the following:
  **Retirement
                    Plans**
                
                **PBOP****December
                    31, 2006**
                **December
                    31, 2005**
                
                **December
                    31, 2006**
                **December
                    31, 2005**Discount
                    rate
                5.75%
                5.63%
                
                5.75%
                5.63%Rate
                    of compensation increase
                5.50%
                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,****2006**
                **2005**
                **2004**
                
                **2006**
                **2005**
                **2004**Discount
                    rate
                5.63%
                5.88%
                6.25%
                
                5.63%
                    to 5.75%
                5.88%
                5.88%Expected
                    return on plan assets
                7.50%
                7.50%
                7.50%
                
                6.15%
                    to 5.00%
                6.15%
                    to 5.00%
                7.50%
                    to 5.00%Rate
                    of compensation increase
                5.50%
                5.50%
                5.50%
                
                -
                -
                -
 
 63
  ***PBOP
        assumed health care cost trends***
 
 Assumed
        healthcare-cost-trend rates have a significant effect on the amounts reported
        for PBOP. A one-percentage-point change in assumed healthcare-cost-trend
        rates
        would have had the following effects on amounts reported for the years ended
        December 31, 2006, 2005 and 2004 (in thousands):
 
 **Effect
                  of 1% Increase:**
              
              **2006**
              
              **2005**
              
              **2004**Benefit
                  obligation at end of year
              
              $
              3,102
              
              $
              19,785
              
              $
              18,077Total
                  of service and interest costs for year
              
              
              927
              
              
              1,585
              
              
              1,352
 
 **Effect
                  of 1% Decrease:**Benefit
                  obligation at end of year
              
              $
              (2,764
              )
              
              (16,077
              )
              
              (14,670
              )Total
                  of service and interest costs for year
              
              
              (757
              )
              
              (1,263
              )
              
              (1,078
              )
 
 For
        measurement purposes, at December 31, 2006, 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. For
        December 31, 2005, measurement purposes, health care costs for the plans
        were
        assumed to increase 9.0% for 2006-2007, grading down to 5.0% in 0.5% annual
        increments for participants not eligible for Medicare eligibles and 11.0%
        grading down to 5.0% in 0.5% annual increments for participants eligible
        for
        Medicare.
 
 
 ***Defined
        Contribution Plans***
 
 The
        Partnership maintains defined contribution plans covering substantially all
        of
        its employees. Costs related to these plans were $5.1 million, $4.9 million
        and
        $2.6 million for the years ended December 31, 2006, 2005 and 2004.
 
 
 ***Strategic
        Long Term Incentive Plan***
  On
        July
        24, 2006, Boardwalk GP approved the Boardwalk Pipeline Partners 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. 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.
 
 On
        December 21, 2006, 125 Phantom GP Units were awarded to selected employees
        that
        vest in approximately 4.0 years. Concurrent with the approval of the plan,
        in
        July 2006, 125 Phantom GP Units were awarded to selected employees that vest
        in
        3.5 years. At December 31, 2006, 250 Phantom GP Units were available for
        grant
        under the plan.
 
 The
        fair
        value of the awards was determined as of the date of grant, 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, and will be remeasured at each
        reporting period in accordance with the treatment of awards classified as
        liabilities prescribed in SFAS No. 123(R) *.* The fair
        value of the awards will be recognized ratably over the vesting period and
        remeasured each quarter until settlement. The Partnership recognized $0.8
        million in Administrative and general expenses during 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, 2006, of $11.4 million will be recognized over
        the
        average remaining vesting period of approximately 3.5 years.
 
 
 ***Long-Term
        Incentive Plan***
 
 During
        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 has reserved 3,525,000 units for grants of
        units,
        restricted units, unit options and unit appreciation rights under the plan.
        On
        December 21, 2006, the Partnership granted 49,387 Phantom Common Units under
        the
        LTIP but did not make any grants of units, restricted units, unit options
        and
        unit appreciation rights. Each such grant includes: a tandem grant of
        Distribution Equivalent Rights (DERs); vests 50% on the second anniversary
        of
        the grant date; and 50% on the third anniversary of the grant date; and will
        be
        payable to the grantee in cash upon vesting in an amount equal to the sum
        of the
        fair market value of the units (as defined in the plan) that vest on the
        vesting
        date plus the vested amount then credited to the grantee’s DER account, less
        applicable taxes. The
        fair
        value of the awards will be recognized ratably over the vesting period and
        remeasured each quarter until settlement based on
        the market price of the Partnership’s common units and amounts credited under
        the DERs.
 
 At
        December 31, 2006, 75,083 Phantom Common Units were outstanding under the
        plan.
        During 2006, 3,480 Phantom Common Units were forfeited. On March 23, 2006,
        the
        general partner purchased 1,000 of our 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 on March 24, 2006, as part of their director compensation.
        See Executive Compensation - Director Compensation in Item 11 of this Report.
        At
        December 31, 2006, 3,524,000 units were available for grants under LTIP.
        The
        Partnership recognized $0.2 million of expense related to the outstanding
        units
        during 2006. Amounts recognized in 2005 were immaterial. The total estimated
        remaining unrecognized compensation expense related to the Phantom Common
        Units
        outstanding at December 31, 2006, of $2.1 million will be recognized over
        the
        average remaining vesting period of approximately 2.2 years.
 
