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EX-32 - EX-32 - TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLCc63700exv32.htm
EX-31.1 - EX-31.1 - TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLCc63700exv31w1.htm
EX-31.2 - EX-31.2 - TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLCc63700exv31w2.htm
 
 
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
     
þ   QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 2011
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 1-7584
TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC
(Exact Name of Registrant as Specified in Its Charter)
     
Delaware   74-1079400
(State or Other Jurisdiction of   (I.R.S. Employer
Incorporation or Organization)   Identification No.)
     
2800 Post Oak Boulevard    
Houston, Texas   77056
(Address of Principal Executive Offices)   (Zip Code)
(713-215-2000)
Registrant’s Telephone Number, Including Area Code
No Change
(Former Name, Former Address and Former Fiscal Year, if Changed Since Last Report)
     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 þ No o
     Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes o No o
     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 o Accelerated filer o Non-accelerated filer þ
(Do not check if a smaller reporting company)
Smaller reporting company o
     Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No þ
REGISTRANT MEETS THE CONDITIONS SET FORTH IN GENERAL INSTRUCTIONS H (1)(a) AND (b) OF FORM 10-Q AND IS THEREFORE FILING THIS FORM 10-Q WITH THE REDUCED DISCLOSURE FORMAT.
 
 

 


 

TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC
INDEX
         
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Forward Looking Statements
     Certain matters contained in this report include “forward-looking statements” within the meaning of section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. These forward-looking statements relate to anticipated financial performance, management’s plans and objectives for future operations, business prospects, outcome of regulatory proceedings, market conditions and other matters. We make these forward-looking statements in reliance on the safe harbor protections provided under the Private Securities Litigation Reform Act of 1995.
     All statements, other than statements of historical facts, included in this report that address activities, events or developments that we expect, believe or anticipate will exist or may occur in the future, are forward-looking statements. Forward-looking statements can be identified by various forms of words such as “anticipates,” “believes,” “seeks,” “could,” “may,” “should,” “continues,” “estimates,” “expects,” “forecasts,” “intends,” “might,” “goals,” “objectives,” “targets,” “planned,” “potential,” “projects,” “scheduled,” “will,” or other similar expressions. These forward-looking statements are based on

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management’s beliefs and assumptions and on information currently available to management and include, among others, statements regarding:
    Amounts and nature of future capital expenditures;
 
    Expansion and growth of our business and operations;
 
    Financial condition and liquidity;
 
    Business strategy;
 
    Cash flow from operations or results of operations;
 
    Rate case filings; and
 
    Natural gas prices and demand.
     Forward-looking statements are based on numerous assumptions, uncertainties and risks that could cause future events or results to be materially different from those stated or implied in this report. Many of the factors that will determine these results are beyond our ability to control or predict. Specific factors which could cause actual results to differ from results contemplated by the forward-looking statements include, among others, the following:
    Availability of supplies (including the uncertainties inherent in assessing and estimating future natural gas reserves), market demand, volatility of prices, and the availability and cost of capital;
 
    Inflation, interest rates and general economic conditions (including future disruptions and volatility in the global credit markets and the impact of these events on our customers and suppliers);
 
    The strength and financial resources of our competitors;
 
    Development of alternative energy sources;
 
    The impact of operational and development hazards;
 
    Cost of, changes in, or the results of laws, government regulations (including proposed climate change legislation), environmental liabilities, litigation and rate proceedings;
 
    Our allocated costs for defined benefit pension plans and other postretirement benefit plans sponsored by our affiliates;
 
    Changes in maintenance and construction costs;
 
    Changes in the current geopolitical situation;

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    Our exposure to the credit risk of our customers;
 
    Risks related to strategy and financing, including restrictions stemming from our debt agreements, future changes in our credit rating and the availability and cost of credit;
 
    Risks associated with future weather conditions;
 
    Acts of terrorism; and
 
    Additional risks described in our filings with the Securities and Exchange Commission (SEC).
     Given the uncertainties and risk factors that could cause our actual results to differ materially from those contained in any forward-looking statement, we caution investors not to unduly rely on our forward-looking statements. We disclaim any obligations to and do not intend to update the above list or to announce publicly the result of any revisions to any of the forward-looking statements to reflect future events or developments.
     In addition to causing our actual results to differ, the factors listed above and referred to below may cause our intentions to change from those statements of intention set forth in this report. Such changes in our intentions may also cause our results to differ. We may change our intentions, at any time and without notice, based upon changes in such factors, our assumptions or otherwise.
     Because forward-looking statements involve risks and uncertainties, we caution that there are important factors, in addition to those listed above, that may cause actual results to differ materially from those contained in the forward-looking statements. For a detailed discussion of those factors, see Part I, Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2010, and Part II, Item 1A. Risk Factors of this Form 10-Q.

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PART 1 — FINANCIAL INFORMATION.
ITEM 1. Financial Statements.
TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC
CONDENSED CONSOLIDATED STATEMENT OF INCOME
(Thousands of Dollars)
(Unaudited)
                 
    Three Months Ended  
    March 31,  
    2011     2010  
 
               
Operating Revenues:
               
Natural gas sales
  $ 27,042     $ 27,722  
Natural gas transportation
    240,376       234,315  
Natural gas storage
    36,820       37,188  
Other
    1,118       1,824  
 
           
Total operating revenues
    305,356       301,049  
 
           
 
               
Operating Costs and Expenses:
               
Cost of natural gas sales
    27,042       27,722  
Cost of natural gas transportation
    11,364       8,529  
Operation and maintenance
    59,435       58,852  
Administrative and general
    42,786       35,116  
Depreciation and amortization
    64,243       62,494  
Taxes — other than income taxes
    13,535       12,508  
Other (income) expense, net
    (9,850 )     1,193  
 
           
Total operating costs and expenses
    208,555       206,414  
 
           
 
               
Operating Income
    96,801       94,635  
 
           
 
               
Other (Income) and Other Deductions:
               
Interest expense
    23,822       23,547  
Interest income — affiliates
    (10 )     (2,162 )
Allowance for equity and borrowed funds used during construction (AFUDC)
    (5,337 )     (2,568 )
Equity in earnings of unconsolidated affiliates
    (1,318 )     (1,541 )
Miscellaneous other (income) deductions, net
    (2,145 )     1,236  
 
           
Total other (income) and other deductions
    15,012       18,512  
 
           
 
               
Income before Income Taxes
    81,789       76,123  
 
               
Provision for Income Taxes
    103       129  
 
           
 
               
Net Income
  $ 81,686     $ 75,994  
 
           
See accompanying notes.

