Boardwalk Pipeline Partners, LP Form 10-Q

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 June 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 July 28, 2006, the registrant had 68,256,122 common units outstanding and 33,093,878 subordinated units outstanding.

TABLE OF CONTENTS

FORM 10-Q

JUNE 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 1A. 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	June 30, 2006		December 31, 2005
Current Assets:
Cash and cash equivalents	$	57,839	$	65,792
Receivables, net:
Trade		41,782		59,115
Other		11,074		5,564
Gas Receivables:
Transportation and exchange		11,090		29,557
Storage		3,971		12,576
Inventories		15,828		15,881
Costs recoverable from customers		9,876		3,560
Gas stored underground		9,879		6,500
Prepaid expenses and other current assets		16,304		7,720
Total current assets		177,643		206,265

Property, Plant and Equipment:
Natural gas transmission plant		1,827,554		1,772,483
Other natural gas plant		210,245		213,136
		2,037,799		1,985,619

Less—accumulated depreciation and amortization		151,563		118,213
Property, plant and equipment, net		1,886,236		1,867,406

Other Assets:
Goodwill		163,474		163,474
Gas stored underground		169,091		169,177
Costs recoverable from customers		33,462		43,960
Other		16,533		15,209
Total other assets		382,560		391,820

Total Assets	$	2,446,439	$	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	June 30, 2006		December 31, 2005
Current Liabilities:
Payables:
Trade	$	25,244	$	20,433
Other		13,012		3,681
Gas Payables:
Transportation and exchange		17,528		14,710
Storage		36,286		27,559
Accrued taxes other		15,930		16,004
Accrued interest		17,744		17,996
Accrued payroll and employee benefits		21,092		29,028
Current note payable		-		42,100
Other current liabilities		31,499		30,776
Total current liabilities		178,335		202,287

Long-Term Debt		1,101,694		1,101,290

Other Liabilities and Deferred Credits:
Postretirement benefits		39,565		32,413
Asset retirement obligations		14,496		14,074
Provision for other asset retirements		39,209		33,212
Other		33,731		93,541
Total other liabilities and deferred credits		127,001		173,240

Commitments and Contingencies (Note 5)		-		-

Partners’ Capital:
Common units - 68,256,122 issued and outstanding		735,921		705,609
Subordinated units - 33,093,878 issued and outstanding		281,269		266,578
General partner		17,579		16,661
Accumulated other comprehensive income (loss)		4,640		(174	)
Total partners’ capital		1,039,409		988,674
Total Liabilities and Partners’ Capital	$	2,446,439	$	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 June 30,		For the Six Months Ended June 30,
	2006	2005	2006	2005
Operating Revenues:
Gas transportation	$ 105,390	$ 99,898	$ 256,402	$ 236,772
Parking and lending	9,414	6,687	22,931	13,076
Gas storage	7,196	5,240	16,814	10,232
Other	6,662	6,437	6,961	8,564
Total operating revenues	128,662	118,262	303,108	268,644

Operating Costs and Expenses:
Operation and maintenance	36,833	36,343	75,160	67,628
Administrative and general	22,844	19,838	50,232	37,979
Depreciation and amortization	18,727	17,864	37,410	35,059
Taxes other than income taxes*	6,785	7,419	12,014	14,559
Net (gain) loss on disposal of operating assets	(2,391)	484	(2,205)	484
Total operating costs and expenses	82,798	81,948	172,611	155,709

Operating Income	45,864	36,314	130,497	112,935

Other (Income) Deductions:
Interest expense	15,215	15,074	30,847	29,739
Interest income	(698)	(594)	(1,242)	(746)
Interest income from affiliates	(7)	(553)	(7)	(957)
Miscellaneous other income, net	(792)	(406)	(977)	(736)
Total other (income) deductions	13,718	13,521	28,621	27,300

Income before income taxes	32,146	22,793	101,876	85,635

Income taxes and charge-in-lieu of income taxes*	246	9,088	246	34,073
Net Income*	$ 31,900	$ 13,705	$ 101,630	$ 51,562

*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 six month periods ended June 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 June 30, 2006	For the Six Months Ended June 30, 2006
Calculation of limited partners’ interest in 2006 net income:
Net income to partners	$ 31,900	$ 101,630
Less general partner’s interest in net income	638	2,033
Limited partners’ interest in net income	$ 31,262	$ 99,597
Basic and diluted net income per limited partner unit:
Common units (See Note 6)	$0.35	$0.95
Subordinated units (See Note 6)	$0.22	$0.95
Cash distribution to common and subordinated unitholders and general partner unit equivalents	$0.36	$0.54
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 Six Months Ended June 30,
	2006		2005

