The following discussion and analysis of financial condition and results of operations should be read in conjunction with our accompanying interim condensed consolidated financial statements and related notes, included elsewhere in this report and prepared in accordance with accounting principles generally accepted in the United States of America and our consolidated financial statements, related notes, Management's Discussion and Analysis of Financial Condition and Results of Operations and Risk Factors included in our Annual Report on Form 10-K for the year ended December 31, 2008.

Overview

Through our subsidiaries, Gulf Crossing Pipeline Company, LLC (Gulf Crossing), Gulf South Pipeline Company, LP (Gulf South) and Texas Gas Transmission, LLC (Texas Gas) (collectively, the operating subsidiaries), we own and operate three interstate natural gas pipeline systems including integrated storage facilities. Our pipeline systems originate in the Gulf Coast region and extend northeasterly to the Midwestern states of Tennessee, Kentucky, Illinois, Indiana and Ohio. As of March 31, 2009, Boardwalk Pipelines Holding Corp. (BPHC) a wholly-owned subsidiary of Loews Corporation (Loews) owns 107.5 million of our common units, all 22.9 million of our class B units and, through Boardwalk GP, LP (Boardwalk GP), an indirect wholly-owned subsidiary of BPHC, holds the 2% general partner interest and all of the incentive distribution rights (IDRs). As of March 31, 2009, the common units, class B units and general partner interest owned by BPHC represent approximately 74% of our equity interests, excluding the IDRs. Our common units are traded under the symbol "BWP" on the New York Stock Exchange.

Our transportation services consist of firm transportation, whereby the customer pays a capacity reservation charge to reserve pipeline capacity at certain receipt and delivery points along our pipeline systems, plus a commodity and fuel charge on the volume of natural gas actually transported, and interruptible transportation, whereby the customer pays to transport gas only when capacity is available and used. We offer firm storage services in which the customer reserves and pays for a specific amount of storage capacity, including injection and withdrawal rights, and interruptible storage and parking and lending (PAL) services where the customer receives and pays for capacity only when it is available and used. Some PAL agreements are paid for at inception of the service and revenues for these agreements are recognized as service is provided over the term of the agreement. Our operating costs and expenses typically do not vary significantly based upon the amount of gas transported, with the exception of fuel consumed at our compressor stations, which is included in Fuel and gas transportation expenses on our Condensed Consolidated Statements of Income.

We are not in the business of buying and selling natural gas other than for system management purposes, but changes in the price of natural gas can affect the overall supply and demand of natural gas, which in turn can affect our results of operations. Our business is affected by trends involving natural gas price levels and natural gas price spreads, including spreads between physical locations on our pipeline system, which affect our transportation revenues, and spreads in natural gas prices across time (for example summer to winter), which primarily affect our storage and PAL revenues.

Expansion Projects

During the first quarter 2009, we placed in service the remaining pipeline assets and the initial compression assets associated with our major pipeline expansion projects, all of which are now transporting natural gas. Additional compression facilities will be constructed in 2010 on the Gulf Crossing Pipeline and the Fayetteville and Greenville Laterals to increase the peak-day delivery capacities of those projects.

We are seeking authority from the Pipelines and Hazardous Material Safety Administration (PHMSA) to operate our new expansion pipelines under special permits that would allow them to be operated at higher operating pressures, thereby increasing the peak-day transmission capacity. During this permitting process, we have discovered anomalies in pipe segments on each of our expansion pipelines. We have tested a significant portion of our expansion pipeline joints and have identified anomalies (slight expansion of the pipe) in less than 1% of the joints. Testing for anomalies is continuing on the remaining portions of the expansion pipelines. In response to these discoveries, and in consultation with PHMSA, we reduced operating pressures on all of our expansion pipelines to levels below normal operating pressures and this reduction will continue until we obtain permission from PHMSA to increase operating pressures. This reduction has limited our ability to transport the maximum contracted amounts on our expansion pipelines which lowers our transportation revenues.

The following provides information on the volumes currently being transported by each of our expansion pipelines. The anticipated peak-day delivery capacity stated below for each expansion pipeline assumes that pipe anomalies have been remediated and that we have received authority from PHMSA to operate the pipeline at higher operating pressures under a special permit:

East Texas Pipeline - We are currently flowing approximately 1.1 billion cubic feet (Bcf) per day of natural gas, out of the anticipated peak-day delivery capacity of 1.4 Bcf per day.