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TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC
CONDENSED CONSOLIDATED BALANCE SHEET
(Thousands of Dollars)
(Unaudited)
                 
    March 31,     December 31,  
    2011     2010  
 
               
ASSETS
               
 
               
Current Assets:
               
Cash
  $ 107     $ 148  
Receivables:
               
Affiliates
    2,654       4,921  
Advances to affiliates
    180,898       108,838  
Others, less allowance of $406 ($406 in 2010)
    102,851       110,434  
Transportation and exchange gas receivables
    5,892       2,417  
Inventories
    80,592       85,425  
Regulatory assets
    45,343       48,444  
Other
    6,330       13,132  
 
           
Total current assets
    424,667       373,759  
 
           
 
               
Investments, at cost plus equity in undistributed earnings
    47,927       43,753  
 
           
 
               
Property, Plant and Equipment:
               
Natural gas transmission plant
    7,769,754       7,674,366  
Less-Accumulated depreciation and amortization
    2,707,123       2,650,133  
 
           
Total property, plant and equipment, net
    5,062,631       5,024,233  
 
           
 
               
Other Assets:
               
Regulatory assets
    199,019       198,921  
Other
    57,195       59,223  
 
           
Total other assets
    256,214       258,144  
 
           
 
               
Total assets
  $ 5,791,439     $ 5,699,889  
 
           
See accompanying notes.

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TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC
CONDENSED CONSOLIDATED BALANCE SHEET (Continued)
(Thousands of Dollars)
(Unaudited)
CONDENSED CONSOLIDATED BALANCE SHEET
                 
    March 31,     December 31,  
    2011     2010  
 
               
LIABILITIES AND OWNER’S EQUITY
               
 
               
Current Liabilities:
               
Payables:
               
Affiliates
  $ 24,872     $ 18,769  
Other
    97,821       92,647  
Transportation and exchange gas payables
    1,585       1,646  
Accrued liabilities
    122,401       119,125  
Current maturities of long-term debt
    299,959       299,932  
 
           
Total current liabilities
    546,638       532,119  
 
           
 
               
Long-Term Debt
    980,302       980,018  
 
           
 
               
Other Long-Term Liabilities:
               
Asset retirement obligations
    220,516       220,644  
Regulatory liabilities
    115,958       115,563  
Other
    6,548       6,785  
 
           
Total other long-term liabilities
    343,022       342,992  
 
           
 
               
Contingent liabilities and commitments (Note 2)
               
 
               
Owner’s Equity:
               
Member’s capital
    1,767,434       1,727,434  
Retained earnings
    2,153,839       2,117,153  
Accumulated other comprehensive income
    204       173  
 
           
Total owner’s equity
    3,921,477       3,844,760  
 
           
 
               
Total liabilities and owner’s equity
  $ 5,791,439     $ 5,699,889  
 
           
See accompanying notes.

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TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC
CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS
(Thousands of Dollars)
(Unaudited)
                 
    Three Months Ended March 31,  
    2011     2010  
Cash flows from operating activities:
               
Net income
  $ 81,686     $ 75,994  
Adjustments to reconcile net income to net cash provided by (used in) operating activities
               
Depreciation and amortization
    64,321       62,323  
Allowance for equity funds used during construction (Equity AFUDC)
    (3,704 )     (1,718 )
Changes in operating assets and liabilities:
               
Receivables — affiliates
    2,267       4,229  
— others
    7,583       17,523  
Transportation and exchange gas receivables
    (3,475 )     (6,149 )
Inventories
    4,976       (16,316 )
Payables — affiliates
    6,103       (22,867 )
— others
    7,527       4,997  
Transportation and exchange gas payables
    (61 )     3,050  
Accrued liabilities
    5,869       (10,646 )
Other, net
    3,779       12,392  
 
           
Net cash provided by operating activities
    176,871       122,812  
 
           
 
               
Cash flows from financing activities:
               
Cash distributions
    (45,000 )     (203,791 )
Cash contribution from parent
    40,000        
Other, net
    (6,032 )     (6,022 )
 
           
Net cash used in financing activities
    (11,032 )     (209,813 )
 
           
 
               
Cash flows from investing activities:
               
Property, plant and equipment additions, net of equity AFUDC*
    (84,626 )     (56,189 )
Disposal of property, plant and equipment, net
    (8,508 )     5,401  
Advances to affiliates, net
    (72,060 )     140,067  
Purchase of long-term investments
    (5,914 )      
Purchase of ARO trust investments
    (4,576 )     (5,696 )
Proceeds from sale of ARO trust investments
    7,841       3,391  
Other, net
    1,963       105  
 
           
Net cash provided by (used in) investing activities
    (165,880 )     87,079  
 
           
 
               
Net increase (decrease) in cash
    (41 )     78  
Cash at beginning of period
    148       108  
 
           
Cash at end of period
  $ 107     $ 186  
 
           
 
               
* Increases to property, plant and equipment
  $ (85,712 )   $ (38,377 )
Changes in related accounts payable and accrued liabilities
    1,086       (17,812 )
 
           
Property, plant and equipment additions, net of equity AFUDC
  $ (84,626 )   $ (56,189 )
 
           
See accompanying notes.

