e10vq
 



UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549
FORM 10-Q
þ Quarterly Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
For the quarterly period ended June 30, 2005
OR
o Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
                       
 
        Exact name of registrant as           I.R.S.  
  Commission     specified in its charter and principal     State of     Employer  
  File Number     office address and telephone number     Incorporation     I.D. Number  
 
1-16163
    WGL Holdings, Inc.
101 Constitution Ave., N.W.
Washington, D.C. 20080
(703) 750-2000
    Virginia     52-2210912  
 
0-49807
    Washington Gas Light Company
101 Constitution Ave., N.W.
Washington, D.C. 20080
(703) 750-4440
    District of Columbia
and Virginia
    53-0162882  
 

Indicate by check mark whether each registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports) and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o

Indicate by check mark whether each registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act). Yes þ No o

Indicate the number of shares outstanding of each of the issuers’ classes of common stock as of the latest practicable date:

WGL Holdings, Inc. common stock, no par value, outstanding as of July 31, 2005: 48,696,490 shares.

All of the outstanding shares of common stock ($1 par value) of Washington Gas Light Company were held by WGL Holdings, Inc. as of July 31, 2005.



 


 

WGL Holdings, Inc.
Washington Gas Light Company
For the Quarter Ended June 30, 2005
Table of Contents
         
PART I. Financial Information
       
 
Item 1. Financial Statements
       
          WGL Holdings, Inc.
       
          Consolidated Balance Sheets
    1  
          Consolidated Statements of Income
    2  
          Consolidated Statements of Cash Flows
    3  
 
       
          Washington Gas Light Company
       
          Balance Sheets
    4  
          Statements of Income
    5  
          Statements of Cash Flows
    6  
 
       
          Notes to Consolidated Financial Statements
       
          WGL Holdings, Inc. and Washington Gas Light Company—Combined
    7  
 
       
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
    23  
          WGL Holdings, Inc.
    26  
          Washington Gas Light Company
    47  
 
       
Item 3. Quantitative and Qualitative Disclosures About Market Risk
    55  
 
       
Item 4. Controls and Procedures
    55  
 
       
 
       
PART II. Other Information
       
 
Item 6. Exhibits
    56  
 
       
Signature
    57  
 i 

 


 

WGL Holdings, Inc.
Washington Gas Light Company
INTRODUCTION
 
FILING FORMAT
     This Quarterly Report on Form 10-Q is a combined report being filed by two separate registrants: WGL Holdings, Inc. (WGL Holdings or the Company) and Washington Gas Light Company (Washington Gas or the regulated utility). Except where the content clearly indicates otherwise, any reference in the report to “WGL Holdings” or “the Company” is to the consolidated entity, WGL Holdings and all of its subsidiaries, including Washington Gas which is a distinct registrant that is a wholly owned subsidiary of WGL Holdings.
     Part I — Financial Information in this Quarterly Report on Form 10-Q includes separate financial statements (i.e., balance sheets, statements of income and statements of cash flows) for consolidated WGL Holdings and Washington Gas.
SAFE HARBOR FOR FORWARD-LOOKING STATEMENTS
     Certain matters discussed in this report, excluding historical information, include forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995 with respect to the outlook for earnings, revenues and other future financial business performance or strategies and expectations. Forward-looking statements are typically identified by words such as, but not limited to, “estimates,” “expects,” “anticipates,” “intends,” “believes,” “plans,” and similar expressions, or future or conditional verbs such as “will,” “should,” “would,” and “could.” Although the registrants, WGL Holdings and Washington Gas, believe such forward-looking statements are based on reasonable assumptions, they cannot give assurance that every objective will be achieved. Forward-looking statements speak only as of today, and the registrants assume no duty to update them. The following factors, among others, could cause actual results to differ materially from forward-looking statements or historical performance:
    the level and rate at which costs and expenses are incurred in connection with constructing, operating and maintaining the Company’s natural gas distribution system;
 
    the ability to successfully implement approaches to modify the current or future composition of gas being used to supply customers as a result of the introduction of Cove Point gas into the Company’s natural gas distribution system;
 
    variations in weather conditions from normal levels;
 
    changes in economic, competitive, political and regulatory conditions and developments;
 
    changes in capital and energy commodity market conditions;
 
    changes in credit ratings of debt securities of WGL Holdings or Washington Gas that may affect access to capital or the cost of debt;
 
    changes in credit market conditions and creditworthiness of customers and suppliers;
 
    changes in relevant laws and regulations, including tax, environmental and employment laws and regulations;
 
    legislative, regulatory and judicial mandates or decisions affecting business operations or the timing of recovery of costs and expenses;
 
    the timing and success of business and product development efforts and technological improvements;
 
    the pace of deregulation efforts and the availability of other competitive alternatives;
 
    changes in accounting principles;
 
    terrorist activities; and
 
    other uncertainties.
     The outcome of negotiations and discussions that the registrants may hold with other parties from time to time regarding utility and energy-related investments and strategic transactions that are both recurring and non-recurring may also affect future performance. All such factors are difficult to predict accurately and are generally beyond the direct control of the registrants. Accordingly, while they believe that the assumptions are reasonable, the registrants cannot ensure that all expectations and objectives will be realized. Readers are urged to use care and consider the risks, uncertainties and other factors that could affect the registrants’ business as described in this Quarterly Report on Form 10-Q. All forward-looking statements made in this report rely upon the safe harbor protections provided under the Private Securities Litigation Reform Act of 1995.
 ii 

 


 

WGL Holdings, Inc.
Consolidated Balance Sheets (Unaudited)

Part I—Financial Information
Item 1—Financial Statements
                 
 
    June 30,   September 30,
(In thousands)   2005   2004
 
ASSETS
               
Property, Plant and Equipment
               
At original cost
  $ 2,733,740     $ 2,667,924  
Accumulated depreciation and amortization
    (796,647 )     (752,373 )
 
Net property, plant and equipment
    1,937,093       1,915,551  
 
Current Assets
               
Cash and cash equivalents
    68,756       6,587  
Receivables
               
Accounts receivable
    183,986       158,590  
Gas costs due from customers
          4,099  
Accrued utility revenues
    17,828       16,832  
Allowance for doubtful accounts
    (17,199 )     (16,042 )
 
Net receivables
    184,615       163,479  
 
Materials and supplies—principally at average cost
    15,743       15,232  
Storage gas—at cost (first-in, first-out)
    128,747       217,630  
Deferred income taxes
    15,500       13,178  
Other prepayments—principally taxes
    7,830       12,260  
Other
    5,555       4,494  
 
Total current assets
    426,746       432,860  
 
Deferred Charges and Other Assets
               
Regulatory assets
               
Gas costs
    900       16,098  
Other
    48,978       45,847  
Prepaid qualified pension benefits
    74,941       71,869  
Other
    8,652       22,683  
 
Total deferred charges and other assets
    133,471       156,497  
 
Total Assets
  $ 2,497,310     $ 2,504,908  
 
CAPITALIZATION AND LIABILITIES
               
Capitalization
               
Common shareholders’ equity
  $ 922,462     $ 853,424  
Washington Gas Light Company preferred stock
    28,173       28,173  
Long-term debt
    523,681       590,164  
 
Total capitalization
    1,474,316       1,471,761  
 
Current Liabilities
               
Current maturities of long-term debt
    50,119       60,639  
Notes payable
    26,668       95,634  
Accounts payable
    164,947       178,970  
Wages payable
    15,942       16,813  
Accrued interest
    11,845       2,781  
Dividends declared
    16,522       16,142  
Customer deposits and advance payments
    31,711       14,450  
Gas costs due to customers
    10,823       7,815  
Accrued taxes
    46,691       16,627  
Other
    7,096       3,040  
 
Total current liabilities
    382,364       412,911  
 
Deferred Credits
               
Unamortized investment tax credits
    14,271       14,944  
Deferred income taxes
    274,019       268,540  
Accrued pensions and benefits
    39,603       37,047  
Regulatory liabilities
               
Accrued asset removal costs
    266,961       251,695  
Other
    17,056       22,079  
Other
    28,720       25,931  
 
Total deferred credits
    640,630       620,236  
 
Commitments and Contingencies (Note 10)
               
 
Total Capitalization and Liabilities
  $ 2,497,310     $ 2,504,908  
 
The accompanying notes are an integral part of these statements.

1


 

WGL Holdings, Inc.
Consolidated Statements of Income (Unaudited)

Part I—Financial Information
Item 1—Financial Statements (continued)
                                 
 
    Three Months Ended   Nine Months Ended
    June 30,   June 30,
 
(In thousands, except per share data)   2005   2004   2005   2004
 
UTILITY OPERATIONS
                               
Operating Revenues
  $ 197,629     $ 180,836     $ 1,241,806     $ 1,144,798  
Less: Cost of gas
    99,576       83,811       712,746       619,575  
Revenue taxes
    9,930       8,374       50,804       42,653  
 
Utility Net Revenues
    88,123       88,651       478,256       482,570  
 
Other Operating Expenses
                               
Operation
    50,605       43,678       147,945       139,341  
Maintenance
    11,428       13,372       29,623       34,135  
Depreciation and amortization
    22,663       20,956       66,277       69,122  
General taxes
    10,389       8,014       31,643       28,667  
Income tax expense (benefit)
    (5,931 )     (5,011 )     64,783       69,376  
 
Utility Other Operating Expenses
    89,154       81,009       340,271       340,641  
 
Utility Operating Income (Loss)
    (1,031 )     7,642       137,985       141,929  
 
NON-UTILITY OPERATIONS
                               
Operating Revenues
                               
Retail energy-marketing
    143,613       169,828       634,819       637,766  
Heating, ventilating and air conditioning (HVAC)
    7,355       5,717       24,557       20,497  
Other non-utility activities
    386       471       999       1,332  
 
Non-Utility Operating Revenues
    151,354       176,016       660,375       659,595  
 
Other Operating Expenses
                               
Operating expenses
    145,719       176,305       640,231       654,918  
Income tax expense (benefit)
    2,200       (200 )     7,823       1,914  
 
Non-Utility Operating Expenses
    147,919       176,105       648,054       656,832  
 
Non-Utility Operating Income (Loss)
    3,435       (89 )     12,321       2,763  
 
TOTAL OPERATING INCOME
    2,404       7,553       150,306       144,692  
Other Income (Expenses)—Net
    (50 )     216       (1,985 )     4,849  
 
INCOME BEFORE INTEREST EXPENSE
    2,354       7,769       148,321       149,541  
INTEREST EXPENSE
                               
Interest on long-term debt
    9,941       10,440       30,939       31,375  
Other—net
    276       1,127       1,507       2,529  
 
Total Interest Expense
    10,217       11,567       32,446       33,904  
DIVIDENDS ON WASHINGTON GAS PREFERRED STOCK
    330       330       990       990  
 
NET INCOME (LOSS) (APPLICABLE TO COMMON STOCK)
  $ (8,193 )   $ (4,128 )   $ 114,885     $ 114,647  
 
AVERAGE COMMON SHARES OUTSTANDING
                               
Basic
    48,695       48,648       48,684       48,638  
Diluted
    48,695       48,648       48,991       48,848  
 
EARNINGS (LOSS) PER AVERAGE COMMON SHARE
                               
Basic
  $ (0.17 )   $ (0.08 )   $ 2.36     $ 2.36  
Diluted
  $ (0.17 )   $ (0.08 )   $ 2.35     $ 2.35  
 
DIVIDENDS DECLARED PER COMMON SHARE
  $ 0.3325     $ 0.3250     $ 0.9900     $ 0.9700  
 
The accompanying notes are an integral part of these statements.

2


 

WGL Holdings, Inc.
Consolidated Statements of Cash Flows (Unaudited)

Part I—Financial Information
Item 1—Financial Statements (continued)
                 
 
    Nine Months Ended
    June 30,
 
(In thousands)   2005   2004
 
OPERATING ACTIVITIES
               
Net income (applicable to common stock)
  $ 114,885     $ 114,647  
 
               
ADJUSTMENTS TO RECONCILE NET INCOME TO NET CASH PROVIDED
               
BY OPERATING ACTIVITIES
               
Depreciation and amortization:
               
Per Consolidated Statements of Income
    66,277       69,122  
Charged to other accounts
    3,242       4,125  
Deferred income taxes—net
    3,671       12,273  
Amortization of investment tax credits
    (673 )     (673 )
Accrued/deferred pension cost
    (3,759 )     (3,748 )
Earnings from sale of carried interest in real estate
          (6,414 )
Other non-cash charges (credits)—net
    3,004       352  
 
               
CHANGES IN ASSETS AND LIABILITIES
               
Accounts receivable and accrued utility revenues
    (25,235 )     (50,511 )
Gas costs due from/to customers—net
    7,107       13,426  
Storage gas
    88,883       38,261  
Other prepayments—principally taxes
    4,430       17,418  
Accounts payable
    (14,023 )     45,890  
Wages payable
    (871 )     (1,146 )
Customer deposits and advance payments
    17,261       2,716  
Accrued taxes
    30,064       42,766  
Accrued interest
    9,064       10,044  
Deferred purchased gas costs—net
    15,198       8,362  
Other—net
    (3,861 )     6,528  
 
Net Cash Provided by Operating Activities
    314,664       323,438  
 
FINANCING ACTIVITIES
               
Common stock issued
    367        
Long-term debt issued
    93       37,000  
Long-term debt retired
    (60,672 )     (36,152 )
Debt issuance costs
          (809 )
Notes payable retired—net
    (68,966 )     (104,654 )
Dividends on common stock
    (47,832 )     (46,936 )
Other financing activities—net
    (421 )     2,219  
 
Net Cash Used in Financing Activities
    (177,431 )     (149,332 )
 
INVESTING ACTIVITIES
               
Capital expenditures (excludes Allowance for Funds Used During Construction)
    (73,127 )     (79,124 )
Net proceeds from sale of carried interest in real estate
          6,414  
Other investing activities—net
    (1,937 )     (272 )
 
Net Cash Used in Investing Activities
    (75,064 )     (72,982 )
 
INCREASE IN CASH AND CASH EQUIVALENTS
    62,169       101,124  
Cash and Cash Equivalents at Beginning of Year
    6,587       4,470  
 
Cash and Cash Equivalents at End of Period
  $ 68,756     $ 105,594  
 
 
               
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION
               
Income taxes paid
  $ 39,839     $ 13,498  
Interest paid
  $ 22,605     $ 23,063  
SUPPLEMENTAL DISCLOSURES OF NON-CASH INVESTING AND FINANCING ACTIVITIES
               
Extinguishment of project debt financing
  $ 16,447     $  
The accompanying notes are an integral part of these statements.

