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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, 2010
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 (State or Other Jurisdiction of Incorporation or Organization) | 74-1079400 (I.R.S. Employer Identification No.) | |
2800 Post Oak Boulevard P. O. Box 1396 Houston, Texas | 77251 | |
(Address of Principal Executive Offices) | (Zip Code) |
(713-215-2000)
Registrant’s Telephone Number, Including Area Code
Registrant’s Telephone Number, Including Area Code
No Change
(Former Name, Former Address and Former Fiscal Year, if Changed Since Last Report)
(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 or15(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. Yesþ Noo
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). Yeso 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 filero | Accelerated filero | Non-accelerated filerþ | Smaller reporting companyo | |||
(Do not check if a smaller reporting company) |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yeso Noþ
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
INDEX
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,”
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“scheduled,” “will,” or other similar expressions. These forward-looking statements are based on 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 publicity 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, 2009.
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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)
(Unaudited)
Three Months Ended | ||||||||
March 31, | ||||||||
2010 | 2009 | |||||||
(Restated) | ||||||||
Operating Revenues: | ||||||||
Natural gas sales | $ | 27,722 | $ | 13,019 | ||||
Natural gas transportation | 234,315 | 229,983 | ||||||
Natural gas storage | 37,188 | 36,489 | ||||||
Other | 1,020 | 10,269 | ||||||
Total operating revenues | 300,245 | 289,760 | ||||||
Operating Costs and Expenses: | ||||||||
Cost of natural gas sales | 27,722 | 13,018 | ||||||
Cost of natural gas transportation | 8,529 | 6,675 | ||||||
Operation and maintenance | 58,852 | 60,650 | ||||||
Administrative and general | 35,116 | 40,320 | ||||||
Depreciation and amortization | 62,494 | 60,925 | ||||||
Taxes – other than income taxes | 12,508 | 12,708 | ||||||
Other expense, net | 1,193 | 1,420 | ||||||
Total operating costs and expenses | 206,414 | 195,716 | ||||||
Operating Income | 93,831 | 94,044 | ||||||
Other (Income) and Other Deductions: | ||||||||
Interest expense | 23,547 | 23,489 | ||||||
Interest income – affiliates | (2,162 | ) | (4,267 | ) | ||||
Allowance for equity and borrowed funds used during construction (AFUDC) | (2,568 | ) | (2,129 | ) | ||||
Equity in earnings of unconsolidated affiliates | (1,541 | ) | (1,375 | ) | ||||
Miscellaneous other (income) deductions, net | 432 | (2,088 | ) | |||||
Total other (income) and other deductions | 17,708 | 13,630 | ||||||
Income before Income Taxes | 76,123 | 80,414 | ||||||
Provision for Income Taxes | 129 | — | ||||||
Net Income | $ | 75,994 | $ | 80,414 | ||||
See accompanying notes.
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TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC
CONDENSED CONSOLIDATED BALANCE SHEET
(Thousands of Dollars)
(Unaudited)
(Unaudited)
March 31, | December 31, | |||||||
2010 | 2009 | |||||||
ASSETS | ||||||||
Current Assets: | ||||||||
Cash | $ | 186 | $ | 108 | ||||
Receivables: | ||||||||
Affiliates | 2,394 | 5,132 | ||||||
Advances to affiliates | 95,770 | — | ||||||
Others, less allowance of $413 ($413 in 2009) | 99,625 | 117,148 | ||||||
Transportation and exchange gas receivables | 13,399 | 7,250 | ||||||
Inventories | 55,310 | 39,164 | ||||||
Regulatory assets | 69,083 | 75,016 | ||||||
Other | 5,741 | 11,792 | ||||||
Total current assets | 341,508 | 255,610 | ||||||
Investments, at cost plus equity in undistributed earnings | 46,553 | 45,488 | ||||||
Property, Plant and Equipment: | ||||||||
Natural gas transmission plant | 7,378,940 | 7,354,805 | ||||||
Less-Accumulated depreciation and amortization | 2,518,059 | 2,474,680 | ||||||
Total property, plant and equipment, net | 4,860,881 | 4,880,125 | ||||||
Other Assets: | ||||||||
Regulatory assets | 198,283 | 197,676 | ||||||
Other | 44,037 | 42,884 | ||||||
Total other assets | 242,320 | 240,560 | ||||||
Total assets | $ | 5,491,262 | $ | 5,421,783 | ||||
See accompanying notes.
