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, 2008
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.) | ||
9 Greenway Plaza, Suite 2800 Houston, Texas 77046 (866) 913-2122 | ||
| (Address and Telephone Number of Registrant’s Principal Executive Office) | ||
| Securities registered pursuant to Section 12(b) of the Act: | ||
| Title of each class | Name of each exchange on which registered | |
| Common Units Representing Limited Partner Interests | New York Stock Exchange | |
Securities registered pursuant to Section 12(g) of the Act: NONE | ||
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, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one)
Large accelerated filer x Accelerated filer o Non-accelerated filer o Smaller reporting company o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ¨ No x
As of July 24, 2008, the registrant had 100,656,122 common units, 22,866,667 class B units and 33,093,878 subordinated units outstanding.
1
TABLE OF CONTENTS
FORM 10-Q
June 30, 2008
BOARDWALK PIPELINE PARTNERS, LP
PART I - FINANCIAL INFORMATION
Item 1. Financial Statements |
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 ...............................................................................................................................22
Item 3. Quantitative and Qualitative Disclosures About Market Risk ...................................................................................................................................................................................30
Item 4. Controls and Procedures ...................................................................................................................................................................................................................................................32
PART II - OTHER INFORMATION
Item 1. Legal Proceedings ..............................................................................................................................................................................................................................................................33
Item 6. Exhibits .................................................................................................................................................................................................................................................................................34
Signatures ..........................................................................................................................................................................................................................................................................................35
2
PART I – FINANCIAL INFORMATION
Item 1. Financial Statements
BOARDWALK PIPELINE PARTNERS, LP
(Millions)
(Unaudited)
| June 30, | December 31, | |||||||
| ASSETS | 2008 | 2007 | ||||||
| Current Assets: | ||||||||
| Cash and cash equivalents | $ | 482.6 | $ | 317.3 | ||||
| Receivables: | ||||||||
| Trade, net | 63.3 | 60.7 | ||||||
| Other | 23.0 | 12.7 | ||||||
| Gas Receivables: | ||||||||
| Transportation and exchange | 32.0 | 12.5 | ||||||
| Storage | 0.3 | 1.3 | ||||||
| Inventories | 18.1 | 16.6 | ||||||
| Costs recoverable from customers | 6.6 | 6.3 | ||||||
| Gas stored underground | 15.0 | 16.3 | ||||||
| Prepaid expenses and other current assets | 33.0 | 11.9 | ||||||
| Total current assets | 673.9 | 455.6 | ||||||
| Property, Plant and Equipment: | ||||||||
| Natural gas transmission plant | 3,305.5 | 2,392.5 | ||||||
| Other natural gas plant | 220.6 | 224.0 | ||||||
| 3,526.1 | 2,616.5 | |||||||
| Less—accumulated depreciation and amortization | 317.6 | 262.5 | ||||||
| 3,208.5 | 2,354.0 | |||||||
| Construction work in progress | 1,194.4 | 951.4 | ||||||
| Property, plant and equipment, net | 4,402.9 | 3,305.4 | ||||||
| Other Assets: | ||||||||
| Goodwill | 163.5 | 163.5 | ||||||
| Gas stored underground | 171.8 | 172.4 | ||||||
| Costs recoverable from customers | 15.7 | 15.9 | ||||||
| Other | 52.8 | 44.5 | ||||||
| Total other assets | 403.8 | 396.3 | ||||||
| Total Assets | $ | 5,480.6 | $ | 4,157.3 | ||||
The accompanying notes are an integral part of these condensed consolidated financial statements.
3
BOARDWALK PIPELINE PARTNERS, LP
CONDENSED CONSOLIDATED BALANCE SHEETS
(Millions)
(Unaudited)
| June 30, | December 31, | |||||||
| LIABILITIES AND PARTNERS’ CAPITAL | 2008 | 2007 | ||||||
| Current Liabilities: | ||||||||
| Payables: | ||||||||
| Trade | $ | 223.8 | $ | 190.6 | ||||
| Affiliates | 2.5 | 1.3 | ||||||
| Other | 6.7 | 5.1 | ||||||
| Gas Payables: | ||||||||
| Transportation and exchange | 12.8 | 17.8 | ||||||
| Storage | 50.7 | 35.3 | ||||||
| Accrued taxes, other | 52.9 | 20.2 | ||||||
| Accrued interest | 34.6 | 30.8 | ||||||
| Accrued payroll and employee benefits | 17.4 | 22.3 | ||||||
| Construction retainage | 28.2 | 32.2 | ||||||
| Deferred income | 2.0 | 7.2 | ||||||
| Other current liabilities | 49.6 | 26.5 | ||||||
| Total current liabilities | 481.2 | 389.3 | ||||||
| Long –Term Debt | 2,096.4 | 1,847.9 | ||||||
| Other Liabilities and Deferred Credits: | ||||||||
| Pension and postretirement benefits | 18.8 | 17.2 | ||||||
| Asset retirement obligation | 16.5 | 16.1 | ||||||
| Provision for other asset retirement | 43.6 | 42.4 | ||||||
| Other | 74.1 | 41.4 | ||||||
| Total other liabilities and deferred credits | 153.0 | 117.1 | ||||||
| Commitments and Contingencies | ||||||||
| Partners’ Capital: | ||||||||
| Common units – 100.7 million units and 90.7 million units issued and outstanding as of June 30, 2008 and December 31, 2007 | 1,741.0 | 1,473.9 | ||||||
| Class B units – 22.9 million units issued and outstanding as of June 30, 2008 | 686.0 | - | ||||||
| Subordinated units – 33.1 million units issued and outstanding as of June 30, 2008 and December 31, 2007 | 300.0 | 291.7 | ||||||
| General partner | 53.0 | 33.2 | ||||||
| Accumulated other comprehensive (loss) income | (30.0 | ) | 4.2 | |||||
| Total partners’ capital | 2,750.0 | 1,803.0 | ||||||
| Total Liabilities and Partners’ Capital | $ | 5,480.6 | $ | 4,157.3 | ||||
The accompanying notes are an integral part of these condensed consolidated financial statements.
4
BOARDWALK PIPELINE PARTNERS, LP
(Millions, except per unit amounts)
(Unaudited)
| For the | For the | |||||||||||||||
| Three Months Ended | Six Months Ended | |||||||||||||||
| June 30, | June 30, | |||||||||||||||
| 2008 | 2007 | 2008 | 2007 | |||||||||||||
| Operating Revenues: | ||||||||||||||||
| Gas transportation | $ | 160.2 | $ | 115.0 | $ | 336.7 | $ | 267.9 | ||||||||
| Parking and lending | 4.6 | 12.8 | 9.7 | 31.2 | ||||||||||||
| Gas storage | 13.6 | 10.5 | 24.3 | 18.2 | ||||||||||||
| Other | 11.9 | 12.2 | 16.9 | 21.4 | ||||||||||||
| Total operating revenues | 190.3 | 150.5 | 387.6 | 338.7 | ||||||||||||
| Operating Costs and Expenses: | ||||||||||||||||
| Operation and maintenance | 54.9 | 43.0 | 95.7 | 82.5 | ||||||||||||
| Administrative and general | 27.3 | 22.1 | 52.5 | 47.9 | ||||||||||||
| Depreciation and amortization | 30.4 | 20.2 | 57.8 | 40.1 | ||||||||||||
| Contract settlement gain | - | - | (11.2 | ) | - | |||||||||||
| Asset impairment | - | 14.7 | 1.4 | 14.7 | ||||||||||||
| Net (gain) loss on disposal of operating assets and related contracts | (14.2 | ) | (1.0 | ) | (14.0 | ) | 1.6 | |||||||||
| Taxes other than income taxes | 10.9 | 7.2 | 22.9 | 15.2 | ||||||||||||
| Total operating costs and expenses | 109.3 | 106.2 | 205.1 | 202.0 | ||||||||||||
| Operating income | 81.0 | 44.3 | 182.5 | 136.7 | ||||||||||||
| Other Deductions (Income): | ||||||||||||||||
| Interest expense | 17.7 | 14.5 | 36.7 | 31.3 | ||||||||||||
| Interest income | (0.4 | ) | (5.9 | ) | (1.4 | ) | (10.5 | ) | ||||||||
| Miscellaneous other (income) deductions, net | (1.2 | ) | 0.1 | (6.1 | ) | (0.2 | ) | |||||||||
| Total other deductions | 16.1 | 8.7 | 29.2 | 20.6 | ||||||||||||
| Income before income taxes | 64.9 | 35.6 | 153.3 | 116.1 | ||||||||||||
| Income taxes | 0.2 | 0.2 | 0.5 | 0.4 | ||||||||||||
| Net income | $ | 64.7 | $ | 35.4 | $ | 152.8 | $ | 115.7 | ||||||||
| Net income | $ | 64.7 | $ | 35.4 | $ | 152.8 | $ | 115.7 | ||||||||
| Less general partner’s interest in Net income | 2.9 | 1.2 | 6.2 | 3.0 | ||||||||||||
| Limited partners’ interest in Net income | $ | 61.8 | $ | 34.2 | $ | 146.6 | $ | 112.7 | ||||||||
| Basic and diluted net income per limited partner unit: | ||||||||||||||||
| Common units | $ | 0.49 | $ | 0.35 | $ | 1.09 | $ | 0.97 | ||||||||
| Subordinated units | $ | 0.49 | $ | 0.17 | $ | 1.09 | $ | 0.97 | ||||||||
| Cash distribution per unit to common and subordinated units | $ | 0.465 | $ | 0.43 | $ | 0.925 | $ | 0.845 | ||||||||
| Weighted-average number of limited partner units outstanding: | ||||||||||||||||
| Common units | 92.3 | 83.2 | 91.5 | 79.6 | ||||||||||||
| Subordinated units | 33.1 | 33.1 | 33.1 | 33.1 |
The accompanying notes are an integral part of these condensed consolidated financial statements.