3


 

Washington Gas Light Company
Balance Sheets (Unaudited)

Part I—Financial Information
Item 1—Financial Statements (continued)
                 
 
    June 30,   September 30,
(In thousands)   2005   2004
 
ASSETS
               
Property, Plant and Equipment
               
At original cost
  $ 2,707,801     $ 2,642,815  
Accumulated depreciation and amortization
    (776,957 )     (733,894 )
 
Net property, plant and equipment
    1,930,844       1,908,921  
 
Current Assets
               
Cash and cash equivalents
    65,151       3,398  
Receivables
               
Accounts receivable
    110,658       66,602  
Gas costs due from customers
          4,099  
Accrued utility revenues
    17,828       16,832  
Allowance for doubtful accounts
    (14,809 )     (13,202 )
 
Net receivables
    113,677       74,331  
 
Materials and supplies—principally at average cost
    15,579       15,068  
Storage gas—at cost (first-in, first-out)
    93,510       165,196  
Deferred income taxes
    14,433       11,654  
Other prepayments—principally taxes
    7,708       9,749  
Receivables from associated companies
    3,208       887  
 
Total current assets
    313,266       280,283  
 
Deferred Charges and Other Assets
               
Regulatory assets
               
Gas costs
    900       16,098  
Other
    48,978       45,847  
Prepaid qualified pension benefits
    74,567       71,511  
Other
    7,525       21,757  
 
Total deferred charges and other assets
    131,970       155,213  
 
Total Assets
  $ 2,376,080     $ 2,344,417  
 
CAPITALIZATION AND LIABILITIES
               
Capitalization
               
Common shareholder’s equity
  $ 868,769     $ 811,632  
Preferred stock
    28,173       28,173  
Long-term debt
    523,681       590,156  
 
Total capitalization
    1,420,623       1,429,961  
 
Current Liabilities
               
Current maturities of long-term debt
    50,119       60,611  
Notes payable
    13       18,699  
Accounts payable
    107,300       123,463  
Wages payable
    15,784       16,714  
Accrued interest
    11,845       2,781  
Dividends declared
    16,522       16,142  
Customer deposits and advance payments
    28,710       14,450  
Gas costs due to customers
    10,823       7,815  
Accrued taxes
    43,587       13,422  
Payables to associated companies
    23,713       19,092  
Other
    5,458       622  
 
Total current liabilities
    313,874       293,811  
 
Deferred Credits
               
Unamortized investment tax credits
    14,256       14,926  
Deferred income taxes
    276,457       270,908  
Accrued pensions and benefits
    39,513       36,954  
Regulatory liabilities
               
Accrued asset removal costs
    266,961       251,695  
Other
    17,048       22,069  
Other
    27,348       24,093  
 
Total deferred credits
    641,583       620,645  
 
Commitments and Contingencies (Note 10)
               
 
Total Capitalization and Liabilities
  $ 2,376,080     $ 2,344,417  
 
The accompanying notes are an integral part of these statements.

4


 

Washington Gas Light Company
Statements of Income (Unaudited)

Part I—Financial Information
Item 1—Financial Statements (continued)
                                 
 
    Three Months Ended   Nine Months Ended
    June 30,   June 30,
 
(In thousands)   2005   2004   2005   2004
 
UTILITY OPERATIONS
                               
Operating Revenues
  $ 200,060     $ 183,079     $ 1,256,922     $ 1,169,490  
Less: Cost of gas
    102,007       85,997       727,862       644,210  
Revenue taxes
    9,930       8,374       50,804       42,653  
 
Utility Net Revenues
    88,123       88,708       478,256       482,627  
 
Other Operating Expenses
                               
Operation
    51,153       44,316       149,416       140,937  
Maintenance
    11,319       13,309       29,332       33,921  
Depreciation and amortization
    22,483       20,781       65,740       68,597  
General taxes
    10,313       7,918       31,423       28,310  
Income tax expense (benefit)
    (6,003 )     (5,109 )     64,618       69,176  
 
Utility Other Operating Expenses
    89,265       81,215       340,529       340,941  
 
Utility Operating Income (Loss)
    (1,142 )     7,493       137,727       141,686  
 
NON-UTILITY OPERATIONS
                               
Operating Revenues
                               
Other non-utility
    365       426       874       1,244  
 
Non-Utility Operating Revenues
    365       426       874       1,244  
 
Other Operating Expenses
                               
Operating expenses (income)
          46       1       (912 )
Income taxes
    142       150       340       850  
 
Non-Utility Operating Expenses (Income)
    142       196       341       (62 )
 
Non-Utility Operating Income
    223       230       533       1,306  
 
TOTAL OPERATING INCOME (LOSS)
    (919 )     7,723       138,260       142,992  
Other Income (Expenses) — Net
    206       160       (2,369 )     (1,034 )
 
INCOME (LOSS) BEFORE INTEREST EXPENSE
    (713 )     7,883       135,891       141,958  
INTEREST EXPENSE
                               
Interest on long-term debt
    9,941       10,440       30,939       31,375  
Other—net
    (29 )     1,284       330       2,801  
 
Total Interest Expense
    9,912       11,724       31,269       34,176  
 
NET INCOME (LOSS) (BEFORE PREFERRED STOCK DIVIDENDS)
  $ (10,625 )   $ (3,841 )   $ 104,622     $ 107,782  
DIVIDENDS ON PREFERRED STOCK
    330       330       990       990  
 
NET INCOME (LOSS) (APPLICABLE TO COMMON STOCK)
  $ (10,955 )   $ (4,171 )   $ 103,632     $ 106,792  
 
The accompanying notes are an integral part of these statements.

5


 

Washington Gas Light Company
Statements of Cash Flows (Unaudited)

Part I—Financial Information
Item 1—Financial Statements (continued)
                 
 
    Nine Months Ended
    June 30,
 
(In thousands)   2005   2004
 
OPERATING ACTIVITIES
               
Net income (before preferred stock dividends)
  $ 104,622     $ 107,782  
 
               
ADJUSTMENTS TO RECONCILE NET INCOME TO NET CASH PROVIDED
               
BY OPERATING ACTIVITIES
               
Depreciation and amortization:
               
Per Statements of Income
    65,740       68,597  
Charged to other accounts
    2,922       3,818  
Deferred income taxes—net
    3,286       15,060  
Amortization of investment tax credits
    (669 )     (669 )
Accrued/deferred pension cost
    (3,750 )     (3,729 )
Other non-cash charges (credits)—net
    2,731       266  
 
               
CHANGES IN ASSETS AND LIABILITIES
               
Accounts receivable, accrued utility revenues and receivables from associated companies
    (45,766 )     (47,899 )
Gas costs due from/to customers—net
    7,107       13,426  
Storage gas
    71,686       28,877  
Other prepayments—principally taxes
    2,041       13,359  
Accounts payable, including payables to associated companies
    (11,542 )     20,840  
Wages payable
    (930 )     (1,141 )
Customer deposits and advance payments
    14,260       2,716  
Accrued taxes
    30,165       46,293  
Accrued interest
    9,064       10,044  
Deferred purchased gas costs—net
    15,198       8,362  
Other—net
    (1,713 )     2,366  
 
Net Cash Provided by Operating Activities
    264,452       288,368  
 
FINANCING ACTIVITIES
               
Long-term debt issued
    93       37,000  
Long-term debt retired
    (60,636 )     (36,085 )
Debt issuance costs
          (809 )
Notes payable retired—net
    (18,686 )     (65,214 )
Dividends on common and preferred stock
    (48,820 )     (47,924 )
Other financing activities—net
    (430 )     1,651  
 
Net Cash Used in Financing Activities
    (128,479 )     (111,381 )
 
INVESTING ACTIVITIES
               
Capital expenditures (excludes Allowance for Funds Used During Construction)
    (72,169 )     (78,815 )
Other investing activities—net
    (2,051 )     (272 )
 
Net Cash Used in Investing Activities
    (74,220 )     (79,087 )
 
INCREASE IN CASH AND CASH EQUIVALENTS
    61,753       97,900  
Cash and Cash Equivalents at Beginning of Year
    3,398       4,119  
 
Cash and Cash Equivalents at End of Period
  $ 65,151     $ 102,019  
 
 
               
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION
               
Income taxes paid
  $ 34,505     $ 10,320  
Interest paid
  $ 21,428     $ 23,243  
 
               
SUPPLEMENTAL DISCLOSURES OF NON-CASH INVESTING AND FINANCING ACTIVITIES
               
Extinguishment of project debt financing
  $ 16,447     $  
The accompanying notes are an integral part of these statements.

6


 

WGL Holdings, Inc.
Washington Gas Light Company

Part I — Financial Information
Item 1 — Financial Statements (continued)
Notes to Consolidated Financial Statements (Unaudited)
NOTE 1. ACCOUNTING POLICIES
 
     Basis of Presentation
     WGL Holdings, Inc. (WGL Holdings or the Company) is the parent of four direct, wholly owned subsidiaries that include Washington Gas Light Company (Washington Gas or the regulated utility), Crab Run Gas Company, Hampshire Gas Company (Hampshire) and Washington Gas Resources Corporation (Washington Gas Resources). Washington Gas Resources owns unregulated subsidiaries that include, among others, Washington Gas Energy Services, Inc. (WGEServices), American Combustion Industries, Inc. (ACI) and Washington Gas Energy Systems, Inc. (WGESystems). Reference is made to the combined Annual Report on Form 10-K for WGL Holdings and Washington Gas for the fiscal year ended September 30, 2004 filed with the Securities and Exchange Commission (SEC) for additional information on the corporate structure.
     The Notes to Consolidated Financial Statements are an integral part of the accompanying consolidated financial statements of WGL Holdings and its subsidiaries, including Washington Gas. Except where otherwise noted, these notes apply equally to WGL Holdings and Washington Gas. Due to the seasonal nature of Washington Gas’ and WGEServices’ businesses, the results of operations presented herein do not necessarily represent the expected results of either WGL Holdings or Washington Gas for the full fiscal years ending September 30, 2005 and 2004.
     The interim consolidated financial statements have been prepared pursuant to the rules and regulations of the SEC. Therefore, certain financial information and footnote disclosures accompanying annual financial statements prepared in accordance with Generally Accepted Accounting Principles in the United States of America (GAAP) are omitted in this interim report pursuant to the SEC rules and regulations. The interim consolidated financial statements and notes thereto should be read in conjunction with the combined Annual Report on Form 10-K for WGL Holdings and Washington Gas for the fiscal year ended September 30, 2004.
     The accompanying unaudited consolidated financial statements for WGL Holdings and Washington Gas reflect all normal recurring adjustments that are necessary, in the opinion of management, to present fairly the results of operations in accordance with GAAP.
     For a description of the Company’s accounting policies, refer to Note 1 of the Notes to Consolidated Financial Statements of the combined Annual Report on Form 10-K for WGL Holdings and Washington Gas for the fiscal year ended September 30, 2004. There have been no significant changes to these policies subsequent to September 30, 2004.
     Stock-Based Compensation
     As permitted by Statement of Financial Accounting Standards (SFAS) No. 123, Accounting for Stock-Based Compensation, as amended by SFAS No. 148, Accounting for Stock-Based Compensation-Transition and Disclosure, the Company applies Accounting Principles Board (APB) Opinion No. 25, Accounting for Stock Issued to Employees, and related interpretations in accounting for its stock-based compensation plans. In accordance with APB Opinion No. 25, the Company does not record compensation expense related to its stock option grants. The Company records compensation expense for performance shares awarded to certain key employees. If compensation expense for stock options had been determined and recorded based on fair value at their grant dates consistent with the method prescribed by SFAS No. 123, as amended, the Company’s net income (loss) and earnings (loss) per share would have been reduced to the amounts shown in the following table.

