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 endedDecember 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

TEXAS GAS TRANSMISSION, LLC

(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)

NONE

Securities registered pursuant to Section 12(b) of the Act

NONE

Securities registered pursuant to Section 12(g) of the Act

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 15(d) of the Act.

Yes x  No o

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.        Yes x    No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.        x

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer.

(See definition of “Accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (check one)

Large accelerated filer  o Accelerated filer  o 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 o  No x

Documents incorporated by reference.    None.

Texas Gas Transmission, LLC meets the conditions set forth in General Instruction (I)(1)(a) and (b) of Form 10-K and is therefore filing this Form 10-K with the reduced disclosure format.

TABLE OF CONTENTS

2005 FORM 10-K

TEXAS GAS TRANSMISSION, LLC

Business

Critical Accounting Policies and Estimates

Financial Analysis of Operations

Impact of Inflation

Financial Condition and Liquidity

Recent Accounting Pronouncements

Forward-Looking Statements

PART I

Item 1.  Business.

We are a wholly owned subsidiary of Boardwalk Pipelines, LP (formerly Boardwalk Pipelines, LLC) (Boardwalk Pipelines) which is a wholly owned subsidiary of Boardwalk Pipeline Partners, LP (Boardwalk Pipeline Partners). Boardwalk Pipeline Partners is a publicly-traded Delaware limited partnership formed in 2005, by a subsidiary of Loews Corporation (Loews) to own and operate the business conducted by Boardwalk Pipelines. We were acquired by Boardwalk Pipelines on May 16, 2003, from a subsidiary of The Williams Companies, Inc. (Williams) (Acquisition).

Throughout this report, we refer to Texas Gas Transmission, LLC, using "Texas Gas," "the Company," "we," "us," "our," and like terms.

We are an interstate natural gas transmission company which owns and operates a natural gas pipeline system originating in the Louisiana Gulf Coast area and in East Texas and running north and east through Louisiana, Arkansas, Mississippi, Tennessee, Kentucky, Indiana and into Ohio, with smaller diameter lines extending into Illinois. Our direct market area encompasses eight states in the South and Midwest and includes the Memphis, Tennessee; Louisville, Kentucky; Cincinnati, Ohio; and Evansville and Indianapolis, Indiana metropolitan areas. We also have indirect market access to the Northeast through interconnections with unaffiliated pipelines.

At December 31, 2005, our pipeline transmission system had a mainline delivery capacity of approximately 2.8 billion cubic feet (Bcf) of gas per day, composed of approximately 5,900 miles of mainline, storage, and branch transmission pipelines and 31 compressor stations having a National Electrical Manufacturers Association (NEMA)-rated capacity totaling 530,545 horsepower.

We own and operate natural gas storage reservoirs in nine underground storage fields located in Indiana and Kentucky. The certificated storage capacity of our fields is approximately 178 Bcf of gas, of which approximately 63 Bcf is certificated as working gas. We own a majority of the gas in our storage fields which we use to meet operational balancing needs on our system, to meet the requirements of firm and interruptible storage customers, and to meet the requirements of our no-notice transportation customers, which allows these customers to temporarily draw from storage gas during the winter season to be repaid during the following summer season. A small amount of storage gas is also used to provide summer no-notice transportation (SNS), designed primarily to meet the needs of summer-season electrical power generation facilities. SNS customers may temporarily draw from our storage gas in the summer, to be repaid in-kind during the same summer season.A large portion of the gas we deliver to our market area is used for space heating, resulting in substantially higher daily requirements during winter months.

Sources of Natural Gas Supply

The principal sources of supply for our pipeline system 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. 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 our no-notice service (NNS). We also provide interruptible parking and lending (PAL) 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 and storage services are subject to a maximum tariff rate authorized by the Federal Energy Regulatory Commission (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.

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 to us regardless of actual pipeline or storage capacity utilization) as well as other charges based on actual utilization. Additionally, we offer interruptible transportation, short-term firm transportation and storage services under agreements that are generally short-term.

Customers and Markets Served

We transport and store natural gas for a broad mix of customers including local distribution companies (LDCs) and municipalities, (93), interstate and intrastate pipelines (15), direct industrial users (10), electric power generation plants (19), and various marketers and producers. In addition to serving directly connected markets, our pipeline system has access to customers in the northeastern and southeastern United States through numerous interconnections with unaffiliated pipelines. In total, at December 31, 2005, we had transportation contracts with 465 shippers.

Each of the following customers accounted for over 10% of our total operating revenue for the year ended December 31, 2005:

Customer	For the Year Ended December 31, 2005
ProLiance Energy, LLC	19.74%
Atmos Energy	10.97%
Louisville Gas & Electric	10.20%

If we are 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 could have a material adverse effect on our financial condition, results of operations and cash flows.

The following table summarizes our total system transportation volumes for the periods shown (expressed in trillion British thermal units [TBtu]):

	For the Year Ended December 31,
	2005	2004	2003
Transportation volumes	718.1	670.0	662.0
Average daily transportation volumes	2.0	1.8	1.8
Average daily firm reserved capacity	2.3	2.2	2.2

Seasonality

Our revenues are seasonal in nature and are affected by weather and 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 system. Colder than normal winters or warmer than normal summers typically result in increased pipeline revenues. Price volatility also affects gas prices, which in turn influence drilling and production. Peak demand for natural gas occurs during the winter months, caused by the heating load, and during 2005, approximately 61% of our operating revenues were realized in the first and fourth calendar quarters.

Regulatory and Environmental

We are subject to regulation by FERC under the Natural Gas Act (NGA) of 1938 and under the Natural Gas Policy Act (NGPA) of 1978, and as such, our rates and charges for the transportation of natural gas in interstate commerce, the extension, enlargement or abandonment of jurisdictional facilities, and our accounting, among other things, are subject to regulation. We hold certificates of public convenience and necessity issued by FERC authorizing ownership and operation of all pipelines, facilities and properties considered jurisdictional for which certificates are required under the NGA.

Our rates are established primarily through FERC’s ratemaking process. Key determinants in the ratemaking 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. We filed a new rate case with the FERC in 2005, and implemented new rates effective November 1, 2005, subject to refund. As of December 31, 2005, a refund liability of approximately $5.0 million related to the 2005 rate case had been recorded.

Our operations 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. For further discussion of this issue, see Item 1A, “Risk Factors”, contained herein.

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) 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", contained herein.

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 and Indiana, with the new Heartland Gas Pipeline currently being constructed in Indiana posing a new competitive threat. The principal elements of competition among pipelines are rates, terms of service, access to supply basins, and flexibility and reliability of service. In addition, FERC’s continuing efforts to increase competition in the natural gas industry are having the effect of increasing the natural gas transportation options of our traditional customer base. As a result, segmentation and capacity release have created an active secondary market which is increasingly competitive with us.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 either attract new supply or attach new load 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.

Competition dictates that much of our transportation services are provided at less than the current maximum applicable rates allowed by our tariff due to competition. This competition occurs in the direct market areas such as Memphis, Louisville, Cincinnati, Dayton and Indianapolis and in indirect market areas such as New Jersey and New York. Increased gas supplies brought to the United States from Canada are an increasing factor in the northern portion of our direct and indirect market areas.

Although increased competition has impacted our business, we believe we are well positioned to execute our business strategy due to the following competitive strengths:

• Our assets are well located to transport natural gas from prolific supply regions to high demand markets;

• Our cash flow is relatively stable due to the monthly capacity reservation charges received on our firm transportation and storage contracts and the fee-based nature of our business;

• We have financial flexibility to pursue growth opportunities;

• Our relationship with Loews provides access to additional strategic guidance, financial expertise and a potential source of capital; and

• Our management team has, on average, more than 20 years of experience in the natural gas pipeline and storage business.

Employee Relations

We had 678 employees as of December 31, 2005. A satisfactory relationship continues to exist between management and labor. The International Chemical Workers Union Council of the United Food and Commercial Workers International Union, Local 187C, represents 112 of our 372 field employees. Our collective bargaining agreement with Local 187C will expire on April 30, 2007.

We have a non-contributory, defined benefit pension plan and various other plans, which provide regular active employees with group life, hospital and medical benefits as well as disability benefits and savings benefits. For further discussion of employee benefits, see Note 5 of Notes to Financial Statements contained in Item 8 herein.

Available Information

Our internet website is located at www.txgt.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 obtained at no cost, by contacting: Texas Gas, 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 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.

Each of the risks and uncertainties described below could lead to events or circumstances that have a material adverse effect on our business, results of operations, financial condition and cash flows.