OPERATING ACTIVITIES:
Net income	$ 101,630	$ 51,562
Adjustments to reconcile to cash provided from (used in) operations:
Depreciation and amortization	37,410	35,059
Amortization of acquired executory contracts	(2,561)	(6,043)
Net (gain) loss on disposal of operating assets	(2,248)	484
Provision for deferred income taxes	-	41,436
Changes in operating assets and liabilities:
Receivables	39,863	44,390
Inventories	53	(1,094)
Affiliates	(122)	(1,317)
Other current assets	(14,358)	(3,665)
Accrued income taxes	38	(7,370)
Payables and accrued liabilities	15,438	(10,917)
Other, including changes in noncurrent assets and liabilities	(38,590)	(18,145)
Net cash provided by operating activities	136,553	124,380
INVESTING ACTIVITIES:
Capital expenditures, net	(51,021)	(33,018)
Insurance and other recoveries	4,960	6,392
Advances to affiliates, net	(623)	(20,852)
Net cash used in investing activities	(46,684)	(47,478)
FINANCING ACTIVITIES:
Payment of short-term debt	(42,100)	-
Proceeds from long-term debt	-	569,369
Payment of long-term debt	-	(575,000)
Distributions paid	(55,722)	(45,000)
Capital contribution from parent	-	6,684
Net cash used in financing activities	(97,822)	(43,947)
Increase (decrease) in cash and cash equivalents	(7,953)	32,955
Cash and cash equivalents at beginning of period	65,792	16,518
Cash and cash equivalents at end of period	$ 57,839	$ 49,473

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	-	51,562	-	$ 51,562	-	-	-	51,562
Capital contribution	6,684	-	-	-	-	-	-	6,684
Distributions paid	-	(45,000)	-	-	-	-	-	(45,000)
Other comprehensive (loss), net of tax	-	-	$ (372)	(372)	-	-	-	(372)
Comprehensive income				$ 51,190
Balance, June 30, 2005	$ 1,078,335	$ 27,838	$ (372)		-	-	-	$ 1,105,801

Balance January 1, 2006	-	-	$ (174)	-	$ 705,609	$ 266,578	$ 16,661	$ 988,674
Add (deduct):
Net income	-	-	-	$ 101,630	67,075	32,522	2,033	101,630
Distributions paid	-	-	-	-	(36,776)	(17,831)	(1,115)	(55,722)
Other comprehensive income	-	-	4,814	4,814	-	-	-	4,814
Transaction costs related to sale of common units	-	-	-	-	13	-	-	13
Comprehensive income				$ 106,444
Balance June 30, 2006	-	-	$ 4,640		$ 735,921	$ 281,269	$ 17,579	$ 1,039,409

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 June 30, 2006 and December 31, 2005, the results of operations for the three and six months ended June 30, 2006 and 2005 and changes in cash flows. Reference is made to the Notes to Condensed 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.

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 $41.4 million and $33.6 million at June 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 June 30, 2006 and December 31, 2005, Gulf South held 52.3 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 June 30, 2006. The average market price during June 2006 and December 2005 was $6.20 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. These derivatives are reported at fair value in accordance with SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended. The fair values of derivatives and the effects thereof, existing as of June 30, 2006 and December 31, 2005, are included in the following captions in the Condensed Consolidated Financial Statements (expressed in millions):

	June 30, 2006	December 31, 2005
Prepaid expenses and other current assets	$6.2	$0.6
Other noncurrent assets	0.5	-
Other current liabilities	0.5	0.8
Accumulated other comprehensive income (loss)	4.6	(0.2)

The changes in fair values of the hedge contracts 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. 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). These deferred gains and losses are recognized in the Condensed Consolidated Statements of Income when the hedged anticipated purchases or sales affect earnings. The Partnership expects to reclassify $4.1 million of the credits currently recorded in Accumulated Other Comprehensive Income 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 solely related to unrealized gains and losses on cash flow hedges.

Each reporting period the Partnership measures the effectiveness of the cash flow hedge contracts. To the extent the change in the fair value of the hedge contracts does not effectively offset the change in the fair value of the anticipated purchases or sales, the ineffective portion of the hedge contracts is currently recognized in earnings. No ineffectiveness was recorded during the three or six month periods ended June 30, 2006 or 2005. If the anticipated purchase or sale is deemed no longer probable to occur, hedge accounting would be terminated and the associated changes in the fair values of the derivative financial instruments would be recognized currently on the Condensed Consolidated Statements of Income. No cash flow hedges were discontinued during the three or six month periods ended June 30, 2006 or 2005.