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TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC
CONDENSED CONSOLIDATED BALANCE SHEET (Continued)
(Thousands of Dollars)
(Unaudited)
(Thousands of Dollars)
(Unaudited)
March 31, | December 31, | |||||||
2010 | 2009 | |||||||
LIABILITIES AND OWNER’S EQUITY | ||||||||
Current Liabilities: | ||||||||
Payables | ||||||||
Affiliates | $ | 19,387 | $ | 24,409 | ||||
Other | 73,713 | 88,780 | ||||||
Transportation and exchange gas payables | 4,484 | 1,434 | ||||||
Accrued liabilities | 83,647 | 116,226 | ||||||
Reserve for rate refunds | 882 | 564 | ||||||
Total current liabilities | 182,113 | 231,413 | ||||||
Long-Term Debt | 1,279,056 | 1,278,770 | ||||||
Other Long-Term Liabilities: | ||||||||
Asset retirement obligations | 233,170 | 229,401 | ||||||
Regulatory liabilities | 83,823 | 72,021 | ||||||
Accrued employee benefits | — | 6,476 | ||||||
Other | 8,990 | 9,145 | ||||||
Total other long-term liabilities | 325,983 | 317,043 | ||||||
Contingent liabilities and commitments (Note 3) | ||||||||
Owner’s Equity: | ||||||||
Member’s capital | 1,652,434 | 1,652,434 | ||||||
Loans to parent | — | (237,526 | ) | |||||
Retained earnings | 2,052,371 | 2,180,367 | ||||||
Accumulated other comprehensive loss | (695 | ) | (718 | ) | ||||
Total owner’s equity | 3,704,110 | 3,594,557 | ||||||
Total liabilities and owner’s equity | $ | 5,491,262 | $ | 5,421,783 | ||||
See accompanying notes.
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TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC
CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS
(Thousands of Dollars)
(Unaudited)
(Thousands of Dollars)
(Unaudited)
Three Months Ended March 31, | ||||||||
2010 | 2009 | |||||||
(Restated) | ||||||||
Cash flows from operating activities: | ||||||||
Net income | $ | 75,994 | $ | 80,414 | ||||
Adjustments to reconcile net income to net cash provided by (used in) operating activities | ||||||||
Depreciation and amortization | 62,323 | 61,278 | ||||||
Allowance for equity funds used during construction (Equity AFUDC) | (1,718 | ) | (1,416 | ) | ||||
Changes in operating assets and liabilities: | ||||||||
Receivables — affiliates | 4,229 | (9,964 | ) | |||||
— others | 17,523 | (12,636 | ) | |||||
Transportation and exchange gas receivables | (6,149 | ) | (2,008 | ) | ||||
Inventories | (16,316 | ) | (3,445 | ) | ||||
Payables — affiliates | (22,867 | ) | 9,726 | |||||
— others | 4,997 | 5,226 | ||||||
Transportation and exchange gas payables | 3,050 | 1,593 | ||||||
Accrued liabilities | (10,964 | ) | (43,129 | ) | ||||
Reserve for rate refunds | 318 | (12,523 | ) | |||||
Other, net | 12,392 | (10,028 | ) | |||||
Net cash provided by operating activities | 122,812 | 63,088 | ||||||
Cash flows from financing activities: | ||||||||
Change in cash overdrafts | (6,022 | ) | (5,420 | ) | ||||
Cash distributions | (203,791 | ) | — | |||||
Net cash used in financing activities | (209,813 | ) | (5,420 | ) | ||||
Cash flows from investing activities: | ||||||||
Property, plant and equipment additions, net of equity AFUDC* | (56,189 | ) | (22,333 | ) | ||||
Disposal of property, plant and equipment | 5,401 | 1,726 | ||||||
Advances to affiliates, net | 140,067 | (38,757 | ) | |||||
Purchase of ARO trust investments | (5,696 | ) | (8,041 | ) | ||||
Proceeds from sale of ARO trust investments | 3,391 | 10,237 | ||||||
Other, net | 105 | (727 | ) | |||||
Net cash provided by (used in) investing activities | 87,079 | (57,895 | ) | |||||
Net increase (decrease) in cash | 78 | (227 | ) | |||||
Cash at beginning of period | 108 | 428 | ||||||
Cash at end of period | $ | 186 | $ | 201 | ||||
* Increases to property, plant and equipment | $ | (38,377 | ) | $ | (22,398 | ) | ||
Changes in related accounts payable and accrued liabilities | (17,812 | ) | 65 | |||||
Property, plant and equipment additions, net of equity AFUDC | $ | (56,189 | ) | $ | (22,333 | ) | ||
Supplemental disclosures of significant non-cash transactions: | ||||||||
Loans to Parent reclassified to equity | $ | — | $ | (1,911 | ) |
See accompanying notes.
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TRANSCONTINENTAL GAS PIPE LINE COMPANY, LLC
NOTED TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
(Unaudited)
1. BASIS OF PRESENTATION.
Unless the context clearly indicates otherwise, references in this report to “we,” “us,” “our” or like terms refer to Transco and its majority-owned subsidiaries. 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 businesses and operations.
General.