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, we filed a rate case requesting an 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 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 be assured that we will be able to recover all of our costs through existing or future rates. An adverse determination in our pending rate case, or in any future rate proceeding could have a material adverse effect on our business, financial condition, results of operations and cash flows.

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 businesses.

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 us to compete 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 re-file a new contract with FERC or, alternatively, to amend its tariff to include the deviating term, thereby offering it to all shippers. If FERC audits a pipeline’s contracts and finds 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 the 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 business, 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 Recent Catastrophic Events in the Notes to Financial Statements contained herein.

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 the transportation and storage of natural gas. Our operations are subject to extensive federal, state and local laws and regulations relating to protection of the environment. These laws include, for example:

(1) the federal Clean Air Act (CAA) and analogous state laws which impose obligations related to air emissions;

(2) the federal 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;

(3) the federal Comprehensive Environmental Response, Compensation and Liability Act, also known 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

(4) the federal Resource Conservation and Recovery Act, also known as RCRA, 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 on commercially reasonable 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. 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, fail to cover certain hazards or fail to 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 U.S. Department of Transportation (DOT) Office of Pipeline Safety 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 a “high consequence area” (HCA) 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 Office of Public Safety 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 pipeline are subject to the requirements of the federal Occupational Safety & 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, we have 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, we 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 system, 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 an average of approximately 3.2% per year according to the Energy Information Administration. 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 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, and 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:

§ the level of successful drilling activity near our pipelines;

§ our ability to compete for these supplies;

§ the successful completion of new liquefied natural gas (LNG) facilities near our pipelines, and

§ 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 financial condition, results of operations and cash flows.

Offtake capacity at our Lebanon, Ohio terminus is limited.

The northeastern terminus of our 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. Approximately 54% of our long-term contracts covering offtake from 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 25% of the firm contract demand on our pipeline system 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.

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;  

• 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, three customers (ProLiance Energy, LLC, Atmos Energy and Louisville Gas and Electric) accounted for approximately 41% 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 parking and lending services and no-notice services. Average natural gas prices have increased dramatically in recent years. This rise in gas prices has materially increased our 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 35 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 that gas 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 have been 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 us, it could have a material adverse effect on our liquidity, financial position and results of operations.

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. If any of these pipeline connections 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 parking and lending 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 involve risks that may adversely affect our business.

Any expansion or new construction involves potential risks, including:  

• performance of our business following the 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 expanded or constructed assets; and 

• diversion of our management’s attention from other business concerns.

Any of these factors could adversely affect our ability to realize the anticipated benefits from newly expanded or constructed assets and meet our debt service requirements. The process of integrating newly 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 and results of operations.

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 due to increased costs to renew such rights, could have a material adverse effect on our business, results of operations and financial condition.

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.

Item 1B.Unresolved Staff Comments

None.

Item 2.Properties.

We own our pipeline system in fee, with certain immaterial portions, such as the offshore areas, being held jointly with third parties. However, a substantial portion of our system is constructed and maintained pursuant to rights-of-way, easements, permits, and licenses or consents on and across property owned by others. Our compressor stations, with appurtenant facilities, are located on lands owned by us in fee. We own our main office building which has approximately 108,000 square foot of office space, and other facilities located in Owensboro, Kentucky. We own our natural gas storage facilities located in Indiana and Kentucky. None of our property is encumbered and all property is in use. For additional information on our material property, including our pipelines and storage facilities, please read Item 1. Business

Item 3.Legal Proceedings.

For a discussion of certain of our current legal proceedings, see Note 3 of Notes to Financial Statements contained in Item 8 herein.

PART II

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

We are wholly-owned by Boardwalk Pipelines, which is an indirect majority-owned subsidiary of Loews. As such, there is no public trading market for our common equity.

Item 7.  Management's Narrative Analysis of the Results of Operations.

The following discussion and analysis of financial condition and operations should be read in conjunction with financial statements and the related notes thereto, included in Item 8, and with Item 1A, "Risk Factors."

Business

We are an interstate natural gas transmission company comprised of 5,900 miles of mainline, storage and branch transmission pipelines. We use 31 compressor stations located throughout the system with a NEMA-rated capacity totaling 530,545 horsepower capable of delivering 2.8 Bcf of gas per day on the mainline. The map below reflects the location of our system:

Approximately 81% of our revenue comes from customers reserving space on our transmission system for transportation of gas at their demand. Approximately 90% of the total capacity is currently reserved by our customers, with an average contract life of over three years. For the year 2005, we successfully extended contracts representing roughly 794,000 MMBtu/day and remarketed approximately 451,000 MMBtu/day of our winter capacity. We have contractual agreements representing approximately 542,000 MMBtu/day of winter capacity expiring in 2006 but have already successfully extended or remarketed approximately 65% of this potential turnback. We believe most of the remaining contracts will also be renewed or remarketed.

In addition to our transmission assets, we operate nine storage fields located at the northern end of our system in western Kentucky and southern Indiana. The storage fields have a total certificated capacity of 178 Bcf of gas, of which 63 Bcf is considered working gas. We own a majority of our storage gas which we use, in part to meet operational balancing needs on our system, in part to meet the requirements of our storage customers, and in part to meet the requirements of no-notice transportation customers.

In November 2005, we completed the expansion of our 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, we have 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 be placed into service in late 2007.

In conjunction with the storage expansion mentioned above, in November 2005, we sold 3.3 Bcf of our 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 for $12.2 million was recorded in November 2005.

Although we do not purchase gas supply for resale, it is important that we provide our customers access to adequate, diverse gas supply options to maintain our competitive position. We continually assess the nature of our supply areas and explore alternative, as well as enhancement, opportunities of existing facilities. In 2005, we provided additional supply options for our customers, including:

· completing a meter expansion project at our Lowry interconnect with NGPL in June 2005, providing an incremental 75,000 MMBtu/day;

· completing an upgrade of our interconnect with Midwestern at Whitesville, Kentucky in November 2005, providing an incremental 125,000 MMBtu/day of potential Chicago-area supplies;

· placing into service a new interconnect at Woodlawn in Louisiana in August 2005, allowing us to receive up to 105,000 MMBtu/day from the Lake Charles LNG terminal, and

· placing into service numerous new direct-connect supplies primarily in Louisiana throughout 2005, allowing us to receive up to 98,000 MMBtu/day additional supply from producers.

Critical Accounting Policies and Estimates

The accompanying financial statements were prepared in accordance with U.S. generally accepted accounting principles (GAAP). As a result of the change in control of us, the financial statements presented for the period after the acquisition by Loews reflect a new basis of accounting. Accordingly, the Statements of Operations and Cash Flows have been separated by a bold vertical line into a pre-Acquisition period and a post-Acquisition period.

The accounting policies discussed below are considered by management to be critical to an understanding of our Statements of Financial Position and Operations 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 or cash flows.

Regulation.Our pipeline operations are regulated by FERC. FERC 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 third-party’s regulatory proceedings, advice of counsel and the estimated risk-adjusted total exposure, as well as other risks. We 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 our 2005 rate case relative to our current rate structure.As of December 31, 2005, an estimated refund liability of approximately $5.0 million related to the open general rate case was recorded on our Balance Sheet. We anticipate that the general rate case will be settled and all required refunds will be paid during 2006.

The Statement of Financial Accounting Standards (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, we capitalize certain costs and benefits as regulatory assets and liabilities, respectively, in order to provide for recovery from or refund to customers in future periods.

Our storage facilities store our gas as well as gas owned by customers. We 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 our tariff, we reflect an equal and offsetting receivable and payable for certain customer-owned gas in our facilities for certain storage and related services. The gas payables amount was valued at the historical cost of gas consistent with other balances, and was $34.8 million and $29.8 million at December 31, 2005 and 2004, respectively.

Contingencies. We record liabilities for estimated loss contingencies when we believe 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, and advice of legal counsel or third parties regarding the probable outcomes of the matter. 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 $3.5 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 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. For further discussion of our environmental liabilities, please read “Environmental and Safety Matters” under Note 3: Commitments and Contingencies in Item 8 herein.

Purchase Price Allocation and Impairment of Goodwill. The purchase price allocation 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. Accordingly, 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. An impairment test performed in accordance with SFAS No. 142 requires that a reporting unit’s fair value be estimated. We use a discounted cash flow model to estimate the fair value of our operating segment, 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. Accordingly, there have been no impairments recorded in 2005.

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.

Employee Benefits. 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 utilized 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 of the Notes to Financial Statements included under Item 8.