 64
  **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 Issue No. 03-6 (EITF 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 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%
              2%First
                  Target Distribution
              
              up to $0.4025
              
              98%
              2%Second
                  Target Distribution
              
              above $0.4025 up to $0.4375
              
              85%
              15%Third
                  Target Distribution
              
              above
                  $0.4375 up to $0.5250
              
              75%
              25%Thereafter
              
              above
                  $0.5250
              
              50%
              50%
 
 
 The amounts
        reported for net income per limited partner unit on the Consolidated
        Statements of Income for the years ended December 31, 2006 and 2005,
        were reduced 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 and not based on the assumed allocation required by EITF No.
        03-6.  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 is as follows (in thousands, except weighted average units and per unit
        data):
 
 **For
                  the Year Ended**
                **December
                  31, 2006**
              
              **For
                  the Period**
                **November
                  15, 2005**
                **through**
                **December
                  31, 2005**Limited
                  partners' interest in net income
              
              $
              193,599
              
              $
              35,272Less
                  assumed allocation to incentive distribution rights
              
              
              5,187
              
              
              -Net
                  income available to limited partners
              
              
              188,412
              
              
              35,272Less
                  assumed allocation to subordinated units
              
              
              61,087
              
              
              11,382Net
                  income available to common units
              
              $
              127,325
              
              $
              23,890Weighted
                  average common units
              
              
              68,977,766
              
              
              68,256,122Weighted
                  average subordinated units
              
              
              33,093,878
              
              
              33,093,878Net
                  income per limited partner unit - common and subordinated
                  units
              
              $
              1.85
              
              $
              0.35
 
   65
  T he
        Partnership has declared quarterly distributions per unit to unitholders
        of
        record, including common and subordinated units and the 2% general partner
        interest held by its general partner as follows:
 
 **Record
                  Date**
              
              **Payable
                  Date**
              
              **Distribution
                  per Unit**February
                  20, 2007
              
              February
                  27, 2007
              
              $
                  0.415October
                  30, 2006
              
              November
                  6, 2006
              
              0.40August
                  11, 2006
              
              August
                  18, 2006
              
              0.38May
                  12, 2006
              
              May
                  19, 2006
              
              0.36February
                  16, 2006
              
              February
                  23, 2006
              
              0.1788*
 
 *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.
 
 The Partnership also
        declared a cash distribution payable to its general partner with respect to
        its 2.0% general partner interests, and with respect to that portion of the
        distribution in excess of $0.4025 per unit, its incentive distribution rights
        described above.
 
 66
  **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 has recorded a charge-in-lieu of income
        taxes for the period January 1, 2005 through the date of the offering and
        has
        recorded no charge-in-lieu of income taxes thereafter. Pursuant to the change
        in
        tax status, the Partnership also eliminated its balance of accumulated deferred
        income taxes at the date of the offering. A
        subsidiary of the Partnership directly incurs some income-based state taxes
        which are accrued as Income taxes and charge-in-lieu of income taxes on the
        Consolidated Statements of Income.
 
 Following
        is a summary of the provision for Income taxes and charge-in-lieu of income
        taxes for the periods ended December 31, 2006, 2005, and 2004 (in
        thousands):
 
 **For
                  the Year Ended December 31,****2006**
              
              **2005**
              
              **2004**Current
                  expense (benefit):Federal
              
              
              -
              
              $
              4,044
              
              $
              (9,131
              )State
              
              $
              292
              
              
              870
              
              
              (1,964
              )Total
              
              
              292
              
              
              4,914
              
              
              (11,095
              )Deferred
                  provision (benefit) :Federal
              
              
              -
              
              
              36,690
              
              
              35,803State
              
              
              (39
              )
              
              7,890
              
              
              7,625Elimination
                  of cumulative deferred taxes
              
              
              -
              
              
              10,102
              
              
              -Total
              
              
              (39
              )
              
              54,682
              
              
              43,428Income
                  taxes and charge-in-lieu of income taxes
              
              $
              253
              
              $
              59,596
              
              $
              32,333
  Reconciliations
        from the provision at the statutory rate to the Income tax and charge-in-lieu
        of
        income tax provision are as follows (in thousands):
 
 **For
                  the Year Ended December 31,****2006**
              
              **2005**
              
              **2004**Provision
                  at statutory rate
              
              
              -
              
              $
              43,583
              
              $
              28,405Increases
                  in taxes resulting from:State
                  income taxes
              
              $
              253
              
              
              5,694
              
              
              3,680Other,
                  net
              
              
              -
              
              
              217
              
              
              248Elimination
                  of deferred taxes
              
              
              -
              
              
              10,102
              
              
              -Income
                  taxes and charge-in-lieu of income taxes
              
              $
              253
              
              $
              59,596
              
              $
              32,333
 
 As
        of
        December 31, 2006 and 2005, there were no significant deferred income tax
        assets
        or liabilities.
 
 67
 
 **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;
        therefore, estimated fair value is based on quoted market prices at December
        31,
        2006 and 2005.
 
 The
        carrying amount and estimated fair values of the Partnership’s financial
        instruments as of December 31, 2006 and 2005 were as follows (in thousands):
 
 **2006**
              
              **2005****Financial
                  Assets**
              
              **Carrying
                  Amount**
              
              **Fair
                  Value**
              
              **Carrying
                  Amount**
              
              **Fair
                  Value**Cash
                  and cash equivalents
              
              $ 399,032
              
              $ 399,032
              
              $ 65,792
              
              $ 65,792**Financial
                  Liabilities**Long-term
                  debt
              
              $ 1,350,920
              
              $ 1,318,293
              
              $ 1,101,290
              
              $ 1,090,854
   68
  **Note
        13: Accumulated Other Comprehensive Income (Loss)**
 
 The
        following table shows the components of Accumulated other comprehensive income
        (loss), net of tax which is included in Partners’ Capital on the Consolidated
        Balance Sheets (in thousands):
 
 **For
                  the Year Ended December 31,****2006**
              
              **2005**Gain
                  (loss) on cash flow hedges, net of tax
              
              $
              8,309
              
              $
              (174
              )Adjustment
                  to initially apply SFAS No. 158, net of tax
              