The derivatives related to the value of company-owned storage capacity and the purchase of operational gas for the East Texas expansion project during the second quarter 2006 have not been designated as cash flow hedges. The changes in the values of the derivatives were recognized currently in earnings. The Partnership recognized $0.3 million and $0.4 million of credits to earnings, respectively, for the three and six months ended June 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:

	June 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	$ 4,052	$ (1,222)
Unrealized hedging gains arising during the period on derivatives qualifying as cash flow hedges	3,390	676
Reclassification adjustment transferred to net income	(2,802)	174
Net unrealized gains (losses) on derivatives qualifying as cash flow hedges at the end of the period	$ 4,640	$ (372)

	June 30,
For the six 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	10,408	$ (546)
Reclassification adjustment transferred to net income	(5,594)	174
Net unrealized gains (losses) on derivatives qualifying as cash flow hedges at the end of the period	$ 4,640	$ (372)

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 second quarter 2006, as a result of a change in estimate primarily related to property retirements, the Partnership reduced the liability accrued for damage incurred during Hurricane Rita by $2.9 million. This decrease resulted in a reduction in overall expenses related to the hurricanes of $0.8 million for the six months ended June 30, 2006 on its Condensed Consolidated Statements of Income. The combined liability for both Hurricanes Katrina and Rita was $2.1 million as of June 30, 2006. For the six months ended June 30, 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. 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, substantial 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 two Hurricane Katrina-related class action lawsuits filed in the United States District Court for the Eastern District of Louisiana. The lawsuits allege that the dredging of canals caused damages to the marshes and that undamaged marshes would have prevented all, or almost all, of the loss of life and destruction of property caused by Hurricane Katrina. These cases are in very early stages and, as such, the Partnership cannot reasonably estimate the amount of potential loss, if any.

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, a declaratory judgment action has been filed and stayed against Gulf South by the lessor of the property, and several individual actions have been filed against Gulf South and other defendants by local residents and businesses. 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 intends to vigorously defend each of these actions, however it is not possible to predict the outcome of this litigation. Litigation is subject to many uncertainties, and it is possible 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 June 30, 2006, Gulf South has incurred $5.4 million for remediation costs, root cause investigation, and legal fees and had a liability balance at June 30, 2006 and December 31, 2005, of $0.9 million and $1.1 million, respectively, in Other 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 its insurance carriers have not taken any definitive coverage positions on all of the issues raised in the various lawsuits. For the six months ended June 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 June 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. As of June 30, 2006, Gulf South deferred the settlement proceeds in Other Payables. 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 its 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:

Increase in Working Gas at Jackson, Mississippi Gas Storage Facility. In June 2006, Gulf South received FERC approval to permanently increase the working gas capacity at the Jackson, Mississippi gas storage facility by 2.4 billion cubic feet (Bcf), bringing the total working gas capacity at the Jackson gas storage facility to 5.1 Bcf.

East Texas/Mississippi Pipeline Expansion Project. Gulf South has entered into long-term precedent agreements with customers providing firm commitments for most of the capacity on its 1.5 Bcf per day pipeline expansion project. The Partnership expects the total cost for the 1.5 Bcf per day expansion to be approximately $800 million, and expects the new capacity associated with this project to be in service during the second half of 2007. Gulf South has been granted the authority to initiate the pre-filing process for this project. Gulf South expects to file its certificate application with FERC on or about September 1, 2006.

Western Kentucky Storage Expansion. Texas Gas has accepted, subject to FERC approval, commitments from customers for incremental no-notice service and firm storage service that will allow it to expand the working gas capacity in its Western Kentucky storage complex by approximately 9 Bcf. On April 14, 2006, Texas Gas filed an application with FERC requesting authority to proceed with this expansion project. The proposed in-service date for the storage expansion is November 2007.

Lake Charles, Louisiana Expansion. On March 17, 2006, Gulf South received approval from FERC to purchase an undivided 38.46 percent interest in 1.7 miles of pipeline from Trunkline Gas Company, LLC (Trunkline Gas) for $1.9 million. The pipeline connects Trunkline LNG Company, LLC’s liquefied natural gas import terminal in Lake Charles, Louisiana to Gulf South’s pipeline. Gulf South’s ownership interest will be equivalent to 500,000 dekatherms per day. Trunkline Gas will continue to operate the pipeline pursuant to an operating agreement. This transaction was completed March 31, 2006, and the assets were placed in service in April 2006.