Financial Analysis of Operations

This analysis compares financial results of operations for the years 2005 and 2004.

Operating revenues decreased by $2.3 million to $259.2 million for the year ended December 31, 2005, compared to $261.5 million for the year ended December 31, 2004. The changes in revenues were primarily as follows:

· Gas transportation revenue increased by $1.4 million to $252.9 million for the year ended December 31, 2005, compared to $251.4 million for the year ended December 31, 2004, due to:

o On November 1, 2005, we completed our market area storage project in Western Kentucky and the associated transportation agreements contributed approximately $1.9 million in revenues during 2005;

o 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;

o On November 1, 2005, we implemented new rates, subject to refund, on our system and during 2005 recorded a reserve for revenues subject to refund of approximately $5.0 million; and

o Revenues associated with power plant load increased by $4.7 million due primarily to a warmer than normal summer in our market areas during 2005.

These increases were partially offset by contract renewals and related discounting at the Lebanon terminus of our system and unfavorable market conditions in January and February 2005, driven primarily by weather.

· Gas storage revenues decreased by $2.0 million for the year ended December 31, 2005, compared to the year ended December 31, 2004. This variance was the result of unusually high interruptible storage revenue generated in 2004 due to favorable market conditions and was partially offset by $0.3 million higher storage revenues in 2005 attributable to the Western Kentucky storage project.

· Other revenues decreased by $1.8 million down to $1.2 million in 2005 compared to the year ended December 31, 2004, with $0.9 million of the decrease attributable to the loss of rental revenue for a portion of our Owensboro office space in late 2004 and $0.2 million lower incidental gas and oil sales in 2005.

Operating costs and expenses decreased by $15.7 million, or 10%, compared to the year ended December 31, 2004. The changes in operating costs and expenses were primarily as follows:

· Operation and maintenance expenses increased by $2.1 million due primarily to $1.1 million higher project costs and a non-recurring system management tracker credit received during 2004;

· Administrative and general costs decreased by $6.2 million, or 12%, compared to 2004, primarily due to $2.0 million lower costs for group insurance, $1.5 million lower property and liability insurance, $1.2 million lower costs for employee benefits, and $1.5 million lower corporate overhead;

· Taxes other than income taxes increased by $1.0 million due to higher property valuations; and,

· Gain on disposal of operating assets increased by $12.2 million attributable to a gain on the sale of storage gas related to our Western Kentucky storage project.

Total other deductions decreased by $7.1 million for the year ended December 31, 2005, or 45%, compared to 2004, primarily due to $5.8 million higher interest income from affiliates.

Impact of Inflation

We have generally 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 will be allowed to recover and earn a return based on the increased actual costs incurred when existing facilities are replaced. Cost-based regulation along with competition and other market factors limit our ability to price services or products to ensure recovery of inflation’s effect on costs.

Financial Condition and Liquidity

We fund our operations and capital requirements with cash flows from operations. In addition, the notes payable from Boardwalk Pipelines are demand notes which we can demand to be repaid at any time. At December 31, 2005, the advances due us by Boardwalk Pipelines totaled $253.8 million. The interest rate on intercompany demand notes is compounded monthly based on the LIBOR plus one percent and is adjusted quarterly.

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 our credit ratings.

We participate in Boardwalk Pipelines’ cash management program to the extent we are permitted under FERC regulations. Under the cash management program, depending on whether we have short-term cash surpluses or requirements, Boardwalk Pipelines either provides cash to us or we provide cash to Boardwalk Pipelines.

Our capital expenditures, net of retirements and salvage, for 2005 and 2004 were $49.4 million and $41.9 million, respectively. We expect to make capital expenditures in 2006 of approximately $45-55 million. Although no assurances can be given, we expect to fund our capital requirements through cash flows from our operating activities and available cash. The table below summarizes our more significant contractual obligations by period (in millions):

	Payments due by Period
Contractual Obligations:	Total		Less than 1 year		1-2 years		3-5 years		More than 5 years
Capital commitments	$	13.5	$	13.4	$	0.1		-		-
Principal payments on long-term debt		350.0		-		-		-	$	350.0
Interest on long-term debt		265.4		18.8		37.5	$	56.2		152.9
Lease commitments		11.8		2.4		4.8		4.6		-
Total	$	640.7	$	34.6	$	42.4	$	60.8	$	502.9

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.

Recent Accounting Pronouncements

For discussion regarding recent accounting pronouncements, see Note 9 in Notes to Financial Statements contained herein.

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 officials of our company, are “forward-looking” statements within the meaning of the Private Securities Litigation Reform Act of 1995 (the “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 be,” “will continue,” “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 us, which may be provided by our 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 and 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 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.

• 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 projects, that we commence, or we may complete it on materially different terms 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 primarily related to our long-term debt. All interest on long-term debt is fixed in nature. Total long-term debt at December 31, 2005, had a carrying value of $348.0 million and a fair value of $355.6 million. The weighted-average interest rate of our long-term debt is 5.36%. The $250.0 million (4.60%) and $100.0 million (7.25%) long-term debt issues mature in 2015 and 2027, respectively.

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 parking and lending services and no-notice services. Average Natural gas prices have increased dramatically in recent years. This rise in gas prices has materially increased our 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 35 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 that gas 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 have been 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 us, it could have a material adverse effect on our liquidity, financial position and results of operations.

Item 8.  Financial Statements and Supplementary Data

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 financial position of Texas Gas Transmission, LLC (formerly Texas Gas Transmission Corporation) (the “Company”) as of December 31, 2005 and 2004, the related statements of operations, stockholder’s and member’s equity, and cash flows for the years ended December 31, 2005 and 2004, and for the periods January 1, 2003 through May 16, 2003 (pre-acquisition) and May 17, 2003 through December 31, 2003 (post-acquisition). These financial statements are the responsibility of the Company’s management.  Our responsibility is to express an opinion on the financial statements 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 Company 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 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 audits provide a reasonable basis for our opinion.

In our opinion, such financial statements present fairly, in all material respects, the financial position of Texas Gas Transmission, LLC as of December 31, 2005 and 2004, and the results of its operations and its cash flows for the years ended December 31, 2005 and 2004, and for the periods January 1, 2003 through May 16, 2003 (pre-acquisition) and May 17, 2003 through December 31, 2003 (post-acquisition), in conformity with accounting principles generally accepted in the United States of America. 

As discussed in Note 2 to the financial statements, the accompanying financial statements reflect a change associated with the Company’s tax status.

DELOITTE & TOUCHE LLP

Chicago, Illinois

March 13, 2006

TEXAS GAS TRANSMISSION, LLC

STATEMENTS OF FINANCIAL POSITION

(Thousands of Dollars)

	December 31,
ASSETS	2005		2004
Current Assets:
Cash and cash equivalents	$	84	$	12,201
Receivables, net:
Trade		34,350		26,900
Affiliates		371		1,527
Other		2,718		3,512
Gas Receivables:
Transportation and exchange		1,911		1,792
Transportation, affiliates		-		375
Storage		12,576		13,948
Advances to affiliates, current		19,718		-
Inventories		14,163		13,746
Costs recoverable from customers		3,560		2,611
Deferred income taxes		-		2,752
Prepaid expenses and other current assets		3,779		2,911
Total current assets		93,230		82,275
Property, Plant and Equipment:
Natural gas transmission plant		644,821		595,182
Other natural gas plant		155,965		168,180
		800,786		763,362
Less—Accumulated depreciation and amortization		79,372		49,508
Property, plant and equipment, net		721,414		713,854
Other Assets:
Goodwill		163,474		163,474
Gas stored underground		130,409		118,177
Advances to affiliates, non-current		234,060		166,668
Deferred income taxes		-		49,258
Costs recoverable from customers		43,960		35,984
Other		13,316		13,077
Total other assets		585,219		546,638
Total Assets	$	1,399,863	$	1,342,767
The accompanying notes are an integral part of these financial statements.