              
              14,803
              
              
              -Total
                  Accumulated other comprehensive income (loss), net of tax
              
              $
              23,112
              
              $
              (174
              )
 
 **Note
        14: Major Customers and Transactions with Affiliates** ****
 
 *Major
        Customers*
 
 Operating
        revenues received from major customers (in thousands) and their percentage
        of
        Operating Revenues were:
 
 **For
                  the Year Ended December 31,****2006**
              
              **2005**
              
              **2004****Customer**
              
              **Revenue**
              
              **%**
              
              **Revenue**
              
              **%**
              
              **Revenue**
              
              **%**ProLiance
                  Energy, LLC
              
              $ 55,129
              
              9.1%
              
              $ 51,168
              
              9.1%
              
              $ 56,742
              
              21.5%Atmos
                  Energy
              
              56,413
              
              9.3%
              
              61,774
              
              11.0%
              
              28,569
              
              10.8%
 
 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, 2006, the amount of gas loaned by the operating subsidiaries
        was
        approximately 15.1 TBtu and, assuming an average market price during December
        2006 of $6.81 per million British thermal units (MMBtu), the market value
        of
        that gas was approximately $102.8 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.
 
 *Related
        Parties*
 
 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 $13.0 million, $9.7 million, and $6.9
        million for the years ended December 31, 2006, 2005 and 2004 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 and 2% general
        partner interest held by Boardwalk GP were $116.6 million during
        2006.
 
 69
 
 **Note
        15: Recently Issued Accounting Pronouncements** ****
 
 *Staff
        Accounting Bulletin (SAB) No. 108*
 
 In
        September of 2006, the Securities and Exchange Commission (SEC) issued SAB
        No.
        108, *Considering
        the Effects of Prior Year Misstatements when Quantifying Misstatements in
        Current Year Financial Statements.* This
        bulletin summarizes the SEC staff’s views regarding the process of quantifying
        financial statement misstatements. SAB No. 108 was effective for reporting
        periods ending after November 15, 2006. The Partnership has recognized no
        adjustments to its Consolidated Financial Statements as a result of the
        application of SAB No. 108.
 
 
 *SFAS
        No. 158*
 
 In
        September 2006, the FASB issued SFAS No. 158, which requires that an employer
        with a single-employer defined benefit plan:
 (a)
            recognize
                the funded status of a benefit plan in its statement of financial
                position, (b)
            recognize
                as a component of other comprehensive income, net of tax, the gains
                or
                losses and prior service cost or credits that arise during the period
                but
                are not recognized as components of net periodic benefit cost, (c)
            measure
                defined benefit plan assets and obligations as of the date of the
                employer’s fiscal year-end statement of financial position, and (d)
            disclose
                in the notes to the financial statements additional information about
                certain effects on net periodic benefit cost for the next fiscal
                year that
                arise from delayed recognition of gains or losses, prior service
                cost or
                credits, and transition asset or obligation. 
 Entities
        with publicly traded equity securities were required to adopt SFAS No. 158
        for
        fiscal years ending after December 15, 2006. Gains or losses, prior service
        costs or credits, and transition assets or obligations that had not yet been
        included in net periodic benefit cost as of the end of the fiscal year in
        which
        SFAS No. 158 is initially applied are recognized as components of the ending
        balance of accumulated other comprehensive income (AOCI), net of tax. The
        Partnership began applying the provisions of SFAS No. 158 for its year ended
        December 31, 2006.
 
 In
        accordance with SFAS No. 71, certain costs and benefits of a regulated entity
        are recorded as regulatory assets and liabilities based on expected recovery
        from customers or refund to customers in future periods. In the application
        of
        SFAS No. 158, the Partnership made a determination regarding whether any
        of the
        amounts required to be recorded to AOCI should instead be recorded as regulatory
        assets or liabilities as amounts that will be recoverable from or refundable
        to
        customers in future periods. With regard to previously unrecognized actuarial
        losses related to the pension plan, a determination was made that treatment
        as a
        regulatory asset was not appropriate as the recoverability of such amounts
        in
        future rates was not deemed probable. For PBOP, a portion of the amount that
        would otherwise have been recorded in AOCI was instead recorded as a reduction
        of the regulatory asset to the extent that the plan was overfunded. The
        regulatory asset for PBOP will continue to be amortized in accordance with
        the
        rate case settlement.
 
  The
        following tables present the incremental effect of applying SFAS No. 158
        on
        individual line items in the Consolidated Balance Sheets for both the retirement
        plans and PBOP (in
        thousands):
 
 **Retirement
                  Plans****Before
                  Application of SFAS No. 158**
              
              **Adjustments**
              
              **After
                  Application of SFAS No. 158**Other
                  Assets - Costs recoverable from customers
              
              $
                  7,820
              
              -
              
              $
                  7,820Other
                  Assets - Other
              
              3,561
              
              $
                  (3,561)
              
              -Total
                  Assets
              
              $
                  11,381
              
              $
                  (3,561)
              
              $
                  7,820Other
                  Liabilities and Deferred Credits - Other
              
              1,282
              
              14,479
              
              15,761AOCI
                  (Loss)
              
              -
              
              (18,040)
              
              (18,040)Total
                  Liabilities and Partners’ Capital
              
              $
                  1,282
              
              $
                  (3,561)
              
              $
                  (2,279)
 
 **PBOP****Before
                    Application of SFAS No. 158**
                
                **Adjustments**
                
                **After
                    Application of SFAS No. 158**Current
                    Assets - Costs recoverable from customers
                
                $ 5,415
                
                -
                
                $ 5,415Other
                    Assets - Costs recoverable from customers
                
                20,692
                
                $
                    (15, 538)
                
                5,154Other
                    Assets - Other
                
                -
                
                14,877
                
                14,877Total
                    Assets
                
                $
                    26,107
                
                $
                    (661)
                
                $ 25,446Pension
                    and postretirement benefits
                
                $
                    33,551
                
                $
                    (33,551)
                
                -AOCI
                    Gain
                
                -
                
                32,890
                
                $ 32,890Total
                    Liabilities and Partners’ Capital
                
                $
                    33,551
                
                $ (661)
                
                $ 32,890
 
 *SFAS
        No. 157*
 
 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.
 