Magnolia Storage Expansion. Gulf South has leased a gas storage facility near Napoleonville, Louisiana, and is currently developing high-deliverability storage caverns. During recent mining operations, certain issues have arisen causing the mining of the caverns to be temporarily suspended. Gulf South will conduct operational integrity tests on the cavern and associated facilities during the third quarter 2006. 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, or sale or abandonment of the project. The total book value at June 30, 2006 was $42.2 million. During the second quarter 2006, the Partnership tested 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 was recognized as a result of the recoverability test.

General Rate Case

On April 29, 2005, Texas Gas filed a general rate case. Texas Gas began collecting new rates, subject to refund, on November 1, 2005. Texas Gas and the other participants (FERC staff and customers) reached an unopposed settlement offer that was approved by FERC on April 21, 2006, and became final on June 20, 2006. The annual settled cost of service was $257.8 million. 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 $28.5 million at June 30, 2006 will continue to be amortized on a straight-line basis over approximately five years.

Pipeline Integrity

The Office of Pipeline Safety (OPS) has issued a final rule that requires natural gas pipeline operators to develop integrity management programs. 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. 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 June 30, 2006 and December 31, 2005, the Partnership had an accrued liability of approximately $20 million 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 June 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.

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

Boardwalk Pipeline Partners’ significant commitments for construction as of June 30, 2006, by period were as follows (expressed in millions):

Less than 1 year	$ 271.9
1-2 years	37.2
3-5 years	-
> 5 years	-
Total	$ 309.1

The commitments for construction were primarily related to the East Texas/Mississippi pipeline expansion. For further discussion of the East Texas/Mississippi pipeline expansion see Note 5C Expansion Projects contained herein.

F. Lease Commitments

Boardwalk Pipeline Partners has various operating lease commitments extending through the year 2018 covering storage facilities, offices and other equipment. The table below summarizes minimum future commitments related to these items at June 30, 2006, as follows (expressed in millions):

2006	$ 3.0
2007	6.4
2008	5.5
2009	4.4
2010	4.2
Thereafter	14.5
Total	$ 38.0

The increase in lease commitments from December 31, 2005 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.

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.

Due to the seasonal nature of the Partnership’s business, with the highest percentage of earnings typically occurring in the first and fourth quarters of a calendar year, the amount reported for net income per limited partner unit on the Condensed Consolidated Statements of Income for the six month period ended June 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 allocation rights. Assuming a historically seasonal earnings pattern, as the year progresses the impact on the disclosed net income per limited partner unit from the assumed allocation to the general partner’s incentive distribution rights would be reduced in subsequent year-to-date reporting periods from the assumed effect indicated in the first quarter and six-month period ended June 30, 2006 on a stand-alone basis.

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 June 30, 2006	For the Six Months Ended June 30, 2006
Limited partners’ interest in net income	$ 31,262	$ 99,597
Less assumed allocation to incentive distribution rights	-	3,503
Net income available to limited partners	31,262	96,094
Less assumed allocation to subordinated units	7,372	31,378
Net income available to common units	$ 23,890	$ 64,716
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	$ 0.95
Net income per limited partner unit - subordinated units	$ 0.22	$ 0.95

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

As of June 30, 2006 and December 31, 2005 the weighted-average interest rate of the Partnership’s long-term debt was 5.29%.

In June 2006, certain subsidiaries of the Partnership entered into a $400 million unsecured revolving credit facility which amended and restated the previous $200 million facility entered into by Boardwalk Pipelines at the time of the IPO. Under the amended and restated facility, which will continue to be guaranteed by the Partnership, Boardwalk Pipelines, Texas Gas and Gulf South may borrow funds, up to sub-limits. Interest on amounts drawn under the credit facility will be 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 respectively 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 (as defined in the agreement), measured for the preceding twelve months, of not more than five to one. There were no outstanding borrowings against the facility as of June 30, 2006.

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 June 30, 2006, the amount of gas loaned by the Partnership’s subsidiaries was approximately 16 TBtu and, assuming an average market price during June 2006 of $6.20 per MMBtu, the market value of that gas was approximately $99.2 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

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 $4.0 million. During the six months ended June 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 June 30, 2006, no cash contributions had been made for the current year, however, the contribution for 2006 is expected to be $3.5 million.

