**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, 2005**





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 o No x





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. o





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 filero
            Accelerated
                filer ̈
            Non-accelerated
                filerx





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 December 30, 2005 was approximately $268,360,000. As of
      March 1, 2006, the registrant had 68,256,122 common units outstanding.





Documents
      incorporated by reference. None.











**TABLE
      OF CONTENTS**





**2005
      FORM 10-K**





**BOARDWALK
      PIPELINE PARTNERS, LP**





PART
                IITEM
                1.  BUSINESS.ITEM
                1A.  RISK FACTORS.ITEM
                1B.  UNRESOLVED STAFF
                COMMENTS.ITEM
                2.  PROPERTIESITEM
                3.  LEGAL PROCEEDINGS.ITEM
                4.  SUBMISSION OF MATTERS TO A VOTE OF
                SECURITY HOLDERS.PART
                IIITEM
                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.*Overview**Recent
                Expansion Projects**Trends
                and Uncertainties**Critical
                Accounting Policies and Estimates**Financial
                Analysis of Operations**Liquidity
                and Capital Resources**Forward-Looking
                Statements*ITEM
                7A.  QUANTITATIVE AND QUALITATIVE
                DISCLOSURES ABOUT MARKET RISK.ITEM
                8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY
                DATA.*Note
                1:**Corporate
                Structure**Note
                2:**Accounting
                Policies**Note
                3: Commitments and
                Contingencies**Note
                4:**Financing**Note
                5:**Employee
                Benefits**Note
                6:**Income
                Tax**Note
                7:**Financial
                Instruments**Note
                8:**Major
                Customers and Transactions with Affiliates**Note
                9:**Recent
                Accounting Pronouncements**Note
                10:**Supplemental
                Disclosure of Cash Flow Information**Note
                11:**Selected
                Quarterly Financial Data (Unaudited)*ITEM
                9.  CHANGES IN AND DISAGREEMENTS WITH
                ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.ITEM
                9A.  CONTROLS AND
                PROCEDURES.ITEM
                9B.  OTHER
                INFORMATION.PART
                IIIITEM
                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
                IVITEM
                15.  EXHIBITS, FINANCIAL STATEMENT
                SCHEDULES.











**PART
      I**








**Item
      1.****Business****.**








**General
      Development of Our Business**





We
      are a
      Delaware limited partnership formed in 2005 to own and operate the business
      conducted by Boardwalk Pipelines, LP and its subsidiaries, Texas Gas
      Transmission, LLC and Gulf South Pipeline Company, LP. The ownership of each
      of
      these entities is described in the chart presented under “Organizational Chart.”
Throughout this report, we use the terms set forth below.







•
            “BGL”
                refers to Boardwalk GP, LLC, the general partner of Boardwalk GP;




•
            “Boardwalk
                GP” refers to Boardwalk GP, LP, the general partner of Boardwalk Pipeline
                Partners, LP;




•
            “Boardwalk
                Pipelines” refers to Boardwalk Pipelines, LP (formerly Boardwalk
                Pipelines, LLC);




•
            “BPHC”
                refers to Boardwalk Pipelines Holding
                Corp;




•
            “Gulf
                South” refers to Gulf South Pipeline Company,
                LP;




•
            “Loews”
                refers to Loews Corporation;




•
            “our
                general partner” refers collectively to Boardwalk GP and
                BGL;




•
            “Texas
                Gas” refers to Texas Gas Transmission, LLC; and




•
            the
                “Partnership,” “we,” “us,” “our” and like terms refer to Boardwalk
                Pipeline Partners, LP, collectively with our subsidiaries unless
                the
                context indicates otherwise.








**Completion
      of Our Initial Public Offering of Common Units and Related
      Transactions**





On
      November 15, 2005, we sold 15 million common units in an underwritten
      initial public offering (IPO), the net proceeds of which were approximately
      $271.4 million. We used the net proceeds from our IPO to repay $250.0 million
      of
      indebtedness to Loews, and provide $21.4 million of additional working capital
      to our subsidiaries. The common units sold in our IPO represent approximately
      14.5% of the 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 our IPO, are held by BPHC. Boardwalk GP
      holds our 2% general partner interest and all of our incentive distribution
      rights. In connection with the consummation of our IPO, we and our affiliates
      effected a number of additional transactions, which are described in Item 13,
      “Certain Relationships and Related Transactions-Transactions Consummated in
      Connection with the Completion of our IPO.”




In
      addition, in connection with the closing of our IPO, Boardwalk Pipelines entered
      into a five-year $200 million revolving credit facility. Boardwalk Pipeline
      Partners has guaranteed the obligations of Boardwalk Pipelines under that credit
      facility. For further discussion of our credit facility, please read Item 7,
      “Management’s Discussion and Analysis of Financial Condition and Results of
      Operations."













**Organizational
      Chart**




The
      following diagram depicts our organizational structure after giving effect
      to
      our IPO and the related transactions discussed above.












**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, and
      various marketers and producers. Our transportation and storage rates are
      established by, and subject to review and revision by, the Federal Energy
      Regulatory Commission (FERC). These rates are designed to allow us the
      opportunity to recover our costs and earn a reasonable return on equity. Our
      storage rates for Gulf South are market-based pursuant to authority granted
      by
      FERC.




We
      provide a significant portion of our pipeline transportation and storage
      services under 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, 2005, approximately 63% of our
      revenues were derived from capacity reservation charges under firm contracts,
      approximately 19% of our revenues were derived from other charges based on
      actual utilization under firm contracts, and approximately 18% of our revenues
      were derived from interruptible transportation and storage services and other
      services.








***Our
      Pipeline and Storage Systems***





We
      own
      and operate two interstate natural gas pipeline systems, with approximately
      13,470 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 2005,
      our pipeline systems transported approximately 1,350 billion cubic feet (Bcf)
      of
      gas. Average daily throughput on our pipeline systems during 2005 was
      approximately 3.7 Bcf. Our natural gas storage facilities are comprised of
      eleven underground storage fields located in four states with aggregate
      certificated working gas capacity of approximately 143 Bcf. We conduct all
      of
      our natural gas transportation and storage operations through our two
      subsidiaries, Texas Gas and Gulf South, operating as one segment.








The
      following map depicts our natural gas pipeline and storage systems:

















***Our
      Texas Gas System***




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 pipelines, having a peak-day delivery capacity of
                approximately 2.8 Bcf/day;







•
            31
                compressor stations having an aggregate of approximately 531,000
                horsepower; and







•
            nine
                natural gas storage fields located in Indiana and Kentucky, having
                aggregate storage capacity of approximately 178 Bcf of gas, of which
                approximately 63 Bcf is certificated as working gas.







Texas
      Gas’ 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 requirements of its
      firm
      and interruptible storage customers and the requirements of its no-notice
      transportation service, which allows customers to temporarily draw from storage
      gas during the winter season to be repaid in-kind during the following summer
      season. Texas Gas’ storage facilities also offer summer no-notice transportation
      service, designed primarily to meet the needs of summer-season electrical power
      generation facilities. A large portion of the gas delivered by Texas Gas’ system
      is used for space heating, resulting in substantially higher daily requirements
      during winter months.








***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
                7,570 miles of pipeline, having a peak-day delivery capacity of
                approximately 3.5 Bcf/day;





•
            29
                compressor stations having an aggregate of approximately 223,000
                horsepower; and




•
            two
                natural gas storage fields located in Louisiana and Mississippi,
                having
                aggregate storage capacity of approximately 129 Bcf of gas, of which
                approximately 80 Bcf is certificated 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 the Baton Rouge—New Orleans industrial
      corridor; Lake Charles, Louisiana; Mobile, Alabama; and Pensacola, Florida.
      Gulf
      South also has indirect access to off-system markets through over 100
      interconnections with other interstate and intrastate pipelines and storage
      facilities. These pipeline interconnections provide access to major cities
      throughout the northeastern and southeastern United States.




Gulf
      South’s Bistineau, Louisiana gas storage facility has approximately 77 Bcf of
      working gas storage capacity, with a maximum injection rate of 480 million
      cubic
      feet (MMcf)/day and a maximum withdrawal rate of 870 MMcf/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 2.7 Bcf of working gas storage capacity, with a
      maximum injection rate of 100 MMcf/day and a maximum withdrawal rate of 250
      MMcf/day. The Jackson gas storage facility is used for operational purposes
      and
      its capacity is not offered for sale to the market.




Gulf
      South has received FERC approval for approximately 2.4 Bcf expansion of the
      working gas storage capacity at its Jackson storage facility, effective through
      October 2006. Gulf South will seek permanent FERC approval of this expansion.
      Gulf South has also received FERC approval to drill two new horizontal storage
      wells at its Bistineau storage facility and is implementing a company-wide
      multi-year efficiency improvement plan, which may include well work-overs and
      is
      expected to increase efficiency and late-season deliverability.











***Recent
      Expansion Projects***





*East
      Texas and Mississippi Pipeline Expansion.* In
      February and March of 2006, Gulf South entered into long-term agreements with
      customers providing firm commitments for capacity on its 1.5 Bcf per day
      pipeline expansion projects in East Texas and Mississippi. We expect the total
      cost for the 1.5 Bcf expansion to be approximately $800 million, and we expect
      the new capacity to be in-service during the second half of 2007.




The
      East
      Texas pipeline expansion will extend from Carthage in East Texas to the
      Perryville area in Richland Parish, Louisiana. Natural gas originating primarily
      from the prolific Barnett Shale and Bossier Sands producing regions of East
      Texas will be transported to interstate pipelines serving markets in the Midwest
      and Northeast, including Texas Gas, MRT, Tennessee, ANR, Columbia Gulf and
      Southern Natural. The Mississippi pipeline expansion will continue eastward
      from
      the Perryville area to the Jackson, Mississippi area and will provide additional
      supplies to customers in the Northeast and Southeast through interconnects
      with
      interstate pipelines serving those markets, including Texas Eastern, Transco,
      Southern Natural and Florida Gas, and to customers in the Baton Rouge - New
      Orleans industrial complex.





These
      projects are subject to FERC approvals. Gulf South will submit separate
      applications to FERC for authority to construct the East Texas and Mississippi
      expansion projects. In February 2006, FERC granted Gulf South's request to
      initiate the pre-filing process for the East Texas expansion.





*Western
      Kentucky Storage Expansion.* In
      November 2005, Texas Gas completed the expansion of its western Kentucky storage
      complex by approximately 8 Bcf of working gas, which allows for the additional
      withdrawal of approximately 82 MMcf/day, and contracted with customers for
      that
      new capacity at maximum rates for five years. In addition, Texas Gas has
      accepted commitments from customers for incremental no-notice service (NNS)
      and
      firm storage service that will allow it to further expand the working gas in
      this storage complex by approximately 9 Bcf, subject to FERC approval. We expect
      this second storage expansion to go into service in late 2007.





*East
      Texas Lease Arrangement.* In
      December 2005, Texas Gas initiated service under a lease arrangement which
      allowed us to tie in 100 MMcf/day of supply from the growing Barnett Shale
      production area in East Texas to the Texas Gas system at Sharon, Louisiana,
      using existing pipeline infrastructure.





*Magnolia
      Storage Facility.* Gulf
      South has leased a gas storage facility, which we refer to as the Magnolia
      facility, near Napoleonville, Louisiana, at which it has installed two
      compressor stations, with a combined horsepower of 9,470, and other storage
      infrastructure and is currently developing a high-deliverability storage cavern
      that, when operational, may add up to approximately 5 Bcf of working gas storage
      capacity. Magnolia’s storage capacity is expected to be in service and available
      for sale at market-based rates in late 2008 or early 2009, subject to the
      operational requirements of the lessor.








***Sources
      of Natural Gas Supply***




The
      principal sources of supply for our pipeline systems are regional supply hubs
      and market centers in the Gulf Coast region, including Mobile Bay, Alabama;
      offshore Louisiana; Perryville, Louisiana; the Henry Hub in Louisiana; and
      Agua
      Dulce and Carthage, Texas. The Henry Hub serves as the designated delivery
      point
      for natural gas futures contracts traded on the New York Mercantile Exchange.
      Carthage, Texas provides access to natural gas supplies from the Bossier Sands
      and Barnett Shale gas producing regions in East Texas. In addition, the Gulf
      South’s system provides access to wellhead supplies in East Texas, North and
      South 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 interconnects and to Canadian
      natural gas through a pipeline interconnect at Whitesville, Kentucky.








***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 service.
      In
      addition, we provide interruptible parking and lending services (PAL).











*Transportation
      Services* .
      We
      offer transportation service on both a firm and interruptible basis. Our
      customers choose a combination thereof, depending upon the importance of factors
      such as availability, price of service, and the volume and timing of the
      customer’s requirements. Firm transportation customers reserve a specific amount
      of pipeline capacity at certain 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. As such, firm transportation revenues typically remain
      relatively constant over the term of the contract. 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. The rates charged for transportation services are subject to
      a
      maximum tariff rate authorized by FERC, which establishes rates designed to
      provide an opportunity for us to recover costs of service, including a
      reasonable return on equity. Currently, most of our transportation services
      are
      provided at less than the current maximum applicable rates.




*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. Gulf South
      is
      authorized to charge market-based rates for their firm and interruptible storage
      services. Accordingly, unlike most other FERC-regulated pipelines, including
      Texas Gas, Gulf South’s stand-alone storage services are not subject to
      cost-based rate caps.




*NNS* .
      NNS
      consists of a combination of firm transportation and storage services that
      allow
      customers to pull gas from storage with little or no notice and requires 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 paid on the volume of gas actually transported. NNS
      provides customers with additional flexibility over traditional firm
      transportation and storage services. The Texas Gas system loans stored gas
      to
      its no-notice customers, who are obligated to repay the gas used in-kind.




*PAL
      Services* .
      PAL is
      an interruptible service offered to customers providing them the ability to
      park
      (inject) or lend (withdraw) gas into or out of our pipelines at a specific
      location for a specific period of time.







***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. Unlike most
      interstate pipelines, Gulf South does not transport natural gas solely from
      one
      supply area located at one end of its system to a consuming area located at
      the
      other end of its system. Instead, Gulf South’s customers are located throughout
      the system or, through numerous interconnections, on unaffiliated pipeline
      systems. In contrast, the Texas Gas system primarily moves gas in a
      northeasterly direction to the system’s north and northeast endpoints. Texas Gas
      customers located at these endpoints generally transport their gas to the major
      east coast metropolitan areas through interconnections with unaffiliated
      pipeline systems.




Based
      upon revenues, our customer mix as of December 31, 2005, is represented in
      the
      following percentages: LDCs (39%), pipeline interconnects (33%), storage (8%),
      industrial end-users (6%), power plants (5%) and other/miscellaneous (9%).
      We
      contract both directly with customers connected to our system and with
      marketers, producers and other third parties who provide transportation and
      storage services to our customers.




*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 three years as of December 31, 2005. We serve approximately 185
      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 approximately 85 interconnects with third-party interstate 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 are
      directly connected to industrial facilities in the Baton Rouge—New Orleans
      industrial corridor; Lake Charles, Louisiana; Mobile, Alabama; and Pensacola,
      Florida. We can also access the Houston Ship Channel through third-party
      pipelines. We can directly serve more than 150 industrial facilities. Most
      industrial facilities use a combination of firm and interruptible transportation
      services.




*Power
      Plants* .
      We
      serve a key role in providing gas supply to major electrical power generators
      in
      nine 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 firm and
      interruptible transportation services.








***Major
      Customers***




During
      2005, Atmos Energy accounted for approximately 11.0% of our total operating
      revenues. The loss of all or even a portion of the contracted volumes of this
      customer, as a result of competition, creditworthiness or otherwise, could
      have
      a material adverse effect on our financial condition, results of operations
      and
      cash flows.





***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 states of Louisiana, Texas and
      Indiana, with the new Heartland Gas Pipeline currently being constructed in
      Indiana posing a competitive threat. The principal elements of competition
      among
      pipelines are rates, terms of service, access to supply, and flexibility and
      reliability of service. In addition, FERC’s 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. Natural gas competes with other forms of energy
      available to our customers, including electricity, coal, and fuel oils. Our
      competitors attempt to attract new supply to their pipelines including those
      that are currently connected to markets served by us. As a result, we compete
      with these entities to maintain current business levels and to serve new demand
      and markets.




FERC
      has
      granted us the authority to charge market-based rates for our Gulf South firm
      and interruptible storage services. Gulf South charges market-based rates for
      the storage services provided from its Bistineau storage facility and when
      operational will charge market-based rates for storage services provided at
      its
      Magnolia storage field.








***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 revenues. Natural gas
      prices are also volatile, which in turn influences 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 2005,
      approximately 58% of our total operating revenues were realized in the first
      and
      fourth calendar quarters.














***Government
      Regulation*** **





FERC
      regulates pipelines under the Natural Gas Act of 1938 (NGA) and the Natural
      Gas
      Policy Act of 1978. FERC regulates, among other things, the rates and charges
      for the transportation and storage of natural gas in interstate commerce, 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, Texas Gas and Gulf South hold certificates of public convenience
      and
      necessity issued by FERC covering their facilities, activities, and services.
      FERC has power to prescribe accounting treatment for items for regulatory
      purposes. The books and records of Texas Gas and Gulf South may be periodically
      audited by FERC.





The
      maximum rates that may be charged by Texas Gas and Gulf South for gas
      transportation and storage services are established through the FERC rate-making
      process. Key determinants in the rate-making process are costs of providing
      service, allowed rate of return, and volume throughput assumptions. The allowed
      rate of return must be approved by FERC in each rate case. Rate design and
      the
      allocation of costs between the demand and commodity rates also impact
      profitability. Texas Gas filed a new rate case with FERC in 2005, and
      implemented new rates effective November 1, 2005, subject to refund. As of
      December 31, 2005, Texas Gas had recorded a refund liability of approximately
      $5.0 million related to the 2005 rate case. Gulf South currently has no
      obligation to file a 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. For further discussion regarding our
                environmental risk factors, please read Item 1A, "Risk
                Factors."





***Employee
      Relations***





We
      have
      approximately 1,100 employees, approximately 100 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.
      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,
      and
      savings benefits. We also have a non-contributory, defined benefit pension
      plan
      which covers substantially all the Texas Gas employees. For further discussion
      of our Employee Benefits, please read Note 5 in the Notes to Consolidated
      Financial Statements included in Item 8.








**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.











**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.







***Our
      natural gas transportation 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
      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. On April 29, 2005, Texas Gas filed a rate case. The rate
      case reflected a requested increase in annual cost of service, primarily
      attributable to increases in the utility rate base, operating expenses, and
      rate
      of return, and related taxes. The proposed rates, which were placed in effect
      on
      November 1, 2005, are subject to refund in the event lower maximum rates are
      established as a result of a settlement or hearing. We cannot make assurances
      that we will be able to recover all of our actual costs through existing or
      future rates. An adverse determination in Texas Gas’ pending rate case, or in
      any future rate proceeding of Texas Gas or Gulf South could have a material
      adverse effect on our business, financial condition, results of operations
      and
      cash flows.




In
      a
      decision last year involving an oil pipeline limited partnership, BP West Coast
      Products, LLC v. FERC, the United States Court of Appeals for the District
      of
      Columbia Circuit vacated FERC’s Lakehead policy. In its Lakehead decision, 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. In May 2005, FERC issued a statement of general policy,
      as well as an order on remand of BP West Coast. According to the policy
      statement, pipelines, including those organized as partnerships, can include
      in
      computing their cost of service a tax allowance to reflect actual or potential
      tax liability on their public utility income attributable to all entities or
      individuals owning public utility assets, if the pipeline establishes that
      the
      entities or individuals have 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 FERC on a case-by-case basis. Although the new
      policy affords pipelines that are organized as pass-through entities an
      opportunity to recover a tax allowance, FERC has not indicated what is required
      to establish such actual or potential income tax liability for all owners.
      The
      new tax allowance policy as applied to the BP West Coast decision is subject
      to
      rehearing and possible further action by the United States Court of Appeals
      for
      the District of Columbia Circuit or another court on appeal. Further,
      application of FERC’s policy statement in individual cases may be subject to
      further FERC action or review in the appropriate Court of Appeals. Therefore,
      the ultimate outcome of these proceedings is not certain and could result in
      changes to FERC’s treatment of income tax allowances in cost of service. If FERC
      were to disallow a substantial portion of Texas Gas or Gulf South’s income tax
      allowance, it is likely that the level of maximum allowed rates could decrease
      from current levels. If FERC policy is reversed or implemented in a manner
      that
      is disadvantageous to us, our general partner’s right to repurchase our
      outstanding units, as provided in our partnership agreement, may be triggered.











***Our
      natural gas transportation and storage operations are subject to extensive
      regulation by FERC in addition to FERC rules and regulations related to the
      rates we can charge for our services.***




FERC’s
      regulatory authority also extends to:




•
            operating
                terms and conditions of service;




•
            the
                types of services we may offer to our customers;




•
            construction
                of new facilities;




•
            acquisition,
                extension or abandonment of services or facilities;




•
            accounts
                and records; and




•
            relationships
                with affiliated companies involved in all aspects of the natural
                gas
                business.




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. For example, the development of uniform
      interstate gas quality standards by FERC could create two distinct markets
      for
      natural gas—an interstate market subject to uniform minimum quality standards
      and an intrastate market with no uniform minimum quality standards. Such a
      bifurcation of markets could make it difficult for our pipelines to compete
      in
      both markets or to attract certain gas supplies away from the intrastate market.
      Another example is the time 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.




FERC
      has
      authority to review pipeline contracts. If FERC determines that a term of any
      such contract deviates in a material manner from a pipeline’s tariff, FERC
      typically will order the pipeline to remove the term from the contract and
      execute and refile a new contract with FERC, or alternatively, amend its tariff
      to include the deviating term, thereby offering it to all shippers. If FERC
      audits a pipeline’s contracts and finds material deviations that appear to be
      unduly discriminatory, 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, 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 likely 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, severe winter weather and fires, and their frequency and severity
      are inherently unpredictable. For example, Hurricanes Katrina and Rita that
      struck the Gulf Coast in 2005 are unprecedented in modern times. The extent
      of
      losses from catastrophes is a function of both the total amount of insured
      exposures in the affected areas and the severity of the events
      themselves.




For
      further discussion of the impact on us of Hurricanes Katrina and Rita, please
      read Note 3 Commitments and Contingencies—Impact of Hurricanes Katrina and Rita
      in the Notes to the Consolidated Financial Statements included in Item
      8.











***We
      are subject to laws and regulations relating to the environment which may expose
      us to significant costs, liabilities and loss of revenues. Any changes in such
      regulations or their application could negatively affect our results of
      operations.***




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:




(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)
            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.





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,
      or any other government action which may have the effect of requiring or
      encouraging reduced consumption or production of natural gas, could adversely
      impact our business, financial condition, results of operations and cash
      flows.




Compliance
      with current or future environmental regulations could require significant
      expenditures and the failure to comply with current or future regulations might
      result in the imposition of fines and penalties. The steps we may be required
      to
      take to bring certain of our facilities into compliance could be prohibitively
      expensive and we may be required to shut down or alter the operation of those
      facilities, which might cause us to incur losses. Further, current rate
      structures, customer contracts and prevailing market conditions might not allow
      us to recover the additional costs incurred to comply with new environmental
      requirements and we might not be able to obtain or maintain all required
      environmental regulatory approvals for certain projects. If there is a delay
      in
      obtaining any required environmental regulatory approvals or if we fail to
      obtain and comply with them, we may be required to shut down certain facilities
      or become subject to additional costs. The costs of complying with environmental
      regulation in the future could have a material adverse effect on our business,
      financial condition, results of operations and cash flows.







***Our
      operations are subject to operational hazards and unforeseen interruptions
      for
      which we may not be adequately insured.***




There
      are
      a variety of operating risks inherent in our natural gas transportation and
      storage operations, such as leaks, explosions and mechanical problems, all
      of
      which could cause substantial financial losses. Any of these or other similar
      occurrences could result in the disruption of our operations, substantial repair
      costs, personal injury or loss of human life, significant damage to property,
      environmental pollution, impairment of our operations and substantial revenue
      losses. The location of pipelines near populated areas, including residential
      areas, commercial business centers and industrial sites, could significantly
      increase the level of damages resulting from these risks.




We
      currently possess property, business interruption and general liability
      insurance, but proceeds from such insurance coverage may not be adequate for
      all
      liabilities or expenses incurred or revenues lost. Moreover, such insurance
      may
      not be available in the future at commercially reasonable costs and terms.
      Changes in the insurance markets subsequent to the September 11, 2001, terrorist
      attacks have made it more difficult for us to obtain certain types of coverage.
      Moreover, after Hurricanes Katrina and Rita there can be no assurance that
      we
      will be able to obtain the levels or types of insurance we would otherwise
      have
      obtained prior to these market changes or that the insurance coverage we do
      obtain will not contain large deductibles or fail to cover certain hazards
      or
      cover all potential losses. The occurrence of any operating risks not fully
      covered by insurance could have a material adverse effect on our business,
      financial condition, results of operations and cash flows.