On December 31, 2009, Transcontinental Gas Pipe Line Company, LLC (Transco) was a wholly-owned subsidiary of Williams Gas Pipeline Company, LLC (WGP). WGP was a wholly-owned subsidiary of The Williams Companies, Inc. (Williams). On February 17, 2010, Williams completed a strategic restructuring which involved contributing substantially all of its domestic midstream and pipeline businesses, which includes us, to Williams Partners L.P. (WPZ). WPZ, a master limited partnership with publicly traded units, is controlled by and consolidated with Williams. Effective February 17, 2010, we are a wholly owned subsidiary of WPZ, approximately 82 percent of whose limited partnership interests and all of whose general partnership interest as of such date were owned by Williams.
Effective September 2009, WGP contributed its ownership interests in the following entities to us: TransCardinal Company, LLC (TransCardinal), Cardinal Operating Company, LLC (Cardinal Operating), TransCarolina LNG Company, LLC (TransCarolina) and Pine Needle Operating Company, LLC (Pine Needle Operating). Accordingly, we have adjusted financial and operating information retrospectively to reflect the effects of these transactions.
The condensed consolidated financial statements include our accounts and the accounts of our majority-owned subsidiaries. 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, 2010 and December 31, 2009 consist of Cardinal with ownership interest of approximately 45 percent and Pine Needle with ownership interest of 35 percent. Distributions associated with our equity method investments were $0.5 million in the three months ended March 31, 2010. In addition, distributions totaling $1.3 million were received by WGP during the three months ended March 31, 2009 in which it owned the equity method investments.
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, 2010, and results of operations for the three months ended March 31, 2010 and 2009, and cash flows for the three months ended March 31, 2010 and 2009. These condensed consolidated financial statements should be read in
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conjunction with the consolidated financial statements and the notes thereto included in our 2009 Annual Report on Form 10-K.
As a participant in Williams’ cash management program, we made advances to and received advances from Williams. The advances were represented by demand notes. 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. In accordance with Williams’ restructuring of its business, our participation in the Williams’ cash management program terminated on February 28, 2010. On January 31, 2010, our Management Committee authorized a cash distribution which included the amount of our outstanding advances and associated interest receivable which was paid February 16, 2010. Accordingly, the note advance balance and related interest outstanding at December 31, 2009 were reflected as a reduction of our owner’s equity as the advances were not available to us as working capital. As a result of the restructuring, we became a participant in WPZ’s cash management program on March 1, 2010.
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, as our agent, 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.
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. Estimates and assumptions which, in the opinion of management, are significant to the underlying amounts included in the financial statements and for which it would be reasonably possible that future events or information could change those estimates include: 1) revenues subject to refund; 2) litigation-related contingencies; 3) environmental remediation obligations; 4) impairment assessments of long-lived assets; 5) depreciation; and 6) asset retirement obligations.
2. RESTATEMENT AND CHANGE IN REPORTING ENTITY.
As discussed in our 2009 Annual Report on Form 10-K, on January 20, 2010, we concluded that our financial statements for the year ended December 31, 2008 should be restated due to the manner in which we had presented and recognized pension and postretirement obligations in certain benefit plans for which Williams is the plan sponsor. We concluded that the impact of the error is not material to any of the three quarterly periods of 2009.
Effective September 2009, WGP contributed its ownership interests in the following entities to us: TransCardinal, Cardinal Operating, TransCarolina and Pine Needle Operating. These entities were transferred at historical cost, as the entities were under common control. No gains or losses were recorded as a result of the contributions. These changes were retrospectively applied to the financial statements. The impact of these retrospective adjustments to our net income and our comprehensive income for the three months ended March 31, 2009 was an increase of $1.4 million.
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3. CONTINGENT LIABILITIES AND COMMITMENTS.
Rate Matters.
On March 1, 2001, we submitted to the Federal Energy Regulatory Commission (FERC) a general rate filing (Docket No. RP01-245) to recover increased costs. All cost of service, throughput and throughput mix, cost allocation and rate design issues in this rate proceeding have been resolved by settlement or litigation. The resulting rates were effective from September 1, 2001 to March 1, 2007. A tariff matter in this proceeding has not yet been resolved.
On August 31, 2006, we submitted to the 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.
Environmental Matters.
Since 1989, 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 $8 million to $10 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, 2010, we had a balance of approximately $4.5 million for the expense portion of these estimated costs recorded in current liabilities ($0.8 million) and other long-term liabilities ($3.7 million) in the accompanying Condensed Consolidated Balance Sheet. At March 31, 2009, we had a balance of approximately $4.5 million for the expense portion of these estimated costs recorded in current liabilities ($0.9 million) and other long-term liabilities ($3.6 million).
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, these estimated costs of environmental assessment and remediation, less amounts collected, have been recorded as regulatory assets in Current Assets, in the accompanying Condensed Consolidated Balance sheet. At March 31, 2010 and 2009, we had recorded approximately $0.1 million and $1.3 million, respectively, of environmental related regulatory assets.