 70
  **Note
        16: Supplemental Disclosure of Cash Flow Information** **** (in
        thousands):
 
 **For
                  the Year Ended December 31,****2006**
              
              **2005**
              
              **2004**Cash
                  paid during the period for:Interest
                  (net of amount capitalized)
              
              $
              58,111
              
              $
              45,357
              
              $
              28,847Income
                  taxes, net
              
              
              215
              
              
              -
              
              
              -Non-cash
                  capital contribution
              
              
              -
              
              
              681,809
              
              
              -Non-cash
                  dividends
              
              
              -
              
              
              101,401
              
              
              -
 
  71
  **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 2006 and 2005 for
        the
        Partnership (in thousands):
 
 **2006**
                **For
                  the Quarter Ended:**December
                  31
              
              September
                  30
              
              June
                  30
              
              March
                  31Operating
                  revenues
              
              $
                  171,489
              
              $
                  133,045
              
              $
                  128,662
              
              $
                  174,446Operating
                  expenses
              
              92,811
              
              88,272
              
              82,798
              
              89,813Operating
                  income
              
              78,678
              
              44,773
              
              45,864
              
              84,633Interest
                  expense, net
              
              13,348
              
              14,424
              
              14,517
              
              15,632Other
                  expense (income)
              
              168
              
              (416)
              
              (799)
              
              (729)Income
                  before income taxes
              
              65,162
              
              30,765
              
              32,146
              
              69,730Charge-in-lieu
                  of income taxes
              
              (111)
              
              118
              
              246
              
              -Net
                  income
              
              $ 65,273
              
              $
                  30,647
              
              $
                  31,900
              
              $ 69,730
 
 **2005**
                **For
                  the Quarter Ended:**December
                  31
              
              September
                  30
              
              June
                  30
              
              March
                  31Operating
                  revenues
              
              $
                  170,905
              
              $
                  120,916
              
              $
                  118,263
              
              $
                  150,382Operating
                  expenses
              
              89,378
              
              99,898
              
              81,910
              
              73,800Operating
                  income
              
              81,527
              
              21,018
              
              36,353
              
              76,582Interest
                  expense, net
              
              14,964
              
              14,632
              
              14,482
              
              14,511Other
                  income
              
              722
              
              1,215
              
              922
              
              771Income
                  before income taxes
              
              67,285
              
              7,601
              
              22,793
              
              62,842Charge-in-lieu
                  of income taxes
              
              22,476
              
              3,047
              
              9,088
              
              24,985Net
                  income
              
              $ 44,809
              
              $
                  4,554
              
              $
                  13,705
              
              $
                  37,857
 
 
 **Note
        18: 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 loans to the Partnership and have no restricted assets
        at
        December 31, 2006. See Note 7 for additional information.
 
 
  72
  **Item
        9****.
        Changes in and Disagreements with Accountants on Accounting and Financial
        Disclosure**
 
 None.
 
 **Item
        9A. Controls and Procedures**
 
 We
        maintain a system of disclosure controls and procedures which are designed
        to
        ensure that information required to be disclosed in reports filed or submitted
        under the federal securities laws, including this report, is recorded,
        processed, summarized and reported on a timely basis. These disclosure controls
        and procedures are designed to ensure that information required to be disclosed
        under the federal securities laws is accumulated and communicated to management
        on a timely basis to allow assessment of required disclosures.
 
 Our
        principal executive officer and principal financial officer have conducted
        an
        evaluation of the disclosure controls and procedures as of the end of the
        period
        covered by this report. Based on this evaluation, the principal executive
        officer and principal financial officer have each concluded that the disclosure
        controls and procedures are effective for their intended purpose.
 
 There
        was
        no change in our internal control over financial reporting identified in
        connection with the foregoing evaluation that occurred during the fourth
        quarter
        2006 that has materially affected, or is reasonably likely to materially
        affect,
        our internal control over financial reporting.
 
 *Management’s
        Annual Report on Internal Control over Financial Reporting*
 
 Our
        management is responsible for establishing and maintaining adequate internal
        control over financial reporting, as defined by the Securities Exchange Act
        of
        1934, as amended. Our internal control over financial reporting is designed
        to
        provide reasonable assurance regarding the reliability of financial reporting
        and the preparation of financial statements for external purposes in accordance
        with generally accepted accounting principles. It consists of policies and
        procedures that:
 
 ·
            Pertain
                to the maintenance of records that, in reasonable detail, accurately
                and
                fairly reflect the transactions and dispositions of our
                assets; 
 ·
            Provide
                reasonable assurance that transactions are recorded as necessary
                to permit
                preparation of the financial statements in accordance with generally
                accepted accounting principles, and that our receipts and expenditures
                are
                being made only in accordance with authorizations of our management
                and
                directors; and 
 ·
            Provide
                reasonable assurance regarding prevention or timely detection of
                unauthorized acquisition, use or disposition of our assets that could
                have
                a material effect on the financial
                statements. 
 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
        controls can provide no more than reasonable assurance with respect to the
        fair
        presentation of financial statements and the processes under which they were
        prepared.
 