***Pipeline
      safety integrity programs and repairs may impose significant costs and
      liabilities on us.***




The
      United States DOT 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 an 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, and failure to comply with these regulations could adversely affect
      our
      financial condition.***





The
      workplaces associated with our pipelines are subject to the requirements of
      the
      Occupational Safety and Health Act (OSHA) and comparable state statutes that
      regulate the protection of the health and safety of workers. In addition, the
      OSHA hazard communication standard requires that we maintain information about
      hazardous materials used or produced in our operations and that we provide
      this
      information to employees, state and local governmental authorities and local
      residents. The failure to comply with OSHA requirements or general industry
      standards, keep adequate records or monitor occupational exposure to regulated
      substances could have a material adverse effect on our business, financial
      condition, results of operations and cash flows.







***Increased
      competition could have a significant financial impact on us.***




We
      compete primarily with other interstate and intrastate pipelines in the
      transportation and storage of natural gas. Natural gas also competes with other
      forms of energy available to our customers, including electricity, coal and
      fuel
      oils. The principal elements of competition among pipelines are rates, terms
      of
      service, access to gas supplies, flexibility and reliability. FERC’s policies
      promoting competition in gas markets are having the effect of increasing the
      gas
      transportation options for our traditional customer base. As a result, Texas
      Gas
      has begun to experience some “turnback” of firm capacity as existing
      transportation service agreements expire and are not renewed. If we are unable
      to remarket this capacity or can remarket it only at substantially discounted
      rates compared to previous contracts, Texas Gas may have to bear the costs
      associated with the turned back capacity. 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 the greater rate, 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, which
      is
      dependent on factors beyond our control. Any decrease in supplies of natural
      gas
      could adversely affect our business and operating results.***




Since
      2003, gas production from the Gulf Coast region, which supplies the majority
      of
      our throughput, has declined on average approximately 3.2% per year according
      to
      the Energy Information Administration (EIA). 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 supplies 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.




***Offtake
      capacity at 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, 2005, approximately 54% 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 and new LNG facilities proposed to be constructed along
      the East Coast.











***Successful
      development of LNG import terminals in the eastern or northeastern 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, 2005,
      approximately 28% of the firm contract load on our pipeline systems was due
      to
      expire on or before December 31, 2006. 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 or market price spread between two points on the pipeline. The
      difference in natural gas prices between the points along the pipeline where
      gas
      enters and gas is delivered represents the gross margin that a customer can
      expect to achieve from holding transportation capacity at any point in time.
      This margin and its variability become important factors in determining the
      rate
      customers are willing to pay when they renegotiate their transportation
      contracts. The basis differential between markets 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
                reduction of basis differentials across our pipeline systems;




•
            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.







***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, 2005, ProLiance Energy, LLC and Atmos Energy accounted
      for approximately 20% 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. Average natural
      gas prices have increased dramatically in recent years. This rise in gas prices
      has materially increased credit risk related to gas loaned to customers. The
      amount of gas loaned out by us over the past 24 months at any one time to our
      customers has ranged from a high of approximately 38 Bcf at April 30, 2005
      to a
      low of approximately 4 Bcf at December 31, 2005. Assuming an average market
      price during December 2005 of $12.34 per million British thermal units (MMBtu),
      the market value of gas loaned out at December 31, 2005, would have been
      approximately $49.4 million. As of February 28, 2006, the amount of gas loaned
      out was approximately 18 Bcf and, assuming an average market price during
      February 2006 of $7.30 per MMBtu, the market value of that gas would be
      approximately $131.4 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 us, this could have a material adverse effect on our financial
      condition, results of operations and cash flows.








***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/day to a major pipeline connection with 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 interruptible
      storage services. This 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;




•
            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.













***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.











***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. Because
      most
      of our operating costs are fixed, a reduction in volumes would result in not
      only a reduction of revenues, but also a decline in net income and cash flow
      of
      a similar magnitude, which would 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. In addition, it has been reported that terrorists might target
      domestic energy facilities. 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.***





Affiliates
      of Loews own 85.5% of the interests in us and own and control our general
      partner, which controls us. Our general partner makes all of our important
      decisions, including among others those relating to the amount and timing of
      asset purchases and sales, capital expenditures, borrowings, repayments of
      indebtedness, issuances of additional partnership securities, cash reserves,
      capital expenditures and distributions to unitholders.





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 may be
      directors or officers of our general partners’ affiliates, including Loews.
      Conflicts of interest may arise between Loews and its affiliates, including
      our
      general partner, on the one hand, and us and our unitholders, on the other
      hand.
      As a result of 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 its shareholders,
                which may be contrary to our interests. Our general partner intends
                to
                limit its liability regarding our contractual obligations;




•
            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;




•
            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. Common units 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
      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 include the exercise of our general partner's limited call
                rights, as provided in our partnership agreement, its voting rights
                with
                respect to the units it owns and its right to cause us to register
                resale
                of our units held by it under the Securities Act of 1933, 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, Texas Gas and Gulf
      South, conduct all of our operations and own all of our operating assets. We
      have no significant assets other than the ownership interests in our
      subsidiaries. As a result, our ability to make distributions to our unitholders
      depends on the performance of our subsidiaries and their ability to distribute
      funds to us. The ability of our subsidiaries to make distributions to us may
      be
      restricted by, among other things, the provisions of existing and future
      indebtedness, applicable state partnership and limited liability company laws
      and other laws and regulations, including FERC policies.








***Tax
      Risks***




*Our
      tax treatment depends on our status as a partnership for federal income tax
      purposes, as well as our not being subject to a material amount of entity-level
      taxation by individual states. If the IRS were to treat us as a corporation
      or
      if we were to become subject to entity-level taxation for state tax purposes,
      then our cash distributions to our unitholders would be substantially reduced.*




The
      anticipated after-tax benefit of an investment in the common units depends
      largely on our being treated as a partnership for federal income tax purposes.
      We have not requested, and do not plan to request, a ruling from the IRS on
      this
      or any other matter affecting us.











If
      we
      were treated as a corporation for federal income tax purposes, we would pay
      federal income tax on our income at the corporate tax rate, which is currently
      a
      maximum of 35%. 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. For example, because of widespread state budget deficits, several
      states are evaluating ways to subject partnerships to entity-level taxation
      through the imposition of state income, franchise or other forms of taxation.
      If
      any additional state were to impose a tax upon us as an entity, the cash
      available for distribution to our unitholders would be reduced. 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 counsel’s conclusions. It may
      be necessary to resort to administrative or court proceedings to sustain some
      or
      all of our counsel’s conclusions or the positions we take. A court may not agree
      with some or all of our 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.







***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.







***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 profits interests will result
      in the termination of our partnership for federal income tax purposes.***




We
      will
      be considered to have 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, our unitholders will likely be subject to
      other taxes, such as state and local income 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. Our unitholders may
      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, our
      unitholders may be subject to penalties for failure to comply with those
      requirements. We will initially conduct business in twelve states. We may own
      property or conduct business in other states or foreign countries in the future.
      It is our unitholders responsibility to file all federal, state and local tax
      returns. Our counsel has not rendered an opinion on the state and local tax
      consequences of an investment in our common units.








**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. Texas Gas and Gulf South
      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.





For
      additional information on our material property, including our pipelines and
      storage facilities, please read Item 1. “Business-Our Pipeline and Storage
      Systems” included herein.








**Item
      3.****Legal
      Proceedings.******







For
      a
      discussion of certain of our current legal proceedings, please read Note 3
      in
      the Notes to the Consolidated Financial Statements included in Item 8.





**Item
      4.****Submission
      of Matters to a Vote of Security Holders****.**








None.











**PART
      II**








**Item
      5.****Market
      for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases
      of Equity Securities.**








**Market
      Information**





As
      discussed elsewhere in this report, on November 15, 2005, we completed our
      IPO,
      in which we sold 15 million of our common units. Trading in our common units
      commenced on November 8, 2005. The high and the low sales price per common
      unit
      during the fourth quarter of 2005, as reported on the New York Stock Exchange,
      the principal market in which our common units are traded, was $19.51 and
      $17.58, respectively.








**Distributions**








***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 our
      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, FERC regulations which places restrictions on various types
      of
      cash management programs employed by companies in the energy industry, including
      Texas Gas and Gulf South, 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.








***Cash
      Distributions for the Year Ended December 31, 2005.***





On
      February 23, 2006, we made a cash distribution of $0.1788 per unit, including
      common and subordinated units and unit equivalents of the 2% general partner
      interest held by our general partner. This distribution represented a prorated
      portion of the minimum quarterly distribution for the period from November
      15,
      2005 through December 31, 2005.







***How
      We Make Cash Distributions.***





All
      distributions of our available cash will be made from either “operating surplus”
or “capital surplus.” We treat distributions of available cash from operating
      surplus differently than distributions of available cash from capital surplus.





“Available
      cash” is defined in our partnership agreement, and generally means, for each
      fiscal quarter, all cash on hand at the end of the quarter, less any cash
      reserves established by our general partner to conduct our business, comply
      with
      legal or contractual requirements or provide funds for future distributions
      for
      any one or more of the next four quarters, plus cash from any working capital
      borrowings made from our revolving credit facility after the end of the relevant
      quarter.











“Operating
      Surplus” is also defined in our partnership agreement and generally means the
      sum of our cash balance on the closing date of our IPO, $75 million, all of
      our
      cash receipts after our IPO, excluding cash from certain capital transactions,
      certain cash amounts paid in connection with capital projects, and cash from
      working capital borrowings made from our revolving credit facility after the
      end
      of the relevant quarter, less all of our operating expenditures after our IPO
      and the amount of any cash reserves established by our general partner to
      provide funds for future operating expenditures. Operating surplus does not
      reflect actual cash on hand that is available for distribution to our
      unitholders.





We
      treat
      all available cash distributed as coming from operating surplus, to the extent
      available. We will treat any amount distributed in excess of operating surplus,
      regardless of its source, as capital surplus. We do not anticipate that we
      will
      make any distributions from capital surplus.







***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. BPHC owns all
      of
      our 33,093,878 outstanding 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.








***Payment
      of Cash Distributions.*** **





Assuming
      we do not issue any additional classes of units and our general partner
      maintains its 2% interest, we will make distributions of available cash from
      operating surplus for any quarter during the subordination period in the
      following manner:




•
            First,
                98% to the common unitholders, pro rata, and 2% to our general partner,
                until we distribute for each outstanding common unit an amount equal
                to
                the minimum quarterly distribution for that
                quarter;




•
            Second,
                98% to the common unitholders, pro rata, and 2% to our general partner,
                until we distribute for each outstanding common unit an amount equal
                to
                any arrearages in payment of the minimum quarterly distribution on
                the
                common units for any prior quarters during the subordination
                period;




•
            Third,
                98% to the subordinated unitholders, pro rata, and 2% to our general
                partner, until we distribute for each subordinated unit an amount
                equal to
                the minimum quarterly distribution for that quarter;
                and




•
            Thereafter,
                98% to the common and subordinated unitholders, pro rata, and 2%
                to our
                general partner, except as described below under “Incentive Distribution
                Rights.”




Again,
      assuming we do not issue any additional classes of units and our general partner
      maintains its 2% interest, following the end of the subordination period, we
      will make distributions of available cash from operating surplus for any quarter
      first, 98% to all unitholders, pro rata, and 2% to our general partner, except
      as described below under “Incentive Distribution Rights.”











***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:




•
            First,
                98% to all unitholders, pro rata, and 2% to our general partner,
                until
                each unitholder receives a total of $0.4025 per unit for that quarter,
                the
                “first target distribution”;




•
            Second,
                85% to all unitholders, pro rata, and 15% to our general partner,
                until
                each unitholder receives a total of $0.4375 per unit for that quarter,
                the
                “second target distribution”;




•
            Third,
                75% to all unitholders, pro rata, and 25% to our general partner,
                until
                each unitholder receives a total of $0.5250 per unit for that quarter,
                the
                “third target distribution”; and




•
            Thereafter,
                50% to all unitholders, pro rata, and 50% to our general
                partner.







**Holders
      of Common Units**





We
      had
      approximately 12,000 holders of record of our common units as of February 16,
      2006. BPHC owns all of our subordinated units and Boardwalk GP holds all of
      our
      general partner interest and our incentive distribution rights.








**Use
      of Proceeds**





On
      November 8, 2005, the registration statement on Form S-1 (SEC File
      No. 333-127578) as amended, that we filed with the SEC relating to our IPO
      became effective. The managing underwriters were Citigroup Global Markets,
      Inc.
      and Lehman Brothers Inc. The closing date of our IPO was November 15, 2005,
      and
      on that date we sold 15 million common units at $19.50 per common unit, or
      $292.5 million. The underwriting discount on this sale was approximately $17.6
      million. In addition, concurrent with the closing of our IPO, Boardwalk
      Pipelines entered into and borrowed $42.1 million under our revolving credit
      facility and Boardwalk Pipeline Partners assumed $250.0 million of indebtedness
      to Loews from BPHC.





A
      summary
      of the proceeds received and use of proceeds from these transactions is as
      follows (in million):





Proceeds
                received:Sale
                of common units
            
            $
            292.5Borrowings
                under credit facility
            
            
            42.1$
            334.6Use
                of proceeds:Underwriting
                discount
            
            $
            17.6Structuring
                fee
            
            
            1.2Professional
                fees and offering costs
            
            
            2.3Reimbursement
                of BPHC for capital expenditures
            
            
            42.1Repayment
                of debt owed to Loews
            
            
            250.0Retained
                for working capital
            
            
            21.4Total
            
            $
            334.6











**Recent
      Sales of Unregistered Securities**





On
      August
      4, 2005, in connection with our formation we issued (1) to Boardwalk GP a 2%
      general partner interest for $20 and (2) to BPHC a 98% limited partner interest
      for $980. Upon the closing of our IPO, BPHC received 33,093,878 subordinated
      units and 53,256,122 common units in exchange for its contribution to us of
      all
      the equity interest of Boardwalk Pipelines. Each of these offerings was exempt
      from registration under Section 4(2) of the Securities Act of 1933. Each of
      the
      subordinated units will convert into a common unit as described above under
      “Distributions-Subordination Period.”








**Securities
      Authorized for Issuance Under Equity Compensation Plans**





Prior
      to
      the completion of our IPO, our Board adopted the Boardwalk Pipeline Partners,
      LP
      Long-Term Incentive Plan. For a description of this plan, see “Executive
      Compensation-Long-Term Incentive Plan” included in Item 11 of this report.





The
      following table provides certain information as of December 31, 2005 with
      respect to this plan.





**Plan
                category**
            
            **Number
                of securities to be issued upon exercise of outstanding options,
                warrants
                and rights**
            
            **Weighted-average
                exercise price of outstanding options, warrants and
                rights**
            
            **Number
                of securities remaining available for future issuance under equity
                compensation plan (excluding securities reflected in the first
                column)**Equity
                compensation plans approved by security holders
            
            -
            
            N/A
            
            -Equity
                compensation plans not approved by security holders
            
            -
            
            N/A
            
            3,525,000











**Item
      6.****Selected
      Financial Data.**








The
      table
      below presents summary historical financial and operating data for us, and
      our
      predecessor, Texas Gas, as of the dates and for the periods indicated. 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
      (TG-Acquisition). Because Boardwalk Pipelines had no assets or operations prior
      to its TG-Acquisition, we refer to Texas Gas as our predecessor (Predecessor).
      The summary historical financial and operating data is derived from our
      historical consolidated financial statements and those of Texas Gas included
      elsewhere in this report. .




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 separating Predecessor financial data from ours.




The
      acquisition of Gulf South by Boardwalk Pipelines in December 2004
      (GS-Acquisition) 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
      year
      ended December 31, 2005.





In
      connection with the consummation of our IPO, BPHC contributed all of the equity
      interests of Boardwalk Pipelines to us. This contribution was accounted for
      as a
      transfer of assets between entities under common control in accordance with
      Statement of Financial Accounting Standards (SFAS) No. 141, *Business
      Combinations* .
      Therefore, the results of Boardwalk Pipelines prior to November 15, 2005 have
      been combined with results subsequent to November 15, 2005 as our consolidated
      results for 2005.





Prior
      to
      our IPO, we recorded a charge-in-lieu of income taxes pursuant to accounting
      principles generally accepted in the United States of America (GAAP). With
      our
      conversion to a limited partnership representing a change in the tax status
      of
      the entity, we eliminated through the Consolidated Statements of Income all
      deferred income taxes recorded on the Consolidated Balance Sheets as of the
      date
      of our IPO. Subsequent to the conversion, we will no longer reflect income
      taxes
      on our financial statements. Prior to the TG-Acquisition, the Predecessor was
      charged or credited with an amount equivalent to its federal income tax expense
      or benefit as if the Predecessor had filed a separate return.





The
      following table presents a non-GAAP financial measure, EBITDA, which we use
      in
      our business. As used herein, EBITDA means earnings before interest expense,
      income taxes, and depreciation and amortization. This measure is not calculated
      or presented in accordance with 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” below. The
      financial data should be read in conjunction with the financial statements
      and
      the notes thereto included in this report.





**Boardwalk
                Pipeline Partners**
            
            
            
            **Predecessor**(Expressed
                in thousands)
            
            **For
                the Year Ended**
              **December
                31, 2005**
            
            **For
                the Year Ended**
              **December
                31, 2004**
            
            **For
                the Period May 17, 2003 through December 31, 2003**
            
            
            
            **For
                the Period January 1, 2003 through**
              **May
                16, 2003**
            
            **For
                the Year Ended**
              **December
                31, 2002**
            
            **For
                the Year**
              **Ended**
              **December
                31, 2001**Total
                operating revenues
            
            $
            560,466
            
            $
            263,621
            
            $
            142,860
            
            
            
            $
            113,447
            
            $
            266,674
            
            $
            251,585Net
                income
            
            
            100,925
            
            
            48,825
            
            
            22,451
            
            
            
            
            34,474
            
            
            56,099
            
            
            45,131EBITDA**
            
            
            291,188
            
            
            144,864
            
            
            77,467
            
            
            
            
            80,345
            
            
            151,042
            
            
            143,114Total
                assets
            
            
            2,465,491
            
            
            2,472,140
            
            
            1,238,627
            
            
            
            
            N/A
            
            
            1,412,148
            
            
            1,396,
                519Long-term
                debt
            
            
            1,101,290
            
            
            1,106,135
            
            
            548,115
            
            
            
            
            N/A
            
            
            249,781
            
            
            250,174





Our
      net
      income per common unit was $0.35 for the period from November 15, 2005, the
      closing date of our IPO, through December 31, 2005.











****Non-GAAP
      Financial Measure**




EBITDA
      is
      used as a supplemental financial measure by management and by external users
      of
      our financial statements, such as investors, commercial banks, research analysts
      and rating agencies, to assess:




•
            our
                financial performance without regard to financing methods, capital
                structure or historical cost basis;




•
            our
                ability to generate cash sufficient to pay interest on our indebtedness
                and to make distributions to our partners;




•
            our
                operating performance and return on invested capital as compared
                to those
                of other companies in the natural gas transportation and storage
                business,
                without regard to financing methods and capital structure; and




•
            the
                viability of acquisitions and capital expenditure projects.




EBITDA
      should not be considered an alternative to 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:





**Boardwalk
                Pipeline Partners**
            
            
            
            **Predecessor****For
                the Year Ended**
              **December
                31, 2005**
            
            **For
                the Year Ended**
              **December
                31, 2004**
            
            **For
                the Period May 17, 2003 through December 31, 2003**
            
            
            
            **For
                the Period January 1, 2003 through**
              **May
                16, 2003**
            
            **For
                the Year Ended**
              **December
                31, 2002**
            
            **For
                the Year Ended**
              **December
                31, 2001**Net
                income
            
            $
            100,925
            
            $
            48,825
            
            $
            22,451
            
            
            
            $
            34,474
            
            $
            56,099
            
            $
            45,131Provision
                for income taxes
            
            
            -
            
            
            -
            
            
            -
            
            
            
            
            22,387
            
            
            36,647
            
            
            30,484Charge-in-lieu
                of income taxes
            
            
            49,494
            
            
            32,333
            
            
            15,104
            
            
            
            
            -
            
            
            -
            
            
            -Elimination
                of cumulative deferred taxes
            
            
            10,102
            
            
            -
            
            
            -
            
            
            
            
            -
            
            
            -
            
            
            -Depreciation
                and amortization
            
            
            72,078
            
            
            33,977
            
            
            20,544
            
            
            
            
            16,092
            
            
            37,806
            
            
            45,821Interest
                expense
            
            
            58,589
            
            
            29,729
            
            
            19,368
            
            
            
            
            7,392
            
            
            20,490
            
            
            21,678EBITDA
            
            $
            291,188
            
            $
            144,864
            
            $
            77,467
            
            
            
            $
            80,345
            
            $
            151,042
            
            $
            143,114








**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 in 2005 to own and operate the business
      conducted by Boardwalk Pipelines and its subsidiaries, Texas Gas and Gulf South.
      Boardwalk Pipelines was formed to acquire Texas Gas in the TG-Acquisition,
      which
      was completed in May 2003. Because Boardwalk Pipelines had no assets or
      operations prior to the TG-Acquisition, Texas Gas is referred to as our
      Predecessor. We acquired Gulf South in the GS-Acquisition, which was completed
      in December 2004.





We
      own
      and operate pipelines 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. Firm transportation capacity reservation revenues typically do not
      vary over the term of the contract. For the year ended December 31, 2005, the
      percentage of our total operating revenues under firm contracts was
      approximately 82%.





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 depend on the availability of competitively priced natural
      gas
      supplies that our customers desire to ship through the pipeline systems. We
      are
      connected to several major regional supply hubs and market centers for natural
      gas, including Agua Dulce and Carthage, Texas, Mobile Bay, Alabama, offshore
      Louisiana, and the Henry Hub in Louisiana. We have the largest take away
      capacity at the Henry Hub, which serves as the designated delivery point for
      natural gas futures contracts traded on the New York Mercantile Exchange. The
      supply areas along the Gulf Coast, both onshore and offshore, and in East Texas
      have been prolific sources of natural gas for many years, accounting for
      approximately 48% of the U.S. natural gas supply in 2004, according to the
      Energy Information Administration.





Demand
      for natural gas in our markets is also critical to our long-term financial
      performance. We deliver to a broad mix of customers including LDCs, industrial
      facilities, electric utilities, merchant power plants, and other pipelines.
      In
      addition to serving directly connected markets, our pipeline systems have
      indirect market access to the northeastern and southeastern United States
      through interconnections with unaffiliated pipelines.





Our
      natural gas storage facilities allow us to offer customers a high degree of
      flexibility in meeting their delivery requirements. For example, LDC customers
      use traditional storage services under their no-notice contracts by injecting
      natural gas into the storage facilities in the summer months when gas prices
      are
      typically lower and then withdrawing the gas during the winter months in order
      to reduce their exposure to the potential volatility of winter gas prices.
      During the summer months, other customers use our storage services to manage
      highly variable levels of electric power generation load. Other customers use
      storage to support trading and marketing activities. We offer firm storage
      service in which the customer reserves and pays for a specific amount of storage
      capacity, including injection and withdrawal rights, and interruptible storage
      service, where the customer receives and pays for capacity only when it is
      available and used.








**Recent
      Expansion Projects**





*East
      Texas and Mississippi Pipeline Expansion.* In
      February and March of 2006, Gulf South entered into long-term agreements with
      customers providing firm commitments for capacity on its 1.5 Bcf per day
      pipeline expansion projects in East Texas and Mississippi. We expect the total
      cost for the 1.5 Bcf expansion to be approximately $800 million, and we expect
      the new capacity to be in-service during the second half of 2007.




The
      East
      Texas pipeline expansion will extend from Carthage in East Texas to the
      Perryville area in Richland Parish, Louisiana. Natural gas originating primarily
      from the prolific Barnett Shale and Bossier Sands producing regions of East
      Texas will be transported to interstate pipelines serving markets in the Midwest
      and Northeast, including Texas Gas, MRT, Tennessee, ANR, Columbia Gulf and
      Southern Natural. The Mississippi pipeline expansion will continue eastward
      from
      the Perryville area to the Jackson, Mississippi area and will provide additional
      supplies to customers in the Northeast and Southeast through interconnects
      with
      interstate pipelines serving those markets, including Texas Eastern, Transco,
      Southern Natural and Florida Gas, and to customers in the Baton Rouge - New
      Orleans industrial complex.