Southeast Expansion - We are currently flowing approximately 0.5 Bcf per day of natural gas, out of the anticipated peak-day delivery capacity of 1.9 Bcf per day.

Gulf Crossing Project - We are currently flowing approximately 0.7 Bcf per day of natural gas, out of the anticipated peak-day delivery capacity of 1.4 Bcf per day. We expect to increase the peak-day delivery capacity to 1.7 Bcf per day by adding compression, which is expected to be in service in 2010, subject to Federal Energy Regulatory Commission (FERC) approval.

Fayetteville and Greenville Laterals - We are currently flowing approximately
0.7 Bcf per day of natural gas on the Fayetteville Lateral and 0.4 Bcf per day on the Greenville Lateral, in each case out of the anticipated peak-day delivery capacity of 0.8 Bcf per day. In early 2010, we expect to increase the peak-day delivery capacities to 1.3 Bcf per day on the Fayetteville Lateral and 1.0 Bcf per day on the Greenville Lateral with the addition of compression facilities. During the second quarter 2009, we expect to replace a section of this line comprised of 18-inch pipe running under the Little Red River in Arkansas with 36-inch pipe.

As a result of these reduced transportation volumes, our revenues from the expansion pipelines were lower than expected in the first quarter 2009, as discussed further under Results of Operations. In addition, we expect to temporarily shut down each expansion pipeline for periods of time during the remainder of 2009 to remove and replace affected pipe joints as necessary. As a result, we expect throughput on these expansion pipelines to be below the full capacity which our shippers have contracted for, causing reduced transportation revenues in future periods. Until we have remediated the pipe anomalies, performed additional testing required by PHMSA and obtained PHMSA's consent to increase operating pressures to normal levels, as well as the higher levels under the special permits, we will not be able to operate at our peak-day transmission capacity, which could have a material adverse affect on our business, financial condition, results of operations and cash flows, including our ability to make distributions to unitholders. PHMSA retains discretion as to whether to grant, or to maintain in force, authority to operate a pipeline at higher operating pressures. Item 1A, Risk Factors - A portion of the expected maximum daily capacity of our pipeline expansion projects is contingent on our receiving and maintaining authority from PHMSA to operate at higher operating pressures in our Annual Report on Form 10-K for the year ended December 31, 2008, contains more information regarding risks associated with this matter.

In addition to the projects previously described, we recently signed shipper agreements for approximately 0.4 Bcf per day of capacity that will support a further expansion of our Gulf South system to transport natural gas from the Haynesville production area in Louisiana. This expansion, which we anticipate will be in service in late 2010, will be accomplished by adding compression at an expected cost of up to approximately $200.0 million, subject to FERC approval.

We are also engaged in Phase III of our Western Kentucky Storage Expansion project. We have placed in service approximately 5.4 Bcf of new working gas capacity. In the first quarter 2009 we sold the remaining capacity available, and we expect to place into service another 3.0 Bcf of working gas capacity in November 2009. We expect this project to cost approximately $87.7 million, of which we have spent approximately $51.1 million as of March 31, 2009.

Results of Operations for the Three Months Ended March 31, 2009 and 2008

Our net income for the three months ended March 31, 2009, decreased $36.1 million, or 41%, to $52.0 million compared to $88.1 million for the three months ended March 31, 2008. Operating expenses for the first quarter 2009 were higher than the comparable period in 2008, mainly as a result of increases in depreciation and property taxes associated with our expansion projects. The increase in expenses more than offset the increase in revenues from our expansion projects, which were approximately $12.0 million lower than expected as a result of operating our expansion pipelines at reduced pressures as previously discussed under Expansion Projects.

Operating revenues for the three months ended March 31, 2009, increased $26.1 million, or 13%, to $223.4 million, compared to $197.3 million for the three months ended March 31, 2008. Gas transportation revenues, excluding fuel, increased $28.2 million, primarily from our expansion projects. Gas storage revenues increased $2.9 million related to an increase in storage capacity associated with our Western Kentucky Storage Expansion and PAL revenues increased $2.3 million due to favorable winter-to-summer natural gas price spreads. These increases were partially offset by lower fuel revenues of $7.3 million due to unfavorable natural gas prices.

