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 JuneSeptember 30, 2008
OR
   
o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period fromto
Commission File Number 1-7584
TRANSCONTINENTAL GAS PIPE LINE CORPORATION
(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)
Registrant’s telephone number, including area code (713) 215-2000
NoneNo 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 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 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 filer  þSmaller reporting company o

(Do not check if a smaller reporting company)		Smaller reporting companyo
     Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 ofthe Exchange Act).YesoNoþ
The number of shares of Common Stock, par value $1.00 per share, outstanding as of JulyOctober 31, 2008 was 100.
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 CORPORATION
INDEX
     
  Page 
PART I. FINANCIAL INFORMATION:
    
     
Item 1. Financial Statements —-
    
     
Condensed Consolidated Statements of Income for the three and sixnine months ended JuneSeptember 30, 2008 and 2007
  5 
     
Condensed Consolidated Balance Sheets as of JuneSeptember 30, 2008 and December 31, 2007
  6 
     
Condensed Consolidated Statements of Cash Flows for the sixnine months ended JuneSeptember 30, 2008 and 2007
  8 
     
Notes to Condensed Consolidated Financial Statements
  910 
     
Item 2. Management’s Narrative Analysis of the Results of Operations
  1620 
     
Item 4. Controls and Procedures
  2024 
     
PART II. OTHER INFORMATION
  2125 
     
Item 1. Legal Proceedings.
  2125 
     
Item 1A. Risk Factors.
  2125 
     
Item 6. Exhibits
  2127 
Certification of CEO Pursuant to Section 302
Certification of CFO Pursuant to Section 302
Section 906 Certification
     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 statements discuss our expected future results based on current and pending business operations. 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 which 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,” “could,” “may,” “should,” “continues,” “estimates,” “expects,” “forecasts,” “might,” “planned,” “potential,” “projects,” “scheduled” or similar expressions. These forward-looking statements include, among others, statements regarding:
Amounts and nature of future capital expenditures;

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 • Expansion and growth of our business and operations;
•Financial condition and liquidity;
 
 • Business strategy;
 
 • Cash flow from operations or results of operations;
 
 • Rate case filing; 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 document. Many of the factors that will determine these results are beyond our ability to control or predict.project. Specific factors which could cause actual results to differ from those in the forward-looking statements include:
 • Availability of supplies (including the uncertainties inherent in assessing and estimating future natural gas reserves), market demand, volatility of prices, and increased costs of capital;
 
 • Inflation, interest rates and general economic conditions;
 
 • The strength and financial resources of our competitors;
 
 • Development of alternative energy sources;
 
 • The impact of operational and development hazards;
 
 • Costs of, changes in, or the results of laws, government regulations including proposed climate change legislation, environmental liabilities, litigation, and rate proceedings;
 
 • Our costs and funding obligations for defined benefit pension plans and other postretirement benefit plans;
•Increasing maintenance and construction costs;
 
 • Changes in the current geopolitical situation;
 
 • Our exposure to the credit risk of our customers;
•Risks related to strategy and financing, including restrictions stemming from our debt agreements and future changes in our credit ratings;ratings and the availability and cost of credit;
 
 • Risk associated with future weather conditions; and
 
 • Acts of terrorism.terrorism; and
•Additional risks described in our filings with the Securities and Exchange Commission.
     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 document. 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.

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     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, 2007, and Part II, Item 1A. Risk Factors ofin this Form 10-Q.

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PART 1 — FINANCIAL INFORMATION
ITEM 1. Financial Statements
TRANSCONTINENTAL GAS PIPE LINE CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(Thousands of Dollars)
(Unaudited)
                
 Three Months Ended Six Months Ended                 
 June 30, June 30,  Three Months Ended Nine Months Ended 
 2008 2007 2008 2007  September 30, September 30, 
  2008 2007 2008 2007 
Operating Revenues:  
Natural gas sales $40,330 $59,952 $70,651 $91,239  $42,631 $36,546 $113,282 $127,785 
Natural gas transportation 220,125 210,453 455,982 412,186  219,697 215,059 675,679 627,245 
Natural gas storage 36,231 35,676 73,552 68,366  35,930 36,036 109,482 104,402 
Other 2,907 9,071 6,186 16,499  1,272 1,047 7,458 17,546 
                  
Total operating revenues 299,593 315,152 606,371 588,290  299,530 288,688 905,901 876,978 
                  
  
Operating Costs and Expenses:  
Cost of natural gas sales 40,330 59,948 70,724 91,168  42,630 36,547 113,354 127,715 
Cost of natural gas transportation  (1,214) 1,238 3,814 5,441   (138) 3,005 3,676 8,446 
Operation and maintenance 56,049 56,104 110,985 111,396  55,134 55,698 166,119 167,094 
Administrative and general 41,068 37,451 75,755 77,692  39,145 36,647 114,900 114,339 
Depreciation and amortization 58,136 57,602 113,283 111,172  58,301 57,590 171,584 168,762 
Taxes — other than income taxes 10,600 14,381 24,101 28,578  13,204 11,424 37,305 40,002 
Other (income) expense, net  (10,193) 3,979  (7,521) 4,325   (6,210) 4,143  (13,731) 8,468 
                  
Total operating costs and expenses 194,776 230,703 391,141 429,772  202,066 205,054 593,207 634,826 
                  
  
Operating Income 104,817 84,449 215,230 158,518  97,464 83,634 312,694 242,152 
                  
  
Other (Income) and Other Deductions:  
Interest expense 24,495 23,431 48,822 46,624  23,811 24,097 72,633 70,721 
Interest income — affiliates  (6,828)  (4,267)  (12,131)  (7,925)  (5,417)  (3,830)  (17,548)  (11,755)
Allowance for equity and borrowed funds used during construction (AFUDC)  (1,540)  (2,982)  (2,868)  (4,713)  (1,678)  (5,463)  (4,546)  (10,176)
Equity in earnings of unconsolidated affiliates  (1,528)  (1,723)  (2,959)  (3,397)  (1,533)  (1,717)  (4,492)  (5,114)
Miscellaneous other income, net  (1,431)  (1,938)  (3,540)  (4,520)  (1,643)  (2,933)  (5,183)  (7,453)
                  
Total other (income) and other deductions 13,168 12,521 27,324 26,069  13,540 10,154 40,864 36,223 
                  
  
Income before Income Taxes 91,649 71,928 187,906 132,449  83,924 73,480 271,830 205,929 
  
Provision for Income Taxes 34,856 27,808 71,440 50,705  31,523 27,927 102,963 78,632 
             ��     
  
Net Income $56,793 $44,120 $116,466 $81,744  $52,401 $45,553 $168,867 $127,297 
                  
See accompanying notes.