These
      projects are subject to FERC approvals. Gulf South will submit separate
      applications to FERC for authority to construct the East Texas and Mississippi
      expansion projects. In February 2006, FERC granted Gulf South's request to
      initiate the pre-filing process for the East Texas expansion.





*Western
      Kentucky Storage Expansion.* In
      November 2005, Texas Gas completed the expansion of its western Kentucky storage
      complex by approximately 8 Bcf of working gas, which allows for the additional
      withdrawal of approximately 82 MMcf/day, and contracted with customers for
      that
      new capacity at maximum rates for five years. In addition, Texas Gas has
      accepted commitments from customers for incremental no-notice service (NNS)
      and
      firm storage service that will allow it to further expand the working gas in
      this storage complex by approximately 9 Bcf, subject to FERC approval. We expect
      this second storage expansion to go into service in late 2007.





*East
      Texas Lease Arrangement.* In
      December 2005, Texas Gas initiated service under a lease arrangement which
      allowed us to tie in 100 MMcf/day of supply from the growing Barnett Shale
      production area in East Texas to the Texas Gas system at Sharon, Louisiana,
      using existing pipeline infrastructure.





*Magnolia
      Storage Facility.* Gulf
      South has leased a gas storage facility, which we refer to as the Magnolia
      facility, near Napoleonville, Louisiana, at which it has installed two
      compressor stations, with a combined horsepower of 9,470 and other storage
      infrastructure and is currently developing a high-deliverability storage cavern
      that, when operational, may add up to approximately 5 Bcf of working gas storage
      capacity. Magnolia’s storage capacity is expected to be in service and available
      for sale at market-based rates in late 2008 or early 2009, subject to the
      operational requirements of the lessor.





We
      evaluate our business based upon a few key drivers:




•
            the
                level of firm service for our transportation and storage
                businesses;




•
            the
                level of interruptible service for our transportation and storage
                businesses;




•
            the
                average rate for our firm and interruptible services;




•
            operating
                costs and expenses; and




•
            EBITDA.







**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;




•
            a
                desire by certain of our customers to replace long-term contracts
                with
                contracts of shorter duration when their current contracts
                expire;




•
            disruption
                at the facilities of gas suppliers and end users in the Gulf Coast
                region
                and other uncertainties regarding the impact of Hurricanes Katrina
                and
                Rita;




•
            increased
                demand for natural gas in our traditional market areas at a rate
                greater
                than discoveries of natural gas in our supply
                areas;




•
            the
                likelihood that LNG from the Gulf Coast region will become an increasingly
                important source of supply for our
                customers;




•
            a
                widening basis, meaning increases in the differential between the
                sale
                price of natural gas in our market areas and the price at which natural
                gas may be purchased in certain of our supply areas, particularly
                East
                Texas, where pipeline capacity constraints limit the gas which may
                be sold
                from that region.











We
      believe the collective impact of the trends and uncertainties described in
      the
      first four 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 last three bullet points above may
      provide us with growth opportunities. They may 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.








***Firm
      Service***





Firm
      transportation customers reserve a specific amount of pipeline capacity from
      certain receipt points to certain delivery points. Firm customers generally
      pay
      a “demand” or “capacity reservation” charge based on the amount of capacity
      being reserved regardless of whether the capacity is used, plus a commodity
      and
      fuel charge paid on the volume of gas actually transported. Firm storage
      customers reserve a specific amount of storage capacity, including injection
      and
      withdrawal rights, and generally pay a capacity reservation charge based on
      the
      amount of capacity being reserved plus an injection and/or withdrawal fee and
      fuel charge. Capacity reservation revenues derived from firm service generally
      remain constant over the term of the contract because the revenues are generated
      based upon the capacity reserved and not whether the capacity is actually used.
      Our ability to maintain or increase the amount of firm service provided is
      key
      to assuring a consistent revenue stream.








***Interruptible
      Service***





Interruptible
      transportation and storage service is typically short-term in nature and is
      generally used by customers that either do not need firm service or have been
      unable to contract for firm service. These customers pay a rate and fuel charge
      only for the volume of gas actually transported or stored. We attempt to provide
      interruptible service at competitive prices in order to capture short-term
      market opportunities. Typically, we are able to price this service at rates
      which allows us to receive a significant portion of the basis differential
      and/or to augment revenues when firm capacity is not being utilized. We view
      interruptible service revenues as an important measure of how effective we
      are
      in optimizing the transportation and storage capacity of the pipeline
      systems.








***Average
      Rates***





A
      large
      percentage of our contracts are at rates below maximum tariff rates due to
      the
      competitive environment in which we operate. Another key factor in how
      transportation services are priced is the difference in gas prices between
      different physical locations (basis or basis differentials). When gas supplies
      compete for limited amounts of pipeline capacity in a given area, the average
      price of gas in those locations will tend to decline. As an example, significant
      gas drilling has occurred in East Texas and production from that area has
      increased. Because of the limited take away capacity, gas prices at the
      Carthage, Texas hub have fallen to historic lows relative to other locations
      on
      our system such as the Henry Hub (the settlement location for NYMEX futures
      contracts). We monitor the basis differentials at specific locations on the
      system to determine the length of the contract term we will propose to offer
      a
      shipper. Because competition requires us to discount capacity, we attempt to
      structure contract terms to match market conditions. In periods of flat or
      narrowing basis differentials, we will seek to enter into longer term contracts
      especially if we believe basis will continue to narrow. In periods of increasing
      basis differentials, we tend to seek to enter into shorter term contracts to
      take advantage of rising basis spreads. We will follow this pattern until the
      maximum applicable rates can be charged, at which time we will seek to lengthen
      the contract term. As we look at the market opportunities across our systems,
      we
      may implement several different contracting strategies based upon our current
      view of the market.











***Operating
      Costs and Expenses***





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. While
      expenses may not materially vary with throughput other than as noted above,
      the
      timing of spending during a year can be dictated by customer demands. During
      the
      winter months, our pipelines' average throughput is higher, and therefore,
      we
      typically do not perform routine compressor maintenance until off peak periods,
      which results in higher costs in the third and fourth quarters compared to
      the
      first half of the year. We are also regulated by the federal government and
      state and local laws which can impact the activities we perform on our pipeline
      systems. Changes in these regulations can increase our costs. As an example,
      the
      Pipeline Safety Act set new standards for pipelines in assessing the safety
      and
      reliability of the pipeline infrastructure. We have incurred additional costs,
      as have other pipelines, to meet these standards. Our pipeline systems are
      located in areas that are served by many other interstate and intrastate natural
      gas pipelines and we need to operate the pipeline systems efficiently and
      reliably to effectively compete for transportation and storage
      services.





**Critical
      Accounting Policies and Estimates**





The
      accounting policies discussed below are considered by management to be critical
      to an understanding of our consolidated financial statements as their
      application places the most significant demands on management’s judgment. Due to
      the inherent uncertainties involved with this type of judgment, actual results
      could differ significantly from estimates and may have a material adverse impact
      on our financial condition, results of operations and cash flows.











***Regulation***





Texas
      Gas’ and Gulf South’s pipeline operations are regulated by FERC whose regulatory
      policies govern the rates that each pipeline is permitted to charge customers
      for interstate transportation and storage of natural gas. From time to time,
      certain revenues collected may be subject to possible refunds upon final FERC
      orders. Accordingly, estimates of rate refund reserves are recorded considering
      regulatory proceedings, advice of counsel and estimated risk-adjusted total
      exposure, as well as other risks. Texas Gas filed a general rate case with
      FERC
      on April 29, 2005, and implemented new rates on November 1, 2005, subject to
      refund. No assurances can be provided as to the financial outcome of Texas
      Gas’
2005 rate case relative to its current rate structure. As of December 31, 2005,
      an estimated refund liability of approximately $5.0 million related to Texas
      Gas’ open general rate case was recorded on our Consolidated Balance Sheets.
      Texas Gas anticipates that the general rate case will be settled and all
      required refunds will be paid during 2006.




SFAS
      No.
      71, “ *Accounting
      for the Effects of Certain Types of Regulation* ,”
      requires rate-regulated public utilities that apply this standard 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 capitalizes 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 market-based and competition
      in Gulf South’s market area often results in discounts from the maximum
      allowable cost-based rate such that SFAS No. 71 is not appropriate.




The
      storage facilities operated by Texas Gas and Gulf South store gas that is owned
      by them as well as gas owned by customers. Texas Gas and Gulf South provide
      various services that allow customers to borrow gas from us with a requirement
      to repay the gas at some future prescribed date. Consistent with certain
      regulatory treatment prescribed by FERC as a result of 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. 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 and receivables, please see Note 2, Accounting Policies in the Notes
      to the Consolidated Financial Statements included in item 8.








***Hurricane
      Insurance Costs and Indemnification***





In
      late
      August and September 2005, Hurricanes Katrina and Rita caused damage to our
      gas
      metering facilities, cathodic protection devices, communication devices, rights
      of way and other above ground facilities such as office buildings and signage.
      We have recorded approximately $13.6 million representing an estimate of the
      repairs, cleanup, lost gas and other storm-related expenditures relating to
      the
      Hurricanes. Additionally, while we anticipate coverage for a substantial portion
      of the costs by insurance carriers after meeting certain deductibles, we have
      not recorded any anticipated insurance recovery to date as the claims process
      is
      in the early stage, and the insurance carriers have not taken a definitive
      coverage position on each aspect of the claim to record such receipts. Should
      there be additional information that becomes available with respect to the
      extent of damage caused by the Hurricanes or an acknowledgement by insurance
      carriers that certain of these identified costs are eligible for recovery,
      we
      will record revised estimates based on that information.








***Contingencies***





We
      record
      liabilities for estimated loss contingencies when a loss is probable and the
      amount of the loss can be reasonably estimated. Revisions to contingent
      liabilities are reflected in income in the period in which different facts
      or
      information become known or circumstances change that affect previous
      assumptions with respect to the likelihood or amount of loss. Liabilities for
      contingent losses are based upon management’s assumptions and estimates
      regarding the probable outcomes of the matters. Should the outcomes differ
      from
      the assumptions and estimates, revisions to the liabilities for contingent
      losses would be required.











***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, 2005, we had accrued approximately $20.0 million for environmental
      matters. Our environmental accrued liabilities could change substantially in
      the
      future due to factors such as the nature and extent of any contamination,
      changes in remedial requirements, technological changes, discovery of new
      information, and the involvement of and direction taken by the Environmental
      Protection Agency (EPA), 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.








***Purchase
      Price Allocation and Impairment of Goodwill***




Our
      purchase price allocation for the acquisition of Texas Gas reflects the
      underlying assumption that the historical net book value of regulatory related
      assets and liabilities are considered to be the fair value of those respective
      assets and liabilities. The excess purchase price over the fair value of the
      assets and liabilities was allocated to goodwill. As of December 31, 2005,
      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, 2005, and, therefore,
      resulted in no impairment.





We
      made
      an allocation of the purchase price in connection with the acquisition of Gulf
      South. The determination of fair value with respect to property, plant and
      equipment, as well as gas in storage, was based on management's analyses with
      consideration of external valuations.





Judgments
      and assumptions are inherent in management’s estimate of undiscounted future
      cash flows used to determine recoverability of an asset and the estimate of
      an
      asset’s fair value used to calculate the amount of impairment to recognize. 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 such as inflation, interest rates and fiscal
      and monetary policies. 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 in
      2005, 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
      double A 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 5 in the Notes to Consolidated Financial Statements included in Item
      8.





**Financial
      Analysis of Operations**








***Overview***





The
      following discussion presents summary historical financial and operating data
      for us and our Predecessor. On November 15, 2005, we sold 15 million of our
      common units in an underwritten IPO. All of our common and subordinated units,
      other than the common units sold in our IPO, are held by BPHC. Our general
      partner, Boardwalk GP, LP holds our 2% general partner interest and incentive
      distribution rights. In connection with the consummation of our IPO, BPHC
      contributed all of the equity interests of Boardwalk Pipelines to us. This
      contribution was accounted for as a transfer of assets between entities under
      common control in accordance with SFAS No. 141, *Business
      Combinations* .
      Therefore, the results of Boardwalk Pipelines prior to November 15, 2005 have
      been combined with the results of Boardwalk Pipeline Partners subsequent to
      November 15, 2005 as the consolidated results of Boardwalk Pipeline Partners
      for
      2005.





Boardwalk
      Pipelines was formed in April 2003, with an initial capitalization on May 16,
      2003, of $804 million, to acquire all of the outstanding capital stock of Texas
      Gas. 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 results of Texas Gas for the periods
      prior to May 16, 2003, are not directly comparable to its financial results
      subsequent to that date.





On
      December 29, 2004, Boardwalk Pipelines acquired Gulf South for a purchase price
      of $1.1 billion. The acquisition was funded with a $575 million term loan and
      a
      capital contribution from BPHC. In January 2005, Gulf South issued $275 million
      aggregate principal amount of its 5.05% notes due 2015, and Boardwalk Pipelines
      issued $300 million aggregate principal amount of its 5.50% notes due 2017.
      The
      net proceeds of these two offerings were used to repay the $575 million term
      loan.





The
      acquisition of Gulf South was also accounted for using the purchase method
      of
      accounting. Accordingly, the post-acquisition financial information included
      below reflects the purchase. Therefore, our Consolidated Statements of Income
      for the year ended December 31, 2005, are not readily comparable with our
      Consolidated Statements of Income for the year ended December 31,
      2004.





We
      acquired all of the assets of Gulf South, including the entire revenue stream
      and basic operating cost structure. Gulf South added approximately six
      employees, in addition to shared resources from Texas Gas, to replace human
      resources and certain accounting and finance services provided by Gulf South’s
      previous owner, Entergy-Koch, LP. Gulf South’s information technology services
      were provided by a third party and beginning with the third quarter of 2005,
      Gulf South assumed responsibility for these services resulting in the addition
      of approximately 15 employees. The increased costs associated with the
      additional employees were offset by the elimination of charges incurred from
      the
      third party information technology service provider.





Upon
      our
      completion of the GS-Acquisition, Texas Gas and Gulf South installed certain
      operating facilities to connect the two pipelines or enhance existing
      inter-connections for approximately $2.0 million. These new facilities created
      additional operational flexibility on the Gulf South system.





Prior
      to
      our IPO, we recorded a charge-in-lieu of income taxes pursuant to GAAP. With
      our
      conversion to a limited partnership we eliminated through the Consolidated
      Statements of Income all deferred  income taxes recorded on our
      Consolidated Balance Sheets as of the date of our IPO. Subsequent to the
      conversion, we will no longer reflect income taxes on our financial statements.











***Basis
      of Presentation***





The
      following analysis discusses the financial results of operations of us (and,
      where applicable, our Predecessor) for the years 2005, 2004 and 2003. As more
      fully discussed in the Notes to Consolidated Financial Statements included
      in
      Item 8, the TG-Acquisition purchase price allocation created a new basis of
      accounting in May of 2003, necessitating the use of a bold black line in the
      Consolidated Statements of Income. For the purpose of this financial analysis
      of
      operations, we have combined the results of 2003 for our Predecessor and
      Boardwalk Pipelines. This pro forma total combines two different bases of
      accounting, which qualifies as a non-GAAP measure. However, due to the fact
      that
      the purchase price allocation considers that historical book value is equal
      to
      fair value, there are no significant differences between the two presentations.
      Texas Gas’ depreciation expense and interest expense are impacted by the new
      purchase price allocation and related financing. As the excess of fair value
      paid over net book value was allocated to goodwill for Texas Gas, which is
      non-amortizable, there is no impact on results of operations from that
      allocation item.





The
      GS-Acquisition was consummated on December 29, 2004. Three days of activity
      are
      included in the 2004 Consolidated Statements of Income and Cash Flows.
      Approximately $2.0 million of franchise taxes were recorded in the period ended
      December 31, 2004 as Taxes other than income taxes. All other financial activity
      of Gulf South for those three days is considered immaterial and does not impact
      discussions below.








***2005
      Compared with 2004***





Gas
      transportation revenues increased by $273.1 million, or 108%, substantially
      all
      of which was attributable to Gulf South, to $526.6 million for the year ended
      December 31, 2005, compared to $253.5 million for the year ended December 31,
      2004. 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 the
      following new projects:





•
            On
                November 1, 2005, we completed our market area storage expansion
                project
                in Western Kentucky and the associated transportation agreements
                contributed approximately $2 million in revenues during 2005;
                and




•
            On
                December 1, 2005, we increased capacity from Carthage, Texas by leasing
                capacity on a third party pipeline which contributed approximately
                $1
                million in revenues during 2005.





Gas
      storage revenues increased by $14.4 million, or 197%, of which $16.3 million
      was
      attributable to Gulf South, to $21.7 million for the year ended December 31,
      2005, compared to $7.3 million for the year ended December 31, 2004. 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.





Other
      revenues increased by $9.4 million, or 330%, of which $11.1 million was
      attributable to Gulf South, to $12.2 million for the year ended December 31,
      2005, compared to $2.8 million for the year ended December 31, 2004.





Operating
      costs and expenses increased by $191.1 million, or 124%, of which $207.4 million
      was attributable to Gulf South, to $345.0 million for the full year ended
      December 31, 2005, compared to $153.9 million for the year ended December 31,
      2004. This increase in expenses was partially offset by a gain of $12.2 million
      on the sale of storage gas related to our Western Kentucky storage expansion
      project, partially offset by asset retirements.





Total
      other deductions increased by $26.4 million, or 92%, of which $28.9 million
      is
      due to higher interest expense primarily related to debt incurred in 2004 to
      fund the GS-Acquisition.











***2004
      Compared with 2003***





Operating
      revenues increased by $7.3 million, or 3%, to $263.6 million in 2004, compared
      to $256.3 million in 2003. This increase was comprised primarily of $3.3 million
      of revenue from a Texas Gas regulatory settlement in 2004 related to deferred
      interruptible transportation revenue recognized as income in December 2004
      and
      $2.1 million attributable to the ownership of Gulf South for three days in
      2004.
      Gas storage revenue increased $4.0 million, or 124%, due primarily to two new
      firm storage contracts on Texas Gas, effective late in 2003.





Operating
      costs and expenses increased by $15.7 million, or 11%, to $153.9 million in
      2004, compared to $138.2 million in 2003. The increase was primarily comprised
      of a $3.9 million accrual for environmental costs due to proactive steps taken
      by Texas Gas with various state agencies, a $5.7 million increase resulting
      from
      a reduction in benefit accruals prior to the TG-Acquisition in 2003, a $2.8
      million increase in labor and benefit costs due to an increase in approximately
      40 employees in information technology, human resources, and finance and
      accounting to replace services previously provided by Williams prior to the
      TG-Acquisition and $3.8 million attributable to our ownership of Gulf South
      for
      three days in 2004. Taxes, other than income taxes, increased by $2.3 million,
      or 14%, which was attributable to Gulf South’s franchise taxes resulting from
      the GS-Acquisition.




Total
      other deductions increased $4.9 million, or 21%, primarily attributable to
      an
      increase of $3.0 million in interest expense related to debt incurred in 2003
      and 2004 to fund the TG-Acquisition and the GS-Acquisition,
      respectively.








**Liquidity
      and Capital Resources** ****




We
      are a
      partnership holding company and derive all of our operating cash flow from
      our
      subsidiaries, Texas Gas and Gulf South. Texas Gas and Gulf South 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 Texas Gas and Gulf South and, as needed, borrowings under its revolving
      credit facility discussed below, to services its outstanding indebtedness and,
      when available, make distributions or advances to us to fund our distributions
      to unitholders.




Texas
      Gas
      and Gulf South 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.







***Credit
      Facility***




At
      the
      closing of our IPO, Boardwalk Pipelines entered into a five-year $200 million
      revolving credit facility. We have guaranteed all of the obligations of
      Boardwalk Pipelines under that credit facility. Citibank, N.A., acts as
      administrative agent under this facility which may be used for letters of credit
      and general partnership purposes. As of December 31, 2005, we had $42.1 million
      outstanding under the credit facility, which we borrowed at the closing of
      our
      IPO to reimburse BPHC for capital expenditures it had incurred in connection
      with the GS-Acquisition.




We
      are
      required under the agreement that governs our credit facility, to maintain
      minimum leverage and interest coverage ratios. The leverage ratio covenant
      requires us to maintain, as of the last day of each fiscal quarter, a ratio
      of
      our total indebtedness, measured as of such last day, to our Consolidated EBITDA
      (as defined in our credit agreement), measured for the preceding twelve months,
      of not more than 5.00 to 1.00. If we complete an acquisition having a
      purchase price of $100.0 million or more that otherwise meets the conditions
      for
      a qualifying acquisition under the credit facility, the leverage ratio we are
      permitted to maintain increases to 5.50 to 1.00 for a period of three
      consecutive fiscal quarters immediately following the consummation of the
      acquisition. The interest coverage ratio covenant requires us to maintain,
      as of
      the last day of each fiscal quarter, a ratio of our Consolidated EBITDA to
      our
      cash interest expense, each measured for the preceding twelve months, of not
      less than 3.00 to 1.00. As of December 31, 2005, we were in compliance with
      all
      the covenant requirements under our credit agreement.  For
      further discussion regarding EBITDA, please read Item 6 “Selected Financial
      Data.”











***Capital
      Expenditures***





Capital
      expenditures, net of retirements and salvage, for 2005 and 2004 are as follows
      (expressed in millions):





**December
                31, 2005**
            ****
            **December
                31, 2004**Maintenance
                capital
            
            $
            52.9
            
            $
            34.2Expansion
                capital
            
            
            30.1
            
            
            7.7Total
            
            $
            83.0
            
            $
            41.9





For
      the
      year ending December 31, 2006 we expect to make capital expenditures of
      approximately $310 million, of which we expect $50 million to be for maintenance
      capital and $260 million to be for expansion capital, including approximately
      $210 million to fund our East Texas and Mississippi pipeline expansion projects
      discussed in Item 1.  The amount of expansion capital we expend in 2006
      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 2006 maintenance capital expenditures from operating cash flows
      and
      our 2006 expansion capital expenditures with borrowings under our revolving
      credit facility. Thereafter, we expect to fund the balance of the cost of our
      East Texas and Mississippi pipeline expansion projects with a combination of
      borrowings under our revolving credit facility and proceeds from sales of our
      debt and equity securities, though we have not made any determination with
      regard to such financing.











***Recent
      Accounting Pronouncements***





For
      a
      discussion regarding recent accounting pronouncements, please read Note 9 in
      the
      Notes to Consolidated Financial Statements included in Item 8.








***Contractual
      Obligations***




The
      table
      below summarizes significant contractual cash payment obligations as of December
      31, 2005, by period (expressed in millions):





**Payments
                due by Period****Total**
            
            **Less than**
              **1
                Year**
            
            **1-2 Years**
            
            **3-5 Years**
            
            **More than**
              **5
                Years**Lease
                commitments
            
            $
            21.1
            
            $
            4.9
            
            $
            7.2
            
            $
            5.8
            
            $
            3.2Interest
                on long-term debt
            
            
            709.9
            
            
            58.8
            
            
            117.5
            
            
            117.5
            
            
            416.1Capital
                commitments
            
            
            15.8
            
            
            15.7
            
            
            0.1
            
            
            -
            
            
            -Principal
                payments on long-term debt
            
            
            1,110.0
            
            
            -
            
            
            -
            
            
            -
            
            
            1,110.0Total
            
            $
            1,856.8
            
            $
            79.4
            
            $
            124.8
            
            $
            123.3
            
            $
            1,529.3





Our
      obligation to contribute $5.3 million to benefit plans expired on November
      1,
      2005, with the filing of our rate case. We anticipate contributing toward this
      benefit plan; however, we will not be obligated to do so until we have a final
      settlement in our rate case. The above table does not reflect commitments we
      have made after December 31, 2005 relating to our East Texas and Mississippi
      pipeline expansion projects. For information on these projects please read
      “Capital Expenditures” and “Recent Expansion Projects” included in this
      MD&A.








***Impact
      of Inflation***




We
      generally 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 can directly affect 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***




We
      have
      no guarantees of off-balance sheet debt to third parties and maintain no debt
      obligations that contain provisions requiring accelerated payment of the related
      obligations in the event of specified levels of declines in credit ratings.











**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:




•
            The
                gas transmission and storage operations of our subsidiaries are subject
                to
                rate-making policies that could have an adverse impact on our ability
                to
                recover the full cost of operating our pipelines, including a reasonable
                return.




•
            The
                impact of Hurricanes Katrina and Rita could have a material adverse
                effect
                on our business, financial condition and results of operations because
                some of our damages may not be covered by
                insurance.




•
            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 results of
                operations.




