Edgar Filing: Boardwalk Pipeline Partners, LP

christina.e.halbig@txgt.com

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

(Mark One)

x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2006

o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from _______________ to _______________

Commission file number: 01-32665

BOARDWALK PIPELINE PARTNERS, LP

(Exact name of registrant as specified in its charter)

DELAWARE

(State or other jurisdiction of incorporation or organization)

20-3265614

(I.R.S. Employer Identification No.)

3800 Frederica Street, Owensboro, Kentucky 42301

(Address of principal executive office)

(270) 926-8686

(Registrant’s telephone number, including area code )

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 ¨

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

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

Large accelerated filer o Accelerated filer ¨ Non-accelerated filer x

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No x

As of October 27, 2006, the registrant had 68,256,122 common units outstanding and 33,093,878 subordinated units outstanding.

TABLE OF CONTENTS

FORM 10-Q

SEPTEMBER 30, 2006

BOARDWALK PIPELINE PARTNERS, LP

PART I - FINANCIAL INFORMATION

Item 1. Financial Statements

Condensed Consolidated Balance Sheets

Condensed Consolidated Statements Of Income

Condensed Consolidated Statements Of Cash Flows

Condensed Consolidated Statements Of Changes In Member’s Equity And Partners’ Capital And Comprehensive Income

Notes To Condensed Consolidated Financial Statements

Item 2. Management’s Discussion And Analysis Of Financial Condition And Results Of Operations

Item 3. Quantitative And Qualitative Disclosures About Market Risk

Item 4. Controls And Procedures

PART II - OTHER INFORMATION

Item 1. Legal Proceedings

Item 1 A. Risk Factors

Item 6. Exhibits

PART I - FINANCIAL INFORMATION

Item 1. Financial Statements

BOARDWALK PIPELINE PARTNERS, LP

CONDENSED CONSOLIDATED BALANCE SHEETS

(Thousands of Dollars)

(Unaudited)

ASSETS	September 30, 2006		December 31, 2005
Current Assets:
Cash and cash equivalents	$	57,560	$	65,792
Receivables, net:
Trade		45,356		59,115
Other		6,655		5,564
Gas receivables:
Transportation and exchange		8,172		29,557
Storage		306		12,576
Inventories		14,148		15,881
Costs recoverable from customers		9,665		3,560
Gas stored underground		15,063		6,500
Prepaid expenses and other current assets		21,288		7,720
Total current assets		178,213		206,265

Property, Plant and Equipment:
Natural gas transmission plant		1,897,774		1,772,483
Other natural gas plant		212,857		213,136
		2,110,631		1,985,619

Less—accumulated depreciation and amortization		169,204		118,213
Property, plant and equipment, net		1,941,427		1,867,406

Other Assets:
Goodwill		163,474		163,474
Gas stored underground		169,523		169,177
Costs recoverable from customers		35,095		43,960
Other		16,165		15,209
Total other assets		384,257		391,820

Total Assets	$	2,503,897	$	2,465,491


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

BOARDWALK PIPELINE PARTNERS, LP

CONDENSED CONSOLIDATED BALANCE SHEETS

(Thousands of Dollars, except number of units)

(Unaudited)

LIABILITIES AND PARTNERS’ CAPITAL	September 30, 2006		December 31, 2005
Current Liabilities:
Payables:
Trade	$	21,084	$	20,433
Other		14,547		3,681
Gas payables:
Transportation and exchange		13,494		14,710
Storage		36,091		27,559
Accrued taxes other		23,118		16,004
Accrued interest		14,045		17,996
Accrued payroll and employee benefits		20,561		29,028
Current note payable		-		42,100
Other current liabilities		44,510		30,776
Total current liabilities		187,450		202,287

Long-Term Debt		1,161,896		1,101,290

Other Liabilities and Deferred Credits:
Postretirement benefits		42,499		32,413
Asset retirement obligations		14,680		14,074
Provision for other asset retirements		39,962		33,212
Other		27,865		93,541
Total other liabilities and deferred credits		125,006		173,240

Commitments and Contingencies (Note 5)		-		-

Partners’ Capital:
Common units - 68,256,122 issued and outstanding		730,211		705,609
Subordinated units - 33,093,878 issued and outstanding		278,500		266,578
General partner		17,406		16,661
Accumulated other comprehensive income (loss)		3,428		(174	)
Total partners’ capital		1,029,545		988,674
Total Liabilities and Partners’ Capital	$	2,503,897	$	2,465,491

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

BOARDWALK PIPELINE PARTNERS, LP

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

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

(Unaudited)

	For the Three Months Ended September 30,		For the Nine Months Ended September 30,
	2006	2005	2006	2005
Operating Revenues:
Gas transportation	$ 108,195	$ 111,181	$ 364,597	$ 347,953
Parking and lending	9,099	3,081	32,030	16,157
Gas storage	8,321	5,314	25,136	15,546
Other	7,430	1,339	14,390	9,904
Total operating revenues	133,045	120,915	436,153	389,560

Operating Costs and Expenses:
Operation and maintenance	39,740	51,635	114,901	119,262
Administrative and general	23,878	22,533	74,111	60,512
Depreciation and amortization	18,888	18,092	56,298	53,152
Taxes other than income taxes*	6,592	6,409	18,607	20,968
Net (gain) loss on disposal of operating assets	(826)	1,228	(3,032)	1,713
Total operating costs and expenses	88,272	99,897	260,885	255,607

Operating Income	44,773	21,018	175,268	133,953

Other (Income) Deductions:
Interest expense	14,977	14,985	45,822	44,722
Interest income	(553)	(353)	(1,796)	(1,098)
Interest income from affiliates, net	(10)	(772)	(16)	(1,729)
Miscellaneous other income, net	(406)	(443)	(1,383)	(1,179)
Total other (income) deductions	14,008	13,417	42,627	40,716

Income before income taxes	30,765	7,601	132,641	93,237

Income taxes and charge-in-lieu of income taxes*	118	3,047	364	37,121
Net Income*	$ 30,647	$ 4,554	$ 132,277	$ 56,116

*Results of operations reflect a change in the tax status associated with Boardwalk Pipeline Partners coincident with its initial public offering and conversion to an MLP on November 15, 2005. Boardwalk Pipeline Partners recorded a charge-in-lieu of income taxes and certain state franchise taxes for the three and nine month periods ended September 30, 2005, and each period thereafter through the date of the offering. A subsidiary of Boardwalk Pipeline Partners directly incurs some income-based state taxes following the date of the offering.

	For the Three Months Ended September 30, 2006	For the Nine Months Ended September 30, 2006
Calculation of limited partners’ interest in 2006 net income:
Net income to partners	$ 30,647	$ 132,277
Less general partner’s interest in net income	613	2,646
Limited partners’ interest in net income	$ 30,034	$ 129,631
Basic and diluted net income per limited partner unit:
Common units (See Note 6)	$ 0.35	$ 1.27
Subordinated units (See Note 6)	$ 0.19	$ 1.27
Cash distribution to common and subordinated unitholders and general partner unit equivalents	$0.38	$0.92
Weighted-average number of limited partner units outstanding:
Common units	68,256,122	68,256,122
Subordinated units	33,093,878	33,093,878

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

BOARDWALK PIPELINE PARTNERS, LP

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Thousands of Dollars)

(Unaudited)

	For the Nine Months Ended September 30,
	2006		2005

OPERATING ACTIVITIES:
Net income	$ 132,277	$ 56,116
Adjustments to reconcile to cash provided from (used in) operations:
Depreciation and amortization	56,298	53,152
Amortization of acquired executory contracts	(3,236)	(7,793)
(Gain) loss on disposal of operating assets	(3,032)	1,713
Provision for deferred income taxes	87	50,550
Changes in operating assets and liabilities:
Receivables	47,291	38,264
Inventories	1,733	(573)
Affiliates	(175)	(671)
Other current assets	(20,560)	(2,897)
Accrued income taxes	69	(13,436)
Payables and accrued liabilities	17,335	9,031
Other, including changes in noncurrent assets and liabilities	(43,227)	(23,774)
Net cash provided by operating activities	184,860	159,682
INVESTING ACTIVITIES:
Capital expenditures, net	(120,209)	(50,440)
Insurance and other recoveries	4,960	-
Advances to affiliates, net	(723)	(27,795)
Net cash used in investing activities	(115,972)	(78,235)
FINANCING ACTIVITIES:
Payment of short-term debt	(42,100)	-
Proceeds from long-term debt	60,000	569,369
Payment of long-term debt	-	(575,000)
Distributions paid	(95,021)	(65,000)
Capital contribution from parent	-	6,684
Net cash used in financing activities	(77,121)	(63,947)
Increase (decrease) in cash and cash equivalents	(8,232)	17,500
Cash and cash equivalents at beginning of period	65,792	16,518
Cash and cash equivalents at end of period	$ 57,560	$ 34,018

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

BOARDWALK PIPELINE PARTNERS, LP

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN MEMBER’S EQUITY AND PARTNERS’ CAPITAL AND COMPREHENSIVE INCOME

(Thousands of Dollars)

(Unaudited)

	Paid-in Capital	Retained Earnings	Accumulated Other Comprehensive Income (Loss)	Comprehensive Income	Common Units	Subordinated Units	General Partner	Total Member’s Equity and Partners’ Capital

Balance January 1, 2005	$ 1,071,651	$ 21,276	-	-	-	-	-	$ 1,092,927
Add (deduct):
Net income	-	56,116	-	$ 56,116	-	-	-	56,116
Capital contribution	6,684	-	-	-	-	-	-	6,684
Distributions paid	-	(65,000)	-	-	-	-	-	(65,000)
Other comprehensive (loss), net of tax	-	-	$ (1,578)	(1,578)	-	-	-	(1,578)
Comprehensive income				$ 54,538
Balance, September 30, 2005	$ 1,078,335	$ 12,392	$ (1,578)		-	-	-	$ 1,089,149