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TRANSCONTINENTAL GAS PIPE LINE CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
(Thousands of Dollars)
(Unaudited)
        
 June 30, December 31,         
 2008 2007  September 30, December 31, 
  2008 2007 
ASSETS  
Current Assets:  
Cash $120 $119  $136 $119 
Receivables:  
Affiliates 2,248 6,307  2,266 6,307 
Advances to affiliates 349,539 223,657  191,460 223,657 
Others, less allowance of $429 ($462 in 2007) 115,253 115,003 
Others, less allowance of $426 in 2008 ($462 in 2007) 152,462 115,003 
Transportation and exchange gas receivables 16,707 10,724  8,919 10,724 
Inventories 68,324 55,120  60,256 55,120 
Deferred income taxes 18,136 38,588  — 38,588 
Other 64,808 33,619  75,102 33,619 
          
Total current assets 635,135 483,137  490,601 483,137 
          
  
Investments, at cost plus equity in undistributed earnings 44,921 44,730  45,056 44,730 
          
  
Property, Plant and Equipment:  
Natural gas transmission plant 6,913,738 6,840,377  6,951,961 6,840,377 
Less-Accumulated depreciation and amortization 2,216,226 2,113,561  2,253,422 2,113,561 
          
Total property, plant and equipment, net 4,697,512 4,726,816  4,698,539 4,726,816 
          
  
Other Assets 272,343 256,169  280,861 256,169 
          
  
Total assets $5,649,911 $5,510,852  $5,515,057 $5,510,852 
          
See accompanying notes.

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TRANSCONTINENTAL GAS PIPE LINE CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS (Continued)
(Thousands of Dollars)
(Unaudited)
        
 June 30, December 31,         
 2008 2007  September 30, December 31, 
  2008 2007 
LIABILITIES AND STOCKHOLDER’S EQUITY  
Current Liabilities:  
Payables:  
Affiliates $24,102 $15,530  $17,501 $15,530 
Other 241,871 86,273  119,994 86,273 
Transportation and exchange gas payables 5,618 7,245  4,694 7,245 
Accrued liabilities 191,786 204,305  122,229 204,305 
Reserve for rate refunds 12,618 98,035  10,485 98,035 
Deferred income taxes 4,898 — 
Current maturities of long-term debt — 75,000  — 75,000 
          
Total current liabilities 475,995 486,388  279,801 486,388 
          
  
Long-Term Debt 1,277,165 1,127,370  1,277,420 1,127,370 
          
  
Other Long-Term Liabilities:  
Deferred income taxes 1,015,376 1,027,441  1,068,436 1,027,441 
Other 259,587 255,153  270,072 255,153 
          
Total other long-term liabilities 1,274,963 1,282,594  1,338,508 1,282,594 
          
  
Contingent liabilities and commitments (Note 2)  
  
Common Stockholder’s Equity:  
Common stock $1.00 par value:  
100 shares authorized, issued and outstanding — —  — — 
Premium on capital stock and other paid-in capital 1,652,430 1,652,430  1,652,430 1,652,430 
Retained earnings 983,900 977,434  981,302 977,434 
Accumulated other comprehensive loss  (14,542)  (15,364)  (14,404)  (15,364)
          
Total common stockholder’s equity 2,621,788 2,614,500  2,619,328 2,614,500 
          
  
Total liabilities and stockholder’s equity $5,649,911 $5,510,852  $5,515,057 $5,510,852 
          
See accompanying notes.

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TRANSCONTINENTAL GAS PIPE LINE CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Thousands of Dollars)
(Unaudited)
        
 Six Months Ended         
 June 30,  Nine Months Ended 
 2008 2007  September 30, 
  2008 2007 
Cash flows from operating activities:  
Net income $116,466 $81,744  $168,867 $127,297 
Adjustments to reconcile net income to net cash provided by (used in) operating activities:  
Depreciation and amortization 113,941 111,894  172,596 169,920 
Deferred income taxes 8,154 12,788  83,887 18,369 
(Gain)/loss on sale of property, plant and equipment  (10,542) 12 
Allowance for equity funds used during construction (Equity AFUDC)  (2,065)  (3,444)  (3,191)  (7,420)
Changes in operating assets and liabilities:  
Receivables — affiliates 4,059 2,284  4,041 2,487 
— others  (250)  (35,059)  (37,459)  (15,663)
Transportation and exchange gas receivables  (5,983)  (11,448) 1,805  (6,338)
Inventories  (13,204) 9,140   (5,136)  (5,310)
Payables — affiliates 6,355 5,099   (246)  (4,003)
— others 26,180  (8,985)  (130,785)  (4,660)
Transportation and exchange gas payables  (1,627)  (5,977)  (2,551) 1,745 
Accrued liabilities  (11,676) 9,255   (77,038)  (8,369)
Reserve for rate refunds 59,158 45,050  57,025 67,262 
Other, net  (43,291) 238   (56,011) 24,207 
          
Net cash provided by operating activities 256,217 212,579  165,262 359,536 
          
  
Cash flows from financing activities:  
Additions to long-term debt 424,332 —  424,332 — 
Retirement of long-term debt  (350,000) —   (350,000) — 
Debt issue costs  (1,873)  (10)  (2,009)  (10)
Common stock dividends paid  (110,000)  (40,000)  (165,000)  (80,000)
Change in cash overdrafts  (3,516)  (13,951) 28,080  (894)
          
Net cash used in financing activities  (41,057)  (53,961)  (64,597)  (80,904)
          
 
Cash flows from investing activities: 
Property, plant and equipment: 
Additions, net of equity AFUDC  (72,167)  (193,020)
Changes in accounts payable  (9,424) 22,761 
Changes in accrued liabilities  (843) 10,697 
Advances to affiliates, net  (125,882) 14,104 
Advances to others, net  (24) 516 
Other, net  (6,819)  (13,871)
     
Net cash used in investing activities  (215,159)  (158,813)
     
 
Net increase (decrease) in cash 1  (195)
Cash at beginning of period 119 315 
     
Cash at end of period $120 $120 
     
See accompanying notes.(continued)

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TRANSCONTINENTAL GAS PIPE LINE CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Continued)
(Thousands of Dollars)
(Unaudited)
         
  Nine Months Ended 
  September 30, 
  2008  2007 
Cash flows from investing activities:        
Property, plant and equipment:        
Additions, net of equity AFUDC $(125,698) $(327,884)
Changes in accounts payable  (5,932)  15,058 
Changes in accrued liabilities  (5,051)  13,763 
Advances to affiliates, net  32,197   37,619 
Advances to others, net  152   651 
Purchase of ARO trust investments  (23,966)  — 
Proceeds from sale of ARO trust investments  11,765   — 
Other, net  15,885   (18,037)
       
Net cash used in investing activities  (100,648)  (278,830)
       
         
Net increase (decrease) in cash  17   (198)
Cash at beginning of period  119   315 
       
Cash at end of period $136  $117 
       
See accompanying notes.