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

	Pension Benefits For the Three Months Ended June 30,		Other Benefits For the Three Months Ended June 30,
	2006	2005	2006	2005
Service cost	$ 1,075	$ 975	$ 464	$ 519
Interest cost	1,600	1,500	1,582	1,806
Expected return on plan assets	(1,775)	(1,675)	(1,157)	(1,158)
Amortization of prior service cost	-	-	(647)	-
Amortization of accumulated loss	100	-	330	90
Regulatory accrual/amortization	-	(800)	1,354	68
Estimated net periodic benefit cost	$ 1,000	$ -	$ 1,926	$ 1,325

	Pension Benefits For the Six Months Ended June 30,		Other Benefits For the Six Months Ended June 30,
	2006	2005	2006	2005
Service cost	$ 2,150	$ 1,950	$ 1,105	$ 1,038
Interest cost	3,200	3,000	3,526	3,612
Expected return on plan assets	(3,550)	(3,450)	(2,326)	(2,316)
Amortization of prior service cost	-	-	(647)	-
Amortization of accumulated loss	200	-	770	180
Regulatory accrual/amortization	-	(1,500)	3,610	136
Estimated net periodic benefit cost	$ 2,000	$ -	$ 6,038	$ 2,650

Defined Contribution Plans

Subsidiaries of the Partnership maintain defined contribution plans covering substantially all of its employees. Costs related to these plans were $1.3 million and $2.5 million, respectively, for the three and six months ended June 30, 2006 and $1.2 million and $2.4 million, respectively, for the three and six months ended June 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 PBOP beginning January 1, 2007. Under the revised plan, Texas Gas will cap its contributions toward medical benefit coverage for pre-65 retirees 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 second quarter 2006, the change resulted in a reduction of $1.3 million for net periodic benefit cost from the amount that would otherwise have been recognized.

Early Retirement Incentive Program

In May 2006, Texas Gas began implementing an early retirement incentive program (ERIP) 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. For the second quarter 2006, Texas Gas did not recognize any effects of the program in its financial statements due to uncertainty as to which, if any, eligible employees would accept the terms of the program and the resulting inability to quantify the actual financial results of the program. The eligible employees will indicate their intent to participate in the program during the third quarter 2006.

Note 11: Related Parties

Loews has a policy of charging its subsidiary companies for management services provided by Loews. The Partnership recorded $2.4 million and $6.5 million, respectively, for the three and six months ended June 30, 2006 and $2.3 million and $4.0 million, respectively, for the three and six month periods ended June 30, 2005, respectively, for management services.

Note 12: Distributions

On July 31, 2006, the Partnership declared a quarterly distribution of $0.38 per unit, payable on August 18, 2006 to unitholders of record on August 11, 2006, including common and subordinated units and the 2% general partner interest held by its general partner.

On May 19, 2006, the Partnership paid a cash distribution of $0.36 per unit to unitholders of record on May 12, 2006, including common and subordinated units and the 2% general partner interest held by its general partner.

On February 23, 2006, the Partnership paid a cash distribution of $0.1788 per unit. This 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.

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 the 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 experts 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 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%

Due to the seasonal nature of our business, with the highest percentage of earnings typically occurring in the first and fourth quarters of a calendar year, the amount reported for net income per limited partner unit on the Condensed Consolidated Statements of Income for the six month period ended June 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 allocation rights. Assuming a historically seasonal earnings pattern, as the year progresses the impact on the disclosed net income per limited partner unit from the assumed allocation to the general partner’s incentive distribution rights would be reduced in subsequent year-to-date reporting periods from the assumed effect indicated in the first quarter and six-month period ended June 30, 2006 on a stand-alone basis.

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 for the Three Months Ended June 30, 2006 and 2005

Total Operating Revenues increased by $10.4 million, or 9%, to $128.7 million for the three months ended June 30, 2006, compared to $118.3 million for the three months ended June 30, 2005 primarily due to:

·	$6.8 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;

·	$4.7 million increase in storage and parking-and-lending due to favorable natural gas price spreads and volatility in forward gas prices; and

·	$0.8 million increase in fuel retained primarily due to an increase in realized gas prices, including revenues locked in at favorable rates through hedging activities;

·	partially offset by,

·	$1.2 million decrease in revenues for a reduction in the amortization of acquired executory contracts.