7


 

WGL Holdings, Inc.
Washington Gas Light Company
Part I — Financial Information
Item 1 — Financial Statements (continued)
Notes to Consolidated Financial Statements (Unaudited)

                                     
Pro Forma Effect of Stock-Based Compensation
        Three Months Ended   Nine Months Ended
        June 30,   June 30,
 
(In thousands, except per share data)     2005       2004       2005       2004  
 
Net income (loss) as reported   $ (8,193 )   $ (4,128 )   $ 114,885     $ 114,647  
Add:
  Stock-based employee compensation expense                                
 
  included in reported net income, net of tax (a)     823       300       2,036       1,260  
Deduct:
  Total stock-based employee compensation expense                                
 
  determined under the fair value-based method, net of tax (b)     (955 )     (408 )     (2,432 )     (1,584 )
 
Pro forma net income (loss)   $ (8,325 )   $ (4,236 )   $ 114,489     $ 114,323  
 
Earnings (loss) per average common share—basic                                
     As reported   $ (0.17 )   $ (0.08 )   $ 2.36     $ 2.36  
     Pro forma   $ (0.17 )   $ (0.09 )   $ 2.35     $ 2.35  
 
Earnings (loss) per average common share—diluted                                
     As reported   $ (0.17 )   $ (0.08 )   $ 2.35     $ 2.35  
     Pro forma   $ (0.17 )   $ (0.09 )   $ 2.34     $ 2.34  
 
(a)   Reflects compensation expense related to performance shares.
(b)   Reflects compensation expense related to performance shares and stock options.
     Recent Accounting Standards
     In May 2005, the Financial Accounting Standards Board (FASB) issued SFAS No. 154, Accounting Changes and Error Corrections, which supersedes APB Opinion No. 20, Accounting Changes and SFAS No. 3, Reporting Accounting Changes in Interim Financial Statements. SFAS No. 154 changes the requirements for the accounting for and reporting of a change in accounting principle. SFAS No. 154 requires retrospective application to prior period financial statements of changes in accounting principle, unless it is impracticable. SFAS No. 154 is effective for the Company on October 1, 2006.
     In March 2005, the FASB issued FASB Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations (FIN 47). FIN 47 clarifies the manner of accounting for asset retirement obligations (ARO) containing uncertainties as to the timing and/or method of settlement of the obligation. FIN 47 also clarifies the circumstances under which the fair value of the ARO is considered subject to reasonable estimation. FIN 47 is effective for the Company no later than September 30, 2006. Management is currently evaluating the effect of this new standard, but does not believe it will materially affect the Company’s consolidated financial statements.
     In December 2004, the FASB  issued SFAS No. 123 (revised 2004), Share-Based Payment, which revises SFAS No. 123 and supersedes APB Opinion No. 25 (collectively referred to as “SFAS No. 123 (revised)”). SFAS No. 123 (revised) requires all share-based payment transactions, including stock options, restricted stock plans, performance-based awards, share appreciation rights, and employee stock purchase plans, to be recognized as compensation expense in the financial statements. The cost will be measured based on the fair value of the equity or liability instruments issued. SFAS No. 123 (revised) was initially required to be adopted by the Company on July 1, 2005. In April 2005, the SEC issued a final rule that amended the effective date of the new standard for SEC registrants. Accordingly, SFAS No. 123 (revised) is effective for the Company on October 1, 2005 pursuant to the SEC rule. Management is currently evaluating the effect of this new standard, but does not believe it will materially affect the Company’s consolidated financial statements.
     In December 2004, the FASB issued SFAS No. 153, Exchanges of Nonmonetary Assets, an amendment of APB Opinion No. 29, Accounting for Nonmonetary Transactions. SFAS No. 153 redefines the types of nonmonetary exchanges that require fair value measurement. SFAS No. 153

8


 

WGL Holdings, Inc.
Washington Gas Light Company
Part I — Financial Information
Item 1 — Financial Statements (continued)
Notes to Consolidated Financial Statements (Unaudited)

will be effective for the Company for nonmonetary transactions entered into on and after July 1, 2005. Accordingly, this standard had no effect on the Company’s consolidated financial statements as of and for the periods ended June 30, 2005.
     In November 2004, the FASB issued SFAS No. 151, Inventory Costs. SFAS No. 151 requires that abnormal amounts of idle facility expense, freight, handling costs and spoilage be charged to income as a current period expense rather than capitalized as inventory costs. SFAS No. 151 is effective for the Company for inventory costs incurred on and after October 1, 2005. Management is currently evaluating the effect of this new standard, but does not believe it will materially affect the Company’s consolidated financial statements.
NOTE 2. SHORT-TERM DEBT
 
     On June 30, 2005 and September 30, 2004, WGL Holdings and its subsidiaries had $26.7 million and $95.6 million, respectively, of short-term debt outstanding in the form of commercial paper, at a weighted average cost of 3.32 percent and 1.99 percent, respectively. Substantially all of the outstanding short-term debt balance at June 30, 2005 was commercial paper issued by WGL Holdings. Of the outstanding short-term debt balance at September 30, 2004, $76.9 million was commercial paper issued by WGL Holdings and $18.7 million was commercial paper issued by Washington Gas.
     WGL Holdings and Washington Gas each have a $175 million back-up line of credit with a group of commercial banks to support their commercial paper borrowings. The credit facility for Washington Gas expires on April 28, 2009, and permits the regulated utility to request prior to April 28, 2008, and the banks to approve, an additional line of credit of $100 million above the original credit limit, for a maximum potential total of $275 million. WGL Holdings’ credit facility expires on April 27, 2007, and permits the Company to request prior to April 28, 2006, and the banks to approve, an additional line of credit of $50 million above the original credit limit, for a maximum potential total of $225 million. There were no outstanding borrowings under these credit facilities at June 30, 2005 or September 30, 2004.
NOTE 3. LONG-TERM DEBT
 
     Washington Gas issues unsecured Medium-Term Notes (MTNs) with individual terms regarding interest rates, maturities and call or put options. These notes can have maturity dates of one or more years from the date of issuance. At June 30, 2005, Washington Gas was authorized to issue up to $213.0 million of long-term debt under a shelf registration that was declared effective by the SEC on April 24, 2003.
     During the nine months ended June 30, 2005, Washington Gas retired a total of $60.5 million of MTNs. On March 7, 2005, Washington Gas, through exercise of a call option, retired $20.0 million of MTNs. The MTNs redeemed were $10.0 million of 7.76 percent MTNs and $10.0 million of 7.75 percent MTNs that had a nominal maturity date in March 2025. On June 9, 2005, Washington Gas, through exercise of a call option, retired $20.0 million of 6.50 percent MTNs that had a nominal maturity date in June 2025. Additionally, on June 20, 2005, Washington Gas retired $20.5 million of 7.45 percent MTNs that matured on the same date. Washington Gas paid the applicable accrued interest on each debt retirement date.
     On August 4, 2005, Washington Gas agreed to sell $20.0 million of 4.83 percent MTNs due August 2015 to replace the MTNs retired on March 7, 2005, as discussed above. The issuance of this $20.0 million of MTNs is expected to occur on August 9, 2005. On August 8, 2005, Washington Gas agreed to sell $40.5 million of 5.44 percent MTNs due 2025 to replace the MTNs retired in June 2005, as discussed above. The issuance of this $40.5 million of MTNs is expected to occur on August 11, 2005. Refer to Note 7—Derivative Instruments for a discussion of derivative transactions that will be settled concurrent with these expected new debt issues discussed herein.

9


 

WGL Holdings, Inc.
Washington Gas Light Company
Part I — Financial Information
Item 1 — Financial Statements (continued)
Notes to Consolidated Financial Statements (Unaudited)

NOTE 4. COMMON SHAREHOLDERS’ EQUITY
 
     The tables below reflect the components of “Common shareholders’ equity” for WGL Holdings, Inc. and Washington Gas Light Company as of June 30, 2005 and September 30, 2004.
                 
WGL Holdings, Inc.
Components of Common Shareholders' Equity
(In thousands, except shares)   Jun. 30, 2005   Sept. 30, 2004
 
Common stock, no par value, 120,000,000 shares authorized, 48,696,490 and 48,652,507 shares issued, respectively
  $ 472,784     $ 471,547  
Paid-in capital
    5,882       3,789  
Retained earnings
    446,235       379,562  
Deferred compensation
    1       (5 )
Accumulated other comprehensive loss, net of taxes
    (2,440 )     (1,469 )
 
Total
  $ 922,462     $ 853,424  
 
                 
Washington Gas Light Company
Components of Common Shareholder's Equity
(In thousands, except shares)   Jun. 30, 2005   Sept. 30, 2004
 
Common stock, $1 par value, 80,000,000 shares authorized, 46,479,536 shares issued
  $ 46,479     $ 46,479  
Paid-in capital
    455,080       452,400  
Retained earnings
    369,649       314,227  
Deferred compensation
    1       (5 )
Accumulated other comprehensive loss, net of taxes
    (2,440 )     (1,469 )
 
Total
  $ 868,769     $ 811,632  
 
NOTE 5. COMPREHENSIVE INCOME (LOSS)
 
     The tables below reflect the components of “Comprehensive income (loss)” for the three and nine months ended June 30, 2005 and 2004 for WGL Holdings, Inc. and Washington Gas Light Company. Items that are excluded from “Net income (loss)” and charged directly to “Common shareholders’ equity” are accumulated in “Other comprehensive income (loss), net of taxes.” The amount of “Accumulated other comprehensive loss, net of taxes” is included in “Common shareholders’ equity” (refer to Note 4—Common Shareholders’ Equity).
                                 
WGL Holdings, Inc.
Components of Comprehensive Income (Loss)
    Three Months Ended   Nine Months Ended
    June 30,   June 30,
 
(In thousands)
    2005       2004       2005       2004  
 
Net income (loss) (applicable to common stock)
  $ (8,193 )   $ (4,128 )   $ 114,885     $ 114,647  
Other comprehensive income (loss), net of taxes — minimum pension liability adjustment
                (971 )     61  
 
Comprehensive income (loss)
  $ (8,193 )   $ (4,128 )   $ 113,914     $ 114,708  
 

10


 

WGL Holdings, Inc.
Washington Gas Light Company

Part I — Financial Information
Item 1 — Financial Statements (continued)
Notes to Consolidated Financial Statements (Unaudited)

                                 
Washington Gas Light Company
Components of Comprehensive Income (Loss)
    Three Months Ended   Nine Months Ended
    June 30,   June 30,
 
(In thousands)
    2005       2004       2005       2004  
 
Net income (loss) (before preferred stock dividends)
  $ (10,625 )   $ (3,841 )   $ 104,622     $ 107,782  
Other comprehensive income (loss), net of taxes — minimum pension liability adjustment
                (971 )     61  
 
Comprehensive income (loss)
  $ (10,625 )   $ (3,841 )   $ 103,651     $ 107,843  
 
NOTE 6. EARNINGS (LOSS) PER SHARE
 
     Basic earnings (loss) per share (EPS) is computed by dividing net income (loss) by the weighted average number of common shares outstanding during the reported period. Diluted EPS assumes the issuance of common shares pursuant to stock-based compensation plans at the beginning of the applicable period. During interim periods in which the Company incurs a net loss, common shares pursuant to stock-based compensation plans are not considered in diluted loss per share computations due to the anti-dilutive effect of such shares. The following table reflects the computation of the Company’s basic and diluted EPS for WGL Holdings for the three and nine months ended June 30, 2005 and 2004.
                         
Basic and Diluted EPS
    Net            
    Income           Per Share
(In thousands, except per share data)   (Loss)   Shares   Amount
 
Three Months Ended June 30, 2005
                       
Basic EPS:
                       
Net loss
  $ (8,193 )     48,695     $ (0.17 )
Stock-based compensation plans
                 
 
Diluted EPS:
                       
Net loss
  $ (8,193 )     48,695     $ (0.17 )
 
Three Months Ended June 30, 2004
                       
Basic EPS:
                       
Net loss
  $ (4,128 )     48,648     $ (0.08 )
Stock-based compensation plans
                 
 
Diluted EPS:
                       
Net loss
  $ (4,128 )     48,648     $ (0.08 )
 
Nine Months Ended June 30, 2005
                       
Basic EPS:
                       
Net income
  $ 114,885       48,684     $ 2.36  
Stock-based compensation plans
          307        
 
Diluted EPS:
                       
Net income
  $ 114,885       48,991     $ 2.35  
 
Nine Months Ended June 30, 2004
                       
Basic EPS:
                       
Net income
  $ 114,647       48,638     $ 2.36  
Stock-based compensation plans
          210        
 
Diluted EPS:
                       
Net income
  $ 114,647       48,848     $ 2.35  
 

11


 

WGL Holdings, Inc.
Washington Gas Light Company

Part I — Financial Information
Item 1 — Financial Statements (continued)
Notes to Consolidated Financial Statements (Unaudited)