 Under
        the
        supervision and with the participation of management, including the Chief
        Executive Officer (CEO) and Chief Financial Officer (CFO), we made an assessment
        of the effectiveness of our internal control over financial reporting as
        of
        December 31, 2006. In making this assessment, we used the criteria established
        in Internal Control — Integrated Framework issued by the Committee of Sponsoring
        Organizations of the Treadway Commission (COSO). Based on our evaluation,
        we
        concluded that our internal control over financial reporting was effective
        as of
        December 31, 2006. Our assessment of the effectiveness of our internal control
        over financial reporting as of December 31, 2006 has been audited by Deloitte
        & Touche LLP, an independent registered public accounting firm, as stated in
        their report included in Item 8.
 
 
 **Item
        9B. Other Information**
 
 None.
  73
  **PART
        III******
 
 
 **Item
        10. Directors and Executive Officers of the
        Registrant**
 
 
 **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.
 
 74
 
 **Directors
        and Executive Officers**
  The
        following table shows information for the directors and executive officers
        of
        BGL:
 **Name**
              
              **Age**
              
              **Position**Rolf
                  A. Gafvert
              
              53
              
              Chief
                  Executive Officer and DirectorH.
                  Dean Jones II
              
              54
              
              President
                  and DirectorJamie
                  L. Buskill
              
              42
              
              Chief
                  Financial OfficerArthur
                  L. Rebell
              
              66
              
              Director,
                  Chairman of the BoardWilliam
                  R. Cordes
              
              58
              
              DirectorThomas
                  E. Hyland
              
              61
              
              DirectorJonathan
                  E. Nathanson
              
              45
              
              DirectorMark
                  L. Shapiro
              
              62
              
              DirectorAndrew
                  H. Tisch
              
              57
              
              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.
        Prior
        thereto he had been the Co-President of BGL since its inception in 2005.
        Mr.
        Gafvert has been the President of Gulf South since 2000 and has been employed
        by
        Gulf South or its predecessors since 1993. During that time he also served
        in
        various management roles for affiliates of Gulf South, including President
        of
        Koch Power, Inc., Managing Director of Koch Energy International and Vice
        President of Corporate Development for Koch Energy, Inc. Mr. Gafvert is also
        on
        the Board of Directors of the Interstate Natural Gas Association of America
        and
        the Southern Gas Association.
  **H.
        Dean Jones II** —Mr.
        Jones has been the President of BGL since its inception in 2005. Mr. Jones
        is
        also the President of Texas Gas Transmission. He 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 1980, including as Vice President, Commercial Operations
        of
        Texas Gas from November 2002 until May 2003, Vice President, Customer Service
        of
        Williams Gas Pipelines Eastern Region in 2002 and Vice President, Customer
        Services and Rates of Williams Gas Pipelines South Central from 2000 until
        2002.
        Mr. Jones is also on the Board of Directors of the Interstate Natural Gas
        Association of America, the Southern Gas Association and Corporate TeleLink
        Network.
 
 
 **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 Transmission. 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.
  **Arthur
        L. Rebell** —Mr.
        Rebell is a Senior Vice President at Loews Corporation. 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, a subsidiary
        of Loews.
  **William
        R. Cordes** —Mr.
        Cordes has been President of Northern Border Pipeline Company since April
        2006.
        He has 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.
 
 **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 Corporation. 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 Corporation since January
        2006
        and is the Chairman of the Executive Committee and a member of the Office
        of the
        President of Loews Corporation. He has served as a director of Loews Corporation
        since 1985. Mr. Tisch also serves as a director of CNA Financial Corporation,
        a
        subsidiary of Loews.
 
 
 75
  **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 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 co-principal executive officers, 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% 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 2006, in a timely manner.
 
 76
  **Item
        11. Executive Compensation**
 
 **Compensation
        Discussion and Analysis**
 
 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
        considered 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 of our Named Executive Officers is
        reviewed with and is subject to the approval of our entire Board, with Messrs.
        Gafvert and Jones not participating in those discussions with respect to
        their
        own compensation. Named Executive Officers are those officers whose compensation
        is required to be reported accordance with Item 402, *Executive
        Compensation* ,
        of SEC
        Regulation S-K rules.
 
 The
        principal components of compensation for our Named Executive Officers are:
  ·
            base
                salary;  ·
            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, the primary factor 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 also review and consider
        compensation levels and types in other companies that are engaged in similar
        businesses. Based on these factors, we determine an overall level of
        compensation.
 
 77
  *Base
        Salary*
  Since
        the
        completion of our IPO in November 2005, our executive compensation policies
        have
        emphasized the incentive based compensation elements discussed below. As
        a
        result, the base salaries of our executive officers generally remained unchanged
        through the end of 2006, with modest adjustments made from year to year in
        some
        cases. 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.
 
 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% on
        the
        second anniversary of the grant date and 50% on the third anniversary of
        the
        grant date, and become payable in cash upon vesting. Since the value of the
        Phantom Common Units is tied directly to the price of our common units, and
        the
        amount of distributions made on those units during the vesting period, this
        element of compensation directly aligns the interests of our 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 2006 and increased our
        distributions to unitholders in each quarter. As a result, we paid out the
        full
        amount of incentive compensation we had targeted for 2006 to our key employees
        including the Named Executive Officers, of which approximately 75% was paid
        as
        annual cash bonuses and 25% 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 2006 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 from our general partner 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 equity
        holders.
 
 We
        awarded an aggregate of 125 Phantom GP Units in December 2006, which vest
        in 4.0
        years, to 13 of our key employees, of which 50 were awarded to our Named
        Executive Officers. In July 2006, in connection with our adoption of our
        Strategic Long Term Incentive Plan our Board awarded 125 Phantom GP Units,
        which
        vest in 3.5 years to 13 of our key employees as compensation for their
        performance in 2005, of which 52 were awarded to our Named Executive Officers.
        Consistent with the 2006 awards of incentive compensation discussed above,
        in
making these awards, our Board considered each grantee’s overall performance,
        with particular emphasis on the contributions made by the individual executive
        to our expansion projects, among other strategic goals and
        objectives.
 
