Boardwalk Pipeline Partners, LP 10-Q 033107

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 March 31, 2007

OR

o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
  
For the transition period from _______________ to _______________

Commission file number: 01-32665
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
(270) 926-8686
(Address and Telephone Number of Registrant’s Principal Executive Office)


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 Noo


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 x  Non-accelerated filer o

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 April 20, 2007, the registrant had 83,156,122 common units outstanding and 33,093,878 subordinated units outstanding.

1


TABLE OF CONTENTS

FORM 10-Q

MARCH 31, 2007

BOARDWALK PIPELINE PARTNERS, LP


PART I - FINANCIAL INFORMATION
Item 1. Financial Statements................................................................................................................................................................................................3
Condensed Consolidated Balance Sheets....................................................................................................................................................................3
            Condensed Consolidated Statements of Income............................................................................................................................................................5
            Condensed Consolidated Statements of Cash Flows......................................................................................................................................................6
            Condensed Consolidated Statements of Changes in Partners’ Capital..............................................................................................................................7
            Condensed Consolidated Statements of Comprehensive Income......................................................................................................................................8
            Notes to Condensed Consolidated Financial Statements.................................................................................................................................................9
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations..................................................................................................18
Item 3. Quantitative and Qualitative Disclosures About Market Risk.........................................................................................................................................24
Item 4. Controls and Procedures..........................................................................................................................................................................................25
 

 
PART II - OTHER INFORMATION
Item 1. Legal Proceedings....................................................................................................................................................................................................26
Item 2.  Unregistered Sales of Equity Securities and Use of Proceeds...........................................................................................................................................26
Item 6. Exhibits...................................................................................................................................................................................................................27
Signatures........................................................................................................................................................................................................................28




2

PART I - FINANCIAL INFORMATION

Item 1. Financial Statements

 BOARDWALK PIPELINE PARTNERS, LP

CONDENSED CONSOLIDATED BALANCE SHEETS
(Thousands of Dollars)
(Unaudited)


       
ASSETS
  
March 31, 2007
  
December 31, 2006
  
Current Assets:
              
Cash and cash equivalents
  
$
563,179
  
$
399,032
  
Receivables:
              
Trade, net
    
54,011
    
54,082
  
Other
    
9,344
    
12,759
  
Gas Receivables:
              
Transportation and exchange
    
10,518
    
9,115
  
Storage
    
12,498
    
11,704
  
Inventories
    
14,270
    
14,110
  
Costs recoverable from customers
    
7,742
    
11,236
  
Gas stored underground
    
15,108
    
14,001
  
Prepaid expenses and other current assets
    
8,739
    
22,117
  
Total current assets
    
695,409
    
548,156
  
               
Property, Plant and Equipment:
              
Natural gas transmission plant
    
2,176,231
    
1,997,922
  
Other natural gas plant
    
221,330
    
213,926
  
     
2,397,561
    
2,211,848
  
               
Less—Accumulated depreciation and amortization
    
206,353
    
187,412
  
Property, plant and equipment, net
    
2,191,208
    
2,024,436
  
               
Other Assets:
              
Goodwill
    
163,474
    
163,474
  
Gas stored underground
    
139,055
    
161,537
  
Costs recoverable from customers
    
18,198
    
19,767
  
Other
   
29,497
    
33,929
  
Total other assets
    
350,224
    
378,707
  
               
Total Assets
  
$
3,236,841
  
$
2,951,299
  


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

3

BOARDWALK PIPELINE PARTNERS, LP

CONDENSED CONSOLIDATED BALANCE SHEETS
(Thousands of Dollars, except number of units)
(Unaudited)

       
LIABILITIES AND PARTNERS’ CAPITAL
  
March 31, 2007
  
December 31, 2006
  
Current Liabilities:
              
Payables:
              
Trade
  
$
65,462
  
$
56,604
  
Affiliates
    
1,341
    
3,014
  
Other
    
10,629
    
14,459
  
Gas Payables:
              
Transportation and exchange
    
8,996
    
15,485
  
Storage
    
20,934
    
42,127
  
Other accrued taxes
    
17,233
    
16,082
  
Accrued interest
    
18,919
    
19,376
  
Accrued payroll and employee benefits
    
13,388
    
18,198
  
Deferred income
    
12,075
    
22,147
  
Other current liabilities
    
20,530
    
20,926
  
Total current liabilities
    
189,507
    
228,418
  
               
Long -Term Debt
    
1,351,152
    
1,350,920
  
               
Other Liabilities and Deferred Credits:
              
Pension and postretirement benefits
   
16,458
    
15,761
  
Asset retirement obligation
    
14,490
    
14,307
  
Provision for other asset retirement
   
40,228
    
39,644
  
Other
    
33,551
    
29,742
  
Total other liabilities and deferred credits
    
104,727
    
99,454
  
               
Commitments and Contingencies
             
               
Partners’ Capital:
              
Common units - 83,156,122 units and 75,156,122 units issued and outstanding as of March 31, 2007 and December 31, 2006
   
1,253,099
    
941,792
  
Subordinated units - 33,093,878 units issued and outstanding as of March 31, 2007 and December 31, 2006
    
295,628
    
285,543
  
General partner
    
28,702
    
22,060
  
Accumulated other comprehensive income
   
14,026
    
23,112
  
Total partners’ capital
    
1,591,455
    
1,272,507
  
Total Liabilities and Partners’ Capital
  
$
3,236,841
  
$
2,951,299
  


The accompanying notes are an integral part of these condensed consolidated financial statements.
4

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
March 31,
  
   
2007
  
2006
  
Operating Revenues:
              
Gas transportation
  
$
152,913
  
$
151,012
  
Parking and lending
    
18,382
    
13,517
  
Gas storage
    
7,711
    
9,618
  
Other
    
9,106
    
299
  
Total operating revenues
   
188,112
    
174,446
  
               
Operating Costs and Expenses:
              
Operation and maintenance
    
39,459
    
38,327
  
Administrative and general
    
25,792
    
27,388
  
Depreciation and amortization
    
19,915
    
18,683
  
Taxes other than income taxes
    
7,961
    
5,229
  
Net loss on disposal of operating assets and related contracts
    
2,639
    
186
  
Total operating costs and expenses
   
95,766
    
89,813
  
 
              
Operating income
   
92,346
    
84,633
  
               
Other (Income) Deductions:
              
Interest expense
    
16,797
    
15,632
  
Interest income
    
(4,574
)
  
(544
)
Interest income from affiliates, net
   
(7
)
  
-
  
Miscellaneous other income, net
    
(334
)
  
(185
)
Total other (income) deductions
   
11,882
    
14,903
  
               
Income before income taxes
    
80,464
    
69,730
  
               
Income taxes
    
230
    
-
  
               
Net income
  
$
80,234
  
$
69,730
  
               

   
For the Three Months Ended
March 31,
  
   
2007
  
2006
  
Calculation of limited partners’ interest in Net income:
              
Net income
 
$
80,234
  
$
69,730
  
Less general partner’s interest in Net income
    
1,811
    
1,395
  
Limited partners’ interest in Net income
  
$
78,423
  
$
68,335
  
Basic and diluted net income per limited partner unit:
              