•
            Our
                operations are subject to operational hazards and unforeseen interruptions
                for which we may not be adequately
                insured.




•
            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
                and
                operating results.




•
            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.




•
            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.




•
            Significant
                changes in natural gas prices could affect supply and demand, reducing
                system throughput and adversely affecting our revenues**.**




•
            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.







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.











**Item
      7A.****Quantitative
      and Qualitative Disclosures About Market Risk.**








Our
      market risk is substantially limited to our long-term debt. Total long-term
      debt
      at December 31, 2005, had a carrying value of $1.1 billion and a fair value
      of
      $1.1 billion. The weighted-average interest rate of our long-term debt was
      5.29%
      at December 31, 2005.





Certain
      volumes of gas stored underground at Gulf South are available for sale and
      subject to commodity price risk. At
      December 31, 2005 and 2004, approximately $6.5 million and $3.5 million,
      respectively, of Gulf South’s gas stored underground, which we own and carry as
      inventory, is exposed to commodity price risk. In accordance with Gulf South’s
      risk management policy, Gulf South utilizes natural gas futures, swap, and
      option contracts (collectively, hedge contracts) to hedge certain exposures
      to
      market price fluctuations on our anticipated purchases and sales of gas and
      anticipated cash for fuel reimbursement related to transportation revenues.
      The
      changes in fair value of the hedge contracts are expected to, and do, have
      a
      high correlation to changes in the anticipated value of the hedged transactions
      and therefore qualify for hedge accounting under SFAS No. 133. In addition,
      if
      the hedge contracts cease to have high correlation or if the anticipated
      transaction is deemed no longer probable to occur, hedge accounting is
      terminated and the associated changes in the fair value of the derivative
      financial instruments are recognized in the related period on our Consolidated
      Statements of Income. The related gains and losses derived from changes in
      the
      fair value of hedge contracts are deferred as a component of accumulated other
      comprehensive loss. These deferred gains and losses are recognized in our
      Consolidated Statements of Income when the hedged anticipated transaction
      affects earnings. However, to the extent that the change in the fair value
      of
      the hedge contracts does not effectively offset the change in the fair value
      of
      the anticipated transaction, the ineffective portion of the hedge contracts
      is
      immediately recognized.





We
      are
      exposed to credit risk. 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. We maintain credit policies intended to minimize credit risk
      and
      actively monitor these policies.  Average natural gas prices have increased
      dramatically in recent years. This rise in gas prices has materially increased
      credit risk related to gas loaned to customers. The amount of gas loaned out
      by
      us over the past 24 months at any one time to our customers has ranged from
      a
      high of approximately 38 Bcf at April 30, 2005 to a low of approximately 4
      Bcf
      at December 31, 2005. Assuming an average market price during December 2005
      of
      $12.34 per MMBtu, the market value of gas loaned out at December 31, 2005,
      would
      have been approximately $49.4 million. As of February 28, 2006, the amount
      of
      gas loaned out was approximately 18 Bcf and, assuming an average market price
      during February 2006 of $7.30 per MMBtu, the market value of that gas would
      be
      approximately $131.4 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 us, this could have a material adverse effect on our financial
      condition, results of operations and cash flows.





As
      of
      December 31, 2005, our cash and investment portfolio did not include
      fixed-income securities. Due to the short-term nature of our investment
      portfolio, 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 to any significant
      degree by the effect of a sudden change in market interest rates on our
      investment portfolio.











**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, 2005 and
      2004 and the related consolidated statements of income, member’s equity and
      partners’ capital and comprehensive income, and cash flows for the years ended
      December 31, 2005 and 2004 and the period May 17, 2003 through December 31,
      2003. 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 these 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. The Partnership is not required
      to
      have, nor were we engaged to perform, an audit of its internal control over
      financial reporting. Our audits included consideration of internal control
      over
      financial reporting as a basis for designing audit procedures that are
      appropriate in the circumstances, but not for the purpose of expressing an
      opinion on the effectiveness of the Partnership's internal control over
      financial reporting. Accordingly, we express no such opinion. An audit also
      includes examining, on a test basis, evidence supporting the amounts and
      disclosures in the financial statements, assessing the accounting principles
      used and significant estimates made by management, 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, 2005 and 2004, and the results of their
      operations and their cash flows for the years ended December 31, 2005 and 2004
      and the period May 17, 2003 through December 31, 2003, 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 2 to the consolidated financial statements, the accompanying
      financial statements reflect a change in the Partnership’s tax
      status.








DELOITTE
      & TOUCHE LLP


Chicago,
      Illinois


March
      13,
      2006











**REPORT
      OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM**





To
      the
      Board of Directors and Member of Texas Gas Transmission, LLC





We
      have
      audited the accompanying statements of operations, stockholder’s equity, and
      cash flows of Texas Gas Transmission, LLC (formerly Texas Gas Transmission
      Corporation) (the “Company”) for the period January 1, 2003 through May 16,
      2003.  Our audit 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 Company’s management.  Our
      responsibility is to express an opinion on the financial statements and
      financial statement schedule 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
      the
      financial statements are free of material misstatement.  The Company is not
      required to have, nor were we engaged to perform, an audit of its internal
      control over financial reporting. Our audit included consideration of
      internal control over financial reporting as a basis for designing audit
      procedures that are appropriate in the circumstances, but not for the purpose
      of
      expressing an opinion on the effectiveness of the Company’s internal control
      over financial reporting.  Accordingly, we express no such opinion. 
An audit also includes examining, on a test basis, evidence supporting the
      amounts and disclosures in the financial statements, assessing the accounting
      principles used and significant estimates made by management, as well as
      evaluating the overall financial statement presentation.  We believe that
      our audit provides a reasonable basis for our opinion.





In
      our
      opinion, such financial statements present fairly, in all material respects,
      the
      results of the Company’s operations and its cash flows for the period January 1,
      2003 through May 16, 2003, 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 financial
      statements taken as a whole, presents fairly in all material respects the
      information set forth therein.








DELOITTE
      & TOUCHE LLP


Chicago,
      Illinois


March
      13,
      2006











**BOARDWALK
      PIPELINE PARTNERS, LP**





**CONSOLIDATED
      BALANCE SHEETS**


**(Thousands
      of Dollars)**





**December
                31,****ASSETS**
            
            **2005**
            
            **2004**Current
                Assets:Cash
                and cash equivalents
            
            $
            65,792
            
            $
            16,518Receivables,
                net:Trade
            
            
            59,115
            
            
            45,662Other
            
            
            5,564
            
            
            26,978Gas
                Receivables:Transportation
                and exchange
            
            
            29,557
            
            
            34,294Storage
            
            
            12,576
            
            
            13,948Inventories
            
            
            15,881
            
            
            14,182Costs
                recoverable from customers
            
            
            3,560
            
            
            2,611Deferred
                income taxes
            
            
            -
            
            
            13,390Gas
                stored underground
            
            
            6,500
            
            
            3,534Prepaid
                expenses and other current assets
            
            
            7,720
            
            
            7,225Total
                current assets
            
            
            206,265
            
            
            178,342Property,
                Plant and Equipment:Natural
                gas transmission plant
            
            
            1,772,483
            
            
            1,676,729Other
                natural gas plant
            
            
            213,136
            
            
            215,1951,985,619
            
            
            1,891,924Less—accumulated
                depreciation and amortization
            
            
            118,213
            
            
            49,801Property,
                plant and equipment, net
            
            
            1,867,406
            
            
            1,842,123Other
                Assets:Goodwill
            
            
            163,474
            
            
            163,474Gas
                stored underground
            
            
            169,177
            
            
            149,872Deferred
                income taxes
            
            
            -
            
            
            46,206Costs
                recoverable from customers
            
            
            43,960
            
            
            35,984Advances
                to affiliates, non-current
            
            
            -
            
            
            41,812Other
            
            
            15,209
            
            
            14,327Total
                other assets
            
            
            391,820
            
            
            451,675Total
                Assets
            
            $
            2,465,491
            
            $
            2,472,140





The
      accompanying notes are an integral part of these consolidated financial
      statements.











**BOARDWALK
      PIPELINE PARTNERS, LP**





**CONSOLIDATED
      BALANCE SHEETS**


**(Thousands
      of Dollars)**





**December
                31,****LIABILITIES,
                MEMBER’S EQUITY AND PARTNERS’ CAPITAL**
            
            **2005**
            
            **2004**Current
                Liabilities:Payables:Trade
            
            $
            20,433
            
            $
            21,135Affiliates
            
            
            835
            
            
            1,659Other
            
            
            3,681
            
            
            6,251Gas
                Payables:Transportation
                and exchange
            
            
            14,710
            
            
            25,422Storage
            
            
            27,559
            
            
            28,296Accrued
                taxes other
            
            
            16,004
            
            
            10,523Accrued
                interest
            
            
            17,996
            
            
            5,241Accrued
                payroll and employee benefits
            
            
            29,028
            
            
            25,796Current
                note payable
            
            
            42,100
            
            
            -Other
                current liabilities
            
            
            29,941
            
            
            37,733Total
                current liabilities
            
            
            202,287
            
            
            162,056Long
                -Term Debt
            
            
            1,101,290
            
            
            1,106,135Other
                Liabilities and Deferred Credits:Postretirement
                benefits
            
            
            32,413
            
            
            28,001Asset
                retirement obligation
            
            
            14,074
            
            
            3,254Provision
                for other asset retirement
            
            
            33,212
            
            
            29,700Other
            
            
            93,541
            
            
            50,067Total
                other liabilities and deferred credits
            
            
            173,240
            
            
            111,022Commitments
                and Contingencies (Note 3)
            
            
            -
            
            
            -Member’s
                Equity and Partners' Capital:Common
                units - 68,256,122 common units issued and outstanding
            
            
            705,609
            
            
            -Subordinated
                units- 33,093,878 units issued and outstanding
            
            
            266,578
            
            
            -General
                partner's units - 2,068,367 units issued and outstanding
            
            
            16,661
            
            
            -Paid-in
                capital
            
            
            -
            
            
            1,071,651Member’s
                equity
            
            
            -
            
            
            21,276Accumulated
                other comprehensive loss
            
            
            (174
            )
            
            -Total
                member’s equity and partners’ capital
            
            
            988,674
            
            
            1,092,927Total
                Liabilities, Member’s Equity and Partners’ Capital
            
            $
            2,465,491
            
            $
            2,472,140





The
      accompanying notes are an integral part of these consolidated financial
      statements.











**BOARDWALK
      PIPELINE PARTNERS, LP**





**CONSOLIDATED
      STATEMENTS OF INCOME**


**(Thousands
      of Dollars, except earnings per unit and number of units)**





**Boardwalk
                Pipeline Partners**
            
            
            
            **Predecessor****For
                the Year Ended December 31, 2005**
            
            **For
                the Year Ended December 31, 2004**
            
            **For
                the Period May 17 through December 31, 2003**
            
            
            
            **For
                the Period January 1 through May 16, 2003**Operating
                Revenues:Gas
                transportation
            
            $
            526,574
            
            $
            253,488
            
            $
            138,693
            
            
            
            $
            111,622Gas
                storage
            
            
            21,667
            
            
            7,289
            
            
            2,435
            
            
            
            
            814Other
            
            
            12,225
            
            
            2,844
            
            
            1,732
            
            
            
            
            1,011Total
                operating revenues
            
            
            560,466
            
            
            263,621
            
            
            142,860
            
            
            
            
            113,447Operating
                Costs and Expenses:Operation
                and maintenance
            
            
            174,641
            
            
            48,336
            
            
            25,430
            
            
            
            
            16,097Administrative
                and general
            
            
            78,752
            
            
            52,535
            
            
            29,646
            
            
            
            
            13,642Depreciation
                and amortization
            
            
            72,078
            
            
            33,977
            
            
            20,544
            
            
            
            
            16,092Taxes
                other than income taxes
            
            
            27,361
            
            
            19,044
            
            
            10,690
            
            
            
            
            6,077Net
                gain on disposal of operating assets
            
            
            (7,846
            )
            
            -
            
            
            -
            
            
            
            
            (30
            )Total
                operating costs and expenses
            
            
            344,986
            
            
            153,892
            
            
            86,310
            
            
            
            
            51,878Operating
                Income
            
            
            215,480
            
            
            109,729
            
            
            56,550
            
            
            
            
            61,569Other
                (Income) Deductions:Interest
                expense, net
            
            
            58,589
            
            
            29,729
            
            
            19,368
            
            
            
            
            7,392Interest
                income from affiliates
            
            
            (2,186
            )
            
            (375
            )
            
            (21
            )
            
            
            
            (1,965
            )Miscellaneous
                other income
            
            
            (1,444
            )
            
            (783
            )
            
            (352
            )
            
            
            
            (719
            )Total
                other deductions
            
            
            54,959
            
            
            28,571
            
            
            18,995
            
            
            
            
            4,708Income
                before income taxes
            
            
            160,521
            
            
            81,158
            
            
            37,555
            
            
            
            
            56,861Provision
                for income taxes *
            
            
            -
            
            
            -
            
            
            -
            
            
            
            
            22,387Charge-in-lieu
                of income taxes *
            
            
            49,494
            
            
            32,333
            
            
            15,104
            
            
            
            
            -Elimination
                of cumulative deferred taxes *
            
            
            10,102
            
            
            -
            
            
            -
            
            
            
            
            -Net
                Income *
            
            $
            100,925
            
            $
            48,825
            
            $
            22,451
            
            
            
            $
            34,474




*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. Accordingly,
                Boardwalk Pipeline Partners 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 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").  See Note 2 to the
                consolidated financial statements for additional
                information.




Calculation
                of limited partners’ interest in net income:Net
                income to partners (November 15-December 31, 2005)
            
            $
            35,992
            
            
            
            
            
            -Less
                general partner's interest in net income
            
            
            720Limited
                partners’ interest in net income
            
            $
            35,272Net
                income per limited partners’ unit:Common
                units and subordinated units
            
            $
            0.35Weighted-average
                number of limited partners units outstanding:Common
                units
            
            
            68,256,122Subordinated
                units
            
            
            33,093,878





The
      accompanying notes are an integral part of these consolidated financial
      statements.











**BOARDWALK
      PIPELINE PARTNERS, LP**





**CONSOLIDATED
      STATEMENTS OF CASH FLOWS**


**(Thousands
      of Dollars)**





**Boardwalk
                Pipeline Partners**
            
            
            
            **Predecessor****For
                the Year Ended**
              **December
                31, 2005**
            
            **For
                the Year Ended**
              **December
                31, 2004**
            
            **For
                the Period May 17, 2003 through December 31, 2003**
            
            
            
            **For
                the Period January 1, 2003 through**
              **May
                16, 2003**OPERATING
                ACTIVITIES:Net
                income
            
            $
            100,925
            
            $
            48,825
            
            $
            22,451
            
            
            
            $
            34,474Adjustments
                to reconcile to cash providedfrom
                (used in) operations:Depreciation
                and amortization
            
            
            72,078
            
            
            33,977
            
            
            20,544
            
            
            
            
            16,092Amortization
                of acquired executory contracts
            
            
            (9,630
            )
            
            -
            
            
            -
            
            
            
            
            -Provision
                for deferred income taxes
            
            
            54,682
            
            
            43,428
            
            
            19,962
            
            
            
            
            5,494Net
                gain on sale of operating assets
            
            
            (7,846
            )
            
            -
            
            
            -
            
            
            
            
            (30
            )Changes in operating assets and liabilities, net assets and liabilities
                acquired:Receivables
            
            
            (21,147
            )
            
            (9,777
            )
            
            10,378
            
            
            
            
            (27,426
            )Inventories
            
            
            (1,699
            )
            
            (217
            )
            
            73
            
            
            
            
            (22
            )Affiliates
            
            
            (824
            )
            
            (341
            )
            
            473
            
            
            
            
            (7,550
            )Other
                current assets
            
            
            (3,669
            )
            
            6,320
            
            
            (3,126
            )
            
            
            
            5,004Accrued
                income taxes due affiliate
            
            
            -
            
            
            -
            
            
            -
            
            
            
            
            (11,306
            )Accrued
                and deferred income taxes
            
            
            4,908
            
            
            (10,996
            )
            
            (5,347
            )
            
            
            
            -Payables
                and accrued liabilities
            
            
            43,788
            
            
            (9,532
            )
            
            32,474
            
            
            
            
            (4,196
            )Other,
                including changes in noncurrent assets and liabilities
            
            
            (12,852
            )
            
            2,729
            
            
            (36,359
            )
            
            
            
            27,196Net
                cash provided by operating activities
            
            
            218,714
            
            
            104,416
            
            
            61,523
            
            
            
            
            37,730INVESTING
                ACTIVITIES:Capital
                expenditures, net
            
            
            (82,955
            )
            
            (41,920
            )
            
            (34,749
            )
            
            
            
            (43
            )Proceeds
                from sale of operating assets
            
            
            4,725
            
            
            -
            
            
            -
            
            
            
            
            -Proceeds
                from insurance reimbursements
            
            
            4,177
            
            
            -
            
            
            -
            
            
            
            
            -Advances
                to affiliates, net
            
            
            (28,252
            )
            
            (32,194
            )
            
            (3,968
            )
            
            
            
            (37,964
            )Investment
                in Texas Gas
            
            
            -
            
            
            -
            
            
            (803,748
            )
            
            
            
            -Investment
                in Gulf South, net of cash and working capital adjustment
                receivable
            
            
            -
            
            
            (1,111,411
            )
            
            -
            
            
            
            
            -Net
                cash used in investing activities
            
            
            (102,305
            )
            
            (1,185,525
            )
            
            (842,465
            )
            
            
            
            (38,007
            )FINANCING
                ACTIVITIES:Proceeds
                from notes payable
            
            
            42,100
            
            
            -
            
            
            -
            
            
            
            
            -Payments
                of notes payable
            
            
            (250,000
            )
            
            -
            
            
            -
            
            
            
            
            -Proceeds
                from long-term debt
            
            
            569,369
            
            
            575,000
            
            
            706,918
            
            
            
            
            -Payment
                of long-term debt
            
            
            (575,000
            )
            
            (17,285
            )
            
            (407,715
            )
            
            
            
            -Dividends
            
            
            (131,686
            )
            
            (30,000
            )
            
            (20,000
            )
            
            
            
            -Capital
                contribution from parent
            
            
            6,684
            
            
            550,741
            
            
            520,910
            
            
            
            
            -Proceeds
                from sale of common units net of related transaction costs
            
            
            271,398
            
            
            -
            
            
            -
            
            
            
            
            -Net
                cash provided by (used in) financing activities
            
            
            (67,135
            )
            
            1,078,456
            
            
            800,113
            
            
            
            
            -Increase
                (decrease) in cash and cash equivalents
            
            
            49,274
            
            
            (2,653
            )
            
            19,171
            
            
            
            
            (277
            )Cash
                and cash equivalents at beginning of period
            
            
            16,518
            
            
            19,171
            
            
            -
            
            
            
            
            277Cash
                and cash equivalents at end of period
            
            $
            65,792
            
            $
            16,518
            
            $
            19,171
            
            
            
            $
            -





The
      accompanying notes are an integral part of these consolidated financial
      statements.











**BOARDWALK
      PIPELINE PARTNERS, LP**





**CONSOLIDATED
      STATEMENTS OF CHANGES IN STOCKHOLDER’S EQUITY,**


**MEMBER’S
      EQUITY AND PARTNERS’ CAPITAL AND COMPREHENSIVE INCOME**


**(Thousands
      of Dollars, except units)**





**Paid
                in Capital**
            
            **Retained
                Earnings**
            
            **Accumulated
                Other Comp Income (Loss)**
            
            **Comprehensive
                Income**
            
            **Common
                Stock**
            
            **Common
                Units**
            
            **Subordinated
                Units**
            
            **General
                Partner**
              **Units**
            
            **Total
                Partners’ Capital****Predecessor****Balance
                January 1, 2003**
            
            $
            630,608
            
            $
            101,070
            
            
            -
            
            
            -
            
            $
            1
            
            
            -
            
            
            -
            
            
            -
            
            
            -Add
                (deduct):Net
                income
            
            
            -
            
            
            34,474
            
            
            -
            
            $
            34,472
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -Non-cash
                dividend
            
            
            -
            
            
            (29,022
            )
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -**Balance
                May 16, 2003**
            $
            630,608
            
            $
            106,522
            
            
            -
            
            $
            34,472
            
            $
            1
            
            
            -
            
            
            -
            
            
            -
            
            
            -**Boardwalk
                Pipelines, LP****Balance
                May 16, 2003**
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -Add
                (deduct):Capital
                contribution
            
            $
            520,910
            
            
            -
            
            
            -
            
            
            
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -Net
                income
            
            
            -
            
            $
            22,451
            
            
            -
            
            $
            22,451
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -Dividends
                paid
            
            
            -
            
            
            (20,000
            )
            
            -
            
            
            
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -**Balance
                January 1, 2004**
            
            $
            520,910
            
            $
            2,451
            
            
            -
            
            $
            22,451
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -Add
                (deduct):Capital
                contribution
            
            
            550,741
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -Net
                income
            
            
            -
            
            
            48,825
            
            
            -
            
            
            48,825
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -Dividends
                paid
            
            
            -
            
            
            (30,000
            )
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -**Balance
                December 31, 2004**
            
            $
            1,071,651
            
            $
            21,276
            
            
            -
            
            $
            48,825
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -Add
                (deduct):
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            
            -Net
                income
            
            
            -
            
            
            64,933
            
            
            -
            
            
            64,933
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -Capital
                contribution
            
            
            6,684
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -Dividends
                paid
            
            
            -
            
            
            (233,087
            )
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -Other
                comprehensive income, net of tax
            
            
            -
            
            
            -
            
            $
            287
            
            
            287
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -Elimination
                of deferred taxes on accumulated other comprehensive
                income
            
            
            -
            
            
            -
            
            
            64
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -**Balance
                November 15, 2005**
            
            $
            1,078,335
            
            $
            (146,878
            )
            $
            351
            
            $
            65,220
            
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            -**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 2,068,367 general
                partner
                units)
            
            
            -
            
            
            -
            
            $
            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
            )
            
            -
            
            
            -
            
            
            -
            
            
            -
            
            
            (525
            )Net
                income
            
            
            -
            
            
            -
            
            
            -
            
            
            35,992
            
            
            -
            
            
            23,755
            
            
            11,517
            
            
            720
            
            
            35,992**Balance
                December 31, 2005**
            
            
            -
            
            
            -
            
            $
            (174
            )
            $
            35,467
            
            
            -
            
            $
            705,609
            
            $
            266,578
            
            $
            16,661
            
            $
            988,674





The
      accompanying notes are an integral part of these consolidated financial
      statements.











**BOARDWALK
      PIPELINE PARTNERS, LP**





**NOTES
      TO CONSOLIDATED FINANCIAL STATEMENTS**








**Note
      1:  Corporate Structure**








Boardwalk
      Pipeline Partners, LP is a Delaware limited partnership formed in 2005 to own
      and operate the business conducted by Boardwalk Pipelines, LP and its
      subsidiaries, Texas Gas Transmission, LLC and Gulf South Pipeline Company,
      LP.
      The ownership of each of these entities is described below:




•
            “BGL”
                refers to Boardwalk GP, LLC, the general partner of Boardwalk GP;




•
            “Boardwalk
                GP” refers to Boardwalk GP, LP, the general partner of Boardwalk Pipeline
                Partners, LP;




•
            “Boardwalk
                Pipeline Partners” refers to Boardwalk Pipeline Partners,
                LP;




•
            “Boardwalk
                Pipelines” refers to Boardwalk Pipelines, LP (formerly Boardwalk
                Pipelines, LLC);




•
            “BPHC”
                refers to Boardwalk Pipelines Holding Corp, wholly owned by
                Loews;




•
            “Gulf
                South” refers to Gulf South Pipeline Company,
                LP;




•
            “Loews”
                refers to Loews Corporation;




•
            “general
                partner” refers collectively to Boardwalk GP and BGL;
                and




•
            “Texas
                Gas” refers to Texas Gas Transmission,
                LLC.




On
      November 15, 2005, Boardwalk Pipeline Partners sold 15 million common units
      in an underwritten initial public offering (IPO), the net proceeds of which
      were
      approximately $271.4 million. Boardwalk Pipeline Partners used the net proceeds
      from the IPO to repay $250.0 million of indebtedness to Loews, and provide
      $21.4
      million of additional working capital to its subsidiaries. The common units
      sold
      in the IPO represent approximately 14.5% of the outstanding equity of Boardwalk
      Pipeline Partners, which includes common units, subordinated units, and a 2%
      general partner interest. All of the common and subordinated units, other than
      the common units sold in the IPO, are held by BPHC. Boardwalk GP holds the
      2%
      general partner interest and all of the incentive distribution rights. Boardwalk
      Pipeline Partners is traded under the symbol “BWP” on the New York Stock
      Exchange (NYSE).