Balance January 1, 2006	-	-	$ (174)	-	$ 705,609	$ 266,578	$ 16,661	$ 988,674
Add (deduct):
Net income	-	-	-	$ 132,277	87,303	42,329	2,645	132,277
Distributions paid	-	-	-	-	(62,714)	(30,407)	(1,900)	(95,021)
Other comprehensive income	-	-	3,602	3,602	-	-	-	3,602
Transaction costs related to sale of common units	-	-	-	-	13	-	-	13
Comprehensive income				$ 135,879
Balance September 30, 2006	-	-	$ 3,428		$ 730,211	$ 278,500	$ 17,406	$ 1,029,545

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

BOARDWALK PIPELINE PARTNERS, LP

Notes to Condensed Consolidated Financial Statements

(Unaudited)

Note 1: Basis of Presentation

Boardwalk Pipeline Partners, LP (the Partnership) is a Delaware limited partnership formed in 2005 to own and operate the business conducted by Boardwalk Pipelines, LP (Boardwalk Pipelines) and its subsidiaries, Texas Gas Transmission, LLC (Texas Gas) and Gulf South Pipeline Company, LP (Gulf South). The Partnership is an 85.5% owned subsidiary of Boardwalk Pipelines Holding Corp. (BPHC) which is wholly owned by Loews Corporation (Loews). The Partnership is engaged through its subsidiaries in the interstate transportation and storage of natural gas and operates in one reportable segment - the operation of interstate natural gas pipeline systems.

The accompanying Condensed Consolidated Financial Statements of the Partnership were prepared in accordance with accounting principles generally accepted in the United States of America (GAAP) and in the opinion of management, reflect all adjustments (consisting of only normal recurring accruals) necessary to present fairly the financial position as of September 30, 2006 and December 31, 2005, the results of operations for the three and nine months ended September 30, 2006 and 2005 and changes in cash flows. Reference is made to the Notes to Consolidated Financial Statements in the 2005 Annual Report on Form 10-K, which should be read in conjunction with these unaudited condensed consolidated financial statements.

Net income for interim periods may not necessarily be indicative of results for the calendar year. All significant intercompany items have been eliminated in consolidation. Certain reclassifications have been made to the 2005 financial statements to conform to the 2006 presentation, primarily related to the presentation of parking and lending revenues and interest expense as separate line items on the Condensed Consolidated Statements of Income.

In connection with the November 15, 2005 initial public offering of the Partnership (IPO), BPHC contributed all of the equity interests of Boardwalk Pipelines to the Partnership for limited partner and general partner units. This contribution was accounted for as a transfer of assets between entities under common control in accordance with Statement of Financial Accounting Standards (SFAS) No. 141, Business Combinations. Therefore, the consolidated results of Boardwalk Pipelines for the periods prior to the IPO have been presented in this report as the consolidated results of the Partnership.

See Note 4 of the Notes to Condensed Consolidated Financial Statements for additional information related to the change in income and franchise taxes.

Note 2: Gas in Storage and Gas Receivables/Payables

Gas receivables and payables reflect amounts of customer-owned gas at the Texas Gas facilities. Consistent with regulatory treatment prescribed by the Federal Energy Regulatory Commission (FERC) and risk of loss provisions included in its tariff, Texas Gas reflects an equal and offsetting receivable and payable for customer-owned gas in its facilities for storage and related services. The gas payables amount is valued at the historical cost of gas, and was $40.7 million and $33.6 million at September 30, 2006 and December 31, 2005, respectively. The Partnership does not reflect volumes held by Gulf South on behalf of others on its Condensed Consolidated Balance Sheets. As of September 30, 2006 and December 31, 2005, Gulf South held 57.4 trillion British thermal units (TBtu) and 32.9 TBtu of gas owned by shippers, respectively, and had loaned 0.2 TBtu of gas to shippers as of December 31, 2005. No gas was loaned by Gulf South to shippers as of September 30, 2006. The average market price during September 2006 and December 2005 was $4.88 and $12.34 per one million British thermal units (MMBtu), respectively.

Note 3: Derivative Financial Instruments

In accordance with the Partnership’s risk management policy, Gulf South utilizes natural gas futures, swaps and options contracts (collectively, derivatives) to hedge exposures to market price fluctuations for natural gas. These transactions include hedges of anticipated natural gas purchases and sales related to system operations, fuel reimbursement and management of company-owned storage capacity. Each of these types of transactions are performed by employees of Gulf South in furtherance of its performance of transportation and storage services in interstate commerce. The derivatives are reported at fair value in accordance with SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended.

On August 1 and August 3, 2006, Boardwalk Pipelines entered into Treasury rate locks with two counterparties, each for a notional amount of $100 million of principal to hedge the risk attributable to changes in the risk-free component of forward 10-year interest rates through August 1, 2007. The reference rates on the Treasury rate locks were 5.00% and 4.96%. Under the terms of the Treasury rate locks, the counterparties would pay Boardwalk Pipelines settlement amounts if the 10-year Treasury rate was greater than the reference rates at August 1, 2007. Conversely, Boardwalk Pipelines would pay the counterparties settlement amounts if the 10-year Treasury rate was less than the reference rates. The Treasury rate locks are reported at fair value in accordance with SFAS No. 133.

The fair values of derivatives existing as of September 30, 2006 and December 31, 2005, were included in the following captions in the condensed consolidated financial statements (expressed in millions):

	September 30, 2006	December 31, 2005
Prepaid expenses and other current assets	$ 10.2	$ 0.6
Other noncurrent assets	0.6	-
Other current liabilities	6.4	0.8
Accumulated other comprehensive income (loss)	3.4	(0.2)

The changes in fair values of the derivatives designated as cash flow hedges are expected to, and do, have a high correlation to changes in value of the anticipated transactions. The derivatives related to the sale of natural gas and derivatives related to cash for fuel reimbursement generally qualify for cash flow hedge accounting under SFAS No. 133 and are designated as such. Similarly, the Treasury rate locks are designated as a cash flow hedge of expected future interest payments in accordance with SFAS No. 133. The related unrealized gains and losses resulting from changes in the fair values of derivatives contracts designated as cash flow hedges are deferred as a component of Accumulated Other Comprehensive Income (Loss). For the cash flow hedges related to the sale of natural gas and fuel reimbursement, the deferred gains and losses are recognized in the Condensed Consolidated Statements of Income when the hedged anticipated purchases or sales affect earnings. For the Treasury rate locks, the balance of Accumulated Other Comprehensive Income (Loss) would be amortized to interest expense over the term corresponding with the related interest payments on the debt issue.

The Partnership expects to reclassify $2.5 million of the credits currently recorded in Accumulated Other Comprehensive Income (Loss) to earnings by December 31, 2006. The amounts recorded in Accumulated Other Comprehensive Income (Loss) reflected in the Condensed Consolidated Balance Sheets and the Condensed Consolidated Statements of Changes in Member’s Equity and Partners’ Capital and Comprehensive Income were comprised of $8.9 million from cash flow hedges related to the sale of natural gas and fuel retained less the unrealized loss of $5.5 million associated with the Treasury rate locks.

Each reporting period the Partnership measures the effectiveness of the cash flow hedge contracts. To the extent the changes in the fair values of the hedge contracts do not effectively offset the changes in the estimated cash flows of the anticipated purchases or sales or, in the case of the Treasury rate locks, the change in the expected future interest payments, the ineffective portion of the hedge contracts is currently recognized in earnings. Less than $0.1 million of ineffectiveness was recorded during the three and nine month periods ended September 30, 2006. No ineffectiveness was recorded during the comparable 2005 periods. If the anticipated purchases, sales, debt issuances or other related transactions are deemed no longer probable to occur, hedge accounting would be terminated and the changes in the fair values of the associated derivative financial instruments would be recognized currently on the Condensed Consolidated Statements of Income. No cash flow hedges were discontinued during the three and nine month periods ended September 30, 2006 and 2005.

Derivatives related to the value of company-owned storage capacity and the purchase of operational gas for the East Texas and Mississippi pipeline expansion project during the second quarter 2006 were not designated as hedges in accordance with SFAS No. 133. The changes in the values of the derivatives were recognized currently in earnings. The Partnership recognized $0.9 million and $1.3 million of credits to earnings, respectively, for the three and nine months ended September 30, 2006 related to the change in fair values associated with the derivatives.

The activity affecting Accumulated Other Comprehensive Income (Loss), with respect to cash flow hedges included the following:

	September 30,
For the three months ended (expressed in thousands):	2006	2005 (net of tax)
Net unrealized gains (losses) on derivatives qualifying as cash flow hedges at the beginning of the period	$ 4,640	$ (372)
Unrealized hedging gains (losses) arising during the period on derivatives qualifying as cash flow hedges	1,328	(1,877)
Reclassification adjustment transferred to net income	(2,540)	671
Net unrealized gains (losses) on derivatives qualifying as cash flow hedges at the end of the period	$ 3,428	$ (1,578)

	September 30,
For the nine months ended (expressed in thousands):	2006	2005 (net of tax)
Net unrealized losses on derivatives qualifying as cash flow hedges at the beginning of the period	$ (174)	-
Unrealized hedging gains (losses) arising during the period on derivatives qualifying as cash flow hedges	11,736	$ (2,424)
Reclassification adjustment transferred to net income	(8,134)	846
Net unrealized gains (losses) on derivatives qualifying as cash flow hedges at the end of the period	$ 3,428	$ (1,578)

Note 4: Income and Franchise Taxes

The Partnership is not a taxable entity for federal income tax purposes and does not directly pay federal income tax. The Partnership’s taxable income or loss, which may vary substantially from the net income or loss reported in the Condensed Consolidated Statements of Income, is includable in the taxable income of its partners. The partners are required to pay federal income taxes and, in some cases, state and local income taxes on their share of taxable income.