TEXAS GAS TRANSMISSION, LLC

STATEMENTS OF FINANCIAL POSITION

(Thousands of Dollars)

	December 31,
LIABILITIES AND MEMBER’S EQUITY	2005		2004
Current Liabilities:
Payables:
Trade	$	7,450	$	8,867
Affiliates		621		1,659
Other		1,077		511
Gas Payables:
Transportation and exchange		6,060		1,513
Transportation and exchange, affiliates		1,131		-
Storage		27,559		28,296
Accrued income taxes		-		1,286
Accrued taxes other		10,870		5,822
Accrued interest		4,281		4,281
Accrued payroll and employee benefits		22,433		21,770
Accrued fuel tracker		5,004		917
Other accrued liabilities		6,336		6,815
Total current liabilities		92,822		81,737
Long -Term Debt		347,976		347,802
Other Liabilities and Deferred Credits:
Postretirement benefits		32,413		28,001
Provision for other asset retirement		33,212		29,700
Other		11,446		12,330
Total other liabilities and deferred credits		77,071		70,031
Commitments and Contingencies (Note 3)		-		-
Member’s Equity:
Paid-in capital		811,491		803,748
Retained earnings		70,503		39,449
Total member’s equity		881,994		843,197
Total Liabilities and Member’s Equity	$	1,399,863	$	1,342,767
The accompanying notes are an integral part of these financial statements.

TEXAS GAS TRANSMISSION, LLC

STATEMENTS OF OPERATIONS

(Thousands of Dollars)

	Post-Acquisition									Pre-Acquisition
	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 Revenues:
Gas transportation	$	252,859		$	251,411		$	138,693		$	111,622
Gas storage		5,219			7,173			2,435			814
Other		1,161			2,913			1,732			1,011
Total operating revenues		259,239			261,497			142,860			113,447
Operating Costs and Expenses:
Operation and maintenance		49,298			47,159			25,430			16,097
Administrative and general		46,167			52,379			29,632			13,642
Depreciation and amortization		33,279			33,684			20,544			16,092
Taxes other than income taxes		17,796			16,844			10,690			6,077
(Gain) loss on disposal of operating assets		(12,208	)		-			1			(30	)
Total operating costs and expenses		134,332			150,066			86,297			51,878
Operating Income		124,907			111,431			56,563			61,569
Other (Income) Deductions:
Interest expense, net		19,071			19,758			13,353			7,392
Interest income from affiliates		(9,061	)		(3,270	)		(1,516	)		(1,965	)
Miscellaneous other income		(1,444	)		(783	)		(146	)		(719	)
Total other deductions		8,566			15,705			11,691			4,708
Income before income taxes		116,341			95,726			44,872			56,861
Provision for income taxes *		-			-			-			22,387
Charge-in-lieu of income taxes *		34,650			38,091			18,058			-
Elimination of cumulative deferred taxes *		30,649			-			-			-
Net Income *	$	51,042		$	57,635		$	26,814		$	34,474

*Results of operations for the year ended December 31, 2005, reflect a change in the tax status associated with Texas Gas as of November 2005. Accordingly, Texas Gas has recorded a charge-in-lieu of income taxes for the period January 1, 2005 through November 15, 2005, and has recorded no income taxes thereafter. Pursuant to the change in tax status, Texas Gas also eliminated its balance of accumulated deferred income taxes effective November 15, 2005 (as presented in line item, "Elimination of cumulative deferred taxes").  See Note 2 to the financial statements for additional information.

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

TEXAS GAS TRANSMISSION, LLC

STATEMENTS OF CASH FLOWS

(Thousands of Dollars)

	Post-Acquisition									Pre-Acquisition
	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	$	51,042		$	57,635		$	26,814		$	34,474
Adjustments to reconcile to cash provided from (used in) operations:
Depreciation and amortization		33,279			33,684			20,544			16,092
Provision for deferred income taxes		49,037			37,953			19,678			5,494
(Gain) loss on sale of operating assets		(12,208	)		-			1			(30	)
Changes in operating assets and liabilities:
Receivables		(25,391	)		5,567			10,378			(27,426	)
Inventories		(417	)		(217	)		73			(22	)
Affiliates		1,624			(341	)		473			(7,550	)
Other current assets		(976	)		6,200			(3,126	)		5,004
Accrued income taxes due affiliate		-			-			-			(11,306	)
Accrued and deferred income taxes		16,256			630			(2,109	)		-
Payables and accrued liabilities		9,802			(10,448	)		31,672			(4,196	)
Other, including changes in non-currentassets                           and liabilities		9,149			1,967			(34,966	)		27,196
Net cash provided by operating activities		131,197			132,630			69,432			37,730
INVESTING ACTIVITIES:
Capital expenditures, net of allowance for funds used during construction		(49,378	)		(41,920	)		(34,706	)		(43	)
Advances to affiliates, net		(93,936	)		(50,395	)		(116,146	)		(37,964	)
Net cash used in investing activities		(143,314	)		(92,315	)		(150,852	)		(38,007	)
FINANCING ACTIVITIES:
Proceeds from long-term debt		-			-			523,306			-
Payment of long-term debt		-			(17,285	)		(407,715	)		-
Dividends		-			(30,000	)		(15,000	)		-
Net cash provided by (used in) financing activities		-			(47,285	)		100,591			-
Increase (decrease) in cash and cash equivalents		(12,117	)		(6,970	)		19,171			(277	)
Cash and cash equivalents at beginning of period		12,201			19,171			-			277
Cash and cash equivalents at end of period	$	84		$	12,201		$	19,171		$	-

Supplemental Disclosure of Cash Flow Information:
Cash paid during the period for:
Interest (net of amount capitalized)	$	18,394	$	19,227	$	10,405	$	9,852
Income taxes, net		-		-		492		28,199
Non-cash dividends		19,988		-		-		29,022
Capital contribution from parent		7,743		-		-		-

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

TEXAS GAS TRANSMISSION, LLC

STATEMENTS OF STOCKHOLDER’S AND MEMBER’S EQUITY

(Thousands of Dollars)

	Retained Earnings			Common Stock		Paid-in Capital
Pre-Acquisition
Balance stockholder’s equity, January 1, 2003	$	101,070		$	1	$	630,608
Add (deduct):
Net income		34,474			-		-
Non-cash dividend		(29,022	)		-		-
Balance, stockholder’s equity, May 16, 2003	$	106,522		$	1	$	630,608
Post-Acquisition
Beginning Balance, Member’s Equity, May 16, 2003		-			-	$	802,813
Add (deduct):
Additional paid in capital		-			-		935
Dividends paid	$	(15,000	)		-		-
Net income		26,814			-		-
Balance, Member’s Equity, January 1, 2004		11,814			-		803,748
Add (deduct):
Dividends paid		(30,000	)		-		-
Net income		57,635			-		-
Balance, Member’s Equity, January 1, 2005		39,449			-		803,748
Add (deduct):
Dividends paid		(19,988	)		-		-
Additional paid in capital		-			-		7,743
Net income		51,042			-		-
Balance, Member’s Equity, December 31, 2005	$	70,503			-	$	811,491

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

TEXAS GAS TRANSMISSION, LLC

NOTES TO FINANCIAL STATEMENTS

Note 1:  Corporate Structure

Texas Gas Transmission, LLC (Texas Gas) is a wholly owned subsidiary of Boardwalk Pipelines, LP (formerly Boardwalk Pipelines, LLC) (Boardwalk Pipelines), which is a wholly owned subsidiary of Boardwalk Pipeline Partners, LP (Boardwalk Pipeline Partners). Boardwalk Pipeline Partners is a publicly-traded Delaware limited partnership formed November 15, 2005, by a subsidiary of Loews Corporation (Loews) to own and operate the business conducted by Boardwalk Pipelines. Texas Gas was acquired by Loews on May 16, 2003, from a subsidiary of The Williams Companies, Inc. (Williams) (Acquisition).

Basis of Presentation

The accompanying financial statements of Texas Gas were prepared in accordance with accounting principles generally accepted in the United States of America (GAAP). As a result of the change in control of Texas Gas, the financial statements presented for the period after the Acquisition reflect a new basis of accounting. Accordingly, the Statements of Operations, Stockholder’s and Member’s Equity and Cash Flows have been separated by a bold vertical line into a pre-Acquisition period and a post-Acquisition period.

The accompanying post-Acquisition financial statements reflect the pushdown of 100% of the purchase price resulting from the 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 Statement of Financial Accounting Standards (SFAS) No. 71, “Accounting for the Effects of Certain Types of Regulations”, 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 above the historical net book value was allocated to Goodwill. The accounting for the effects of the 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. As of December 31, 2005, Texas Gas had $163.5 million of goodwill recorded as an asset on its Statements of Financial Position.