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TRANSCONTINENTAL GAS PIPE LINE CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
1. BASIS OF PRESENTATION
General
     Transcontinental Gas Pipe Line Corporation (Transco) is a wholly-owned subsidiary of Williams Gas Pipeline Company, LLC (WGP). WGP is a wholly-owned subsidiary of The Williams Companies, Inc. (Williams).
     In this report, Transco (which includes Transcontinental Gas Pipe Line Corporation 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.”
     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 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 have been condensed or omitted. The condensed unaudited consolidated financial statements include all adjustments both normal recurring and others which, in the opinion of our management, are necessary to present fairly our financial position at JuneSeptember 30, 2008, and results of operations for the three and sixnine months ended JuneSeptember 30, 2008 and 2007, and cash flows for the sixnine months ended JuneSeptember 30, 2008 and 2007. These condensed consolidated financial statements should be read in conjunction with the consolidated financial statements and the notes thereto included in our 2007 Annual Report on Form 10-K.
     As a participant in Williams’ cash management program, we have advances to and from Williams. The advances are represented by demand notes. The interest rate on intercompany demand notes is based upon the weighted average cost of Williams’ debt outstanding at the end of each quarter.
     Through an agency agreement, Williams Gas Marketing, Inc. (WGM), an 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 U.S. generally accepted accounting principles 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

910

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) deferred and other income taxes; 6) depreciation; 7) pensions and other post-employment benefits; and 8) asset retirement obligations.
     Our Board of Directors declared and we paid cash dividends on common stock in the amount of $50 million on March 31, 2008, and $60 million on June 30, 2008 and $55 million on September 30, 2008.
     Certain reclassifications have been made to the presentation of the 2007 financial statements to conform to the 2008 presentation, including the segregation of changes in capital related accrued liabilities from Additions, net of equity AFUDC within the investing activities in the Condensed Consolidated Statement of Cash Flows.
Comprehensive Income
     Comprehensive income is as follows (in thousands):
                                
 Three Months Six Months  Three Months Nine Months 
 Ended June 30, Ended June 30,  Ended September 30, Ended September 30, 
 2008 2007 2008 2007  2008 2007 2008 2007 
Net income $56,793 $44,120 $116,466 $81,744  $52,401 $45,553 $168,867 $127,297 
Equity interest in unrealized gain/(loss) on interest rate hedge, net of tax 234 125 211 114   (168)  (132) 43  (18)
Pension benefits, net of tax  
Amortization of prior service credit  (122)  (255)  (244)  (511)  (122)  (256)  (366)  (767)
Amortization of net actuarial loss 660 659 855 1,157  428 579 1,283 1,736 
                  
Total comprehensive income $57,565 $44,649 $117,288 $82,504  $52,539 $45,744 $169,827 $128,248 
                  
Recent Accounting Standards
     In September 2006, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (SFAS) No. 157, “Fair Value Measurements” (SFAS 157). This Statement establishes a framework for fair value measurements in the financial statements by providing a definition of fair value, provides guidance on the methods used to estimate fair value and expands disclosures about fair value measurements. SFAS 157 is effective for fiscal years beginning after November 15, 2007. In February 2008, the FASB issued FASB Staff Position (FSP) No. FAS 157-2, permitting entities to delay application of SFAS 157 to fiscal years beginning after November 15, 2008, for nonfinancial assets and nonfinancial liabilities, except for items that are recognized or disclosed at fair value in the financial statements on a recurring basis (at least annually). On January 1, 2008, we applied SFAS 157 to our assets and liabilities that are measured at fair value on a recurring basis (primarily our equity interest in the cash flow hedge of an unconsolidated company) with no material impact to our Condensed Consolidated Financial Statements. Beginning January 1, 2009, we will apply SFAS 157 fair value requirements to nonfinancial assets and nonfinancial liabilities that are not recognized or disclosed on a recurring basis. Application will be prospective when nonrecurring fair value measurements are required. We will assess the impact on our Condensed Consolidated Financial Statements of applying these requirements to nonrecurring fair value measurements for nonfinancial assets and nonfinancial liabilities. (See Note 4. Fair Value Measurements.)

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     In March 2008, the FASB issued SFAS No. 161 “Disclosures about Derivative Instruments and Hedging Activities — an amendment of FASB Statement No. 133” (SFAS 161). SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,”currently establishes the disclosure requirements for derivative instruments and hedging activities. SFAS 161 amends and expands the disclosure requirements of Statement 133 with enhanced quantitative, qualitative and credit risk disclosures. The Statement requires quantitative disclosure in a tabular format about the fair values of derivative instruments, gains and losses on derivative instruments and information about where these items are reported in the financial statements. Also required in the tabular presentation is a separation of hedging and nonhedging activities. Qualitative disclosures include outlining objectives and strategies for using derivative instruments in terms of underlying risk exposures, use of derivatives for risk management and other purposes and accounting designation, and an understanding of the volume and purpose of derivative activity. Credit risk disclosures provide information about credit risk related contingent features included in derivative agreements. SFAS 161 also amends SFAS No. 107, “Disclosures about Fair Value of Financial Instruments” to clarify that disclosures about concentrations of credit risk should include derivative instruments. This Statement is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008, with early application encouraged. We plan to apply this Statement beginning in 2009. This Statement encourages, but does not require, comparative disclosures for earlier periods at initial adoption. We will assess theThe application of this Statement on ourwill increase the disclosures in our Condensed Consolidated Financial Statements.
Subsequent EventSale of South Texas Assets
     On June 30, 2008, we closed on the sale of certain South Texas assets. The effective date of the sale, on which ownership of the assets transferred to the buyer, iswas July 1, 2008. The sale price was $12.5 million. The gain on the sale, approximately $10.4 million, will bewas recorded in the third quarter of 2008.
2. 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) principally designed to recover costs associated with (a) an increase in operation and maintenance expenses and administrative and general expenses; (b) an increase in depreciation expense; (c) the inclusion of costs for asset retirement obligations; (d) an increase in rate base resulting from additional plant; and (e) an increase in rate of return and related taxes. The rates became effective March 1, 2007, subject to refund and the outcome of a hearing. On November 28, 2007, we filed with the FERC a Stipulation and Agreement (Agreement) resolving all substantive issues in the rate case. On March 7, 2008, the FERC issued an order approving the Agreement without modifications. Pursuant to its terms, the Agreement became effective on June 1, 2008, and refunds of approximately $144 million were issued on July 17, 2008. We had previously provided a reserve for the refunds, which was reclassified, from Reserve for rate refunds to Payables-Other on the Condensed Consolidated Balance Sheet at June 30, 2008.