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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 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 $8 million to $10 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 $8 million to $10 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. We anticipate that additional facilities may be subject to increased controls within three years. For many of these facilities, we are developing more cost effective and innovative compressor engine control designs. Due to the developing nature of federal and state emission regulations, it is not possible to precisely determine the ultimate emission controls costs. However, the emission control additions required to comply with current Act requirements, the 1990 Amendments, the hazardous air pollutant regulations and the individual state implementation plans for NOx reductions are estimated to include costs in the range of $5 million to $10 million for the period 2010 through 2013. 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 August 2010 and anticipates designation of new eight-hour non-attainment areas under the new August 2010 ozone NAAQS standards in July 2011. Designation of new eight-hour ozone non-attainment areas could result in additional federal and state regulatory actions that would likely impact our operations and increase the cost of additions to property, plant and equipment. Additionally, the EPA is expected to promulgate additional hazardous air pollutant regulations in 2010 that will likely impact our operations. We are unable at this time to estimate with any certainty the cost of additions that may be required to meet new regulations, although we believe that some of those costs are included in the range discussed above. Management considers costs associated with compliance with the environmental laws and regulations described above to be prudent costs incurred in the ordinary course of business and, therefore, recoverable through our rates.
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
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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. In July 2009, the EPA requested additional information pertaining to these compressor stations; in August 2009, we submitted the requested information.
Safety Matters.
Pipeline Integrity Regulations.We have developed an Integrity Management Plan that meets the United States Department of Transportation Pipeline and Hazardous Materials Safety Administration (PHMSA) final rule pursuant to the requirements of the Pipeline Safety Improvement Act of 2002. In meeting the integrity regulations, we have identified high consequence areas and completed our baseline assessment plan. We are on schedule to complete the required assessments within specified timeframes. Currently, we estimate that the cost to perform required assessments and remediation will be between $150 million and $220 million over the remaining assessment period of 2010 through 2012, the majority of which are capital expenditures. Management considers the cost 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 confirmed that the remaining remedial actions should be completed by December 31, 2010. 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 $150 million at March 31, 2010. We have
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commitments for gas purchases of approximately $50 million at March 31, 2010. See Note 1 of Notes to Condensed Consolidated Financial Statements for our discussion of our agency agreement with WGM.
4. DEBT, FINANCING ARRANGEMENT AND LEASES.
Revolving Credit and Letter of Credit Facility.
Prior to Williams’ restructuring of its business, we participated in Williams’ unsecured $1.5 billion revolving credit facility (Credit Facility) with a maturity date of May 1, 2012. As part of the restructuring, we were removed as borrowers under the Credit Facility, and on February 17, 2010, we entered into a new $1.75 billion three-year senior unsecured revolving credit facility (the “New Credit Facility”) with 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 New 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 New Credit Facility to the extent not otherwise utilized by WPZ and Northwest. At closing, WPZ borrowed $250 million under the New Credit Facility to repay the term loan outstanding under its existing senior unsecured credit agreement. As of March 31, 2010, loans outstanding under the New Credit Facility were reduced to $108 million using available cash.
Interest on borrowings under the New Credit Facility is payable at rates per annum equal to, at the option of the borrower: (1) a fluctuating base rate equal to Citibank, N.A.’s adjusted base rate plus an applicable margin, or (2) a periodic fixed rate equal to London Interbank Offered Rate (LIBOR) plus an applicable margin. The adjusted base rate will be the highest of (i) the federal funds rate plus 0.5 percent, (ii) Citibank N.A.’s publicly announced base rate, and (iii) one-month LIBOR plus 1.0 percent. WPZ pays a commitment fee (currently 0.5 percent) based on the unused portion of the New Credit Facility. The applicable margin and the commitment fee are based on the specific borrower’s senior unsecured long-term debt ratings.
The New Credit Facility contains various covenants that limit, among other things, the borrower’s and its respective subsidiaries’ ability to incur indebtedness, grant certain liens supporting indebtedness, merge or consolidate, sell all or substantially all of its assets, enter into certain affiliate transactions, make certain distributions during an event of default, and allow any material change in the nature of their business.
Under the New Credit Facility, WPZ is required to maintain a ratio of debt to Earnings Before Income Taxes, Interest, Depreciation and Amortization (EBITDA) (each as defined in the New Credit Facility) of no greater than 5.00 to 1.00 for itself and its consolidated subsidiaries. The debt to EBITDA ratio is measured on a rolling four-quarter basis. For us and our consolidated subsidiaries, the ratio of debt to capitalization (defined as net worth plus debt) is not permitted to be greater than 55 percent. Each of the above ratios will be tested, beginning June 30, 2010, at the end of each fiscal quarter (with the first full year measured on an annualized basis).
The New Credit Facility includes customary events of default. If an event of default with respect to a borrower occurs under the New Credit Facility, the lenders will be able to terminate the commitments for all borrowers and accelerate the maturity of the loans of the defaulting borrower under the New Credit Facility and exercise other rights and remedies.
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As of March 31, 2010, there were $108 million of revolving credit loans outstanding under the New Credit Facility, none of which were associated with us, and no letters of credit were issued by the participating institutions.