NOTE 7. DERIVATIVE INSTRUMENTS
 
     Washington Gas enters into forward contracts and other related transactions for the purchase of natural gas that qualify as derivative instruments under SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended by SFAS No. 138, Accounting for Certain Derivative Instruments and Certain Hedging Activities and SFAS No. 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities (collectively referred to as “SFAS No. 133”). The net fair value loss of certain of these forward contracts and other related transactions at June 30, 2005, September 30, 2004 and June 30, 2004 totaled $3.6 million, $8.2 million and $6.3 million, respectively. These amounts were recorded as payables, with corresponding amounts recorded as regulatory assets in accordance with regulatory accounting requirements for recoverable costs.
     Washington Gas enters into derivative instruments that are designed to minimize interest-rate risk associated with planned issuances of MTNs. On September 16, 2004, Washington Gas entered into two forward-starting swaps with an aggregate notional principal amount of $60.5 million. These swaps were intended to mitigate a substantial portion of the risk of rising interest rates associated with anticipated future debt issuances and will terminate concurrent with the execution of these debt issuances. The forward-starting swaps were designated as cash flow hedges and are carried at fair value. These swaps had a fair value loss totaling $5.3 million and $475,000 at June 30, 2005 and September 30, 2004, respectively, that was recorded as a payable with a corresponding amount recorded as a regulatory asset.
     Concurrent with the decision to sell $20.0 million of 4.83 percent MTNs on August 4, 2005 (refer to Note 3—Long-Term Debt), Washington Gas agreed to terminate $20.0 million of the total $60.5 million aggregate notional principal amount of the forward-starting swaps, as discussed above. Washington Gas is expected to pay $364,000 on August 9, 2005 associated with the settlement of this hedge agreement. This cost will be recorded as a regulatory asset, and will be amortized over the life of the newly issued MTNs in accordance with regulatory accounting. Similarly, concurrent with the decision to sell $40.5 million of 5.44 percent MTNs on August 8, 2005 (refer to Note 3—Long-Term Debt), Washington Gas agreed to terminate the remaining $40.5 million notional principal amount of the forward-starting swaps. Washington Gas is expected to pay $2.2 million on August 11, 2005 associated with the settlement of this hedge agreement. This cost will be recorded as a regulatory asset, and will be amortized over the life of the newly issued MTNs in accordance with regulatory accounting.
     In July 2005, Washington Gas entered into two forward-starting swaps with an aggregate notional principal amount of $50.0 million. These swaps are intended to mitigate a substantial portion of the risk of rising interest rates associated with anticipated future debt issuances, and are scheduled to terminate concurrent with the execution of these debt issuances that are planned for May 2006.
     The Company’s non-regulated retail energy-marketing subsidiary, WGEServices, enters into contracts for the sale and purchase of natural gas that qualify as derivative instruments under SFAS No. 133. WGEServices also enters into other derivative instruments (primarily in the form of call options, put options and swap contracts) related to the sale and purchase of natural gas. WGEServices’ derivative instruments are recorded at fair value on the Company’s consolidated balance sheets. Changes in the fair value of these various derivative instruments are reflected in the earnings of the retail energy-marketing segment. At June 30, 2005, September 30, 2004 and June 30, 2004, these derivative instruments were recorded on the Company’s consolidated balance sheets as a fair value gain of $715,000, $719,000 and $292,000, respectively. In connection with these derivative instruments, WGEServices recorded pre-tax losses of $233,000 and $876,000 for the three and nine months ended June 30, 2005, respectively. WGEServices recorded pre-tax gains of $214,000 and $699,000 for the three and nine months ended June 30, 2004, respectively.

12


 

WGL Holdings, Inc.
Washington Gas Light Company
Part I — Financial Information
Item 1 — Financial Statements (continued)
Notes to Consolidated Financial Statements (Unaudited)

NOTE 8. OPERATING SEGMENT REPORTING
 
     WGL Holdings reports three operating segments: (i) regulated utility; (ii) retail energy-marketing; and (iii) heating, ventilating and air conditioning (HVAC) activities.
     With approximately 95 percent of WGL Holdings’ consolidated total assets, the regulated utility segment is the Company’s core business. Represented by Washington Gas and Hampshire, the regulated utility segment provides regulated gas distribution services (including the sale and delivery of natural gas, meter reading, responding to customer inquiries and bill preparation) to customers primarily in Washington, D.C. and the surrounding metropolitan areas in Maryland and Virginia. In addition to the regulated operations of Washington Gas, the regulated utility segment includes the operations of Hampshire, an underground natural gas storage facility that is regulated under a cost of service tariff by the Federal Energy Regulatory Commission (FERC), and provides services exclusively to Washington Gas.
     Through WGEServices, the retail energy-marketing segment sells natural gas and electricity directly to retail customers, both inside and outside of Washington Gas’ traditional service territory, in competition with unregulated gas and electricity marketers. Through two wholly owned subsidiaries, ACI and WGESystems, the commercial HVAC segment designs, renovates and services mechanical heating, ventilating and air conditioning systems for commercial and governmental customers.
     Certain activities of the Company are not significant enough on a stand-alone basis to warrant treatment as an operating segment and the activities do not fit into one of the segments contained in the Company’s financial statements. For purposes of segment reporting, these activities are aggregated in the category “Other Activities” of the Company’s non-utility operations as presented below in the Operating Segment Financial Information. These activities are included in the Consolidated Statements of Income in the appropriate lines, revenues and expenses in “Non-Utility Operations.”
     The same accounting policies applied in preparing the Company’s consolidated financial statements also apply to the reported segments. While net income or loss are the primary criteria for measuring a segment’s performance, the Company also evaluates its operating segments based on other relevant factors, such as penetration into their respective markets and return on invested capital. The following tables present operating segment information for the three and nine months ended June 30, 2005 and 2004.

13


 

WGL Holdings, Inc.
Washington Gas Light Company
Part I — Financial Information
Item 1 — Financial Statements (continued)
Notes to Consolidated Financial Statements (Unaudited)

                                                         
Operating Segment Financial Information
            Non-Utility Operations                
    Regulated   Retail Energy-           Other           Eliminations/    
(In thousands)   Utility   Marketing   HVAC   Activities   Total   Other   Consolidated
 
Three Months Ended June 30, 2005
                                                       
 
Total Revenues
  $ 200,060     $ 143,613     $ 7,355     $ 386     $ 151,354     $ (2,431 )   $ 348,983  
Operating Expenses:
                                                       
Depreciation and Amortization
    22,663       70       66             136             22,799  
Other Operating Expenses (a)
    184,359       136,902       8,410       271       145,583       (2,431 )     327,511  
Income Tax Expense (Benefit)
    (5,931 )     2,604       (419 )     15       2,200             (3,731 )
 
Total Operating Expenses
    201,091       139,576       8,057       286       147,919       (2,431 )     346,579  
 
Operating Income (Loss)
    (1,031 )     4,037       (702 )     100       3,435             2,404  
Interest Expense — Net
    9,912       84             268       352       (47 )     10,217  
Other Non-Operating Income (Expense) (b)
    220       83       102       (408 )     (223 )     (47 )     (50 )
Dividends on Washington Gas Preferred Stock
    330                                     330  
 
Net Income (Loss) (Applicable to Common Stock)
  $ (11,053 )   $ 4,036     $ (600 )   $ (576 )   $ 2,860     $     $ (8,193 )
 
Total Assets
  $ 2,381,420     $ 122,459     $ 23,848     $ 34,596     $ 180,903     $ (65,013 )   $ 2,497,310  
 
Capital Expenditures/Investments
  $ 30,924     $ 85     $ 87     $     $ 172     $     $ 31,096  
 
 
                                                       
 
Three Months Ended June 30, 2004
                                                       
 
Total Revenues
  $ 183,079     $ 169,828     $ 5,717     $ 471     $ 176,016     $ (2,243 )   $ 356,852  
Operating Expenses:
                                                       
Depreciation and Amortization
    20,956       55       34             89             21,045  
Other Operating Expenses (a)
    159,492       167,325       7,748       1,143       176,216       (2,243 )     333,465  
Income Tax Expense (Benefit)
    (5,011 )     925       (1,000 )     (125 )     (200 )           (5,211 )
 
Total Operating Expenses
    175,437       168,305       6,782       1,018       176,105       (2,243 )     349,299  
 
Operating Income (Loss)
    7,642       1,523       (1,065 )     (547 )     (89 )           7,553  
Interest Expense — Net
    11,407       127       3       153       283       (123 )     11,567  
Other Non-Operating Income (Expense) (b)
    (152 )     36       6       449       491       (123 )     216  
Dividends on Washington Gas Preferred Stock
    330                                     330  
 
Net Income (Loss) (Applicable to Common Stock)
  $ (4,247 )   $ 1,432     $ (1,062 )   $ (251 )   $ 119     $     $ (4,128 )
 
Total Assets
  $ 2,379,100     $ 147,313     $ 22,521     $ 72,772     $ 242,606     $ (75,873 )   $ 2,545,833  
 
Capital Expenditures/Investments
  $ 29,479     $ 11     $ 15     $     $ 26     $     $ 29,505  
 
(a) Includes cost of gas and electricity, and revenue taxes.
(b) Amounts reported are net of applicable income taxes.

14


 

WGL Holdings, Inc.
Washington Gas Light Company

Part I — Financial Information
Item 1 — Financial Statements (continued)
Notes to Consolidated Financial Statements (Unaudited)

                                                         
Operating Segment Financial Information
            Non-Utility Operations              
    Regulated     Retail Energy-             Other             Eliminations/        
(In thousands)   Utility     Marketing     HVAC     Activities     Total     Other     Consolidated  
 
Nine Months Ended June 30, 2005
                                                       
 
Total Revenues
  $ 1,256,922     $ 634,819     $ 24,557     $ 999     $ 660,375     $ (15,116 )   $ 1,902,181  
Operating Expenses:
                                                       
Depreciation and Amortization
    66,277       186       134             320             66,597  
Other Operating Expenses (a)
    987,877       610,967       26,760       2,188       639,915       (15,120 )     1,612,672  
Income Tax Expense (Benefit)
    64,783       9,114       (871 )     (420 )     7,823             72,606  
 
Total Operating Expenses
    1,118,937       620,267       26,023       1,768       648,058       (15,120 )     1,751,875  
 
Operating Income (Loss)
    137,985       14,552       (1,466 )     (769 )     12,317       4       150,306  
Interest Expense — Net
    31,269       718       1       1,096       1,815       (638 )     32,446  
Other Non-Operating Income (Expense) (b)
    (2,336 )     95       179       719       993       (642 )     (1,985 )
Dividends on Washington Gas Preferred Stock
    990                                     990  
 
Net Income (Loss) (Applicable to Common Stock)
  $ 103,390     $ 13,929     $ (1,288 )   $ (1,146 )   $ 11,495     $     $ 114,885  
 
Total Assets
  $ 2,381,420     $ 122,459     $ 23,848     $ 34,596     $ 180,903     $ (65,013 )   $ 2,497,310  
 
Capital Expenditures/Investments
  $ 72,468     $ 482     $ 177     $     $ 659     $     $ 73,127  
 
 
                                                       
 
Nine Months Ended June 30, 2004
                                                       
 
Total Revenues
  $ 1,169,490     $ 637,766     $ 20,497     $ 1,332     $ 659,595     $ (24,692 )   $ 1,804,393  
Operating Expenses:
                                                       
Depreciation and Amortization
    69,122       163       101       43       307             69,429  
Other Operating Expenses (a)
    889,006       627,256       24,698       2,714       654,668       (24,692 )     1,518,982  
Income Tax Expense (Benefit)
    69,376       3,894       (1,867 )     (113 )     1,914             71,290  
 
Total Operating Expenses
    1,027,504       631,313       22,932       2,644       656,889       (24,692 )     1,659,701  
 
Operating Income (Loss)
    141,986       6,453       (2,435 )     (1,312 )     2,706             144,692  
Interest Expense — Net
    33,241       539       12       654       1,205       (542 )     33,904  
Other Non-Operating Income (Expense) (b)
    (1,956 )     145       113       7,089       7,347       (542 )     4,849  
Dividends on Washington Gas Preferred Stock
    990                                     990  
 
Net Income (Loss) (Applicable to Common Stock)
  $ 105,799     $ 6,059     $ (2,334 )   $ 5,123     $ 8,848     $     $ 114,647  
 
Total Assets
  $ 2,379,100     $ 147,313     $ 22,521     $ 72,772     $ 242,606     $ (75,873 )   $ 2,545,833  
 
Capital Expenditures/Investments
  $ 78,929     $ 51     $ 144     $     $ 195     $     $ 79,124  
 
(a) Includes cost of gas and electricity, and revenue taxes.
(b) Amounts reported are net of applicable income taxes.
NOTE 9. TRANSACTIONS BETWEEN WASHINGTON GAS AND AFFILIATES
 
     Washington Gas and other subsidiaries of WGL Holdings engage in transactions with each other during the ordinary course of business. All significant intercompany transactions and balances have been eliminated from the consolidated financial statements of WGL Holdings.
     Washington Gas provides accounting, treasury, legal and other administrative and general support to affiliates, and has filed consolidated tax returns that include affiliated taxable transactions. The actual costs of these services are billed to the appropriate affiliates and to the extent such billings are not yet paid, they are reflected in “Receivables from associated companies” on the Washington Gas Balance Sheets. Cash collected by Washington Gas on behalf of its affiliates but not yet transferred is recorded in “Payables to associated companies” on the Washington Gas Balance Sheets. Washington Gas does not recognize revenues or expenses associated with providing these services.
     At June 30, 2005 and September 30, 2004, the Washington Gas Balance Sheets reflected a net payable to associated companies of $20.5 million and $18.2 million, respectively. All significant affiliated transactions, including these balances, were eliminated from the WGL Holdings

15


 

WGL Holdings, Inc.
Washington Gas Light Company
Part I — Financial Information
Item 1 — Financial Statements (continued)
Notes to Consolidated Financial Statements (Unaudited)