Total Operating Costs and Expenses increased by $0.9 million, or 1%, to $82.8 million for the three months ended June 30, 2006, compared to $81.9 million for the three months ended June 30, 2005 primarily due to:

·	$2.0 million increase due to the amortization of a deferred asset related to postretirement benefits other than pensions and pension expense recognition as a result of the settled rate case;

·	$1.1 million increase in costs for transportation of gas on third-party pipelines due to utilization of increased capacity;

·	$0.9 million increase in labor and outside services primarily due to growth in operations;

·	$0.9 million increase in depreciation and amortization due to the increased asset base from additions to plant; and

·	$0.5 million increase in group insurance;

·	partially offset by,

·	$2.9 million decrease related to adjustment of the accrual for hurricane damage, and

·	$1.6 million decrease in company-used gas due to lower natural gas prices.

Total Other (Income) Deductions increased by $0.2 million, or 1%, to $13.7 million for the three months ended June 2006, compared to $13.5 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. The increase for interest expense was partially offset by a $0.5 million gain related to the purchase of operational gas for the East Texas/Mississippi pipeline expansion project included in Miscellaneous Other (Income), net.

Income Taxes and Charge-In-Lieu of Income Taxes decreased by $8.8 million, to $0.2 million for the second quarter 2006, due to the change in tax status and conversion to a limited partnership concurrent with the IPO.

Results of Operations for the Six Months Ended June 30, 2006 and 2005

Total Operating Revenues increased by $34.5 million, or 13%, to $303.1 million for the six months ended June 30, 2006, compared to $268.6 million for the six months ended June 30, 2005 primarily due to:

·	$16.4 million increase in storage and parking-and-lending due to favorable natural gas price spreads and volatility in forward gas prices;

·	$15.7 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

·	$5.2 million increase in fuel retained revenue primarily due to an increase in realized gas prices including revenues locked in at favorable rates through hedging activities;

·	partially offset by,

·	$3.4 million decrease in revenues for a reduction in the amortization of acquired executory contracts.

Total Operating Costs and Expenses increased by $16.9 million, or 11%, to $172.6 million for the six months ended June 30, 2006, compared to $155.7 million for the six months ended June 30, 2005 primarily due to:

$7.5 million increase in operations and maintenance expenses primarily due to increased costs of outside services and materials from high demand for the services, cost of transportation on third-party pipelines due to new contract rates, and an increase in company-used gas due to increased gas prices;

·	$7.0 million increase due to the amortization of a deferred asset related to postretirement benefits other than pensions and pension expense recognition as a result of the settled rate case;

·	$2.6 million increase in corporate overhead; and

·	$2.4 million increase in depreciation and amortization due to the increased asset base from additions to plant;

·	partially offset by,

·	$3.5 million decrease related to adjustment of the accrual for hurricane damage, and

·	$2.5 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 $1.3 million, or 5%, to $28.6 million for the six months ended June 30, 2006, compared to $27.3 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. The increase for interest expense was partially offset by a $0.5 million gain related to the purchase of operational gas for the East Texas/Mississippi pipeline expansion project included in Miscellaneous Other (Income), net.

Income Taxes and Charge-In-Lieu of Income Taxes decreased by $33.8 million, to $0.2 million for the six months ended June 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 for the six months ended June 30, 2006 and 2005 were $51.0 million and $33.0 million, respectively.

For the year ending December 31, 2006, we expect to make capital expenditures of approximately $300 million, of which we expect approximately $55 million to be for maintenance capital and $245 million to be for expansion capital, including approximately $193 million to fund our East Texas/Mississippi pipeline expansion project, discussed below. 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 and our 2006 expansion capital expenditures with borrowings under our revolving credit facility. Thereafter, we expect to fund the balance of the cost of our pipeline expansion projects, with a combination of 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:

Increase in Working Gas at Jackson, Mississippi Gas Storage Facility. In June 2006, Gulf South received the Federal Energy Regulatory Commission (FERC) approval to permanently increase the working gas capacity at the Jackson, Mississippi gas storage facility by 2.4 Bcf, bringing the total working gas capacity at the Jackson gas storage facility to 5.1 Bcf.

Lake Charles, Louisiana Expansion. On March 17, 2006, Gulf South received approval from FERC to purchase an undivided 38.46 percent interest in 1.7 miles of pipeline from Trunkline Gas for $1.9 million. The pipeline connects Trunkline LNG Company, LLC’s liquefied natural gas import terminal in Lake Charles, Louisiana to Gulf South’s pipeline. Gulf South’s ownership interest will be equivalent to 500,000 dekatherms per day. Trunkline Gas will continue to operate the pipeline pursuant to an operating agreement. This transaction was completed March 31, 2006 and the assets were placed in service in April 2006.