Prior to converting to a limited partnership on November 15, 2005, Boardwalk Pipelines’ taxable income was included in the consolidated federal income tax return of Loews, and Boardwalk Pipelines recorded a charge-in-lieu of income taxes pursuant to a tax sharing agreement with Loews. The tax sharing agreement required Boardwalk Pipelines to remit to Loews on a quarterly basis any federal income taxes as if it were filing a separate return. Boardwalk Pipelines and its subsidiaries were also included in the state franchise tax filings of BPHC. The franchise taxes were charged to, and recorded by, Boardwalk Pipelines and its subsidiaries pursuant to the companies’ tax sharing policy.

Following the IPO, the Partnership and its subsidiaries no longer record a charge-in-lieu of income taxes or certain state franchise taxes incurred by BPHC and no longer participate in a tax sharing agreement with Loews or tax sharing policy with BPHC. A subsidiary of the Partnership directly incurs some income-based state taxes which are accrued as Income taxes and charge-in-lieu of income taxes on the Condensed Consolidated Statements of Income.

Note 5: Commitments and Contingencies

A. Impact of Hurricanes Katrina and Rita

In August and September 2005, Hurricanes Katrina and Rita and related storm activity caused extensive and catastrophic physical damage in and to the offshore, coastal and inland areas in the Gulf Coast region of the United States. A substantial portion of the Gulf South assets and a smaller portion of the Texas Gas assets are located in the area directly impacted by the hurricanes.

The total cost to repair storm damages before insurance recoveries is not expected to exceed $20.0 million; however, repairs and system evaluations are ongoing. During the third quarter 2006, an additional $0.5 million was accrued related to ongoing Katrina-related expenditures. The combined remaining liability for both Hurricanes Katrina and Rita was $1.8 million as of September 30, 2006.

In the first quarter 2006, the Partnership accrued estimated insurance proceeds of $2.7 million related to Hurricane Katrina which represented the minimum amount of insurance proceeds that were probable of recovery. The Partnership will continue to pursue recovery of additional insurance proceeds related to Hurricane Katrina. In September 2006, the Partnership received confirmation from the insurance underwriters that a partial payment was approved for the Katrina claim. In addition, the Partnership is pursuing recovery of insurance proceeds related to Hurricane Rita, but no amount has been recorded.

Although the Partnership does not currently anticipate that the overall impact of Hurricanes Katrina and Rita will have a material adverse effect upon its future financial condition, results of operations or cash flows, in light of the magnitude of the damage caused by the hurricanes and the enormity of the relief and reconstruction effort, some uncertainty remains as to the ultimate impact these hurricanes will have on the Partnership.

B. Legal Proceedings

Hurricane Katrina - Related Class Actions

Gulf South, along with at least eight other interstate pipelines and major natural gas producers, has been named in three Hurricane Katrina-related class action lawsuits filed in the United States District Court for the Eastern District of Louisiana (District Court). The lawsuits allege that the dredging of canals caused damage to the marshes and that undamaged marshes would have prevented all, or almost all, of the loss of life and destruction of property caused by Hurricane Katrina. The District Court has dismissed the first two lawsuits for failure to state a claim. The third case was filed after the motions to dismiss were filed but prior to the District Court’s ruling. A motion to dismiss has been filed in this third case, but has not been ruled upon. The Partnership is currently unable to estimate the ultimate outcomes of the proceedings.

Napoleonville Salt Dome Matter

In December 2003, natural gas leaks were observed near two natural gas storage caverns that were being leased and operated by Gulf South for natural gas storage in Napoleonville, Louisiana. Gulf South commenced remediation efforts immediately and ceased using those storage caverns. Two class action lawsuits were filed relating to this incident and were converted to individual actions. Several individual actions have been filed against Gulf South and other defendants by local residents and businesses. In addition, the lessor of the property has filed an affirmative claim against Gulf South in an action filed against the lessor by one of Gulf South’s insurers. Gulf South continues to vigorously defend each of these actions; however it is not possible to predict the outcome of this litigation as the cases are in the early stages of discovery. Litigation is subject to many uncertainties, and it is possible these actions could be decided unfavorably. Gulf South has settled several of the cases filed against it and may enter into discussions in an attempt to settle other cases if Gulf South believes it is appropriate to do so.

From the date of acquisition of Gulf South on December 29, 2004 through September 30, 2006, Gulf South has incurred $6.2 million for remediation costs, root cause investigation, and legal fees and had a liability balance at September 30, 2006 and December 31, 2005, of $0.3 million and $1.1 million, respectively, in Other current liabilities on the Condensed Consolidated Balance Sheets pertaining to this incident. Gulf South has made demand for reimbursement from its insurance carriers and will continue to pursue recoveries of the remaining expenses, including legal expenses. To date the insurance carriers have not taken any definitive coverage positions on all of the issues raised in the various lawsuits. For the nine months ended September 30, 2006, Gulf South received $0.8 million of insurance reimbursements for legal expenses and root cause investigation. The range of loss related to this incident could not be estimated at September 30, 2006.

Other Legal Matters

Devon Energy Eugene Island Offshore Facilities Settlement. In June 2006, Gulf South received $4.0 million from Devon Energy in settlement of a lawsuit concerning the parties’ rights and obligations under a lease for a platform that Devon will decommission in the Eugene Island area in the Gulf of Mexico. The proceeds will be used to offset the costs of rebuilding certain offshore facilities. The total cost of the new facilities is not expected to exceed $8.0 million.

The Partnership’s subsidiaries are parties to various other legal actions arising in the normal course of business. Management believes the disposition of all known outstanding legal actions will not have a material adverse impact on the Partnership’s financial condition, results of operations or cash flows.

C. Regulatory and Rate Matters

Expansion Projects

The Partnership is currently engaged in the following expansion projects:

·	Carthage to Keatchie Loop. The Partnership has begun construction on a 20.5 mile segment of 42-inch pipeline from Carthage, Texas to Keatchie, Louisiana. The capacity of the segment will be 120 MMcf per day and is expected to be in service by the end of November 2006.

East Texas and Mississippi Pipeline Expansion. The Partnership is pursuing a pipeline expansion project consisting of 242 miles of 42-inch pipeline from DeSoto Parish in western Louisiana to near Harrisville, Mississippi and approximately 110,000 horsepower of new compression. The expansion would add approximately 1.7 Bcf per day of new transmission capacity to the Gulf South pipeline system. The natural gas to be transported on this expansion will originate primarily from the Barnett Shale and Bossier Sands producing regions of East Texas. The expansion will transport natural gas to new interstate pipeline interconnects in the Perryville, Louisiana area and existing pipeline interconnects with other pipelines east of the Mississippi River. This expansion is supported by binding precedent agreements with customers who have contracted, on a long-term basis (with a weighted average life of approximately 7 years), for 1.3 Bcf with an option for an additional 100 MMcf of the approximately 1.7 Bcf per day capacity. On September 1, 2006, Gulf South filed a certificate application relating to this project with FERC. Gulf South has ordered the pipeline and compression materials needed to construct this project. The Partnership expects this project to be in service during September 2007. The total cost of this expansion and the Carthage to Keatchie Loop is expected to be approximately $800 million.

Western Kentucky Storage Expansion. The Partnership is pursuing a project to expand the working gas capacity in Texas Gas’ western Kentucky storage complex by approximately 9 Bcf. This project is supported by binding commitments from customers to contract on a long-term firm basis for the full additional capacity at Texas Gas’ maximum applicable rate. On April 14, 2006, Texas Gas filed a certificate application relating to this project with FERC. The Partnership expects this project to cost approximately $36 million and to be in service during November 2007.

Magnolia Storage Expansion. Gulf South has leased a gas storage facility near Napoleonville, Louisiana, and is currently developing an additional storage cavern. During recent mining operations, certain issues have arisen causing the mining of the caverns to be suspended. Gulf South has conducted and is continuing during the fourth quarter 2006 to conduct operational integrity tests on the caverns and associated facilities. If the test results are favorable, Gulf South expects the storage facilities to be in service during 2009. If the test results are not favorable, management will consider the options it has available, including developing a new cavern, sale or abandonment of the project. The total book value of the project at September 30, 2006 was $42.2 million. The Partnership tests the investment in Magnolia for recoverability in accordance with the requirements of SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets. No impairment loss has been recognized as a result of the recoverability tests.

General Rate Case

On June 20, 2006 the settlement of Texas Gas’ general rate case became final. On June 30, 2006, Texas Gas refunded approximately $6.6 million consisting of $6.4 million in principal and $0.2 million of interest to its customers. The amount of the refund was accrued as a reduction to revenues and an increase to interest expense over the period from November 1, 2005 to the date of the refund. At December 31, 2005, the amount of the estimated liability for refund was approximately $5.0 million.

Due to the settlement, in the first quarter 2006, Texas Gas began to amortize the balance of its regulatory asset for postretirement benefits other than pensions (PBOP). The amortization of the remaining regulatory asset balance of approximately $27.2 million at September 30, 2006, will continue to be amortized on a straight-line basis over approximately five years.