Consolidated Balance Sheets in accordance with GAAP.
     Additionally, Washington Gas provides natural gas balancing services related to storage, injections, withdrawals and deliveries to all unregulated energy marketers participating in the sale of natural gas on an unregulated basis through the customer choice programs that operate in its service territory. Washington Gas records revenues for these balancing services pursuant to tariffs approved by the appropriate regulatory bodies. In conjunction with such services and the related sales and purchases of natural gas, Washington Gas charged WGEServices, an affiliated energy marketer, $2.4 million and $2.2 million for the three months ended June 30, 2005 and 2004, respectively. For the nine months ended June 30, 2005 and 2004, the charges were $15.1 million and $24.7 million, respectively. These related party amounts have been eliminated in the consolidated financial statements of WGL Holdings.
NOTE 10. COMMITMENTS AND CONTINGENCIES
 
     REGULATED UTILITY OPERATIONS
     Prince George’s County, Maryland Operating Issues
     On April 1, 2005, Washington Gas reported that it will address a significant increase in the number of natural gas leaks on its distribution system in a portion of Prince George’s County, Maryland. Washington Gas determined that these leaks resulted from the shrinkage of seals located in mechanical couplings that connect sections of distribution mains and services. Washington Gas announced that it would replace gas service lines and rehabilitate gas mains that contain the applicable mechanical couplings in the affected area of the distribution system in Prince George’s County (the rehabilitation project) by December 2007, even if no leaks are detected.
     The rehabilitation project in Prince George’s County is currently expected to cost $144 million. This estimate could vary materially from the actual costs incurred and these costs will increase significantly the budgeted capital expenditures for fiscal years 2006 through 2008 originally reported in the Form 10-K for the year ended September 30, 2004.
     As a result of the receipt of an Accounting Order dated June 1, 2005 from the Public Service Commission of Maryland (PSC of MD), the Company will be capitalizing all costs of encapsulating certain couplings on mains that otherwise would have been expensed under normal operating conditions. This phase represents approximately $13 million of the total cost of the rehabilitation project. However, the receipt of the order from the PSC of MD is not determinative of the ratemaking treatment and the PSC of MD retains jurisdiction to adopt any ratemaking treatment it deems appropriate. After considering the impact of the June 1, 2005 Accounting Order and the GAAP that is applicable to the remainder of the rehabilitation project, Washington Gas anticipates that all of the costs of this project will be capitalized.
     Management of Washington Gas believes that the cost of the rehabilitation project described above is necessary to provide safe and reliable utility service. Management believes that costs such as these are normally recognized in the ratemaking process as reasonable. At the present time, Washington Gas has not requested regulatory recovery of the costs that will be incurred. However, Washington Gas is considering the effect of these capital expenditures on its ability to earn its allowed rate of return in Maryland, and is evaluating the most appropriate regulatory option to enable full and timely recovery of, and return on, the amounts to be expended. There can be no assurance at this time that recovery in rates will be allowed or at what point in time such recovery may begin to be reflected in rates. Significant negative effects on earnings in future years could result if such costs are incurred and recovery in rates is not allowed.
     Washington Gas retained a consultant to determine the reason for the increase in leaks in the affected area of Prince George’s County. Based on the work conducted to date there is a combination of three contributing factors to the higher leak rates of seals on couplings. The relevant factor

16


 

WGL Holdings, Inc.
Washington Gas Light Company
Part I — Financial Information
Item 1 — Financial Statements (continued)
Notes to Consolidated Financial Statements (Unaudited)

is the change in the gas composition resulting from a change in the gas supply arising from the reactivation of the Cove Point LNG terminal owned by Dominion Resources, Inc. The Cove Point gas has a lower concentration of heavy hydrocarbons (HHCs) than domestic natural gas. A characteristic of the rubber material comprising the seals in the couplings is the ability of the seals to both adsorb and desorb HHCs. When seals are exposed to higher levels of HHCs they swell in size and cause a tighter seal. However, when gas is introduced that has a lower level of HHCs, the seals shrink in size and there is a greater propensity for those seals to cause the couplings to leak.
     Also considered as contributing factors to a higher failure rate for seals of this nature are the age of the couplings and the colder ground temperature during winter periods. However, both the age of the couplings and the ground temperature are common to couplings in other areas of Washington Gas’ service territory where leak patterns have not been observed like those in the affected area of Prince George’s County. Thus the relevant change that explains the higher incidence of leaks in the affected area of Prince George’s County is the composition of the gas resulting from the introduction of Cove Point gas.
     The consultant hired by Washington Gas believes that the condition caused by the gas coming from the Cove Point terminal is reversible. Washington Gas is examining three potential approaches that will enable it to reverse or reduce the effect of the introduction of gas from the Cove Point terminal on the distribution system in the affected area of Prince George’s County. Washington Gas is also examining approaches to limit the potential effect of Cove Point gas on other areas of its distribution system. At the present time, Washington Gas believes that the cost of implementing any one or a combination of the three approaches being examined should not be material to its financial position or to the results of operations.
     Rate Case Contingencies
     Certain legal and administrative proceedings incidental to the Company’s business, including rate case contingencies, involve WGL Holdings and/or its subsidiaries. In the opinion of management, the Company has recorded an adequate provision for probable losses or refunds to customers for rate case contingencies related to these proceedings in accordance with SFAS No. 5, Accounting for Contingencies.
     District of Columbia Jurisdiction
     In a March 28, 2003 Final Order, the Public Service Commission of the District of Columbia (PSC of DC) upheld a previous ruling that approved, among other things, a methodology for sharing with customers 50 percent of annual ground lease and development fees that Washington Gas received from Maritime Plaza, a commercial development project constructed on land owned by Washington Gas. On May 23, 2003, the District of Columbia Office of the People’s Counsel (DC OPC) filed an appeal with the District of Columbia Court of Appeals (DC Court of Appeals) seeking to overturn this portion of the March 28, 2003 ruling by the PSC of DC. On March 18, 2004, the DC Court of Appeals ordered, among other things, the PSC of DC to provide an explanation of its decision to approve the allocation methodology for sharing with customers the ground lease and development fee revenues attributable to the Maritime Plaza development project. The PSC of DC issued a subsequent order requiring both the DC OPC and Washington Gas to file testimony on this matter of the allocation. On October 12, 2004, Washington Gas filed testimony before the PSC of DC that supports the allocation methodology that was approved in the PSC of DC’s initial order. The DC OPC filed opposing testimony on the same date. Rebuttal testimony was filed on November 19, 2004 by the DC OPC and Washington Gas. The PSC of DC issued an order on April 4, 2005 that required Washington Gas and the DC OPC to file supplemental testimony on April 25, 2005, and set a one-day evidentiary hearing for May 17, 2005 that was postponed and has not yet been rescheduled. Management cannot predict

17


 

WGL Holdings, Inc.
Washington Gas Light Company
Part I — Financial Information
Item 1 — Financial Statements (continued)
Notes to Consolidated Financial Statements (Unaudited)

the outcome of this matter; however, it believes that the likely outcome will not have a material impact on Washington Gas’ financial statements.
     Virginia Jurisdiction
     On December 18, 2003, the State Corporation Commission of Virginia (SCC of VA) issued a Final Order in response to an application filed by Washington Gas on June 14, 2002 to increase annual revenues in Virginia. The Final Order granted Washington Gas an increase in annual revenues of $9.9 million, reflecting an allowed rate of return on common equity of 10.50 percent and an overall rate of return of 8.44 percent. In the Final Order, the SCC of VA ordered that the implementation date of new depreciation rates should be January 1, 2002, as opposed to November 12, 2002, as originally requested and implemented by Washington Gas. This required Washington Gas to record additional depreciation expense in the quarter ended December 31, 2003 of approximately $3.5 million, on a pre-tax basis, that related to the period from January 1, 2002 through November 11, 2002.
     The SCC of VA also ordered Washington Gas to reduce its rate base related to net utility plant by $28 million, which is net of accumulated deferred income taxes of $14 million, and to establish an equivalent regulatory asset that the Company has done for regulatory accounting purposes only. This regulatory asset represents the difference between the accumulated reserve for depreciation recorded on the books of Washington Gas and a theoretical reserve that was derived by the Staff of the SCC of VA (VA Staff) as part of its review of Washington Gas’ depreciation rates, less accumulated deferred income taxes. This regulatory asset is being amortized, for regulatory accounting purposes only, as a component of depreciation expense over 32 years pursuant to the Final Order. The SCC of VA provided for both a return on, and a return of, this regulatory asset established for regulatory accounting purposes.
     In approving the treatment described in the preceding paragraph, the SCC of VA further ordered that an annual “earnings test” be performed to determine if Washington Gas has earned in excess of its allowed rate of return on common equity for its Virginia operations. The current procedure for performing this earnings test does not normalize the actual return on equity for the effect of weather over the applicable twelve-month period. To the extent that Washington Gas earns in excess of its allowed return on equity in any annual earnings test period, Washington Gas is required to increase depreciation expense (after considering the impact of income tax benefits) and increase the accumulated reserve for depreciation for the amount of the actual earnings in excess of the earnings produced by the 10.50 percent allowed return on equity. Under the SCC of VA’s requirements for performing earnings tests, if weather is warmer than normal in a particular annual earnings test period, Washington Gas is not allowed to restore any amount of earnings previously eliminated as a result of this earnings test. These annual earnings tests will continue to be performed until the $28 million difference between the accumulated reserve for depreciation recorded on Washington Gas’ books and the theoretical reserve derived by the VA Staff, net of accumulated deferred income taxes, is eliminated or the level of the regulatory asset established for regulatory accounting purposes is adjusted as a result of a future depreciation study. On March 17, 2005, the VA Staff filed a report with the SCC of VA in connection with Washington Gas’ earnings test for the twelve-month period ended December 31, 2003. The VA Staff’s report concluded that Washington Gas did not earn in excess of its allowed return on equity during this period, and recommended that Washington Gas not be required to record any additional depreciation expense related to its earnings for the twelve-month period ended December 31, 2003. On April 26, 2005, the SCC of VA issued an Order that concurred with the VA Staff’s recommendation. As a result, Washington Gas reversed $1.0 million of depreciation expense, on a pre-tax basis, in the nine months ended June 30, 2005 that had been previously recorded in fiscal year 2004 related to this earnings test.
     On January 27, 2004, Washington Gas filed an expedited rate case with the SCC of VA to

18


 

WGL Holdings, Inc.
Washington Gas Light Company
Part I — Financial Information
Item 1 — Financial Statements (continued)
Notes to Consolidated Financial Statements (Unaudited)

increase annual revenues in Virginia by $19.6 million, with an overall rate of return of 8.70 percent and a 10.50 percent return on equity. On February 26, 2004, based upon expedited rate case filing procedures, Washington Gas placed the proposed revenue increase into effect, subject to refund, pending the SCC of VA’s final decision in the proceeding.
     On September 27, 2004, the SCC of VA issued a Final Order approving a Stipulation that resolved all issues related to Washington Gas’ January 27, 2004 expedited rate case application filed with the SCC of VA. The Stipulation ordered no change in Washington Gas’ annual base revenues, and for Washington Gas to maintain its allowed rate of return on common equity of 10.50 percent and overall rate of return of 8.44 percent that had been approved by the December 18, 2003 Final Order as previously discussed. Accordingly, refunds to customers, with interest, were made during the December 2004 billing cycle for the amount of the proposed annual revenue increase that had been collected since February 26, 2004. Based on the terms of the Stipulation, the Company implemented billing rates commencing October 4, 2004 that reflected the level of annual revenues determined in the December 18, 2003 Final Order, and implemented the agreed upon changes in rate design that were contained in the Stipulation.
     The Stipulation also provided for a one-time credit to all Virginia customers of $3.2 million for certain liabilities that were previously recorded by Washington Gas. This one-time credit was made to customers during the January 2005 billing cycle. Providing this credit to customers did not have an effect on the earnings of the Company or Washington Gas in the three or nine months ended June 30, 2005. The Stipulation also required Washington Gas to file with the SCC of VA annual earnings test calculations based on a twelve-month period ended December 31; such calculations are being estimated by the Company quarterly, and when appropriate, accounting adjustments are being recorded.
     NON-UTILITY OPERATIONS
     As discussed below, the Company is a party to financial guarantees related to the energy-marketing activities of WGEServices. WGEServices also is exposed to the risk of non-performance associated with its principal electric supplier.
     Financial Guarantees
     WGL Holdings has guaranteed payments primarily for certain purchases of natural gas and electricity made by WGEServices. At June 30, 2005, these guarantees totaled $170.9 million. Termination of these guarantees is coincident with the satisfaction of all obligations of WGEServices covered by the guarantees. WGL Holdings also had guarantees totaling $5.0 million at June 30, 2005 that were made on behalf of certain of its non-utility subsidiaries associated with their banking transactions. Of the $175.9 million total guarantees, $16.1 million, $4.0 million and $600,000 are due to expire on December 31, 2005, June 30, 2006 and February 29, 2008, respectively. The remaining guarantees of $155.2 million do not have specific maturity dates. For all of its financial guarantees, WGL Holdings may cancel any or all future obligations imposed by the guarantees upon written notice to the counterparty, but WGL Holdings would continue to be responsible for the obligations that had been created under the guarantees prior to the effective date of the cancellation.
     Construction Project Financing
     In October 2000, Washington Gas contracted with the U.S. General Services Administration (GSA) to construct certain facilities at the GSA central plant in Washington, D.C. Payments to Washington Gas for this construction were to be made by the GSA over a 15-year period. In November 2000, Washington Gas and General Electric Capital Assurance Company (GEFA) entered

19


 