 *Employee
        Benefits*
 
 Each
        Named Executive Officer participates in benefit programs available generally
        to
        salaried employees of the operating subsidiary which employs such officer,
        including health and welfare benefits and a qualified defined contribution
        401(k) plan that includes a dollar-for-dollar match on elective deferrals
        of up
        to 6% of eligible compensation within Internal Revenue Code (IRC) requirements.
        Mr. Gafvert participates in a defined contribution money purchase plan available
        to employees of Gulf South. Messrs. Jones and Buskill 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. Messrs. Jones and Buskill 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.
 
 78
   ***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*
 *H.
        Dean Jones II*
 *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 Messrs. Gafvert and
          Jones, have been or are officers or employees of us or our
          subsidiaries.  Messrs. Gafvert and Jones participate in deliberations of
          our Board with regard to executive compensation generally, but do not
          participate in deliberations or Board actions with respect to their 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
          2006.
 79
  ***Summary
        of Executive Compensation***
 
 The
        following table shows a summary of total compensation earned by our Named
        Executive Officers during 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
              2006
              $
                  240,000
              $300,000
              $112,944
              -
              $183,442
              -
              $
                  32,149 (4)
              $
                  868,535Chief
                  Executive Officer and DirectorH.
                  Dean Jones II
              2006
              325,000
              195,000
              59,778
              -
              110,065
              154,458
                  (5)
              24,432
                  (5)
              868,733President
                  and DirectorJamie
                  L. Buskill
              2006
              225,000
              100,000
              26,196
              -
              87,011
              40,333
                  (6)
              14,292
                  (6)
              492,832Chief
                  Financial Officer
  (1)
            Reflects
                cash amounts paid in 2007 to the Named Executive Officers for services
                performed by them during 2006.  (2)
            Represents
                compensation expense accrued for 2006 related to Phantom Common Units
                granted in 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 2006 related to Phantom GP Units
        granted in 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 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
                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 includes
                the
                change in qualified retirement plan account balance ($60,562), interest
                and pay credits for the supplemental retirement plan ($83,935) and
                excess
                nonqualified deferred compensation plan earnings
                ($9,961).  (6)
            Includes
                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 includes
                the
                change in qualified retirement plan account balance ($28,675) and
                interest
                and pay credits for the supplemental retirement plan
                ($11,658). 
 
 80
  ***Grants
        of Plan-Based Awards***
 
 The
        following table displays information regarding grants during 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****Name**
              **Grant
                  Date**
                **(2006)**
              **Estimated
                  future payouts under**
                **non-equity
                  incentive plan awards (1)**
              **Estimated
                  future payouts under equity incentive plan awards**
              **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)****Thres-hold
                  ($)**
              **Target**
                **($)**
              **Maximum
                  ($)**
              **Threshold
                  (#)**
              **Target
                  (#)**
              **Maximum
                  (#)**Rolf
                  Gafvert
              12/20
              -
              -
              1,250,000
              -
              -
              -
              6,427
              -
              -
              200,0007/24
              -
              -
              1,250,000
              -
              -
              -
              -
              -
              -H.
                  Dean Jones II
              12/20
              -
              -
              750,000
              -
              -
              -
              2,571
              -
              -
              80,0007/24
              -
              -
              750,000
              -
              -
              -
              -
              -
              -Jamie
                  Buskill
              12/20
              -
              -
              500,000
              -
              -
              -
              1,205
              -
              -
              37,5007/24
              -
              -
              600,000
              -
              -
              -
              -
              -
              -
 
 (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. Concurrent with the approval of the Plan, Messrs.
                Gafvert, Jones and Buskill were awarded 25, 15 and 12 Phantom GP
                Units,
                that have a 3.5 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. 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 July 24, 2006 grants and the December 20, 2006 grants were $27,422
                and
                $50,000, respectively, per GP Phantom Unit. The fair value of the
                awards
                will be recognized ratably over the vesting period. As of December
                31,
                2006 the remeasured fair value of each of the July 24, 2006 grants
                was
                $47,718 and the fair value of each of the December 20, 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
                was
                $31.12. Each such grant includes a tandem grant of Distribution Equivalent
                Rights (DERs); vests 50% on the second anniversary of the grant date
                and
                50% on the third anniversary of the grant date; and will be payable
                to the
                grantee in cash upon vesting in an amount equal to the sum of the
                fair
                market value of the units (as defined in the plan) that vest on the
                vesting date plus the vested amount then credited to the grantee’s DER
                account, less applicable taxes. Note 9 in Item 8 of this Report contains
                more information regarding our LTIP. 
 
 81
  ***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, 2006:
 
 **Outstanding
                  Equity Awards at Fiscal Year End****Option
                  Awards**
              **Stock
                  Awards****Name**
              **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
                  Gafvert
              -
              -
              -
              -
              -
              14,457
              456,155
              -
              -H.Dean
                  Jones II
              -
              -
              -
              -
              -
              6,854
              216,888
              -
              -Jamie
                  Buskill
              -
              -
              -
              -
              -
              3,079
              97,366
              -
              -
 
 (1)
            On
                December 15, 2005, Phantom Common Units were awarded 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. 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.  (2)
            The
                market value per share reported in the above table is based on the
                NYSE
                last sale price on 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 and
                Buskill were $10,590, $5,648 and $2,471. 
 
 ***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. As of December 31, 2006, none of the awards
        issued
        to our Named Executive Officers have vested. We have not issued any awards
        in
        the form of options on our units to any employees including Named Executive
        Officers.
 