Magnolia Storage Expansion. Gulf South has leased a gas storage facility near Napoleonville, Louisiana and is currently developing high-deliverability storage caverns. During recent mining operations, certain issues have arisen causing the mining of the caverns to be temporarily suspended. Gulf South will conduct operational integrity tests on the cavern and associated facilities during the third quarter 2006. If the test results are favorable, we expect the 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, or sale or abandonment of the project. The total book value at June 30, 2006 was $42.2 million. During the second quarter 2006, the Partnership tested 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 was recognized as a result of the recoverability test. Gulf South incurred costs of $0.6 million on this project during the six months ended June 30, 2006, and expects the remaining costs to be approximately $5.0 million, which will be funded by internally generated cash flows.

We are also engaged in discussions with customers and potential partners on several other proposed future expansion projects, which would connect our pipeline system to growing supplies of gas in the Mid-Continent region, and would expand our capacity serving Southeast markets through interconnections with other pipelines. Among these are our previously announced Mid-Continent Pipeline Expansion and the Southeast Expansion. The Mid-Continent Pipeline Expansion is a proposed joint venture that would construct, own and operate a new interstate pipeline which would connect gas supplies originating in North Central Texas, Oklahoma, and Arkansas to a new interconnect with Texas Gas. The Southeast Expansion is a proposed pipeline expansion, which may consist of newly constructed facilities and a lease of third party transportation capacity, which would expand Gulf South’s capacity to deliver gas to Florida markets through interconnects with interstate pipelines serving markets in the Southeast and Northeast. The completion of these projects is subject to risks and uncertainties including market conditions, signing of definitive agreements, obtaining appropriate regulatory approvals, obtaining the necessary financing for the projects and other factors beyond our control.

Distributions

The following distributions were paid from our available cash pursuant to the partnership agreement and were funded by cash from operations.

On July 31, 2006, we declared a quarterly distribution of $0.38 per unit, payable on August 18, 2006 to unitholders of record on August 11, 2006, including common and subordinated units and the 2% general partner interest held by its general partner.

On May 19, 2006, we paid a quarterly distribution in the amount of $0.36 per unit to unitholders of record on May 12, 2006, including common and subordinated units and the 2% general partner interest held by our general partner.

On February 23, 2006, we paid a cash distribution of $0.1788 per unit. This distribution represented a prorated portion of the $0.35 per unit minimum quarterly distribution (as provided in the Partnership’s partnership agreement) for the period from November 15, 2005 through December 31, 2005.

Cost Reduction Program

Texas Gas is implementing a program intended to reduce normal, recurring costs by approximately $15 to $20 million annually. The components of the program include changes to postretirement benefits other than pensions (PBOP) an early retirement incentive program (ERIP), a reduction in the annual cash incentive program and the elimination of the broad-based merit increase pool for 2006. Refer to Note 10 of the Notes to Condensed Consolidated Financial Statements in 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 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.

In June 2006, certain of our subsidiaries entered into a $400 million unsecured revolving credit facility which amended and restated the previous $200 million facility entered into by Boardwalk Pipelines at the time of the IPO. Under the amended and restated facility, which will continue to be guaranteed by us, Boardwalk Pipelines, Texas Gas and Gulf South may borrow funds, up to sub-limits. Interest on amounts drawn under the credit facility will be payable at a floating rate equal to an applicable spread per annum over the London Interbank Offered Rate or a base rate defined as the greater of the prime rate or the Federal funds rate plus 50 basis points. Under the terms of the agreement, each of the borrowers respectively 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 (as defined in the agreement), measured for the preceding twelve months, of not more than five to one. There were no outstanding borrowings against the facility as of June 30, 2006.

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

Net cash provided by operating activities was $136.6 million for the six months ended June 30, 2006, compared to $124.4 million in the comparable period of 2005. The increase of $12.2 million in cash flow from operating activities primarily consisted of:

· $53.2 million increase in net income, excluding non-cash items such as depreciation;

· $41.4 million decrease in the provision for deferred income taxes due to the change in entity structure;

· $20.4 million decrease in cash inflows relative to net changes in non-current assets and liabilities; and

· $20.8 million decrease in cash outflows relative to net changes in working capital items.