Operating costs and expenses for the three months ended March 31, 2009, increased $49.0 million, or 51%, to $144.8 million, compared to $95.8 million for the three months ended March 31, 2008. The primary factors for the increases were higher depreciation and other taxes, comprised primarily of property taxes, of $29.1 million associated with an increase in our asset base. Operations and maintenance expense increased $5.9 million due to major maintenance projects and expansion project operations. Administrative and general expense increased $3.7 million due to increases in outside services, unit-based compensation driven by an increase in the price of our common units and employee benefits from reductions in trust assets for our pension and post-retirement benefit plans. The 2008 period was favorably impacted by an $11.2 million contract settlement gain.

Total other deductions increased by $13.2 million, or 100%, to $26.3 million for the three months ended March 31, 2009, compared to $13.1 million for the 2008 period. The primary factor for the increase was higher interest expense of $7.6 million resulting from increased debt levels in 2009 and lower capitalized interest associated with our expansion projects. The 2008 period included $3.1 million of gains from the mark-to-market effect of derivatives associated with the purchase of line pack for our expansion projects.

Liquidity and Capital Resources

We are a partnership holding company and derive all of our operating cash flow from our operating subsidiaries. Our principal sources of liquidity include cash generated from operating activities, our revolving credit facility to the extent there is undrawn availability thereunder, debt issuances and sales of limited partner units. Our operating subsidiaries use cash from operations to fund their operating activities and maintenance capital requirements, service their indebtedness and make advances or distributions to Boardwalk Pipelines. Boardwalk Pipelines uses cash provided from the operating subsidiaries and, as needed, borrowings under our revolving credit facility to service its outstanding indebtedness and, when available, make distributions or advances to us to fund our distributions to unitholders. We have no material guarantees of debt or other similar commitments to unaffiliated parties.

Maintenance Capital Expenditures

Maintenance capital expenditures for the three months ended March 31, 2009 and 2008 were $9.2 million and $5.2 million. We expect to fund the remaining 2009 maintenance capital expenditures of approximately $58.6 million from our operating cash flows.

Expansion Capital Expenditures

We will incur costs to remediate the pipeline anomalies previously described, including costs associated with our East Texas Pipeline. Additionally, we are still testing portions of the expansion pipelines for anomalies, thereby making the full cost of remediating the pipelines unknown. However, we anticipate that the cost to remediate the anomalies will not require us to increase our previously announced estimated total cost to complete our expansion projects due to lower costs experienced during the initial phase of the construction. The following table presents the estimated total costs and the amounts invested through March 31, 2009, for our remaining pipeline expansion projects (in millions):

                                            Estimated
                                            Total Cost       Cash Invested through
                                               (1)              March 31, 2009
   Southeast Expansion                    $         775     $                 735.5
   Gulf Crossing Project                          1,800                     1,518.6
   Fayetteville and Greenville Laterals           1,290                       803.0
     Total                                $       3,865     $               3,057.1

(1) Our cost estimates are based on internally developed financial models and timelines. Factors in the estimates include, but are not limited to, those related to pipeline costs based on mileage, size and type of pipe, materials and construction and engineering costs.

We expect to incur capital expenditures of approximately $800.0 million for the remainder of 2009 and in 2010 to complete our pipeline expansion projects. The majority of the expenditures are expected to occur in 2009, with the balance to be incurred in early 2010. We also expect to spend up to $200.0 million for our Haynesville project which expenditures are expected to occur in 2010. Our cost and timing estimates for these projects are subject to a variety of risks and uncertainties as discussed in Item 1A, Risk Factors, of our Annual Report on Form 10-K for the year ended December 31, 2008.

We have financed our expansion capital costs through the issuance of equity and debt, borrowings under our revolving credit facility and available operating cash flow in excess of our operating needs. We anticipate we will need to finance approximately $700.0 million to complete our pipeline expansion projects, including the Haynesville project, which we expect to finance through the issuance of both debt and equity. Our largest unitholder, Loews Corporation, has advised us that it is willing to provide up to an additional $500.0 million of capital to fund these projects to the extent the public markets remain unavailable on acceptable terms. Any additional financing provided by Loews would be subject to review and approval, as to fairness, by our independent Conflicts Committee. Item 1A, Risk Factors, of our Annual Report on Form 10-K for the year ended December 31, 2008, contains more information regarding risks associated with our expansion projects and the related financing.