Pipeline Integrity

On June 30, 2005, FERC issued an order addressing the accounting treatment for the costs pipeline operators will incur in implementing all aspects of pipeline integrity management programs which are required by the Office of Pipeline Safety. FERC’s accounting guidance became effective prospectively, beginning with integrity management costs incurred on or after January 1, 2006. Amounts capitalized in periods prior to January 1, 2006, were permitted to remain as recorded. The Partnership applied the accounting guidance order on January 1, 2006. There were no changes to the Partnership’s accounting policy for the pipeline integrity management programs as a result of the application of this guidance.

D. Environmental and Safety Matters

Texas Gas and Gulf South are subject to federal, state and local environmental laws and regulations in connection with the operation and remediation of various sites. When possible, the Partnership enters into voluntary remediation programs with the regulatory agencies. The Partnership accrues for environmental remediation expenses resulting from existing conditions that relate to past operations when the costs are probable and can be reasonably estimated. As of September 30, 2006 and December 31, 2005, the Partnership had an accrued liability of approximately $19 million and $20 million respectively, related to environmental remediation.

The Partnership’s pipeline operations are subject to the Clean Air Act (CAA) and include two facilities in areas affected by non-attainment requirements for the current ozone standard (eight-hour standard), which are now in compliance. As of September 30, 2006, the Partnership had incurred costs of approximately $14 million for emission control modifications of compression equipment located at facilities required to comply with current CAA provisions and state implementation plans for nitrogen oxide reductions. The costs were recorded as additions to Property, plant and equipment (PPE) as the modifications were added. If the Environmental Protection Agency (EPA) designates additional new non-attainment areas where the pipelines operate, the cost of additions to PPE would be expected to increase. The Partnership is unable at this time to estimate with any certainty the cost of any additions that may be required.

On October 20, 2006, Texas Gas received notice from the EPA that Texas Gas is a potentially responsible party under the Comprehensive Environmental Response, Compensation, and Liability Act of 1980 with respect to the LWD, Inc. Superfund Site in Calvert City, Marshall County, Kentucky. The Partnership is unable to estimate with any certainty at this time any potential liability it may incur related to this notice; however, the Partnership does not expect this to have a material effect on its financial condition.

In addition, the EPA promulgated new rules regarding hazardous air pollutants in 2004, which will impose additional controls at four facilities at an estimated cost of $1.6 million. The effective compliance date for the hazardous air pollutants regulations is 2007. The Partnership anticipates installation of associated controls to meet these new regulations in 2006 and 2007.

The Partnership considers environmental assessment, remediation costs and costs associated with compliance with environmental standards to be recoverable through its rates, as they are prudent costs incurred in the ordinary course of business. No regulatory asset has been recorded to defer these costs. The actual costs incurred will depend on the amount and extent of contamination discovered, the final cleanup standards mandated by the EPA or other governmental authorities, and other factors.

E. Commitments for Construction

The Partnership’s significant commitments for construction as of September 30, 2006, by period were as follows (expressed in millions):

Less than 1 year	$ 277.9
1-2 years	7.0
3-5 years	-
> 5 years	-
Total	$ 284.9

The commitments for construction were primarily related to the East Texas and Mississippi pipeline expansion. For further discussion of the East Texas and Mississippi pipeline expansion see Note 5C Expansion Projects contained in these Notes to Condensed Consolidated Financial Statements.

F. Lease Commitments

The Partnership has various operating lease commitments extending through the year 2018 covering storage facilities, transportation capacity on third-party pipelines, office facilities and equipment. The table below summarizes minimum future commitments related to the leases at September 30, 2006 (expressed in millions):

2006	$ 1.2
2007	5.5
2008	5.6
2009	4.4
2010	4.2
Thereafter	14.6
Total	$ 35.5

The Partnership’s lease commitments increased from those shown in the 2005 Annual Report on Form 10-K, mainly from the signing of a ten-year lease for new office facilities at Gulf South. The estimated commencement date of the lease is May 1, 2007.

Note 6: Net Income per Limited Partner Unit

The Partnership calculates net income per limited partner unit in accordance with Emerging Issues Task Force Issue No. 03-6 (EITF No. 03-6), Participating Securities and the Two-Class Method under Financial Accounting Standards Board (FASB) Statement No. 128. In Issue 3 of EITF No. 03-6, the EITF reached a consensus that undistributed earnings for a period should be allocated to a participating security based on the contractual participation rights of the security to share in those earnings as if all of the earnings for the period had been distributed. The Partnership’s general partner holds contractual participation rights which are incentive distribution rights in accordance with the partnership agreement as follows:

Net Income per Unit	Limited Partner Units *(and Subordinated Units)**	General Partner Units
Up to $0.4025	98%	2%
From $0.4026 to $0.4375	85%	15%
From $0.4376 to $0.5250	75%	25%
Greater than $0.5250	50%	50%

* Under the terms of the partnership agreement, distributions during the subordination period are first made to the common unitholders and general partner, and then to the subordinated unitholders and general partner to the extent the total distributed amount is greater than the minimum quarterly distribution of $0.35 per unit to the common unitholders.

The amount reported for net income per limited partner unit on the Condensed Consolidated Statements of Income for the nine month period ended September 30, 2006 was reduced to take into account an assumed allocation to the general partner’s incentive distribution rights. However, the Partnership has not paid, nor has the general partner authorized the payment of any amounts to the general partner on account of its incentive distribution rights.

A reconciliation of the limited partners’ interest in net income and net income available to limited partners used in computing net income per limited partner unit is as follows (expressed in thousands, except per unit data):

	For the Three Months Ended September 30, 2006		For the Nine Months Ended September 30, 2006
Limited partners’ interest in net income	$	30,034	$	129,631
Less assumed allocation to incentive distribution rights		-		962
Net income available to limited partners		30,034		128,669
Less assumed allocation to subordinated units		6,144		42,015
Net income available to common units	$	23,890	$	86,654
Weighted average common units		68,256		68,256
Weighted average subordinated units		33,094		33,094
Net income per limited partner unit - common units	$	0.35	$	1.27
Net income per limited partner unit - subordinated units	$	0.19	$	1.27

Note 7: Sale of Facilities

In June 2006, Texas Gas received $2.5 million for the sale of offshore transmission facilities in the Gulf of Mexico at West Cameron 294. The sale of the facilities was considered a normal retirement. In accordance with the composite method of accounting for property, plant and equipment, the proceeds and the related book value of the plant were recorded to accumulated depreciation which is classified as Property, plant and equipment, net on the Condensed Consolidated Balance Sheets.

Note 8: Financing

In June 2006, the Partnership’s revolving credit facility was amended and restated from a $200.0 million facility to a $400.0 million facility. Under the amended and restated facility, which the Partnership has guaranteed, Boardwalk Pipelines, Texas Gas and Gulf South each may borrow funds, up to applicable sub-limits. 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 (LIBOR) or a base rate defined as the greater of the prime rate or the Federal funds rate plus 50 basis points. Under the terms of the agreement, each of the borrowers must maintain a minimum ratio, as of the last day of each fiscal quarter, of consolidated total debt to consolidated earnings before interest, taxes, depreciation and amortization (EBITDA) (as defined in the agreement), measured for the preceding twelve months, of not more than five to one. As of September 30, 2006, the Partnership had drawn $60.0 million under this facility at an interest rate of 5.73%. The revolving credit facility has a maturity date of June 29, 2011.

As of September 30, 2006 and December 31, 2005 the weighted-average interest rate of the Partnership’s long-term debt, including the borrowing under the revolving credit facility, was 5.13% and 5.29%, respectively. Due to the recent increase in capital expenditures mainly from work performed on the East Texas and Mississippi pipeline expansion project, the amount of interest capitalized during the third quarter 2006 has increased over previous periods. The construction work in progress included in PPE, net in the Condensed Consolidated Balance Sheets was $183.5 million as of September 30, 2006. During the three months ended September 30, 2006 and 2005, the Partnership capitalized interest of $0.7 million and less than $0.1 million. For the nine months ended September 30, 2006 and 2005, the Partnership capitalized $0.8 million and $0.1 million of interest. In accordance with SFAS No. 71, Accounting for the Effect of Certain Types of Regulation, the Partnership’s Texas Gas subsidiary capitalizes allowance for funds used during construction (AFUDC), comprised of debt and equity components. The Partnership capitalized $0.5 million and $0.6 million of AFUDC for the three months ended September 30, 2006 and 2005. For the nine months ended September 30, 2006 and 2005, the Partnership capitalized $1.1 million and $1.6 million of AFUDC.

In connection with the IPO, Boardwalk Pipelines borrowed approximately $42.1 million under its revolving credit facility to reimburse BPHC for capital expenditures it incurred in connection with the acquisition of Gulf South. Interest on the borrowings was accrued at the 3-month LIBOR rate plus applicable margin (4.68%). The borrowings were repaid in full during February 2006.

In December 2004, Boardwalk Pipelines borrowed $575.0 million as an interim term loan in connection with the Gulf South Acquisition. In January 2005, Boardwalk Pipelines issued $300.0 million principal amount of 5.50% notes due in 2017 and Gulf South issued $275.0 million principal amount of 5.05% notes due in 2015. The proceeds from these notes, together with available cash, were used to repay the interim loan.

Note 9: Credit Concentration

Natural gas price volatility has increased dramatically in recent years, which has materially increased credit risk related to gas loaned to customers. As of September 30, 2006, the amount of gas loaned by the Partnership’s subsidiaries was approximately 5 TBtu and, assuming an average market price during September 2006 of $4.88 per MMBtu, the market value of that gas was approximately $24.4 million. As of December 31, 2005, the amount of gas loaned was approximately 15 TBtu and, assuming an average market price during December 2005 of $12.34 per MMBtu, the market value of that gas was approximately $185.1 million. If any significant customer should have credit or financial problems resulting in a delay or failure to repay the gas owed to the Partnership’s subsidiaries, this could have a material adverse effect on the Partnership’s financial condition, results of operations and cash flows.