Common and subordinated units
  
$
0.61
  
$
0.58
  
Cash distribution to common and subordinated unitholders
  
$
0.415
  
$
0.179
  
Weighted-average number of limited partner units outstanding:
              
Common units
    
75,956,122
    
68,256,122
  
Subordinated units
    
33,093,878
    
33,093,878
  

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

5

BOARDWALK PIPELINE PARTNERS, LP
 

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Thousands of Dollars)
(Unaudited)

   
For the Three Months Ended
March 31,
  
   
2007
  
2006
  
OPERATING ACTIVITIES:
              
Net income
  
$
80,234
  
$
69,730
  
Adjustments to reconcile to cash provided
              
by operations:
              
Depreciation and amortization
    
19,915
    
18,683
  
Amortization of deferred costs
    
1,823
    
2,809
  
Amortization of acquired executory contracts
    
(783
)
  
(1,852
)
Loss on disposal of operating assets
    
2,639
    
186
  
Changes in operating assets and liabilities:
              
Trade and other receivables
   
3,486
    
617
  
Gas receivables and storage assets
    
19,178
    
41,626
  
Costs recoverable from customers
    
3,606
    
1,697
  
Other assets
    
633
    
(1,370
)
Trade and other payables
    
(14,537
)
  
(2,035
)
Gas payables
    
(24,188
)
  
(45,901
)
Accrued liabilities
    
(4,116
)
  
(14,316
)
Other liabilities
    
(10,548
)
  
3,399
  
Net cash provided by operating activities
   
77,342
    
73,273
  
INVESTING ACTIVITIES:
              
Capital expenditures
    
(162,086
)
  
(21,779
)
Proceeds from sale of operating assets
    
429
    
1,417
  
Proceeds from insurance reimbursements and other recoveries
    
-
    
960
  
Advances to affiliates, net
    
662
    
-
  
Net cash used in investing activities
    
(160,995
)
  
(19,402
)
FINANCING ACTIVITIES:
              
Payments of notes payable
    
-
    
(42,100
)
Distributions
   
(46,052
)
  
(18,491
)
Proceeds from sale of common units, net of related transaction costs
    
287,893
    
-
  
Capital contribution from general partner
    
5,959
    
-
  
Net cash provided by (used in) financing activities
    
247,800
    
(60,591
)
Increase (decrease) in cash and cash equivalents
    
164,147
    
(6,720
)
Cash and cash equivalents at beginning of period
    
399,032
    
65,792
  
Cash and cash equivalents at end of period
  
$
563,179
  
$
59,072
  

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


6

BOARDWALK PIPELINE PARTNERS, LP

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN PARTNERS’ CAPITAL
(Thousands of Dollars, except units)
(Unaudited)

   
Common
Units
  
Subordinated Units
 
General Partner
  
Accumulated Other Comprehensive (Loss) Income
  
Total Partners’ Capital
  
Balance, January 1, 2006
  
$
705,609
  
$
266,578
  
$
16,661
  
$
(174
)
$
988,674
  
Add (deduct):
                                
Net income
    
46,022
    
22,313
    
1,395
    
-
    
69,730
  
Distributions paid
   
(12,204
)
  
(5,917
)
  
(370
)
  
-
    
(18,491
)
Other comprehensive income
   
-
    
-
    
-
    
4,226
    
4,226
  
Transaction costs related to sale of common units
    
(14
)
  
-
    
-
    
-
    
(14
)
Balance, March 31, 2006
  
$
739,413
  
$
282,974
  
$
17,686
  
$
4,052
  
$
1,044,125
  


 
Balance, January 1, 2007
  
$
941,792
  
$
285,543
  
$
22,060
  
$
23,112
  
$
1,272,507
  
Add (deduct):
                                
Net income
    
54,604
    
23,819
    
1,811
    
-
    
80,234
  
Distributions paid
   
(31,190
)
  
(13,734
)
  
(1,128
)
  
-
    
(46,052
)
Other comprehensive income
   
-
    
-
    
-
    
(9,086
)
  
(9,086
)
Sale of common units, net of related transaction costs (8,000,000 units)
    
287,893
    
-
    
-
    
-
    
287,893
  
Capital contribution from general partner
    
-
    
-
    
5,959
    
-
    
5,959
  
Balance, March 31, 2007
  
$
1,253,099
  
$
295,628
  
$
28,702
  
$
14,026
  
$
1,591,455
  

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



7

BOARDWALK PIPELINE PARTNERS, LP


CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Thousands of Dollars)
(Unaudited) 


   
For the Three Months Ended
March 31,
  
   
2007
  
2006
  
Net income
  
$
80,234
  
$
69,730
  
Other comprehensive income:
              
(Loss) gain on cash flow hedges
    
(7,537
)
  
7,018
  
Reclassification adjustment transferred to Net income
    
(1,549
)
  
(2,792
)
Total comprehensive income
  
$
71,148
  
$
73,956
  
 
The accompanying notes are an integral part of these condensed consolidated financial statements.


8


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 to own and operate the business conducted by Boardwalk Pipelines, LP (Boardwalk Pipelines) and its subsidiaries, Gulf South Pipeline Company, LP (Gulf South) and Texas Gas Transmission, LLC (Texas Gas) (together, the operating subsidiaries). The Partnership is a 74.8% owned subsidiary of Boardwalk Pipelines Holding Corp. (BPHC), which is wholly owned by Loews Corporation (Loews).

The accompanying unaudited condensed consolidated financial statements of the Partnership were prepared pursuant to the rules and regulations of the United States Securities and Exchange Commission (SEC). Certain information and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America (GAAP) have been condensed or omitted pursuant to such rules and regulations. In the opinion of management, the accompanying condensed consolidated financial statements reflect all adjustments (consisting of only normal recurring accruals) necessary to present fairly the financial position as of March 31, 2007 and December 31, 2006, and the results of operations and changes in cash flow for the three months ended March 31, 2007 and 2006. Reference is made to the Notes to Consolidated Financial Statements in the 2006 Annual Report on Form 10-K, which should be read in conjunction with these unaudited condensed consolidated financial statements. The accounting policies described in Note 2 to the Consolidated Financial Statements included in such Annual Report on Form 10-K are the same used in preparing the accompanying 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 2006 financial statements to conform to the 2007 presentation, primarily related to individual amounts and captions within the Operating Activities section of the Condensed Consolidated Statements of Cash Flows.
 
 
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 the method of storage accounting elected by Texas Gas and the 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 reflected in Gas Payables on the Condensed Consolidated Balance Sheets and is valued at a historical cost of gas of $21.9 million and $45.7 million at March 31, 2007 and December 31, 2006. Due to the method of storage accounting elected by Gulf South, the Partnership does not reflect volumes held by Gulf South on behalf of others on its Condensed Consolidated Balance Sheets. As of March 31, 2007 and December 31, 2006, Gulf South held 44.4 trillion British thermal units (TBtu) and 61.0 TBtu of gas owned by shippers. No gas was loaned by Gulf South to shippers as of March 31, 2007 and December 31, 2006.