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TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
1. BASIS OF PRESENTATION.
     In this report, Transco (which includes Transcontinental Gas Pipe Line Company, LLC and unless the context otherwise requires, all of our majority-owned subsidiaries) is at times referred to in the first person as “we,” “us” or “our.” Unless the context clearly indicates otherwise, references to “we,” “us,” and “our” include the operations of Cardinal Pipeline Company, LLC (Cardinal) and Pine Needle LNG Company, LLC (Pine Needle) in which we own interests accounted for as equity investments. When we refer to Cardinal and Pine Needle by name, we are referring exclusively to their respective businesses and operations.
General.
     The condensed consolidated financial statements include our accounts and the accounts of the subsidiaries we control. Companies in which we and our subsidiaries own 20 percent to 50 percent of the voting common stock or otherwise exercise significant influence over operating and financial policies of the company are accounted for under the equity method. The equity method investments as of March 31, 2011 and December 31, 2010 consist of Cardinal with ownership interest of approximately 45 percent and Pine Needle with ownership interest of 35 percent. We received distributions associated with our equity method investments totaling $3.1 million and $0.5 million in the three months ended March 31, 2011 and March 31, 2010, respectively. We made capital contributions to Cardinal related to Cardinal’s expansion project totaling $5.9 million in the three months ended March 31, 2011, and $2.3 million in April 2011.
     The condensed consolidated financial statements have been prepared from our books and records. Certain information and footnote disclosures normally included in financial statements prepared in accordance with U.S. generally accepted accounting principles (GAAP) have been condensed or omitted in this Form 10-Q pursuant to SEC rules and regulations. The condensed consolidated unaudited financial statements include all normal recurring adjustments and others which, in the opinion of our management, are necessary to present fairly our financial position at March 31, 2011, and results of operations for the three months ended March 31, 2011 and 2010, and cash flows for the three months ended March 31, 2011 and 2010. These condensed consolidated financial statements should be read in conjunction with the consolidated financial statements and the notes thereto included in our 2010 Annual Report on Form 10-K.
     Through an agency agreement, Williams Gas Marketing, Inc. (WGM), our affiliate, manages our remaining jurisdictional merchant gas sales, which excludes our cash out sales in settlement of gas imbalances. The long-term purchase agreements managed by WGM remain in our name, as do the corresponding sales of such purchased gas. Therefore, we continue to record natural gas sales revenues and the related accounts receivable and cost of natural gas sales and the related accounts payable for the jurisdictional merchant sales that are managed by WGM. WGM receives all margins associated with jurisdictional merchant gas sales business and assumes all market and credit risk associated with our jurisdictional merchant gas sales. Consequently, our merchant gas sales service has no impact on our operating income or results of operations.

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     The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported in the condensed consolidated financial statements and accompanying notes. Actual results could differ from those estimates.
     Certain reclassifications from non-operating income to operating income, related to oil and gas royalties of $0.8 million for the three months ended March 31, 2010, have been made to the 2010 financial statements to conform to the 2011 presentation.
2. CONTINGENT LIABILITIES AND COMMITMENTS.
Rate Matters
     On August 31, 2006, we submitted to the Federal Energy Regulatory Commission (FERC) a general rate filing (Docket No. RP06-569) designed to recover increased costs. The rates became effective March 1, 2007, subject to refund and the outcome of a hearing. All issues in this proceeding except one have been resolved by settlement.
     The one issue reserved for litigation or further settlement relates to our proposal to change the design of the rates for service under one of our storage rate schedules, which was implemented subject to refund on March 1, 2007. A hearing on that issue was held before a FERC Administrative Law Judge (ALJ) in July 2008. In November 2008, the ALJ issued an initial decision in which he determined that our proposed incremental rate design is unjust and unreasonable. On January 21, 2010, the FERC reversed the ALJ’s initial decision, and approved our proposed incremental rate design. Two parties have requested rehearing of the FERC’s order. If the FERC were to reverse their opinion on rehearing, we believe any refunds would not be material to our results of operations.
Environmental Matters
     We have had studies underway to test some of our facilities for the presence of toxic and hazardous substances to determine to what extent, if any, remediation may be necessary. We have responded to data requests from the U.S. Environmental Protection Agency (EPA) and state agencies regarding such potential contamination of certain of our sites. On the basis of the findings to date, we estimate that environmental assessment and remediation costs under various federal and state statutes will total approximately $7 million to $9 million (including both expense and capital expenditures), measured on an undiscounted basis, and will be spent over the next four to six years. This estimate depends on a number of assumptions concerning the scope of remediation that will be required at certain locations and the cost of the remedial measures. We are conducting environmental assessments and implementing a variety of remedial measures that may result in increases or decreases in the total estimated costs. At March 31, 2011, we had a balance of approximately $3.7 million for the expense portion of these estimated costs recorded in current liabilities ($0.8 million) and other long-term liabilities ($2.9 million) in the accompanying Condensed Consolidated Balance Sheet. At December 31, 2010, we had a balance of approximately $3.8 million for the expense portion of these estimated costs recorded in current liabilities ($0.8 million) and other long-term liabilities ($3.0 million) in the accompanying Condensed Consolidated Balance Sheet.
     Although we discontinued the use of lubricating oils containing polychlorinated biphenyls (PCBs) in the 1970s, we have discovered residual PCB contamination in equipment and soils at certain gas compressor station sites. We have worked closely with the EPA and state regulatory authorities regarding PCB issues, and we have a program to assess and remediate such conditions where they exist. In

