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, related notes and Risk Factors, 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 September 30, 2009, Boardwalk Pipelines Holding Corp. (BPHC), a wholly-owned subsidiary of Loews Corporation (Loews) owned 114.2 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 September 30, 2009, the common units, class B units and general partner interest owned by BPHC represent approximately 72% 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 expense 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. Each of these projects is now transporting natural gas at normal operating pressures. 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.

As previously reported, we are seeking authority from the Pipeline and Hazardous Materials Safety Administration (PHMSA) to operate our East Texas Pipeline, Southeast Expansion, Gulf Crossing Project and our Fayetteville Lateral under special permits that would allow each pipeline to operate at higher than normal operating pressures (up to 0.80 of the pipe's Specified Minimum Yield Strength, or SMYS, as opposed to normal operating pressure of up to 0.72 SMYS), thereby increasing each pipeline's maximum peak-day transmission capacity. PHMSA retains discretion as to whether to grant, or to maintain in force, authority to operate a pipeline at higher than normal operating pressures. For those expansion pipelines for which we are seeking special permits, we have entered into firm transportation contracts with shippers which would utilize the maximum capacity available from operating at higher than normal operating pressures. Our Greenville Lateral was constructed to operate at normal operating pressures and we are not seeking the authority to operate that pipeline at higher than normal operating pressures under a special permit.

While completing the requirements to operate at higher than normal operating pressures, we discovered anomalies in certain pipeline segments on each of our expansion projects. Accordingly, we reduced the operating pressures on each pipeline below normal operating pressures as we performed additional testing procedures, remediated the anomalies and sought authority from PHMSA to increase operating pressures, first to normal operating pressures and for those expansion pipelines for which we are seeking special permits, subsequently to higher than normal operating pressures under the special permits. We have also shut down pipeline segments for periods of time to remediate anomalies. We entered into an agreement with PHMSA during the second quarter 2009, which modified each of our special permits and defined the testing protocol and remediation efforts that we need to complete in order to return to normal operating pressures, and for those expansion pipelines for which we are seeking special permits, to operate at higher than normal operating pressures. The testing protocol and remediation efforts include replacement of certain pipe joints, performing investigative digs to physically inspect the pipe sections and conducting metallurgical testing and analysis on a variety of pipe samples.

The pressure reductions and shutdowns that were undertaken to remediate anomalies on our expansion pipeline projects have reduced throughput and adversely affected our transportation revenues, net income and cash flows. At the same time, our operating costs and expenses, particularly depreciation and property taxes, have increased due to costs associated with the expansion project pipelines being placed into service. See Results of Operations for more information on the impacts of the pipeline pressure reductions and shutdowns on our income.

With respect to each of our expansion pipelines, until we have remediated the pipe anomalies, performed additional testing required by PHMSA and obtained PHMSA's consent to increase operating pressures to higher than normal levels under special permits for those expansion pipelines for which we are seeking special permits, we will not be able to operate that pipeline at its anticipated 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. See 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 than normal operating pressures.

Set forth below is information with respect to the status of each of our four pipeline expansion projects as of October 28, 2009. Expected transportation revenues are based on the projected reservation charges under firm contracts.

East Texas Pipeline. Portions of this pipeline were shut down for periods of time in May and July 2009, during which time we completed the requisite anomaly remediation. Effective July 27, 2009, we received authority from PHMSA to operate the East Texas pipeline at normal operating pressures. At this level of capacity, we are able to meet our current contractual obligations of 1.4 billion cubic feet (Bcf) per day. In October 2009, we requested that PHMSA grant us the authority to operate at higher than normal operating pressures under a special permit.

Southeast Expansion. Portions of this pipeline were shut down for periods of time in May and July 2009, during which time we completed the requisite anomaly remediation. Effective July 27, 2009, we received authority from PHMSA to operate the Southeast Expansion pipeline at normal operating pressures. At this level of capacity, we are able to meet our current contractual obligations of
1.7 Bcf per day. In October 2009, we requested that PHMSA grant us the authority to operate at higher than normal operating pressures under a special permit.

Gulf Crossing Project. The Gulf Crossing Project was shut down the entire month of June, during which time we completed the requisite anomaly remediation. Effective July 1, 2009, we received authority from PHMSA to operate the Gulf Crossing Project at normal operating pressures. At this level of capacity, we are able to meet our current contractual obligations of 1.3 Bcf per day. In October 2009, we requested that PHMSA grant us the authority to operate at higher than normal operating pressures under the special permit. We expect to increase the peak-day transmission capacity of this pipeline to approximately
1.7 Bcf per day, assuming we have received authority to operate under a special permit, by adding compression in 2010, which has been approved by the Federal Energy Regulatory Commission (FERC).