 
 82
  ***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**
              **Plan
                  Name**
              **Number
                  of Years Credited Service (#)**
              **Present
                  Value of Accumulated Benefit**
                **($)**
              **Payments
                  During 2006**
                **($)**H.
                  Dean Jones II
              TGRP
              26.1
              $470,863
              -SRP
              26.1
              576,311
              -Jamie
                  Buskill
              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% age 40 through 49 and 10%
        age
        50 and older. Additional credit rates on annual pay above Social Security
        Wage
        Base is 1%, 2%, 3% and 5% 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 retirees
        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, 2006, neither
        Mr.
        Jones nor Mr. Buskill are 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
        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
        Name Executive Officer, is determined using assumptions consistent with the
        assumptions used for financial reporting. Interest is credited, to the cash
        balance at December 31, 2006, commencing in the year 2007 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, 2006 were 4.85%
        for 2006 and 4.25% for future years. Credited interest rates at December
        31,
        2005 were 4.47% and 4.125% for future years. The future normal retirement
        date
        accumulated cash balance is then discounted using an interest rate at December
        31, 2006 of 5.75% (5.625% at December 31, 2005). The December 31, 2005, present
        value of accumulated benefits for Messers. Jones and Buskill were $410,301
        and
        $113,974. 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 December 31, 2005 present value of accumulated benefits
        under
        the SRP for Messers. Jones and Buskill were $492,376 and $7,221. 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.
 
 83
  ***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**
              **Executive
                  Contributions in 2006**
                **($)**
              **Registrant
                  Contributions in 2006**
                **($)**
              **Aggregate
                  Earnings in 2006**
                **($)**
              **Aggregate
                  Withdrawals/ Distributions during 2006**
                **($)**
              **Aggregate
                  Balance at December 31, 2006**
                **($)**H.
                  Dean Jones II
              -
              -
              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%, compounded monthly.
                Aggregate earnings in 2006 includes $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 February 15, 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 $35.40, 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, $1,000 for each Board meeting attended which
        is
        not a regularly scheduled meeting, and an annual grant of 500 of our common
        units. Directors who are officers or employees of us, our subsidiaries, our
        general partner or an affiliate of our general partner do not receive the
        compensation described above. All directors are reimbursed for out-of-pocket
        expenses they incur in connection with attending Board and committee meetings
        and will be fully indemnified by us for actions associated with being a director
        to the extent permitted under Delaware law. The following table displays
        information related to director compensation:
 **Name**
              **Fees
                  Earned or Paid in Cash**
                **($)
                  (1)**
              **Stock
                  Awards**
                **($)
                  (4)**
              **Option
                  Awards ($)**
              **Non-Equity
                  Incentive Plan Compensation ($)**
              **Change
                  in Pension Value and Nonqualified Deferred Compensation
                  Earnings**
              **All
                  Other Compensation including perquisites**
                **($)**
              **Total**
                **($)**William
                  R. Cordes
              8,750 (2)
              -
              -
              -
              -
              -
              8,750Thomas
                  E. Hyland
              60,667 (3)
              10,800
              -
              -
              -
              -
              71,467Mark
                  L. Shapiro
              54,833
              10,800
              -
              -
              -
              -
              65,633
  (1)
        Represents amounts paid in cash for 2006.
 (2)
        Mr.
        Cordes commenced serving on the Board in the fourth quarter 2006.
 (3)
        Chairman of Audit Committee.
 (4)
        On
        March 24, 2006, Messrs. Hyland and Shapiro were each granted 500 common
        units.
 The
        closing sales price on the NYSE on March 24, 2006 was $21.60 per
        unit.
 
 84
  **Item
        12. Security Ownership of Certain Beneficial Owners and
        Management**
 
 The
        following table sets forth certain information, at February 9, 2007, as to
        the
        beneficial ownership of our common and subordinated units by beneficial holders
        of 5% or more of either such class of units, each member of our Board, each
        of
        the Named Executive Officers and all of our executive officers and directors
        as
        a group, based on data furnished by them:
 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 OwnedJamie
                    L. Buskill
                
                -
                
                -
                
                -
                
                -
                
                -William
                    R. CordesRolf
                    A. Gafvert
                
                -
                
                -
                
                -
                
                -
                
                -Thomas
                    E. Hyland
                
                5,500
                
                *
                
                -
                
                -
                
                -H.
                    Dean Jones II
                
                -
                
                -
                
                -
                
                -
                
                -Jonathan
                    E. Nathanson
                
                10,000
                
                *
                
                -
                
                -
                
                -Arthur
                    L. Rebell
                
                36,583
                    (2)
                
                *
                
                -
                
                -
                
                -Mark
                    L. Shapiro
                
                10,500
                
                *
                
                -
                
                -
                
                -Andrew
                    H. Tisch
                
                18,550
                    (3)
                
                *
                
                -
                
                -
                
                -All
                    directors and executive officers as a group
                
                81,133
                
                *
                
                -
                
                -
                
                -BPHC
                    (4)
                
                53,256,122
                
                70.86%
                
                33,093,878
                
                100.00%
                
                80.17%Loews
                    Corporation (4)
                
                53,256,122
                
                70.86%
                
                33,093,878
                
                100.00%
                
                80.17%
 
 *Represents
        less than 1% of the outstanding common units
 
 (1)
            As
                of February 9, 2007, we had 75,156,122 common units and 33,093,878
                subordinated units issued and outstanding. 
 (2)
            30,583
                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 3800
                Frederica Street, Owensboro, Kentucky 42301. The address of Loews
                is 667
                Madison Avenue, New York, New York 10021. 
 **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, 2006
        with
        respect to this plan (in thousands):
 
 **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
              
              3,524,000
 
 Note
        9 in
        Item 8 of this Report contains more information regarding our equity
        compensation plan.
 