Note 10: Employee Benefits and Compensation

Retirement Plan

Substantially all of Texas Gas' employees are covered under a non-contributory, defined benefit pension plan. Texas Gas also provides postretirement life insurance and postretirement health care benefits to certain retired employees. Texas Gas uses a measurement date of December 31 for its pension and postretirement benefits plans.

During the first quarter 2006, Texas Gas began recognizing pension expense based on the actuarially determined net periodic pension cost pursuant to the settlement of its rate case. Based on the annual actuarial study, pension expense for 2006 was determined to be approximately $4.6 million. During the nine months ended September 30, 2006, Texas Gas recorded pension expense retroactive to November 1, 2005, the date on which Texas Gas’ new general rate case became effective. As of September 30, 2006, Texas Gas contributed $3.0 million to its pension plan. The contribution for 2006 is expected to be approximately $5.2 million.

Net periodic benefit cost components were as follows (expressed in thousands):

	Pension Benefits For the Three Months Ended September 30,		Other Benefits For the Three Months Ended September 30,
	2006	2005	2006	2005
Service cost	$ 1,147	$ 975	$ 108	$ 519
Interest cost	1,765	1,500	858	1,806
Expected return on plan assets	(1,799)	(1,725)	(1,134)	(1,158)
Amortization of prior service cost	-	-	(1,939)	-
Amortization of accumulated loss	332	-	110	90
Special termination benefit	5,600	-	900	-
Regulatory accrual/amortization	(3,045)	(750)	1,354	68
Estimated net periodic benefit cost	$ 4,000	$ -	$ 257	$ 1,325

	Pension Benefits For the Nine Months Ended September 30,		Other Benefits For the Nine Months Ended September 30,
	2006	2005	2006	2005
Service cost	$ 3,971	$ 2,925	$ 1,194	$ 1,557
Interest cost	6,001	4,500	4,319	5,418
Expected return on plan assets	(6,492)	(5,175)	(3,418)	(3,474)
Amortization of prior service cost	-	-	(2,587)	-
Amortization of accumulated loss	584	-	876	270
Special termination benefit	5,600	-	900	-
Regulatory accrual/amortization	(3,045)	(2,250)	4,964	204
Estimated net periodic benefit cost	$ 6,619	$ -	$ 6,248	$ 3,975

Defined Contribution Plans

Subsidiaries of the Partnership maintain defined contribution plans covering substantially all of its employees. Costs related to these plans were $1.2 million and $3.7 million, respectively, for the three and nine months ended September 30, 2006 and $1.3 million and $3.6 million, respectively, for the three and nine months ended September 30, 2005.

Postretirement Benefits other than Pensions

In May 2006, as part of an overall cost reduction program, Texas Gas announced to its employees and retirees a plan to make changes to its postretirement benefits plan beginning January 1, 2007. Under the revised plan, Texas Gas will cap its contributions toward medical benefit coverage for retirees younger than age 65 to the amount contributed for each retiree in 2006. For retirees age 65 and older, Texas Gas will cap its contribution at three times the 2006 amount. In addition, Texas Gas will no longer cover prescription drug costs for retirees age 65 and older. In conjunction with the plan amendments, Texas Gas increased the discount rate used in determining the accumulated postretirement benefit obligation (APBO) and net periodic postretirement benefit cost from 5.88% to 6.38%, effective June 1, 2006 to accomodate changes in market interest rates since the end of 2005. The changes will result in an estimated reduction in the APBO of approximately $75.3 million for the plan amendment and $13.5 million for the increase in the discount rate. In accordance with SFAS No. 106, Employers’ Accounting for Postretirement Benefits other than Pensions, the decrease in the APBO from the plan amendment will be recognized as a reduction to net periodic postretirement benefit cost over the average remaining service lives of active employees covered under the plan, or approximately nine years. For the nine months ended September 30, 2006, the change resulted in a reduction of $5.1 million for net periodic benefit cost from the amount that would otherwise have been recognized.

Early Retirement Incentive Program

In 2006, Texas Gas implemented an early retirement incentive program (ERIP) which was made available to approximately 240 non-executive employees age 52 and older with at least five years of service. Under the program, Texas Gas would provide eligible employees three additional years for purposes of age-based vesting under the postretirement medical plan and three additional years of pay credits under the pension plan. Retirements under the program would generally be effective January 1, 2007. Approximately 100 of the eligible employees indicated their intent to participate in the program.

As a result of the ERIP, the Partnership recognized a special termination benefit of approximately $5.6 million for pension and $0.9 million for PBOP. In accordance with the regulatory treatment for Texas Gas’ pension expense, $2.6 million of the special termination benefit for pension was recognized in Administrative and general expense and the remainder was deferred as a regulatory asset. The charge for PBOP was recognized in Administrative and general expense.

Strategic Long Term Incentive Plan

On July 24, 2006 the Partnership approved the Boardwalk Pipeline Partners Strategic Long Term Incentive Plan (the Plan). The Plan provides for the issuance of up to 500 General Partner (GP) Phantom Units to key executives of the Partnership and its subsidiaries. Each GP Phantom Unit entitles the holder thereof, upon vesting, to a lump sum cash payment in an amount determined by a formula based on cash distributions made by the Partnership to its general partner during the four quarters preceding the vesting date.

Concurrent with the approval of the Plan, 125 GP Phantom Units were awarded to employees that would vest in 3.5 years. The fair value of the awards was determined as of the date of grant and remeasured at the end of the third quarter 2006 in accordance with the treatment of awards classified as liabilities prescribed in SFAS No. 123 (revised 2004), Share-Based Payment. The fair value of the awards will be recognized ratably over the vesting period. The fair value will be remeasured each quarter until settlement. Any change to the fair value at the end of a particular quarter would be recognized over the remaining vesting period. For the third quarter 2006, the Partnership recognized a liability and concurrent charge to Administrative and general expenses of $0.2 million related to the fair value of the GP Phantom Unit awards.

Note 11: Related Parties

Loews has a policy of charging its subsidiary companies for management services provided by Loews. The Partnership recorded $2.1 million and $8.6 million, respectively, for the three and nine months ended September 30, 2006 and $3.6 million and $7.6 million, respectively, for the three and nine month periods ended September 30, 2005 for management services.

Note 12: Distributions

The Partnership has declared quarterly distributions per unit to unitholders of record, including common and subordinated units and the 2% general partner interest held by its general partner as follows:

Record Date	Payable Date	Distribution per Unit
October 30, 2006	November 6, 2006	$ 0.40
August 11, 2006	August 18, 2006	$ 0.38
May 12, 2006	May 19, 2006	$ 0.36
February 16, 2006	February 23, 2006	$ 0.1788*

*Distribution represented a prorated portion of the $0.35 per unit “minimum quarterly distribution” (as defined in the Partnership’s partnership agreement) for the period from November 15, 2005 through December 31, 2005.

Note 13: Recently Issued Accounting Pronouncements

In September of 2006, the Securities and Exchange Commission (SEC) issued Staff Accounting Bulletin (SAB) No. 108, Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements. This bulletin summarizes the SEC staff’s views regarding the process of quantifying financial statement misstatements. SAB No. 108 is effective for reporting periods ending after November 15, 2006. SAB No. 108 is not expected to have a material impact on the Partnership’s financial condition, results of operation or cash flows.

On September 29, 2006 the FASB issued SFAS No. 158, Employers' Accounting for Defined Benefit Pension and Other Postretirement Plans. Under SFAS No. 158, a defined benefit postretirement plan sponsor must (a) recognize in its statement of financial position an asset for a plan's overfunded status or a liability for the plan's underfunded status, (b) measure the plan's assets and its obligations that determine its funded status as of the end of the employer's fiscal year (with limited exceptions), and (c) recognize, as a component of other comprehensive income, the changes in the funded status of the plan that arise during the year but are not recognized as components of net periodic benefit cost pursuant to SFAS No. 87, Employers' Accounting for Pensions, or SFAS No. 106, Employers' Accounting for Postretirement Benefits Other Than Pensions. Previous standards required an employer to disclose the complete funded status of its plan only in the notes to the financial statements. Moreover, because those standards allowed an employer to delay recognition of certain changes in plan assets and obligations that affected the costs of providing benefits, employers reported an asset or liability that almost always differed from the plan's funded status. SFAS No. 158 is initially effective for fiscal years ending after December 15, 2006, except for (b), measurement of plan assets and benefit obligations which will be effective for fiscal years ending after December 15, 2008. The Partnership is currently evaluating the impact, if any, that SFAS No. 158 would have on its financial statements.

On September 15, 2006, the FASB issued SFAS No. 157, Fair Value Measurements. Under the standard, fair value refers to the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants in the market in which the reporting entity transacts. The standard clarifies the principle that fair value should be based on the assumptions market participants would use when pricing the asset or liability. In support of this principle, the standard establishes a fair value hierarchy that prioritizes the information used to develop those assumptions. The fair value hierarchy gives the highest priority to quoted prices in active markets and the lowest priority to unobservable data, for example, the reporting entity’s own data. Under the standard, fair value measurements would be separately disclosed by level within the fair value hierarchy. The Statement is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. The Partnership is currently evaluating the impact, if any, that SFAS No. 157 would have on its financial statements.

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with (i) 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 (GAAP), (ii) 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, 2005, and (iii) the Risk Factors described in Item 1A of Part II of this report.