Note 3: Derivative Financial Instruments

Subsidiaries of the Partnership use futures, swaps, and option contracts (collectively, derivatives) to hedge exposure to various risks, including natural gas commodity risk and interest rate risk. These hedge contracts are reported at fair value in accordance with Statement of Financial Accounting Standards (SFAS) No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended. The related unrealized gains and losses resulting from changes in fair values of the derivatives contracts designated as cash flow hedges are deferred as a component of Accumulated other comprehensive income. The deferred gains and losses are recognized in the Condensed Consolidated Statements of Income when the hedged anticipated transactions affect earnings.

Certain volumes of gas stored underground are available for sale and subject to commodity price risk. At March 31, 2007 and December 31, 2006, approximately $15.1 million and $14.0 million, of Gulf South's gas stored underground, which the Partnership owns and carries as current Gas stored underground, is exposed to commodity price risk. Gulf South utilizes derivatives to hedge certain exposures to market price fluctuations on the anticipated operational sales of gas.

9
As a result of the Texas Gas Western Kentucky storage expansion project, approximately 4.8 billion cubic feet (Bcf) of gas stored underground with a book value of $11.3 million is available for sale. Approximately 3.0 Bcf of this gas is subject to forward sales agreements under which the ultimate sales price was determined in March 2007, based on the price of New York Mercantile Exchange (NYMEX) natural gas futures. Texas Gas entered into derivatives to hedge the price exposure related to the storage gas. The derivatives associated with the volumes subject to forward sales agreements were designated as cash flow hedges during February 2007, concurrent with the designation of the forward sales agreements as normal sales. Prior to the designation, these derivatives were marked to fair value through earnings along with the related forward sales agreements, resulting in a loss of $0.1 million in the first quarter 2007. The derivatives related to the remaining 1.8 Bcf of storage gas were also marked to fair value through earnings resulting in a loss of $2.0 million in the first quarter 2007.

With the exception of the storage gas volumes referred to above, the derivatives related to the sale of natural gas and cash for fuel reimbursement generally qualify for cash flow hedge accounting under SFAS No. 133 and are designated as such. Generally, for gas sales and cash for fuel reimbursement, any gains and losses on the related derivatives would be recognized in Operating Revenues.  For the sale of gas related to the Western Kentucky storage expansion project, any gains and losses on the related derivatives would be recognized in Net loss on disposal of operating assets and related contracts.

In August 2006, the Partnership entered into Treasury rate locks with two counterparties each for a notional amount of $100.0 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 rate locks are 5.00% and 4.96%. Under the terms of the rate locks, the counterparties would pay the Partnership settlement amounts if the 10-year Treasury rate is greater than the reference rates on August 1, 2007. Conversely, the Partnership would pay the counterparties settlement amounts if the 10-year Treasury rate is less than the reference rates. The Treasury rate locks were designated as cash flow hedges in accordance with SFAS No. 133. As of March 31, 2007, the Partnership reported a liability of $5.0 million, and a reduction in Accumulated other comprehensive income in an equal and offsetting amount less ineffectiveness recognized in 2007 of less than $0.1 million, for the fair values of the rate locks.

The fair values of derivatives existing as of March 31, 2007 and December 31, 2006, were included in the following captions in the Condensed Consolidated Balance Sheets (in millions):

 
  
March 31, 2007
  
December 31, 2006
  
Prepaid expenses and other current assets
  
$
2.3
  
$
13.7
  
Other current liabilities
    
8.1
    
5.1
  
Accumulated other comprehensive (loss) income
    
(2.2
)
  
8.5
  

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. 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 transactions, the ineffective portion of the hedge contracts is currently recognized in earnings. If the anticipated transactions are deemed no longer probable to occur, hedge accounting would be terminated and changes in the fair values of the associated derivative financial instruments would be recognized currently in the Condensed Consolidated Statements of Income.  Ineffectiveness recorded during the three month periods ended March 31, 2007 and 2006 was $0.4 million favorable and $0.5 million unfavorable. No cash flow hedges were discontinued during the three month periods ended March 31, 2007 and 2006. 


Note 4: Income Taxes

The Partnership is not a taxable entity for federal income tax purposes. As such, it 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 federal income tax returns of each partner. The aggregate difference in the basis of the Partnership’s net assets for financial and income tax purposes cannot be readily determined as it does not have access to the information about each partner’s tax attributes related to the Partnership. The Partnership’s subsidiaries directly incur some income-based state taxes which are presented in Income taxes on the Condensed Consolidated Statements of Income.




10


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 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.
 
In the fourth quarter 2006, the Partnership recognized a receivable of $4.6 million associated with insurance claims deemed probable of recovery. Of this amount, approximately $0.5 million was received during the first quarter 2007. During the first quarter 2006, the Partnership accrued additional expenses of $2.1 million and recognized $2.7 million of insurance proceeds related to Hurricane Katrina, which were received in the fourth quarter 2006. Through March 31, 2007, the Partnership has received approximately $6.5 million in insurance proceeds related to the hurricanes. As of March 31, 2007 and December 31, 2006, the remaining liability for both hurricanes was $0.8 million and $1.0 million.

B. Legal 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. Several actions have been filed against Gulf South and other defendants by local residents and businesses as well as the lessor of the property; seeking monetary damages. 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 remain 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.

The remediation work related to the incident was completed in November 2006. Gulf South incurred $7.3 million for remediation costs, root cause investigation and legal fees. Gulf South has made demand for reimbursement from its insurance carriers and will continue to pursue recoveries of the costs incurred, 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. Through March 31, 2007, Gulf South has received $0.8 million of insurance reimbursements for legal expenses and root cause investigation.

Other Legal Matters
 
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

East Texas to Mississippi 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 Partnership’s 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 project is supported by binding precedent agreements with customers who have contracted, on a long-term basis (with a weighted average term of approximately 7 years), for 1.3 Bcf per day from Carthage, Texas with an option for an additional 100 million cubic feet (MMcf) per day. On September 1, 2006, the Partnership filed a certificate application relating to this project with the Federal Energy Regulatory Commission (FERC). The Partnership expects this project to be in service during the fall of 2007.

11
Gulf Crossing Project. The Partnership is pursuing construction of a new interstate pipeline that will begin near Sherman, Texas and proceed to the Perryville, Louisiana area. The project will be owned by a new subsidiary, Gulf Crossing Pipeline Company LLC (Gulf Crossing), and will consist of approximately 355 miles of 42-inch pipeline having capacity of up to approximately 1.6 Bcf per day. Additionally, Gulf Crossing will enter into: (i) a lease for at least 1.1 Bcf per day of capacity on the Partnership’s Gulf South pipeline system (including on the Southeast Expansion and a portion of the East Texas to Mississippi Expansion) to make deliveries to an interconnect with Transcontinental Pipe Line Company (Transco) in Choctaw County, Alabama; and (ii) a lease with a third-party intrastate pipeline which will bring certain gas supplies to the Partnership’s system. This project is supported by binding agreements with customers who have contracted for 1.1 Bcf per day of capacity under firm contracts having terms of 5 to 10 years (with a weighted average term of approximately 9.8 years), and options with certain of these customers for an additional 350 MMcf per day of capacity. The Partnership anticipates making the required filings with the FERC by July 2007 and for the project to be in service during the fourth quarter 2008. The Partnership continues to engage in negotiations with one of the foundation shippers supporting this project concerning the possible purchase of up to a 49.0% equity interest in Gulf Crossing.