The Acquisition was treated as an acquisition of assets for income tax purposes and, accordingly, Texas Gas had tax basis in its net assets approximately equal to the Acquisition price. In connection with the terms of this election, temporary differences that existed prior to the Acquisition no longer exist and differences between the new allocated purchase price for book and income tax were established as part of the purchase price allocation. Therefore, deferred tax asset and liability balances existing prior to the Acquisition have been eliminated. Texas Gas was converted into a limited liability company immediately following the Acquisition. The financial statements contained herein reflect a Charge-in-lieu of income taxes subsequent to the Acquisition consistent with its treatment as a division of a corporate entity and the operation of a tax-sharing agreement. Results of operations for the year ended December 31, 2005, reflect a change in the tax status associated with Texas Gas as of November 2005. Accordingly, Texas Gas has recorded a charge-in-lieu of income taxes for the period January 1, 2005 through November 15, 2005, and has recorded no income taxes thereafter. Pursuant to the change in tax status, Texas Gas also eliminated its balance of accumulated deferred income taxes effective November 15, 2005.

The following unaudited pro forma financial information is presented as if Texas Gas had been acquired as of the beginning of the period presented. The pro forma amounts include certain adjustments, including a reduction of Depreciation expense based on the allocation of the Acquisition purchase price to Property, plant and equipment; adjustment of Interest expense to reflect the issuance of post-Acquisition debt by Texas Gas, and the application of a portion of the proceeds of such debt to prepay $132.7 million principal amount of its existing notes and the related tax effect of these items.

	For the Year Ended December 31, 2003
Operating revenue	$ 255,811
Income before charge-in-lieu of taxes	103,018
Net income	60,784

The pro forma information does not necessarily reflect the actual results that would have occurred had Boardwalk Pipelines owned Texas Gas during the periods presented, nor is it necessarily indicative of future results of operations.

Note 2:  Accounting Policies

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, Texas Gas evaluates its estimates, including those related to revenues subject to refund, bad debts, materials and supplies obsolescence, investments, goodwill, property and equipment and other long-lived assets, workers' compensation insurance, pensions and other post-retirement and employment benefits, contingent liabilities, and prior to the elimination of income taxes, charge-in-lieu of income taxes. Texas Gas 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

Texas Gas operates in one reportable segment - gas transportation and integrated underground gas storage. This segment consists of an interstate natural gas pipeline system originating in the Louisiana Gulf Coast area and in East Texas and running north and east through Louisiana, Arkansas, Mississippi, Tennessee, Kentucky, Indiana and into Ohio, with smaller diameter lines extending into Illinois, having 5,900 miles of mainline, storage and branch transmission pipelines. In addition, Texas Gas owns and operates natural gas storage reservoirs in nine underground storage fields located in Indiana and Kentucky.

Regulatory Accounting

Texas Gas is regulated by FERC and is subject to the provisions of SFAS No. 71. Accordingly, it has recorded assets and liabilities on its Statements of Financial Position resulting from the effects of the ratemaking process, which would not be recorded under GAAP for non-regulated entities. Regulatory assets represent costs incurred that have been deferred because future recovery in customer rates is probable. Regulatory liabilities generally represent probable future reductions in revenue or refunds to customers. Texas Gas’ continued ability to meet the criteria for application of SFAS No. 71 may be affected in the future by competitive forces and restructuring in the natural gas industry. In the event that SFAS No. 71 no longer applied to all, or a separable portion, of Texas Gas’ operations, the related regulatory assets and liabilities would be written off unless an appropriate regulatory recovery mechanism is provided. None of its 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 Texas Gas Statements of Financial Position as of December 31, 2005 and 2004, are summarized as follows (shown in thousands):

Regulatory Assets	2005			2004
Pension	$	3,841		$	128
Income tax effect of AFUDC equity		7,236			6,526
Unamortized debt expense and premium on reacquired debt		12,701			13,699
Post retirement 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 Texas Gas’ 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 these items are recorded in the regulatory books of account.

Effective November 1, 1993, Texas Gas restructured its business to implement the provisions of FERC Order 636, which, among other things, required pipelines to unbundle their merchant role from their transportation services. FERC Order 636 also provided that pipelines should be allowed the opportunity to recover a portion of prudently incurred transition costs which, for Texas Gas, were primarily related to gas supply realignment (GSR) costs and unrecovered purchased gas costs.

In September of 1995, Texas Gas received FERC approval of a settlement agreement, which resolved all issues regarding Texas Gas’ recovery of GSR costs. Texas Gas paid approximately $76.0 million related to GSR costs and subsequently collected approximately $68.0 million, plus interest, from its customers.

GSR collections pursuant to the settlement ended in 2004. On November 19, 2004, Texas Gas filed a final GSR reconciliation report with the FERC and revised tariff sheets to remove the GSR recovery mechanism from its rates. On December 10, 2004, the FERC issued a letter order accepting the report. As a result, Texas Gas recognized $3.3 million of revenue and a $1.8 million expense adjustment related to the settlement during the fourth quarter of 2004. Texas Gas refunded approximately $0.4 million to customers during the first half of 2005.

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

Texas Gas participates in Boardwalk Pipeline Partners cash management program to the extent it is permitted under FERC regulations. Under the cash management program, depending on whether Texas Gas has short-term cash surpluses or requirements, Boardwalk Pipeline Partners either provides cash to Texas Gas or Texas Gas provides cash to Boardwalk Pipeline Partners.

Accounts Receivable and Allowance for Doubtful Accounts

Accounts receivable are stated at the historical carrying amount net of reserves or write-offs. Texas Gas 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. This allowance was approximately $0.2 million at December 31, 2005 and 2004. Texas Gas expensed $0.0 in 2005 and 2004, $(0.4) million in post-Acquisition 2003 and $0.0 in pre-Acquisition 2003 on its Statements of Operations to write off or reserve for doubtful accounts.

Advances to Affiliates

Texas Gas makes advances to Boardwalk Pipelines and 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. Advances relating to the cash management program are classified as current and other advances are classified as non-current based on Texas Gas’ anticipated demand for these funds during the next twelve months and thereafter. The interest rate on intercompany demand notes is the London Interbank Offered Rate (LIBOR) plus one percent and is adjusted each three-month period.

Inventories

Inventories consisting of materials and supplies are carried at the lower of average cost or market less an allowance for obsolescence. No allowance existed at December 31, 2005, while the balance at December 31, 2004, was $0.2 million.

Property, Plant and Equipment

Depreciation is provided primarily on the straight-line method at FERC prescribed rates, over estimated useful lives ranging from 5 to 56 years. Reflecting the application of composite depreciation, gains and losses from the ordinary sale and retirement of property, plant and equipment (PPE) generally does not impact net PPE. Other gains and losses are recorded in net income. Depreciation and amortization expenses for the years ended December 31, 2005, and December 31, 2004, were $33.3 million and $33.7 million, respectively, $20.5 million for post-Acquisition in 2003 and $16.1 million for pre-Acquisition in 2003.

PPE is recorded at its original cost of construction. Construction costs and expenditures for major renewals and improvements, which extend the lives of the respective assets, are capitalized.

Texas Gas 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.

The following table represents Texas Gas’ 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	$	12,889		23
Storage		76,399		58		52,001		73
Transmission		590,392		56		558,863		56
General		32,371		29		30,693		25
Total utility depreciable plant		709,938		54		654,446		56
N  Non-depreciable:
Land		4,641				4,485
Storage		61,701				77,060
Other		24,506				27,371
Total other		90,848				108,916
Total PPE		800,786				763,362
Less: accumulated depreciation		79,372				49,508
Total PPE, net	$	721,414			$	713,854

The non-transmission assets have weighted-average useful lives of 48 years and 51 years as of December 31, 2005 and 2004, respectively. The gross value of these non-transmission assets was $119.5 million and $95.6 million as of December 31, 2005 and 2004, respectively. The non-depreciable assets and work in progress of $129.3 million and $133.7 million as of December 31, 2005 and 2004, respectively, are not included in the calculation of the weighted-average useful lives.

Gas in Storage and Gas Receivables/Payables

Texas Gas has 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 services. Consistent with the above, certain of these volumes are necessary to provide storage services which allow third parties to store their natural gas in Texas Gas’ underground facilities. Additionally, in the course of providing transportation and storage services to customers, the quantities of gas received from shippers by the pipelines may differ from the quantities actually 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 financial statements reflect the balance of underground gas in storage, as well as the resulting activity around the services and balancing activity described above. Gas stored underground includes natural gas volumes owned by Texas Gas, reduced by certain operational encroachments upon that gas. These amounts are valued at historical cost, consistent with the provisions of SFAS No. 71.

Gas receivables and payables 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.Gas receivables and payables also represent certain amounts attributable to balancing and tariff services associated with the storage services. 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.