5
BOARDWALK PIPELINE PARTNERS, LP
(Millions)
(Unaudited)
| For the | ||||||||
| Six Months Ended | ||||||||
| June 30, | ||||||||
| 2008 | 2007 | |||||||
| OPERATING ACTIVITIES: | ||||||||
| Net income | $ | 152.8 | $ | 115.7 | ||||
| Adjustments to reconcile to cash provided by operations: | ||||||||
| Depreciation and amortization | 57.8 | 40.1 | ||||||
| Amortization of deferred costs | 4.4 | 3.8 | ||||||
| Amortization of acquired executory contracts | (0.2 | ) | (0.9 | ) | ||||
| Asset impairment | 1.4 | 14.7 | ||||||
| (Gain) loss on disposal of operating assets and related contracts | (14.0 | ) | 1.6 | |||||
| Changes in operating assets and liabilities: | ||||||||
| Trade and other receivables | (26.5 | ) | 17.1 | |||||
| Gas receivables and storage assets | (16.5 | ) | (1.9 | ) | ||||
| Costs recoverable from customers | (0.2 | ) | 4.3 | |||||
| Other assets | (12.3 | ) | (6.1 | ) | ||||
| Trade and other payables | 1.2 | (11.6 | ) | |||||
| Other payables, affiliates | 0.4 | - | ||||||
| Gas payables | 38.3 | (5.3 | ) | |||||
| Accrued liabilities | 8.1 | 10.1 | ||||||
| Other liabilities | (23.1 | ) | (9.9 | ) | ||||
| Net cash provided by operating activities | 171.6 | 171.7 | ||||||
| INVESTING ACTIVITIES: | ||||||||
| Capital expenditures | (1,089.5 | ) | (380.0 | ) | ||||
| Proceeds from sale of operating assets | 4.9 | 0.3 | ||||||
| Proceeds from insurance reimbursements and other recoveries | 3.8 | 1.7 | ||||||
| Advances to affiliates, net | (1.1 | ) | (1.2 | ) | ||||
| Net cash used in investing activities | (1,081.9 | ) | (379.2 | ) | ||||
| FINANCING ACTIVITIES: | ||||||||
| Proceeds from long-term debt, net of issuance costs | 247.2 | - | ||||||
| Proceeds from borrowings on revolving credit agreement | 518.0 | - | ||||||
| Repayment of borrowings on revolving credit agreement | (518.0 | ) | - | |||||
| Distributions | (120.1 | ) | (97.7 | ) | ||||
| Proceeds from sale of common units, net of related transaction costs | 243.3 | 287.9 | ||||||
| Proceeds from sale of class B units | 686.0 | - | ||||||
| Capital contribution from general partner | 19.2 | 6.0 | ||||||
| Net cash provided by financing activities | 1,075.6 | 196.2 | ||||||
| Increase (Decrease) in cash and cash equivalents | 165.3 | (11.3 | ) | |||||
| Cash and cash equivalents at beginning of period | 317.3 | 399.1 | ||||||
| Cash and cash equivalents at end of period | $ | 482.6 | $ | 387.8 | ||||
The accompanying notes are an integral part of these condensed consolidated financial statements.
6
BOARDWALK PIPELINE PARTNERS, LP
(Millions)
(Unaudited)
Common Units | Class B Units | Subordinated Units | General Partner | Accumulated Other Comp Income (Loss) | Total Partners’ Capital | |||||||||||||||||||
| Balance January 1, 2007 | $ | 941.8 | - | $ | 285.5 | $ | 22.1 | $ | 23.1 | $ | 1,272.5 | |||||||||||||
| Add (deduct): | ||||||||||||||||||||||||
| Net income | 79.1 | - | 33.6 | 3.0 | - | 115.7 | ||||||||||||||||||
| Distributions paid | (67.0 | ) | - | (28.0 | ) | (2.7 | ) | - | (97.7 | ) | ||||||||||||||
Sale of common units, net of related transaction costs (8.0 million common units) | 287.9 | - | - | - | - | 287.9 | ||||||||||||||||||
Capital contribution from general partner | - | - | - | 6.0 | - | 6.0 | ||||||||||||||||||
| Other comprehensive loss | - | - | - | - | (3.7 | ) | (3.7 | ) | ||||||||||||||||
| Balance June 30, 2007 | $ | 1,241.8 | - | $ | 291.1 | $ | 28.4 | $ | 19.4 | $ | 1,580.7 | |||||||||||||
| Balance January 1, 2008 | $ | 1,473.9 | - | $ | 291.7 | $ | 33.2 | $ | 4.2 | $ | 1,803.0 | |||||||||||||
| Add (deduct): | ||||||||||||||||||||||||
| Net income | 107.6 | - | 39.0 | 6.2 | - | 152.8 | ||||||||||||||||||
| Distributions paid | (83.8 | ) | - | (30.7 | ) | (5.6 | ) | - | (120.1 | ) | ||||||||||||||
Sale of common units, net of related transaction costs (10.0 million common units) | 243.3 | - | - | - | - | 243.3 | ||||||||||||||||||
Sale of class B units (22.9 million class B units) | - | $ | 686.0 | - | - | - | 686.0 | |||||||||||||||||
Capital contribution from general partner | - | - | - | 19.2 | - | 19.2 | ||||||||||||||||||
| Other comprehensive loss | - | - | - | - | (34.2 | ) | (34.2 | ) | ||||||||||||||||
| Balance June 30, 2008 | $ | 1,741.0 | $ | 686.0 | $ | 300.0 | $ | 53.0 | $ | (30.0 | ) | $ | 2,750.0 | |||||||||||
The accompanying notes are an integral part of these condensed consolidated financial statements.
7
BOARDWALK PIPELINE PARTNERS, LP
(Millions)
(Unaudited)
For the Three Months Ended June 30, | For the Six Months Ended June 30, | |||||||||||||||
| 2008 | 2007 | 2008 | 2007 | |||||||||||||
| Net income | $ | 64.7 | $ | 35.4 | $ | 152.8 | $ | 115.7 | ||||||||
| Other comprehensive (loss) income: | ||||||||||||||||
| (Loss) gain on cash flow hedges | (23.0 | ) | 8.4 | (47.4 | ) | 0.9 | ||||||||||
Reclassification adjustment transferred to Net income from cash flow hedges | 17.0 | (1.5 | ) | 17.6 | (4.5 | ) | ||||||||||
| Pension and other postretirement benefits costs | (2.2 | ) | (1.5 | ) | (4.4 | ) | (0.1 | ) | ||||||||
| Total comprehensive income | $ | 56.5 | $ | 40.8 | $ | 118.6 | $ | 112.0 | ||||||||
The accompanying notes are an integral part of these condensed consolidated financial statements.
8
BOARDWALK PIPELINE PARTNERS, LP
(Unaudited)
Note 1: Basis of Presentation
Boardwalk Pipeline Partners, LP (the Partnership) is a Delaware limited partnership formed in 2005. Its business is 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), and Gulf Crossing Pipeline Company, LLC (Gulf Crossing) which will operate a new interstate pipeline expected to be placed in service in 2009. Boardwalk Pipelines Holding Corp. (BPHC), a wholly-owned subsidiary of Loews Corporation (Loews), owns 53.3 million common units, 22.9 million class B units and 33.1 million subordinated units. Boardwalk GP, LP (Boardwalk GP), an indirect wholly-owned subsidiary of BPHC, is the Partnership’s general partner and holds a 2% general partner interest in and all of the incentive distribution rights of the Partnership, further described in Note 8. The Partnership’s common units are traded under the symbol “BWP” on the New York Stock Exchange.
The accompanying unaudited condensed consolidated financial statements of the Partnership were prepared pursuant to the rules and regulations of the Securities and Exchange Commission. Certain information and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America 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 June 30, 2008 and December 31, 2007, and the results of operations and comprehensive income for the three and six months ended June 30, 2008 and 2007, and changes in cash flow and changes in partners’ capital for the six months ended June 30, 2008 and 2007. Reference is made to the Notes to Consolidated Financial Statements in the 2007 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 unaudited condensed consolidated financial statements.
Net income for interim periods may not necessarily be indicative of results for the full year. All intercompany items have been eliminated in consolidation.
Note 2: Gas in Storage and Gas Receivables/Payables
Gulf South and Texas Gas store gas on behalf of others. 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 June 30, 2008 and December 31, 2007, Gulf South held 35.2 trillion British thermal units (TBtu) and 52.0 TBtu of gas owned by shippers. Gulf South loaned 1.0 and 0.2 TBtu of gas to shippers as of June 30, 2008 and December 31, 2007. Consistent with the method of storage accounting elected by Texas Gas and the risk-of-loss provisions included in its tariff, Texas Gas reflects gas held on behalf of others in Gas stored underground and records an equal offsetting payable. The amount reflected in Gas Payables on the Condensed Consolidated Balance Sheets is valued at a historical cost of gas of $50.7 million and $35.3 million at June 30, 2008 and December 31, 2007.
9
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 price risk and interest rate risk. These derivatives 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.
Certain volumes of gas stored underground are available for sale and subject to commodity price risk. At June 30, 2008 and December 31, 2007, approximately $15.0 million and $16.3 million of gas stored underground, which the Partnership owns and carries as current Gas stored underground, was exposed to commodity price risk. The Partnership utilizes derivatives to hedge certain exposures to market price fluctuations on the anticipated operational sales of gas.
As a result of the approval by the Federal Energy Regulatory Commission (FERC) of Phase III of the Western Kentucky Storage Expansion project in the first quarter 2008, approximately 5.1 billion cubic feet (Bcf) of gas stored underground with a book value of $11.8 million became available for sale. The Partnership entered into derivatives, which were designated as cash flow hedges, to hedge the price exposure related to the expected sale of this gas. Approximately 2.2 Bcf of this gas was sold in the second quarter 2008, and the related derivatives were settled, resulting in a gain of $14.7 million which was reported in Net gain on disposal of operating assets and related contracts on the Condensed Consolidated Statements of Income. The Partnership recognized a gain of $1.4 million and a loss of $0.7 million for the three and six months ended June 30, 2007, on derivatives and related contracts not designated as hedges related to gas stored underground that became available for sale as a result of Phase II of the Western Kentucky Storage Expansion project.