WGL Holdings, Inc.
Washington Gas Light Company
Part I — Financial Information
Item 1 — Financial Statements (continued)
Notes to Consolidated Financial Statements (Unaudited)

into a long-term financing arrangement, whereby GEFA funded this construction project. Under the terms of this financing arrangement, Washington Gas assigned to GEFA the 15-year stream of payments due from the GSA. The final amount of this long-term financing arrangement, including amendments, change orders, origination fees and capitalized finance charges was $69.4 million. As the long-term financing from GEFA was funded, Washington Gas established a note receivable representing the GSA’s obligation to remit principal and interest. Upon completion and acceptance of phases of the construction project, Washington Gas accounted for the transfer of the financed asset as an extinguishment of long-term debt and removed both the note receivable and long-term financing from its financial statements. In December 2004, all remaining work under the construction project was fully accepted by the GSA. Accordingly, the remaining note receivable and corresponding long-term note payable related to the GSA construction project were removed from the Company’s financial statements at December 31, 2004. As a result of GSA’s final acceptance, GEFA has no further recourse against the Company related to the extinguished long-term debt.
     Electric Supplier Contingency
     WGEServices owns no electric generation assets and, through June 30, 2005, received a majority of its electric supply to serve its retail customers under full requirements supply contracts. WGEServices’ principal supplier of electricity under full requirements supply contracts is Mirant Americas Energy Marketing L.P. (MAEM), a wholly owned subsidiary of Mirant Americas, Inc., which is a wholly owned subsidiary of Mirant Corporation (Mirant). On July 14, 2003, Mirant and substantially all of its subsidiaries filed voluntary petitions for reorganization under Chapter 11 of the U.S. Bankruptcy Code. MAEM was included in these bankruptcy filings. Since the bankruptcy filing, MAEM has continued to honor its supply obligations to WGEServices. The majority of the obligations to WGEServices under the pre-bankruptcy petition MAEM contracts expired on or before December 31, 2004, and the remainder of these contracts will expire by the end of October 2005. Future performance by MAEM may be subject to further developments in the bankruptcy proceedings.
     The performance risk associated with the pre-bankruptcy petition MAEM contracts is mitigated through a Security and Escrow agreement entered into between WGEServices and MAEM prior to the bankruptcy filing. Under the Security and Escrow agreement, WGEServices has access to collateral that was intended to cover the difference between the current market price of electricity and the price at which WGEServices has contracted to buy electricity from MAEM. WGEServices has the contractual right to draw on the escrow funds in the account (which totaled $102,000 and $3.0 million as of June 30, 2005 and September 30, 2004, respectively) if the pre-bankruptcy petition contracts between WGEServices and MAEM are terminated. Accordingly, WGEServices is potentially exposed to any excess damages above this escrow account balance in the event of contract rejection.
     On January 19, 2005, Mirant filed a plan of reorganization in connection with its bankruptcy. The plan proposes that upon MAEM’s emergence from bankruptcy, any pre-bankruptcy petition executory contracts not expressly assumed would be rejected. At this time, WGEServices’ pre-bankruptcy petition contracts have not been expressly assumed, and there is no assurance that they will be.
     Should MAEM reject the WGEServices pre-bankruptcy petition contracts either prior to or at the time of its emergence from bankruptcy, WGEServices estimates that its potential exposure would not be material to its results of operations or financial position. This estimate of WGEServices’ exposure to contract termination is based upon acquiring supply, priced at forward electricity prices through the expiration of the existing sales contracts. The actual exposure for WGEServices may differ from the estimate due to the timing of contract terminations, deviations from normal weather, changes in future market conditions or other factors.
     In October 2003, WGEServices and MAEM signed a post-bankruptcy petition contract that

20


 

WGL Holdings, Inc.
Washington Gas Light Company
Part I — Financial Information
Item 1 — Financial Statements (continued)
Notes to Consolidated Financial Statements (Unaudited)

enables WGEServices to renew expiring contracts with its current electric customers and to make purchases for new customers. These post-bankruptcy petition contracts include provisions that allow WGEServices to net payables to MAEM against any damages that might result from default on the part of MAEM, and allow WGEServices to request collateral under certain situations.
     WGEServices has made efforts to reduce its reliance on a single supplier. In addition to MAEM, WGEServices has separate master purchase and sale agreements under which it purchases full requirements services from other wholesale electricity suppliers. These electric suppliers either have investment grade credit ratings or provide guarantees from companies with investment grade credit ratings. Electric suppliers other than MAEM accounted for less than ten percent of WGEServices’ full requirements electric purchases for the nine months ended June 30, 2005.
     Electric Purchase Commitments
     Commencing in the third quarter of fiscal year 2005, WGEServices began procuring a portion of its electricity supply under contract structures other than full requirements contracts and which contain minimum purchase commitments. These contracts contain terms of up to 26 months. WGEServices designs these purchase contracts to match the duration of its sales commitments and effectively to lock in a margin based on estimated electricity sales over the terms of existing sales contracts. The following electricity purchase commitments are based on existing fixed-price purchase commitments, all of which are for fixed volumes. As of June 30, 2005, WGEServices had minimum electricity purchase commitments under contract structures other than full requirements contracts of $18.7 million for the remaining three months of fiscal year 2005, $48.7 million for fiscal year 2006 and $26.5 million for fiscal year 2007.
NOTE 11. PENSION AND OTHER POST-RETIREMENT BENEFIT PLANS
 
     The following tables show the components of net periodic benefit costs (income) recognized in the Company’s financial statements during the three and nine months ended June 30, 2005 and 2004:
                                 
Components of Net Periodic Benefit Costs (Income)
    Three Months Ended   Three Months Ended
    June 30, 2005   June 30, 2004
        Health           Health
    Pension   and Life   Pension   and Life
(In thousands)   Benefits   Benefits   Benefits   Benefits
 
Components of net periodic benefit costs (income)
                               
Service cost
  $ 2,539     $ 2,590     $ 2,588     $ 2,081  
Interest cost
    9,197       5,759       9,029       4,748  
Expected return on plan assets
    (12,941 )     (3,291 )     (13,079 )     (3,079 )
Recognized prior service cost
    560             569        
Recognized actuarial loss
    289       2,241       240       770  
Amortization of transition obligation-net
          1,436       44       1,436  
 
Net periodic benefit cost (income)
    (356 )     8,735       (609 )     5,956  
 
Amount capitalized as construction costs
    130       (1,104 )     177       (781 )
Amount deferred as regulatory asset/liability-net
    (833 )     (434 )     (782 )     81  
Other
    (25 )     (12 )     4        
 
Amount charged (credited) to expense
  $ (1,084 )   $ 7,185     $ (1,210 )   $ 5,256  
 

21


 

WGL Holdings, Inc.
Washington Gas Light Company

Part I — Financial Information
Item 1 — Financial Statements (concluded)
Notes to Consolidated Financial Statements (Unaudited)

                                 
Components of Net Periodic Benefit Costs (Income)
    Nine Months Ended   Nine Months Ended
    June 30, 2005   June 30, 2004
        Health           Health
    Pension   and Life   Pension   and Life
(In thousands)   Benefits   Benefits   Benefits   Benefits
 
Components of net periodic benefit costs (income)
                               
Service cost
  $ 7,616     $ 7,770     $ 7,764     $ 6,463  
Interest cost
    27,591       17,276       27,087       14,831  
Expected return on plan assets
    (38,824 )     (9,913 )     (39,237 )     (9,237 )
Recognized prior service cost
    1,680             1,707        
Recognized actuarial loss
    868       6,686       720       3,092  
Amortization of transition obligation-net
          4,308       132       4,308  
 
Net periodic benefit cost (income)
    (1,069 )     26,127       (1,827 )     19,457  
 
Amount capitalized as construction costs
    387       (3,293 )     577       (3,402 )
Amount deferred as regulatory asset/liability-net
    (2,566 )     (1,317 )     (1,932 )     178  
Other
    (108 )     (1 )     11        
 
Amount charged (credited) to expense
  $ (3,356 )   $ 21,516     $ (3,171 )   $ 16,233  
 
     During fiscal year 2005, the Company has not made, and does not expect to make any contributions related to its qualified, trusteed, non-contributory defined benefit pension plan covering all active and vested former employees of Washington Gas.
     During the nine months ended June 30, 2005, the Company paid $817,000 on behalf of participants in its non-funded supplemental executive retirement plan, and expects to pay an additional $559,000 for the remainder of fiscal year 2005.
     For the nine months ended June 30, 2005, the Company contributed $25.5 million to its healthcare and life insurance benefit plans, and expects to contribute an additional $8.1 million for the remainder of fiscal year 2005.
     Amounts included in the line item “Amount deferred as regulatory asset/liability-net,” as shown in the table above, represent the difference between the cost of the applicable Pension Benefits or the Health and Life Benefits, and the amount that Washington Gas is permitted to recover in rates that Washington Gas charges in the District of Columbia. These differences are recorded as regulatory assets or liabilities and will be reflected as adjustments to customer bills in future rate proceedings.

22


 

WGL Holdings, Inc.
Washington Gas Light Company

Part I – Financial Information
Item 2 – Management’s Discussion and Analysis of
Financial Condition and Results of Operations
ITEM 2.  MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
 
INTRODUCTION
     This Management’s Discussion and Analysis of Financial Condition and Results of Operations (Management’s Discussion) is divided into the following two major sections:
    WGL Holdings – This section describes the financial condition and results of operations of WGL Holdings, Inc. (WGL Holdings or the Company) and its subsidiaries on a consolidated basis. It includes discussions of WGL Holdings’ regulated utility and non-utility operations. On an annual basis, the majority of WGL Holdings’ operations are derived from the results of its regulated utility, Washington Gas Light Company (Washington Gas or the regulated utility), and to a much lesser extent, the results of its non-utility operations. These unregulated, non-utility operations are wholly owned by Washington Gas Resources Corporation, a wholly owned subsidiary of WGL Holdings. For more information on the Company’s regulated utility operations, please refer to the Management’s Discussion for Washington Gas.
 
    Washington Gas – This section describes the financial condition and results of operations of Washington Gas, a wholly owned subsidiary that comprises the majority of WGL Holdings’ regulated utility segment. The financial condition and results of operations of Washington Gas’ utility operations and WGL Holdings’ regulated utility segment are essentially the same.
     Both of the major sections of Management’s Discussion—WGL Holdings and Washington Gas—should be read to obtain an understanding of the Company’s operations and financial performance. Management’s Discussion also should be read in conjunction with the respective company’s financial statements and the combined Notes to Consolidated Financial Statements thereto.
     Unless otherwise noted, earnings per share amounts are presented herein on a diluted basis, and are based on weighted average common and common equivalent shares outstanding. The Company’s operations are seasonal and, accordingly, the Company’s operating results for the interim periods presented herein are not indicative of the results to be expected for the full fiscal year.
EXECUTIVE OVERVIEW
     Introduction
     WGL Holdings, through its wholly owned subsidiaries, sells and delivers natural gas and provides a variety of energy-related products and services to customers primarily in Washington, D.C. and the surrounding metropolitan areas in Maryland and Virginia. WGL Holdings has three primary operating segments that are described below.
     Regulated Utility. The Company’s core subsidiary, Washington Gas, delivers natural gas to retail customers in accordance with tariffs approved by the District of Columbia, Maryland and Virginia regulatory commissions that have jurisdiction over Washington Gas’ rates. These rates are intended to provide the regulated utility with an opportunity to earn a just and reasonable rate of return on the investment devoted to the delivery of natural gas to customers. Washington Gas also sells natural gas to customers who have not elected to purchase natural gas from unregulated third-party

23


 

WGL Holdings, Inc.
Washington Gas Light Company

Part I – Financial Information
Item 2 – Management’s Discussion and Analysis of
Financial Condition and Results of Operations (continued)
marketers. The regulated utility does not earn a profit or incur a loss when it sells the natural gas commodity because utility customers are charged for the natural gas commodity at the same cost the regulated utility incurs.
     Retail Energy-Marketing. Washington Gas Energy Services (WGEServices) competes with other third-party marketers by selling natural gas and electricity directly to residential, commercial and industrial customers, both inside and outside of the regulated utility’s traditional service territory. WGEServices does not own or operate any natural gas or electric generation, transmission or distribution assets. Rather, it sells natural gas and electricity with the objective of earning a profit, and these commodities are delivered to retail customers through the assets owned by regulated utilities, such as Washington Gas or other unaffiliated natural gas or electric utilities.
     Commercial Heating, Ventilating and Air Conditioning (HVAC). The Company’s commercial HVAC operations provide turnkey, design-build and renovation projects to the commercial and government markets.
     Key Indicators of Financial Condition and Operating Performance
     Management believes that the following are key indicators for monitoring the Company’s financial condition and operating performance:
     Return on Average Common Equity. This measure is calculated by dividing twelve months ended net income (applicable to common stock) by average common shareholders’ equity. For the regulated utility, management compares the actual return on common equity with the return on common equity that is allowed to be earned by regulators and the return on equity that is necessary for the Company to compensate investors sufficiently and be able to continue to attract capital.
     Common Equity Ratio. This ratio is calculated by dividing total common shareholders’ equity by the sum of common shareholders’ equity, preferred stock and long-term debt (including current maturities). Maintaining this ratio in the mid-50 percent range affords the Company financial flexibility and access to long-term capital at relatively low costs. Refer to the “Liquidity and Capital Resources – General Factors Affecting Liquidity” section of Management’s Discussion for a discussion of the Company’s capital structure.
     Primary Factors Affecting WGL Holdings and Washington Gas
     The principal business, economic and other factors that affect the operations and/or financial performance of WGL Holdings and Washington Gas include:
    weather conditions and weather patterns;
    regulatory environment and regulatory decisions;
    availability of natural gas supplies and interstate pipeline transportation and storage capacity;
    natural gas prices and the prices of competing fuels such as oil and electricity;
    changes in natural gas usage resulting from improved appliance efficiencies and the effect of changing natural gas prices;
    the safety and reliability of the natural gas distribution system;
    the level of capital expenditures for adding new customers and replacing facilities worn beyond economic repair;
    competitive environment;
    environmental matters;