5. 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 priority to unobservable inputs (Level 3 measurements). We classify fair value balances based on the observability of those inputs. The three levels of the fair value hierarchy are as follows:
• | Level 1 — Quoted prices in active markets for identical assets or liabilities that we have the ability to access. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Our Level 1 consists of financial instruments in our ARO Trust totaling $24.6 million at March 31, 2010. These financial instruments include money market funds, U.S. equity funds, international equity funds and municipal bond funds. | ||
• | Level 2 — Inputs are other than quoted prices in active markets included in Level 1, that are either directly or indirectly observable. These inputs are either directly observable in the marketplace or indirectly observable through corroboration with market data for substantially the full contractual term of the asset or liability being measured. We do not have any Level 2 measurements. | ||
• | Level 3 — Includes inputs that are not observable for which there is little, if any market activity for the asset or liability being measured. These inputs reflect management’s best estimate of the assumptions market participants would use in determining fair value. We do not have any Level 3 measurements. |
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 transfers in or out of Level 1 and Level 2 occurred during the period ended March 31, 2010.
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6. FINANCIAL INSTRUMENTS AND GUARANTEES.
Fair value of financial instruments.The carrying amount and estimated fair values of our financial instruments as of March 31, 2010 and December 31, 2009 are as follow (in thousands);
March 31, 2010 | December 31, 2009 | |||||||||||||||
Carrying | Fair | Carrying | Fair | |||||||||||||
Amount | Value | Amount | Value | |||||||||||||
Financial assets: | ||||||||||||||||
Cash | $ | 186 | $ | 186 | $ | 108 | $ | 108 | ||||||||
Short-term financial assets | 96,112 | 96,112 | — | — | ||||||||||||
Long-term financial assets | 331 | 331 | 373 | 373 | ||||||||||||
Financial liabilities: | ||||||||||||||||
Long-term debt, including current portion | 1,279,056 | 1,428,327 | 1,278,770 | 1,417,300 |
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 long-term financial assets (long-term receivables), the carry 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 year-end traded bond market prices. Private debt is valued based on the prices of similar securities with similar terms and credit ratings. At March 31, 2010 and December 31, 2009, 100 percent of long-term debt was publicly traded. As a participant in Williams’ or WPZ’s cash management program, we made advances to and received advances from Williams and WPZ. Advances were stated at the historical carrying amounts. At March 31, 2010, the advances due us by WPZ total $95.8 million and are reflected in current assets. At December 31, 2009, the advances due us by Williams totaled $186.1 million and were reflected as a reduction of owner’s equity. Advances to affiliates are due on demand. However, in accordance with the restructuring of Williams’ business in February 2010, our Management Committee authorized a distribution which included an amount equivalent to our advance balance and related interest outstanding. Accordingly, our advance balance and related interest receivable at December 31, 2009 were reflected as a reduction of owner’s equity as the advances were not available to us as working capital.
7. TRANSACTIONS WITH AFFILIATES.
As a participant in Williams’ cash management program, we made advances to and received advances from Williams. The interest rate on intercompany demand notes is 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 and $4.3 million during the three months ended March 31, 2010 and 2009, respectively.
In connection with Williams’ restructuring in February 2010, our Management Committee authorized a distribution which included an amount equivalent to our advance balance and related interest outstanding. Accordingly, our advance balance and related interest receivable at December 31, 2009 were reflected as a reduction of owner’s equity as the advances were not available to us as working capital.
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, 2010, the advances due us by WPZ totaled approximately $95.8 million. The advances are represented by
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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, 2010, the interest rate was 0.01 percent. The interest income from these advances to WPZ was minimal during the three months ended March 31, 2010.
Included in our operating revenues for the three months ending March 31, 2010 and 2009 are revenues received from affiliates of $6.1 million and $5.1 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, WGM manages our remaining jurisdictional merchant gas sales. The agency fees billed by WGM under the agency agreement for the three months ending March 31, 2010 and 2009 were not significant.
Included in our cost of sales for the three months ending March 31, 2010 and 2009 is purchased gas cost from affiliates of $1.5 million and $2.5 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 it and other affiliated companies. Included in our administrative and general expenses for the three months ending March 31, 2010 and 2009, are $13.8 million and $12.4 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 ending March 31, 2010 and 2009, we recorded reductions in operating expense of $1.3 million and $2.4 million, respectively, for services provided to and reimbursed by WFS under terms of the operating agreement.
Two distributions totaling approximately $203.8 million were declared and paid to WGP and a $0.2 million non cash distribution was made to WGP during the quarter ended March 31, 2010. No distributions were paid in the quarter ended March 31, 2009.
As part of Williams’ restructuring of its business, effective as of February 16, 2010, all of our former employees were transferred to our 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 otherwise provided by us that are necessary to operate our business. In return, we will 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.
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8. COMPREHENSIVE INCOME.