On
      May
      16, 2003, Boardwalk Pipelines acquired all of the capital stock of Texas Gas
      Transmission Corporation for $804 million, (TG-Acquisition). Texas Gas
      subsequently converted from a corporation to a limited liability company.
      Because Boardwalk Pipeline Partners had no assets or operations prior to
      Boardwalk Pipelines’ acquisition of Texas Gas, the financial statements of Texas
      Gas prior to the formation of Boardwalk Pipelines are presented herein as
      predecessor (Predecessor) financial statements.





On
      December 29, 2004, Boardwalk Pipelines acquired Gulf South from Entergy-Koch,
      LP
      for $1.1 billion, subject to certain working capital adjustments
      (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. The GS-Acquisition was funded with a $575 million term loan
      (Interim Loan) and a capital contribution from BPHC. In January 2005, Gulf
      South
      issued $275 million aggregate principal amount of its 5.05% notes due 2015
      and
      Boardwalk Pipelines issued $300 million aggregate principal amount of its 5.50%
      notes due 2017. The net proceeds of these two offerings were used to repay
      the
      Interim Loan.











**Basis
      of Presentation**





In
      connection with the consummation of the IPO, BPHC contributed all of the equity
      interests of Boardwalk Pipelines to Boardwalk Pipeline Partners. 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 Boardwalk Pipeline Partners subsequent to
      November 15, 2005, as the consolidated results of Boardwalk Pipeline Partners.
      The period prior to 2005 represent the financial position and results of
      Boardwalk Pipelines and the Predecessor. 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 IPO.
      Accordingly, Boardwalk Pipeline Partners 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 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 Elimination of
      cumulative deferred taxes. See Note 2 in these Notes to Consolidated Financial
      Statements for additional information.





As
      discussed above, Boardwalk Pipelines was formed to acquire Texas Gas. Because
      Boardwalk Pipeline Partners had no assets or operations prior to Boardwalk
      Pipelines’ acquisition of Texas Gas, the financial statements of Texas Gas prior
      to the formation of Boardwalk Pipelines are presented herein as Predecessor
      financial statements. The
      Consolidated Statements of Income, Member’s Equity and Cash Flows of Boardwalk
      Pipeline Partners have been separated by a bold black line to separate the
      Predecessor financial statements from those of Boardwalk Pipeline Partners
      subsequent to the TG-Acquisition. The accompanying consolidated financial
      statements of Boardwalk Pipeline Partners and Predecessor were prepared in
      accordance with accounting principles generally accepted in the United States
      of
      America (GAAP).




The
      accompanying financial statements reflect the allocation of the purchase price
      resulting from the TG-Acquisition. An allocation of the purchase price was
      assigned to the assets and liabilities of Texas Gas, based on their estimated
      fair values in accordance with GAAP. As Texas Gas’ rates are regulated by the
      Federal Energy Regulatory Commission (FERC) and FERC does not allow recovery
      in
      rates of amounts in excess of original cost, in accordance with SFAS No. 71, *Accounting
      for the Effects of Certain Types of Regulation* ,
      Texas
      Gas’ historical net book value of regulatory related assets and liabilities are
      considered to be the fair value of those respective assets and liabilities.
      The
      excess purchase price above the historical net book value was allocated to
      goodwill. The accounting for the effects of the TG-Acquisition included
      recognizing unfunded benefit obligations related to postretirement benefits
      other than pensions and pension benefits with a corresponding offset to costs
      recoverable from customers, due to the probable future rate recovery of these
      costs.





Boardwalk
      Pipeline Partners made an allocation of the purchase price in connection with
      the GS-Acquisition for the determination of fair value with respect to PPE,
      as
      well as gas in storage. An allocation of the purchase price, which was finalized
      in December 2005, 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. These adjustments to the purchase price
      in
      2005 included an increase in PPE of $25.8 million, a working capital adjustment
      of $4.7 million and payment of miscellaneous acquisition expenses of $0.2
      million.





As
      discussed in Note 2 herein, Gulf South does not apply the provisions of SFAS
      No.
      71. Accordingly, the purchase price allocation reflected below does not
      necessarily consider the book value of assets and liabilities to be the fair
      value of those respective assets and liabilities.





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 and Texas Gas had been acquired as of the beginning of each period
      presented. The pro forma amounts include certain adjustments, including
      depreciation expense based on the allocation of purchase price to property,
      plant and equipment (PPE); adjustment of interest expense to reflect the
      issuance of debt by Texas Gas, Gulf South and Boardwalk Pipelines; and the
      related tax effect of these items.














**(unaudited)****For
                the Year Ended December 31, 2004**
            
            **For
                the Year Ended December 31, 2003**Operating
                revenues
            
            $
            504,471
            
            $
            468,046Income
                before income taxes
            
            
            121,598
            
            
            75,182Net
                income
            
            
            73,525
            
            
            45,297








The
      pro
      forma information does not necessarily reflect the actual results that would
      have occurred had the companies been combined during the periods presented,
      nor
      is it necessarily indicative of future results of operations.







**Note
      2:  Accounting Policies**








***Principles
      of Consolidation***





The
      Consolidated Financial Statements include Boardwalk Pipeline Partners’ 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, Boardwalk Pipeline Partners evaluates its
      estimates, including those related to revenues subject to refund, bad debts,
      materials and supplies obsolescence, investments, intangible assets, goodwill,
      property and equipment and other long-lived assets, workers' compensation
      insurance, pensions and other post-retirement and employment benefits,
      contingent liabilities and, prior to converting to a limited partnership,
      charge-in-lieu of income taxes. Boardwalk Pipeline Partners bases its estimates
      on historical experience and on various other assumptions that are believed
      to
      be reasonable under the circumstances, the results of which form the basis
      for
      making judgments about the carrying values of assets and liabilities that are
      not readily apparent from other sources. Actual results could differ from such
      estimates.








***Segment
      Information***





Boardwalk
      Pipeline Partners operates in one reportable segment - gas transportation and
      integrated underground gas storage. 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 13,470 miles of pipelines.
      The Predecessor financial statements reflect the results of Texas Gas, which
      also operated as one segment.








***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.











***Cash
      Management***





Under
      the
      cash management program, depending on whether a participating subsidiary has
      short-term cash surpluses or cash requirements, Boardwalk Pipeline Partners
      either provides cash to the subsidiary or the subsidiary provides cash to
      Boardwalk Pipeline Partners.








***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
      Texas Gas and Gulf South 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 services and
      parking and lending (PAL) services. Consistent with the above, 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.
      Additionally, 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. Transportation or contractual imbalances are repaid or recovered
      in
      cash or through the receipt or delivery of gas in the future. Settlement of
      imbalances requires agreement between the pipeline and shippers or operators
      as
      to allocations of volumes to specific transportation contracts and timing of
      delivery of gas based on operational conditions.





The
      accompanying consolidated financial statements reflect the balance of
      underground gas in storage, as well as the resulting activity relating to the
      services and balancing activity described above. Gas stored underground includes
      natural gas volumes owned by the pipelines, reduced by certain operational
      encroachments upon that gas. Since Texas Gas’ rates are regulated by FERC, in
      accordance with SFAS No. 71  Texas
      Gas
      records Gas stored underground at historical cost. For Gulf South, the carrying
      value of noncurrent Gas stored underground, exclusive of operational
      encroachments, is recorded at historical cost including certain purchase
      accounting adjustments required by GAAP. 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 delivering gas.





Gas
      receivables and payables represent certain amounts attributable to system
      balancing and storage related tariff services. As discussed above, imbalances
      arise in the normal course of providing transportation and storage services
      to
      customers. Gas receivables and payables include volumes receivable from or
      payable to third parties in connection with the imbalance activity. 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 also reflect certain amounts of customer-owned gas
      at
      the Texas Gas facilities. Consistent with certain regulatory treatment
      prescribed by FERC as a result of 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. The gas payables amount was valued at the historical cost of gas
      consistent with other Texas Gas balances, and was $34.8 million and $29.8
      million at December 31, 2005 and 2004, respectively. Boardwalk Pipeline Partners
      does not reflect volumes held by Gulf South on behalf of others on its
      Consolidated Balance Sheets. As of December 31, 2005 and 2004, Gulf South held
      32.9 billion cubic feet (Bcf) and 52.7 Bcf of gas owned by shippers,
      respectively and had loaned 0.1 Bcf and 2.2 Bcf of gas to shippers,
      respectively.





Average
      natural gas prices have increased dramatically in recent years. This rise in
      gas
      prices has materially increased credit risk related to gas loaned to customers.
      The amount of gas loaned out over the past 24 months at any one time to
      customers has ranged from a high of approximately 38 Bcf at April 30, 2005,
      to a
      low of approximately 4 Bcf at December 31, 2005. Assuming an average market
      price during December 2005 of $12.34 per million British thermal units (MMBtu),
      the market value of gas loaned out at December 31, 2005, would have been
      approximately $49.4 million. As of February 28, 2006, the amount of gas loaned
      out was approximately 18 Bcf and, assuming an average market price during
      February 2006 of $7.30 per MMBtu, the market value of that gas would be
      approximately $131.4 million. If any significant customer should have credit
      or
      financial problems resulting in a delay or failure to repay the gas they owe
      Boardwalk Pipeline Partners, this could have a material adverse effect on its
      financial condition, results of operations and cash flows.











***Derivative
      Financial Instruments***





In
      accordance with the Gulf South’s risk management policy, Gulf South utilizes
      natural gas futures, swap, and option contracts (collectively, “hedge
      contracts”) to hedge certain exposures to market price fluctuations on Gulf
      South’s anticipated purchases and sales of gas and anticipated cash for fuel
      reimbursement related to transportation revenues. These hedge contracts are
      reported at fair value in accordance with SFAS No. 133, “ *Accounting
      for Derivative Instruments and Hedging Activities”* as
      amended As of December 31, 2005, Gulf South had a liability of approximately
      $0.8 million related to the hedge contracts included in Other current
      liabilities and no related liability as of December 31, 2004. As of December
      31,
      2005 and 2004, Gulf South had an asset of approximately $0.6 million and $0.3
      million, respectively related to the hedge contracts included in Prepaid
      expenses and other current assets on the Consolidated Balance Sheets. As of
      December 31, 2005, Gulf South had a deferred loss on cash flow hedges in
      Accumulated other comprehensive loss of $0.2 million. As of December 31,
      2004, there was no deferred loss on cash flow hedges. Gulf South expects to
      reclassify the entire amount of accumulated other comprehensive loss to earnings
      by December 31, 2006.





The
      changes in fair value of the hedge contracts are expected to, and do, have
      a
      high correlation to changes in the anticipated purchase and sales prices of
      gas
      and therefore qualify for hedge accounting under SFAS No. 133. In addition,
      if
      the hedge contracts cease to have high correlation or if the anticipated
      purchase or sale is deemed no longer probable to occur, hedge accounting is
      terminated and the associated changes in the fair value of the derivative
      financial instruments are recognized in the related period on the Consolidated
      Statements of Income.  No cash flow hedges were discontinued during 2005.
      The related gains and losses derived from changes in the fair value of hedge
      contracts are deferred as a component of Accumulated other comprehensive loss.
      These deferred gains and losses are recognized in the Consolidated Statements
      of
      Income when the hedged anticipated purchases or sales affect earnings. However,
      to the extent that the change in the fair value of the hedge contracts does
      not
      effectively offset the change in the fair value of the anticipated purchases
      or
      sales, the ineffective portion of the hedge contracts is immediately recognized.
      No ineffectiveness was recorded during 2005. During 2005, Gulf South
      reclassified approximately $2.6 million loss from Accumulated other
      comprehensive income, as a result of the hedged transactions affecting earnings.
      Additionally during 2005, Boardwalk Pipeline Partners recorded approximately
      $2.7 million as the change in the value of hedge contracts in Accumulated other
      comprehensive income.





***Property,
      Plant and Equipment***





PPE
      is
      recorded at its original cost of construction or fair value of the assets
      acquired. For Texas Gas, PPE as of the date of the TG-Acquisition is reflected
      at its historical cost. PPE as of the date of the GS-acquisition at Gulf South
      has been reflected at estimated fair value, consistent with the results of
      an
      appraisal. Construction costs and expenditures for major renewals and
      improvements, which extend the lives of the respective assets, are capitalized.




Boardwalk
      Pipeline Partners 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.




Texas
      Gas’ depreciation is provided primarily on the straight-line method at
      FERC-prescribed rates over estimated useful lives of 5 to 56 years. Reflecting
      the application of composite depreciation, gains and losses from the ordinary
      sale and retirement of PPE generally do not impact net PPE on the Texas Gas
      system. Gulf South depreciates assets using the straight line method of
      depreciation over the respective 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. Boardwalk Pipeline Partners’ depreciation
      and amortization expense for the years ended December 31, 2005 and 2004, was
      $72.1 million, $34.0 million, $20.5 million for post-TG-Acquisition in 2003
      and
      the Predecessor recorded $16.1 million in 2003.











The
      following table represents Boardwalk Pipeline Partners’ PPE as of December 31,
      2005 and 2004 (expressed in thousands):




**Category**
              
              **2005
                  Class Amount**
              
              **Weighted-Average
                  Useful Lives (Years)**
              
              **2004
                  Class Amount**
              
              **Weighted-Average
                  Useful Lives (Years)**Depreciable
                  plant:Intangible
              
              $
              10,776
              
              
              30
              
              $
              12,890
              
              
              23Gathering
              
              
              88,852
              
              
              19
              
              
              91,330
              
              
              19Storage
              
              
              155,717
              
              
              46
              
              
              129,294
              
              
              50Transmission
              
              
              1,484,901
              
              
              42
              
              
              1,407,055
              
              
              43General
              
              
              64,548
              
              
              19
              
              
              47,081
              
              
              19Total
                  utility depreciable plant
              
              
              1,804,794
              
              
              41
              
              
              1,687,650
              
              
              41Non-depreciable:Land
              
              
              9,470
              
              
              
              
              
              9,318Storage
              
              
              85,393
              
              
              
              
              
              94,258Other
              
              
              85,962
              
              
              
              
              
              100,698Total
                  other
              
              
              180,825
              
              
              
              
              
              204,274Total
                  PPE
              
              
              1,985,619
              
              
              
              
              
              1,891,924Less:
                  accumulated depreciation
              
              
              118,213
              
              
              
              
              
              49,801Total
                  PPE, net
              
              $
              1,867,406
              
              
              
              
              $
              1,842,123




The
      non-transmission assets have weighted-average useful lives of 33 years as of
      December 31, 2005 and 2004. The gross non-transmission asset value was $309.4
      million and $280.6 million as of December 31, 2005 and 2004, respectively.
      The
      non-depreciable assets and work in progress of $257.7 million and $204.3 million
      as of December 31, 2005 and 2004, respectively are not included in the
      calculation of the weighted-average useful lives.








***Impairment
      of Goodwill***




As
      part
      of the allocation of the purchase price of the TG-Acquisition, the excess
      purchase price over the fair value of the assets and liabilities was allocated
      to 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 annual impairment test is performed on December 31.





Judgments
      and assumptions are inherent in management’s estimate of undiscounted future
      cash flows used to determine recoverability of an asset and the estimate of
      an
      asset’s fair value used to calculate the amount of impairment to recognize. The
      use of alternate judgments and/or assumptions could result in the recognition
      of
      different levels of impairment charges in the financial statements.





The
      purchase price allocation for the TG-Acquisition reflects the underlying
      assumption that the historical net book value of regulatory related assets
      and
      liabilities are considered to be the fair value of those respective assets
      and
      liabilities. The excess purchase price over the fair value of the assets and
      liabilities was allocated to goodwill. Texas Gas used a discounted cash flow
      model to estimate the fair value of its reporting unit, and that estimated
      fair
      value was compared to its carrying amount, including goodwill. The estimated
      fair value was in excess of the carrying amount at December 31, 2005, and
      therefore, resulted in no impairment.











***Advances
      to Affiliates***





Boardwalk
      Pipeline Partners makes advances to its subsidiaries and BPHC. It also receives
      advances from its subsidiaries. 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 each three-month period.








***Regulatory
      Accounting***





Texas
      Gas
      and Gulf South are regulated by FERC. SFAS No. 71 requires that rate-regulated
      public utilities 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 capitalized as regulatory
      assets and liabilities, respectively, 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 often results in discounts from the maximum allowable
      cost-based rate such that SFAS No. 71 is not appropriate. Therefore, Gulf South
      does not record any regulatory assets or liabilities.





Boardwalk
      Pipeline Partners monitors the regulatory and competitive environment in which
      it operates to determine that the regulatory assets recorded at Texas Gas
      continue to be probable for recovery. If Boardwalk Pipeline Partners were to
      determine that all or a portion of these regulatory assets no longer met the
      criteria for continued application of 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. The pipelines have various mechanisms whereby
      rates or surcharges are established and revenues are collected and recognized
      based on estimated costs. None of the regulatory assets shown below were earning
      a return as of December 31, 2005 and 2004.





The
      amounts recorded as regulatory assets and liabilities in the Consolidated
      Balance Sheets as of December 31, 2005 and 2004, are summarized as follows
      (shown in thousands):




**2005**
            
            **2004**Regulatory
                Assets:Pension
            
            $
            3,841
            
            $
            128Tax
                effect of AFUDC equity
            
            
            7,236
            
            
            6,526Unamortized
                debt expense and premium on reacquired debt
            
            
            12,701
            
            
            13,699Postretirement
                benefits other than pension
            
            
            33,156
            
            
            32,374Fuel
                tracker
            
            
            2,005
            
            
            -Imbalances/storage
                valuation tracker
            
            
            1,283
            
            
            -Gas
                supply realignment costs
            
            
            -
            
            
            (432
            )Total
                regulatory assets
            
            $
            60,222
            
            $
            52,295





Regulatory
                Liabilities:Fuel
                tracker
            
            
            -
            
            $
            917System
                management/cashout tracker
            
            
            -
            
            
            77Provision
                for asset retirement
            
            $
            33,212
            
            
            29,700Unamortized
                discount on long-term debt
            
            
            (2,024
            )
            
            (2,198
            )Total
                regulatory liabilities
            
            $
            31,188
            
            $
            28,496







The
      tax
      effect of allowance for funds used during construction (AFUDC) equity represents
      amounts recoverable from rate payers for the tax effects created prior to the
      change in Boardwalk Pipelines' tax status. The table above 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’ embedded cost of debt financing utilized in its rate proceedings.
      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.











***Excise
      Taxes***





Boardwalk
      Pipeline Partners may collect from customers certain excise taxes imposed by
      state or local governments upon customers. These amounts do not impact the
      Consolidated Statements of Income and are accumulated as a liability until
      remitted to the state or local taxing authority.








***Acquired
      Executory Contracts***




As
      a
      result of the GS-Acquisition, Boardwalk Pipeline Partners acquired certain
      shipper contracts at fair value.  The below market valuation balance of
      $5.3 million as of December 31, 2005, included $4.0 million as a component
      of
      Other current liabilities and $1.3 million as a component of Other liabilities
      and deferred credits.  These credits will be amortized over the life of the
      shipper contracts ranging from three months to three years. Amortization during
      year 2005 was $9.6 million. Amortization for the next three years is reflected
      below (expressed in millions):




2006
            $
                4.02007
            1.12008
            0.2





***Asset
      Retirement Obligations***





Boardwalk
      Pipeline Partners follows SFAS No. 143, *Accounting
      for Asset Retirement Obligations* ,
      which
      addresses accounting and reporting for legal asset retirement obligations (AROs)
      associated with the retirement of long-lived assets. SFAS No. 143 requires
      entities to record the fair value of a liability for an ARO during the period
      in
      which the liability is incurred, if a reasonable estimate of fair value can
      be
      made.  The liability is reported at fair value and is adjusted in
      subsequent periods as accretion expense is recorded. 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.





Texas
      Gas’ depreciation rates for utility plant are approved by FERC.  The
      approved depreciation rates are comprised of two types: one based on economic
      service life (capital recovery) and one based on net costs of removal (negative
      salvage). Therefore, Texas Gas accrues estimated net costs of removal of
      long-lived assets through negative salvage expense. Accordingly, Texas Gas
      collects a certain amount in rates representing estimated costs of removal,
      which do not represent a legal obligation. Boardwalk Pipeline Partners has
      reclassified $33.2 million and $29.7 million as of December 31, 2005 and 2004,
      respectively in the accompanying Consolidated Balance Sheets as Provision for
      other asset retirement.





Boardwalk
      Pipeline Partners 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, Boardwalk Pipeline Partners has a legal obligation to cut
      and purge any pipeline that will remain in place after abandonment and to remove
      offshore platforms once gas flow has ceased. Abatement of asbestos consists
      of
      removal, transportation and disposal. Furthermore, legal obligations exist
      for
      certain other Boardwalk Pipeline Partners' utility assets; however,
      the fair value of the obligations cannot be determined because the end of the
      utility system life is potentially indefinite and therefore cannot be estimated
      with the degree of accuracy necessary to establish a liability for the
      obligations.





The
      table
      below summarizes the aggregate carrying amount of AROs as follows (expressed
      in
      thousands):





Balance
                at beginning of year
            $
                3,254Liabilities
                recorded
            10,593Liabilities
                settled
            (417)Accretion
                expense
            644Balance
                at end of year
            $
                14,074











In
      March
      2005, Financial Accounting Standards Board (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. The Interpretation is effective for fiscal years ending
      after December 15, 2005. In light of this interpretation, Boardwalk Pipeline
      Partners believes that an ARO exists for Texas Gas’ corporate office building
      constructed in Owensboro, Kentucky, in 1962. Under the legal requirements
      enacted by the Environmental Protection Agency (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, following written maintenance
      procedures. Boardwalk Pipeline Partners anticipates that the fair
      value of any liability relating to the remediation referred to above is not
      material to the financial position, results of operations or cash flows.
      Additionally, Boardwalk Pipeline Partners believes that should any
      costs be incurred for this remediation, it would have the opportunity to collect
      such amounts from rate-payers with no impact on the results of
      operations.








***Unit-Based
      Compensation***





In
      December 2004, the FASB issued SFAS No. 123R, *Share-Based
      Payment,* which
      establishes standards for the accounting of transactions in which an entity
      exchanges its equity instruments for goods or services, primarily focusing
      on
      accounting for transactions where an entity obtains employee services in
      share-based payment transactions. SFAS No. 123R requires a public entity to
      measure the cost of employee services received in exchange for an award of
      equity instruments, including stock options, 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. Boardwalk Pipeline Partners adopted SFAS 123R during 2005 due
      to
      the adoption of the Long-Term Incentive Plan in 2005. There were no previous
      employee unit-based compensation plans.





In
      February 2006, FAS 123(R)-4 amended FASB SFAS 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. Boardwalk
      Pipeline Partners applied the principles of FAS 123(R)-4 in conjunction with
      the
      adoption of FAS No. 123(R) having no material impact on its financial
      condition, results of operations, or cash flows. For further detailed discussion
      of Boardwalk Pipeline Partners’ Long-Term Incentive Plan, see Note 5 of these
      Notes to Consolidated Financial Statements.




***Revenue
      Recognition***





The
      maximum rates that may be charged by Texas Gas and Gulf South for their gas
      transportation and storage services are established through FERC rate-making
      purposes. Rates charged by Texas Gas and Gulf South may be less than those
      allowed by FERC due to discounts. 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 contract. Texas Gas is subject to FERC regulations and,
      accordingly, certain revenues collected may be subject to possible refunds
      upon
      final orders in pending cases. Texas Gas estimates rate refund liabilities
      considering its own and third-party regulatory proceedings, advice of counsel
      and estimated total exposure. As of December 31, 2005, an estimated refund
      liability of approximately $5.0 million related to Texas Gas’ open general rate
      case filed on April 29, 2005, was recorded on the Consolidated Balance
      Sheets. Texas Gas anticipates that the general rate case will be settled and
      all
      required refunds will be paid during 2006.





Retained
      fuel is a component of Gulf South’s tariff structure and is recognized at market
      prices in the month of retention. Customers may also elect to pay cash for
      fuel,
      instead of having fuel retained in-kind. Transportation revenue recognized
      from
      retained fuel for the year ended December 31, 2005, was $86.7
      million.





Boardwalk
      Pipeline Partners has deferred revenue of $1.0 million at December 31, 2005,
      related to the fair value of prepaid PAL services to be provided through 2006.
      Revenue deferred at year end will be recognized when the services are provided.
      All deferred revenue as of December 31, 2005, will be recognized during
      2006.