Southeast Expansion. The Partnership is pursuing a pipeline expansion extending its Gulf South pipeline system from near Harrisville, Mississippi to an interconnect with Transco in Choctaw County, Alabama which will enhance its ability to deliver gas to the Northeast through other pipeline interconnects. This expansion will consist of approximately 112 miles of 42-inch pipeline having initial capacity of approximately 1.2 Bcf per day, expandable to as much as 2.0 Bcf per day to accommodate volumes expected to come from the Gulf Crossing leased capacity discussed above. In addition, Gulf South has executed a lease with Destin Pipeline Company to access markets in Florida. This project is supported by binding agreements with customers who have contracted for 660 MMcf per day of capacity under firm contracts having terms of 5 to 10 years (with a weighted-average term of 8.7 years), as well as the capacity leased to Gulf Crossing discussed above. The certificate filing was made with the FERC in December 2006 and the project is anticipated to be in service during the first quarter 2008. The FERC issued a draft environmental impact statement for the expansion project on April 13, 2007.
 
Fayetteville Shale. The Partnership is pursuing the construction of two laterals connected to the Partnership’s pipeline system to transport gas from the Fayetteville Shale area in Arkansas to markets directly and indirectly served by the Partnership’s pipelines. The Fayetteville Lateral, consisting of approximately 165 miles of 36-inch pipeline, is anticipated to have an initial design capacity of 800 MMcf per day. This lateral will originate in Conway County, Arkansas and proceed southeast through the Bald Knob, Arkansas area to an interconnect with the Partnership’s mainline in Coahoma County, Mississippi. The Greenville Lateral, consisting of approximately 95 miles of pipeline with an initial design capacity of 750 MMcf per day, will originate at the Partnership’s mainline near Greenville, Mississippi and proceed east to the Kosciusko, Mississippi area. The Greenville Lateral will allow customers to access additional markets, primarily in the Midwest, Northeast and Southeast. Construction of both laterals is supported by a binding precedent agreement with Southwestern Energy Services Company, a wholly-owned subsidiary of Southwestern Energy Company. In December 2006, the Partnership initiated the pre-filing process with FERC for this project and anticipate making the required certificate filings with the FERC by July 2007. The Partnership expects the project to be in service during the first quarter 2009.

The total cost of the pipeline expansion projects discussed above, before taking into account any potential equity contribution by the foundation shipper in Gulf Crossing or the exercise of customer options for additional capacity also discussed above, is estimated to be approximately $3.4 billion. The actual cost to complete these projects may exceed the current estimate as a result of, among other things, higher labor and materials costs due to the large number of pipeline projects under way throughout the industry, the need to expand pipeline capacity if the Partnership contracts for additional volumes, including as a result of option exercises, or design modifications.  For example, the cost estimate set forth above reflects the Partnership’s recent decision to increase the pipeline diameter for a portion of the Fayetteville Shale project to provide additional operational flexibility on that line.

Western Kentucky Storage Expansion. In December 2006, the FERC issued a certificate approving the Phase II storage expansion project which will expand the working gas capacity in the Partnership’s western Kentucky storage complex by approximately 9.0 Bcf. This project is supported by binding commitments from customers to contract on a long-term basis for the full additional capacity at Texas Gas’ maximum applicable rate. The Partnership expects this project to cost approximately $40.7 million and to be in service by November 2007. In December 2006, Texas Gas commenced an open season related to a potential third expansion of its storage facilities and has signed one precedent agreement for 2.0 Bcf of storage capacity. The Phase III storage expansion is subject to the FERC approvals, including potential market-based rate authority for the additional new storage capacity being created.

Magnolia Storage Facility. The Partnership is currently developing an additional storage cavern near Napoleonville, Louisiana. During mining operations, certain issues arose causing the mining of the cavern to be suspended. Operational integrity tests on the caverns are under way. Assuming favorable testing results, the Partnership expects the storage facilities to be in service perhaps as early as mid-2008 with working gas capacity of approximately 2.0 Bcf, reduced from the original design capacity of 6.0 Bcf. The total book value of the project at March 31, 2007 and December 31, 2006 was $43.7 million and $42.7 million, respectively. The Partnership has 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 has been recognized as a result of the testing.



12


Pipeline Integrity

  The Office of Pipeline Safety (OPS) has issued a final rule that requires natural gas pipeline operators to develop integrity management programs. Pursuant to the rule, pipelines were required to identify high consequence areas (HCAs) on their systems and develop a written integrity management program providing for a baseline assessment and periodic reassessments to be completed within specified timeframes. The Partnership has complied with these requirements. Its estimated costs to comply with the rule during the initial ten-year baseline period ending in 2012 range from $105.0 to $125.0 million. As of March 31, 2007, the Partnership has invested approximately $22.4 million to develop and implement integrity management programs that allow it to dynamically assess various pipeline risks on an integrated basis. The Partnership has systematically used smart, in-line inspection tools to verify the integrity of certain of its pipelines. 
 

D. Environmental and Safety Matters

The operating subsidiaries are subject to federal, state and local environmental laws and regulations in connection with the operation and remediation of various operating sites. The Partnership accrues for environmental expenses resulting from existing conditions that relate to past operations when the costs are probable and can be reasonably estimated. In addition to federal and state mandated remediation requirements, the Partnership often enters into voluntary remediation programs with the agencies.

As of March 31, 2007 and December 31, 2006, the Partnership had an accrued liability of approximately $18.0 million and $18.4 million related to assessment and/or remediation costs associated with the historical use of polychlorinated biphenyls, petroleum hydrocarbons and mercury, enhancement of groundwater protection measures and other costs. These costs are expected to occur over approximately the next seven years. The accrual represents management’s estimate of the undiscounted future obligations based on evaluations and discussions with counsel and independent consultants and the current facts and circumstances related to these matters. As of March 31, 2007 and December 31, 2006, approximately $3.5 million was recorded in Other current liabilities. As of March 31, 2007 and December 31, 2006, approximately $14.5 million and $14.9 million was recorded in Other Liabilities and Deferred Credits.

On October 20, 2006, Texas Gas received notice from the Environmental Protection Agency (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.

The Partnership’s pipelines are subject to the Clean Air Act (CAA) and the CAA Amendments of 1990 (Amendments) which added significant provisions to the CAA. The Amendments require the EPA to promulgate new regulations pertaining to mobile sources, air toxins, areas of ozone non-attainment and acid rain. The Partnership operates two facilities in areas affected by non-attainment requirements for the current ozone standard (eight-hour standard). As of March 31, 2007, the Partnership had incurred costs of approximately $14.1 million for emission control modifications of compression equipment located at facilities required to comply with current CAA provisions, the Amendments and state implementation plans for nitrogen oxide reductions. These costs are being recorded as additions to property, plant and equipment (PPE) as the modifications are added. If the EPA designates additional new non-attainment areas where the Partnership operates, the cost of additions to PPE is expected to increase, however the Partnership is unable at this time to estimate with any certainty the cost of any additions that may be required.
 
The Partnership considers environmental assessment, remediation costs, and costs associated with compliance with environmental standards to be recoverable through base rates, as they are prudent costs incurred in the ordinary course of business and, therefore, no regulatory asset has been recorded to defer these costs. The actual costs incurred will depend on the actual amount and extent of contamination discovered, the final cleanup standards mandated by the EPA or other governmental authorities and other factors.