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addition, we commenced negotiations with certain environmental authorities and other parties concerning investigative and remedial actions relative to potential mercury contamination at certain gas metering sites. All such costs are included in the $7 million to $9 million range discussed above.
     We have been identified as a potentially responsible party (PRP) at various Superfund and state waste disposal sites. Based on present volumetric estimates and other factors, our estimated aggregate exposure for remediation of these sites is less than $0.5 million. The estimated remediation costs for all of these sites are included in the $7 million to $9 million range discussed above. Liability under the Comprehensive Environmental Response, Compensation and Liability Act (and applicable state law) can be joint and several with other PRPs. Although volumetric allocation is a factor in assessing liability, it is not necessarily determinative; thus, the ultimate liability could be substantially greater than the amounts described above.
     We are also subject to the Federal Clean Air Act (Act) and to the Federal Clean Air Act Amendments of 1990 (1990 Amendments), which added significantly to the existing requirements established by the Act. Pursuant to requirements of the 1990 Amendments and EPA rules designed to mitigate the migration of ground-level ozone (NOx), we are planning installation of air pollution controls on existing sources at certain facilities in order to reduce NOx emissions. For many of these facilities, we are developing more cost effective and innovative compressor engine control designs.
     In March 2008, the EPA promulgated a new, lower National Ambient Air Quality Standard (NAAQS) for ground-level ozone. Within two years, the EPA was expected to designate new eight-hour ozone non-attainment areas. However, in September 2009, the EPA announced it would reconsider the 2008 NAAQS for ground level ozone to ensure that the standards were clearly grounded in science and were protective of both public health and the environment. As a result, the EPA delayed designation of new eight-hour ozone non-attainment areas under the 2008 standards until the reconsideration is complete. In January 2010, the EPA proposed to further reduce the ground-level ozone NAAQS from the March 2008 levels. The EPA currently anticipates finalization of the new ground-level ozone standard in the third quarter of 2011. Designation of new eight-hour ozone non-attainment areas are expected to result in additional federal and state regulatory actions that will likely impact our operations and increase the cost of additions to property, plant and equipment. We are unable at this time to estimate the cost of additions that may be required to meet this new regulation.
     Additionally, in August 2010, the EPA promulgated National Emission Standards for hazardous air pollutants (NESHAP) regulations that will impact our operations. The emission control additions required to comply with the hazardous air pollutant regulations are estimated to include costs in the range of $25 million to $30 million through 2013, the compliance date.
     Furthermore, the EPA promulgated the Greenhouse Gas (GHG) Mandatory Reporting Rule on October 30, 2009, which requires facilities that emit 25,000 metric tons or more carbon dioxide (CO2) equivalent per year from stationary fossil-fuel combustion sources to report GHG emissions to the EPA annually beginning March 31, 2011 for calendar year 2010. On March 18, 2011, EPA extended this reporting deadline to September 30, 2011. On November 30, 2010, the EPA issued additional regulations that expand the scope of the Mandatory Reporting Rule to include fugitive and vented greenhouse gas emissions effective January 1, 2011. Facilities that emit 25,000 metric tons or more CO2 equivalent per year from stationary fossil-fuel combustion and fugitive/vented sources combined will be required to report GHG combustion and fugitive/vented emissions to the EPA annually beginning March 31, 2012 for calendar year 2011. Compliance with this reporting obligation is estimated to cost $7 million to $9 million over the next four to five years.

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     In February 2010, the EPA promulgated a final rule establishing a new one-hour nitrogen dioxide (NO2) NAAQS. The effective date of the new NO2 standard was April 12, 2010. This new standard is subject to numerous challenges in the federal court. We are unable at this time to estimate the cost of additions that may be required to meet this new regulation.
     We consider prudently incurred environmental assessment and remediation costs and the costs associated with compliance with environmental standards to be recoverable through rates. To date, we have been permitted recovery of environmental costs, and it is our intent to continue seeking recovery of such costs through future rate filings. As a result, as estimated costs of environmental assessment and remediation are incurred, they are recorded as regulatory assets in the Consolidated Balance Sheet until collected through rates. However, we had no uncollected environmental related regulatory assets at March 31, 2011 or December 31, 2010.
     By letter dated September 20, 2007, the EPA required us to provide information regarding natural gas compressor stations in the states of Mississippi and Alabama as part of the EPA’s investigation of our compliance with the Act. By January 2008, we responded with the requested information. By Notices of Violation (NOVs) dated March 28, 2008, the EPA found us to be in violation of the requirements of the Act with respect to these compressor stations. We met with the EPA in May 2008 to discuss the allegations contained in the NOVs; in June 2008, we submitted to the EPA a written response denying the allegations. The EPA has requested additional information pertaining to these compressor stations, most recently in February 2011. In August, 2010, the EPA requested, and we provided, similar information for a compressor station in Maryland.
Safety Matters
     Pipeline Integrity Regulations We have developed an Integrity Management Plan that we believe meets the United States Department of Transportation Pipeline and Hazardous Materials Safety Administration (PHMSA) final rule that was issued pursuant to the requirements of the Pipeline Safety Improvement Act of 2002. The rule requires gas pipeline operators to develop an integrity management program for transmission pipelines that could affect high consequence areas in the event of pipeline failure. The Integrity Management Program includes a baseline assessment plan along with periodic reassessments to be completed within required timeframes. In meeting the integrity regulations, we have identified high consequence areas and developed our baseline assessment plan. We are on schedule to complete the required assessments within required timeframes. Currently, we estimate that the cost to complete the required initial assessments over the period of 2011 through 2012 and associated remediation will be primarily capital in nature and range between $80 million and $110 million. Ongoing periodic reassessments and initial assessments of any new high consequence areas will be completed within the timeframes required by the rule. Management considers the costs associated with compliance with the rule to be prudent costs incurred in the ordinary course of business and, therefore, recoverable through our rates.
     Appomattox, Virginia Pipeline Rupture On September 14, 2008, we experienced a rupture of our 30-inch diameter mainline B pipeline near Appomattox, Virginia. The rupture resulted in an explosion and fire which caused several minor injuries and property damage to several nearby residences. On September 25, 2008, PHMSA issued a Corrective Action Order (CAO) which required that we operate three of our mainlines in a portion of Virginia at reduced operating pressure and prescribed various remedial actions. After completion of some of the remedial actions PHMSA approved our requests to restore the affected pipelines to normal operating pressure. By letter dated April 29, 2010, PHMSA