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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. On March 7, 2008,A hearing on this issue was held before a FERC Administrative Law Judge (ALJ) in July 2008. A decision by the FERC issued an order approving the Agreement without modifications. Pursuant to its terms, the Agreement became effective on June 1, 2008, and refunds of approximately $144 million were issued on July 17, 2008.

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We had previously provided a reserve for the refunds, which was reclassified, from Reserve for rate refunds to Payables-Other on the accompanying Condensed Consolidated Balance Sheet at June 30,ALJ is expected in November 2008.
Legal Proceedings
     In 1998, the United States Department of Justice (DOJ) informed Williams that Jack Grynberg, an individual, had filed claims in the United States District Court for the District of Colorado under the False Claims Act against Williams and certain of its wholly-owned subsidiaries including us. Mr. Grynberg had also filed claims against approximately 300 other energy companies and alleged that the defendants violated the False Claims Act in connection with the measurement, royalty valuation and purchase of hydrocarbons. The relief sought was an unspecified amount of royalties allegedly not paid to the federal government, treble damages, a civil penalty, attorneys’ fees, and costs. In April 1999, the DOJ declined to intervene in any of the Grynberg qui tam cases, and in October 1999, the Panel on Multi-District Litigation transferred all of the Grynberg qui tam cases, including those filed against Williams, to the United States District Court for the District of Wyoming for pre-trial purposes. In October 2002, the court granted a motion to dismiss Grynberg’s royalty valuation claims. Grynberg’s measurement claims remained pending against Williams, including us, and the other defendants, although the defendants have filed a number of motions to dismiss these claims on jurisdictional grounds. In May 2005, the court-appointed special master entered a report which recommended that many of the cases be dismissed, including the case pending against us and certain of the Williams defendants. In October 2006, the District Court dismissed all claims against us and in November 2006, Grynberg filed his notice of appeal with the Tenth Circuit Court of Appeals. Oral argument was held on September 25, 2008.
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 $10 million to $12 million (including both expense and capital expenditures), measured on an undiscounted basis, and will be spent over the next five to seven years. This estimate depends upon 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 JuneSeptember 30, 2008, we had a balance of approximately $5.3$5.1 million for the expense portion of these estimated costs recorded in current liabilities ($0.9 million) and other long-term liabilities ($4.44.2 million) in the accompanying Condensed Consolidated Balance Sheet.
     We consider prudently incurred environmental assessment and remediation costs and 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. Therefore, these estimated costs of environmental assessment and remediation, less amounts collected, have also been recorded as regulatory assets in Current Assets: Other and Other

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Assets in the accompanying Condensed Consolidated Balance Sheet. At JuneSeptember 30, 2008, we had recorded approximately $3.0$2.5 million of environmental related regulatory assets.
     We have used lubricating oils containing polychlorinated biphenyls (PCBs) and, although the use of such oils was discontinued in the 1970s, we have discovered residual PCB contamination in equipment and

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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 $10 million to $12 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 have been included in the environmental reserve 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 and to the federal Clean Air Act Amendments of 1990 (1990 Amendments), which added significantly to the existing requirements established by the federal Clean Air 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 five 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 control costs. However, the emission control additions required to comply with current federal Clean Air 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 $25 million to $30 million for the period 2008 through 2010. In March 2008, the EPA promulgated a new, lower National Ambient Air Quality Standard for ground-level ozone. Within three years, the EPA will designate new eight-hour ozone non-attainment areas. Designation of new eight-hour ozone non-attainment areas will result in additional federal and state regulatory actions that may impact our operations. As a result, the cost of additions to property, plant and equipment is expected to increase. We are unable at this time to estimate with any certainty the cost of additions that may be required to meet new regulations, although it is believed that some of those costs are included in the ranges 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 EPA’s investigation of our compliance with the Clean Air Act (Act). By January 2008, we responded with the requested information. By Notices of Violation (NOVs) dated March 28, 2008, EPA found us to be in violation of the requirements of the Act with respect to these compressor stations and offered to hold a conference in May 2008 to discuss the NOVs. We met with the EPA in May 2008 to discuss the allegations contained in the NOVs and in June 2008 we submitted to the EPA a written response denying the allegations.

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Safety Matters
     Pipeline Integrity RegulationsWe 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

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regulations, we have identified the 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 $250 million and $300 million over the remaining assessment period of 2008 through 2012. 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 RuptureOn 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 requires that we operate three of our mainlines in a portion of Virginia at reduced operating pressure and prescribes various remedial actions that must be undertaken before the lines can be restored to normal operating pressure. On October 6, 2008, we filed a request for hearing with PHMSA to challenge the CAO but asked that the hearing be stayed pending discussions with PHMSA to modify certain aspects of the order.
Other Matters
     In addition to the foregoing, 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 internalcounsel, 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 financial position.
Other Commitments
     Commitments for construction and gas purchasesWe have commitments for construction and acquisition of property, plant and equipment of approximately $114$130 million at JuneSeptember 30, 2008, the majority of which $86 million is expected to be spent in the remainder of 2008. We have commitments for gas purchases of approximately $174$113 million at JuneSeptember 30, 2008, which is expected to be spent over the next ten years. See Note 1, Basis of Presentation, for our discussion of our agency agreement with WGM.
Guarantees
     In connection with our renegotiations with producers to resolve take-or-pay and other contract claims and to amend gas purchase contracts, we entered into certain settlements that may require that we indemnify producers for claims for additional royalties resulting from such settlements. Through our agent WGM, we

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continue to purchase gas under contracts which extend, in some cases, through the life of the associated gas reserves. Certain of these contracts contain royalty indemnification provisions, which have no carrying value. We have been made aware of demands on producers for additional royalties and such producers may receive other demands which could result in claims against us pursuant to royalty indemnification provisions. Indemnification for royalties will depend on, among other things, the specific lease provisions between the producer and the lessor and the terms of the agreement between the producer and us. Consequently, the potential maximum future payments under such indemnification provisions cannot be determined. However, we believe that the probability of material payments is remote.