13




E. Commitments for Construction

The Partnership’s future capital commitments as of March 31, 2007, for contracts already authorized are expected to approximate the following amounts (in millions):

Less than 1 year
  
$
547.7
  
1-3 years
    
231.1
  
4-5 years
    
-
  
More than 5 years
    
-
  
Total
 
$
778.8
  

The construction work in progress included in PPE, net in the Condensed Consolidated Balance Sheets was $369.2 million and $205.1 million as of March 31, 2007 and December 31, 2006.


Note 6: Net Income per Limited Partner Unit and Cash Distributions

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 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:

 
 
 
 
 
 
 
 
 
 
  
Total Quarterly Distribution
  
Marginal Percentage Interest in
Distributions
  
Target Amount
Common and
Subordinated
Unitholders
 
 
 
 
 
General Partner
Minimum Quarterly Distribution
  
$0.3500
  
98%
2%
First Target Distribution
  
up to $0.4025
  
98%
2%
Second Target Distribution
  
Above $0.4025 up to $0.4375
  
85%
15%
Third Target Distribution
  
Above $0.4375 up to $0.5250
  
75%
25%
Thereafter
  
above $0.5250
  
50%
50%


The amounts reported for net income per limited partner unit on the Condensed Consolidated Statements of Income for the three month periods ended March 31, 2007 and 2006, were reduced to take into account an assumed allocation to the general partner's incentive distribution rights. Payments made on account of the incentive distribution rights are determined in relation to actual declared distributions and not based on the assumed allocation required by EITF No. 03-6.  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 (in thousands, except weighted average units and per unit data):


   
For the Three Months Ended
March 31,
  
   
2007
  
2006
  
Limited partners' interest in net income
  
$
78,423
  
$
68,335
  
Less assumed allocation to incentive distribution rights
    
12,055
    
9,073
  
Net income available to limited partners
  
$
66,368
  
$
59,262
  
Less assumed allocation to subordinated units
    
20,141
    
19,351
  
Net income available to common units
  
$
46,227
  
$
39,911
  
Weighted average common units
    
75,956,122
    
68,256,122
  
Weighted average subordinated units
    
33,093,878
    
33,093,878
  
Net income per limited partner unit - common and subordinated units
  
$
0.61
  
$
0.58
  

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Note 7: Financing

In April 2007, the Partnership’s revolving credit facility was amended to increase the aggregate commitments from $400.0 million to $700.0 million and to extend the term to June 29, 2012, among other modifications. As of March 31, 2007 and December 31, 2006, no funds were drawn under the facility. During April 2007, the Partnership issued letters of credit for $221.5 million to support certain obligations associated with the Fayetteville Shale expansion project which reduced the available capacity under the facility.

In March 2007, the Partnership completed a public offering of 8.0 million of its common units at a price of $36.50 per unit. The Partnership received proceeds of approximately $293.9 million, net of underwriting discounts and offering expenses, and including approximately $6.0 million from the general partner to maintain its 2.0% general partner interest. After the offering, the Partnership has 83.2 million common units issued and outstanding, of which 29.9 million are held by the public. The balance of the common units and all of the subordinated units are held by BPHC.

As of March 31, 2007 and December 31, 2006 the weighted average interest rate of the Partnership’s long-term debt was 5.41%. The Partnership was in compliance with all loan covenants at March 31, 2007.

During the three months ended March 31, 2007 and 2006, the Partnership capitalized interest of $2.1 million and less than $0.1 million.  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 $0.4 million and $0.2 million of AFUDC for the three months ended March 31, 2007 and 2006.


Note 8: 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 March 31, 2007, the amount of gas loaned out by the Partnership’s subsidiaries was approximately 36.9 TBtu and, assuming an average market price during March 2007 of $7.07 per million British thermal units (MMBtu), the market value of gas loaned out at March 31, 2007 would have been approximately $260.9 million. If any significant customer of the Partnership should have credit or financial problems resulting in a delay or failure to repay the gas they owe to it this could have a material adverse effect on the Partnership’s financial condition, results of operations and cash flows.


Note 9: Employee Benefits

Substantially all of Texas Gas' employees are covered under a non-contributory, defined benefit pension plan. Additionally, the Texas Gas Supplemental Retirement Plan provides pension benefits for the portion of an eligible employee’s pension benefit that becomes subject to compensation limitations under the Internal Revenue Code (IRC). Effective in November 2006, the defined benefit retirement plan was closed to new participants and new employees will be provided benefits under a defined contribution money purchase plan. All Gulf South employees are provided retirement benefits under a similar defined contribution money purchase plan. Texas Gas also provides postretirement life insurance and postretirement health care benefits to certain retired employees. The Partnership uses a measurement date of December 31 for its benefits plans.


Early Retirement Incentive Program

In 2006, Texas Gas implemented an early retirement incentive program (ERIP) which was made available to approximately 240 eligible non-executive employees. Retirements under the program were generally effective January 1, 2007. Approximately 100 of the eligible employees elected to participate in the program. In the first quarter 2007, the Partnership recognized a pension settlement charge related to the ERIP of approximately $3.1 million which was recorded in Administrative and general expense.



15


Components of Net Periodic Benefit Cost

Components of net periodic benefit cost for both the retirement plans and post retirement benefits other than pensions (PBOP) for the years ended March 31, 2007 and 2006 were the following (in thousands): 

 
   
Retirement Plans
  
PBOP
  
   
For the Year Ended March 31,
  
For the Year Ended March 31,
  
   
2007
  
2006
  
2007
  
2006
  
Service cost
  
$
930
  
$
1,079
  
$
155
  
$
641
  
Interest cost
    
1,682
    
1,614
    
900
    
1,944
  
Expected return on plan assets
    
(1,885
)
  
(1,775
)
  
(1,168
)
  
(1,169
)
Amortization of prior service credit
    
1
    
-
    
(1,940
)
  
-
  
Amortization of unrecognized net loss
    
77
    
100
    
298
    
440
  
Settlement charge (ERIP)
    
3,100
    
-
    
-
    
-
  
Regulatory asset decrease
    
-
    
250
    
1,354
    
3,266
  
Net periodic pension expense
  
$
3,905
  
$
1,268
  
$
(401
)
$
5,122
  

The decrease in the regulatory asset for PBOP is due primarily to the amortization of costs incurred in prior years.


Defined Contribution Plans

The Partnership maintains defined contribution plans covering substantially all of its employees. Costs related to these plans were $1.2 million for each of the three months ended March 31, 2007 and 2006.


Note 10: Related Parties

Loews provides a variety of corporate services to the Partnership and its subsidiaries under services agreements. Services provided by Loews include, among others, information technology, tax, risk management, internal audit and corporate development services. Loews charged $4.2 million and $4.1 million for the three months ended March 31, 2007 and 2006, respectively, to the Partnership based on the actual time spent by Loews personnel performing these services, plus related expenses.
 
Distributions paid on common and subordinated units held by BPHC and the 2.0% general partner interest and incentive distribution rights held by Boardwalk GP, LP were $37.0 million and $15.8 million during the first quarter 2007 and 2006. In addition, as a result of the public offering of common units in March 2007, the general partner contributed approximately $6.0 million to maintain its general partner interest.