In the second quarter 2007, the Partnership entered into natural gas price swaps to hedge exposure to prices associated with the purchase of 2.1 Bcf of natural gas to be used for line pack for pipeline expansion projects, of which approximately 1.3 Bcf remained outstanding at June 30, 2008. The derivatives were not designated as hedges and were marked to fair value through earnings resulting in a gain of $4.1 million and $7.2 million in Miscellaneous other income, net on the Condensed Consolidated Statements of Income for the three and six months ended June 30, 2008, and resulting in a loss of $0.7 million for the corresponding periods in 2007.
In August 2007, the Partnership entered into a Treasury rate lock for a notional amount of $150.0 million of principal to hedge the risk attributable to changes in the risk-free component of forward 10-year interest rates through February 1, 2008. The Treasury rate lock was designated as a cash flow hedge in accordance with SFAS No. 133. As of December 31, 2007, the Partnership recorded a payable of $8.4 million and a corresponding amount in Accumulated other comprehensive loss for the fair value of the rate lock. On February 1, 2008, the Partnership settled the rate lock and paid the counterparty approximately $15.0 million which was deferred as a component of Accumulated other comprehensive loss. The loss will be amortized to interest expense over 10 years.
With the exception of the derivatives related to certain storage gas volumes related to Phase II of the Western Kentucky Storage Expansion project and line pack gas purchases referred to above, the derivatives related to the sale or purchase of natural gas, cash for fuel reimbursement and debt generally qualify for cash flow hedge accounting under SFAS No. 133 and are designated as such. The effective component of related 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 loss. The deferred gains and losses are recognized in the Condensed Consolidated Statements of Income when the anticipated transactions affect earnings. In situations where continued reporting of a loss in Accumulated other comprehensive loss would result in recognition of a future loss on the combination of the derivative and the hedged transaction, SFAS No. 133 requires that the loss be immediately recognized in earnings for the amount that is not expected to be recovered. The Partnership reclassified losses of $1.7 million for the three and six months ended June 30, 2008, from Accumulated other comprehensive loss to earnings related to amounts that are not expected to be recovered in future periods from the combination of sales of gas stored underground and the deferred losses associated with related derivatives.
10
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 projects, any gains and losses on the related derivatives would be recognized in Net (gain) loss on disposal of operating assets and related contracts. Any gains and losses on the derivatives related to the line pack gas purchases would be recognized in Miscellaneous other income, net.
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 no longer deemed 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 earnings. Less than $0.1 million of ineffectiveness was recorded for the three and six months ended June 30, 2008. Ineffectiveness increased Net income by $0.1 million and $0.4 million for the three and six months ended June 30, 2007. The Partnership did not discontinue any cash flow hedges during the three and six month periods ended June 30, 2008 and 2007.
Note 4 contains information regarding the fair values of the Partnership’s derivative instruments. Included as a component of Other current assets was $9.3 million of cash which was deposited as collateral as a result of net loss positions on derivatives at June 30, 2008.
Note 4: Fair Value
SFAS No. 157, Fair Value Measurements
In 2008, the Partnership implemented the provisions of SFAS No. 157, except for the provisions related to non-financial assets and liabilities measured at fair value on a non-recurring basis, which provisions will be applied beginning in 2009. Fair value refers to the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction in the principal market in which the reporting entity transacts based on the assumptions market participants would use when pricing the asset or liability. SFAS No. 157 establishes a fair value hierarchy that prioritizes the information used to develop those assumptions giving priority, from highest to lowest, to quoted prices in active markets for identical assets and liabilities (Level 1); observable inputs not included in Level 1, for example, quoted prices for similar assets and liabilities (Level 2); and unobservable data (Level 3), for example, a reporting entity’s own internal data based on the best information available in the circumstances.
The Partnership identified its derivatives as items governed by the provisions of SFAS No. 157. The derivatives in existence at June 30, 2008, were natural gas price swaps and options, which were recorded at fair value based on New York Mercantile Exchange (NYMEX) quotes for natural gas futures and options. The NYMEX quotes were deemed to be observable inputs for similar assets and liabilities and rendered Level 2 inputs for purposes of disclosure. The application of SFAS No. 157 had no effect on the Partnership’s financial statements.
11
The fair values of derivatives existing as of June 30, 2008, were included in the following captions in the Condensed Consolidated Balance Sheets (in millions):
Total at June 30, 2008 | Quoted Prices in Active Markets for Identical Assets Level 1 | Significant Other Observable Inputs Level 2 | Significant Unobservable Inputs Level 3 | |||||||||||||
| Assets: | ||||||||||||||||
| Prepaid expenses and other current assets | $ | 7.9 | - | $ | 7.9 | - | ||||||||||
| Total assets | $ | 7.9 | - | $ | 7.9 | - | ||||||||||
| Liabilities: | ||||||||||||||||
| Other current liabilities | $ | 15.9 | - | $ | 15.9 | - | ||||||||||
| Other non-current liabilities | 1.6 | - | 1.6 | - | ||||||||||||
| Total liabilities | $ | 17.5 | - | $ | 17.5 | - | ||||||||||
SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities
In 2008, the Partnership had the option to apply the provisions of SFAS No. 159, which allows companies to elect to measure and record certain financial assets and liabilities at fair value that would not otherwise be recorded at fair value, such as long-term debt or notes receivable. Unrealized gains and losses on items for which the fair value option was chosen would be reported in earnings. The Partnership reviewed its financial assets and liabilities in existence at January 1, 2008, as well as any financial assets and liabilities entered into during the six month period ended June 30, 2008, and did not elect the fair value option for any applicable items. Consequently, the application of SFAS No. 159 had no effect on the Partnership’s financial statements.
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 the Partnership does not have access to the information about each partner’s tax attributes. The subsidiaries of the Partnership directly incur some income-based state taxes which are presented in Income taxes on the Condensed Consolidated Statements of Income.
Note 6: Commitments and Contingencies
A. Calpine Energy Services (Calpine) Settlement
In December 2007, Gulf South and Calpine filed a stipulation and agreement in Calpine’s Chapter 11 Bankruptcy proceedings to settle, for approximately $16.5 million, Gulf South’s claim against Calpine related to Calpine’s non-payment under a transportation agreement. The claim, which was approved in January 2008, was to be paid in the form of Calpine stock, along with other general creditors having claims in the Bankruptcy proceeding. In the fourth quarter 2007, the Partnership recognized $4.1 million of revenues related to previously reserved amounts invoiced to Calpine for transportation services previously rendered. In January 2008, the Partnership sold the entire claim to a third party and received a cash payment of approximately $15.3 million. The transfer of the claim was deemed a sale and any recourse related to the sale expired in January 2008. As a result, in the first quarter 2008, the Partnership recorded a net gain of $11.2 million related to the realization of the unrecognized portion of the claim which was reported as Contract settlement gain on the Condensed Consolidated Statements of Income. The matter is considered settled and the Partnership does not expect to receive additional amounts related to the claim.
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B. Jackson Storage Loss
The Partnership’s Jackson, Mississippi aquifer storage facility has a working gas capacity of approximately 5.0 Bcf and is primarily used for operational purposes. In the fourth quarter 2007, it was estimated that a gas loss of approximately 1.3 Bcf had occurred. As a result of the estimated gas loss, the Partnership recognized a charge to earnings of $0.7 million in the fourth quarter 2007. In the second quarter 2008, a more comprehensive test of the field was completed resulting in no adjustment to the amount previously charged to earnings.
C. Hurricane Rita Settlement
In September 2005, Hurricane Rita caused physical damage to a portion of the Partnership’s assets. The related remediation work was completed in 2007. In the second quarter 2008, the Partnership received insurance proceeds of $4.7 million which were applied against a receivable for probable recoveries that was established in the third quarter 2007. The Partnership received an additional $1.0 million in the third quarter 2008 as final settlement.
D. Legal Proceedings
Napoleonville Salt Dome Matter
In December 2003, natural gas leaks were observed near two natural gas storage caverns that were leased and operated by Gulf South for natural gas storage in Napoleonville, Louisiana. Gulf South commenced remediation efforts immediately and ceased using those storage caverns. Two class action lawsuits were filed relating to this incident and were converted to individual actions. Several additional 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 a claim against Gulf South in an action filed against the lessor by one of Gulf South's insurers. Most of the claims have been settled and Gulf South continues to vigorously defend each of the remaining actions, however it is not possible to predict the outcome of this litigation as the cases remain in discovery. Litigation is subject to many uncertainties, and it is possible these actions could be decided unfavorably. Gulf South has settled many 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. For the six month period ended June 30, 2008, the Partnership received $3.9 million in insurance proceeds related to previously incurred litigation and remediation costs, which were recorded as a reduction to Operation and maintenance expense.
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.
E. Regulatory and Rate Matters
Expansion Capital Projects
The Partnership has been engaged in several pipeline expansion projects as described below:
East Texas to Mississippi Expansion. The Partnership completed the East Texas to Mississippi expansion project during the second quarter 2008 at a total cost of approximately $960.1 million. This project consists of approximately 242 miles of 42-inch pipeline from DeSoto Parish in western Louisiana to near Harrisville, Mississippi. Customers have contracted at fixed rates for 1.4 Bcf per day of firm transportation capacity on a long-term basis which represents substantially all of the normal operating capacity.