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3. DEBT AND FINANCING ARRANGEMENTS
Revolving Credit and Letter of Credit Facility
     UnderWe are a borrower under Williams’ $1.5 billion unsecured revolving credit facility (Credit Facility), letters and have access to $400 million of the facility to the extent not utilized by Williams. Letters of credit totaling $28 million, none of which are associated with us, have been issued by the participating institutions andinstitutions. There were no revolving credit loans were outstanding as of JuneSeptember 30, 2008. Our ratio of debt to capitalization must be no greater than 55 percent under this agreement. We are in compliance with this covenant as our ratio of debt to capitalization, as calculated under this covenant, was approximately 33 percent at JuneSeptember 30, 2008.
     Lehman Commercial Paper Inc., which is committed to fund up to $70 million of the Credit Facility, has filed for bankruptcy. Williams expects that its ability to borrow under this facility is reduced by this committed amount. Consequently, we expect our ability to borrow under the Credit Facility is reduced by approximately $18.7 million. The committed amounts of other participating banks under this agreement remain in effect and are not impacted by the above.
Issuance and Retirement of Long-Term Debt
     In January 2008, we borrowed $100 million under the Credit Facility to retire $100 million of 6.25 percent senior unsecured notes that matured on January 15, 2008. In April 2008, we borrowed $75 million under the Credit Facility to retire $75 million of adjustable rate unsecured notes that matured on April 15, 2008.
     On May 22, 2008, we issued $250 million aggregate principal amount of 6.05 percent senior unsecured notes due 2018 (6.05 percent Notes) to certain institutional investors in a Rule 144A private debt placement. Interest is payable on June 15 and December 15 of each year, beginning December 15, 2008. We used $175 million of the net proceeds to repay our borrowings under the Credit Facility. We will use the remainder for general corporate purposes, including the funding of capital expenditures.
Registration Payment Arrangements
     Under the terms of our $250 million 6.05 percent senior unsecured notes mentioned above, In September 2008, we are obligated to filecompleted an exchange offer registration statement offering to exchange theof these notes for a new issue of substantially identical new notes (except they will not be subject to transfer restrictions) to bethat are registered under the Securities Act of 1933, as amended,amended.

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4. FAIR VALUE MEASUREMENTS
Adoption of SFAS No. 157
     SFAS No. 157, “Fair Value Measurements” (SFAS 157), establishes a framework for fair value measurements in the financial statements by providing a definition of fair value, provides guidance on the methods used to estimate fair values and expands disclosures about fair value measurements. On January 1, 2008, we applied SFAS 157 for our assets and liabilities that are measured at fair value on a recurring basis. The initial adoption of SFAS 157 had no material impact on our Condensed Consolidated Financial Statements.
          Pursuant to the terms of the Agreement (see Note 2) approved by the FERC in March 2008, we are entitled to collect in rates the amounts necessary to fund our asset retirement obligations (ARO). Per the Agreement, we will deposit monthly, into an external trust account, the revenues collected specifically designated for ARO. We established the ARO trust account (ARO Trust) on June 30, 2008. The ARO Trust carries a moderate risk portfolio. At September 30, 2008, we applied SFAS 157 to the financial instruments held in our ARO Trust.
          SFAS 157 establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives 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 primarily consists of financial instruments in our ARO Trust.
•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.

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     The following table sets forth by level within 180 days after closing. Wethe fair value hierarchy our assets that are obligated to use commercially reasonable efforts to cause such registration statementmeasured at fair value on a recurring basis. There are no liabilities that are required to be declared effective within 270 days after closingmeasured at fair value on a recurring basis.
Fair Value Measurements at September 30, 2008 Using:
                 
  Quoted Prices          
  in Active          
  Markets for  Significant       
  Identical  Other  Significant    
  Assets or  Observable  Unobservable    
  Liabilities  Inputs  Inputs    
  (Level 1)  (Level 2)  (Level 3)  Total    
  (Millions) 
Assets:                
Other assets $11.9   $—   $—   $11.9  
             
Total assets $11.9   $—   $—   $11.9  
             
     Other assets include money market funds, U.S. equity funds, international equity funds and to consummate the exchange offer within 30 business days after such effective date. We may also be required to provide a shelf registration statement to cover the resale of the notes under certain circumstances. If we fail to fulfill these obligations, additional interest will accrue on the affected securities. The rate of additional interest will be 0.25 percent per annum on the principal amount of the affected securities for the first 90-day period immediately following the occurrence of the default, increasing by an additional 0.25 percent per annum with respect to each subsequent 90-days period thereafter up to a maximum amount for all such defaults of 0.5 percent annually.municipal bonds.
4.5. TRANSACTIONS WITH AFFILIATES
     As a participant in Williams’ cash management program, we make advances to and receive advances from Williams. At September 30, 2008 and December 31, 2007, the advances due to us by Williams totaled approximately $191.5 million and $223.7 million, respectively. The advances are represented by demand notes.
     Included in our operating revenues for the sixnine months ending JuneSeptember 30, 2008 and 2007 are revenues received from affiliates of $19.8$27.7 million and $23.0$32.0 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 remaining jurisdictional merchant gas sales. The agency fees billed by WGM under the agency agreement for the sixnine months ending JuneSeptember 30, 2008 and 2007 were not significant.

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     Included in our cost of sales for the sixnine months ending JuneSeptember 30, 2008 and 2007 is purchased gas cost from affiliates of $4.1$10.0 million and $4.8$8.3 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 sixnine months ending JuneSeptember 30, 2008 and 2007, are $26.1$35.8 million and $25.0$37.9 million, respectively, for such

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corporate expenses charged by Williams 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 sixnine months ending JuneSeptember 30, 2008 and 2007, we recorded reductions in operating expenses for services provided to WFS for $3.6$5.9 million and $2.5$4.4 million, respectively, under terms of the operating agreement.