Our expansion pipelines are operating at normal operating pressures and we are meeting our current contractual obligations for those projects. However, if our East Texas Pipeline, Southeast Expansion, Gulf Crossing Project and Fayetteville Lateral are not permitted to operate at higher than normal operating pressures, our transportation revenues would not grow to the extent we had expected, beginning in late 2010, as the volume commitments under our existing firm contracts increase. Absent authority to operate at higher than normal pressures, we could also incur additional costs for system upgrades on those projects to increase capacity to meet contracted volume commitments.

Other

In addition to the projects previously described, we are continuing with efforts to expand our system in the Haynesville production area in Louisiana. This expansion, which we anticipate will be in service in late 2010, consists of adding compression at an expected cost of approximately $185.0 million, subject to FERC approval. Customers have contracted for approximately 0.4 Bcf per day of capacity on this project which will be delivered at normal operating pressures. If we are granted the authority by PHMSA to operate at higher than normal operating pressures on our East Texas Pipeline, then an additional 150.0 million cubic feet per day of capacity would be available for the Haynesville Project.

We have completed Phase III of our Western Kentucky Storage Expansion project, which consisted of developing approximately 8.3 Bcf of new storage working gas capacity. Approximately 5.4 Bcf of capacity was placed into service in 2008 and we placed the remaining capacity into service on October 1, 2009. We expect this project to cost approximately $75.0 million. We have spent approximately $65.3 million as of September 30, 2009.

Our net income for the third quarter 2009 decreased $54.8 million, or 74%, to $18.8 million compared to $73.6 million for the third quarter 2008. Operating expenses for the third 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 $47.0 million lower than expected due to operating our expansion pipelines at reduced operating pressures and portions of the expansion pipelines being shut down for periods of time during the third quarter 2009, as discussed under Expansion Projects. The 2008 period was favorably impacted by gains of $36.2 million related to the sale of gas from our Western Kentucky Storage Expansion project and the disposition of coal reserves.

Operating revenues for the third quarter 2009 increased $13.8 million, or 7%, to $205.4 million, compared to $191.6 million for the third quarter 2008. Gas transportation revenues, excluding fuel, increased $27.7 million, primarily from our expansion projects. PAL revenues increased $6.5 million due to increased parking opportunities and favorable summer-to-summer natural gas price spreads. The increases were partially offset by lower fuel revenues of $21.0 million due to unfavorable natural gas prices.

Operating costs and expenses for the third quarter 2009 increased $48.2 million, or 47%, to $151.0 million, compared to $102.8 million for the third quarter 2008. The primary factors for the increases were higher depreciation and property taxes of $27.8 million associated with a larger asset base from expansion. Administrative and general expenses increased $4.0 million mainly due to increases in employee benefits as a result of reductions in trust assets for our pension and post-retirement benefit plans driven by investment losses, and increases in unit-based compensation from an increase in the price of our common units. Operations and maintenance expenses and losses on disposal of assets were $1.9 million due to pipeline investigation and retirement costs related to the East Texas Pipeline. Fuel and gas transportation expenses decreased $21.2 million primarily as a result of lower natural gas prices. The 2008 period was favorably impacted by a $19.7 million gain on the sale of gas related to the Western Kentucky Storage Expansion project and a $16.5 million gain on the disposition of coal reserves.

Total other deductions increased by $20.8 million, or 140%, to $35.7 million for the third quarter 2009, compared to $14.9 million for the 2008 period. The primary factor for the increase was higher interest expense of $23.3 million resulting from lower capitalized interest associated with placing expansion projects in service and higher debt levels in 2009. The 2008 period included $6.3 million of losses from the mark-to-market effect of derivatives associated with the purchase of line pack for our expansion projects.

Results of Operations for the Nine Months Ended September 30, 2009 and 2008

Our net income for the first nine months of 2009 decreased $135.3 million, or 60%, to $91.1 million compared to $226.4 million from the comparable period in 2008. Although revenues for the nine month period ended September 30, 2009, were higher than the comparable period for 2008, the increase was more than offset by increased operating expenses, mainly as a result of increased depreciation and property taxes due to an increase in the asset base associated with our expansion projects. Transportation revenues from expansion projects, excluding fuel, were approximately $117.0 million lower than expected due to operating our expansion pipelines at reduced operating pressures and portions of the expansion pipelines being shut down for periods of time during 2009. The 2008 period was favorably impacted by gains of $62.1 million related to the sale of gas from the Western Kentucky Storage Expansion project, the disposition of coal reserves and a contract settlement.