Southeast Expansion. The pipeline and one compressor station related to this project were placed in service during the second quarter 2008. This project consists of approximately 111 miles of 42-inch pipeline originating near Harrisville, Mississippi and extending to an interconnect with Transcontinental Pipe Line Company (Transco) in Choctaw County, Alabama (Transco 85), having 1.2 Bcf of peak-day transmission capacity. The Partnership expects to expand the project through the addition of compression facilities to 2.2 Bcf of peak-day transmission capacity. The Partnership expects this additional capacity to be in service during the first quarter 2009 to coincide with the commencement of service on its Gulf Crossing project. Customers have contracted at fixed rates for 660 million cubic feet (MMcf) per day of firm transportation capacity on a long-term basis (with a weighted-average term of 9.2 years), in addition to the capacity lease agreement with Gulf Crossing discussed below. Through June 30, 2008, the Partnership spent $553.6 million related to this project.
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Gulf Crossing Project. The Partnership is constructing a new interstate pipeline that will begin near Sherman, Texas and proceed to the Perryville, Louisiana area and will consist of approximately 357 miles of 42-inch pipeline having approximately 1.7 Bcf of peak-day transmission capacity with the addition of compression facilities. Additionally, Gulf Crossing has entered into, subject to regulatory approval: (i) a capacity lease agreement for 1.1 Bcf per day of capacity on the Partnership’s Gulf South pipeline system (including capacity on the Southeast Expansion and capacity on a portion of the East Texas to Mississippi Expansion) to make deliveries to an interconnect with Transco 85; and (ii) a capacity lease agreement with Enogex, a third-party intrastate pipeline, which will bring gas supplies to the Partnership’s system. Customers have contracted at fixed rates for 1.7 Bcf per day of long-term firm transportation capacity (with a weighted average term of approximately 9.5 years). The Partnership expects the pipeline to be in service during the first quarter 2009 and the additional compression to be in service by 2010. Through June 30, 2008, the Partnership spent $504.7 million related to this project.
Fayetteville and Greenville Laterals. The Partnership is constructing two laterals on its Texas Gas pipeline system to transport gas from the Fayetteville Shale area in Arkansas to markets directly and indirectly served by the Partnership’s existing interstate pipelines. The Fayetteville Lateral will originate in Conway County, Arkansas and proceed southeast through the Bald Knob, Arkansas area to an interconnect with the Texas Gas mainline in Coahoma County, Mississippi and consists of approximately 165 miles of 36-inch pipeline. The Greenville Lateral will originate at the Texas Gas mainline near Greenville, Mississippi and proceeds east to the Kosciusko, Mississippi area consisting of approximately 95 miles of 36-inch pipeline. The Greenville Lateral will allow customers to access additional markets, primarily in the Midwest, Northeast and Southeast. The Partnership recently executed contracts for additional capacity that will require it to add compression to increase the peak-day transmission capacity to approximately 1.3 Bcf for the Fayetteville Lateral and to approximately 1.0 Bcf for the Greenville Lateral. The contracts associated with this project are at fixed rates with a weighted average term of 9.9 years. The Partnership expects the first 60 miles of the Fayetteville Lateral to be in service during the third quarter 2008 and the remainder of the pipeline related to the Fayetteville and Greenville Laterals to be in service during the first quarter 2009. The Partnership expects to make additional filings with FERC during the third quarter 2008 regarding the additional compression required to increase the peak-day transmission capacity and expects the additional capacity to be in service during 2010. Through June 30, 2008, the Partnership spent $260.9 million related to the Fayetteville and Greenville Laterals.
The Partnership is also engaged in the following storage expansion project:
Western Kentucky Storage Expansion Phase III. The Partnership is developing up to 8.3 Bcf of new working gas capacity at its Midland storage facility and FERC has granted the Partnership market-based rate authority for this new capacity. This expansion is supported by 10-year precedent agreements for 5.1 Bcf of storage capacity. The cost of this project will be dependent on the ultimate size of the expansion. The Partnership expects 5.4 Bcf of storage capacity to be in service during the fourth quarter 2008. Through June 30, 2008, the Partnership spent $15.8 million related to this project.
F. 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 remediation efforts are probable and the costs can be reasonably estimated. In addition to federal and state mandated remediation requirements, the Partnership often enters into voluntary remediation programs with the agencies. The Partnership believes its accruals for environmental liabilities are adequate to accomplish remediation related to federal and state regulations. Depending on the results of on-going assessments and federal and state agency review of the data, revisions to the Partnership’s estimates may be necessary based on actual costs or new circumstances.
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As of June 30, 2008 and December 31, 2007, the Partnership had an accrued liability of approximately $15.9 million and $17.0 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. The expenditures are expected to occur over approximately the next ten years. The accrual represents management’s estimate of the undiscounted future obligations based on evaluations and discussions with counsel and operating personnel and the current facts and circumstances related to these matters. As of June 30, 2008 and December 31, 2007, approximately $2.7 million was recorded in Other current liabilities and approximately $13.2 million and $14.3 million were recorded in Other Liabilities and Deferred Credits.
In March 2008, the Environmental Protection Agency (EPA) adopted regulations lowering the 8-hour ozone standard relevant to non-attainment areas. Under the regulation new non-attainment areas will be identified which may require additional emission controls for compliance at as many as 14 facilities operated by the Partnership. The anticipated effective date for compliance with the proposed standard in its current state is between 2013 and 2016.
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.
G. Commitments
The Partnership’s future capital commitments as of June 30, 2008, for contracts already authorized are expected to approximate the following amounts (in millions):
| Less than 1 year | $ | 429.4 | ||
| 1-3 years | 21.8 | |||
| 4-5 years | - | |||
| More than 5 years | - | |||
| Total | $ | 451.2 |
There were no substantial changes to the Partnership’s operating lease commitments as disclosed in Note 3 to the Partnership’s Annual Report on Form 10-K.
Note 7: Financing
Senior Unsecured Debt
In March 2008, the Partnership received net proceeds of approximately $247.2 million after deducting initial purchaser discounts and offering expenses of $2.8 million from the sale of $250.0 million of 5.50% senior unsecured notes of Texas Gas due April 1, 2013. Interest on the notes will be payable on April 1 and October 1 of each year, beginning on October 1, 2008. The notes are redeemable, in whole or in part, at the option of Texas Gas at any time, at a redemption price equal to the greater of 100% of the principal amount of the notes to be redeemed or a “make whole” redemption price based on the remaining scheduled payments of principal and interest discounted to the date of redemption at a Treasury rate plus 50 basis points, plus accrued and unpaid interest, if any. Other customary covenants apply, including those concerning events of default.
As of June 30, 2008 and December 31, 2007, the weighted-average interest rate of the Partnership’s long-term debt was 5.89% and 5.82%.
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Revolving Credit Facility
As of June 30, 2008 and December 31, 2007, no funds were drawn under the Partnership’s $1.0 billion revolving credit facility. However, at June 30, 2008, the Partnership had outstanding letters of credit under the facility of $57.6 million to support certain obligations associated with the pipeline expansion projects which reduced the available capacity under the facility by such amount. During the six-month period ended June 30, 2008, the Partnership borrowed and repaid $518.0 million under the facility, with a weighted-average borrowing rate of 2.87%. As of June 30, 2008, the Partnership and its subsidiaries were in compliance with all covenant requirements under the credit agreement.
Capitalized Interest and Allowance for Funds Used During Construction
During the three and six months ended June 30, 2008, the Partnership capitalized interest of $14.9 million and $23.5 million. During the three and six months ended June 30, 2007, the Partnership capitalized interest of $4.2 million and $6.3 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 for certain of its operations. The Partnership capitalized AFUDC of $0.1 million for the three and six months ended June 30, 2008, and $0.7 million and $1.2 million for the three and six months ended June 30, 2007. In the second quarter 2008, the Partnership determined that SFAS No. 71 would not be applicable for the Fayetteville and Greenville Laterals. As a result, the Partnership recorded $2.6 million of capitalized interest and reversed $3.6 million of AFUDC.
Offering of Common Units
In June 2008, the Partnership completed a public offering of 10.0 million of its common units at a price of $25.30 per unit. The Partnership received proceeds of approximately $248.5 million, net of underwriting discounts and offering expenses of $9.7 million, which includes approximately $5.2 million contributed by its general partner to maintain its 2% interest. The proceeds of the offering were used to repay amounts borrowed under the revolving credit facility and to fund a portion of the costs of its ongoing expansion projects.
In March 2007, the Partnership completed an equity 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 of $4.2 million, which includes approximately $6.0 million contributed by its general partner to maintain its 2% interest. The proceeds of the offering have been used to finance the Partnership’s expansion projects.
Class B Units
In June 2008, the Partnership issued and sold, pursuant to the Class B Unit Purchase Agreement (the Purchase Agreement), approximately 22.9 million of class B units representing limited partner interests (class B units) to BPHC for $30.00 per class B unit, or an aggregate purchase price of $686.0 million. The Partnership’s general partner also contributed $14.0 million to the Partnership to maintain its 2% interest. The Partnership used the proceeds of $700.0 million to repay amounts borrowed under the revolving credit facility and to fund a portion of the costs of its ongoing expansion projects.
The class B units will share in quarterly distributions of available cash from operating surplus on a pari passu basis with the Partnership’s common units, until each common unit and class B unit has received a quarterly distribution of $0.30. The class B units will not participate in quarterly distributions above $0.30 per unit.
The class B units will share in income allocations beginning on July 1, 2008, and any distribution that may be made beginning with the fourth quarter 2008. As a result, no earnings were allocated to the class B capital account for the three and six months ended June 30, 2008.
The class B units have the same voting rights as if they were outstanding common units and are entitled to vote as a separate class on any matters that materially adversely affect the rights or preferences of the class B units in relation to other classes of partnership interests or as required by law. Pursuant to the Purchase Agreement, the Partnership entered into a Registration Rights Agreement with BPHC covering the common units into which the class B units will be convertible. The class B units will be convertible into common units by the holder on a one-for-one basis at any time after June 30, 2013.