Note 11: Distributions

The Partnership has declared quarterly distributions per unit to unitholders of record, including common and subordinated units and the 2.0% general partner interest held by its general partner as follows:

Record Date
  
Payable Date
  
Distribution per Unit
May 7, 2007
  
May 14, 2007
  
0.43
February 20, 2007
  
February 27, 2007
  
0.415
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
  
0.179*

*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 November 15, 2005 through December 31, 2005.

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The Partnership also pays cash distributions to its general partner on account of its incentive distribution rights with respect to that portion of a quarterly distribution in excess of $0.4025 per unit. These payments were $0.2 million in February 2007 and will be $0.5 million in May 2007.


Note 12: Accumulated Other Comprehensive Income

The following table shows the components of Accumulated other comprehensive income at March 31, 2007 and December 31, 2006 (in thousands):

   
As of March 31, 2007
  
As of December 31, 2006
  
(Loss) gain on cash flow hedges
  
$
(2,197
)
$
8,309
  
Deferred components of net periodic benefit cost
    
16,223
    
14,803
  
Total Accumulated other comprehensive income
  
$
14,026
  
$
23,112
  


Note 13: Guarantee of Securities of Subsidiaries

The Partnership has no independent assets or operations other than its investment in its subsidiaries. The Partnership’s operating subsidiaries have issued securities which have all been fully and unconditionally guaranteed by the Partnership. The Partnership does have separate partners’ capital including publicly traded limited partner common units.

The Partnership’s subsidiaries have no significant restrictions on their ability to pay distributions or loans to the Partnership and have no restricted assets at March 31, 2007.


Note 14: Recently Issued Accounting Pronouncements

SFAS No. 157

On September 15, 2006, the Financial Accounting Standards Board (FASB) issued SFAS No. 157, Fair Value Measurements. 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 condition, results of operations or cash flows.


SFAS No. 159

In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities- including an amendment of SFAS No. 115. SFAS No. 159 allows companies to elect to measure many financial assets and financial liabilities at fair value. Unrealized gains and losses on items for which the fair value option has been chosen are reported in earnings. SFAS No. 159 is effective for fiscal years beginning after November 15, 2007. The Partnership is currently evaluating the impact, if any, of adopting SFAS No. 159 on its financial condition, results of operations or cash flows.

17


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

The following discussion and analysis of financial condition and results of operations should be read in conjunction with our accompanying interim condensed consolidated financial statements and related Notes, included elsewhere in this report and prepared in accordance with accounting principles generally accepted in the United States of America (GAAP) and our consolidated financial statements, related notes, management's discussion and analysis of financial condition and results of operations and Risk Factors included in our Annual Report on Form 10-K for the year ended December 31, 2006.

We are a Delaware limited partnership formed to own and operate the business conducted by Boardwalk Pipelines, LP (Boardwalk Pipelines) and its subsidiaries, Gulf South Pipeline Company, LP (Gulf South) and Texas Gas Transmission, LLC (Texas Gas) (together, the operating subsidiaries). We own and operate pipeline systems in the Gulf Coast states of Texas, Louisiana, Mississippi, Alabama, and Florida and which extend northward through Arkansas to the Midwestern states of Tennessee, Kentucky, Illinois, Indiana, and Ohio.

 
Results of Operations - Business Overview
 
We derive our 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. Our Gulf South subsidiary is authorized to charge market-based rates for its firm and interruptible storage services.

We are not in the business of buying and selling natural gas other than for system management and operational purposes, but changes in the price of natural gas can affect the overall supply and demand of natural gas which in turn does affect our results of operations. We deliver to a broad mix of customers including local distribution companies (LDCs), municipalities, interstate and intrastate pipelines, direct industrial users, electric power generation plants, marketers and producers. In addition to serving directly connected markets, our pipeline systems have indirect market access to the northeastern and southeastern United States through interconnections with unaffiliated pipelines.

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 a firm service contract (including no-notice storage service) are generally consistent during the contract term, but can be higher in winter peak periods, especially related to no-notice storage agreements, than in off-peak periods. 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 services 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.



18



 
Results of Operations for the Three Months Ended March 31, 2007 and 2006

Our net income for the first quarter 2007 increased $10.5 million or 15.1% from the comparable 2006 period.  The primary drivers for the increase were higher revenues from pipeline system expansion, strong demand for firm transportation services and increased utilization, and a continued strong environment for PAL and storage services. 

Operating revenues for the first quarter 2007 increased $13.7 million, or 7.9%, to $188.1 million, compared to $174.4 million for the first quarter 2006 primarily due to:

·  
$5.9 million increase in transportation fees due to revenues from the Carthage, Texas to Keatchie, Louisiana pipeline expansion project which was placed in service at the end of 2006, strong demand for firm transportation services due to wide natural gas basis differentials primarily between South and East Texas and other points on our system, and increased utilization;
·  
$5.9 million increase in operating revenues driven primarily from higher fuel revenues from increased throughput and retained volumes; and
·  
$3.0 million increase in PAL and storage services mainly due to favorable natural gas price spreads and volatility in forward natural gas prices.

These increases were partly offset by:

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

Operating expenses for the first quarter 2007 increased $6.0 million, or 6.7%, to $95.8 million, compared to $89.8 million for the first quarter 2006 primarily due to:

·  
$3.1 million pension settlement charge related to the early retirement incentive program (ERIP);
·  
$2.8 million increase in property and other taxes resulting primarily as a result of a reversal of a franchise tax accrual in the 2006 period;
·  
$2.1 million loss on mark-to-market adjustment associated with derivatives on storage gas volumes;
·  
$1.6 million increase in administrative expenses and outside services mainly due to growth in operations and regulatory compliance; and
·  
$1.2 million increase in depreciation and amortization resulting primarily from increased property, plant and equipment.

These increases were partly offset by:

·  
a $5.5 million decline in PBOP costs primarily as a result of plan changes in the second half of 2006.

Total other deductions for the first quarter 2007 declined by $3.0 million, or 20.1%, to $11.9 million, compared to $14.9 million for the first quarter 2006. The decline is primarily due to an increase in interest income of $4.0 million as a result of higher levels of cash invested, partially offset by higher interest expense of $1.2 million driven by increased levels of outstanding long-term debt.


Capital Expenditures

Capital expenditures for the three months ended March 31, 2007 and 2006 were $162.1 million and $21.8 million. For the year ending December 31, 2007, we expect to make capital expenditures of approximately $1.9 billion, of which we expect approximately $1.8 billion to be for the expansion projects discussed below and approximately $60.0 million to be for maintenance capital. The amount of expansion capital we expend in 2007 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 expect to fund our expansion capital expenditures for 2007 and beyond with proceeds from sales of our debt and equity securities, borrowings under our revolving credit facility and operating cash flows, though we have not made any determination with regard to such financing. We expect to fund our maintenance capital expenditures from operating cash flows.
 