Comprehensive income is as follows (in thousands):
Three Months | ||||||||
Ended March 31, | ||||||||
2010 | 2009* | |||||||
(Restated) | ||||||||
Net income | $ | 75,994 | $ | 80,414 | ||||
Equity interest in unrealized gain/(loss) on interest rate hedge | 23 | 84 | ||||||
Total comprehensive income | $ | 76,017 | $ | 80,498 | ||||
* | Prior year amount has been restated to reflect accounting for pension and postretirement benefit obligations on a multi-employer accounting model (see Note 2 of Notes to the Consolidated Financial Statements). The effect of the restatement decreased Total Comprehensive Income by $2.7 million for the three months ended March 31, 2009. |
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 2009 Annual Report on Form 10-K and with the Condensed Consolidated Financial Statements and Notes contained in this report.
RESULTS OF OPERATIONS.
Operating Income and Net Income.
Operating incomefor the three months ended March 31, 2010 was $93.8 million compared to operating income of $94.0 million for the three months ended March 31, 2009.Net incomefor the three months ended March 31, 2010 was $76.0 million compared to $80.4 million for the three months ended March 31, 2009.Operating incomewas comparable for the three months ended March 31, 2010 and 2009; increases inOperating Costs and Expenseswere mostly offset by increases inOperating Revenues. The decrease inNet incomeof $4.4 million (5.5 percent) was mostly attributable to higher net deductions inOther (Income) and Other Deductions.
Transportation Revenues.
Operating revenues:Natural gas transportationfor the three months ended March 31, 2010 was $234.3 million, compared to $230.0 million for the three months ended March 31, 2009. The $4.3 million (1.9 percent) increase was primarily due to higher transportation demand revenues of $5.7 million primarily from Phase II of our Sentinel expansion placed in service in November 2009 and $3.3 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 $4.6 million from lower
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commodity revenues resulting from lower IT Feeder revenue due to displacement of volumes as a result of new interconnects and declining production attached to our IT Feeder laterals.
Our facilities are divided into eight rate zones. Five are located in the production area and three are located in the market area. Long-haul transportation is gas that is received in one of the production-area zones and delivered in a market-area zone. Market-area transportation is gas that is both received and delivered within market-area zones. Production-area transportation is gas that is both received and delivered within production-area zones.
Our total system deliveries in trillion British Thermal Units (TBtu) for the three months ended March 31, 2010 and 2009 are shown below.
Three Months | ||||||||
Ended March 31, | ||||||||
Transco System Deliveries (TBtu) | 2010 | 2009 | ||||||
Market-area deliveries: | ||||||||
Long-haul transportation | 138.4 | 188.5 | ||||||
Market-area transportation | 413.3 | 315.5 | ||||||
Total market-area deliveries | 551.7 | 504.0 | ||||||
Production-area transportation | 34.4 | 45.7 | ||||||
Total system deliveries | 586.1 | 549.7 | ||||||
Average Daily Transportation Volumes (TBtu) | 6.5 | 6.1 | ||||||
Average Daily Firm Reserved Capacity (TBtu) | 7.0 | 7.0 |
Sales Revenues.
We make jurisdictional merchant gas sales pursuant to a blanket sales certificate issued by the FERC. Through an agency agreement, WGM manages our long-term purchase agreement and 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 the jurisdictional merchant gas sales business and, as our agent, 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.
In addition to our merchant gas sales, we also have cash out sales which settle gas imbalances with shippers. In the course of providing transportation services to customers, we may receive different quantities of gas from shippers than the quantities delivered on behalf of those shippers. Additionally, we transport gas on various pipeline systems which may deliver different quantities of gas on our behalf than the quantities of gas received from us. These transactions result in gas transportation and exchange imbalance receivables and payables. Our tariff includes a method whereby the majority of transportation imbalances are settled on a monthly basis through cash out sales or purchases. The cash out sales have no impact on our operating income or results of operations.
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Operating revenues:Natural gas saleswere $27.7 million for the three months ended March 31, 2010 compared to $13.0 million for the same period in 2009. The $14.7 million (113.1 percent) increase was primarily due to higher cash out sales of $6.3 million and higher merchant sales of $0.8 million in 2010, in addition to sales of Hester excess base gas and Eminence excess top gas of $7.6 million in the first quarter of 2010. Cash out 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.
Storage Revenues.
Operating revenues:Natural gas storagefor the three months ended March 31, 2010 was comparable to the same period in 2009.
Other Revenues.
Operating revenues:Otherdecreased $9.3 million (90.3 percent) to $1.0 million for the three months ended March 31, 2010 when compared to the same period in 2009, primarily due to a $9.0 million decrease in Park and Loan Service revenue as a result of lower gas volumes parked and/or loaned by customers in 2010.
Other Operating Costs and Expenses.