 85
  **Item
        13. Certain Relationships and Related Transactions****,
        and Director Independence**
  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% 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 threeyears,
                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 million, or 2% of
                the
                other company’s consolidated gross
                revenues. 
 Our
        Board
        has appointed an Audit Committee comprised solely of independent directors.
        The
        NYSE does not require a listed limited partnership, or a listed company that
        is
        majority-owned by another listed company, such as us, to have a majority
        of
        independent directors on its board of directors or to maintain a compensation
        or
        nominating/corporate governance committee. In reliance on these exemptions,
        our
        Board is not comprised of a majority of independent directors, nor do we
        maintain a compensation or nominating/corporate governance
        committee.
 
 
  86
  **Item
        14. Principal Accounting Fees and
        Services**
 
 
 **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 2006
        and 2005, by category as described in the notes to the table (in
        thousands):
  **2006**
              
              **2005**Audit
                  fees (1)
              
              $
              1,513
              
              $
              1,271Audit
                  related fees (2)
              
              
              553
              
              
              990Tax
                  fees (3)
              
              
              2
              
              
              6Total
              
              $
              2,068
              
              $
              2,267
 
 (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,
                accounting consultations, Sarbanes-Oxley implementation, and due
                diligence
                for the GS-Acquisition and other potential
                acquisitions. 
 (3)
            Includes
                the aggregate fees and expenses for tax compliance and tax planning
                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. Prior to November 2005, the
        Audit Committee of Loews served as the audit committee of our predecessor
        and
        its subsidiaries and pre-approved all engagements by our predecessor and
        its
        subsidiaries during 2005, including the terms and fees thereof, and the Loews
        Audit Committee concluded that all such engagements were compatible with
        the
        continued independence of Deloitte & Touche in serving as the independent
        auditor of such companies.
  87
  **PART
        IV**
 
 
 **Item
        15. Exhibits, Financial Statement
        Schedules**
  
 **(a)
        1. Financial Statements**
 
 Included
        in Item 8 of this report:
 
 Reports
        of Independent Registered Public Accounting Firm
 
 Consolidated
        Balance Sheets at December 31, 2006 and 2005
 
 Consolidated
        Statements of Income for the years ended December 31, 2006 and 2005 and 2004
 
 Consolidated
        Statements of Cash Flows for the years ended December 31, 2006 and 2005 and
        2004
 
 Consolidated
        Statements of Changes in Member’s Equity and Partners’ Capital for the years
        ended December 31, 2006  and
        2005
        and 2004
 
 Consolidated
        Statements of Comprehensive Income for the years ended December 31, 2006
        and
        2005 and 2004
 
 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,
        2006, 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:2006
              
              $
              730
              
              $
              2,053
              
              
              -
              
              $
              173
              
              $
              2,6102005
              
              
              174
              
              
              745
              
              $
              (187
              )
              
              2
              
              
              7302004
              
              
              203
              
              
              -
              
              
              -
              
              
              29
              
              
              174Inventory
                  obsolescence:2006
              
              
              -
              
              
              33
              
              
              -
              
              
              -
              
              
              332005
              
              
              201
              
              
              -
              
              
              11
              
              
              212
              
              
              -2004
              
              
              630
              
              
              -
              
              
              16
              
              
              445
              
              
              201
 
 
 88
  **(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
              
              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).10.3
              
              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).10.4
              
              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).
 
 10.5
              
              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).10.6
              
              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).10.7
              
              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).10.8
              
              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).10.9
              
              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)10.10
              
              Boardwalk
                  Pipeline Partners 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).10.11
              
              Form
                  of Phantom Unit Award Agreement under the Boardwalk Pipeline Partners
                  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).10.12
              
              Boardwalk
                  Pipeline Partners 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).10.13
              
              Form
                  of GP Phantom Unit Award Agreement under the Boardwalk Pipeline
                  Partners
                  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).10.14
              
              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.*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
              
              Certifications
                  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.
  89
  **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, LPits
                  general partnerBy:
                  Boardwalk GP, LLCits
                  general partnerDated:
                  February 23, 2007
              
              
              By:
              */s/
                  Jamie L. Buskill*Jamie
                  L. BuskillChief
                  Financial Officer
 
  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 23, 2007
              */s/
                  Rolf A. Gafvert***Rolf
                  A. Gafvert
              Chief
                  Executive Officer and Director
                (principal
                  executive officer)Dated:
                  February 23, 2007
              */s/
                  H. Dean Jones II***H.
                  Dean Jones II
              President
                  and DirectorDated:
                  February 23, 2007
              */s/
                  Jamie L. Buskill***Jamie
                  L. Buskill
              Chief
                  Financial Officer
                (principal
                  financial officer)Dated:
                  February 23, 2007
              */s/
                  Steven A. Barkauskas*Steven
                  A. Barkauskas
              Vice
                  President and Corporate Controller
                (principal
                  accounting officer)Dated:
                  February 23, 2007
              */s/
                  William R. Cordes*William
                  R. Cordes
              DirectorDated:
                  February 23, 2007
              */s/
                  Thomas E. Hyland***Thomas
                  E. Hyland
              DirectorDated:
                  February 23, 2007
              */s/
                  Jonathon E. Nathanson*Jonathon
                  E. Nathanson
              DirectorDated:
                  February 23, 2007
              */s/
                  Arthur L. Rebell***Arthur
                  L. Rebell
              DirectorDated:
                  February 23, 2007
              */s/
                  Mark L. Shapiro***Mark
                  L. Shapiro
              DirectorDated:
                  February 23, 2007
              */s/
                  Andrew H. Tisch***Andrew
                  H. Tisch
              Director
 
  90