24


 

WGL Holdings, Inc.
Washington Gas Light Company

Part I – Financial Information
Item 2 – Management’s Discussion and Analysis of
Financial Condition and Results of Operations (continued)
    industry consolidation;
    economic conditions and interest rates;
    inflation/deflation;
    labor contracts, including labor and benefit costs; and
    changes in accounting principles.
     For a further discussion of the Company’s business, operating segments and the factors listed above, refer to Management’s Discussion within the combined Annual Report on Form 10-K for WGL Holdings and Washington Gas for the fiscal year ended September 30, 2004, and Management’s Discussion contained herein.
CRITICAL ACCOUNTING POLICIES
     Preparation of financial statements and related disclosures in compliance with Generally Accepted Accounting Principles in the United States of America (GAAP) requires the selection and the application of appropriate technical accounting rules to the relevant facts and circumstances of the Company’s operations, as well as the use of estimates by management to compile the consolidated financial statements. The application of these accounting policies involves judgment regarding estimates and projected outcomes of future events, including the likelihood of success of particular regulatory initiatives or challenges, the likelihood of realizing estimates for legal and environmental contingencies, and the probability of recovering costs and investments in both the regulated utility and non-utility operations.
     The following critical accounting policies require management’s judgment and estimation, where such estimates have a material effect on the consolidated financial statements:
    accounting for utility revenue and cost of gas recognition;
    accounting for the effects of regulation – regulatory assets and liabilities;
    accounting for income taxes;
    accounting for contingencies; and
    accounting for derivative instruments.
     For a description of these critical accounting policies, refer to Management’s Discussion within the combined Annual Report on Form 10-K for WGL Holdings and Washington Gas for the fiscal year ended September 30, 2004, and Management’s Discussion contained herein.

25


 

WGL Holdings, Inc.
Part I – Financial Information
Item 2 – Management’s Discussion and Analysis of
Financial Condition and Results of Operations (continued)
WGL HOLDINGS, INC.
     RESULTS OF OPERATIONS – Three Months Ended June 30, 2005 vs. June 30, 2004
     Summary Results
     WGL Holdings, Inc. reported a net loss $8.2 million, or $0.17 per share, for the three months ended June 30, 2005, the third quarter of the Company’s fiscal year 2005. This compares to a net loss of $4.1 million, or $0.08 per share, for the three months ended June 30, 2004. Reporting a net loss for quarters ending June 30 is typical due to the seasonal nature of the Company’s utility operations and the corresponding reduced demand for natural gas during this period. For the twelve-month period ended June 30, 2005, the Company earned a return on average common equity of 10.7 percent as compared to 11.2 percent for the corresponding twelve-month period of the prior fiscal year.
     Operating results for the third quarter of fiscal year 2005, when compared to the same quarter of the prior fiscal year, reflect increased utility operating expenses including operation and maintenance, depreciation and amortization, and general taxes, as well as the effect of an anticipated rate increase in Virginia that was reflected in the prior year’s third quarter operating results but excluded from the current quarter’s results. Favorably affecting operating results for the current quarter were increased earnings from the Company’s major non-utility operations, utility customer growth and lower interest expense.
     Regulated Utility Operating Results
     The operating results of the Company’s core regulated utility operations are the primary influence on consolidated operating results. The regulated utility segment reported a seasonal net loss of $11.1 million, or $0.23 per share, for the three months ended June 30, 2005, as compared to a net loss of $4.2 million, or $0.09 per share, for the same three-month period of the prior fiscal year. Operating results for the third quarter of fiscal year 2005 were favorably affected by the addition of 23,336 active customer meters, an increase of 2.4 percent, from the end of the comparable quarter of the prior fiscal year. This growth was more than offset by the effect of a Virginia rate increase that was in effect in the prior year’s third quarter but that was not in effect in the third quarter of the current fiscal year, along with higher operating expenses in the current quarter. As further discussed below, weather had a negligible effect on operating results for both the current and prior fiscal year’s third quarter.
     Comparisons between the third quarter of the current and prior fiscal year reflect the inclusion in the prior year’s third quarter of an anticipated Virginia rate increase that went into effect on February 26, 2004, subject to refund. Since the Company did not ultimately receive an increase in its base rates in Virginia, the amount recorded through the end of the third quarter of fiscal year 2004 was reversed in the fourth quarter of fiscal year 2004, and a similar amount was not recorded in the third quarter of fiscal year 2005 (refer to the “Regulatory Matters—Virginia Jurisdiction” section of Management’s Discussion for Washington Gas).
     Third quarter of fiscal year 2005 operating results for the regulated utility segment also reflect a $5.0 million (pre-tax), or $0.06 per share, increase in operation and maintenance expenses over the comparable quarter of the prior fiscal year. The increase in these operating expenses primarily reflects: (i) higher labor expenses; (ii) increased employee benefits expenses principally related to post-retirement benefits and group insurance costs for active employees; (iii) greater expenses associated with performing the initial assessment of internal controls in accordance with Section 404 of the Sarbanes-Oxley Act and (iv) higher expenses for uncollectible accounts. Higher labor

26


 

WGL Holdings, Inc.
Part I – Financial Information
Item 2 – Management’s Discussion and Analysis of
Financial Condition and Results of Operations (continued)
expenses during the current quarter were due in part to increased overtime incurred in connection with the response to issues that arose in a portion of the Company’s distribution system in Prince George’s County, Maryland such as special leak surveys, emergency response site visits and repairs. The increase in labor expenses for the current quarter was tempered by 3.8 percent fewer employees, reduced employee severance costs, and the inclusion in the third quarter of fiscal year 2004 of an accrual of $2.4 million for unusual operational expenses that did not recur in the current quarter.
     During the third quarter of fiscal year 2005, when compared to the same quarter in fiscal year 2004, the regulated utility segment also incurred $1.7 million (pre-tax), or $0.02 per share, of higher depreciation and amortization expense, of which $1.3 million relates to a reduction in deprecation expense in the third quarter of fiscal year 2004 in connection with implementing a Maryland rate order. The current quarter also reflects $2.4 million (pre-tax), or $0.03 per share, of higher general taxes, partially offset by $1.5 million (pre-tax), or $0.02 per share, of lower interest expense (refer to the “Interest Expense” section of Management’s Discussion). Although income tax benefits were enhanced in the current quarter due to a higher pre-tax loss, much of this effect was offset by a higher estimated annual effective income tax rate.
     The regulated utility’s operations are weather sensitive, with a significant portion of its revenue coming from deliveries of natural gas to residential and commercial heating customers. Weather, when measured by heating degree days, was 21.3 percent colder in the current quarter than in the same quarter last fiscal year. However, total natural gas deliveries to firm customers increased only 2.7 million therms, or 1.6 percent, to 167.6 million therms delivered during the third quarter of fiscal year 2005. Quarters ending on June 30 include months in which the Company is coming out of the primary portion of its winter heating season. In such “shoulder” months, weather patterns may become erratic and some space-heating customers may turn off their furnaces for the remainder of the heating season upon the first significant rise in temperatures. Thus, usage patterns may not highly correlate with the level of degree days in periods that include shoulder months. Overall, weather had no significant effect on operating results for the current or prior year’s third quarter.
     Non-Utility Operating Results
     Total net income for the Company’s non-utility operations was $2.9 million, or $0.06 per share, for the three months ended June 30, 2005, as compared to net income of $119,000 for the same quarter of the prior fiscal year. The following table compares the financial results from non-utility activities for the three months ended June 30, 2005 and 2004.
Net Income (Loss) Applicable to Non-Utility Activities
 
    Three Months Ended        
    June 30,        
(In thousands)   2005     2004     Variance  
 
Retail energy-marketing
  $ 4,036     $ 1,432     $ 2,604  
Commercial HVAC  
    (600 )     (1,062 )     462  
 
Subtotal
    3,436       370       3,066  
Other non-utility activities
    (576 )     (251 )     (325 )
 
Total
  $ 2,860     $ 119     $ 2,741  
 
     Retail Energy-Marketing. WGL Holdings’ retail energy-marketing subsidiary, WGEServices, sells natural gas and electricity in competition with other unregulated marketers to residential, commercial and industrial customers. WGEServices reported net income of $4.0 million, or $0.08 per share, for the third quarter of fiscal year 2005, an increase of $2.6 million, or $0.05 per share, over net income of $1.4 million, or $0.03 per share, reported for the same quarter of fiscal year 2004. The year-over-year

27


 

WGL Holdings, Inc.
Part I — Financial Information
Item 2 — Management’s Discussion and Analysis of
Financial Condition and Results of Operations (continued)
improvement in earnings for this segment primarily reflects higher gross margins from the sale of natural gas, slightly offset by reduced gross margins from the sale of electricity.
     Gross margins per therm of natural gas sold increased over 60 percent, while natural gas sales volumes declined by less than one percent. The increase in gross margins from the sale of natural gas is due to the impact of the shape of the forward curve of the cost of natural gas in relation to retail sales prices, and a larger proportion of the quarterly sales volumes coming from higher margin, mass market customers. Natural gas customers declined from 154,700 at June 30, 2004 to 149,100 at June 30, 2005.
     Volumes of electricity sold fell 67 percent in the current quarter as electric customers declined from 47,200 at June 30, 2004 to 37,400 at June 30, 2005. This reduction reflects changing market conditions that include intensified competition for large volume commercial customers and utility standard offer service rates that are extremely attractive. Despite the reduction in volumes sold, margins per kilowatt hour sold increased 100 percent when compared to the same quarter last year. This increase was due to the non-renewal of several large volume customers previously served at lower per unit margins.
     The earnings improvement for the retail energy-marketing segment also reflects a $1.3 million, or $0.02 per share, benefit in the current quarter for bad debt expenses due to enhanced recoveries related to these accounts.
     Commercial HVAC. Two subsidiaries, American Combustion Industries, Inc. and Washington Gas Energy Systems, Inc., comprise the Company’s commercial HVAC operations. This operating segment reported a net loss of $600,000, or $0.01 per share, for the third quarter of fiscal year 2005, an improvement of $462,000, or $0.01 per share, over the net loss of $1.1 million, or $0.02 per share, reported for the same quarter of the prior fiscal year. This improvement primarily reflects higher gross margins.
     Other Non-Utility Activities. Transactions not significant enough to be reported as a separate business segment are aggregated as “Other Activities” and included as part of the Company’s non-utility operations. Other non-utility activities for the 2005 third quarter reflect a $325,000, or $0.01 per share, decrease in operating results from the comparable quarter of the prior fiscal year to a net loss of $576,000 for the current quarter from a net loss of a $251,000 for the third quarter of fiscal year 2004.
     Interest Expense
     The following table depicts the components of interest expense for the quarters ended June 30, 2005 and 2004.
Composition of Interest Expense
 
    Three Months Ended        
    June 30,        
(In thousands)   2005     2004     Variance  
 
Long-term debt
  $ 9,941     $ 10,440     $ (499 )
Short-term debt
    297       151       146  
Other (includes AFUDC*)
    (21 )     976       (997 )
 
Total
  $ 10,217     $ 11,567     $ (1,350 )
 
*   Represents the debt component of the Allowance for Funds Used During Construction.