We are a Delaware limited partnership formed in 2005 to own and operate the business conducted by Boardwalk Pipelines, LP (Boardwalk Pipelines) and its subsidiaries, Texas Gas Transmission, LLC (Texas Gas) and Gulf South Pipeline Company, LP (Gulf South). We are engaged through our subsidiaries in the interstate transportation and storage of natural gas and operate in one reportable segment - the operation of interstate natural gas pipeline systems. Our pipeline systems are comprised of an aggregate of 13,470 miles of pipe and integrated storage originating in the Gulf Coast area and running north and east through Texas, Louisiana, Mississippi, Alabama, Florida, Arkansas, Tennessee, Kentucky, Indiana, Ohio and Illinois.

In connection with our initial public offering (IPO), Boardwalk Pipelines Holding Corp. (BPHC) contributed all of the equity interests of Boardwalk Pipelines to us in exchange for limited partner and general partner units. This contribution was accounted for as a transfer of assets between entities under common control in accordance with Statement of Financial Accounting Standards (SFAS) No. 141, Business Combinations. Therefore, the consolidated results of Boardwalk Pipelines for the periods prior to the IPO have been presented in this report as our consolidated results.

Critical Accounting Policies and Estimates

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 at the date of 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 period in which the facts that give rise to the revision become known.

We calculate net income per limited partner unit in accordance with Emerging Issues Task Force Issue No. 03-6 (EITF No. 03-6), Participating Securities and the Two-Class Method under Financial Accounting Standards Board (FASB) Statement No. 128. In Issue 3 of EITF No. 03-6, the EITF reached a consensus that undistributed earnings for a period should be allocated to a participating security based on the contractual participation rights of the security to share in those earnings as if all of the earnings for the period had been distributed. The Partnership’s general partner holds contractual participation rights which are incentive distribution rights in accordance with the partnership agreement as follows:

Net Income per Unit	Limited Partner Units *(and Subordinated Units)**	General Partner Units
Up to $0.4025	98%	2%
From $0.4026 to $0.4375	85%	15%
From $0.4376 to $0.5250	75%	25%
Greater than $0.5250	50%	50%

The amount reported for net income per limited partner unit on the Condensed Consolidated Statements of Income for the nine month period ended September 30, 2006 was reduced to take into account an assumed allocation to the general partner’s incentive distribution rights. However, we have not paid, nor has the general partner authorized the payment of, any amounts to the general partner on account of its incentive distribution rights.

Further information regarding our accounting policies and estimates that we considered to be critical can be found in our Annual Report on Form 10-K for the year ended December 31, 2005. There have not been any significant changes in these policies and estimates during 2006.

Results of Operations - Business Overview

The Partnership derives its revenues primarily from the interstate transportation and storage of natural gas for third parties. Transportation and storage services are provided under firm and interruptible service agreements. Transportation rates are subject to maximum tariff rates established by the Federal Energy Regulatory Commission (FERC), although many services are provided at a discount to the maximum tariff rates due to competition in the marketplace.

Under firm transportation agreements, customers generally pay a fixed “demand” or “capacity reservation” charge to reserve pipeline capacity at certain receipt and delivery points, plus a commodity and fuel charge paid on the volume of gas actually transported. Firm storage customers reserve a specific amount of storage capacity and injection and withdrawal capability and generally pay a capacity reservation charge based on the amount of capacity being reserved plus an injection and/or withdrawal fee. Capacity reservation revenues derived from firm services are generally higher in winter peak periods (November through March) than off-peak periods resulting in a seasonal earnings pattern where the majority of earnings are generated in the first and fourth quarters of a calendar year. The seasonal effect is also impacted by increased revenues generated from usage during the winter peak periods.

Interruptible transportation and storage services are typically short-term in nature and are generally used by customers that do not require the certainty of delivery that is provided with firm services. Customers pay for interruptible services when the service is used.

Revenues for our parking and lending (PAL) services and certain of our storage service for which we are authorized to charge market-based rates are affected by period-to-period natural gas price spreads (for example, summer to winter). In recent periods, these price spreads have been wider and more volatile than in previous years, resulting in significant increases in parking and lending and storage revenues. We are uncertain if these recent favorable trends in period-to-period natural gas price spreads will continue. A reversal of this trend could result in lower revenues and profits from these services in future periods.

Operating expenses typically do not vary significantly based upon the amount of gas transported with the exception of gas consumed by Gulf South’s compressor stations. Gulf South’s fuel recoveries are included as part of transportation revenues.

Results of Operations for the Three Months Ended September 30, 2006 and 2005

Total Operating Revenues increased by $12.1 million, or 10%, to $133.0 million for the three months ended September 30, 2006, compared to $120.9 million for the three months ended September 30, 2005 primarily due to:

·	$9.0 million increase in storage and parking-and-lending services due to favorable natural gas price spreads and volatility in forward gas prices; and

·	$7.7 million increase in transportation services primarily from higher reservation rates and additional capacity reserved by shippers due to increased production in the East Texas region;

partially offset by,

·	$3.6 million decrease in usage fees on interruptible services due to 2006 volumes being transported on new firm contracts; and

·	$1.1 million decrease in revenues for a reduction in the amortization of acquired executory contracts.

Total Operating Costs and Expenses decreased by $11.6 million, or 11.6%, to $88.3 million for the three months ended September 30, 2006, compared to $99.9 million for the three months ended September 30, 2005 primarily due to:

·	$8.1 million decrease in company-used gas due to lower natural gas prices and operational efficiencies resulting in decreased usage; and

·	$4.6 million decrease from charges recognized in 2005 for hurricanes Katrina and Rita;

partially offset by,

·	$1.2 million increase in labor and benefits consisting of the recognition of a $3.5 million special termination benefit charge as a result of the Texas Gas early retirement incentive program (ERIP), reduced by the effects of a cost-reduction program implemented at Texas Gas.

Total Other (Income) Deductions increased by $0.6 million, or 4.4%, to $14.0 million for the three months ended September 2006, compared to $13.4 million for the comparable 2005 period. The increase is primarily due to a reduction in interest income.

Income Taxes and Charge-In-Lieu of Income Taxes decreased by $2.9 million, to $0.1 million for the third quarter 2006, due to the change in tax status and conversion to a limited partnership concurrent with the IPO.

Results of Operations for the Nine Months Ended September 30, 2006 and 2005

Total Operating Revenues increased by $46.6 million, or 12%, to $436.2 million for the nine months ended September 30, 2006, compared to $389.6 million for the nine months ended September 30, 2005 primarily due to:

·	$25.5 million increase in storage and parking-and-lending services due to favorable natural gas price spreads and volatility in forward gas prices;

·	$20.0 million increase in transportation services due primarily to higher reservation rates and additional capacity reserved by shippers due to increased production in the East Texas region; and

·	$5.5 million increase in fuel related revenues due to an increase in realized gas prices including revenues locked in through hedging activities and additional system volumes;

partially offset by,

·	$4.5 million decrease in revenues for a reduction in the amortization of acquired executory contracts.

Total Operating Costs and Expenses increased by $5.3 million, or 2.1%, to $260.9 million for the nine months ended September 30, 2006, compared to $255.6 million for the nine months ended September 30, 2005 primarily due to:

·	$6.9 million increase in labor and outside services primarily due to growth in operations;

·	$6.5 million increase due to the amortization of a regulatory asset related to postretirement benefits other than pensions and pension expense recognition as a result of the settled rate case, reduced by the impact of other postretirement benefit plan changes;

·	$3.5 million increase in benefits expense due to the recognition of a special termination benefit charge as a result of the Texas Gas ERIP and expense recognition as a result of the settled Texas Gas rate case;

·	$3.1 million increase in depreciation and amortization due to the increased asset base from additions to plant and purchase accounting adjustments in 2005; and

·	$2.8 million increase in costs for transportation of gas on third-party pipelines to provide additional deliveries to the market area;

partially offset by,

·	$8.7 million decrease from charges recognized in 2005 for hurricanes Katrina and Rita;

·	$6.1 million decrease in company-used gas due to operational efficiencies resulting in decreased usage; and

·	$2.4 million decrease in expenses for state franchise taxes due to the change in tax status to a limited partnership concurrent with the IPO.

Total Other (Income) Deductions increased by $1.9 million, or 4.7%, to $42.6 million for the nine months ended September 30, 2006, compared to $40.7 million for the comparable 2005 period. The increase is primarily due to interest expense related to borrowings under a credit facility that occurred after the IPO in 2005 of $1.1 million and a reduction in interest income of $1.0 million.

Income Taxes and Charge-In-Lieu of Income Taxes decreased by $36.8 million, to $0.4 million for the nine months ended September 30, 2006, due to the change in tax status and conversion to a limited partnership concurrent with the IPO.

Capital Expenditures

Capital expenditures, net of amounts received for retirements and salvage and accrued amounts for the nine months ended September 30, 2006 and 2005 were $120.2 million and $50.4 million, respectively.

For the year ending December 31, 2006, we expect to make capital expenditures of approximately $275.0 million, of which we expect approximately $221.0 million to be for expansion capital, including approximately $170.0 million to fund our East Texas and Mississippi pipeline expansion project, discussed below, and $54.0 million to be for maintenance capital. The amount of expansion capital we expend in 2006 could vary significantly depending on the progress made with these projects, the number and types of other capital projects we decide to pursue, the timing of any of those projects and numerous other factors beyond our control.

We currently expect to fund our 2006 maintenance capital expenditures from operating cash flows. We expect to fund our 2006 expansion capital expenditures on an interim basis with borrowings under our revolving credit facility. We expect to pay off any borrowings under our revolving credit facility with the issuance of debt and equity during the fourth quarter 2006. Thereafter, we expect to fund the balance of the cost of our pipeline expansion projects with a combination of cash from operations, borrowings under our revolving credit facility, and proceeds from sales of our debt and equity securities.