19
We are currently engaged in the following expansion projects:

·  
East Texas to Mississippi 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 billion cubic feet (Bcf) per day of new transmission capacity to our 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 project is supported by binding precedent agreements with customers who have contracted, on a long-term basis (with a weighted average term of approximately 7 years), for 1.3 Bcf per day from Carthage, Texas with an option for an additional 100 million cubic feet (MMcf) per day. On September 1, 2006, we filed a certificate application relating to this project with the FERC. We expect this project to be in service during the fall of 2007.

·  
Gulf Crossing Project. We are pursuing construction of a new interstate pipeline that will begin near Sherman, Texas and proceed to the Perryville, Louisiana area. The project will be owned by a new subsidiary, Gulf Crossing Pipeline Company LLC (Gulf Crossing), and will consist of approximately 355 miles of 42-inch pipeline having capacity of up to approximately 1.6 Bcf per day. Additionally, Gulf Crossing will enter into: (i) a lease for at least 1.1 Bcf per day of capacity on our Gulf South pipeline system (including on the Southeast Expansion and a portion of the East Texas to Mississippi Expansion) to make deliveries to an interconnect with Transcontinental Pipe Line Company (Transco) in Choctaw County, Alabama; and (ii) a lease with a third-party intrastate pipeline which will bring certain gas supplies to our system. This project is supported by binding agreements with customers who have contracted for 1.1 Bcf per day of capacity under firm contracts having terms of 5 to 10 years (with a weighted average term of approximately 9.8 years), and options with certain of these customers for an additional 350 MMcf per day of capacity. We anticipate making the required filings with the FERC by July 2007 and for the project to be in service during the fourth quarter 2008. We continue to engage in negotiations with one of the foundation shippers supporting this project concerning the possible purchase of up to a 49.0% equity interest in Gulf Crossing.

·  
Southeast Expansion. We are pursuing a pipeline expansion extending our Gulf South pipeline system from near Harrisville, Mississippi to an interconnect with Transco in Choctaw County, Alabama which will enhance our ability to deliver gas to the Northeast through other pipeline interconnects. This expansion will consist of approximately 112 miles of 42-inch pipeline having initial capacity of approximately 1.2 Bcf per day, expandable to as much as 2.0 Bcf per day to accommodate volumes expected to come from the Gulf Crossing leased capacity discussed above. In addition, Gulf South has executed a lease with Destin Pipeline Company to access markets in Florida. This project is supported by binding agreements with customers who have contracted for 660 MMcf per day of capacity under firm contracts having terms of 5 to 10 years (with a weighted-average term of 8.7 years), as well as the capacity leased to Gulf Crossing discussed above. The certificate filing was made with the FERC in December 2006 and the project is anticipated to be in service during the first quarter 2008. The FERC issued a draft environmental impact statement for the expansion project on April 13, 2007.

·  
Fayetteville Shale. We are pursuing the construction of two laterals connected to our pipeline system to transport gas from the Fayetteville Shale area in Arkansas to markets directly and indirectly served by our pipelines. The Fayetteville Lateral, consisting of approximately 165 miles of 36-inch pipeline, is anticipated to have an initial design capacity of 800 MMcf per day. This lateral will originate in Conway County, Arkansas and proceed southeast through the Bald Knob, Arkansas area to an interconnect with our mainline in Coahoma County, Mississippi. The Greenville Lateral, consisting of approximately 95 miles of pipeline with an initial design capacity of 750 MMcf per day, will originate at our mainline near Greenville, Mississippi and proceed east to the Kosciusko, Mississippi area. The Greenville Lateral will allow customers to access additional markets, primarily in the Midwest, Northeast and Southeast. Construction of both laterals is supported by a binding precedent agreement with Southwestern Energy Services Company, a wholly-owned subsidiary of Southwestern Energy Company. In December 2006, we initiated the pre-filing process with FERC for this project and anticipate making the required certificate filings with the FERC by July 2007. We expect the project to be in service during the first quarter 2009.

The total cost of the pipeline expansion projects discussed above, before taking into account any potential equity contribution by the foundation shipper in Gulf Crossing or the exercise of customer options for additional capacity also discussed above, is estimated to be approximately $3.4 billion. The actual cost to complete these projects may exceed the current estimate as a result of, among other things, higher labor and materials costs due to the large number of pipeline projects under way throughout the industry, the need to expand pipeline capacity if we contract for additional volumes, including as a result of option exercises, or design modifications.  For example, the cost estimate set forth above reflects our recent decision to increase the pipeline diameter for a portion of the Fayetteville Shale project to provide additional operational flexibility on that line.

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·  
Western Kentucky Storage Expansion. In December 2006, the FERC issued a certificate approving our Phase II storage expansion project which will expand the working gas capacity in our western Kentucky storage complex by approximately 9.0 Bcf. This project is supported by binding commitments from customers to contract on a long-term basis for the full additional capacity at Texas Gas’ maximum applicable rate. We expect this project to cost approximately $40.7 million and to be in service by November 2007. In December 2006, Texas Gas commenced an open season related to a potential third expansion of its storage facilities and has signed one precedent agreement for 2.0 Bcf of storage capacity. The Phase III storage expansion is subject to the FERC approvals, including potential market-based rate authority for the additional new storage capacity being created.

·  
Magnolia Storage Facility. We are currently developing an additional storage cavern near Napoleonville, Louisiana. During mining operations, certain issues arose causing the mining of the cavern to be suspended. Operational integrity tests on the caverns are under way. Assuming favorable testing results, we expect the storage facilities to be in service perhaps as early as mid-2008 with working gas capacity of approximately 2.0 Bcf, reduced from the original design capacity of 6.0 Bcf. The total book value of the project at March 31, 2007 and December 31, 2006 was $43.7 million and $42.7 million, respectively. We 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 has been recognized as a result of the testing.


Distributions

Note 11 in Item 1 of this Report contains information regarding our distributions.

 
Liquidity and Capital Resources

We are a limited partnership holding company and derive all of our operating cash flow from our operating subsidiaries. Boardwalk Pipelines uses cash provided from its subsidiaries 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 April 2007, our revolving credit facility was amended to increase the aggregate commitments from $400.0 million to $700.0 million and to extend the term to June 29, 2012, among other modifications. As of March 31, 2007 and December 31, 2006, no funds were drawn under the facility. During April 2007, we issued letters of credit for $221.5 million to support certain obligations associated with the Fayetteville Shale expansion project which reduced the available capacity under the facility.

In March 2007, we completed a public offering of 8.0 million of our common units. We received proceeds of approximately $293.9 million, net of underwriting discounts and offering expenses, and including approximately $6.0 million from our general partner to maintain its 2.0% general partner interest. The proceeds will primarily be used to fund capital expenditures associated with the expansion projects. After the offering, we have 83.2 million common units issued and outstanding, of which 29.9 million are held by the public. The balance of the common units plus all of the subordinated units are held by Boardwalk Pipelines Holding Corp. (BPHC).


Changes in cash flow from operating activities
 
Net cash provided by operating activities increased $4.1 million, or 5.6%, to $77.3 million for the three months ended March 31, 2007, compared to $73.2 million for the comparable 2006 period, primarily due to:

·       $11.8 million improvement in net income, excluding non-cash items such as depreciation and amortization was primarily driven by an increase in revenues;
·      $2.5 million increase in the loss on disposal of operating assets; and
·      $10.1 million decrease in deferred income primarily as a result of higher income on PAL agreements.