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Note 8: 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 (EITF) Issue 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 (IDRs) in accordance with the partnership agreement as follows:
| Total Quarterly Distribution | Marginal Percentage Interest in Distributions | |||||
| Target Amount | Limited Partner Unitholders (1),(2) | General Partner Unitholders | ||||
| 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% | |||
| (1) | The class B unitholders participate in distributions on a pari passu basis with the Partnership’s common units up to $0.30 per quarter, beginning with any distribution that may be made in the fourth quarter 2008. The class B units will not participate in quarterly distributions above $0.30 per unit. |
| (2) | The partnership agreement provides that during the subordination period, the subordinated units will not receive distributions until the general partner, common and class B unitholders have received their respective minimum quarterly distribution plus any arrearages. The subordinated units are not entitled to arrearages. |
The amounts reported for net income per limited partner unit on the Condensed Consolidated Statements of Income for the three and six month periods ended June 30, 2008 and 2007, were adjusted to take into account an assumed allocation to the general partner's IDRs. Payments made on account of the IDRs are determined in relation to actual declared distributions. 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 follows (in millions, except per unit data):
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For the Three Months Ended June 30, | For the Six Months Ended June 30, | |||||||||||||||
| 2008 | 2007 | 2008 | 2007 | |||||||||||||
| Limited partners' interest in net income | $ | 61.8 | $ | 34.2 | $ | 146.6 | $ | 112.7 | ||||||||
| Less assumed allocation to IDRs | 0.8 | (0.5 | ) | 10.1 | 3.7 | |||||||||||
| Net income available to limited partners | 61.0 | 34.7 | 136.5 | 109.0 | ||||||||||||
| Less assumed allocation to subordinated units | 16.1 | 5.6 | 36.2 | 32.0 | ||||||||||||
| Net income available to common units | $ | 44.9 | $ | 29.1 | $ | 100.3 | $ | 77.0 | ||||||||
| Weighted average common units | 92.3 | 83.2 | 91.5 | 79.6 | ||||||||||||
| Weighted average subordinated units | 33.1 | 33.1 | 33.1 | 33.1 | ||||||||||||
Net income per limited partner unit – common units | $ | 0.49 | $ | 0.35 | $ | 1.09 | $ | 0.97 | ||||||||
Net income per limited partner unit – subordinated units | $ | 0.49 | $ | 0.17 | $ | 1.09 | $ | 0.97 | ||||||||
As discussed in Note 7, the class B units do not participate in income allocations until the third quarter 2008. As a result, no income allocations were made to the class B unit equity accounts and no assumed allocations to the class B units were made pursuant to EITF No. 03-6 for purpose of computing earnings per unit for the three and six month periods ended June 30, 2008.
In the six month periods ended June 30, 2008 and 2007, the Partnership declared quarterly distributions per unit to unitholders of record, including common and subordinated units and the 2% general partner interest and IDRs held by its general partner as follows (in millions, except distribution per unit):
| Payable Date | Distribution per Unit | Amount Paid to Limited Partner Unitholders | Amount Paid to General Partner Unitholders (Including IDRs) | |||||||||
| May 12, 2008 | $ | 0.465 | $ | 57.6 | $ | 2.9 | ||||||
| February 25, 2008 | 0.460 | 56.9 | 2.7 | |||||||||
| May 14, 2007 | 0.430 | 50.0 | 1.5 | |||||||||
| February 27, 2007 | 0.415 | 45.0 | 1.2 | |||||||||
In July 2008, the Partnership declared a quarterly cash distribution to unitholders of record of $0.47 per unit.
Note 9: Property, Plant and Equipment
In 2008, the Partnership placed in service the remaining pipeline assets and related compression associated with the East Texas to Mississippi Expansion project from Delhi, Louisiana to Harrisville, Mississippi. Additionally, the Partnership placed in service the pipeline assets and one compressor station related to the Southeast Expansion project. As a result, approximately $912.9 million was transferred from Construction work in progress to Property, plant and equipment during the six months ended June 30, 2008. The assets will generally be depreciated over a term of 35 years.
In the first quarter 2008, the Partnership completed a review of the non-contiguous offshore assets of its Gulf South subsidiary and provided notice to the other interest holders of its intent to discontinue any use of its portion of the available capacity of these assets. As a result, the Partnership reviewed the assets for recoverability in accordance with SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, and recorded an impairment charge of approximately $1.4 million representing the net book value of the related assets.
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The Partnership was developing a salt dome storage cavern near Napoleonville, Louisiana. Operational tests, which were completed in July 2007, indicated that due to geological and other anomalies that could not be corrected, the Partnership would be unable to place the cavern in service as expected. As a result, the Partnership elected to abandon that cavern and is exploring the possibility of securing a new site on which a new cavern could be developed. In accordance with the requirements of SFAS No. 144, the carrying value of the cavern and related facilities was tested for recoverability. In the second quarter 2007, the Partnership recognized an impairment charge to earnings of approximately $14.7 million, representing the carrying value of the cavern, the fair value of which was determined to be zero based on discounted expected future cash flows. The charge was presented as Asset impairment on the Condensed Consolidated Statements of Income.
Note 10: Credit Concentration
Natural gas price volatility has increased dramatically in recent years, which has materially increased credit risk related to gas loaned to customers. Gas loaned to customers refers to receivables for services provided, as well as volumes owed by customers for imbalances or gas lent by the Partnership to them, generally under parking and lending and no-notice services. As of June 30, 2008, the amount of gas loaned out by the Partnership’s subsidiaries was approximately 20.1 TBtu and the amount considered an imbalance was approximately 4.2 TBtu. Assuming an average market price during June 2008 of $12.54 per million British thermal units, the market value of gas loaned out and considered an imbalance at June 30, 2008, would have been approximately $304.8 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 11: Employee Benefits
Defined Benefit Plans
Texas Gas employees hired prior to November 1, 2006, are covered under a non-contributory, defined benefit pension plan. 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. Texas Gas provides postretirement medical benefits and life insurance to retired employees who were employed full time, hired prior to January 1, 1996, and have met certain other requirements. The Partnership uses a measurement date of December 31 for its benefits plans.
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Components of net periodic benefit cost for both the retirement plans and postretirement benefits other than pensions (PBOP) for the three and six months ended June 30, 2008 and 2007, were the following (in millions):
| Retirement Plans | PBOP | |||||||||||||||
For the Three Months Ended June 30, | For the Three Months Ended June 30, | |||||||||||||||
| 2008 | 2007 | 2008 | 2007 | |||||||||||||
| Service cost | $ | 0.9 | $ | 0.9 | $ | 0.1 | $ | 0.1 | ||||||||
| Interest cost | 1.6 | 1.6 | 0.8 | 0.7 | ||||||||||||
| Expected return on plan assets | (1.7 | ) | (1.7 | ) | (1.2 | ) | (1.2 | ) | ||||||||
| Amortization of prior service credit | - | - | (1.9 | ) | (1.9 | ) | ||||||||||
| Amortization of unrecognized net loss | - | 0.1 | - | - | ||||||||||||
| Settlement charge | - | 0.7 | - | - | ||||||||||||
| Regulatory asset decrease | - | - | 1.3 | 1.4 | ||||||||||||
| Net periodic pension expense | $ | 0.8 | $ | 1.6 | $ | (0.9 | ) | $ | (0.9 | ) | ||||||
| Retirement Plans | PBOP | |||||||||||||||
For the Six Months Ended June 30, | For the Six Months Ended June 30, | |||||||||||||||
| 2008 | 2007 | 2008 | 2007 | |||||||||||||
| Service cost | $ | 1.8 | $ | 1.9 | $ | 0.3 | $ | 0.3 | ||||||||
| Interest cost | 3.2 | 3.2 | 1.6 | 1.6 | ||||||||||||
| Expected return on plan assets | (3.3 | ) | (3.6 | ) | (2.5 | ) | (2.3 | ) | ||||||||
| Amortization of prior service credit | - | - | (3.9 | ) | (3.9 | ) | ||||||||||
| Amortization of unrecognized net loss | - | 0.2 | 0.1 | 0.3 | ||||||||||||
| Settlement charge | - | 3.8 | - | - | ||||||||||||
| Regulatory asset decrease | - | - | 2.7 | 2.7 | ||||||||||||
| Net periodic pension expense | $ | 1.7 | $ | 5.5 | $ | (1.7 | ) | $ | (1.3 | ) | ||||||
Defined Contribution Plans
Gulf South employees and Texas Gas employees hired on or after November 1, 2006, are provided retirement benefits under a defined contribution money purchase plan. The operating subsidiaries also provide 401(k) plan benefits to their employees. Costs related to the Partnership’s defined contribution plans were $1.5 million and $3.1 million for the three and six months ended June 30, 2008, and $1.3 million and $2.6 million for the three and six months ended June 30, 2007.
Note 12: Related Parties
Loews provides a variety of corporate services to the Partnership and its subsidiaries under service agreements. Services provided by Loews include, among others, information technology, tax, risk management, internal audit and corporate development services. Loews charged $3.4 million and $7.5 million for the three and six months ended June 30, 2008, and $2.4 million and $6.6 million for the three and six months ended June 30, 2007, to the Partnership based on the actual time spent by Loews personnel performing these services, plus related expenses.
Distributions paid related to common and subordinated units held by BPHC and the 2% general partner interest and IDRs held by Boardwalk GP were $85.5 million and $75.6 million during the six months ended June 30, 2008 and 2007.
The Partnership pays franchise and certain other taxes on behalf of BPHC and records a note receivable from BPHC for the amounts paid, which is settled quarterly. The notes accrue interest at London Interbank Offered Rate plus one percent. For the three and six months ended June 30, 2008, the Partnership paid $1.2 million and $1.3 million on behalf of BPHC. For the three and six months ended June 30, 2007, the Partnership paid $0.4 million and $0.9 million on behalf of BPHC. A note receivable of $2.7 million remained at June 30, 2008.
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Note 13: Accumulated Other Comprehensive (Loss) Income
The following table shows the components of Accumulated other comprehensive loss, net of tax which is included in Partners’ Capital on the Condensed Consolidated Balance Sheets (in millions):
As of June 30, | As of December 31, | |||||||
| 2008 | 2007 | |||||||
| Loss on cash flow hedges | $ | (38.7 | ) | $ | (8.9 | ) | ||
| Deferred components of net periodic benefit cost | 8.7 | 13.1 | ||||||
| Total Accumulated other comprehensive (loss) income | $ | (30.0 | ) | $ | 4.2 | |||
Note 14: 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 make loans to the Partnership and had no restricted assets at June 30, 2008.