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ITEM 2. Management’s Narrative Analysis of Results of Operations.
General
     The following discussion should be read in conjunction with the Consolidated Financial Statements, Notes and Management’s Narrative Analysis contained in Items 7 and 8 of our 2007 Annual Report on Form 10-K and with the Condensed Consolidated Financial Statements and Notes contained in this report.
RECENT MARKET EVENTS
     The recent instability in financial markets has created global concerns about the liquidity of financial institutions and is having overarching impacts on the economy as a whole. In this volatile economic environment, many financial markets, institutions and other businesses remain under considerable stress. These events are impacting our business. However, we note the following:
•We have no significant debt maturities until 2011.
•As of September 30, 2008, we have approximately $191.5 million of available cash from return of advances made to affiliates and available capacity under our Credit Facility. (See Note 3 of Notes to the Condensed Consolidated Financial Statements.)
•A significant portion of our transportation and storage services are provided pursuant to long-term firm contracts that obligate our customers to pay us monthly capacity reservation fees regardless of the amount of pipeline or storage capacity actually utilized by a customer.
RESULTS OF OPERATIONS
Operating Income and Net Income
     Our operating income for the sixnine months ended JuneSeptember 30, 2008 was $215.2$312.7 million compared to operating income of $158.5$242.2 million for the sixnine months ended JuneSeptember 30, 2007. Net income for the sixnine months ended JuneSeptember 30, 2008 was $116.5$168.9 million compared to $81.7$127.3 million for the sixnine months ended JuneSeptember 30, 2007. The increase in operating income of $56.7$70.5 million (35.8(29.1 percent) was due primarily to an increase in transportation and storage revenues andrevenues. Also contributing was the recognition of the gain in 2008 related to the sale of Eminence top gas sold in 2007.2007 ($9.5 million) and the gain related to the sale of our South Texas assets ($10.4 million). The increase in net income of $34.8$41.6 million (42.6(32.7 percent) was mostly attributable to the higher operating income, partially offset by a corresponding increase in the applicable provision for income taxes of $20.7$24.3 million (40.8(30.9 percent).
Pipeline Rupture
     As stated in Note 2 of Notes to Condensed Consolidated Financial Statements, on September 14, 2008, we experienced a rupture of our 30-inch diameter mainline B pipeline near Appomattox, Virginia. The United States Department of Transportation Pipeline and Hazardous Materials Safety Administration (PHMSA) issued a Corrective Action Order which requires that we operate three of our mainlines in a portion of Virginia at reduced operating pressure. We are taking steps to ensure the integrity of our mainlines and we plan to return them to full operating pressure as soon as possible, but doing so will require PHMSA’s approval. If some or all of our mainlines

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continue to operate at reduced pressure into the winter heating season, it is possible that we will not be able to meet all of our firm delivery obligations on certain days in which case we may be required to refund to affected customers demand charges paid to us for deliveries that were not made on those days due to the rupture. The amount of such refunds, if any, cannot be determined in part because weather will likely have a significant impact on our ability to perform.
Transportation Revenues
     Our operating revenues related to transportation services for the sixnine months ended JuneSeptember 30, 2008 were $456.0$675.7 million, compared to $412.2$627.2 million for the sixnine months ended JuneSeptember 30, 2007. The $43.8$48.5 million (10.6

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(7.7 percent) increase was primarily due to the effects of placing into effect, subject to refund, the rates in Docket No. RP06-569, on March 1, 2007 and additional revenues in 2008 of $21.8$32.8 million from the Potomac and Leidy to Long Island expansion projects placed in service in the fourth quarter of 2007.
     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.
     As shown in the table below, our total market-area deliveries for the sixnine months ended JuneSeptember 30, 2008 increased 22.3decreased 7.0 trillion British Thermal Units (TBtu) (2.6(0.5 percent) when compared to the same period in 2007. The increaseddecreased deliveries are primarily the result of the in-servicereduction of volumes available from producers in the third quarter of 2008, as a result of gas wells shut-in and/or damages to gathering lines in the Gulf of Mexico caused by Hurricane Ike, partially offset by increased deliveries throughout most of 2008 as a result of Transco’s Potomac and Leidy to Long Island expansions being placed in service in November 2007 and December 2007, respectively. Our production-area deliveries for the sixnine months ended JuneSeptember 30, 2008 increased 4.44.8 TBtu (4.5(3.3 percent) compared to the same period in 2007. The increase in production area deliveries is primarily due primarily to an increase in volumes received from the East Breaks Area, Offshoreoffshore Texas as a result of new wells drilled and producing.producing, partially offset by decreased volumes in the third quarter of 2008 due to gas wells shut-in and/or damages to gathering lines in the Gulf of Mexico caused by Hurricane Ike.
                
 Six months Nine months
 Ended June 30, Ended September 30,
Transco System Deliveries (TBtu) 2008 2007 2008 2007
Market-area deliveries:  
Long-haul transportation 403.4 422.2  577.6 621.7 
Market-area transportation 474.0 432.9  699.6 662.5 
          
Total market-area deliveries 877.4 855.1  1,277.2 1,284.2 
Production-area transportation 102.1 97.7  150.8 146.0 
          
Total system deliveries 979.5 952.8  1,428.0 1,430.2 
          
Average Daily Transportation Volumes (TBtu) 5.4 5.3  5.2 5.2 
Average Daily Firm Reserved Capacity (TBtu) 6.8 6.6  6.8 6.5 
Sales Revenues
     We make jurisdictional merchant gas sales pursuant to a blanket sales certificate issued by the FERC.

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Through an agency agreement, WGM manages our long-term purchase agreements 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 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

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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.
     Operating revenues related to our sales services were $70.7$113.3 million for the sixnine months ended JuneSeptember 30, 2008, compared to $91.2$127.8 million for the same period in 2007. The $20.5$14.5 million (22.5(11.3 percent) decrease was primarily due to the absence in 2008 of sales of excess top gas from our Eminence storage field of $37.0 million in 2007.2007 and lower merchant sales of $8.8 million, partially offset by increased cash-out sales of $31.3 million. These sales were offset in our costs of natural gas sold and therefore had no impact on our operating income or results of operations.
Storage Revenues
     Our operating revenues related to storage services were $73.6$109.5 million for the sixnine months ended JuneSeptember 30, 2008 compared to $68.4$104.4 million for the same period in 2007. The increase of $5.2$5.1 million (7.6(4.9 percent) was primarily due to the effects of placing into effect, subject to refund, the rates in Docket No. RP06-569, on March 1, 2007.
Other Revenues
     Our other operating revenues were $6.2$7.5 million for the sixnine months ended JuneSeptember 30, 2008 compared to $16.5$17.5 million for the same period in 2007. The decrease of $10.3$10.0 million (62.4(57.1 percent) was primarily due to a $10.6$10.5 million decrease of Park and Loan Service revenue as a result of lower gas volumes parked and/or loaned by customers in 2008 due to unfavorable market conditions.
Operating Costs and Expenses
     Excluding the cost of natural gas sales of $70.7$113.4 million for the sixnine months ended JuneSeptember 30, 2008 and $91.2$127.7 million for the comparable period in 2007, our operating expenses for the sixnine months ended JuneSeptember 30, 2008, were approximately $18.2$27.3 million (5.4 percent) lower than the comparable period in 2007. This decrease was primarily attributable to:

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A decrease in taxes other than income taxes of $4.5 million primarily resulting from a $1.3 million sales and use tax refund from the State of Texas applicable to prior years, a decrease of $1.5 million related to the State of Pennsylvania gross receipt tax due to a favorable ruling, a decrease of $0.9 million in property taxes due to a higher estimate of Texas property tax in the first six months of 2007 and a decrease of $0.8 million in Texas franchise tax mostly attributable to an audit accrual for prior years recorded in 2007.
•A decrease in cost of natural gas transportation of $4.8 million due to lower fuel expense of $10.4 million in 2008 resulting from favorable pricing differentials between cost recoveries at spot prices and expenses recognized at weighted average prices, partly offset by $5.8 million higher electric power costs.
•A $4 million charge associated with a third quarter 2008 pipeline rupture.
•Lower other (income) expense, net of $22.2 million, primarily resulting from:
Lower Other (income) expense, net of $11.9 million, primarily resulting from a $9.5 million gain recognized in 2008 related to the sale of Eminence top gas sold in 2007. In 2007, the gain was deferred pending a FERC Order on our March 2007 fuel tracker filing, which was issued in May 2008. Also contributing was a net decrease of $2.3
oA $10.4 million gain related to the sale of our South Texas assets and
oA $9.5 million gain recognized in 2008 related to the sale of Eminence top gas sold in 2007. In 2007, the gain was deferred pending a FERC Order on our March 2007 fuel tracker filing, which was issued in May 2008.
oA net decrease in expense of $3.6 million associated with our asset retirement obligations (ARO) due to the new rates in Docket No. RP06-569, effective March 1, 2007 (See Note 2 of Notes to Condensed Consolidated Financial Statements). Prior to the effective date of the new rates, the depreciation expense of the asset and the accretion expense of the liability were being deferred as a regulatory asset. Effective March 1, 2007, with recovery of ARO costs in rates, the depreciation and accretion expense are no longer being deferred, resulting in increased expense of $1.0 million and $1.8

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million, respectively. Also resulting is an increase in expense of $1.3 million associated with the amortization of the ARO regulatory asset. These increases are being offset as a result of the rate settlement. Any differences between the recovery of ARO costs in rates and the depreciation, accretion, and amortization of the regulatory asset from March 1, 2007 forward are being deferred as a regulatory asset for collection/refund in the next rate case, thus resulting in a $6.4 million decrease in expense.case.
Other Income(Income) and Other Deductions
     Other income and other deductions for the sixnine months ended JuneSeptember 30, 2008 were comparable$40.9 million compared to $36.2 million for to the same period in 2007. This increase of $4.7 million (13.0 percent) was due to:
•Lower allowance for equity and borrowed funds used during construction (AFUDC) of $5.6 million due to lower construction spending in 2008 primarily due to the completion of our Leidy to Long Island expansion placed in service in December 2007.
•Lower miscellaneous other income, net of $2.3 million primarily due to lower equity AFUDC gross-up in the nine months ended September 30, 2008 as compared to the same period in 2007.
•Increased interest expense of $1.9 million primarily due to higher interest on reserve for rate refunds for the nine months ended September 30, 2008 as compared to the same period in 2007 due to the effect of placing into effect, subject to refund, the rates in Docket No. RP06-569, on March 1, 2007. On March 7, 2008, the FERC issued an order approving without modifications a Stipulation and Agreement (Agreement) resolving all substantive issues in the rate case. Pursuant to its terms, the Agreement became effective on June 1, 2008, and refunds of approximately $144 million were issued on July 17, 2008.
•Partly offsetting these was an increase in interest income — affiliates of $5.8 million due to overall higher average advances to affiliates in 2008 as compared to the same period in 2007.
Capital Expenditures
     Our capital expenditures for the sixnine months ended JuneSeptember 30, 2008 were $72.2$125.7 million, compared to $193.0$327.9 million for the sixnine months ended JuneSeptember 30, 2007. The lower expenditures are$202.2 million decrease is due to

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higher spending in the six months ended June 30, 2007 on two expansion projects which were completed and placed in service in late 2007, and lower spending on maintenance capital projects in 2008. Our capital expenditures estimate for 2008 and future capital projects are discussed in our 2007 Annual Report on Form 10-K. The following describes those projects and certain new capital projects proposed by us.
     Sentinel Expansion ProjectThe Sentinel Expansion Project will involveinvolves an expansion of our existing natural gas transmission system from the Leidy Hub in Clinton County, Pennsylvania and from the Pleasant Valley interconnection with Cove Point LNG in Fairfax County, Virginia to various delivery points requested by the shippers under the project. The capital cost of the project is estimated to be up to approximately $169$200 million. Transco plans to place the project into service in phases, in late 2008 and late 2009.
     Pascagoula Expansion ProjectThe Pascagoula Expansion Project will involveinvolves the construction of a new pipeline to be jointly owned with Florida Gas Transmission connecting Transco’s existing Mobile Bay Lateral to the outlet pipeline of a proposed liquefied natural gas import terminal in Mississippi. Transco’s share of the estimated capital cost of the project is estimated to be up to approximately $37 million. Transco plans to place the project into service on or about October 1, 2011.
     Mobile Bay South Expansion ProjectThe Mobile Bay South Expansion Project will involveinvolves the addition of compression at Transco’s Station 85 in Choctaw County, Alabama to allow Transco to provide firm transportation service southbound on the Mobile Bay line from Station 85 to various delivery points. The capital cost of the project is estimated to be up to approximately $37 million. Transco plans to place the project into service by May 2010.
     85 North Expansion ProjectThe 85 North Expansion Project will involveinvolves 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. The capital cost of the project is estimated to be up to approximately $284$278 million. Transco plans to place the project into service in phases, in July 2010 and May 2011.
Asset Retirement Obligation Funding Requirement
     Pursuant to the terms of the Agreement (see Note 2 of Notes to Condensed Consolidated Financial