We are currently engaged in the following expansion projects:

·	Carthage to Keatchie Loop. We have begun construction on a 20.5 mile segment of 42-inch pipeline from Carthage, Texas to Keatchie, Louisiana. The capacity of the segment will be 120 MMcf per day and we expect it to be in service by the end of November 2006.

East Texas and Mississippi Pipeline Expansion. We are pursuing a pipeline expansion project consisting of 242 miles of 42-inch pipeline from DeSoto Parish in western Louisiana to near Harrisville, Mississippi and approximately 110,000 horsepower of new compression. The expansion would add approximately 1.7 Bcf per day of new transmission capacity to the Gulf South pipeline system. The natural gas to be transported on this expansion will originate primarily from the Barnett Shale and Bossier Sands producing regions of East Texas. The expansion will transport natural gas to new interstate pipeline interconnects in the Perryville, Louisiana area and existing pipeline interconnects with other pipelines east of the Mississippi River. This expansion is supported by binding precedent agreements with customers who have contracted, on a long-term basis (with a weighted average life of approximately 7 years), for 1.3 Bcf with an option for an additional 100 MMcf of the approximately 1.7 Bcf per day capacity. On September 1, 2006, Gulf South filed a certificate application relating to this project with FERC. Gulf South has ordered the pipeline and compression materials needed to construct this project. We expect this project to be in service during September 2007. The total cost of this expansion and the Carthage to Keatchie Loop is expected to be approximately $800 million.

Western Kentucky Storage Expansion. We are pursuing a project to expand the working gas capacity in Texas Gas’ western Kentucky storage complex by approximately 9 Bcf. This project is supported by binding commitments from customers to contract on a long-term firm basis for the full additional capacity at Texas Gas’ maximum applicable rate. On April 14, 2006, Texas Gas filed a certificate application relating to this project with FERC. We expect this project to cost approximately $36 million and to be in service during November 2007.

Magnolia Storage Expansion. Gulf South has leased a gas storage facility near Napoleonville, Louisiana, and is currently developing an additional storage cavern. During recent mining operations, certain issues have arisen causing the mining of the caverns to be suspended. Gulf South has conducted and is continuing during the fourth quarter 2006 to conduct operational integrity tests on the caverns and associated facilities. If the test results are favorable, Gulf South expects the storage facilities to be in service during 2009. If the test results are not favorable, management will consider the options it has available, including developing a new cavern, sale or abandonment of the project. The total book value of the project at September 30, 2006 was $42.2 million. We test the investment in Magnolia for recoverability in accordance with the requirements of SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets. No impairment loss has been recognized as a result of the recoverability tests.

We are also engaged in discussions on other proposed future expansion projects, which would connect our pipeline system to growing supplies of gas in the Mid-Continent region. We previously announced the signing of a letter of intent to pursue the formation of a joint venture to construct a new interstate pipeline that would connect gas supplies originating in the Fayetteville Shale region of Arkansas, in North Central Texas and Oklahoma to a new interconnect with Texas Gas. One of the original participants has withdrawn from the project, alleging that we breached the terms of the letter of intent based on its belief that we are pursuing a competing project. We strongly disagree with these allegations. We and the remaining participant continue to pursue this project.

The completion of all of these projects is subject to risks and uncertainties including market conditions, signing of definitive agreements, obtaining appropriate regulatory approvals (including FERC’s review of requests for authorization), obtaining the necessary financing for the projects and other factors beyond our control.

Distributions

We have declared quarterly distributions per unit to unitholders of record, including common and subordinated units and the 2% general partner interest held by its general partner as follows:

Record Date	Payable Date	Distribution per Unit
October 30, 2006	November 6, 2006	$0.40
August 11, 2006	August 18, 2006	$0.38
May 12, 2006	May 19, 2006	$0.36
February 16, 2006	February 23, 2006	$0.1788*

The distributions have been paid, or will be paid, from our available cash pursuant to the partnership agreement and funded by cash from operations.

Cost Reduction Program

In 2006, Texas Gas implemented a program that will reduce labor and benefits costs by approximately $15 million on an annualized basis. The components of the program included changes to postretirement benefits other than pensions (PBOP), the ERIP, a reduction in the annual cash incentive program and the elimination of the 2006 broad-based merit increase pool for 2006. Refer to Note 10 of the Notes to Condensed Consolidated Financial Statements in Part I, Item 1 of this report for additional information regarding the changes to PBOP and the ERIP.

Liquidity and Capital Resources

We are a limited partnership holding company and derive all of our operating cash flow from our subsidiaries, Texas Gas and Gulf South. Our subsidiaries use funds from their respective operations to fund their operating activities and maintenance and expansion capital requirements, service their indebtedness and make advances or distributions to Boardwalk Pipelines. Boardwalk Pipelines uses cash provided from Texas Gas and Gulf South and, as needed, borrowings under its revolving credit facility, to service its indebtedness and make distributions or advances to us to fund our distributions to unitholders and our general partner.

We have filed registration statements on Form S-1 covering the offering and sale of: (i) $250 million of senior unsecured notes of our subsidiary, Boardwalk Pipelines, to be guaranteed by us; and (ii) up to 5,750,000 of our common units. The proceeds of such offerings, if consummated, will be used to finance our expansion activities and/or repay outstanding borrowings under our revolving credit facility which were used to finance such activities.

To hedge the risk attributable to changes in the risk-free component of forward 10-year interest rates through December 1, 2006, on October 5, 2006 we entered into a Treasury rate lock for a notional amount of $250 million of principal. The reference rate on the Treasury rate lock was 4.6%. In addition, on August 1 and August 3, 2006 we entered into Treasury rate locks with two counterparties each for a notional amount of $100 million of principal to hedge the risk attributable to changes in the risk-free component of forward 10-year interest rates through August 1, 2007. The reference rates on those Treasury rate locks were 5.00% and 4.96%. See Item 3 for more information regarding the Treasury rate locks and interest rate risk.

In June 2006, our revolving credit facility was amended and restated from a $200 million facility to a $400 million facility. Under the amended and restated facility, which we have guaranteed, Boardwalk Pipelines, Texas Gas and Gulf South each may borrow funds up to applicable sub-limits. 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 LIBOR) or a base rate defined as the greater of the prime rate or the Federal funds rate plus 50 basis points. Under the terms of the agreement, each of the borrowers must maintain a minimum ratio, as of the last day of each fiscal quarter, of consolidated total debt to consolidated earnings before interest, taxes, depreciation and amortization (EBITDA) (as defined in the agreement), measured for the preceding twelve months, of not more than five to one. As of September 30, 2006, we had drawn $60 million under this facility at an interest rate of 5.73%. The revolving credit facility has a maturity date of June 29, 2011.

Changes in cash flow from operating activities for the Nine Months Ended September 30, 2006 and September 30, 2005

Net cash provided by operating activities was $184.9 million for the nine months ended September 30, 2006, compared to $159.7 million in the comparable 2005 period. The increase of $25.2 million in cash flow from operating activities primarily consisted of:

· $79.1 million increase in net income, excluding non-cash items such as depreciation; and

· $16.0 million increase in cash inflows relative to net changes in working capital items; partially offset by

· $50.5 million decrease in the provision for deferred income taxes due to the change in entity structure; and

· $19.5 million increase in cash outflows relative to net changes in non-current assets and liabilities.

Changes in cash flow from investing activities:

Net cash used in investing activities increased $37.7 million, to $116.0 million for the nine month period ended September 30, 2006, from $78.2 million in the comparable 2005 period, which was primarily attributable to:

· $69.8 million increase in capital expenditures; partially offset by

· $27.1 million decrease in advances to affiliates; and

· $5.0 million increase in insurance and other recoveries.

Changes in cash flow from financing activities:

Net cash used in financing activities amounted to $77.1 million for the nine months ended September 30, 2006, compared to $63.9 million during the same period in 2005. The increase of $13.2 million was primarily due to:

· $30.0 million increase in distributions paid; and

· $6.7 million decrease in capital contributions received in 2005 from our parent; partially offset by

· $23.5 million primarily due to a net increase in debt.

Contractual Obligations

The table below is updated for significant changes in lease and capital commitments from those included in the Annual Report on Form 10-K for the year ended December 31, 2005 by period (expressed in millions):

	Payments due by Period
	Total		Less than 1 Year		1-2 Years		3-5 Years		More than 5 Years
Lease commitments	$	35.5	$	5.4	$	10.3	$	8.8	$	11.0
Capital commitments		284.9		277.9		7.0		-		-
Total	$	320.4	$	283.3	$	17.3	$	8.8	$	11.0

The change in lease commitments was related to the signing of a ten-year lease for new office facilities at Gulf South. The estimated commencement date of the lease is May 1, 2007.

The capital commitments for construction were primarily related to the East Texas and Mississippi pipeline expansion. For further discussion of the East Texas and Mississippi pipeline expansion please read Note 5C Expansion Projects in the Notes to Condensed Consolidated Financial Statements included in Part I, Item 1 of this report.

The 2006 funding requirement to the employee benefits retirement plan as a result of Texas Gas’ settled rate case is $5.2 million.

For a detailed listing of our Contractual Obligations, please see our Annual Report on Form 10-K for the year ended December 31, 2005.

Off-Balance Sheet Arrangements

We have no off-balance sheet arrangements as defined by Regulation S-K.