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confirmed that the remaining remedial actions should be completed by December 31, 2010. This deadline was subsequently extended by PHMSA to September 30, 2011. In 2009, PHMSA proposed, and we paid, a $1.0 million civil penalty related to this matter.
Other Matters
     Various other proceedings are pending against us incidental to our operations.
Summary
     Litigation, arbitration, regulatory matters, environmental matters and safety matters are subject to inherent uncertainties. Were an unfavorable ruling to occur, there exists the possibility of a material adverse impact on the results of operations in the period in which the ruling occurs. Management, including internal counsel, currently believes that the ultimate resolution of the foregoing matters, taken as a whole and after consideration of amounts accrued, insurance coverage, recovery from customers or other indemnification arrangements will not have a material adverse effect upon our future liquidity or financial position.
Other Commitments
     Commitments for construction and gas purchases We have commitments for construction and acquisition of property, plant and equipment of approximately $187 million at March 31, 2011. We have commitments for gas purchases of approximately $31 million at March 31, 2011. See Note 1 for our discussion of our agency agreement with WGM.
3. DEBT AND FINANCING ARRANGEMENT.
Revolving Credit and Letter of Credit Facility.
     We participate in a $1.75 billion three-year senior unsecured revolving credit facility (Credit Facility) with Williams Partners L.P. (WPZ) and Northwest Pipeline GP (“Northwest”), as co-borrowers, and Citibank N.A., as administrative agent, and certain other lenders named therein. The full amount of the Credit Facility is available to WPZ, and may, under certain conditions, be increased by up to an additional $250 million. We may borrow up to $400 million under the Credit Facility to the extent not otherwise utilized by WPZ and Northwest. As of March 31, 2011, the full $400 million under the Credit Facility was available.
4. FAIR VALUE MEASUREMENTS.
     We are entitled to collect in rates the amounts necessary to fund our asset retirement obligations (ARO). We deposit monthly, into an external trust account, the revenues specifically designated for ARO. We established the ARO trust account (ARO Trust) on June 30, 2008. The ARO Trust carries a moderate risk portfolio. We measure the financial instruments held in our ARO Trust at fair value. However, in accordance with the ASC Topic 980, Regulated Operations, both realized and unrealized gains and losses of the ARO Trust are recorded as regulatory assets or liabilities.
     The fair value hierarchy prioritizes the inputs used to measure fair value, giving the highest priority to quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest

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priority to unobservable inputs (Level 3 measurements). We classify our ARO Trust within Level 1 of the hierarchy. Our ARO Trust consists of the following financial instruments (in millions):
                 
    March 31,     December 31,  
    2011     2010  
Money market funds
  $ 2.5     $ 1.6  
U.S. equity funds
    15.3       17.4  
International equity funds
    6.3       6.0  
Municipal bond funds
    14.1       15.4  
 
           
Total
  $ 38.2     $ 40.4  
 
           
     Reclassifications of fair value between Level 1, Level 2, and Level 3 of the fair value hierarchy, if applicable, are made at the end of each quarter. No such transfers occurred during the period ended March 31, 2011.
5. FINANCIAL INSTRUMENTS.
Fair value of financial instruments.
     The carrying amount and estimated fair values of our financial instruments as of March 31, 2011 and December 31, 2010 are as follow (in thousands);
                                 
    March 31, 2011     December 31, 2010  
    Carrying     Fair     Carrying     Fair  
    Amount     Value     Amount     Value  
Financial assets:
                               
Cash
  $ 107     $ 107     $ 148     $ 148  
Short-term financial assets
    181,045       181,045       108,985       108,985  
ARO Trust Investments
    38,158       38,158       40,413       40,413  
Long-term financial assets
    106       106       144       144  
Financial liabilities:
                               
Long-term debt, including current portion
    1,280,261       1,407,776       1,279,950       1,432,866  
     For cash and short-term financial assets (third-party notes receivable and advances to affiliates) that have variable interest rates, the carrying amount is a reasonable estimate of fair value due to the short maturity of those instruments. For ARO Trust investments, the ARO Trust invests in a moderate risk portfolio that is reported at fair value. For long-term financial assets (long-term receivables), the carrying amount is a reasonable estimate of fair value because the interest rate is a variable rate. The fair value of our publicly traded long-term debt is valued using period-end traded bond market prices.
6. TRANSACTIONS WITH AFFILIATES.
     Prior to The Williams Companies, Inc. (Williams) restructuring in February 2010, we were a participant in Williams’ cash management program, whereby we made advances to and received advances from Williams. The interest rate on these intercompany demand notes was based upon the weighted average cost of Williams’ debt outstanding at the end of each quarter. We received interest income from advances to Williams of $2.2 million during the three months ended March 31, 2010.