Revolving Credit Facility

We maintain a revolving credit facility which has aggregate lending commitments of $1.0 billion, under which Boardwalk Pipelines, Gulf South and Texas Gas each may borrow funds, up to applicable sub-limits. A financial institution which has a $50.0 million commitment under the revolving credit facility filed for bankruptcy protection in 2008 and has not funded its portion of our borrowing requests since that time. Interest on amounts drawn under the credit facility is payable at a floating rate equal to an applicable spread per annum over the London Interbank Offered Rate or a base rate defined as the greater of the prime rate or the Federal funds rate plus 50 basis points. The revolving credit facility has a maturity date of June 29, 2012.

As of March 31, 2009, we have fully borrowed against all commitments available under our revolving credit facility, resulting in loans outstanding of $953.5 million with a weighted-average interest rate of 0.79%. We were in compliance with all covenant requirements under our credit facility at March 31, 2009.

Our revolving credit facility contains customary negative covenants, including, among others, limitations on the payment of cash dividends and other restricted payments, the incurrence of additional debt, sale-leaseback transactions and transactions with our affiliates. The facility also contains a financial covenant that requires us and our subsidiaries to maintain a ratio of total consolidated debt to consolidated earnings before income taxes, depreciation and amortization (as defined in the credit agreement), measured for the preceding twelve months, of not more than five to one. Although we do not believe that these covenants have had, or will have, a material impact on our business and financing activities or our ability to obtain the financing to maintain operations and continue our capital investments, they could restrict us in some circumstances as stated in Item 1A, Risk Factors, of our Annual Report on Form 10-K for the year ended December 31, 2008. In particular, maintaining compliance with the financial covenant may limit our ability to incur additional indebtedness to finance our growth projects, which could limit our growth opportunities or require the issuance of more equity securities by us than anticipated.

Distributions

For the three months ended March 31, 2009 and 2008, we paid distributions of $85.8 million and $59.6 million. Note 6 in Part 1, Item 1 of this report contains further discussion regarding our distributions.

Changes in cash flow from operating activities

Net cash provided by operating activities decreased $45.9 million to $28.4 million for the three months ended March 31, 2009, compared to $74.3 million for the comparable 2008 period, primarily due to a $22.2 million increase in inventories and trade receivables, and $11.0 million from the change in net income, excluding non-cash items such as depreciation and amortization and the recognition of income previously deferred.

Changes in cash flow from investing activities

Net cash used in investing activities decreased $415.9 million to $126.9 million for the three months ended March 31, 2009, compared to $542.8 million for the comparable 2008 period, from a $240.6 million decrease in capital expenditures related to our expansion projects, and the sale of $175.0 million of short-term investments.

Changes in cash flow from financing activities

Net cash provided by financing activities decreased $112.2 million to $75.4 million for the three months ended March 31, 2009, compared to $187.6 million for the comparable 2008 period. These decreases resulted from an $85.7 million decrease in proceeds from the issuance of debt and net borrowings under our revolving credit facility and a $26.2 million increase in distributions to our partners.

Contractual Obligations

The table below is updated for significant changes in contractual cash payment
obligations as of March 31, 2009, by period (in millions):

                                                Less than 1                                    More than 5
                                  Total            Year          1-3 Years      4-5 Years         Years
Principal payments on long-term
debt (1)                          $ 3,063.5     $         -     $         -     $  1,428.5     $   1,635.0
Interest on long-term debt (2)        887.9            83.5           234.9          214.4           355.1
Capital commitments (3)               162.9           161.6             1.3              -               -
Total                             $ 4,114.3     $     245.1     $     236.2     $  1,642.9     $   1,990.1

(1) Includes our senior unsecured notes, having maturity dates from 2012 to 2027 and $953.5 million of loans outstanding under our revolving credit facility, having a maturity date of June 29, 2012.