Forward-Looking Statements

Investors are cautioned that certain statements contained in this report as well as some statements in periodic press releases and some oral statements made by our officials and our subsidiaries during presentations about us, are “forward-looking” statements within the meaning of the Private Securities Litigation Reform Act of 1995 (Act). Forward-looking statements include, without limitation, any statement that may project, indicate or imply future results, events, performance or achievements, and may contain the words “expect,” “intend,” “plan,” “anticipate,” “estimate,” “believe,” “will likely result,” and similar expressions. In addition, any statement concerning future financial performance (including future revenues, earnings or growth rates), ongoing business strategies or prospects, and possible actions by us or our subsidiaries, which may be provided by management, are also forward-looking statements as defined by the Act.

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

•

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

•

the impact of Hurricanes Katrina and Rita or any new hurricane could have a material adverse effect on our business, financial condition and results of operations because some of our damages may not be covered by insurance;

•

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

•

our operations are subject to operational hazards and unforeseen interruptions for which we may not be adequately insured;

•

the cost of insuring our assets may increase dramatically;

•

because of the natural decline in gas production from existing wells, our success depends on the 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, financial condition and results of operations;

•

successful development of liquefied natural gas import terminals in the eastern or northeastern United States could reduce the demand for our services;

•

we may not be able to maintain or replace expiring gas transportation and storage contracts at favorable rates;

•

we depend on certain key customers for a significant portion of our revenues. The loss of any of these key customers could result in a decline in our revenues;

•

significant changes in natural gas prices could affect supply and demand, reducing system throughput and adversely affecting our revenues;

•

we may not complete projects, including growth or expansion projects, that we commence, or we may complete projects on materially different terms or timing than anticipated and we may not be able to achieve the intended benefits of any such project, if completed; and

•

the successful completion, timing, cost, scope and future financial performance of our expansion projects could differ materially from our expectations due to weather, untimely regulatory approvals or denied applications, land owner opposition, the lack of adequate materials, or labor, we may encounter difficulties with partners or potential partners and numerous other factors beyond our control.

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 3. Quantitative and Qualitative Disclosures About Market Risk

Our long-term debt is subject to interest rate risk. Total long-term debt at September 30, 2006, had a carrying value of $1.2 billion and a fair value of $1.1 billion. The weighted-average interest rate of our long-term debt was 5.13% at September 30, 2006, including the effect of the interest rate on $60 million borrowed against our revolving credit facility.

We entered into a Treasury rate lock October 5, 2006 for a notional amount of $250 million of principal to hedge the risk attributable to changes in the risk-free component of forward 10-year interest rates through December 1, 2006, the expected date of issuance of $250 million of Boardwalk Pipelines’ senior unsecured notes. The reference rate on the Treasury rate lock is 4.60%. Under the terms of the Treasury rate lock, the counterparty would pay us a settlement amount if the 10-year Treasury rate is greater than 4.60% on December 1, 2006. Conversely, we would pay the counterparty a settlement amount if the 10-year Treasury rate is less than 4.60%.

On August 1 and August 3, 2006, we entered into Treasury rate locks with two counterparties each for a notional amount of $100 million of principal to hedge the risk attributable to changes in the risk-free component of forward 10-year interest rates through August 1, 2007. The reference rates on the Treasury rate locks are 5.00% and 4.96%. Under the terms of the Treasury rate locks, the counterparties would pay us settlement amounts if the 10-year Treasury rate is greater than the reference rates at October 1, 2007. Conversely, we would pay the counterparties settlement amounts if the 10-year Treasury rate is less than the reference rates. As of September 30, 2006, the Partnership recognized a liability of $5.6 million related to the fair values of the August 2007 rate locks. In addition to the liability, the Partnership recognized a charge to Accumulated other comprehensive income in an equal and offsetting amount less ineffectiveness recognized of less than $0.1 million.

The Treasury rate locks will be accounted for as cash flow hedges in accordance with SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended. Under a cash flow hedge of expected future interest payments, gains and losses on the derivative would be recognized in Accumulated other comprehensive income. The balance of Accumulated other comprehensive income would be amortized to interest expense over the term of the related interest payments.

Certain volumes of gas stored underground at Gulf South are available for sale under its tariff and subject to commodity price risk. At September 30, 2006 and December 31, 2005, approximately $15.1 million and $6.5 million, respectively, of Gulf South’s gas stored underground, which we own and carry as inventory, is exposed to commodity price risk. In accordance with the Partnership’s risk management policy, Gulf South utilizes natural gas futures, swaps, and options contracts (collectively, derivatives) to hedge certain exposures to market price fluctuations on our anticipated operational sales of gas. The changes in fair values of the derivatives related to the anticipated sales of gas, are designated as cash flow hedges under SFAS No. 133 and are expected to, and do, have a high correlation to changes in the anticipated value of the hedged transactions. Pursuant to SFAS No. 133, the periodic changes in fair values of the derivatives are deferred as a component of Accumulated other comprehensive income (loss) and are recognized in the Condensed Consolidated Statements of Income when the hedged anticipated purchases or sales affect earnings.

Derivatives related to the value of company-owned storage capacity and the purchase of operational gas for the East Texas and Mississippi pipeline expansion project during the second quarter 2006 were not designated as hedges in accordance with SFAS No. 133. The changes in the values of the derivatives were recognized currently in earnings. We recognized $0.9 million and $1.3 million of credits to earnings, respectively, for the three and nine months ended September 30, 2006 related to the change in fair values associated with the derivatives.

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 and no-notice services. We maintain credit policies intended to minimize credit risk and actively monitor these policies. Natural gas price volatility has increased dramatically in recent years, which has materially increased credit risk related to gas loaned to customers. As of September 30, 2006, the amount of gas loaned out by our subsidiaries was approximately 5 Trillion British thermal units (Tbtu) and, assuming an average market price during September 2006 of $4.88 per million British thermal units (MMBtu), the market value of gas loaned out at September 30, 2006, would have been approximately $24.4 million. As of December 31, 2005, the amount of gas loaned out was approximately 15 TBtu and, assuming an average market price during December 2005 of $12.34 per MMBtu, the market value of that gas would be approximately $185.1 million. If any significant customer of ours should have credit or financial problems resulting in a delay or failure to repay the gas they owe to us, this could have a material adverse effect on our financial condition, results of operations and cash flows.

As of September 30, 2006, our cash and investment portfolio did not include fixed-income securities. Due to the short-term nature of our investment portfolio, a hypothetical 10% increase in interest rates would not have a material effect on the fair market value of our portfolio. Since we have the ability to liquidate this portfolio, we do not expect our Condensed Consolidated Statements of Income or Cash Flows to be materially affected to any significant degree by the effect of a sudden change in market interest rates on our investment portfolio.

Item 4. Controls and Procedures

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

Our principal executive officers and principal financial officer have conducted an evaluation of the disclosure controls and procedures as of the end of the period covered by this report. Based on this evaluation, the principal executive officers and principal financial officer have each concluded that the disclosure controls and procedures are effective.

Other than the matters discussed below, there was no change in our 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, our internal control over financial reporting.

Changes in Internal Control over Financial Reporting

During the third quarter 2006, we implemented a new financial consolidation and reporting system and our Gulf South subsidiary implemented a new procurement system. It is anticipated that these implementations will enhance internal controls through the automation of manual processes.

PART II-OTHER INFORMATION

Item 1. Legal Proceedings

For further discussion of our legal proceedings, please read Note 5 Commitments and Contingencies—Legal Proceedings in the Notes to Condensed Consolidated Financial Statements included in Item 1.

Item 1 A. Risk Factors

The following discussion supplements the Risk Factors in Item 1A "Risk Factors" of our Annual Report on Form 10-K for the year ended December 31, 2005.

We may not complete expansion projects that we commence, or we may complete projects on materially different terms or timing than anticipated and we may not be able to achieve the intended benefits of any such projects, if completed.

We have announced significant expansion projects and may consider additional expansion projects in the future. We anticipate that we will be required to seek additional financing in the future to fund our current and future expansion projects and may not be able to secure such financing on favorable terms, or at all. We may not be able to complete the expansion projects on time as a result of delays in obtaining regulatory approvals, delays in obtaining key materials and land owner opposition. Further, even if expansion projects are completed the total costs of the expansion projects may be higher than anticipated and the performance of our business following the expansion projects may not meet expectations. In addition, we may not be able to timely and effectively integrate the expansion projects into our operations, such integration may result in unforeseen operating difficulties or unanticipated costs and the expansion projects might divert the attention of management from our other business concerns. Any of these or other factors could adversely affect our ability to realize the anticipated benefits from the expansion projects and thus have a material adverse effect on our business, financial condition, results of operations and cash flows.

Item 6. Exhibits

Exhibit Designation
Exhibit Designation	Registrant	Nature of Exhibit

31.1	Boardwalk Pipeline Partners, LP	Certification of Rolf A. Gafvert, Co-President, pursuant to Rule 13a-14(a) and Rule 15d-14(a)
31.2	Boardwalk Pipeline Partners, LP	Certification of H. Dean Jones II, Co-President, pursuant to Rule 13a-14(a) and Rule 15d-14(a)
31.3	Boardwalk Pipeline Partners, LP	Certification of Jamie L. Buskill, Vice President and Chief Financial Officer, pursuant to Rule 13a-14(a) and Rule 15d-14(a)
32.1	Boardwalk Pipeline Partners, LP	Certification by Rolf A. Gafvert, Co-President and H. Dean Jones, II, Co-President, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.2	Boardwalk Pipeline Partners, LP	Certification of Jamie L. Buskill, Vice President and Chief Financial Officer, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	Boardwalk Pipeline Partners, LP

		By: Boardwalk GP, LP
		its general partner

		By: Boardwalk GP, LLC
		its general partner

Dated: November 8, 2006			By:	/s/ Jamie L. Buskill
				Jamie L. Buskill
				Vice President and Chief Financial Officer