Excluding the Cost of natural gas salesof $27.7 million for the three months ended March 31, 2010 and $13.0 million for the comparable period in 2009, our other operating costs and expenses for the three months ended March 31, 2010 were approximately $4.0 million (2.2 percent) lower than the comparable period in 2009. This decrease was primarily attributable to:
• | A $1.8 million (3.0 percent) decrease inOperation and maintenancecosts primarily resulting from: |
• | A $4.7 million decrease related to miscellaneous contractual services, other outside services, helicopter and aircraft usage, and contract labor primarily related to Hurricane Ike damages assessment incurred in 2009; | ||
• | Partially offset by a $3.1 million increase related to labor and labor related costs, primarily higher salaries and other incentive compensation costs; and |
• | A decrease inAdministrative and generalcosts of $5.2 million (12.9 percent) primarily resulting from: |
• | A $5.6 million decrease related to labor and labor related costs, primarily lower incentive compensation costs and pension costs; | ||
• | A $1.0 million decrease due to the absence of the 2009 increase to charges associated with a 2008 pipeline rupture; | ||
• | Partially offset by a $1.4 million increase in allocated corporate expenses; and | ||
• | A $0.7 million increase in external legal expenses. |
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• | A decrease inOther expense, netof $0.2 million (14.3 percent) primarily resulting from: |
• | A $5.0 million gain on the sale of Hester base gas. In October 2008, the FERC granted us authorization to abandon our Hester Storage Field. As part of the abandonment, we are selling the base gas. One of the provisions of the settlement of our Docket No. RP06-569 rate case (See Note 3 of Notes to the Consolidated Financial Statements) requires that Transco share 45 percent of the gain on the sale of the base gas with its customers; | ||
• | Partially offset by a $2.7 million increase in expense for charges related to a regulatory liability for the over collection of post employment benefits other than pension costs to be returned to our customers. This amount is offset in revenues and therefore has no impact on operating income or results from operations; | ||
• | A $0.9 million increase related to ARO costs; and | ||
• | A $0.5 million increase in project development costs. |
• | Partially offset by an increase inCost of natural gas transportationof $1.8 million (26.9 percent) primarily resulting from: |
• | A $2.6 million increase due to higher electric power costs in 2010. Electric power costs are recovered from customers through transportation rates resulting in no net impact on our operating income or results of operations; | ||
• | Partially offset by $0.5 million lower fuel expense in 2010 resulting from more favorable pricing differentials between cost recoveries at spot prices and expenses recognized at weighted average prices than those realized in 2009; and | ||
• | A $0.3 million decrease due to lower gas supply expense resulting from a settlement of an imbalance recorded in 2009; and |
• | An increase inDepreciation and amortizationcosts of $1.6 million (2.6 percent) primarily resulting from an increase in the depreciation base due to additional plant placed in-service; |
Other (Income) and Other Deductions.
Other (income) and other deductionsfor three months ended March 31, 2010 were $17.7 million compared to $13.6 million for the same period in 2009. The $4.1 million net increase (30.1 percent) was primarily due to:
• | HigherMiscellaneous other (income) deductions, netof $2.5 million primarily due to a lower amount of reimbursements for tax gross-up related to reimbursable projects; | ||
• | A decrease inInterest income—affiliatesof $2.1 million due to overall lower average advances to affiliates in 2010 as compared to the same period in 2009 and a lower rate on the note advance to WPZ; |
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• | Partially offset by higherAllowance for equity and borrowed funds used during construction(AFUDC) of $0.5 million due to higher construction spending in 2010 as compared to 2009. |
Capital Expenditures.
Our capital expenditures for the three months ended March 31, 2010 were $56.2 million, compared to $22.3 million for the three months ended March 31, 2009. The $33.9 million increase is primarily due to higher spending on expansion projects in 2010. Our capital expenditures estimate for 2010 and future capital projects are discussed in our 2009 Annual Report Form 10-K. The following describes those projects and certain new capital projects proposed by us.
Mobile Bay South Expansion Project.The Mobile Bay South Expansion Project involves the addition of compression at our Station 85 in Choctaw County, Alabama to allow us to provide firm transportation service southbound on the Mobile Bay line from Station 85 to various delivery points. In May 2009 we received approval from the FERC. The capital cost of the project is estimated to be approximately $37 million. The project was placed into service in May 2010 and increased capacity by 253 thousand dekatherms per day (Mdt/d.)
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 November 2009 we filed an application with the FERC. The capital cost of the project is estimated to be approximately $36 million, and it will increase capacity by 380 Mdt/d. We plan to place the project into service by May 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 $241 million. We plan to place the project into service in phases, in July 2010 and May 2011, and it will increase capacity by 308 Mdt/d.
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 proposed LNG import terminal in Mississippi. In August 2009 we filed an application with the FERC. Our share of the capital cost of the project is estimated to be up to approximately $34 million. We plan to place the project into service in September 2011, and 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. We anticipate filing an application with the FERC in the fourth quarter of 2010. The capital cost of the project is estimated to be approximately $214 million. We plan to place the project into service in phases in September 2012 and June 2013, and it will increase capacity by up to 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. We anticipate filing an application with the FERC in the fourth quarter
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of 2010. 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 early 2011. The capital cost of the project is estimated to be approximately $120 million. We plan to place the project into service in November 2013, 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. The capital cost of the project is estimated to be approximately $37 million. We plan to place the project into service in November 2013, and it will increase capacity by 100 Mdt/d.