Operating revenues for the nine months ended September 30, 2009, increased $51.0 million, or 9%, to $630.2 million, compared to $579.2 million for the nine months ended September 30, 2008. Gas transportation revenues, excluding fuel, increased $87.3 million primarily due to our expansion projects. PAL revenues increased $12.6 million as a result of favorable natural gas price spreads and gas storage revenues increased $4.2 million mainly from an increase in storage capacity associated with our Western Kentucky Storage Expansion project. These increases were partially offset by lower fuel revenues of $53.1 million due to lower natural gas prices, partly offset by higher retained volumes.

Total other deductions increased by $50.8 million, or 115%, to $94.9 million for the nine months ended September 30, 2009, compared to $44.1 million for the 2008 period as a result of lower capitalized interest associated with placing our expansion projects in service and increased debt levels in 2009.

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 nine months ended September 30, 2009 and 2008 were $26.1 million and $23.9 million. We expect to fund the remaining 2009 maintenance capital expenditures of approximately $33.9 million from our operating cash flows.

Expansion Capital Expenditures

We have incurred and will continue to incur costs to remediate the pipeline
anomalies described under Expansion Projects. Including the costs incurred to
remediate the pipe anomalies, we expect the total cost to complete our expansion
projects to be within our previously announced cost estimates. The following
table presents our estimate of total capital expenditures and the amounts
invested through September 30, 2009, for our remaining pipeline expansion
projects, including expenditures for pipe remediation (in millions):

                                                      Estimated Total       Cash Invested
                                                          Capital              through
                                                       Expenditures         September 30,
                                                            (1)                  2009
Southeast Expansion                                  $             755     $          751.6
Gulf Crossing Project                                            1,765              1,619.1
Fayetteville and Greenville Laterals                             1,215                967.3
Haynesville Project                                                185                  5.0
Pipe Remediation (2)                                               130                 35.3
  Total                                              $           4,050     $        3,378.3

(1) Our estimated total capital expenditures 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.

(2) This estimate represents the cost of remediating pipe anomalies on our expansion projects, including our East Texas Pipeline, our Southeast Expansion, our Gulf Crossing Project and our Fayetteville and Greenville Laterals.

We have financed our expansion capital expenditures through the issuance of equity and debt, borrowings under our revolving credit facility and available operating cash flows in excess of our operating needs. During the third quarter 2009, we raised approximately $529.8 million in financing through the issuance of equity and debt and do not anticipate the need to raise further capital in order to complete our expansion projects.

Equity and Debt Financing

In August 2009, we completed a public offering of 8.1 million of our common units at a price of $23.00 per unit. We received net cash proceeds of approximately $183.1 million after deducting underwriting discounts and offering expenses of $7.0 million and including a $3.8 million contribution received from our general partner to maintain its 2% general partner interest. Also in August 2009, we received net proceeds of approximately $346.7 million after deducting initial purchaser discounts and offering expenses of $3.3 million from the sale of $350.0 million of 5.75% senior unsecured notes of Boardwalk Pipelines due September 15, 2019.

The proceeds of these offerings were used to directly and indirectly fund our expansion projects through the reduction of borrowings under our revolving credit facility and, in the case of the notes, our Subordinated Loan Agreement. As of September 30, 2009, we had $100.0 million outstanding under our Subordinated Loan Agreement with no additional borrowing capacity available.

Note 7 in Item 1of this Report contains more information regarding each of these
offerings.

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, provided, however, that we have the option to convert all outstanding revolving loans on such date to term loans having a maturity date of June 29, 2013.

As of September 30, 2009, borrowings outstanding under our credit facility were $478.5 million with a weighted-average interest rate of 0.49%. We and our subsidiaries are in compliance with all covenant requirements under our credit facility. Note 7 in Item 1 of this Report contains further discussion of the revolving credit facility.

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 growth projects, which could limit our growth opportunities or require the issuance of more equity securities by us than anticipated.

For the nine months ended September 30, 2009 and 2008, we paid distributions of $263.9 million and $186.3 million. Note 6 in 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 $10.4 million to $265.7 . . .