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Statements), Transco iswe are entitled to collect in rates the amounts necessary to fund our ARO. All funds received for such retirements shall be deposited into an external trust account (trust) dedicated to funding our ARO. Effective June 1, 2008, the effective date of the Agreement, Transco waswe were required to initially fund the trust.ARO trust account. On June 30, 2008, Transco paidwe deposited the initial funding of $11.2 million, which included an adjustment for the total spending on ARO requirements as of May 31, 2008. Subsequent to the initial funding, Transcowe will have an annual funding obligation through the effective period of the Agreement of approximately $16.7 million, with installments to be paiddeposited monthly.
ITEM 4. Controls and Procedures.
Evaluation of Disclosure Controls and Procedures
     An evaluation of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) and 15d-15(e) of the Securities Exchange Act) (Disclosure Controls) was performed as of the end 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

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President and Treasurer. Based upon that evaluation, our Senior Vice President and our Vice President and Treasurer have concluded that our Disclosure Controls and procedures were effective at a reasonable assurance level.
     Our management, including our Senior Vice President and our Vice President and Treasurer, does not expect that our 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 the company 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.
SecondThird Quarter 2008 Changes in Internal Control over Financial Reporting
     There have been no changes during the secondthird quarter of 2008 that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

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PART II — OTHER INFORMATION
ITEMS 1. LEGAL PROCEEDINGS.
See discussion in Note 2 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 I, Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2007.2007, includes 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:
Recent events in the global credit markets have created a shortage in the availability of credit.
     Global credit markets have recently experienced a shortage in overall liquidity and a resulting disruption in the availability of credit. While we cannot predict the occurrence of future disruptions or how long the current circumstances may continue, we believe cash on hand and cash provided by operating activities, as well as availability under our existing financing agreements will provide us with adequate liquidity for the foreseeable future. However, our ability to borrow under our existing financing agreements, including Williams’ bank credit facilities, could be impaired if one or more of Williams’ lenders fail to honor its contractual obligation to lend to us.

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Continuing or additional disruptions, including the bankruptcy or restructuring of certain financial institutions, may adversely affect the availability of credit already arranged and the availability and cost of credit in the future.
We are exposed to the credit risk of our customers.
     We are exposed to the credit risk of our customers in the ordinary course of our business. Generally our customers are rated investment grade or are required to make pre-payments or provide security to satisfy credit concerns. However, we cannot predict to what extent our business would be impacted by deteriorating conditions in the economy, including declines in our customers’ creditworthiness. While we monitor these situations carefully and attempt to take appropriate measures to protect ourselves, it is possible that we may have to write down or write off doubtful accounts. Such write-downs or write-offs could negatively affect our operating results for the period in which they occur, and, if significant, could have a material adverse effect on our operating results and financial condition.
Our debt agreements impose restrictions on us that may adversely affect our ability to operate our business.
     Certain of our debt agreements contain covenants that restrict or limit, among other things, our ability to create liens supporting indebtedness, sell assets, make certain distributions, and incur additional debt. In addition, our debt agreements contain, and those we enter into in the future may contain, financial covenants and other limitations with which we will need to comply. Our ability to comply with these covenants may be affected by many events beyond our control, and we cannot assure you that our future operating results will be sufficient to comply with the covenants or, in the event of a default under any of our debt agreements, to remedy that default.
     Our failure to comply with the covenants in our debt agreements and other related transactional documents could result in events of default. Upon the occurrence of such an event of default, the lenders could elect to declare all amounts outstanding under a particular facility to be immediately due and payable and terminate all commitments, if any, to extend further credit. An event of default or an acceleration under one debt agreement could cause a cross-default or cross-acceleration of another debt agreement. Such a cross-default or cross-acceleration could have a wider impact on our liquidity than might otherwise arise from a default or acceleration of a single debt instrument. If an event of default occurs, or if other debt agreements cross-default, and the lenders under the affected debt agreements accelerate the maturity of any loans or other debt outstanding to us, we may not have sufficient liquidity to repay amounts outstanding under such debt agreements.
     Our ability to repay, extend or refinance our existing debt obligations and to obtain future credit will depend primarily on our operating performance, which will be affected by general economic, financial, competitive, legislative, regulatory, business and other factors, many of which are beyond our control.  Our ability to refinance existing debt obligations will also depend upon the current conditions in the credit markets and the availability of credit generally. If we are unable to meet our debt service obligations or obtain future credit on favorable terms, if at all, we could be forced to restructure or refinance our indebtedness, seek additional equity capital or sell assets. We may be unable to obtain financing or sell assets on satisfactory terms, or at all.

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Our costs and funding obligations for defined benefit pension plans and other postretirement benefit plans, in which we participate, are affected by factors beyond our control.
     We are a participating employer in defined benefit pension plans covering substantially all of our U.S. employees and other postretirement benefit plans covering certain eligible participants. The timing and amount of our funding allocation requirements under the defined benefit pension plans in which we participate depend upon a number of factors, including changes to pension plan benefits as well as factors outside of our control, such as asset returns, interest rates and changes in pension laws. Changes to these and other factors that can significantly increase our funding allocation requirements could have a significant adverse effect on our financial condition. The amount of expenses recorded for the defined benefit pension plans and other postretirement benefit plans, in which we participate, is also dependent on changes in several factors, including market interest rates and the returns on plan assets. Significant changes in any of these factors may adversely impact our future results of operations.
ITEM 6. EXHIBITS
The following instruments are included as exhibits to this report. Those exhibits below incorporated by reference herein are indicated as such by the information supplied in the parenthetical thereafter. If no parenthetical appears after an exhibit, copies of the instrument have been included herewith.
(4) Instruments defining the rights of security holders, including indentures
•1    Indenture, dated as of May 22, 2008 between Transcontinental Gas Pipe Line Corporation and The Bank of New York Trust Company, N.A. (filed as Exhibit 4.1 to our Form 8-K filed May 23, 2008).
(10) Material contracts
•1    Registration Rights Agreement, dated as of May 22, 2008 between Transcontinental Gas Pipe Line Corporation and Banc of America Securities LLC, Greenwich Capital Markets, Inc., and J.P. Morgan Securities Inc., acting on behalf of themselves and the several initial purchasers listed on Schedule 1 thereto (filed as Exhibit 10.1 to our Form 8-K filed May 23, 2008).
(31) Section 302 Certifications
 •
-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.
 
 •-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) Section 906 Certification
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.
-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.

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SIGNATURE
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
     
 TRANSCONTINENTAL GAS PIPE LINE
CORPORATION (Registrant)
 		 
Dated: August 7,November 6, 2008 By /s//s/ Jeffrey P. Heinrichs   
 Jeffrey P. Heinrichs  
 Controller
(Principal Accounting Officer) 		 
 

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