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 Texas Gas over the past 24 months at any one time to its customers has ranged from a high of approximately 35 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 that gas 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 have been 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 Texas Gas, it could have a material adverse effect on Texas Gas’ liquidity, financial position and results of operations.

Impairment of Goodwill

As part of the allocation of the purchase price of the 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. An impairment test performed in accordance with SFAS No. 142 requires that a reporting unit’s fair value be estimated. Texas Gas used a discounted cash flow model to estimate the fair value of its assets and liabilities and that estimated fair value was compared to its carrying amount, including goodwill. The estimated fair value was in excess of the carrying amount in 2005, therefore, no impairments were recorded.

Revenue Recognition

The maximum rates that may be charged by Texas Gas for its gas transportation and storage services are established through FERC rate-making purposes. Rates charged by Texas Gas 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 Statements of Financial Position. Texas Gas anticipates that the general rate case will be settled and all required refunds will be paid during 2006.

Repair and Maintenance Costs

Texas Gas accounts 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 for the years ended December 31, 2005, December 31, 2004, and for the pre- and post-Acquisition periods in 2003, was $0.5 million, $ 0.3 million, $0.3 million, $0.0 million, respectively. The allowance for equity funds used during construction for the years ended December 31, 2005, December 31, 2004, and pre- and post-Acquisition periods in 2003, was $1.4 million, $0.8 million, $0.7 million, $0.2 million, respectively. The allowance for borrowed funds used during construction reduces interest expense and the allowance for equity funds is included in Miscellaneous other income within the Statements of Operations.

Cash Flows From Operating Activities

Texas Gas 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.

Asset Retirement Obligations

Texas Gas has adopted SFAS No. 143, “Accounting for Asset Retirement Obligations,” which addresses accounting and reporting for a legal asset retirement obligation (ARO) 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. AROs exist for certain of Texas Gas’ utility assets; however, the fair value of these obligations cannot be determined because the end of the utility system life is not determinable with the degree of accuracy necessary to currently establish a liability for the obligations.

In March 2005, the Financial Accounting Standards Board (FASB) issued Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations, which clarifies when an entity is required to recognize a liability for the fair value of a conditional ARO. The Interpretation will be effective for fiscal years ending after December 15, 2005, with earlier adoption encouraged. In light of this Interpretation, Texas Gas has determined that an ARO exists on its corporate office building which was constructed in Owensboro, Kentucky in 1962. Under the legal requirements enacted by the EPA in 1973, Texas Gas became legally obligated to dismantle and remove the asbestos from its building at the end of its useful life, estimated to be sometime between the years 2112 through 2162. The estimated useful life was obtained from a study by the original architects performed in 1995 and confirmed by an independent consultant in 2003 indicating that the spray-applied asbestos can be maintained, in place, undisturbed, indefinitely when following written maintenance procedures. Texas Gas 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, Texas Gas 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.

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, and accordingly, has collected a certain amount in rates representing estimated costs of removal, which do not represent a legal obligation. Texas Gas has reclassified $33.2 million and $29.7 million as of December 31, 2005, and December 31, 2004, respectively, in the accompanying Statements of Financial Position as Provision for other asset retirement.

Income Taxes

Since the date of the Acquisition, Texas Gas has recorded a charge-in-lieu of income taxes consistent with its treatment as a division of a corporate entity and the operation of a tax-sharing agreement. In connection with the contribution of Boardwalk Pipelines Holding Company’s ownership interests in Boardwalk Pipelines to Boardwalk Pipeline Partners, the tax-sharing agreement ceased to exist coincident with the date of Boardwalk Pipeline Partners’ initial public offering on November 15, 2005. Accordingly, Texas Gas experienced a change in tax status as it was no longer a division of a tax-paying entity. Tax attributes of income and expense items will subsequently be allocated to the individual partners of Boardwalk Pipeline Partners who are subject to United States federal income taxation in accordance with the provisions of the partnership agreement. Additionally, all deferred income taxes included on the Statements of Financial Position as of November 15, 2005, have been reversed through the Statements of Operations.

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

Prior to November 15, 2005, for federal income tax reporting, Texas Gas, as a wholly owned subsidiary of Boardwalk Pipelines, was included in the consolidated federal income tax return of Loews. The tax-sharing agreement required Boardwalk Pipelines and its subsidiaries to remit to Loews on a quarterly basis any charges-in-lieu of federal income taxes as if it were filing a separate return.

Reclassifications

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

Note 3:  Commitments and Contingencies

Impact of Recent Catastrophic Events

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 portion of Texas Gas’ assets are located in the area directly impacted by the hurricanes, however it experienced only minimal damage. Texas Gas continued to operate throughout the hurricanes and thereafter and service to its customers has not been interrupted. Based upon current estimates, the replacement cost for damages is approximately $0.7 million.

Regulatory and Rate Matters

Storage Expansion Projects

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. Texas Gas 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.

Haughton, Louisiana Compressor Station

On October 4, 2005, Texas Gas filed an application in Docket No. CP06-2 for authority to install a back-up turbine compressor at its Haughton compressor station on its north Louisiana supply lateral. The new turbine would not increase the capacity of the lateral but would increase system reliability by providing back-up compression for existing units at Texas Gas’ Haughton, Louisiana and Sharon, Louisiana compressor stations. The project has a proposed in-service date of November 1, 2006, and an estimated total cost of approximately $10 million. Costs incurred through December 31, 2005 totaled approximately $2.2 million. Texas Gas received final approval for this project on February 15, 2006.

West Greenville-Elkton Lateral

On November 9, 2005, Texas Gas submitted a prior notice application in Docket No. CP06-22 for a certificate of public convenience and necessity to authorize it to construct the West Greenville-Elkton lateral in Muhlenberg and Todd Counties, Kentucky, to improve system reliability during periods of peak customer demand. If approved, the new lateral would provide an additional means of transporting natural gas to a growing market area and increase system security for Texas Gas’ customers in and around the Bowling Green, Kentucky area. The lateral will consist of approximately 27.5 miles of natural gas pipeline. The project is estimated to cost $14 million and is projected to be completed in November 2006. Costs incurred through December 31, 2005, totaled approximately $3.0 million. Since no protests were filed with FERC within the 45 day comment period that expired January 7, 2006, Texas Gas is authorized to proceed with the project.

East Texas Extension via Texas Eastern Lease

On November 21 2005, FERC issued an order authorizing Texas Gas to extend its system into east Texas by leasing 103,500 MMBtu/day of capacity from Texas Eastern for a primary term of five years. The capacity leased from Texas Eastern is located in the east Texas access area zone of Texas Eastern’s transmission system between Beckville, Texas, and Sharon, Louisiana. The capacity leased from Texas Eastern was combined with unsubscribed capacity on Texas Gas system to support a new five year service agreement with a shipper for 100,000 MMBtu/day of firm transportation service from Beckville, Texas to Lebanon, Ohio. In compliance with the conditions in the order, Texas Gas filed certain revised tariff sheets and the negotiated rate agreement with its anchor shipper and on December 23, 2005, FERC issued an order accepting both the revised tariff language and the negotiated rate agreement. The Texas Eastern lease and the shipper contract became effective as of December 1, 2005.

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.

Fuel Tracker Filing

On August 31, 2005, Texas Gas filed its annual fuel tracker filing with FERC, Docket No. RP05-617, to adjust its fuel retention percentages effective November 1, 2005. On October 31, 2005, FERC issued an order accepting the tariff sheets, subject to refund, and establishing a technical conference, which was held January 10, 2006. Texas Gas provided additional information on February 7, 2006, as agreed to at the conference. The post-technical conference comment process concludes March 14, after which the parties will await a FERC ruling. Texas Gas does not expect the resolution of this matter to have a material impact on future financial condition, results of operations or cash flows.

Operational Flow Order Penalty Filing

On December 9, 2005, Texas Gas submitted a filing to revise the penalty it charges for violating an Operational Flow Order (OFO) from a fixed price, to the greater of a fixed price or a formula based on a monthly index price. In an environment of rising natural gas prices, Texas Gas was concerned that its then-existing OFO charge of $25 per MMBtu was not an effective or sufficient deterrent to behavior that could compromise the operational integrity of its pipeline system. On January 6, 2006, FERC issued an order accepting the revised tariff sheets effective on January 1, 2006.