Changes in cash flow from investing activities
 
       Net cash used in investing activities increased $141.6 million to $161.0 million for the three months ended March 31, 2007, compared to $19.4 million for the comparable 2006 period, primarily due to a $140.3 million increase in capital expenditures mainly for our expansion projects.

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Changes in cash flow from financing activities

Net cash provided by (used in) financing activities increased $308.3 million to $247.8 million for the three months ended March 31, 2007, compared to a use of $60.5 million for the comparable 2006 period 2006, primarily due to $293.9 million in net equity offering proceeds from the sale of 8,000,000 units and related general partner capital contribution in March 2007.


Contractual Obligations

The table below is updated for significant changes in capital commitments from those included in the 2006 Annual Report on Form 10-K by period (in millions):
 
   
Payments due by Period
  
   
Total
  
Less than
1 Year
  
1-3 Years
  
4-5 Years
  
More than  
5 Years
  
Capital commitments
  
$
778.8
  
$
547.7
  
$
231.1
  
$
-
  
$
-
  

The capital commitments for construction were primarily related to the pipeline expansion projects. For further discussion of the expansion projects please read Note 5C Expansion Projects in the Notes to condensed consolidated financial statements included in Item 1.


Off Balance Sheet Arrangements
 
At March 31, 2007, we had no guarantees of off balance sheet debt to third parties, no debt obligations that contain provisions requiring accelerated payment of the related obligations in the event of specified levels of declines in credit ratings, and no other off balance sheet arrangements.


Critical Accounting Policies 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.

During the first quarter 2007, there were no significant changes to our critical accounting policies, judgments or estimates from those disclosed in our Annual Report on Form 10-K for the year ended December 31, 2006.


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 our partnership or its 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:

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·  
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.

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

·  
We may not complete any future debt or equity financing transaction, including any sale of an interest in Gulf Crossing Pipeline.

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

·  
We are subject to laws and regulations relating to the environment and pipeline operations which may expose us to significant costs, liabilities and loss of revenues. Any changes in such regulations or their application could negatively affect our 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 our ability to obtain access to new sources of natural gas, which is dependent on factors beyond our control. Any decrease in supplies of natural gas in our supply areas could adversely affect our business, financial condition and results of operations.

·  
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.

·  
Significant changes in natural gas prices could affect supply and demand, reducing system throughput and adversely affecting our revenues.

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.


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Item 3. Quantitative and Qualitative Disclosures About Market Risk
 
Our long-term debt is subject to interest rate risk. Total long-term debt at March 31, 2007, had a carrying value of $1.4 billion and a fair value of $1.3 billion. The weighted-average interest rate of our long-term debt was 5.41% at March 31, 2007.

In August 2006, we entered into Treasury rate locks with two counterparties each for a notional amount of $100.0 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 rate locks are 5.00% and 4.96%. Under the terms of the 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. A 10 basis point decrease in the 10-year Treasury rate would result in a $1.6 million favorable change in the value of the rate locks. Conversely, a 10 basis point increase in the 10-year Treasury rate would result in a $1.6 million unfavorable change in the value of the rate locks. The Treasury rate locks were designated as cash flow hedges in accordance with Statement of Financial Accounting Standards (SFAS) No. 133. As of March 31, 2007, we reported a liability of $5.0 million, and a reduction in Accumulated other comprehensive income in an equal and offsetting amount less ineffectiveness recognized of less than $0.1 million, for the fair values of the rate locks.

Certain volumes of our gas stored underground are available for sale and subject to commodity price risk. At March 31, 2007 and December 31, 2006, approximately $15.1 million and $14.0 million, of our gas stored underground, which we own and carry as current Gas stored underground, is exposed to commodity price risk. Our operating subsidiaries utilize derivatives to hedge certain exposures to market price fluctuations on the anticipated operational sales of gas and also for cash received for fuel reimbursement.

As a result of the Texas Gas Western Kentucky storage expansion project, approximately 4.8 Bcf of gas stored underground with a book value of $11.3 million is available for sale. Approximately 3.0 Bcf of this gas is subject to forward sales agreements under which the ultimate sales price was determined in March 2007, based on the price of New York Mercantile Exchange (NYMEX) natural gas futures. Texas Gas entered into derivatives to hedge the price exposure related to the storage gas. The derivatives associated with the volumes subject to forward sales agreements were designated as cash flow hedges during February 2007. Prior to the designation, these derivatives were marked to fair value through earnings along with the related forward sales agreements, resulting in a loss of $0.1 million in the first quarter 2007. The derivatives related to the remaining 1.8 Bcf of storage gas were also marked to fair value through earnings resulting in a loss of $2.0 million in the first quarter 2007.

With the exception of the storage gas volumes referred to above, the derivatives related to the sale of natural gas and 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 fair values of the derivatives contracts designated as cash flow hedges are deferred as a component of Accumulated other comprehensive income. The deferred gains and losses are recognized in the Condensed Consolidated Statements of Income when the hedged anticipated purchases or sales affect earnings.

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. Each reporting period we measure 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 transactions, the ineffective portion of the hedge contracts is currently recognized in earnings. If the anticipated transactions are deemed no longer probable to occur, hedge accounting would be terminated and changes in the fair values of the associated derivative financial instruments would be recognized currently in the Condensed Consolidated Statements of Income. 

 We are exposed to credit risk relating 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 PAL and no-notice service (NNS). 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 March 31, 2007, the amount of gas loaned out by our subsidiaries was approximately 36.9 trillion British thermal units (TBtu) and, assuming an average market price during March 2007 of $7.07 per million British thermal units (MMBtu), the market value of gas loaned out at March 31, 2007 would have been approximately $260.9 million. As of December 31, 2006, the amount of gas loaned out by our subsidiaries was approximately 15.1 TBtu and, assuming an average market price during December 2006 of $6.81 per MMBtu, the market value of gas loaned out at December 31, 2006 would have been approximately $102.8 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 March 31, 2007, our cash equivalents were invested primarily in money market investments. Due to the short-term nature and type of our investments, 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 by the effect of a sudden change in market interest rates on our investment portfolio.

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

There was no change in our internal control over financial reporting identified in connection with the foregoing evaluation that occurred during the first quarter 2007 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.






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PART II - OTHER INFORMATION


Item 1. Legal Proceedings 
 
For a discussion of certain of our current legal proceedings, please read Note 5 of the Notes to condensed consolidated financial statements in Item 1 of this Report.


Item 2.  Unregistered Sales of Equity Securities and Use of Proceeds
 
On March 5, 2007, our general partner purchased 1,500 of our common units in the open market at a price of $36.67 per unit.  These units were granted to our independent directors on March 5, 2007 as part of their director compensation.

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Item 6. Exhibits
 

Exhibit Designation
  
Nature of Exhibit
31.1*
  
Certification of Rolf A. Gafvert, Chief Executive Officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*
  
Certification of Jamie L. Buskill, Chief Financial Officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1*
  
Certification of Rolf A. Gafvert, Chief Executive Officer, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2*
  
Certification of Jamie L. Buskill, Chief Financial Officer, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.


* Filed herewith

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 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: April 30, 2007
    
By:
/s/ Jamie L. Buskill
       
Jamie L. Buskill
       
Chief Financial Officer

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