Note 15: Recently Issued Accounting Pronouncements
In March 2008, the Financial Accounting Standards Board (FASB) issued SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities, which requires entities to provide enhanced disclosures about (a) how and why the entity uses derivative instruments, (b) how derivative instruments and related hedged items are accounted for under SFAS No. 133 and its related interpretations, and (c) how derivative instruments and related hedged items affect the entity’s financial position, financial performance, and cash flows. SFAS No. 161 is effective for fiscal years and interim periods beginning after November 15, 2008. The Partnership is evaluating the effect that SFAS No. 161 will have on its financial statements.
In March 2008, the FASB approved EITF Issue No. 07-4, Application of the Two-Class Method under FASB Statement No. 128, Earnings per Share, to Master Limited Partnerships, which requires that master limited partnerships use the two-class method of allocating earnings to calculate earnings per unit. EITF Issue No. 07-4 is effective for fiscal years and interim periods beginning after December 15, 2008. The Partnership is evaluating the effect that EITF Issue No. 07-4 will have on its earnings per unit and financial statements.
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The following discussion and analysis of financial condition and results of operations should be read in conjunction with our accompanying interim condensed consolidated financial statements and related notes, included elsewhere in this report and prepared in accordance with accounting principles generally accepted in the United States of America and our consolidated financial statements, related notes, Management's Discussion and Analysis of Financial Condition and Results of Operations and Risk Factors included in our Annual Report on Form 10-K for the year ended December 31, 2007.
We are a Delaware limited partnership formed in 2005. Our business is 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, operating subsidiaries) and Gulf Crossing Pipeline Company, LLC (Gulf Crossing), which will operate a new interstate pipeline expected to be placed in service in 2009. Boardwalk Pipelines Holding Corp. (BPHC), a wholly-owned subsidiary of Loews Corporation (Loews), owns 53.3 million of our common units, 22.9 million of our class B units and 33.1 million of our subordinated units. Boardwalk GP, LP (Boardwalk GP), an indirect, wholly-owned subsidiary of BPHC, is our general partner and holds a 2% general partner interest in and all of our incentive distribution rights. Our common units are traded under the symbol “BWP” on the New York Stock Exchange.
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 discounts from the maximum allowable cost-based rates are often granted to customers due to competition in the marketplace. Our Gulf South subsidiary is authorized to charge market-based rates for its firm and interruptible storage services. In first quarter 2008, our Texas Gas subsidiary was provided authority from FERC to charge market-based rates for the storage services associated with Phase III of our Western Kentucky Storage Expansion project.
Our transportation services consist of firm transportation, where the customer pays a capacity reservation charge to reserve pipeline capacity at certain receipt and delivery points along our pipeline systems, plus a commodity and fuel charge on the volume actually transported, and interruptible transportation, where the customer pays to transport gas only when capacity is available and used. We offer firm storage services in which the customer reserves and pays for a specific amount of storage capacity, including injection and withdrawal rights, and interruptible storage and parking and lending (PAL) services where the customer receives and pays for capacity only when it is available and used. Some PAL agreements are paid for at inception of the service and revenues for these agreements are recognized as service is provided over the term of the agreement.
Our operating costs and expenses typically do not vary significantly based upon the amount of gas transported, with the exception of fuel consumed at Gulf South’s compressor stations, which is part of Operation and maintenance expenses. We charge shippers for fuel in accordance with each pipeline’s individual tariff guidelines and Gulf South’s fuel recoveries are included as part of Gas transportation revenues.
We are not in the business of buying and selling natural gas other than for system management purposes, but changes in the price of natural gas can affect the overall supply and demand of natural gas, which in turn does affect our results of operations. We deliver to a broad mix of customers including local distribution companies, 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, midwestern and southeastern United States through interconnections with unaffiliated pipelines.
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Our business is affected by trends involving natural gas price levels and natural gas price spreads, including spreads between physical locations on our pipeline system, which affects our transportation revenues, and spreads in natural gas prices across time (for example summer to winter), which primarily affects our PAL and storage revenues. High natural gas prices in recent years have helped to drive increased production levels in producing locations such as the Bossier Sands and Barnett Shale gas producing regions in East Texas, which has resulted in additional supply being available on the west side of our system. This has resulted in widened west-to-east basis differentials which have benefited our transportation revenues. The high natural gas prices have also driven increased production in regions such as the Fayetteville Shale in Arkansas and the Caney Woodford Shale in Oklahoma, which, together with the higher production levels in East Texas, have formed the basis for several pipeline expansion projects including those being undertaken by us. Wide spreads in natural gas prices between time periods during the past two to three years, for example fall 2006 to spring 2007, were favorable for our PAL and interruptible storage services during that period. These spreads decreased substantially in 2007 and have continued to decrease into 2008, which resulted in reduced PAL and interruptible storage revenues. We cannot predict future time period spreads or basis differentials.
Results of Operations for the Three Months Ended June 30, 2008 and 2007
Our net income for the second quarter 2008 increased $29.3 million, or 83%, from the comparable period in 2007. The primary drivers for the increase were higher revenues from firm transportation services associated with our expansion projects and gains on gas sales and mark-to-market derivative activity associated with our expansion projects. The favorable drivers were partly offset by lower PAL revenues due to unfavorable natural gas price spreads, and higher depreciation and property taxes due to an increase in our asset base from expansion. The 2007 period was unfavorably impacted by an impairment charge.
Operating revenues increased $39.8 million, or 26%, to $190.3 million for the second quarter 2008, compared to $150.5 million for the 2007 period. The primary increase related to a $28.0 million increase in gas transportation revenues, excluding fuel, of which the majority was generated by our expansion projects. Our fuel revenues increased $16.9 million due to expansion-related throughput and an increase in the price of natural gas. Gas storage revenues increased $3.1 million related to an increase in storage capacity associated with our Western Kentucky Storage Expansion project. These increases were partially offset by an $8.2 million decrease in PAL due to unfavorable natural gas price spreads.
Operating costs and expenses increased $3.1 million, or 3%, to $109.3 million for the second quarter 2008, compared to $106.2 million for the 2007 period, primarily resulting from a $17.0 million increase in fuel costs from expansion projects and higher natural gas prices. Depreciation and other taxes increased $13.9 million due to an increase in our asset base from expansion. The increased expenses were offset by a $13.3 million gain on the sale of gas related to our Western Kentucky Storage Expansion project. The 2007 period was unfavorably impacted by a $14.7 million impairment charge related to our Magnolia storage facility.
Total other deductions increased by $7.4 million, or 85%, to $16.1 million for the second quarter 2008, compared to $8.7 million for the 2007 period as a result of increased interest expense due to issuances of debt in March 2008 and August 2007 and increased borrowings under our revolving credit facility. These amounts were partly offset by a $4.8 million gain from the mark-to-market effect of derivatives associated with the purchase of line pack for our pipeline expansion projects.
Results of Operations for the Six Months Ended June 30, 2008 and 2007
Our net income for the first six months of 2008 increased $37.1 million, or 32%, from the comparable period in 2007. The primary drivers for the increase were higher revenues from firm transportation services associated with our expansion projects, gains on gas sales and mark-to-market derivative activity associated with our expansion projects, and a gain from the settlement of a contract claim. The favorable drivers were partly offset by lower PAL revenues due to unfavorable natural gas price spreads and higher depreciation and property taxes due to an increase in our asset base from expansion. The 2007 period was unfavorably impacted by an impairment charge.
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Operating revenues for the six months ended June 30, 2008, increased $48.9 million, or 14%, to $387.6 million, compared to $338.7 million for the six months ended June 30, 2007. Gas transportation revenues, excluding fuel, increased $45.2 million related to our expansion projects and higher rates on our existing systems. Fuel revenues increased $19.1 million due to expansion-related throughput and higher natural gas prices. Gas storage revenues increased $6.1 million related to an increase in storage capacity associated with our Western Kentucky Storage Expansion project. These increases were partially offset by lower PAL revenues of $21.5 million due to unfavorable natural gas price spreads.
Operating costs and expenses for the six months ended June 30, 2008, increased $3.1 million, or 2%, to $205.1 million, compared to $202.0 million for the six months ended June 30, 2007. The primary drivers were increased depreciation and other taxes of $25.4 million associated with an increase in our asset base due to expansion and increased fuel costs of $21.0 million from expansion projects and higher natural gas prices. These increases were offset by a $15.4 million gain on the sale of gas related to our Western Kentucky Storage Expansion project and an $11.2 million gain from the settlement of a contract claim. The 2007 period was unfavorably impacted by a $14.7 million impairment charge related to our Magnolia storage facility.
Total other deductions increased by $8.6 million, or 42%, to $29.2 million for the six months ended June 30, 2008, compared to $20.6 million for the 2007 period as a result of increased interest expense due to issuances of new debt in March 2008 and August 2007 and increased borrowings under our revolving credit facility. These amounts were partially offset by a $7.9 million mark-to-market gain from derivatives associated with the purchase of line pack for our pipeline expansion projects.
Liquidity and Capital Resources
We are a partnership holding company and derive all of our operating cash flow from our operating subsidiaries. Our operating 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 the operating subsidiaries and, as needed, borrowings under its revolving credit facility discussed below, to service its outstanding indebtedness and, when available, make distributions or advances to us to fund our distributions to unitholders.
Expansion Capital Expenditures
We completed our East Texas to Mississippi expansion project during the second quarter of 2008 at a total cost of approximately $960.1 million. This project consists of approximately 242 miles of 42-inch pipeline from DeSoto Parish in western Louisiana to near Harrisville, Mississippi. Customers have contracted at fixed rates for 1.4 billion cubic feet (Bcf) per day of firm transportation capacity on a long-term basis which represents substantially all of the normal operating capacity.