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. Texas Gas has complied with these requirements. Texas Gas has invested approximately $6.7 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. Texas Gas 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 proper accounting for the costs that pipeline operators will incur in implementing all aspects of pipeline integrity management programs in high consequence areas. 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 high consequence areas, 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. Texas Gas 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 is subject to federal, state, and local environmental laws and regulations in connection with the operation and remediation of various operating sites. Texas Gas 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, Texas Gas often enters into voluntary remediation programs with these agencies.

Beginning in 2004, Texas Gas entered into agreements, or began meeting with various state agencies, to address remediation issues primarily on a voluntary basis. As a result of these actions, Texas Gas increased its environmental accrual by $3.9 million during the fourth quarter of 2004. As of December 31, 2005 and 2004, Texas Gas had an accrued liability of approximately $3.5 million and approximately $4.1 million, respectively, for estimated 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 Texas Gas’ own 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 changes to 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:

a) 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

b) 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, EPA will notify Texas Gas that the settlement is effective and payment will be due within thirty days of the effective date.

Texas Gas is also subject to the federal Clean Air Act (CAA) and the CAA Amendments of 1990 (Amendments) which added significant provisions to the existing federal CAA. The Amendments require the EPA to promulgate new regulations pertaining to mobile sources, air toxics, areas of ozone non-attainment, and acid rain. Texas Gas operates one facility in an area designated as non-attainment 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 federal CAA provisions, the Amendments, and state implementation plans for nitrogen oxide (NOx) reductions. These costs are being recorded as additions to PPE as the facilities are added. Texas Gas currently estimates no additional costs for NOx compliance beyond 2005, however, if the EPA designates additional new non-attainment areas which impact operations, the cost of additions to PPE is expected to increase. As a result, Texas Gas 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 imposed controls in addition to the measures described above. Three facilities will be affected by the new regulations at an estimated cost of $1.3 million. The effective compliance date for the hazardous air pollutants regulations is 2007. Texas Gas anticipates installation of associated controls to meet these regulations in 2006 and 2007 and does not believe compliance with these regulations will have a material impact on the results of continuing operations or cash flows.

Texas Gas 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 Texas Gas’ environmental exposure included in the calculation of its asset retirement obligation, see Note 2 of these Notes to Financial Statements.

Litigation

Texas Gas is party to various other 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, Williams agreed to indemnify Texas Gas 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. Williams continues to defend Texas Gas as 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 Texas Gas. Since Williams has retained responsibility for these claims, they are not expected to have a material effect upon Texas Gas' future financial condition, results of operations or cash flows.

Other Commitments

Lease Commitments

Texas Gas has various operating lease commitments extending through the year 2010 covering 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 $0.5 million. The table below summarizes minimum future commitments related to these items at December 31, 2005, as follows (expressed in millions):

2006	$  2.4
2007	2.4
2008	2.4
2009	2.4
2010	2.2
Total	$ 11.8

Commitments for Construction

For the year ending December 31, 2006, Texas Gas expects to make capital expenditures of approximately $55 million, of which approximately $25 million is expected to be for maintenance capital and approximately $30 million is expected to be for expansion capital. The amount of expansion capital expended in 2006 could vary significantly depending on the number and types of capital projects Texas Gas decides to pursue, the timing of any of those projects and numerous other factors beyond its control. Texas Gas expects to fund its 2006 capital expenditures through operating cash flows from operations. Texas Gas incurred approximately $49.4 million, net, in capital expenditures through December 31, 2005.

Texas Gas’ capital commitments for contracts already authorized are expected to approximate the following amounts for the next five years (expressed in millions):

Capital Commitments	Total
Less than 1 year	$ 13.4
1-2 years	0.1
3-5 years	-
More than 5 years	-
Total	$ 13.5

Note 4:  Financing

Long-term debt issues were outstanding as follows (expressed in thousands):

	December 31,
	2005			2004
Debentures:
7.250% due 2027	$	100,000		$	100,000
Notes:
4.600% due 2015		250,000			250,000
		350,000			350,000
Unamortized debt discount		(2,024	)		(2,198	)
Total long-term debt	$	347,976		$	347,802

As of December 31, 2005 and 2004, the weighted-average interest rate of Texas Gas’ long-term debt was 5.36%. Texas Gas' debentures and notes have restrictive covenants which provide that, with certain exceptions, Texas Gas cannot create, assume or suffer to exist any lien upon any property to secure any indebtedness unless the debentures and notes shall be equally and ratably secured. All of Texas Gas’ obligations are unsecured. At December 31, 2005, Texas Gas was in compliance with its debt covenants.

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 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 Statements of Financial Position 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 Balance Sheet consist of:

	Pension Benefits
	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.

Texas Gas’ 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, it 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 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 provides postretirement medical benefits to retired employees who were employed full time, hired prior to January 1, 1996, and have met certain other requirements. Texas Gas 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-Acquisition and $2.7 million during the pre-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 is $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 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
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 Statements of Financial Position 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:
	December 31, 2005			December 31, 2004
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 projected net payments for life insurance and health care benefits, which reflect expected future service, as appropriate, are expected to be paid (expressed in thousands):

Postretirement Life Insurance and Health Care Benefits
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

Texas Gas maintains various defined contribution plans covering substantially all employees. Costs related to these plans were $2.7 million in 2005, $2.6 million in 2004, $1.6 million post-Acquisition 2003 and $1.0 million in pre-Acquisition 2003.

Note 6: Income Tax

Following is a summary of the provision for income taxes and charge-in-lieu of income taxes for the years ended December 31, 2005, 2004 and 2003 (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
Current expense (benefit):
Federal	$	13,384	$	114	$	(1,520	)	$	14,234
State		2,878		24		(99	)		2,659
		16,262		138		(1,619	)		16,893
Deferred provision:
Federal		15,133		31,314		17,414			4,522
State		3,255		6,639		2,263			972
Elimination of cumulative deferred taxes		30,649		-		-			-
		49,037		37,953		19,677			5,494
Net provision for income taxes		-		-		-		$	22,387
Net charge-in-lieu of income tax	$	65,299	$	38,091	$	18,058

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):

	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	$	30,557	$	33,504	$	15,705	$	19,901
Increases (decreases) in taxes resulting from:
State income taxes		3,986		4,331		2,042		2,587
Other, net		107		256		311		(101	)
Elimination of deferred taxes due to formation of   MLP		30,649		-		-		-
Net provision for income taxes		-		-		-	$	22,387
Charge-in-lieu of Income taxes	$	65,299	$	38,091	$	18,058

Results of operations for the year ended December 31, 2005, reflect a change in the tax status associated with Texas Gas as of November 2005. Accordingly, Texas Gas has recorded a charge-in-lieu of income taxes for the period January 1, 2005 through November 15, 2005, and has recorded no income taxes thereafter. Pursuant to the change in tax status, Texas Gas also eliminated its balance of accumulated deferred income taxes at the date of the offering. See Note 2 to the 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):

	2004
Deferred tax assets:
Property, plant and equipment	$	99,258
Accrued payroll, pension and other benefits		14,018
Net operating loss carryover		2,978
Deferred income		1,086
Other assets		3,371
Total deferred tax assets	$	120,711

Deferred tax liabilities:
Storage gas	$	65,568
Unamortized debt expense		3,133
Total deferred tax liabilities		68,701
Net deferred tax assets	$	52,010

Since the date of the Acquisition, Texas Gas has recorded a charge-in-lieu of income taxes consistent with its treatment as a division of a corporate entity and the operation of a tax-sharing agreement. In connection with the contribution of Boardwalk Pipelines Holding Company’s ownership interests in Boardwalk Pipelines to Boardwalk Pipeline Partners, the tax-sharing agreement ceased to exist coincident with the date of Boardwalk Pipeline Partners’ initial public offering on November 15, 2005. Accordingly, Texas Gas experienced a change in tax status as it was no longer a division of a tax-paying entity. Tax attributes of income and expense items will subsequently be allocated to the individual partners of Boardwalk Pipeline Partners who are subject to United States federal income taxation in accordance with the provisions of the partnership agreement.

Note 7:  Financial Instruments

The following methods and assumptions were used in estimating Texas Gas’ fair-value disclosures for financial instruments:

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

Cash and Cash Equivalents: For cash and cash equivalents, the carrying amount is a reasonable estimate of fair value due to the short maturity of those instruments.

Advances to Affiliates: Advances to affiliates, which are represented by demand notes, earn a variable rate of interest, which is adjusted regularly to reflect current market conditions. Therefore, the carrying amount is a reasonable estimate of fair value. The interest rate on intercompany demand notes is LIBOR plus one percent and is adjusted each three-month period.