(2) Interest obligations represent interest due on our senior unsecured notes at fixed rates. Future interest obligations under our revolving credit facility are uncertain, due to the variable interest rate and fluctuating balances. Based on a 0.79% weighted-average interest rate on amounts outstanding under our revolving credit facility as of March 31, 2009, $5.6 million, $15.1 million and $3.7 million would be due under the credit facility in less than one year, 1-3 years, and 4-5 years.

(3) Capital commitments represent binding commitments under purchase orders for materials ordered but not received and firm commitments under binding construction service agreements existing at March 31, 2009. The amounts shown do not reflect commitments we have made after March 31, 2009.

Pursuant to the settlement of the Texas Gas rate case in 2006, we are required to annually fund an amount to the Texas Gas pension plan equal to the amount of actuarially determined net periodic pension cost, including a minimum of $3.0 million. In 2009, we expect to fund approximately $5.0 million to the Texas Gas pension plan.

Off-Balance Sheet Arrangements

At March 31, 2009, we had no guarantees of off-balance sheet debt to third parties, no debt obligations that contain provisions requiring accelerated payment of the related obligations in the event of specified levels of declines in credit ratings, and no other off-balance sheet arrangements.

Critical Accounting Policies

Certain amounts included in or affecting our condensed consolidated financial statements and related disclosures must be estimated, requiring us to make certain assumptions with respect to values or conditions that cannot be known with certainty at the time the financial statements are prepared. These estimates and assumptions affect the amounts we report for assets and liabilities and our disclosure of contingent assets and liabilities in our financial statements. We evaluate these estimates on an ongoing basis, utilizing historical experience, consultation with third parties and other methods we consider reasonable. Nevertheless, actual results may differ significantly from our estimates. Any effects on our business, financial position or results of operations resulting from revisions to these estimates are recorded in the periods in which the facts that give rise to the revisions become known.

During the first quarter 2009, there were no significant changes to our critical accounting policies, judgments or estimates disclosed in our Annual Report on Form 10-K for the year ended December 31, 2008.

Forward-Looking Statements

Investors are cautioned that certain statements contained in this Report, as well as some statements in periodic press releases and some oral statements made by our officials and our subsidiaries during presentations about us, are "forward-looking." Forward-looking statements include, without limitation, any statement that may project, indicate or imply future results, events, performance or achievements, and may contain the words "expect," "intend," "plan," "anticipate," "estimate," "believe," "will likely result," and similar expressions. In addition, any statement made by our management concerning future financial performance (including future revenues, earnings or growth rates), ongoing business strategies or prospects, and possible actions by our partnership or its subsidiaries, are also forward-looking statements.

Forward-looking statements are based on current expectations and projections about future events and are inherently subject to a variety of risks and uncertainties, many of which are beyond our control that could cause actual results to differ materially from those anticipated or projected. These risks and uncertainties include, among others:

· A portion of the transportation capacity on each of our expansion project pipelines that we expect will ultimately be available is contingent upon our receipt of authority to operate each of these pipelines at higher operating pressures under a special permit issued by PHMSA. To the extent that PHMSA does not grant us authority to operate any of our expansion pipelines under a special permit or withdraws previously granted authority to operate under a special permit, transportation capacity made available to the market and transportation revenues received in the future would be reduced.

· We may not complete projects, including growth or expansion projects, that we have commenced or will commence, or we may complete projects on materially different terms, cost or timing than anticipated and we may not be able to achieve the intended economic or operational benefits of any such projects, if completed.

· Global financial markets and economic conditions have been, and continue to be, experiencing extraordinary disruption and volatility following adverse changes in global capital markets. The cost of raising money in the debt and equity capital markets and commercial credit markets has increased substantially while the availability of funds from those markets has diminished significantly.

· Our FERC gas tariffs only allow us to require limited credit support in the event that our transportation customers are unable to pay for our services. If any of our significant customers have credit or financial problems which result in a delay or failure to pay for services provided by us, or contracted for with us, or repay the gas they owe us, it could adversely affect our business, financial condition and results of operations.

· The gas transmission and storage operations of our subsidiaries are subject to rate-making policies and actions by FERC or customers that could have an adverse impact on the services we offer and the rates we charge and our ability to recover the full cost of operating our pipelines, including earning a reasonable return.

· We are subject to laws and regulations relating to the environment and . . .