Changes in cash flow from investing activities:

Net cash used in investing activities decreased $0.8 million, to $46.7 million for the six month period ended June 30, 2006, from $47.5 million in the comparable 2005 period, which was primarily attributable to:

· $18.0 million increase in capital expenditures of which $8.7 million was used for expansion projects;

· $1.4 million decrease in insurance and other recoveries; and

· $20.2 million decrease in advances to affiliates.

Changes in cash flow from financing activities:

Net cash used in financing activities amounted to $97.8 million for the six months ended June 30, 2006, compared to $43.9 million during the same period in 2005. The increase of $53.9 million was primarily due to:

· $36.5 million primarily due to payment of the balance of a revolving credit facility in February 2006; and

· $6.7 million decrease due to a capital contribution from our parent in 2005; partially offset by

· $10.7 million increase in distributions paid.

Contractual Obligations

The table below is updated for significant changes in lease and capital commitments from those included in the 2005 Form 10-K 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	$ 38.0	$ 3.0	$ 11.9	$ 10.6	$ 12.5
Capital commitments	309.1	271.9	37.2	-	-
Total	$ 347.1	$ 274.9	$ 49.1	$ 10.6	$ 12.5

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/Mississippi pipeline expansion. For further discussion of the East Texas/Mississippi pipeline expansion please read Note 5C Expansion Projects in the Notes to Condensed Consolidated Financial Statements included in Item 1.

The annual funding requirement to the employee benefits retirement plan as a result of the settled rate case is $3.0 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 the 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 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 and operating results;

•

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

•

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

•

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

•

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

•

we may not complete projects, including growth or expansion projects, that we commence, or we may complete projects on materially different terms or timing than anticipated and we may not be able to achieve the intended benefits of any such project, if completed; 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, land owner opposition, the lack of adequate materials or labor 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 market risk is substantially limited to our long-term debt. Total long-term debt at June 30, 2006, had a carrying value of $1.1 billion and a fair value of $1.0 billion. The weighted-average interest rate of our long-term debt was 5.29% at June 30, 2006.

Certain volumes of gas stored underground at Gulf South are available for sale under its tariff and subject to commodity price risk. At June 30, 2006 and December 31, 2005, approximately $9.9 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 Gulf South’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.

We also utilize derivatives to hedge exposures to market price fluctuations related to the value of company-owned storage capacity and, during the second quarter 2006, operational gas purchases for the Gulf South expansion projects. While the changes in the derivatives are expected to, and do, have a high correlation to changes in the anticipated value of the hedged transactions, the derivatives have not been designated as cash flow hedges in accordance with SFAS No. 133. The changes in fair values of the derivatives related to the storage capacity were losses of $0.2 million and $0.1 million, respectively, for the three and six months ended June 30, 2006 and accordingly were recognized currently in earnings as reductions to Gas Storage revenue on the Condensed Consolidated Statements of Income. The derivatives associated with the gas purchases referred to above were settled in April 2006, resulting in the recognition of a $0.5 million gain. The gain was recorded as Miscellaneous Other (Income), net on the Condensed Consolidated Statements of Income.

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 June 30, 2006, the amount of gas loaned out by our subsidiaries was approximately 16 Trillion British thermal units (Tbtu) and, assuming an average market price during June 2006 of $6.20 per million British thermal units (MMBtu), the market value of gas loaned out at June 30, 2006, would have been approximately $99.2 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 June 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.

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.

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 1A. 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.

During the first quarter of 2006, we announced projects to expand pipeline capacity on Gulf South by 1.5 Bcf/day. The new capacity is expected to be in service during the second half of 2007. The total cost of the expansion projects is expected to be approximately $800 million.

These expansion projects involve potential risks, including:

·	the inability to complete the projects on time;

·	actual costs of the projects could be higher than expected;

·	delays in obtaining the requisite regulatory approvals;

·	performance of our business following the expansions does not meet expectations;

·	the inability to timely and effectively integrate the expanded capacities into our operations;

·	diversion of our management's attention from other business concerns;

·	inability or delays in obtaining key materials; and

·	land owner opposition.

Any of these factors could adversely affect our ability to realize the anticipated benefits from the newly expanded capacities. The process of integrating newly expanded assets into our operations may result in unforeseen operating difficulties or unanticipated costs that could have a material adverse effect on our business, financial condition, results of operations and cash flows.

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: August 1, 2006			By:	/s/ Jamie L. Buskill
				Jamie L. Buskill
				Vice President and Chief Financial Officer