Long-Term Debt: All of Texas Gas’ long-term debt is publicly traded; therefore, estimated fair value is based on quoted market prices at December 31, 2005 and 2004.

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

	Carrying Amount				Fair Value
Financial Assets	2005		2004		2005		2004
Cash and cash equivalents	$	84	$	12,201	$	84	$	12,201
Advances to affiliates (current and non-current)		253,777		166,668		253,777		166,668
Financial Liabilities
Long-term debt	$	347,976	$	347,802	$	355,576	$	355,968

Note 8:  Major Customers and Transactions with Affiliates

Major Customers

Operating revenues received from the three major customers of Texas Gas (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	19.74%	$ 56,742	21.70%	$ 28,110	19.68%	$ 22,157	19.53%
Atmos Energy	$ 28,434	10.97%	$ 28,359	10.84%	$ 16,208	11.35%	$ 13,318	11.74%
Louisville Gas & Electric	$ 26,443	10.20%	<10%	<10%	<10%	<10%	<10%	<10%

Related Parties

Texas Gas makes advances to Boardwalk Pipelines. At December 31, 2005, the advances due Texas Gas by Boardwalk Pipelines totaled $253.8 million. The advances are represented by demand notes. The interest rate on intercompany demand notes is compounded monthly based on LIBOR plus one percent and is adjusted quarterly.

In addition to these advances to affiliates, Loews provides certain management and other services to Texas Gas under a services agreement. For the years ended December 31, 2005 and 2004, Texas Gas was charged $5.4 million and $6.9 million, respectively, and for the period after the Acquisition in 2003, it was charged $3.3 million by Loews for management services. 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 were $5.4 million prior to the Acquisition in 2003.

Amounts applicable to transportation for affiliates included in Texas Gas’ gas transportation revenues are as follows (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
Gulf South	$ 1,421	-	-	-
Williams Energy Services Co.	-	-	-	$      292
Transcontinental Gas Pipe Line Corp.	-	-	-	1,670
Total transportation for affiliates	$ 1,421	-	-	$   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:  Selected Quarterly Financial Data (Unaudited)

Texas Gas’ operating income may vary by quarter. Based on the current rate structure, the Company experienced 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 Texas Gas (expressed in thousands):

	2005 For the Quarter Ended:
	December 31		September 30		June 30		March 31
Operating revenues	$	81,295	$	49,064	$	50,965	$	77,915
Operating expenses		25,015		39,494		35,756		34,067
Operating income		56,280		9,570		15,209		43,848
Interest expense, net		1,790		2,228		2,710		3,282
Other income		265		443		406		330
Income before income taxes		54,755		7,785		12,905		40,896
Provision for income taxes		40,851		3,090		5,127		16,231
Net income	$	13,904	$	4,695	$	7,778	$	24,665

	2004 For the Quarter Ended:
	December 31		September 30		June 30		March 31
Operating revenues	$	76,979	$	46,920	$	51,925	$	85,673
Operating expenses		40,552		38,068		36,301		35,145
Operating income		36,427		8,852		15,624		50,528
Interest expense, net		3,658		3,999		4,221		4,610
Other income		268		197		104		214
Income before income taxes		33,037		5,050		11,507		46,132
Provision for income taxes		13,100		2,087		4,664		18,240
Net income	$	19,937	$	2,963	$	6,843	$	27,892

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

None

Item 9A.  Controls and Procedures

Texas Gas maintains a system of disclosure controls and procedures which are designed to ensure that information required to be disclosed in reports that are filed or submitted under the federal securities laws, including this report, are recorded, processed, summarized and reported on a timely basis. These disclosure controls and procedures are designed to ensure that information required to be disclosed by Texas Gas under the federal securities laws is accumulated and communicated to its management on a timely basis to allow decisions regarding required disclosure.

Texas Gas' principal executive officer and principal financial officer have conducted an evaluation of the disclosure controls and procedures as of the end of the period covered by this report. Based on this evaluation, the principal executive officer and principal financial officer have each concluded that the disclosure controls and procedures were effective for their intended purpose.

There were no changes in Texas Gas’ 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 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)	$ 436	$ 554
Audit Related Fees (2)	294	-
Tax Fees (3)	5	18
Total	$ 735	$ 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 software services.

Audit Committee’s Pre-Approval Policies and Procedures

In order to assure the continued independence of our independent registered public accounting firm (independent auditor), currently Deloitte & Touche LLP, the Audit Committee of the Board of Directors of Boardwalk GP, LLC (Audit Committee), the general partner of Boardwalk GP, LP, which is the general partner of Boardwalk Pipeline Partners, which serves as our audit committee, has adopted a policy requiring pre-approval of all audit and non-audit services performed for Texas Gas 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 LLP, subject to maximum dollar limitations. All other engagements for services to be performed by Deloitte & Touche LLP must be separately 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, following the initial public offering of Boardwalk Pipeline Partners in November 2005 and the Audit Committee’s adoption of this policy, the Audit Committee has pre-approved all engagements for services of Deloitte & Touche LLP, including the terms and fee thereof, and concluded that such engagements were compatible with the continued independence of Deloitte & Touche LLP in serving as our independent auditor. Prior to the formation of the Audit Committee, the Audit Committee of Loews pre-approved all 2005 engagements for services of Deloitte & Touche LLP, including the terms and fees thereof, and concluded that such engagements were compatible with the continued independence of Deloitte & Touche LLP in serving as our independent auditor.

PART IV

Item 15.  Exhibits, Financial Statement Schedules.

(a) 1. Financial Statements

Included in Item 8, Part II of this Report

Report of Independent Registered Public Accounting Firm

Statements of Financial Position at December 31, 2005 and 2004

Statements of Operations 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

Statements of Stockholder’s and Member’s Equity 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

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 Financial Statements

Schedules are omitted because of the absence of conditions under which they are required or because the required information is given in the financial statements or notes thereto.

(a) 3. Exhibits

The documents listed below are being filed on behalf of Texas Gas Transmission, LLC, and are incorporated herein by reference from the documents indicated and made a part hereof. Those exhibits below incorporated by reference herein are indicated as such by the information supplied in the parenthetical thereafter. If no parenthetical appears after an exhibit, copies of the instrument have been included herewith.

Exhibit Designation	Registrant	Nature of Exhibit
3.1	Texas Gas Transmission LLC	Certificate of Formation of the Registrant, incorporated herein by reference to Exhibit 3.1 to the Registrant’s Current Report on Form 8-K filed on May 23, 2003.
3.2	Texas Gas Transmission LLC	Operating agreement of the Registrant, incorporated by reference to Exhibit 3.2 to the Registrant’s Current Report on Form 8-K filed on May 23, 2003.
4.1	Texas Gas Transmission, LLC	Indenture dated July 15, 1997, between Texas Gas and The Bank of New York relating to 7.250% Debentures, due 2027 (Incorporated by reference to Exhibit 4.1 to Registration Statement No. 333-27359, dated May 16, 1997).
4.2	Texas Gas Transmission, LLC	Indenture dated April 11, 1994, securing 8.625% Notes due April 1, 2004 (Incorporated by reference to Form 8-K dated April 13, 1994, File No. 1-4169).
4.3	Texas Gas Transmission, LLC	Indenture dated as of May 28, 2003, between Texas Gas Transmission, LLC, and The Bank of New York, as Trustee, incorporated herein by reference to Exhibit 3.5 to Texas Gas’ Registration Statement on Form S-4 filed with the SEC on September 11, 2003

*31.1	Texas Gas Transmission, LLC	Certification of H. Dean Jones II, President, pursuant to Rule 13a-14(a) and Rule 15d-14(a)
*31.2	Texas Gas Transmission, LLC	Certification of Jamie L. Buskill, Vice President and Chief Financial Officer, pursuant to Rule 13a-14(a) and Rule 15d-14(a)
*32.1	Texas Gas Transmission, LLC	Certification of H. Dean Jones II, President, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
*32.2	Texas Gas Transmission, LLC	Certification of Jamie L. Buskill, Vice President and Chief Financial Officer, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

* Filed herewith

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.

Texas Gas Transmission, LLC

Registrant

Dated: March 16, 2006	/s/ Jamie L. Buskill
	Jamie L. Buskill	Vice President and 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	Director, President and Chief Executive Officer (Principal Executive Officer)
Dated: March 16, 2006	/s/ Jamie L. Buskill
	Jamie L. Buskill	Director, Vice President and Chief Financial Officer (Principal Financial and Accounting Officer)
Dated: March 16, 2006	/s/ Andrew H. Tisch
	Andrew H. Tisch	Director