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 FredericaStreet, 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 filer  o Accelerated filer  ¨ Non-accelerated filer  x

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

ITEM 5.  MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES.

Overview

Recent Expansion Projects

Trends and Uncertainties

Critical Accounting Policies and Estimates

Financial Analysis of Operations

Liquidity and Capital Resources

Forward-Looking Statements

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	$	292.5
Borrowings under credit facility		42.1
	$	334.6
Use of proceeds:
Underwriting discount	$	17.6
Structuring fee		1.2
Professional fees and offering costs		2.3
Reimbursement of BPHC for capital expenditures		42.1
Repayment of debt owed to Loews		250.0
Retained for working capital		21.4
Total	$	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	$	251,585
Net income		100,925		48,825		22,451		34,474		56,099		45,131
EBITDA**		291,188		144,864		77,467		80,345		151,042		143,114
Total assets		2,465,491		2,472,140		1,238,627		N/A		1,412,148		1,396, 519
Long-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	$	45,131
Provision for income taxes		-		-		-		22,387		36,647		30,484
Charge-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		45,821
Interest expense		58,589		29,729		19,368		7,392		20,490		21,678
EBITDA	$	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	$	34.2
Expansion capital		30.1		7.7
Total	$	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	$	3.2
Interest on long-term debt		709.9		58.8		117.5		117.5		416.1
Capital commitments		15.8		15.7		0.1		-		-
Principal payments on long-term debt		1,110.0		-		-		-		1,110.0
Total	$	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	$	16,518
Receivables, net:
Trade		59,115		45,662
Other		5,564		26,978
Gas Receivables:
Transportation and exchange		29,557		34,294
Storage		12,576		13,948
Inventories		15,881		14,182
Costs recoverable from customers		3,560		2,611
Deferred income taxes		-		13,390
Gas stored underground		6,500		3,534
Prepaid expenses and other current assets		7,720		7,225
Total current assets		206,265		178,342
Property, Plant and Equipment:
Natural gas transmission plant		1,772,483		1,676,729
Other natural gas plant		213,136		215,195
		1,985,619		1,891,924
Less—accumulated depreciation and amortization		118,213		49,801
Property, plant and equipment, net		1,867,406		1,842,123
Other Assets:
Goodwill		163,474		163,474
Gas stored underground		169,177		149,872
Deferred income taxes		-		46,206
Costs recoverable from customers		43,960		35,984
Advances to affiliates, non-current		-		41,812
Other		15,209		14,327
Total other assets		391,820		451,675
Total 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		$	21,135
Affiliates		835			1,659
Other		3,681			6,251
Gas Payables:
Transportation and exchange		14,710			25,422
Storage		27,559			28,296
Accrued taxes other		16,004			10,523
Accrued interest		17,996			5,241
Accrued payroll and employee benefits		29,028			25,796
Current note payable		42,100			-
Other current liabilities		29,941			37,733
Total current liabilities		202,287			162,056
Long -Term Debt		1,101,290			1,106,135
Other Liabilities and Deferred Credits:
Postretirement benefits		32,413			28,001
Asset retirement obligation		14,074			3,254
Provision for other asset retirement		33,212			29,700
Other		93,541			50,067
Total other liabilities and deferred credits		173,240			111,022
Commitments 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		-			1,071,651
Member’s equity		-			21,276
Accumulated other comprehensive loss		(174	)		-
Total member’s equity and partners’ capital		988,674			1,092,927
Total 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		$	111,622
Gas storage		21,667			7,289			2,435			814
Other		12,225			2,844			1,732			1,011
Total operating revenues		560,466			263,621			142,860			113,447
Operating Costs and Expenses:
Operation and maintenance		174,641			48,336			25,430			16,097
Administrative and general		78,752			52,535			29,646			13,642
Depreciation and amortization		72,078			33,977			20,544			16,092
Taxes other than income taxes		27,361			19,044			10,690			6,077
Net gain on disposal of operating assets		(7,846	)		-			-			(30	)
Total operating costs and expenses		344,986			153,892			86,310			51,878
Operating Income		215,480			109,729			56,550			61,569
Other (Income) Deductions:
Interest expense, net		58,589			29,729			19,368			7,392
Interest 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			4,708
Income before income taxes		160,521			81,158			37,555			56,861
Provision for income taxes *		-			-			-			22,387
Charge-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		720
Limited partners’ interest in net income	$	35,272
Net income per limited partners’ unit:
Common units and subordinated units	$	0.35
Weighted-average number of limited partners units outstanding:
Common units		68,256,122
Subordinated 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		$	34,474
Adjustments to reconcile to cash provided
from (used in) operations:
Depreciation and amortization		72,078			33,977			20,544			16,092
Amortization of acquired executory contracts		(9,630	)		-			-			-
Provision for deferred income taxes		54,682			43,428			19,962			5,494
Net 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	)		5,004
Accrued 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	)		27,196
Net cash provided by operating activities		218,714			104,416			61,523			37,730
INVESTING 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			-			277