We are currently engaged in several pipeline expansion projects, described below, and expect the estimated total cost of these projects to be as follows (in millions):
Estimated Cost at March 31, 2008 | Subsequent Costs | Estimated Total Cost | Cash Invested through June 30, 2008 | |||||||||||||
| Southeast Expansion | $ | 775 | - | $ | 775 | $ | 553.6 | |||||||||
| Gulf Crossing Project | 1,690 | $ | 110 | 1,800 | 504.7 | |||||||||||
| Fayetteville and Greenville Laterals | 1,250 | 40 | 1,290 | 260.9 | ||||||||||||
| Total | $ | 3,715 | $ | 150 | (a) | $ | 3,865 | $ | 1,319.2 | |||||||
(a) These costs are related to the addition of compression to increase the transmission capacity to approximately 1.7 Bcf per day on the Gulf Crossing project and 1.3 Bcf per day on the Fayetteville Lateral. The additional capacity is required to accommodate commitments made under new transportation agreements. We expect the additional compression to be in service in 2010. |
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Based upon our current cost estimates, we expect to incur expansion project capital expenditures of approximately $1.8 billion for the remainder of 2008 and $0.7 billion in 2009 and 2010 to complete our pipeline expansion projects. We expect to finance our pipeline expansion capital costs through equity financings and the incurrence of debt, including sales of debt by us and our subsidiaries and borrowings under our revolving credit facility, as well as available operating cash flow in excess of our operating needs.
Our total estimated cost assumes that we will receive the regulatory approvals necessary to operate the pipelines on certain of our projects at higher pressures, which will allow us to utilize a higher percentage of the pipeline capacity. Delays in receipt of these approvals will result in higher costs and additional delays in our expected in-service dates, which would also result in delays of revenues we would have received had these delays not occurred, and in certain instances will result in the payment of penalties to certain customers. Our cost and timing estimates for these projects are subject to a variety of other risks and uncertainties, including adverse weather conditions, delays in obtaining key materials, shortages of qualified labor and escalating costs of labor and materials. Please refer to Item 1A, Risk Factors, in our 2007 Form 10-K regarding risks associated with our expansion projects and the related financing.
The following paragraphs describe each of our pipeline expansion projects in more detail:
Southeast Expansion. The pipeline and one compressor station related to this project were placed in service during the second quarter 2008. The project consists of approximately 111 miles of 42-inch pipeline originating near Harrisville, Mississippi and extending to an interconnect with Transcontinental Pipe Line Company (Transco) in Choctaw County, Alabama (Transco 85), having 1.2 Bcf of peak-day transmission capacity. We expect to expand the project through the addition of compression facilities to 2.2 Bcf of peak-day transmission capacity. We expect this additional capacity to be in service during the first quarter 2009 to coincide with the commencement of service on our Gulf Crossing project. Customers have contracted at fixed rates for 660 million cubic feet (MMcf) per day of firm transportation capacity on a long-term basis (with a weighted-average term of 9.2 years), in addition to a capacity lease agreement with Gulf Crossing discussed below.
Gulf Crossing Project. We are constructing a new interstate pipeline that will begin near Sherman, Texas and proceed to the Perryville, Louisiana area and will consist of approximately 357 miles of 42-inch pipeline having approximately 1.7 Bcf of peak-day transmission capacity with the addition of compression facilities. Additionally, Gulf Crossing has entered into, subject to regulatory approval: (i) a capacity lease agreement for 1.1 Bcf per day of capacity on our Gulf South pipeline system (including capacity on the Southeast Expansion and capacity on a portion of the East Texas to Mississippi Expansion) to make deliveries to an interconnect with Transco 85; and (ii) a capacity lease agreement with Enogex, a third-party intrastate pipeline, which will bring gas supplies to our system. Customers have contracted at fixed rates for 1.7 Bcf per day of long-term firm transportation capacity (with a weighted average term of approximately 9.5 years). We expect the pipeline to be in service during the first quarter 2009 and the additional compression to be in service by 2010.
Fayetteville and Greenville Laterals. We are constructing two laterals on our Texas Gas pipeline system to transport gas from the Fayetteville Shale area in Arkansas to markets directly and indirectly served by our existing interstate pipelines. The Fayetteville Lateral will originate in Conway County, Arkansas and proceed southeast through the Bald Knob, Arkansas area to an interconnect with the Texas Gas mainline in Coahoma County, Mississippi and consists of approximately 165 miles of 36-inch pipeline. The Greenville Lateral will originate at the Texas Gas mainline near Greenville, Mississippi and proceeds east to the Kosciusko, Mississippi area consisting of approximately 95 miles of 36-inch pipeline. The Greenville Lateral will allow customers to access additional markets, primarily in the Midwest, Northeast and Southeast. We recently executed contracts for additional capacity that will require us to add compression to increase the peak-day transmission capacity to approximately 1.3 Bcf for the Fayetteville Lateral and to approximately 1.0 Bcf for the Greenville Lateral. The contracts associated with this project are at fixed rates with a weighted average term of 9.9 years. We expect the first 60 miles of the Fayetteville Lateral to be in service during the third quarter 2008 and the remainder of the pipeline related to the Fayetteville and Greenville Laterals to be in service during the first quarter 2009. We expect to make additional filings with FERC during the third quarter 2008 regarding the additional compression required to increase the peak-day transmission capacity and expect the additional capacity to be in service during 2010.
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We are also engaged in the following storage expansion project:
Western Kentucky Storage Expansion Phase III. We are developing up to 8.3 Bcf of new working gas capacity at our Midland storage facility and FERC has granted us market-based rate authority for this new capacity. This expansion is supported by 10-year precedent agreements for 5.1 Bcf of storage capacity. The cost of this project will be dependent on the ultimate size of the expansion. We expect 5.4 Bcf of storage capacity to be in service during the fourth quarter 2008. Through June 30, 2008, we spent $15.8 million related to this project.
Maintenance Capital Expenditures
Maintenance capital expenditures for the six months ended June 30, 2008 and 2007, were $13.2 million and $18.0 million. We expect to fund the remaining 2008 maintenance capital expenditures of approximately $45.0 million from our operating cash flows.
Distributions
For the six months ended June 30, 2008 and 2007, we paid distributions of $120.1 million and $97.7 million. Please see Note 8 in Part 1 in Item 1 of this report for further discussion.
Equity and Debt Financing
In June 2008, we issued and sold approximately 22.9 million of class B units representing limited partner interests (class B units) to BPHC for $30.00 per class B unit, or an aggregate purchase price of $686.0 million pursuant to the Class B Unit Purchase Agreement (the Purchase Agreement). Our general partner also contributed $14.0 million to us to maintain its 2% general partner interest. We used the proceeds of $700.0 million to repay amounts borrowed under the revolving credit facility and to fund a portion of the costs of our ongoing expansion projects. Please see Note 7 in Part 1 in Item 1 of this report for further discussion.
In June 2008, we completed a public offering of 10.0 million of our common units at a price of $25.30 per unit. We received proceeds of approximately $248.5 million, net of underwriting discounts and offering expenses of $9.7 million, which includes approximately $5.2 million contributed by our general partner to maintain its 2% interest.
In March 2008, we received net proceeds of approximately $247.2 million after deducting initial purchaser discounts and offering expenses of $2.8 million from the sale of $250.0 million of 5.50% senior unsecured notes of Texas Gas due April 1, 2013.
Revolving Credit Facility
We maintain a $1.0 billion revolving credit facility under which Boardwalk Pipelines, Gulf South and Texas Gas each may borrow funds, up to applicable sub-limits. Interest on amounts drawn under the credit facility is payable at a floating rate equal to an applicable spread per annum over the London Interbank Offered Rate or a base rate defined as the greater of the prime rate or the Federal funds rate plus 50 basis points. Under the terms of the agreement, each of the borrowers must maintain a minimum ratio, as of the last day of each fiscal quarter, of consolidated total debt to consolidated earnings before income taxes, depreciation and amortization (as defined in the agreement), measured for the preceding twelve months, of not more than five to one. The revolving credit facility has a maturity date of June 29, 2012.
During the six month period ended June 30, 2008, we borrowed and repaid $518.0 million under the facility of which the weighted average interest rate on the borrowings was 2.87%. As of June 30, 2008, we were in compliance with all covenant requirements under our credit agreement and no funds were drawn under this facility, however, at June 30, 2008, we had outstanding letters of credit under the facility for $57.6 million to support certain obligations associated with the pipeline expansion projects which reduced the available capacity under the facility by such amount.
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Changes in cash flow from operating activities
Net cash provided by operating activities remained relatively unchanged at $171.6 million for the six months ended June 30, 2008 compared to the comparable 2007 period. Cash generated from the increase in net income, excluding non cash items, of $39.0 million was offset by a decrease in cash due to an increase in receivables of $30.8 million and the settlement of derivatives.
Changes in cash flow from investing activities
Net cash used in investing activities increased $702.7 million to $1,081.9 million for the six months ended June 30, 2008, compared to $379.2 million for the comparable 2007 period, primarily due to capital expenditures related to our expansion projects.
Changes in cash flow from financing activities
Net cash provided by financing activities increased $879.4 million to $1,075.6 million for the six months ended June 30, 2008, compared to $196.2 million for the comparable 2007 period, primarily due to a $901.8 million increase in net proceeds from the sale of common and class B units and related general partner capital contributions and net proceeds from the issuance of long-term debt in March 2008. These increases were offset by a $22.4 million decrease in cash from an increase in distributions to our unitholders and general partner.