***Accounts
      Receivable***





Accounts
      receivable are stated at the historical carrying amount net of reserves or
      write-offs. Boardwalk Pipeline Partners establishes an allowance for doubtful
      accounts receivable on a case-by-case basis when it believes the required
      payment of specific amounts owed is unlikely to occur. Uncollectible accounts
      receivable are written off when a settlement is reached for an amount that
      is
      less than the outstanding historical balance.











***Repair
      and Maintenance Costs***





Texas
      Gas
      and Gulf South account for repair and maintenance costs under the guidance
      of
      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***





The
      allowance for funds used during construction represents the cost of funds
      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 reduces interest expense and the
      allowance for equity funds is included in Miscellaneous other income within
      the
      Consolidated Statements of Income. The table below summarizes the allowance
      for
      borrowed funds and the allowance for equity funds used during construction
      as
      follows (expressed in millions):





**Boardwalk
                Pipeline Partners**
            
            
            
            **Predecessor****For
                the Year Ended**
              **December
                31, 2005**
            
            **For
                the Year Ended**
              **December
                31, 2004**
            
            **May
                17, 2003 through**
              **December
                31, 2003**
            
            
            
            **January
                1, 2003**
              **through**
              **May
                16,****2003**Allowance
                for borrowed funds used during construction and capitalized interest
            $
                0.7
            
            $
                0.3
            
            $
                0.3
            
            
            
            -Allowance
                for equity funds used during construction
            1.4
            
            0.8
            
            0.7
            
            
            
            $
                0.2








***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.





Prior
      to
      November 15, 2005, Boardwalk Pipelines recorded charge-in-lieu of income taxes
      pursuant to GAAP. In conjunction with the IPO, Boardwalk Pipelines converted
      from a limited liability company to a limited partnership. As such, subsequent
      to November 15, 2005, Boardwalk Pipeline Partners and its subsidiaries will
      no
      longer record a charge-in-lieu of income taxes. Additionally, all deferred
      income taxes included on the Consolidated Balance Sheets as of November 15,
      2005, have been reversed through the Consolidated Statements of
      Income.





Prior
      to
      the TG-Acquisition, the Predecessor was included in the consolidated federal
      income tax return of Williams. It was Williams’ policy to charge or credit the
      Predecessor with an amount equivalent to its federal income tax expense or
      benefit as if the Predecessor filed a separate return.





Prior
      to
      operating as a limited partnership, for federal income tax reporting, Boardwalk
      Pipelines was included in the consolidated federal income tax return of Loews.
      The tax sharing agreement with Loews required Boardwalk Pipelines to remit
      to
      Loews on a quarterly basis any charges-in-lieu of federal income taxes as if
      it
      were filing a separate return.








***Cash
      Flows from Operating Activities***





Boardwalk
      Pipeline Partners 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.











***Capital
      Structure***





In
      connection with the consummation of the IPO, Boardwalk Pipeline Partners and
      its
      affiliates effected a number of additional 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 Boardwalk Pipeline
                Partners;




•
            Boardwalk
                Pipeline Partners’ reimbursement of BPHC for $42.1 million of capital
                expenditures it incurred in connection with the acquisition of Gulf
                South;




•  the
      assumption by Boardwalk Pipeline Partners of $250.0 million of indebtedness
      to
      Loews from BPHC;




•
            the
                issuance by Boardwalk Pipeline Partners of 53,256,122 common units,
                33,093,878 subordinated units, representing an 83.5% limited partnership
                interest in Boardwalk Pipeline Partners, to BPHC;
                and




•
            the
                issuance by Boardwalk Pipeline Partners of a 2% 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 as
      follows:





•
            to
                repay the $250.0 million of indebtedness that Boardwalk Pipeline
                Partners
                assumed from BPHC in connection with the contribution of its interest
                in
                Boardwalk Pipeline Partners, and




•
            provide
                approximately $21.4 million in additional working capital for Boardwalk
                Pipeline Partners.





For
      purposes of maintaining the capital accounts and in determining the rights
      of
      the partners among themselves, the items of income and loss of Boardwalk
      Pipeline Partners shall be allocated among the partners in each taxable year,
      or
      portion thereof. After giving effect to certain special allocations, net income
      for each taxable year and all items of income, gains, loss and deductions taken
      into account in computing net income for such taxable year shall be allocated
      as
      follows:




(i)
            First,
                100% to the General Partner, in an amount equal to the aggregate
                net
                losses allocated to the General Partner for all taxable years until
                the
                aggregate net income allocated to the General Partner for the current
                taxable year and all previous taxable years is equal to the net losses
                allocated to the General Partner for all previous taxable years;




(ii)
            Second,
                100% of the unitholders, in accordance with their respective percentage
                interests, until the aggregate net income allocated to such Partners
                for
                the current taxable year and all previous taxable years is equal
                to the
                aggregate net losses allocated to such Partners for all previous
                taxable
                years; and




(iii)
            Third,
                the balance, if any, 100% to the unitholders, in accordance with
                their
                respective percentage interests. After giving effect to certain special
                allocations, net losses for each taxable period and all items of
                income,
                gain, loss and deduction taken into account in computing net losses
                for
                such taxable period shall be allocated as follows:




a)
            First,
                100% to the unitholders, in accordance with their respective percentage
                interests, until the net losses allocated for the current taxable
                year and
                all previous taxable years is equal to the aggregate net income allocated
                to such Partners for all previous taxable years, provided that the
                net
                losses shall not be allocated to the extent that such allocations
                would
                cause any unitholder holding Limited Partner Units to have a deficit
                balance to its adjusted capital account at the end of such taxable
                year;




b)
            Second,
                100% to the unitholders, in accordance with their respective percentage
                interests, provided, that net losses shall not be allocated to the
                extent
                that such allocation would cause any unitholders holding Limited
                Partner
                Units to have a deficit balance in its adjusted capital account at
                the end
                of such taxable year; and




c)
            Third,
                the balance of any, 100% to the General
                Partner.











***Cash
      Distribution Policy***





Boardwalk
      Pipeline Partners’ cash distribution policy reflects a basic judgment that
      unitholders will be better served by Boardwalk Pipeline Partners’ distribution
      of available cash surplus rather than them retaining it. The cash distribution
      policy is consistent with the terms of its partnership agreement which requires
      Boardwalk Pipeline Partners to distribute “available cash,” as that term is
      defined in the partnership agreement, to unitholders on a quarterly basis.





There
      is
      no guarantee that unitholders will receive quarterly distributions from
      Boardwalk Pipeline Partners. Its distribution policy may be changed at any
      time
      and is subject to certain restrictions or limitations, including, among others,
      its general partner’s broad discretion to establish reserves which could reduce
      cash available for distributions, FERC regulations which places restrictions
      on
      various types of cash management programs employed by companies in the energy
      industry, including Texas Gas and Gulf South, the requirements of applicable
      state partnership and limited liability company laws, and the requirements
      of
      the revolving credit facility which would prohibit Boardwalk Pipeline Partners
      from making distributions to unitholders if an event of default were to occur.


In
        March
        2004, Emerging Issues Task Force issued Issue *No. 03-6 (EITF 03-6). Participating Securities and the Two-Class method
        under FASB Statement No. 128.* EITF
        03-6 addresses a number of questions regarding the computation of earnings
        per
        unit by companies that issued securities, other than common stock , that
        contractually entitle the holder to participate in dividends and earnings
        of the
        company when, and if, it declares dividends on its common stock. The EITF
        also
        gives guidance in applying the two-class method of calculating earnings per
        unit, clarifying what constitutes a participating security and how to apply
        the
        two-class method of computing earnings per unit once it is determined that
        a
        security is participating, including how to allocate undistributed earnings
        to
        such a security. EITF 03-6 was effective for fiscal periods beginning after
        March 31, 2004. There was no impact on earnings per limited partner unit
        in the
        periods presented due to the adoption of EITF 03-6. The incentive distribution
        rights qualify as partner securities under EITF-03-6 and, as such, certain
        earnings may be allocated to these incentive distributions rights in the
        future.
        EITF 03-6 may have an impact on earnings per limited partner unit in future
        periods if net income exceeds distributions or if other participating securities
        are issued.








***Reclassifications***





Certain
      reclassifications have been made in the 2004 and 2003 financial statements
      to
      conform to the 2005 presentation.





**Note
      3:  Commitments and
      Contingencies**








**Impact
      of Hurricanes Katrina and Rita**





In
      late
      August and September 2005, Hurricanes Katrina and Rita and related storm
      activity, such as windstorms, storm surges, floods and tornadoes, caused
      extensive and catastrophic physical damage in and to the offshore, coastal
      and
      inland areas located in the Gulf Coast region of the United States, specifically
      parts of Louisiana, Mississippi and Alabama. 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.




Gulf
      South experienced damage to gas metering facilities, cathodic protection
      devices, communication devices, rights of way and other above ground facilities
      such as office buildings and signage. Texas Gas experienced only minimal damage.
      The pipelines continued to operate throughout the Hurricanes and thereafter,
      and
      the vast majority of service to customers was not interrupted. The cost of
      damages is not expected to exceed $17.1 million which reflects anticipated
      replacement, repair, and cleanup costs based upon current estimates. $13.6
      million is included in the 2005 Consolidated Statements of Income related to
      these two Hurricanes, primarily for operations and maintenance costs. However,
      after a complete assessment of the extent of the damages caused by and the
      repairs, cleanup, lost gas and other storm-related expenditures relating to
      the
      Hurricanes, including the possible relocation of pipeline facilities, the total
      cost of damages could be higher than its current estimates. While Gulf South
      anticipates coverage for a substantial portion of the costs by insurance
      carriers after meeting certain deductibles, Gulf South has not recorded any
      anticipated insurance recovery to date as the claims process is in its early
      stage, and the insurance carriers have not taken a definitive coverage position
      on each aspect of the claim to record such anticipated receipts.











**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 two Hurricane Katrina-related class action
      lawsuits seeking an unspecified amount of damages. The lawsuits were filed
      in
      the United States District Court for the Eastern District of Louisiana. The
      lawsuits allege that the dredging of canals, including pipeline canals for
      the
      purpose of installing natural gas pipelines, throughout the marshes of
      Southeastern Louisiana, and the failure to maintain such 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. These cases are in a very early stage and, as such, Boardwalk Pipeline
      Partners cannot reasonably estimate the amount of loss, if any.





Although
      Boardwalk Pipeline Partners does not currently anticipate that the overall
      impact of Hurricanes Katrina and Rita will have a material adverse effect upon
      its future financial condition, results of operations or cash flows, in light
      of
      the magnitude of the damage caused by the Hurricanes and the enormity of the
      relief and reconstruction effort, substantial uncertainty remains as to the
      ultimate impact on its business, financial condition and results of operations
      in the near or long term. The reconstruction of the Gulf Coast region is in
      the
      early planning stages and the implementation and success of these plans are
      outside Boardwalk Pipeline Partners’ control.








***Calpine
      Bankruptcy***





On
      December 20, 2005, Calpine Corporation (Calpine) filed a voluntary petition
      in the United States Bankruptcy Court for the Southern District of New York
      in
      Manhattan seeking reorganization under the provisions of Chapter 11 of the
      United States Bankruptcy Code.  Calpine continues to operate its business
      as a debtor-in-possession under the jurisdiction of the bankruptcy court and
      in
      accordance with the applicable provisions of the Bankruptcy Code and the orders
      of the bankruptcy court. As of the petition date, Calpine owed Boardwalk
      Pipeline Partners an immaterial amount for services.   However, Gulf
      South has firm contracts with Calpine that extend through May 2023.  It is
      uncertain whether Calpine will accept or reject these firm contracts at this
      time.  The pre-petition amount was immaterial and should not have a
      material impact on Boardwalk Pipeline Partners’ financial position, results of
      operations or cash flows.








***Napoleonville
      Salt Dome Matter***





On
      or
      about December 24, 2003, natural gas leaks were observed at the surface near
      two
      natural 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 have been filed to date relating to this incident; a
      declaratory judgment action has been filed and stayed against Gulf South by
      the
      lessor of the property, and several individual actions have been filed against
      Gulf South and other defendants by local residents and businesses. Gulf South
      has been informed by plaintiff’s counsel in the two class action lawsuits that
      they intend to convert the class actions lawsuits into individual actions.
      Pleadings to institute such a change in status have been circulated in one
      of
      the cases. Gulf South intends to vigorously defend each of these actions;
      however, it is not possible to predict the outcome of this litigation.
      Litigation is subject to many uncertainties, and it is possible that these
      actions could be decided unfavorably. Gulf South may enter into discussions
      in
      an attempt to settle particular cases if Gulf South believes it is appropriate
      to do so. This lease was terminated during 2005.




For
      the
      period from the date of acquisition of Gulf South through December 31, 2005,
      Gulf South incurred $4.7 million for remediation costs, root cause
      investigation, and legal fees and had an accrual balance at December 31, 2005
      and 2004, of $1.1 million and $2.5 million, respectively, in Other liabilities
      on the Consolidated Balance Sheets pertaining to this 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, but to date its insurance carriers have not taken any definitive
      coverage positions on each of the issues raised in the various lawsuits. For
      the
      year ended December 31, 2005, Gulf South received $0.2 million insurance
      reimbursement for legal expenses. The total range of loss related to this
      incident could not be estimated at December 31, 2005.














***Other
      Legal Matters***





Boardwalk
      Pipeline Partners, together with its subsidiaries, are parties to various legal
      actions arising in the normal course of business. Management believes that
      the
      disposition of outstanding legal actions will not have a material adverse impact
      on its future financial condition, results of operations or cash flows.




In
      connection with the acquisition of Texas Gas, 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;
                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. On April 18, 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. The lawsuit has moved into the next phase for determination
                of
                whether various legal and equitable defenses to plaintiff’s ownership are
                applicable.





As
      a
      result, Williams continues to defend these actions on behalf of Boardwalk
      Pipeline Partners and Texas Gas. Because Williams has retained responsibility
      for these claims, they are not expected to have a material effect upon Boardwalk
      Pipeline Partners’ future financial condition, results of operations or cash
      flows.








**Regulatory
      and Rate Matters**








***Expansion
      Projects***





*East
      Texas and Mississippi Pipeline Expansion.* In
      February and March of 2006, Gulf South entered into long-term agreements with
      customers providing firm commitments for capacity on its 1.5 Bcf per day
      pipeline expansion projects in East Texas and Mississippi. Boardwalk Pipeline
      Partners expects the total cost for the 1.5 Bcf expansion to be approximately
      $800 million, and expects the new capacity to be in service during the second
      half of 2007.




The
      East
      Texas pipeline expansion will extend from Carthage in East Texas to the
      Perryville area in Richland Parish, Louisiana. Natural gas originating primarily
      from the prolific Barnett Shale and Bossier Sands producing regions of East
      Texas will be transported to interstate pipelines serving markets in the Midwest
      and Northeast, including Texas Gas, MRT, Tennessee, ANR, Columbia Gulf and
      Southern Natural. The Mississippi pipeline expansion will continue eastward
      from
      the Perryville area to the Jackson, Mississippi area and will provide additional
      supplies to customers in the Northeast and Southeast through interconnects
      with
      interstate pipelines serving those markets, including Texas Eastern, Transco,
      Southern Natural and Florida Gas, and to customers in the Baton Rouge - New
      Orleans industrial complex.





These
      projects are subject to FERC approvals. Gulf South will submit separate
      applications to FERC for authority to construct the East Texas and Mississippi
      expansion projects. In February 2006, FERC granted Gulf South's request to
      initiate the pre-filing process for the East Texas expansion.





*Western
      Kentucky Storage Expansion.* In
      November 2005, Texas Gas completed the expansion of its western Kentucky storage
      complex by approximately 8 Bcf of working gas, which allows for the additional
      withdrawal of approximately 82 million cubic feet (MMcf)/day, and contracted
      with customers for that new capacity at maximum rates for five years. In
      addition, Texas Gas has accepted commitments from customers for incremental
      no-notice service (NNS) and firm storage service that will allow it to further
      expand the working gas in this storage complex by approximately 9 Bcf, subject
      to FERC approval. Boardwalk Pipeline Partners expects this second storage
      expansion to go into service in late 2007. In
      conjunction with the 2005 storage expansion mentioned above, Texas Gas sold
      3.3
      Bcf of storage gas to one of the customers that had contracted for the new
      firm
      storage service. A one time gain on the sale of this gas of $12.2 million was
      recorded in November 2005 as a Gain on disposal of operating assets in the
      Consolidated Statements of Income.











*East
      Texas Lease Arrangement.* In
      December 2005, Texas Gas initiated service under a lease arrangement which
      allowed it to tie in 100 MMcf/day of supply from the growing Barnett Shale
      production area in East Texas to the Texas Gas system at Sharon, Louisiana,
      using existing pipeline infrastructure.





*Magnolia
      Storage Facility.* Gulf
      South has leased a gas storage facility, which it refers to as the Magnolia
      facility, near Napoleonville, Louisiana, at which it has installed two
      compressor stations, with a combined horsepower of 9,470, and other storage
      infrastructure and is currently developing a high-deliverability storage cavern
      that, when operational, may add up to approximately 5 Bcf of working gas storage
      capacity. Magnolia’s storage capacity is expected to be in service and available
      for sale at market-based rates in late 2008 or early 2009, subject to the
      operational requirements of the lessor.











***General
      Rate Case***





On April
      29, 2005, Texas Gas filed a general rate case. The rate case reflects a
      requested increase in annual cost of service from $258.0 million to $300.0
      million, primarily attributable to increases in the utility rate base, operating
      expenses, rate of return and related taxes.  On May 31, 2005, FERC issued
      an order (the Suspension Order) accepting and suspending the filed rates to
      become effective November 1, 2005, subject to refund, in the event lower rates
      are finally established in the rate case. The Suspension Order set the rate
      case
      for a hearing before an administrative law judge. Texas Gas began collecting
      its
      new rates, subject to refund, on November 1, 2005. Texas Gas and the other
      participants (FERC staff and customers) have been conducting informal settlement
      negotiations. As a result of these negotiations, the procedural schedule in
      the
      rate case has been suspended in order to provide the participants time to draft
      and file a settlement intended to resolve all issues without a formal hearing.
      As of December 31, 2005, an estimated refund liability of approximately $5.0
      million related to Texas Gas’ open general rate case was recorded on the
      Consolidated Balance Sheets. Texas Gas anticipates that the general rate case
      will be settled and all required refunds will be paid during 2006. Gulf South
      currently has no requirements to file a 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 by December 17, 2004, 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. Boardwalk Pipeline Partners 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 $95 to $115 million.
      Boardwalk Pipeline Partners has invested approximately $14.5 million during
      the
      24 months ended December 31, 2005, to develop integrity management programs
      that
      allow it to dynamically assess various pipeline risks on an integrated basis.
      Boardwalk Pipeline Partners has systematically used smart, in-line inspection
      tools to verify the integrity of certain of its pipelines. ******





On
      June
      30, 2005, FERC issued an order addressing the accounting treatment for the
      costs
      that pipeline operators will incur in implementing all aspects of pipeline
      integrity management programs in HCAs. FERC’s general accounting rules provide
      that costs incurred to inspect, test and report on the condition of plant to
      determine the need for repairs or replacements are to be charged to maintenance
      expense in the period the costs are incurred. Therefore, costs to prepare a
      plan
      to implement an integrity management program, costs to identify HCAs, costs
      to
      inspect affected pipeline segments, and costs to develop and maintain a
      recordkeeping system to document program implementation and actions (other
      than
      costs to develop internal-use computer software during the application
      development stage) should be expensed. However, costs of pipeline additions
      or
      modifications undertaken to prepare for a pipeline assessment and costs of
      remedial and mitigation actions to correct an identified condition which could
      threaten a pipeline’s integrity may be capitalized consistent with FERC’s
      general accounting rules for the addition or replacement of plant.




FERC’s
      accounting guidance is effective prospectively, beginning with integrity
      management costs incurred on or after January 1, 2006. Amounts capitalized
      in
      periods prior to January 1, 2006, will be permitted to remain as recorded.
      Boardwalk Pipeline Partners believes it is compliant with FERC’s accounting
      guidance and does not expect any material impact from implementation of these
      guidelines.








**Environmental
      and Safety Matters**





Texas
      Gas
      and Gulf South are subject to federal, state, and local environmental laws
      and
      regulations in connection with the operation and remediation of various
      operating sites. Boardwalk Pipeline Partners 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, Boardwalk Pipeline Partners often enters
      into
      voluntary remediation programs with these agencies. As of December 31, 2005,
      Boardwalk Pipeline Partners had an accrued liability of approximately $20.0
      million related to environmental remediation.











Beginning
      in 2004, as part of Boardwalk Pipeline Partners’ proactive approach and
      continued implementation to environmental matters, Texas Gas entered into
      agreements, or met with various state agencies, to address remediation issues
      primarily on a voluntary basis. As of December 31, 2005 and 2004, Texas Gas
      had
      an accrued liability of $3.5 million and $4.1 million, respectively, 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 best 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
      November 2, 2005, Texas Gas received notice from the EPA that it had 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 (Site). 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)
            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 will hold a 30-day public comment period
      regarding Texas Gas’ settlement. At the end of the public comment period, the
      EPA will notify Texas Gas that the settlement is effective and payment of the
      $0.1 million will be due within thirty days of the effective date.





In
      connection with the GS-Acquisition, an analysis of the environmental
      contamination and related remediation costs at sites owned and/or operated
      by
      Gulf South was conducted by Boardwalk Pipeline Partners and Gulf South
      management in conjunction with a third-party consultant (Environmental
      Consultant). As a result, Gulf South has recorded a $16.6 million environmental
      accrual. The
      material components of the $16.6 million accrual are as follows:




•
            identification
                and remediation of hydrocarbon contamination of $6.0 million;




•
            enhancement
                of groundwater protection measures of $2.5 million;




•
            asbestos
                abatement of $2.7 million;




•
            identification
                and remediation of mercury contamination of $2.0 million;




•
            identification
                and remediation of PCB contamination of $2.0 million; and




•
            other
                costs $1.4 million.





The
      non-current portion of this accrual was $14.1 million and $12.8 million as
      of
      December 31, 2005 and 2004, respectively, and the current portion of this
      accrual was $2.5 million as of December 31, 2005. There was no current portion
      of this accrual as of December 31, 2004. The accruals recorded by Gulf South
      were based upon management’s review and 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 and the historical experience
      of individual pipelines and 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. Boardwalk
      Pipeline Partners 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.











Boardwalk
      Pipeline Partners’ 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.
      Boardwalk Pipeline Partners operates two facilities in areas affected by
      non-attainment requirements for the current ozone standard (eight-hour
      standard). As of December 31, 2005, Texas Gas had incurred costs of
      approximately $13.4 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.
      Since the GS-Acquisition, Gulf South has incurred costs of $0.2 million for
      emission control modifications of compression equipment located at facilities
      required to comply with these provisions. These costs are being recorded as
      additions to PPE as the modifications are added. However, if the EPA designates
      additional new non-attainment areas where Boardwalk Pipeline Partners operates,
      the cost of additions to PPE is expected to increase. As a result, Boardwalk
      Pipeline Partners is unable at this time to estimate with any certainty the
      cost
      of any additions that may be required.





Additionally,
      the EPA promulgated new rules regarding hazardous air pollutants in 2004 which
      will impose controls in addition to the measures described above. Boardwalk
      Pipeline Partners has four facilities which will be affected by the new
      regulations at an estimated cost of $1.6 million. The effective compliance
      date
      for the hazardous air pollutants regulations is 2007. Boardwalk Pipeline
      Partners anticipates installation of associated controls to meet these new
      regulations in 2006 and 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 $0.6 million to meet these requirements. Boardwalk
      Pipeline Partners 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.





Boardwalk
      Pipeline Partners 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 Boardwalk Pipeline Partners' environmental exposure
      included in the calculation of its asset retirement obligation, see Note 2
      of
      these Notes to Consolidated Financial Statements.





**Lease
      Commitments**





Boardwalk
      Pipeline Partners has various operating lease commitments extending through
      the
      year 2018 covering storage facilities, offices and other equipment. On December
      1, 2005, Texas Gas entered into a lease agreement with Texas Eastern
      Transmission, LLC. The primary term of the lease agreement is through November
      30, 2010, and year to year thereafter, unless terminated by either party,
      providing the other party gives no less than 365 days prior written notice.
      The
      lease charge is approximately $2.3 million annually. Lease expenses during
      2005
      were approximately $4.2 million. The table below summarizes minimum future
      commitments related to these items at December 31, 2005, as follows (expressed
      in millions):





2006
            $ 
                 4.92007
            4.02008
            3.22009
            2.82010
            2.6Thereafter
            3.6Total
            $
                21.1











**Commitments
      for Construction**





Boardwalk
      Pipeline Partners has incurred $83.0 million, net, in capital expenditures
      through December 31, 2005. Boardwalk Pipeline Partners’ capital commitments for
      contracts already authorized are expected to approximate the following amounts
      for the next five years (expressed in millions):





Less
                than 1 year
            
            $
                15.71-2
                years
            
            0.13-5
                years
            
            -More
                than 5 years
            
            -Total
            
            $
                15.8




The
      above
      table does not reflect commitments made after December 31, 2005, relating to
      the
      East Texas and Mississippi pipeline expansion projects.