Cash 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	$	681,809
Sale of common units, net of related transaction costs (15,000,000 units)		-		-			-			-			-		271,398		-		-		271,398
Other 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	$	71,283
Property, plant and equipment		1,159,251
Other non-current assets		28,319
Current 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	$	468,046
Income before income taxes		121,598		75,182
Net 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. 71Texas 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		23
Gathering		88,852		19		91,330		19
Storage		155,717		46		129,294		50
Transmission		1,484,901		42		1,407,055		43
General		64,548		19		47,081		19
Total utility depreciable plant		1,804,794		41		1,687,650		41
Non-depreciable:
Land		9,470				9,318
Storage		85,393				94,258
Other		85,962				100,698
Total other		180,825				204,274
Total PPE		1,985,619				1,891,924
Less: accumulated depreciation		118,213				49,801
Total 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	$	128
Tax effect of AFUDC equity		7,236		6,526
Unamortized debt expense and premium on reacquired debt		12,701		13,699
Postretirement benefits other than pension		33,156		32,374
Fuel 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		-		$	917
System management/cashout tracker		-			77
Provision for asset retirement	$	33,212			29,700
Unamortized 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	$ 4.0
2007	1.1
2008	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	$ 3,254
Liabilities recorded	10,593
Liabilities settled	(417)
Accretion expense	644
Balance 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	$   4.9
2007	4.0
2008	3.2
2009	2.8
2010	2.6
Thereafter	3.6
Total	$ 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	$ 15.7
1-2 years	0.1
3-5 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		$	185,000
Interim term loan		-			575,000
5.50% Notes due 2017		300,000			-
Texas Gas
7.25% Debentures due 2027		100,000			100,000
4.60% Notes due 2015		250,000			250,000
Gulf South
5.05% Notes due 2015		275,000			-
		1,110,000			1,110,000
Unamortized 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		$	90,719
Service cost		4,052			3,516
Interest cost		6,220			5,582
Actuarial loss		6,132			6,373
Benefits paid		(3,994	)		(2,717	)
Benefit obligation at end of period		115,883			103,473
Change in plan assets:
Fair value of plan assets at beginning of period		93,056			89,302
Actual return on plan assets		7,131			6,471
Benefits paid		(3,994	)		(2,717	)
Fair value of plan assets at end of period		96,193			93,056
Funded status		(19,690	)		(10,417	)
Unrecognized net actuarial loss		15,849			10,289
Net 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		$	1,631
Interest cost		6,220			5,582			3,243			2,223
Expected 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	$ 3,179
2007	3,690
2008	4,790
2009	6,447
2010	7,968
2011 - 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		$	105,036
Service cost		2,076			2,095
Interest cost		7,222			5,912
Plan participants’ contributions		1,328			1,044
Actuarial loss		5,379			17,480
Benefits 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			71,717
Actual return on plan assets		5,164			4,837
Employer contributions		3,888			4,869
Plan participants’ contributions		1,328			1,044
Benefits paid		(7,416	)		(5,968	)
Fair value of plan assets at end of year		79,463			76,499
Funded status		(54,725	)		(49,100	)
Unrecognized net actuarial loss		20,411			15,927
Net 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		$	2,095
Interest cost		7,222			5,912
Amortization 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	$ 5,292
2007	5,596
2008	5,948
2009	6,260
2010	6,502
2011 - 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	$ 18,077
Total 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	)	$	14,234
State		870		(1,964	)		(717	)		2,659
		4,914		(11,095	)		(4,858	)		16,893
Deferred provision:
Federal		36,690		35,803			17,666			4,522
State		7,890		7,625			2,296			972
Elimination of cumulative deferred taxes		10,102		-			-			-
		54,682		43,428			19,962			5,494
Net provision for income taxes		-		-			-		$	22,387
Net 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	$	19,901
Increases in taxes resulting from:
State income taxes		5,694		3,680		1,709		2,587
Other, net		217		248		250		(101	)
Elimination of deferred taxes		10,102		-		-		-
Net provision for income taxes		-		-		-	$	22,387
Charge-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	$	93,498
Accrued payroll, pension and other benefits		14,018
Deferred income		1,086
Net operating loss carryover		16,216
Other assets		3,479
Total deferred tax assets		128,297
Deferred tax liabilities:
Storage gas		65,568
Unamortized debt expense		3,133
Total deferred tax liabilities		68,701
Net 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	$	16,518
Advances 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.	$    292
Transcontinental Gas Pipe Line Corp.	1,670
Total 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	$	9,852
Income taxes, net		-		-		492		28,199
Non-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 31
Operating revenues	$	170,905	$	120,916	$	118,263	$	150,382
Operating expenses		89,378		99,898		81,910		73,800
Operating income		81,527		21,018		36,353		76,582
Interest expense, net		14,964		14,632		14,482		14,511
Other income		722		1,215		922		771
Income before income taxes		67,285		7,601		22,793		62,842
Charge-in-lieu of income taxes		22,476		3,047		9,088		24,985
Net income	$	44,809	$	4,554	$	13,705	$	37,857