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     Subsequent to Williams’ restructuring in February 2010, we became a participant in WPZ’s cash management program, and we make advances to and receive advances from WPZ. At March 31, 2011 and December 31, 2010, the advances due us by WPZ totaled approximately $180.9 million and $108.8 million, respectively. The advances are represented by demand notes. The interest rate on these intercompany demand notes is based upon the daily overnight investment rate paid on WPZ’s excess cash at the end of each month. At March 31, 2011, the interest rate was 0.02 percent. The interest income from these advances to WPZ was minimal during the three months ended March 31, 2011 and March 31, 2010.
     Included in our operating revenues for the three months ending March 31, 2011 and 2010 are revenues received from affiliates of $4.3 million and $6.1 million, respectively. The rates charged to provide sales and services to affiliates are the same as those that are charged to similarly-situated nonaffiliated customers.
     Through an agency agreement with us, WGM manages our jurisdictional merchant gas sales. The agency fees billed by WGM for the three months ended March 31, 2011 and 2010 were not significant.
     Included in our cost of sales for the three months ended March 31, 2011 and 2010 is purchased gas cost from affiliates, excluding the agency fees discussed above, of $3.3 million and $1.5 million, respectively. All gas purchases are made at market or contract prices.
     We have long-term gas purchase contracts containing variable prices that are currently in the range of estimated market prices. Our estimated purchase commitments under such gas purchase contracts are not material to our total gas purchases. Furthermore, through the agency agreement with us, WGM has assumed management of our merchant sales service and, as our agent, is at risk for any above-spot market gas costs that it may incur.
     Williams has a policy of charging subsidiary companies for management services provided by the parent company and other affiliated companies. Included in our administrative and general expenses for the three months ended March 31, 2011 and 2010, are $14.0 million and $13.8 million, respectively, for such corporate expenses charged by Williams, WPZ, and other affiliated companies. Management considers the cost of these services to be reasonable.
     Pursuant to an operating agreement, we serve as contract operator on certain Williams Field Services Company (WFS) facilities. For the three months ended March 31, 2011 and 2010, we recorded reductions in operating expense of $1.1 million and $1.3 million, respectively, for services provided to and reimbursed by WFS under terms of the operating agreement.
     A distribution of $45.0 million was declared and paid during the quarter ended March 31, 2011. An additional distribution of $56.0 million was declared and paid in April 2011. Two distributions totaling approximately $203.8 million were declared and paid to Williams Gas Pipeline Company, LLC (WGP) and a $0.2 million non cash distribution was made to WGP during the quarter ended March 31, 2010. In the quarter ended March 31, 2011, Williams Partners Operating, LLC (WPO) made a $40.0 million contribution to us to fund a portion of our expenditures for additions to property, plant and equipment. In April 2011, WPO made an additional $46.0 million contribution.
     We have no employees. Services are provided to us by an affiliate, Transco Pipeline Services LLC (TPS), a Delaware limited liability company. On February 17, 2010, we entered into an administrative services agreement pursuant to which TPS will provide personnel, facilities, goods and equipment not

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otherwise provided by us that are necessary to operate our business. In return, we reimburse TPS for all direct and indirect expenses it incurs or payments it makes (including salary, bonus, incentive compensation and benefits) in connection with these services. We were billed $47.0 million and $28.3 million in the three months ended March 31, 2011 and 2010, respectively. Such expenses are primarily included in “Administrative and general” and “Operations and maintenance” expenses on the accompanying Condensed Consolidated Statement of Income.
7. COMPREHENSIVE INCOME.
     Comprehensive income is as follows (in thousands):
                 
    Three Months  
    Ended March 31,  
    2011     2010  
 
               
Net income
  $ 81,686     $ 75,994  
Equity interest in unrealized gain/(loss) on interest rate hedge
    31       23  
 
           
Total comprehensive income
  $ 81,717     $ 76,017  
 
           
ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
General.
     The following discussion should be read in conjunction with the Consolidated Financial Statements, Notes and Management’s Discussion and Analysis contained in Items 7 and 8 of our 2010 Annual Report on Form 10-K and with the Condensed Consolidated Financial Statements and Notes contained in this Form 10-Q.
RESULTS OF OPERATIONS.
Operating Income and Net Income.
     Operating income for the three months ended March 31, 2011 was $96.8 million compared to $94.6 million for the three months ended March 31, 2010. Net income for the three months ended March 31, 2011 was $81.7 million compared to $76.0 million for the three months ended March 31, 2010. The increase in Operating income of $2.2 million (2.3 percent) was primarily due to a $10.1 million reversal of project feasibility costs from expense to capital associated with the Northeast Supply Link Expansion Project and higher Natural gas transportation revenues in 2011 compared to 2010, partially offset by an increase in Operating Costs and Expenses. The increase in Net income of $5.7 million (7.5 percent) was mostly attributable to an increase in Operating income and a favorable change in Other (Income) and Other Deductions.
Transportation Revenues.
     Operating revenues: Natural gas transportation for the three months ended March 31, 2011 increased $6.1 million (2.6 percent) over the same period in 2010. The increase was primarily due to higher transportation demand revenues of $3.9 million, ($2.1 million from the Mobile Bay South project placed

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in service in May 2010 and $1.8 million from Phase I of our 85 North expansion placed in service in July 2010), and $2.9 million higher revenues which recover electric power and other costs. Electric power and certain other costs are recovered from customers through transportation rates resulting in no net impact on our operating income or results of operations. These increases were partially offset by a decrease of $0.7 million from lower commodity revenues resulting from declining production attached to our IT Feeder laterals.
Sales Revenues.
     Operating revenues: Natural gas sales decreased $0.7 million (2.5 percent) for the three months ended March 31, 2011 compared to the same period in 2010. The decrease was primarily due to lower cash out sales of $8.8 million, lower Hester base gas and Eminence excess top gas sales of $3.1 million and lower merchant sales of $0.8 million, partially offset by higher system management gas sales of $12.0 million. Cash out, system management gas, and merchant sales were offset in our cost of natural gas sold and therefore had no impact on our operating income or results of operations.
Operating Costs and Expenses.
     Excluding the Cost of natural gas sales, which is directly offset in revenues, of $27.0 million for the three months ended March 31, 2011 and $27.7 million for the comparable period in 2010, our operating costs and expenses for the three months ended March 31, 2011 increased approximately $2.9 million (1.6 percent) over the comparable period in 2010. This increase was primarily attributable to:
    A $2.9 million (34.1 percent) increase in Cost of natural gas transportation primarily due to higher electric power costs. Electric power costs are recovered from customers through transportation rates resulting in no net impact on our operating income or results of operations;
 
    A $7.7 million (21.9 percent) increase in Administrative and general costs primarily resulting from an increase in employee related benefit costs, and;
 
    A $1.7 million (2.7 percent) increase in Depreciation and amortization costs primarily resulting from an increase in the depreciation base due to additional plant placed in service in 2010.
 