**Note
      4:  Financing**








The
      table
      below represents all long-term debt issues outstanding (expressed in
      thousands):





**December
                31,****2005**
            
            **2004****Boardwalk
                Pipelines**5.20%
                Notes due 2018
            
            $
            185,000
            
            $
            185,000Interim
                term loan
            
            
            -
            
            
            575,0005.50%
                Notes due 2017
            
            
            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
            
            
            -1,110,000
            
            
            1,110,000Unamortized
                debt discount
            
            
            (8,710
            )
            
            (3,865
            )Total
                long-term debt
            
            $
            1,101,290
            
            $
            1,106,135




As
      of
      December 31, 2005 and 2004, the weighted-average interest rate of Boardwalk
      Pipeline Partners’ long-term debt was 5.29% and 4.26%, respectively.





In
      connection with the IPO, Boardwalk Pipelines borrowed approximately
      $42.1 million to reimburse BPHC for capital expenditures it incurred in
      connection with the acquisition of Gulf South. Boardwalk Pipeline Partners
      has
      guaranteed the obligations of Boardwalk Pipelines under that credit facility.
      Interest on the credit facility was accrued at the 3-month LIBOR rate plus
      applicable margin (4.68%). The initial credit facility term matured on February
      13, 2006, was renewed at the 1-month LIBOR rate plus applicable margin (4.92%)
      and subsequently paid off during February 2006. The total amount available
      to
      Boardwalk Pipeline Partners on the five-year revolving credit facility is $200
      million.





The
      credit agreement prevents Boardwalk Pipeline Partners from declaring dividends
      or distributions if any default or event of default, as defined in the credit
      agreement, occurs or would result from such a declaration. In addition, the
      credit agreement contains certain financial covenants. Boardwalk Pipeline
      Partners is allowed to prepay all loans at any time without premium or penalty
      (other than customary LIBOR breakage costs). Interest on amounts drawn are
      payable at a floating rate equal to an applicable spread per annum over
      LIBOR.





Boardwalk
      Pipelines’, Texas Gas’, and Gulf South’s debentures and notes have restrictive
      covenants which provide that, with certain exceptions, neither they nor any
      of
      their 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. Boardwalk Pipeline Partners relies on distributions
      and advances from Texas Gas and Gulf South to fulfill its debt obligations.
      All
      debt obligations are unsecured. At December 31, 2005 Boardwalk Pipelines, Texas
      Gas, and Gulf South 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, together with available cash, were used
      to
      repay the interim loan, which is shown as Long-term debt in the Consolidated
      Balance Sheets and as Proceeds from long-term debt in the Consolidated
      Statements of Cash Flows.











On
      May
      16, 2003, Texas Gas borrowed $275 million (TG-Interim Loan) at 2.6% per annum
      and advanced the proceeds to Boardwalk Pipelines under an interest-bearing
      promissory note. On May 28, 2003, Texas Gas sold $250 million principal amount
      of its 4.60% notes due 2015, at a discount (effective rate of 4.77%).
      Concurrently, Boardwalk Pipelines sold $185 million principal amount of its
      5.20% notes due 2018, at a discount (effective rate of 5.40%) and used the
      proceeds to repay advances to Texas Gas. Texas Gas used the proceeds from the
      sale of its 4.60% notes, together with the proceeds received from Boardwalk
      Pipelines, to repay the TG-Interim Loan, and to repay $132.7 million principal
      amount of its outstanding $150 million aggregate principal amount of 8.625%
      notes due April 2004, plus accrued interest and premium. In March 2004, Texas
      Gas repaid the balance of the notes upon final maturity with available
      cash.





**Note
      5:  Employee Benefits**








**Retirement
      Plan**





Substantially
      all of Texas Gas' employees are covered under a non-contributory, defined
      benefit retirement plan (Retirement Plan) offered by Texas Gas. Texas Gas’
general funding policy is to contribute amounts deductible for federal income
      tax purposes. Texas Gas has not been required to fund the Retirement Plan since
      1986. However, as a result of the TG-Acquisition, Texas Gas recognized $24.9
      million of previously unrecognized market losses and prior service costs,
      reducing its prepaid pension asset and corresponding regulatory liability.
      Since
      the pension plan is now underfunded, Texas Gas is currently seeking FERC
      approval to recover pension costs through its rates and would recognize an
      expense concurrent with the recovery. Texas Gas uses a measurement date of
      December 31 for its pension plan. The following table presents the changes
      in
      benefit obligations and plan assets for pension benefits for the periods
      indicated. It also presents a reconciliation of the funded status of these
      benefits to the amount recognized in the Consolidated Balance Sheets at December
      31 of each year indicated (expressed in thousands).





**For
                the Year Ended**
              **December
                31, 2005**
            
            **For
                the Year Ended**
              **December
                31, 2004**Change
                in benefit obligation:Benefit
                obligation at beginning of period
            
            $
            103,473
            
            $
            90,719Service
                cost
            
            
            4,052
            
            
            3,516Interest
                cost
            
            
            6,220
            
            
            5,582Actuarial
                loss
            
            
            6,132
            
            
            6,373Benefits
                paid
            
            
            (3,994
            )
            
            (2,717
            )Benefit
                obligation at end of period
            
            
            115,883
            
            
            103,473Change
                in plan assets:Fair
                value of plan assets at beginning of period
            
            
            93,056
            
            
            89,302Actual
                return on plan assets
            
            
            7,131
            
            
            6,471Benefits
                paid
            
            
            (3,994
            )
            
            (2,717
            )Fair
                value of plan assets at end of period
            
            
            96,193
            
            
            93,056Funded
                status
            
            
            (19,690
            )
            
            (10,417
            )Unrecognized
                net actuarial loss
            
            
            15,849
            
            
            10,289Net
                amount recognized
            
            $
            (3,841
            )
            $
            (128
            )





Amounts
      recognized in the Consolidated Balance Sheets consist of:





**December
                31, 2005**
            
            **December
                31, 2004**Accrued
                benefit liability
            $
                (3,841)
            
            $   
                 (128)Accumulated
                benefit obligation (ABO)
            $
                93,928
            
            $
                81,376











Net
      pension benefit expense consists of the following:





**For
                the Year Ended**
              **December
                31, 2005**
            
            **For
                the Year Ended**
              **December
                31, 2004**
            
            **For
                the Period May 17, 2003 through December 31, 2003**
            
            
            
            **For
                the Period January 1, 2003 through**
              **May
                16, 2003**Components
                of net periodic pension expense:Service
                cost
            
            $
            4,052
            
            $
            3,516
            
            $
            2,075
            
            
            
            $
            1,631Interest
                cost
            
            
            6,220
            
            
            5,582
            
            
            3,243
            
            
            
            
            2,223Expected
                return on plan assets
            
            
            (6,859
            )
            
            (6,644
            )
            
            (4,186
            )
            
            
            
            (3,278
            )Amortization
                of prior service credit
            
            
            -
            
            
            -
            
            
            -
            
            
            
            
            (478
            )Amortization
                of unrecognized net loss
            
            
            300
            
            
            -
            
            
            -
            
            
            
            
            -Regulatory
                asset accrual
            
            
            (3,713
            )
            
            (2,454
            )
            
            (1,132
            )
            
            
            
            (98
            )Net
                periodic pension expense
            
            $
            -
            
            $
            -
            
            $
            -
            
            
            
            $
            -








The
      following benefit payments, which reflect expected future service, as
      appropriate, are expected to be paid (expressed in thousands):





**Retirement
                Plan**2006
            $
                3,1792007
            3,6902008
            4,7902009
            6,4472010
            7,9682011
                - 2015
            61,862








Texas
      Gas’ pension plan weighted-average asset allocations at December 31, 2005 and
      2004, by asset category are as follows:





**2005**
            
            **2004**Debt
                securities
            62.50%
            
            67.00%Equity
                securities
            30.90%
            
            29.70%Limited
                Partnership
            6.40%
            
            -Other
            0.20%
            
            3.30%Total
            100.00%
            
            100.00%








Texas
      Gas
      employs a total return approach whereby a mix of equities and fixed income
      investments are 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 corporate financial conditions. 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 periods
      indicated:





**December
                31, 2005**
            
            **December
                31, 2004**Discount
                rate
            5.63%
            
            5.88%Rate
                of compensation increase
            5.50%
            
            5.50%











Weighted-average
      assumptions used to determine net periodic benefit cost for the periods
      indicated:





**For
                the Year Ended December 31, 2005**
            **For
                the Year Ended December 31, 2004**
            **For
                the Period**
              **May
                17, 2003 through**
              **December
                31, 2003**
            
            
            
            **For
                the Period January 1, 2003 through**
              **May
                16, 2003**Discount
                rate
            5.88%
            6.25%
            6.00%
            
            
            
            7.00%Expected
                return on plan assets
            7.50%
            7.50%
            7.50%
            
            
            
            8.50%Rate
                of compensation increase
            5.50%
            5.50%
            5.25%
            
            
            
            5.00%








Other
      than supplemental retirement plan costs, Texas Gas recognizes expense concurrent
      with the recovery in rates. Since Texas Gas’ pension plan was underfunded as of
      December 31, 2005, Texas Gas is currently seeking approval to recover pension
      costs through its rates and would recognize an expense concurrent with the
      recovery. Supplemental retirement plan expenses recognized by Texas Gas were
      less than $0.1 million in 2005 and 2004, $0.1 million post-acquisition 2003,
      and
      $1.2 million pre-acquisition 2003.








***Postretirement
      Benefits Other Than Pensions***





Prior
      to
      the TG-Acquisition, Texas Gas' postretirement benefits other than pensions
      were
      part of a multi-employer plan under Williams; however, for regulatory purposes
      its liabilities and plan assets were accounted for separately.





Texas
      Gas
      provides life insurance and health care plans which accords postretirement
      medical benefits to retired employees who were employed full time, hired prior
      to January 1, 1996, and have met certain other requirements. Boardwalk Pipeline
      Partners made contributions to this plan in the amount of $4.9 million during
      2005, $5.3 million during 2004, $2.7 million during the post-TG-Acquisition
      and
      $2.7 million during the pre-TG-Acquisition periods in 2003 **.** Texas
      Gas’ rate case with FERC (Docket No. RP00-260) allowed recovery of $5.3 million
      annually, including amortization of previously deferred postretirement benefit
      costs. Net postretirement benefit expense related to its participation in the
      Williams’ plan was $2.6 million for the 2003 pre-Acquistion period including
      $2.0 million of amortization of a regulatory asset. The regulatory asset
      represents unrecovered costs from prior years, including the unamortized
      transition obligation under SFAS No. 106, “ *Employers’
      Accounting for Postretirement Benefits Other Than Pensions* ,”
which
      was recognized at the date of the Williams acquisition in 1995. This asset
      is
      being amortized concurrently with the recovery of these costs through
      rates.





Texas
      Gas
      uses a measurement date of December 31 for its postretirement benefits other
      than pensions. Postretirement benefits other than pensions since the date of
      TG-Acquisition are as follows (expressed in thousands):





**Postretirement
                Life Insurance and Health Care Benefits****For
                the Year Ended**
              **December
                31, 2005**
            
            **For
                the Year Ended**
              **December
                31, 2004****Change
                in benefit obligation (PBO):**Benefit
                obligation at beginning of period
            
            $
            125,599
            
            $
            105,036Service
                cost
            
            
            2,076
            
            
            2,095Interest
                cost
            
            
            7,222
            
            
            5,912Plan
                participants’ contributions
            
            
            1,328
            
            
            1,044Actuarial
                loss
            
            
            5,379
            
            
            17,480Benefits
                paid
            
            
            (7,416
            )
            
            (5,968
            )Benefit
                obligation at end of year
            
            
            134,188
            
            
            125,599














**For
                the Year Ended**
              **December
                31, 2005**
            
            **For
                the Year Ended**
              **December
                31, 2004****Change
                in plan assets:**Fair
                value of plan assets at beginning of period
            
            
            76,499
            
            
            71,717Actual
                return on plan assets
            
            
            5,164
            
            
            4,837Employer
                contributions
            
            
            3,888
            
            
            4,869Plan
                participants’ contributions
            
            
            1,328
            
            
            1,044Benefits
                paid
            
            
            (7,416
            )
            
            (5,968
            )Fair
                value of plan assets at end of year
            
            
            79,463
            
            
            76,499Funded
                status
            
            
            (54,725
            )
            
            (49,100
            )Unrecognized
                net actuarial loss
            
            
            20,411
            
            
            15,927Net
                amount recognized
            
            $
            (34,314
            )
            $
            (33,173
            )





**Amounts
                recognized in the Consolidated Balance Sheets consist
                of:**Accrued
                benefit liability
            
            $
            (34,314
            )
            $
            (33,173
            )








**Weighted-average
                assumptions used to determine PBO:**Discount
                rate
            
            
            5.63
            %
            
            5.88
            %








**FAS
                106 Expense for the Year:**Service
                cost
            
            $
            2,076
            
            $
            2,095Interest
                cost
            
            
            7,222
            
            
            5,912Amortization
                of net loss (gain)
            
            
            362
            
            
            (66
            )Expected
                return on plan assets
            
            
            (4,632
            )
            
            (5,252
            )Total
            
            $
            5,028
            
            $
            2,689








**Weighted-average
                assumptions used to determine FAS 106 expense:**Discount
                rate
            
            
            5.88
            %
            
            5.88
            %Return
                on assets for medical/life
            
            
            6.15%/5.00
            %
            
            7.50%/5.00
            %








For
      December 31, 2005 measurement purposes, health care costs for the plans were
      assumed to increase 9.00% for 2006-2007 grading down to 5.00% in 0.5% annual
      increments for non-Medicare eligibles and 11.00% grading down to 5.00% in 0.5%
      annual increments for Medicare eligibles. For December 31, 2004 measurement
      purposes, health care costs for the plans were assumed to increase 9.50% pre-65
      and 11.50% post-65, grading down to 5.00% in 0.5% increments pre-65 and post-65
      per annum.











The
      following table reflects the projected net benefit payments for postretirement
      life insurance and health care benefits (expressed in thousands):





2006
            $
                5,2922007
            5,5962008
            5,9482009
            6,2602010
            6,5022011
                - 2015
            38,754








Assumed
      health care cost trend rates have a significant effect on the amounts reported
      for the health care plans. A one-percentage-point change in assumed health
      care
      cost trend rates would have the following effects:













**Effect
                of 1% Increase:**
            **2005**
            
            **2004**Benefit
                obligation at end of year
            $ 19,785
            
            $
                18,077Total
                of service and interest costs for year
            1,585
            
            1,352








**Effect
                of 1% Decrease:**Benefit
                obligation at end of year
            (16,007)
            
            (14,670)Total
                of service and interest costs for year
            (1,263)
            
            (1,078)








Texas
      Gas’ benefits other than pensions weighted-average asset allocations at December
      31, 2005 and 2004, by asset category are as follows:





**2005**
            
            **2004**Fixed
                income
            45.2%
            
            94.7%Cash
                and other
            54.8%
            
            5.3%Total
            100.0%
            
            100.0%





Texas
      Gas' benefits other than pensions investments employs a total return approach
      whereby a mix of equities and fixed income investments are 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 corporate financial conditions. 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.





***Defined
      Contribution Plan***





Boardwalk
      Pipeline Partners maintains various defined contribution plans covering
      substantially all its employees. Costs related to these plans were $4.9 million
      in 2005, $2.6 million in 2004, $1.6 million in 2003 post-TG-Acquisition and
      $1.0
      million in 2003 pre-TG-Acquisition.













***Stock-Based
      Awards***




Prior
      to
      the TG-Acquisition, Williams’ employee stock-based awards were accounted for
      under Accounting Principles Board (APB) Opinion No. 25, *Accounting
      for Stock Issued to Employees* ,
      and
      related interpretations. Williams fixed plan common stock options generally
      did
      not result in compensation expense because the exercise price of the stock
      options equaled the market price of the underlying stock on the date of grant.
      At January 1, 2003, Boardwalk Pipeline Partners had 2,023 options at a
      weighted-average exercise price of $20.96 outstanding. Due to the
      TG-Acquisition, all Williams’ stock options, outstanding at January 1, 2003
      issued to Texas Gas employees expired on November 17, 2003.








***Long-Term
      Incentive Plan***





Boardwalk
      Pipeline Partners adopted the Long-Term Incentive Plan for the officers and
      directors of its general partner and for certain key employees of its
      subsidiaries during 2005. This plan consists of the following five components:
      units, restricted units, phantom units, unit options and unit appreciation
      rights. The board of directors of BGL administers the plan and in its discretion
      may terminate, suspend or discontinue the plan at any time with respect to
      any
      award that has not yet been granted. The Board also has the right to alter
      or
      amend the plan or any part of the plan from time to time, including increasing
      the number of units that may be granted subject to unitholder approval as
      required by the NYSE. However, no change in any outstanding grant will be made
      that would materially impair the rights of a participant without the consent
      of
      the participant. This plan has reserved 3,525,000 of its units for grants of
      units, restricted units, unit option and unit appreciation rights under the
      plan.





On
      December 15, 2005, Boardwalk Pipeline Partners granted 29,176 phantom units
      under the Long-Term Incentive Plan, but did not make any grants of units,
      restricted units, unit options and unit appreciation rights. The phantom units
      were granted at $17.98 per unit, with a fair market value of approximately
      $0.5
      million as of December 31, 2005, of which an immaterial amount was vested and
      included in expense on the Consolidated Statements of Income. 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 incentive distribution rights
      qualify as partner securities under EITF-03-6 and, as such, certain earnings
      may
      be allocated to these incentive distributions rights in the future.





**Note
      6:  Income Tax**








Following
      is a summary of the provision for income taxes and charge-in-lieu of income
      taxes for the periods ended December 31, 2005, 2004, and 2003 (expressed in
      thousands):





**Boardwalk
                Pipeline Partners**
            
            
            
            **Predecessor****For
                the Year Ended**
              **December
                31, 2005**
            
            **For
                the Year Ended**
              **December
                31, 2004**
            
            **For
                the Period May 17, 2003 through December 31, 2003**
            
            
            
            **For
                the Period January 1, 2003 through**
              **May
                16, 2003**Current
                expense (benefit):Federal
            
            $
            4,044
            
            $
            (9,131
            )
            $
            (4,141
            )
            
            
            $
            14,234State
            
            
            870
            
            
            (1,964
            )
            
            (717
            )
            
            
            
            2,6594,914
            
            
            (11,095
            )
            
            (4,858
            )
            
            
            
            16,893Deferred
                provision:Federal
            
            
            36,690
            
            
            35,803
            
            
            17,666
            
            
            
            
            4,522State
            
            
            7,890
            
            
            7,625
            
            
            2,296
            
            
            
            
            972Elimination
                of cumulative deferred taxes
            
            
            10,102
            
            
            -
            
            
            -
            
            
            
            
            -54,682
            
            
            43,428
            
            
            19,962
            
            
            
            
            5,494Net
                provision for income taxes
            
            
            -
            
            
            -
            
            
            -
            
            
            
            $
            22,387Net
                charge-in-lieu of income tax
            
            $
            59,596
            
            $
            32,333
            
            $
            15,104











Reconciliations
      from the charge-in-lieu of income tax provision at the statutory rate to its
      income tax provisions are as follows (expressed in thousands):





**Boardwalk
                Pipeline Partners**
            
            
            
            **Predecessor****For
                the Year Ended**
              **December
                31, 2005**
            
            **For
                the Year**
              **Ended**
              **December
                31, 2004**
            
            **For
                the Period May 17, 2003 through December 31, 2003**
            
            
            
            **For
                the Period January 1, 2003 through**
              **May
                16, 2003**Provision
                at statutory rate
            
            $
            43,583
            
            $
            28,405
            
            $
            13,145
            
            
            
            $
            19,901Increases
                in taxes resulting from:State
                income taxes
            
            
            5,694
            
            
            3,680
            
            
            1,709
            
            
            
            
            2,587Other,
                net
            
            
            217
            
            
            248
            
            
            250
            
            
            
            
            (101
            )Elimination
                of deferred taxes
            
            
            10,102
            
            
            -
            
            
            -
            
            
            
            
            -Net
                provision for income taxes
            
            
            -
            
            
            -
            
            
            -
            
            
            
            $
            22,387Charge-in-lieu
                of income taxes
            
            $
            59,596
            
            $
            32,333
            
            $
            15,104





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 IPO. Accordingly, Boardwalk Pipeline Partners 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 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. See Note 2 to
      these consolidated financial statements for additional information.











As
      of
      December 31, 2005, there were no deferred income tax assets or liabilities.
      As
      of December 31, 2004, significant components of deferred income tax assets
      and
      liabilities were as follows (expressed in thousands):




**December
                31, 2004****Deferred
                tax assets:**Property,
                plant and equipment
            
            $
            93,498Accrued
                payroll, pension and other benefits
            
            
            14,018Deferred
                income
            
            
            1,086Net
                operating loss carryover
            
            
            16,216Other
                assets
            
            
            3,479Total
                deferred tax assets
            
            
            128,297**Deferred
                tax liabilities:**Storage
                gas
            
            
            65,568Unamortized
                debt expense
            
            
            3,133Total
                deferred tax liabilities
            
            
            68,701Net
                deferred tax assets
            
            $
            59,596





At
      December 31, 2004, the accompanying consolidated financial statements reflect
      a
      net deferred tax asset resulting from the tax basis allocation and the
      338(h)(10) election completed as part of the TG-Acquisition. The financial
      statements also reflect a purchase price allocation for the GS-Acquisition.
      Accordingly, the table above reflects only temporary differences for Gulf South
      arising from the date of acquisition primarily reflecting the benefit of
      accumulated tax depreciation.





**Note
      7:  Financial Instruments**





The
      following methods and assumptions were used in estimating Boardwalk Pipeline
      Partners’ fair-value disclosures for financial instruments:





*Cash
      Management:* Under
      the
      cash management program, depending on whether a participating subsidiary has
      short-term cash surpluses or cash requirements, Boardwalk Pipeline Partners
      either provides cash to the subsidiary or the subsidiary provides cash to
      Boardwalk Pipeline Partners.  As such, the carrying amount is a reasonable
      estimate of fair value.





*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.





*Derivatives:* For
      a
      discussion of Boardwalk Pipeline Partners’ derivatives, see Note 2 of these
      Notes to Consolidated Financial Statements.





*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 the LIBOR plus one percent and
      is
      adjusted each three-month period.





*Long-Term
      Debt:* All
      long-term debt is publicly traded, except for financing obtained in connection
      with the GS-Acquisition; therefore, estimated fair value is based on quoted
      market prices at December 31, 2005 and 2004. The carrying value of the $575
      million interim financing obtained in December 2004 related to the
      GS-Acquisition approximates fair value.





The
      carrying amount and estimated fair values of Boardwalk Pipeline Partners’
financial instruments as of December 31, 2005 and 2004 are as follows (expressed
      in thousands):




**2005**
            
            **2004****Financial
                Assets**
            
            **Carrying
                Amount**
            
            **Fair
                Value**
            
            **Carrying
                Amount**
            
            **Fair
                Value**Cash
                and cash equivalents
            
            $
            65,792
            
            $
            65,792
            
            $
            16,518
            
            $
            16,518Advances
                to affiliates
            
            
            -
            
            
            -
            
            
            41,812
            
            
            41,812**Financial
                Liabilities**Long-term
                debt
            
            $
            1,101,290
            
            $
            1,090,854
            
            $
            1,106,135
            
            $
            1,105,411











**Note
      8:  Major Customers and Transactions with
      Affiliates******





**Major
      Customers**





Operating
      revenues received from major customers (expressed in thousands) and their
      percentage of revenues were:


**For
                  the Year Ended**
                **December
                  31, 2005**
              
              **For
                  the Year Ended**
                **December
                  31, 2004**
              
              **For
                  the Period**
                **May
                  17, 2003**
                **through**
                **December
                  31, 2003**
              
              **For
                  the Period**
                **January
                  1, 2003**
                **through**
                **May
                  16, 2003****Customer**
              
              **Revenue**
              
              **%**
              
              **Revenue**
              
              **%**
              
              **Revenue**
              
              **%**
              
              **Revenue**
              
              **%**ProLiance
                  Energy, LLC
              
              $
                  51,168
              
              -9.13%
              
              $
                  56,742
              
              21.53%
              
              $
                  28,110
              
              19.68%
              
              $
                  22,157
              
              19.53%Atmos
                  Energy
              
              $
                  61,774
              
              11.02%
              
              $
                  28,569
              
              10.84%
              
              $
                  16,208
              
              11.35%
              
              $
                  13,318
              
              11.74%





**Related
      Parties**





Loews
      has
      a policy of charging its subsidiary companies for management services provided
      by Loews. Boardwalk Pipeline Partners will also charge overhead costs to its
      subsidiaries. Loews charged its subsidiaries for management services for the
      years ended December 31, 2005 and 2004, and for the period after the
      TG-Acquisition in 2003, $9.7 million, $6.9 million, and $3.3 million,
      respectively. Williams also had a policy of charging its subsidiary companies
      for management services provided by the parent company and other affiliated
      companies. Amounts charged to expense relative to management services by
      Williams and included in the accompanying Predecessor financial statements
      was
      $5.4 million prior to the TG-Acquisition in 2003. Advances existed during 2005
      to Boardwalk Pipeline Partners from BPHC which were settled before the
      completion of its IPO.