ITEM 3. Quantitative and Qualitative Disclosures About Market Risk.
None.
ITEM 4T. 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.
In the first quarter of 2010 and related to our financial statements for the period ended December 31, 2009, we identified a material weakness related to the manner in which we presented and recognized certain pension and postretirement obligations in certain benefit plans for which Williams is the plan sponsor.
A material weakness is a deficiency, or combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the annual or interim financial statements will not be prevented or detected on a timely basis.
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We had previously recorded parent allocated amounts related to these benefit plans on a single-employer basis rather than a multi-employer accounting model. As the plan assets are not legally segregated and we are not contractually required to assume these obligations upon withdrawal, we concluded that the appropriate accounting model for these historical financial statements is a multi-employer model. We corrected our method of accounting for the parent-allocated amounts related to certain pension and postretirement plans to the multi-employer model and this change was reflected in our financial statements for the period ended December 31, 2009. We also enhanced our controls that ensure proper selection and application of generally accepted accounting principles. We consider this material weakness to be remediated as of March 31, 2010.
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 2010 Changes in Internal Controls
Other than described above, there have been no changes during the first quarter of 2010 that have materially affected, or are reasonably likely to materially affect, our Internal Controls.
PART II — OTHER INFORMATION.
ITEM 1. LEGAL PROCEEDINGS.
See discussion in Note 3 of the Notes to Condensed Consolidated Financial Statements included herein.
ITEM 1A. RISK FACTORS.
There are no material changes to the Risk Factors previously disclosed in Part 1, Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2009.
ITEM 6. EXHIBITS.
The following instruments are included as exhibits to this report.
Exhibit Number | Description | |
3.1 | Certificate of Conversion and Certificate of Formation, dated December 24, 2008 and effective on December 31, 2008 (filed on February 26, 2009 as Exhibit 3.1 to the company’s Form 10-K), and incorporated herein by reference. | |
3.2 | Operating Agreement of Transco dated December 31, 2008 (filed on February 26, 2009 as Exhibit 3.2 to the Company’s Form 10-K), and incorporated herein by reference. |
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Exhibit Number | Description | |
10.1 | Credit Agreement, dated as of February 17, 2010, by and among Williams Partners L.P., Transcontinental Gas Pipe Line Company, LLC, Northwest Pipeline GP, the lenders party thereto and Citibank, N.A., as Administrative Agent (filed as Exhibit 10.5 to Williams Partners L.P.’s Current Report on Form 8-K, filed on February 22, 2010 (File No. 001-32599) and incorporated by reference as Item 10.1 to our Form 8-K filed February 22, 2010). | |
10.2 | Administrative Services Agreement, dated as of February 17, 2010, by and between Transco Pipeline Services LLC and Transcontinental Gas Pipe Line Company, LLC (filed as Exhibit 10.3 to Williams Partners L.P.’s Current Report on Form 8-K, filed on February 22, 2010 (File No. 001-32599) and incorporated by reference as Item 10.2 to our Form 8-K filed February 22, 2010). | |
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, 2010 | By: | /s/ Jeffrey P. Heinrichs | ||
Jeffrey P. Heinrichs | ||||
Controller and Assistant Treasurer (Principal Accounting Officer) |
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EXHIBIT INDEX.
Exhibit Number | Description | |
3.1 | Certificate of Conversion and Certificate of Formation, dated December 24, 2008 and effective on December 31, 2008 (filed on February 26, 2009 as Exhibit 3.1 to the company’s Form 10-K), and incorporated herein by reference. | |
3.2 | Operating Agreement of Transco dated December 31, 2008 (filed on February 26, 2009 as Exhibit 3.2 to the Company’s Form 10-K), and incorporated herein by reference. | |
10.1 | Credit Agreement, dated as of February 17, 2010, by and among Williams Partners L.P., Transcontinental Gas Pipe Line Company, LLC, Northwest Pipeline GP, the lenders party thereto and Citibank, N.A., as Administrative Agent (filed as Exhibit 10.5 to Williams Partners L.P.’s Current Report on Form 8-K, filed on February 22, 2010 (File No. 001-32599) and incorporated by reference as Item 10.1 to our Form 8-K filed February 22, 2010). | |
10.2 | Administrative Services Agreement, dated as of February 17, 2010, by and between Transco Pipeline Services LLC and Transcontinental Gas Pipe Line Company, LLC (filed as Exhibit 10.3 to Williams Partners L.P.’s Current Report on Form 8-K, filed on February 22, 2010 (File No. 001-32599) and incorporated by reference as Item 10.2 to our Form 8-K filed February 22, 2010). | |
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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