    Partially offset by an $11.1 million favorable increase (925.0 percent) in Other (income) expense, net primarily due to a $10.1 million reversal of project feasibility costs from expense to capital associated with the Northeast Supply Link Expansion Project upon determining that the project was probable of development. These costs will be included in the capital costs of the project, which we believe are probable of recovery through the project rates.
Other (Income) and Other Deductions.
     Other (income) and other deductions for the three months ended March 31, 2011 decreased $3.5 million (18.9 percent) over the same period in 2010. The decrease was primarily due to higher Allowance for equity and borrowed funds used during construction (AFUDC) of $2.7 million due to higher construction spending in 2011 as compared to 2010 and lower Miscellaneous other (income) deductions, net of $3.3 million primarily due to a lower amount of reimbursements for tax gross-up related to reimbursable projects, partially offset by a $2.2 million decrease in Interest income — affiliates due to a lower rate on the note advance to WPZ.

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Eminence Storage Field Leak.
     On December 28, 2010, we detected a leak in one of the seven underground natural gas storage caverns at our Eminence Storage Field in Covington County, Mississippi. Since that time, we have reduced the pressure in the cavern by safely venting and flaring gas. Due to the leak at this cavern and damage to the well at an adjacent cavern, both caverns are out of service. To date, the event has not affected the performance of our obligations under our service agreements with our customers.
     As a result of these occurrences, we have determined that these two caverns cannot be returned to service. In addition, two other caverns at the field, which were constructed at or about the same time as those caverns, have experienced operating problems, and we have determined that they should be retired. Therefore, we intend to file an application seeking authorization from the FERC to abandon these four caverns. We estimate the cost to abandon the caverns, which will be capital in nature, will be approximately $38 million, which is expected to be spent in 2011 and the first half of 2012. This estimate is subject to change as work progresses and additional information becomes known. We will seek recovery of these costs, net of insurance proceeds, in future rate filings.
     In the first quarter of 2011, we incurred $3.6 million of expense related primarily to costs to ensure the safety of the surrounding area.
Capital Expenditures.
     Our capital expenditures for the three months ended March 31, 2011 were $84.6 million, compared to $56.2 million for the three months ended March 31, 2010. The $28.4 million increase is primarily due to higher spending on expansion projects in 2011. Our capital expenditures estimate for 2011 and future capital projects are discussed in our 2010 Annual Report Form 10-K. The following describes those projects and certain new capital projects proposed by us.
Mobile Bay South II Expansion Project
     The Mobile Bay South II Expansion Project involves the addition of compression at our Station 85 in Choctaw County, Alabama and modifications to existing facilities at our Station 83 in Mobile County, Alabama to allow us to provide additional firm transportation service southbound on the Mobile Bay line from Station 85 to various delivery points. In July 2010 we received approval from the FERC. The capital cost of the project is estimated to be approximately $35 million, and it provides 380 thousand dekatherms per day (Mdt/d) of incremental firm capacity. The project was placed into service on May 1, 2011.
85 North Expansion Project
     The 85 North Expansion Project involves an expansion of our existing natural gas transmission system from Station 85 in Choctaw County, Alabama to various delivery points as far north as North Carolina. In September 2009 we received approval from the FERC. The capital cost of the project is estimated to be approximately $227 million, and it provides 309 Mdt/d of incremental firm capacity. The first phase, for 90 Mdt/d, was placed into service in July 2010, and the second phase for the remaining 219 Mdt/d was placed into service on May 1, 2011.

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Pascagoula Expansion Project
     The Pascagoula Expansion Project involves the construction of a new pipeline to be jointly owned with Florida Gas Transmission connecting our existing Mobile Bay Lateral to the outlet pipeline of a LNG import terminal currently under construction in Mississippi. In July 2010 we received approval from the FERC. Our share of the capital cost of the project is estimated to be approximately $30 million. We plan to place the project into service in September 2011, and our share of its capacity will be 467 Mdt/d.
Mid-South Expansion Project
     The Mid-South Expansion Project involves an expansion of our mainline from Station 85 in Choctaw County, Alabama to markets as far downstream as North Carolina. In October 2010 we filed an application with the FERC. The capital cost of the project is estimated to be approximately $217 million. We plan to place the project into service in phases in September 2012 and June 2013, and it will increase capacity by 225 Mdt/d.
Mid-Atlantic Connector Project
     The Mid-Atlantic Connector Project involves an expansion of our mainline from an existing interconnection with East Tennessee Natural Gas in North Carolina to markets as far downstream as Maryland. In November 2010 we filed an application with the FERC. The capital cost of the project is estimated to be approximately $55 million. We plan to place the project into service in November 2012, and it will increase capacity by 142 Mdt/d.
Rockaway Delivery Lateral Project
     The Rockaway Delivery Lateral Project involves the construction of a three-mile offshore lateral to National Grid’s distribution system in New York. We anticipate filing an application with the FERC in 2012. The capital cost of the project is estimated to be approximately $182 million. We plan to place the project into service as early as April 2014, and its capacity will be 647 Mdt/d.
Northeast Connector Project
     The Northeast Connector Project involves an expansion of our existing natural gas transmission system from southeastern Pennsylvania to the proposed Rockaway Delivery Lateral. We anticipate filing an application with the FERC in 2012. The capital cost of the project is estimated to be approximately $39 million. We plan to place the project into service as early as April 2014, and it will increase capacity by 100 Mdt/d.
Northeast Supply Link Project
     The Northeast Supply Link Project involves an expansion of our existing natural gas transmission system from the Marcellus Shale production region on the Leidy Line to various delivery points in Zone 6. We anticipate filing an application with the FERC in the fourth quarter of 2011. The capital cost of the project is estimated to be approximately $341 million. We plan to place the project into service in November 2013, and it will increase capacity by 250 Mdt/d.