	2004 For the Quarter Ended:
	December 31		September 30		June 30		March 31
Operating revenues	$	79,103	$	46,920	$	51,925	$	85,673
Operating expenses		44,371		38,068		36,308		35,145
Operating income		34,732		8,852		15,617		50,528
Interest expense, net		7,444		7,276		7,314		7,695
Other income		525		254		139		240
Income before income taxes		27,813		1,830		8,442		43,073
Charge-in-lieu of income taxes		11,032		813		3,458		17,030
Net 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 Director
H. Dean Jones II	53	Co-President and Director
Jamie L. Buskill	41	Chief Financial Officer
Arthur L. Rebell	64	Director, Chairman of the Board
Thomas E. Hyland	60	Director
Jonathan E. Nathanson	43	Director
Mark L. Shapiro	61	Director
Andrew 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 and
President of Gulf South
H. Dean Jones II	282,692	195,000	80,000	171,412 (4)
Co-President and
President of Texas Gas
Jamie L. Buskill	170,000	100,000	35,000	55,283 (5)
Chief Financial Officer
and 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	$	554
Audit related fees (2)		720		-
Tax fees (3)		6		18
All 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	$	730
2004		203		-		-			29		174
2003		557		-		354			-		203
2003 Predecessor		557		-		-			-		557
Inventory obsolescence:
2005		201		-		11			212		-
2004		630		-		16			445		201
2003		650		-		-			20		630
2003 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, LP
			its general partner
		By:	Boardwalk GP, LLC
			its general partner
Dated: March 15, 2006			By:	/s/ Jamie L. Buskill
				Jamie L. Buskill
				Chief 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	Director
Dated: March 16, 2006	/s/ Jonathon E. Nathanson
	Jonathon E. Nathanson	Director
Dated: March 16, 2006	/s/ Arthur L. Rebell
	Arthur L. Rebell	Director
Dated: March 16, 2006	/s/ Mark Shapiro
	Mark Shapiro	Director
Dated: March 16, 2006	/s/ Andrew H. Tisch
	Andrew H. Tisch	Director