Contractual Obligations
The table below is updated for significant changes in contractual cash payment obligations as of June 30, 2008, by period (in millions):
| Total | Less than 1 Year | 1-3 Years | 4-5 Years | More than 5 Years | ||||||||||||||||
| Principal payments on long-term debt | $ | 2,110.0 | - | - | $ | 225.0 | $ | 1,885.0 | ||||||||||||
| Interest on long-term debt | 981.0 | $ | 59.5 | $ | 234.9 | 235.0 | 451.6 | |||||||||||||
| Capital commitments | 451.2 | 429.4 | 21.8 | - | - | |||||||||||||||
| Pipeline capacity agreements | 60.6 | 3.1 | 12.3 | 12.3 | 32.9 | |||||||||||||||
| Total | $ | 3,602.8 | $ | 492.0 | $ | 269.0 | $ | 472.3 | $ | 2,369.5 | ||||||||||
The commitments related to pipeline capacity agreements are associated with the initial 10-year term for capacity on a third-party pipeline for the Southeast Expansion project. Pursuant to the settlement of the Texas Gas rate case in 2006, we are required to annually fund an amount to the Texas Gas pension plan equal to the amount of actuarially determined net periodic pension cost, including a minimum of $3.0 million. The above table does not reflect commitments we have made after June 30, 2008, relating to our expansion projects. For information on these projects, please read “Expansion Capital Expenditures” above.
Off-Balance Sheet Arrangements
At June 30, 2008, 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.
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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 in our financial statements. We evaluate these estimates on an ongoing basis, utilizing historical experience, consultation with third parties and other methods we consider reasonable. Nevertheless, actual results may differ significantly from our estimates. Any effects on our business, financial position or results of operations resulting from revisions to these estimates are recorded in the periods in which the facts that give rise to the revisions become known.
During the six months ended June 30, 2008, there were no significant changes to our critical accounting policies, judgments or estimates disclosed in our Annual Report on Form 10-K for the year ended December 31, 2007.
Forward-Looking Statements
Investors are cautioned that certain statements contained in this report, as well as some statements in periodic press releases and some oral statements made by our officials and our subsidiaries during presentations about us, are “forward-looking.” Forward-looking statements include, without limitation, any statement that may project, indicate or imply future results, events, performance or achievements, and may contain the words “expect,” “intend,” “plan,” “anticipate,” “estimate,” “believe,” “will likely result,” and similar expressions. In addition, any statement made by our management concerning future financial performance (including future revenues, earnings or growth rates), ongoing business strategies or prospects, and possible actions by our partnership or its subsidiaries, are also forward-looking statements.
Forward-looking statements are based on current expectations and projections about future events and are inherently subject to a variety of risks and uncertainties, many of which are beyond our control that could cause actual results to differ materially from those anticipated or projected. These risks and uncertainties include, among others:
| · | We may not complete projects, including growth or expansion projects, that we have commenced or will commence, or we may complete projects on materially different terms, cost or timing than anticipated and we may not be able to achieve the intended economic or operational benefits of any such 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 or equipment, weather, difficulties or delays in obtaining regulatory approvals or denied applications, land owner opposition, the lack of adequate materials, labor difficulties or shortages, expansion costs that are higher than anticipated and numerous other factors beyond our control. |
| · | We may not complete any future debt or equity financing transaction. |
| · | 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 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. |
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Because of the natural decline in gas production connected to our system, 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.
| · | 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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Our debt has been issued at fixed rates, therefore interest expense would not be impacted by changes in interest rates. Total long-term debt at June 30, 2008, had a carrying value of $2.1 billion and a fair value of $2.0 billion. A 100 basis point increase in interest rates on our fixed rate debt would result in a decrease in fair value of approximately $123.6 million at June 30, 2008. A 100 basis point decrease would result in an increase in fair value of approximately $133.6 million at June 30, 2008. The weighted-average interest rate of our long-term debt was 5.89% at June 30, 2008.
Certain volumes of our gas stored underground are available for sale and subject to commodity price risk. At June 30, 2008 and December 31, 2007, approximately $15.0 million and $16.3 million of gas stored underground, which we own and carry as current Gas stored underground, is exposed to commodity price risk. We utilize derivatives to hedge certain exposures to market price fluctuations on the anticipated operational sales of gas.
As a result of the approval of Phase III of the Western Kentucky storage expansion project in the first quarter 2008, approximately 5.1 Bcf of gas stored underground became available for sale, approximately 2.9 Bcf of which remained unsold at June 30, 2008. We entered into derivatives to hedge the price exposure related to the expected sale of this gas, which derivatives were designated as cash flow hedges.
In the second quarter 2007, we entered into natural gas price swaps to hedge exposure to prices associated with the purchase of 2.1 Bcf of natural gas to be used for line pack for our pipeline expansion projects, of which approximately 1.3 Bcf remained outstanding at June 30, 2008. The derivatives were not designated as hedges and were marked to fair value through earnings resulting in a gain of $4.1 million and $7.2 million for the three and six months ended June 30, 2008. Changes in the fair value of the derivatives will be recognized in earnings each quarter until settlement. The changes in the fair value of the gas purchased for line pack will not be recognized in earnings each quarter. When the gas is purchased, the ultimate cost will be recorded to Property, Plant and Equipment along with the other capital components of the projects and recognized in earnings as the property is depreciated. A $1.00 increase in the price of New York Mercantile Exchange natural gas futures, would result in the recognition of a $1.3 million gain in earnings. Conversely, a $1.00 decrease would result in the recognition of a $1.3 million loss.
With the exception of the derivatives related to certain storage gas volumes related to Phase II of the Western Kentucky Storage Expansion project and line pack gas purchases referred to above, the derivatives related to the sale or purchase of natural gas, cash for fuel reimbursement and debt issuance generally qualify for cash flow hedge accounting under Statement of Financial Accounting Standards (SFAS) No. 133 and are designated as such. The effective component of related 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 loss. The deferred gains and losses are recognized in the Condensed Consolidated Statements of Income when the anticipated transactions affect earnings. In situations where continued reporting of a loss in accumulated other comprehensive income would result in recognition of a future loss on the combination of the derivative and the hedged transaction, SFAS No. 133 requires that the loss be immediately recognized in earnings for the amount that is not expected to be recovered. We reclassified losses of $1.7 million for the three and six months ended June 30, 2008, from Accumulated other comprehensive loss to earnings related to amounts that are not expected to be recovered in future periods from the combination of sales of gas stored underground and the deferred losses associated with related derivatives.
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 projects, any gains and losses on the related derivatives would be recognized in Net gain on disposal of operating assets and related contracts. Any gains and losses on the derivatives related to the line pack gas purchases would be recognized in Miscellaneous other income, net.
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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. 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, 2008, the amount of gas loaned out by our subsidiaries was approximately 20.1 trillion British thermal units (TBtu) and the amount considered an imbalance was approximately 4.2 TBtu. Assuming an average market price during June 2008 of $12.54 per million British thermal units (MMBtu), the market value of gas loaned out and considered an imbalance at June 30, 2008, would have been approximately $304.8 million. As of December 31, 2007, the amount of gas loaned out by our subsidiaries was approximately 12.7 TBtu and the amount considered an imbalance was approximately 2.5 TBtu. Assuming an average market price during December 2007 of $7.13 per MMBtu, the market value of gas loaned out at December 31, 2007, would have been approximately $108.2 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, 2008, our cash and cash equivalents were invested primarily in mutual funds or treasury bills. 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 earnings or cash flows to be materially impacted by the effect of a sudden change in market interest rates on our investment portfolio.
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Disclosure Controls and Procedures
We maintain a system of disclosure controls and procedures which is designed to ensure that information required to be disclosed by us in reports that we file or submit under the federal securities laws, including this report is recorded, processed, summarized and reported on a timely basis. These disclosure controls and procedures include controls and procedures designed to ensure that information required to be disclosed by us under the federal securities laws is accumulated and communicated to us on a timely basis to allow decisions regarding required disclosure.
Our principal executive officer (CEO) and principal financial officer (CFO) undertook an evaluation of our disclosure controls and procedures as of the end of the period covered by this report. The CEO and CFO have concluded that our controls and procedures were effective as of June 30, 2008.
Changes in Internal Control over Financial Reporting
There were no changes in our internal control over financial reporting that occurred during the quarter ended June 30, 2008, that have materially affected or that are reasonably likely to materially affect our internal control over financial reporting.
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PART II – OTHER INFORMATION
For a discussion of certain of our current legal proceedings, please see Note 6 in Part 1 in Item 1 of this report.
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Exhibit Number | ||
| Description |
| 3.1 | Third Amended and Restated Agreement of Limited Partnership of Boardwalk Pipeline Partners, LP dated June 17, 2008 (Incorporated by reference to Exhibit 3.1 to Boardwalk Pipeline Partners, LP Current Report on Form 8-K filed on June 18, 2008). | |
| 4.1 | Registration Rights Agreement dated June 17, 2008, by and between Boardwalk Pipeline Partners, LP and Boardwalk Pipelines Holding Corp. (Incorporated by reference to Exhibit 4.1 to Boardwalk Pipeline Partners, LP Current Report on Form 8-K filed on June 18, 2008). | |
| 10.1 | Class B Unit Purchase Agreement dated April 24, 2008, by and between Boardwalk Pipeline Partners, LP and Boardwalk Pipelines Holding Corp. (Incorporated by reference to Exhibit 10.1 to Boardwalk Pipeline Partners, LP Current Report on Form 8-K filed on April 24, 2008). | |
| *10.2 | Separation Agreement and General Release between John C. Earley, Jr. and Gulf South Pipeline Company, LP, Gulf Crossing Pipeline Company LLC, Texas Gas Transmission, LLC, Boardwalk GP, LLC and Boardwalk Operating GP, LLC | |
| *31.1 | Certification of Rolf A. Gafvert, Chief Executive Officer, pursuant to Rule 13a-14(a) and Rule 15d-14(a). | |
| *31.2 | Certification of Jamie L. Buskill, Chief Financial Officer, pursuant to Rule 13a-14(a) and Rule 15d-14(a). | |
| *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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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: July 29, 2008 | By: | /s/ Jamie L. Buskill | |||||||
| Jamie L. Buskill | |||||||||
| Senior Vice President, Chief Financial Officer and Treasurer | |||||||||