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ITEM 4. Controls and Procedures.
     Our management, including our Senior Vice President and our Vice President and Treasurer, does not expect that our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act) (Disclosure Controls) or our internal controls over financial reporting (Internal Controls) will prevent all errors and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within Transco have been detected. These inherent limitations include the realities that judgments in decision-making can be faulty, and that breakdowns can occur because of simple error or mistake. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of the control. The design of any system of controls also is based in part upon certain assumptions about the likelihood of future events and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions. Because of the inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected. We monitor our Disclosure Controls and Internal Controls and make modifications as necessary; our intent in this regard is that the Disclosure Controls and the Internal Controls will be modified as systems change and conditions warrant.
Evaluation of Disclosure Controls and Procedures
     An evaluation of the effectiveness of the design and operation of our Disclosure Controls was performed as of the period covered by this report. This evaluation was performed under the supervision and with the participation of our management, including our Senior Vice President and our Vice President and Treasurer. Based upon that evaluation, our Senior Vice President and our Vice President and Treasurer concluded that these Disclosure Controls are effective at a reasonable assurance level.
First Quarter 2011 Changes in Internal Controls
     There have been no changes during the first quarter of 2011 that have materially affected, or are reasonably likely to materially affect, our Internal Controls.

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PART II — OTHER INFORMATION.
ITEM 1.   LEGAL PROCEEDINGS.
     The information called for by this item is provided in Note 2 of the Notes to Condensed Consolidated Financial Statements included under Part I, Item 1. Financial Statements of this report, which information is incorporated by reference into this item.
ITEM 1A. RISK FACTORS.
     Part 1, Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2010, included certain risk factors that could materially affect our business, financial condition or future results. Those Risk Factors have not materially changed, except as set forth below:
Our costs of testing, maintaining or repairing our facilities may exceed our expectations and the FERC or competition in our markets may not allow us to recover such costs in the rates we charge for our services.
     We could experience unexpected leaks or ruptures on our gas pipeline system, or be required by regulatory authorities to test or undertake modifications to our systems that could result in a material adverse impact on our business, financial condition and results of operations if the costs of testing, maintaining or repairing our facilities exceed current expectations and the FERC or competition in our markets do not allow us to recover such costs in the rates we charge for our service. For example, in response to a recent third party pipeline rupture, PHMSA issued an Advisory Bulletin which, among other things, advises pipeline operators that if they are relying on design, construction, inspection, testing, or other data to determine the pressures at which their pipelines should operate, the records of that data must be traceable, verifiable and complete. Locating such records and, in the absence of any such records, verifying maximum pressures through physical testing or modifying or replacing facilities to meet the demands of such pressures, could significantly increase our costs.

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ITEM 6. EXHIBITS.
     The following instruments are included as exhibits to this report.
     
Exhibit Number   Description
 
   
2.1
  Certificate of Conversion dated December 22, 2008 and effective December 31, 2008. (filed on February 24, 2011 as Exhibit 2.1 to our report Form 10-K and incorporated herein by reference).
 
   
3.1
  Certificate of Formation dated December 22, 2008 and effective December 31, 2008. (filed on February 24, 2011 as Exhibit 3.1 to our report Form 10-K and incorporated herein by reference).
 
   
3.2
  Amended and Restated Operating Agreement of Transcontinental Gas Pipe Line Company, LLC dated February 17, 2010. (filed on October 28, 2010 as Exhibit 3.2 to our report Form 10-Q and incorporated herein by reference).
 
   
31.1*
  Certification of Principal Executive Officer pursuant to Rules 13a-14(a) and 15d-14(a) promulgated under the Securities Exchange Act of 1934, as amended, and Item 601(b)(31) of Regulation S-K, as adopted pursuant to Section 302 of The Sarbanes-Oxley Act of 2002.
 
   
31.2*
  Certification of Principal Financial Officer pursuant to Rules 13a-14(a) and 15d-14(a) promulgated under the Securities Exchange Act of 1934, as amended, and Item 601(b)(31) of Regulation S-K, as adopted pursuant to Section 302 of The Sarbanes-Oxley Act of 2002.
 
   
32 **
  Certification of Principal Executive Officer and Principal Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
 
*   Filed herewith.
 
**   Furnished herewith.

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SIGNATURE
     Pursuant to the requirements of the Securities Exchange Act 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
         
  TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC
(Registrant)
 
 
Dated: May 5, 2011  By:   /s/ Jeffrey P. Heinrichs    
    Jeffrey P. Heinrichs   
    Controller and Assistant Treasurer
(Principal Accounting Officer) 
 

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EXHIBIT INDEX.
     
Exhibit Number   Description
 
   
2.1
  Certificate of Conversion dated December 22, 2008 and effective December 31, 2008. (filed on February 24, 2011 as Exhibit 2.1 to our report Form 10-K and incorporated herein by reference).
 
   
3.1
  Certificate of Formation dated December 22, 2008 and effective December 31, 2008. (filed on February 24, 2011 as Exhibit 3.1 to our report Form 10-K and incorporated herein by reference).
 
   
3.2
  Amended and Restated Operating Agreement of Transcontinental Gas Pipe Line Company, LLC dated February 17, 2010. (filed on October 28, 2010 as Exhibit 3.2 to our report Form 10-Q and incorporated herein by reference).
 
   
31.1*
  Certification of Principal Executive Officer pursuant to Rules 13a-14(a) and 15d-14(a) promulgated under the Securities Exchange Act of 1934, as amended, and Item 601(b)(31) of Regulation S-K, as adopted pursuant to Section 302 of The Sarbanes-Oxley Act of 2002.
 
   
31.2*
  Certification of Principal Financial Officer pursuant to Rules 13a-14(a) and 15d-14(a) promulgated under the Securities Exchange Act of 1934, as amended, and Item 601(b)(31) of Regulation S-K, as adopted pursuant to Section 302 of The Sarbanes-Oxley Act of 2002.
 
   
32 **
  Certification of Principal Executive Officer and Principal Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
 
*   Filed herewith.
 
**   Furnished herewith.

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