Amounts
      applicable to transportation for affiliates included in Boardwalk Pipeline
      Partners gas transportation revenues for the Predecessor period are as follows
      (expressed in thousands):





**Predecessor**
            
            **For
                the Period**
              **January
                1, 2003**
              **through**
              **May
                16, 2003**Williams
                Energy Services Co.
            
            $    292Transcontinental
                Gas Pipe Line Corp.
            
            1,670Total
                transportation for affiliates
            
            $
                1,962








**Note
      9:  Recent Accounting Pronouncements******





In
      May
      2005, the FASB issued SFAS 154, *Accounting
      Changes and Error Correction - a replacement of APB Opinion No. 20 and FASB
      Statement No. 3* which
      requires that the direct effect of voluntary changes in accounting principle
      be
      applied retrospectively with all prior period financial statements presented
      on
      the new accounting principle, unless it is impracticable to determine either
      the
      period-specific effects or the cumulative effect of the change. Indirect effects
      of a change should be recognized in the period of the change. SFAS 154 is
      effective for accounting changes and correction of errors made in fiscal years
      beginning after December 15, 2005. The impact of SFAS 154 will depend on
      the nature and extent of any voluntary accounting changes and correction of
      errors after the effective date, but management does not currently expect SFAS
      154 to have a material impact on its financial condition, results of operations
      or cash flows.

















**Note
      10:  Supplemental Disclosure of Cash Flow
      Information**





**Boardwalk
                Pipeline Partners**
            
            
            
            **Predecessor****(**Expressed
                in thousands)
            
            **For
                the Year Ended**
              **December
                31, 2005**
            
            **For
                the Year Ended**
              **December
                31,**
              **2004**
            
            **For
                the Period May 17, 2003 through December 31, 2003**
            
            
            
            **For
                the Period January 1, 2003 through**
              **May
                16, 2003**Supplemental
                Disclosure of Cash Flow Information:Cash
                paid during the period for:Interest
                (net of amount capitalized)
            
            $
            45,357
            
            $
            28,847
            
            $
            15,295
            
            
            
            $
            9,852Income
                taxes, net
            
            
            -
            
            
            -
            
            
            492
            
            
            
            
            28,199Non-cash
                capital contribution
            
            
            681,809
            
            
            -
            
            
            -
            
            
            
            
            -Non-cash
                dividends
            
            
            101,401
            
            
            -
            
            
            -
            
            
            
            
            29,022





**Note
      11:****Selected
      Quarterly Financial Data (Unaudited)**








Boardwalk
      Pipeline Partners’ operating income may vary by quarter. Based on the current
      rate structure, both Texas Gas and Gulf South 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 2005 and 2004
      for Boardwalk Pipeline Partners (expressed in thousands):





**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





**2004**
              **For
                the Quarter Ended:**December
                31
            
            September
                30
            
            June
                30
            
            March
                31Operating
                revenues
            
            $
            79,103
            
            $
            46,920
            
            $
            51,925
            
            $
            85,673Operating
                expenses
            
            
            44,371
            
            
            38,068
            
            
            36,308
            
            
            35,145Operating
                income
            
            
            34,732
            
            
            8,852
            
            
            15,617
            
            
            50,528Interest
                expense, net
            
            
            7,444
            
            
            7,276
            
            
            7,314
            
            
            7,695Other
                income
            
            
            525
            
            
            254
            
            
            139
            
            
            240Income
                before income taxes
            
            
            27,813
            
            
            1,830
            
            
            8,442
            
            
            43,073Charge-in-lieu
                of income taxes
            
            
            11,032
            
            
            813
            
            
            3,458
            
            
            17,030Net
                income
            
            $
            16,781
            
            $
            1,017
            
            $
            4,984
            
            $
            26,043











**Item
      9****.  Changes
      in and Disagreements with Accountants on Accounting and Financial
      Disclosure.**








None.





**Item
      9A.  Controls and Procedures****.******








Boardwalk
      Pipeline Partners maintains 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.




Boardwalk
      Pipeline Partners’ principal executive officers 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 officers and principal financial officer have each concluded
      that the disclosure controls and procedures are effective for their intended
      purpose.





There
      was
      no change in Boardwalk Pipeline Partners’ internal control over financial
      reporting identified in connection with the foregoing evaluation that occurred
      during the last fiscal quarter that has materially affected, or is reasonably
      likely to materially affect, the internal control over its financial
      reporting.





**Item
      9B.  Other Information****.******








None.











**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 our general partner, 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. Our general partner is
      not
      required to act in good faith or pursuant to any other standard imposed by
      our
      partnership agreement or under any law. Examples include the exercise of its
      limited call rights on our units, as provided in our partnership agreement,
      its
      voting rights with respect to the units it owns, its registration rights and
      its
      determination whether or not to consent to any merger or consolidation of the
      partnership all of which are described in our partnership agreement. Actions
      of
      our general partner which are made in its individual capacity will be made
      by
      BPHC, the sole member of BGL, rather than by our Board.










**Directors
      and Executive Officers**






The
      following table shows information for the directors and executive officers
      of
      BGL:


**Name**
            
            **Age**
            
            **Position**Rolf
                A. Gafvert
            
            52
            
            Co-President
                and DirectorH.
                Dean Jones II
            
            53
            
            Co-President
                and DirectorJamie
                L. Buskill
            
            41
            
            Chief
                Financial OfficerArthur
                L. Rebell
            
            64
            
            Director,
                Chairman of the BoardThomas
                E. Hyland
            
            60
            
            DirectorJonathan
                E. Nathanson
            
            43
            
            DirectorMark
                L. Shapiro
            
            61
            
            DirectorAndrew
                H. Tisch
            
            56
            
            Director








**Rolf
      A. Gafvert** —Mr.
      Gafvert has been the Co-President of BGL since its inception in 2005. Mr.
      Gafvert is also the President of Gulf South. He has been employed by Gulf South
      or its predecessors in that capacity 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 Co-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.
      Prior to joining Loews, Mr. Rebell was a managing director with Schroder
      Wertheim. Mr. Rebell also serves as a director for Diamond Offshore Drilling.




**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. From 1989 to 2001, he was
      employed as an investment banker at Citigroup and predecessor
      firms.





**Mark
      L. Shapiro** —Mr.
      Shapiro has been a private investor since 1998. From July 1997 through August
      1998, Mr. Shapiro was a Senior Consultant to the Export-Import Bank of the
      United States and prior thereto he was a Managing Director in the investment
      banking firm of Schroder & Co., Inc. Mr. Shapiro is also a director of W.R.
      Berkley Corporation.





**Andrew
      H. Tisch** —Mr.
      Tisch
      has been Co-Chairman of the Board of Loews Corporation since January 2006 and
      is
      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.


**Our
      Independent Directors**





Our
      Board
      has determined that Thomas E. Hyland and Mark L. Shapiro 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 neither of these directors has any material
      relationship with us, our management, our general partner or its affiliates
      or
      our subsidiaries.





Our
      Board
      has established guidelines to assist it in determining director independence.
      Under these guidelines, a director would not be considered independent if any
      of
      the following relationships exists:






(i)
            during
                the past three years the director has been an employee, or an immediate
                family member has been an executive officer, of us;






(ii)
            the
                director or an immediate family member received, during any twelve
                month
                period within the past three years, more than $100,000 in direct
                compensation from us, excluding director and committee fees, pension
                payments and certain forms of deferred compensation;




(iii)
            the
                director is a current partner or employee or an immediate family
                member is
                a current partner of a firm that is our internal or external auditor,
                or an immediate family member is a current employee of such a firm
                and
                participates in the firm’s audit, assurance or tax compliance (but not tax
                planning) practice or, within the last three years, the director
                or an
                immediate family member was a partner employee of such a firm and
                personally worked on our audit within that time;




(iv)
            the
                director or an immediate family member has at any time during the
                past
                three years been employed as an executive officer of another company
                where
                any of our present executive officers at the same time serves or
                served on that company’s compensation committee; or




(v)
            the
                director is a current employee, or an immediate family member is
                a current
                executive officer, of a company that has made payments to, or received
                payments from us for property or services in an amount which, in any
                of the last three years, exceeds the greater of $1 million, or 2%
                of the
                other company’s consolidated gross
                revenues.











Our
      Board
      has appointed an Audit Committee comprised solely of independent directors,
      as
      discussed below. However, although most companies listed on the NYSE are
      required to have a majority of independent directors serving on their board
      of
      directors and to establish and maintain a compensation committee and a
      nominating/corporate governance committee, in addition to an audit committee,
      each consisting 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, to have a majority of independent directors on its
      board
      of directors or to maintain a compensation or nominating/corporate governance
      committee. In reliance on these exemptions, our Board is not comprised of a
      majority of independent directors, nor do we maintain a compensation or
      nominating/corporate governance committee.








**Audit
      Committee**





Our
      Board’s Audit Committee presently consists of Thomas E. Hyland, Chairman, and
      Mark L. Shapiro, 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. As required by NYSE listing
      standards, our Board will add a third Audit Committee member, who will also
      be
      an independent director, not later than November 2006,. 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, and Thomas E. Hyland. 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 will, from time to time as such directors deem
      necessary or appropriate, meet in regular executive sessions without management
      participation. The Chairman of the Audit Committee and the Conflicts Committee
      will 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 co-principal executive officers, principal financial officer and
      principal accounting officer on our website.





The
      certifications of BGL’s co-principal executive officers and principal financial
      officer required by Section 302 of the Sarbanes-Oxley Act have been included
      as
      exhibits to this report.











**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 2005, in a timely manner, other than one late Form 3 filing
      for
      each of Messrs. Hyland and Shapiro and one late Form 4 filing for each Messrs.
      Gafvert, Jones, and Buskill.








**Available
      Information; Communications with our Board**





We
      make
      available free of charge within the “Governance” section of our website, at *www.boardwalkpipelines.com* ,
      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.
      The
      information contained on or connected to our website is not incorporated by
      reference into this report and should not be considered part of this or any
      other report that we file with or furnish to the SEC.





Our
      chairpersons of any of our Board committees, our Board’s independent directors
      as a group or our full Board may be contacted in writing by mail to Boardwalk
      Pipeline Partners, LP, 3800 Frederica St., Owensboro, KY 42301, Attention:
      Corporate Secretary. Communicate clearly the intended recipient. All such
      communications will be delivered to the director or directors to whom they
      are
      addressed.











**Item
      11.  Executive Compensation.******








The
      following table sets forth information regarding the compensation of each of
      our
      executive officers, whom we refer to in this report as the “Named Executive
      Officers” for services in all capacities to us and our subsidiaries during 2005.





**Summary
      Compensation Table**


**Long-Term****Annual
                Compensation**
            **Compensation****Grants
                of**
            **All
                Other****Name
                and Position**
            **Salary**
            **Bonus
                (1)**
            **Phantom
                Units (2)**
            **Compensation**Rolf
                A. Gafvert
            $
                240,000
            $
                350,000
            $
                150,000
            $
                21,525 (3)Co-President
                andPresident
                of Gulf SouthH.
                Dean Jones II
            282,692
            195,000
            80,000
            171,412
                (4)Co-President
                andPresident
                of Texas GasJamie
                L. Buskill
            170,000
            100,000
            35,000
            55,283 (5)Chief
                Financial Officerand
                CFO of Texas Gas





(1)
            Reflects
                amounts paid to the named executive officers in 2006 for services
                performed by them during 2005.


(2)
            Reflects
                the cash value at the date of grant of grants under our Long-Term
                Incentive Plan of 8,030, 4,283 and 1,874 phantom units, respectively,
                to
                Messrs. Gafvert, Jones and Buskill on December 15, 2005. The closing
                price
                of our common units on such date on the New York Stock Exchange was
                $18.68. Each such grant: included 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.


(3)
            Includes
                matching contributions made under a 401(k) and money purchase plan,
                and
                insurance premiums.


(4)
            Includes
                matching contributions made under a 401(k) plan, interest and pay
                credits
                on existing balances under a non-qualified supplemental retirement
                plan
                and qualified retirement plan, interest on existing balances under
                an
                inactive salary continuation plan, and insurance
                premiums.


(5)
            Includes
                matching contributions made under a 401(k) plan, interest and pay
                credits
                on existing balances under a non-qualified supplemental retirement
                plan
                and qualified retirement plan, and insurance
                premiums.








**Long-Term
      Incentive Plan**




We
      have
      adopted the Boardwalk Pipeline Partners Long-Term Incentive Plan for the
      officers and directors of our general partner and for certain key employees
      of
      our subsidiaries. This plan consists of the following five components: units,
      restricted units, phantom units, unit options and unit appreciation rights.
      Our
      Board administers the plan and in its discretion may terminate, suspend or
      discontinue the plan at any time with respect to any award that has not yet
      been
      granted. The Board also has the right to alter or amend the plan or any part
      of
      the plan from time to time, including increasing the number of units that may
      be
      granted subject to unitholder approval as required by the NYSE. However, no
      change in any outstanding grant will be made that would materially impair the
      rights of a participant without the consent of the participant. This plan has
      reserved 3,525,000 of our units for grants of units, restricted units, unit
      option and unit appreciation rights under the plan.





During
      2005, we made grants of phantom units to the Named Executive Officers and
      certain others but did not make any grants of units, restricted units, unit
      options and unit appreciation rights to any of the Named Executive Officers.
      See
“Summary Compensation Table” for additional information on equity compensation
      herein.











**Compensation
      of Directors**





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 will 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.








**Item
      12.  Security Ownership of Certain Beneficial Owners and
      Management****.**








The
      following table sets forth certain information, at March, 1, 2006, 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 Owned**Jamie
                L. Buskill
            -
            -
            -
            -
            -Rolf
                A. Gafvert
            -
            -
            -
            -
            -Thomas
                E. Hyland
            -
            -
            -
            -
            -H.
                Dean Jones II
            -
            -
            -
            -
            -Jonathan
                E. Nathanson
            10,000
            *
            -
            -
            -Arthur
                L. Rebell
            36,000
                (2)
            *
            -
            -
            -Mark
                L. Shapiro
            10,000
            *
            -
            -
            -Andrew
                H. Tisch
            18,550
                (3)
            *
            -
            -
            -All
                directors and executive officers as a group
            74,550
            *
            -
            -
            -BPHC
                (4)
            53,256,122
            78.02%
            33,093,878
            100.00%
            85.19%Loews
                Corporation (4)
            53,256,122
            78.02%
            33,093,878
            100.00%
            85.19%





*Represents
      less than 1% of the outstanding common units





(1)
            As
                of March 1, 2006, we had 68,256,122 common units and 33,093,878
                subordinated units issued and outstanding.


(2)
            30,000
                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.





For
      information regarding Securities authorized for issuance under our Long-Term
      Incentive Plan, please read Item 5, "Market for Registrant's Common Equity,
      Related Stockholder Matters and Issuer Purchases of Equity
      Securities."














**Item
      13.  Certain Relationships and Related
      Transactions.******







**Transactions
      Consummated in Connection with the Completion of Our IPO**







In
      connection with the consummation of our IPO, we and our affiliates
      effected the following transactions:




•
            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 us;




•
            our
                reimbursement of BPHC for $42.1 million of capital expenditures it
                incurred in connection with the
                GS-Acquisition;




•
            our
                assumption from BPHC of $250.0 million of indebtedness to Loews and
                the
                repayment of that indebtedness with proceeds from our IPO;




•
            the
                issuance by us to BPHC of 53,256,122 common units and 33,093,878
                subordinated units, representing an 83.5% limited partnership interest
                in;
                and




•
            the
                issuance by us to Boardwalk GP of a 2% general partner interest and
                all of
                our incentive distribution rights.










**Reimbursement
      of Expenses of Our General Partner and Its Affiliates**





We
      reimburse our general partner and its affiliates for certain expenses incurred
      by them. These expenses include the costs of employee, officer and director
      compensation and benefits properly allocable to us, and all other expenses
      necessary or appropriate to the conduct of our business, and allocable to us.
      These expenses also include overhead allocated to us by Loews in amounts
      allowable consistent with accounting and allocation methodologies generally
      permitted by FERC for rate-making purposes and past business practices. During
      2005, we paid our general partner and its affiliates, including Loews,
      approximately $9.7 million in reimbursement for expenses incurred by them on
      our
      behalf, including amounts charged to us under the Services Agreements described
      below, as well as overhead allocated to us by Loews as discussed above. The
      amounts paid to the general partner and its affiliates may not necessarily
      be
      reflective of direct reimbursements for services performed on our behalf by
      the
      general partner and its affiliates in any given year. Our partnership agreement
      provides that the general partner will determine the expenses that are allocable
      to us.








**Services
      Agreements**




Loews
      provides a variety of corporate services to us and our subsidiaries under
      Services Agreements. Services provided by Loews include, among others,
      information technology, tax, risk management, internal audit and corporate
      development services. Loews charges us based on the actual time spent by Loews
      personnel performing these services, plus related expenses.








**Distributions
      and Payments to Our General Partner and Its Affiliates**




BPHC
      owns
      53,256,122 of our common units and 33,093,878 of our subordinated units,
      representing an 83.5% limited partner interest in us. In addition, Boardwalk
      GP
      owns the 2% general partner interest and all of our incentive distribution
      rights. As holders of our units and incentive distribution rights, these
      affiliates will receive distributions from us, to the extent we declare and
      pay
      distributions, in accordance with the terms of our partnership agreement. Please
      read Item 5, “Market for Registrant's Common Equity, Related Stockholder Matters
      and Issuer Purchases of Equity Securities-Distributions.”











**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, our predecessors and our
      subsidiaries in 2005 and 2004, by category as described in the notes to the
      table (expressed in thousands):





**2005**
            
            **2004**Audit
                fees (1)
            
            $
            1,271
            
            $
            554Audit
                related fees (2)
            
            
            720
            
            
            -Tax
                fees (3)
            
            
            6
            
            
            18All
                other fees (4)
            
            
            270
            
            
            -Total
            
            $
            2,267
            
            $
            572





(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, and Sarbanes-Oxley
                implementation.




(3)
            Includes
                the aggregate fees and expenses for tax compliance and tax planning
                services.




(4)
            Includes
                the aggregate fees and expenses for products and services provided,
                other
                than the services described above, including principally, tax software
                products and due diligence for the
                GS-Acquisition.










**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.











**PART
      IV**








**Item
      15.  Exhibits, Financial Statement Schedules****.**








**(a)
      1. Financial Statements**





Included
      in Item 8, Part II of this report:





Reports
      of Independent Registered Public Accounting Firm





Consolidated
      Balance Sheets at December 31, 2005 and 2004





Consolidated
      Statements of Income for the years ended December 31, 2005 and 2004 and for
      the
      periods January 1, 2003 through May 16, 2003 and May 17, 2003 through December
      31, 2003





Consolidated
      Statements of Changes in Stockholder’s Equity, Member’s Equity and Partners’
Capital and Comprehensive Income for the years ended December 31, 2005 and
      2004,
      and for the periods January 1, 2003 through May 16, 2003 and May 16, 2003
      through December 31, 2003





Consolidated
      Statements of Cash Flows for the years ended December 31, 2005 and 2004, and
      for
      the periods January 1, 2003 through May 16, 2003, and May 17, 2003 through
      December 31, 2003





Notes
      to
      Consolidated Financial Statements








**(a)
      2.**  **Financial
      Statement Schedules**





**Valuation
      and Qualifying Accounts**





The
      table
      below presents those accounts that have a reserve as of December 31, 2005,
      and
      are not included in specific schedules herein. These amounts have been deducted
      from the respective asset on the Consolidated Balance Sheets as follows **(** expressed
      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:2005
            
            $
            174
            
            $
            745
            
            $
            (187
            )
            $
            2
            
            $
            7302004
            
            
            203
            
            
            -
            
            
            -
            
            
            29
            
            
            1742003
            
            
            557
            
            
            -
            
            
            354
            
            
            -
            
            
            2032003
                Predecessor
            
            
            557
            
            
            -
            
            
            -
            
            
            -
            
            
            557Inventory
                obsolescence:2005
            
            
            201
            
            
            -
            
            
            11
            
            
            212
            
            
            -2004
            
            
            630
            
            
            -
            
            
            16
            
            
            445
            
            
            2012003
            
            
            650
            
            
            -
            
            
            -
            
            
            20
            
            
            6302003
                Predecessor
            
            
            650
            
            
            -
            
            
            -
            
            
            -
            
            
            650











**(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
            
            First
                Amended and Restated Agreement of Limited Partnership of Boardwalk
                Pipeline Partners, LP (Incorporated by reference to Exhibit 3.1 to
                the
                Registrant’s Current Report on Form 8-K filed on November 18,
                2005).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
            
            Revolving
                Credit Agreement, dated as of November 15, 2005, among Boardwalk
                Pipelines, LP (formerly known as Boardwalk Pipelines, LLC), 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, Citibank, N.A., as administrative agent for the lenders
                and the
                issuers, Wachovia Bank, National Association, as syndication agent,
                JPMorgan Chase Bank, N.A., Deutsche Bank Securities, Inc. and Union
                Bank
                of California, N.A., as co-documentation agents, and Citigroup Global
                Markets Inc. and Wachovia Capital Markets LLC, 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 November 18,
                2005).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
            
            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)10.9
            
            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).*10.10
            
            Form
                of Phantom Unit Award Agreement under the Boardwalk Pipeline Partners
                Long-Term Incentive Plan.*21.1
            
            List
                of Subsidiaries of the Registrant.*31.1
            
            Certification
                of, Rolf A. Gafvert, Co-President, pursuant to Rule 13a-14(a) and
                Rule
                15d-14(a).*31.2
            
            Certification
                of H. Dean Jones II, Co-President, pursuant to Rule 13a-14(a) and
                Rule
                15d-14(a).*31.3
            
            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 and H. Dean Jones II, Co- Presidents, 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 10.8 except for the identities of Gulf South
                Pipeline Company, LP and Boardwalk Pipelines, LLC and the date of
                the
                agreement.













**SIGNATURE**







Pursuant
      to the requirements of Section 13 or 15(d) of the Securities Exchange Act of
      1934, the Registrant has duly caused this report to be signed on its behalf
      by
      the undersigned, thereunto duly authorized.





**Boardwalk
                Pipeline Partners, LP**By:
            Boardwalk
                GP, LPits
                general partnerBy:
            Boardwalk
                GP, LLCits
                general partnerDated:March15, 2006
            
            
            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:
                  March 16, 2006
              */s/
                  H. Dean Jones II*H.
                  Dean Jones II
              Co-President
                  and Director
                (co-principal
                  executive officer)Dated:
                  March 16, 2006
              */s/
                  Rolf A. Gafvert*Rolf
                  A. Gafvert
              Co-President
                  and Director
                (co-principal
                  executive officer)Dated:
                  March 16, 2006
              */s/
                  Jamie L. Buskill*Jamie
                  L. Buskill
              Chief
                  Financial Officer
                (principal
                  financial and accounting officer)Dated:
                  March 16, 2006
              */s/
                  Thomas E. Hyland*Thomas
                  E. Hyland
              DirectorDated:
                  March 16, 2006
              */s/
                  Jonathon E. Nathanson*Jonathon
                  E. Nathanson
              DirectorDated:
                  March 16, 2006
              */s/
                  Arthur L. Rebell*Arthur
                  L. Rebell
              DirectorDated:
                  March 16, 2006
              */s/
                  Mark Shapiro*Mark
                  Shapiro
              DirectorDated:
                  March 16, 2006
              */s/
                  Andrew H. Tisch*Andrew
                  H. Tisch
              Director