28


 

WGL Holdings, Inc.
Part I — Financial Information
Item 2 — Management’s Discussion and Analysis of
Financial Condition and Results of Operations (continued)
     WGL Holdings’ interest expense of $10.2 million for the third quarter of fiscal year 2005 decreased $1.4 million from the same period last year. This decrease primarily reflects lower other interest expense due to an $882,000 fair value loss recorded in the third quarter of fiscal year 2004 related to an interest-rate swap at the regulated utility. The current quarter also reflects reduced interest costs on long-term debt due to a temporary decline in the average balance of long-term debt outstanding, combined with a slight reduction in the cost of this debt. Slightly offsetting the lower expense on long-term debt were higher interest costs associated with short-term debt, reflecting an increase of approximately 200 basis points in the weighted average cost of short-term debt, partially offset by a lower average balance outstanding.
     RESULTS OF OPERATIONS – Nine Months Ended June 30, 2005 vs. June 30, 2004
     Summary Results
     For the first nine months of fiscal year 2005, the Company reported net income of $114.9 million, or $2.35 per share, as compared to net income of $114.6 million, or $2.35 per share, for the corresponding nine-month period in fiscal year 2004. Earnings comparisons between the first nine months of fiscal years 2005 and 2004 reflect an $8.9 million, or $0.18 per share, increase in current year-to-date earnings from the Company’s retail energy-marketing and commercial HVAC segments. This increase was offset by $2.4 million, or $0.06 per share, of lower earnings from the regulated utility segment, and the effect of an after-tax gain of $5.8 million, or $0.12 per share, realized in the first nine months of fiscal year 2004 from the sale of two buildings by a third party in a commercial real estate project in which the Company held a carried interest under the equity method of accounting.
     Regulated Utility Operating Results
     The regulated utility segment reported net income of $103.4 million, or $2.11 per share, for the nine months ended June 30, 2005, as compared to net income of $105.8 million, or $2.17 per share, for the corresponding nine-month period in fiscal year 2004. Earnings for the current nine-month period when compared to the same period of the prior fiscal year reflect a decrease in total natural gas deliveries to firm customers of 27.5 million therms, or 2.3 percent, to 1.189 billion therms delivered during the current period. Although natural gas deliveries fell by 2.3 percent, heating degree days were relatively unchanged for the nine months ended June 30, 2005 when compared to the same period in fiscal year 2004. For the nine months ended June 30, 2005, weather was 6.2 percent colder than normal, enhancing net income in relation to normal weather by an estimated $5 million, or $0.10 per share. For the nine months ended June 30, 2004, weather was 6.4 percent colder than normal, and that colder than normal weather contributed approximately $10 million, or $0.20 per share, to net income for that period.
     The decrease in natural gas deliveries to firm customers is due, in part, to warmer weather experienced primarily during the second quarter of fiscal year 2005, the most significant period of the Company’s winter heating season. However, during the current nine-month period (particularly in the shoulder months of October and November within the first quarter, and the shoulder months of April and May within the third quarter), the Company experienced lower natural gas deliveries as the increase in heating degree days did not correlate highly with the change in the volume of gas delivered (refer to the “Results of Operations—Three Months Ended June 30, 2005 vs. June 30, 2004—Regulated Utility Operating Results” section of Management’s Discussion).
     Favorably affecting earnings for the regulated utility segment for the nine months ended June 30, 2005 was a 2.4 percent increase in active customer meters from the end of the same period of the prior fiscal year. The current nine-month period also benefited from realizing the favorable effect of

29


 

WGL Holdings, Inc.
Part I — Financial Information
Item 2 — Management’s Discussion and Analysis of
Financial Condition and Results of Operations (continued)
changes in rates charged to customers that were implemented in Maryland on November 6, 2003 and the District of Columbia on November 24, 2003. These benefits were slightly offset by the impact of an anticipated Virginia rate increase that went into effect on February 26, 2004, subject to refund, and was included in this segment’s operating results for the nine months ended June 30, 2004, but that was not in effect during the nine months ended June 30, 2005 as a result of a Virginia rate order issued after June 30, 2004 (refer to the “Regulatory Matters—Virginia Jurisdiction” section of Management’s Discussion for Washington Gas).
     Current year-to-date earnings also reflect a $4.1 million (pre-tax), or $0.05 per share, increase in operation and maintenance expenses. This represents a 2.4 percent year-over-year increase and primarily reflects: (i) higher employee benefits expenses principally related to post-retirement benefits and group insurance costs for active employees; (ii) increased overtime associated with work being performed in Prince George’s County, Maryland; (iii) higher expenses associated with performing the initial assessment of internal controls in accordance with Section 404 of the Sarbanes-Oxley Act and (iv) higher expenses for uncollectible accounts. These increased expenses were partially offset by fewer employees, reduced employee severance costs, and an accrual of $2.4 million recorded in the 2004 nine-month period for unusual operational expenses that were not incurred in the current nine-month period.
     Depreciation and amortization expense for the current nine-month period declined by $2.8 million (pre-tax), or $0.04 per share. The lower expense is attributable to a reversal in the current nine-month period of $1.0 million of depreciation expense that was previously estimated and recorded in fiscal year 2004 related to the performance of an earnings test required by a December 18, 2003 Final Order of the State Corporation Commission of Virginia (SCC of VA). The year-over-year reduction in expense is also due to the inclusion in the first nine months of fiscal year 2004 of depreciation expense of $3.5 million (pre-tax), or $0.04 per share, applicable to the period from January 1, 2002 through November 11, 2002, that was recorded in connection with the SCC of VA’s December 18, 2003 Final Order. This was partially offset by an increase in depreciation and amortization expense in the current nine-month period related to increased investment in property, plant and equipment.
     The regulated utility segment also benefited during the current year-to-date period from reduced income tax expense due to lower pre-tax income, as well as a lower estimated annual effective income tax rate (primarily attributable to a greater amount of non-taxable benefits associated with a Medicare prescription drug subsidy). This segment also benefited from $2.0 million (pre-tax), or $0.02 per share, of lower interest expense (refer to the “Interest Expense” section of Management’s Discussion), partially offset by $3.0 million, or $0.04 per share, of increased general taxes.
     Non-Utility Operating Results
     Total net income for the Company’s non-utility operations was $11.5 million, or $0.24 per share, for the nine months ended June 30, 2005, an increase of $2.6 million, or $0.06 per share, over the corresponding period of the prior fiscal year. The following table compares the financial results from non-utility activities for the nine months ended June 30, 2005 and 2004.

30


 

WGL Holdings, Inc.
Part I — Financial Information
Item 2 — Management’s Discussion and Analysis of
Financial Condition and Results of Operations (continued)
Net Income (Loss) Applicable to Non-Utility Activities
 
    Nine Months Ended        
    June 30,        
(In thousands)   2005     2004     Variance  
 
Retail energy-marketing
  $ 13,929     $ 6,059     $ 7,870  
Commercial HVAC  
    (1,288 )     (2,334 )     1,046  
 
Subtotal
    12,641       3,725       8,916  
Other non-utility activities
    (1,146 )     5,123       (6,269 )
 
Total
  $ 11,495     $ 8,848     $ 2,647  
 
     Retail Energy-Marketing. WGEServices reported net income of $13.9 million, or $0.28 per share, for the nine months ended June 30, 2005 as compared to net income of $6.1 million, or $0.12 per share reported for the same period last fiscal year. The $7.8 million, or $0.16 per share, year-over-year improvement in earnings primarily reflects higher gross margins from the sale of natural gas. Although natural gas sales volumes declined by 1.1 percent, gross margins per therm increased over 50 percent in the current nine-month period. The higher gross margins from gas sales reflect the utilization of greater volumes of lower cost storage inventory to supply customers in the first nine months of fiscal year 2005 compared to the corresponding period in fiscal year 2004, and a greater spread between the cost of that storage gas and retail prices charged to customers during the current nine-month period in relation to the prior year. This improvement was partially offset by changes in the mark-to-market valuation associated with derivative contracts used in WGEServices’ gas supply portfolio to reduce the risk of variations in demand caused by weather. These mark-to-market changes, when compared to the same period of the prior fiscal year, decreased net income by $972,000 (after-tax), or $0.02 per share (refer to the “Market Risk—Price Risk Related to Retail Energy-Marketing Operations” section of Management’s Discussion). The earnings improvement for this segment also reflects a $2.3 million (pre-tax), or $0.03 per share, benefit in the current year-to-date period for reduced expenses associated with uncollectible accounts due to enhanced recoveries of these accounts.
     Slightly tempering the earnings improvement for WGEServices was a decline in gross margins from electric sales in the current nine-month period, primarily reflecting a 62.3 percent decline in electric sales volumes that was partially offset by an increase in the gross margin per kilowatt hour sold. The decline in electric sales volumes primarily reflects the combined effect of increased competition for sales to large-volume commercial customers and below-market utility rates.
     Commercial HVAC. The commercial HVAC segment reported a net loss of $1.3 million, or $0.03 per share, for the nine months ended June 30, 2005, reducing its net loss by $1.0 million, or $0.02 per share, from the same period last fiscal year. This improvement primarily reflects improved operating margins during the period due to a focus on higher gross margin service work, being more selective of construction jobs that are being undertaken, and reducing selling, general and administrative expenses.
     Other Non-Utility Activities. Results for other non-utility activities for the current nine-month period reflect a $6.3 million decrease in income from the same period of the prior fiscal year, primarily due to an after-tax gain of $5.8 million, or $0.12 per share, realized from the sale of a carried interest in a real estate development in the first nine months of fiscal year 2004 that did not recur in the current period.
     Interest Expense
     The following table depicts the components of interest expense for the nine months ended June 30, 2005 and 2004.

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WGL Holdings, Inc.
Part I — Financial Information
Item 2 — Management’s Discussion and Analysis of
Financial Condition and Results of Operations (continued)
Composition of Interest Expense
 
    Nine Months Ended        
    June 30,        
(In thousands)   2005     2004     Variance  
 
Long-term debt
  $ 30,939     $ 31,375     $ (436 )
Short-term debt
    1,524       925       599  
Other (includes AFUDC*)
    (17 )     1,604       (1,621 )
 
Total
  $ 32,446     $ 33,904     $ (1,458 )
 
*   Represents the debt component of the Allowance for Funds Used During Construction.
     WGL Holdings’ interest expense of $32.4 million for the first nine months of fiscal year 2005 decreased $1.5 million from the same period last year. This decrease primarily reflects lower other interest expense due to an $882,000 fair value loss recorded during the nine months ended June 30, 2004 related to an interest-rate swap, and a reduction in interest associated with other miscellaneous items. The current year-to-date period also reflects reduced interest costs on long-term debt due to a temporary decrease in the average balance of long-term debt outstanding, partially offset by a slight increase in the weighted average cost of these borrowings. Interest expense on short-term debt rose, reflecting an increase of approximately 130 basis points in the weighted average cost of short-term debt, partially offset by a lower average balance outstanding.
     LIQUIDITY AND CAPITAL RESOURCES
     General Factors Affecting Liquidity
     It is important for the Company to have access to short-term debt markets to maintain satisfactory liquidity to operate its businesses on a near-term basis. Acquisition of natural gas, electricity, pipeline capacity, and the need to finance accounts receivable are the most significant short-term financing requirements of the Company. The need for long-term capital is driven primarily by capital expenditures and maturities of long-term debt.
     Significant swings can take place in the level of short-term debt required by the Company due primarily to changes in the price and volume of natural gas and electricity purchased to satisfy customer demand, and also due to seasonal cash collections on accounts receivable. Back-up financing to the Company’s commercial paper program in the form of revolving credit agreements enables the Company to maintain access to short-term debt markets. The ability of the Company to obtain such financing depends on its credit ratings, which are greatly affected by the Company’s financial performance and the liquidity of financial markets. Also potentially affecting access to short-term debt capital is the nature of any restrictions that might be placed upon the Company such as ratings triggers or a requirement to provide creditors with additional credit support in the event of a determination of insufficient creditworthiness.
     The ability to procure sufficient levels of long-term capital at reasonable costs is determined by the level of the Company’s capital expenditure requirements, its financial performance, and the effect of these factors on its credit ratings and investment alternatives available to investors.
     The Company has a goal to maintain its common equity ratio in the mid-50 percent range of total consolidated capital. The level of this ratio can vary during the fiscal year due to the seasonal nature of the Company’s business. In addition, the Company typically reduces short-term debt balances in the spring because a significant portion of the Company’s current assets is converted into cash at the

32


 

WGL Holdings, Inc.
Part I — Financial Information
Item 2 — Management’s Discussion and Analysis of
Financial Condition and Results of Operations (continued)
end of the winter heating season. Accomplishing these capital structure objectives and maintaining sufficient cash flow are necessary to maintain attractive credit ratings for the Company and Washington Gas, and to allow access to capital at reasonable costs. As of June 30, 2005, total consolidated capitalization, including current maturities of long-term debt and excluding notes payable, comprised 60.5 percent common equity, 1.9 percent preferred stock and 37.6 percent long-term debt. The cash flow requirements of the Company and the ability to provide satisfactory resources to satisfy those requirements are primarily influenced by the activities of Washington Gas and to a lesser extent the non-utility operations.
     The Company believes it has sufficient liquidity to satisfy its financial obligations. At June 30, 2005, the Company did not have any restrictions on its cash balances that would affect the payment of common or preferred stock dividends by WGL Holdings or Washington Gas.
     Short-Term Cash Requirements and Related Financing
     The regulated utility’s business is weather sensitive and seasonal, causing short-term cash requirements to vary significantly during the year, and from year-to-year for the same quarter. Over 75 percent of the total therms delivered in the regulated utility’s service area (excluding deliveries to two electric generation facilities) occur during the first and second fiscal quarters. Cash requirements peak in the fall and winter months when accounts receivable, accrued utility revenues and storage gas inventories are at their highest levels. After the winter heating season, many of these assets are converted into cash, which Washington Gas generally uses to reduce and sometimes eliminate short-term debt and to acquire storage gas for the next heating season.
     The Company’s retail energy-marketing subsidiary, WGEServices, has seasonal short-term cash requirements resulting from its need to purchase storage gas inventory in advance of the period in which the storage gas is sold. In addition, WGEServices must continually pay its suppliers of natural gas and electricity before it collects its accounts receivable balances resulting from these sales. WGEServices derives its funding to finance these activities from short-term debt issued by the Company.
     Both the regulated utility and the retail energy-marketing segment maintain storage gas inventory. WGEServices maintains storage gas inventory that is assigned to it by natural gas utilities such as Washington Gas. Storage gas inventories represent gas purchased from producers and are stored in facilities primarily owned by interstate pipelines. The regulated utility and retail energy-marketing subsidiary generally pay for storage gas between heating seasons and withdraw it during the heating season. Significant variations in storage gas balances between years are possible, and are caused by the price paid to producers and marketers, which is a function of short-term market fluctuations in gas costs, and changing requirements for storage volumes. For the regulated utility, such costs become a component of the cost of gas recovered from customers when volumes are withdrawn from storage. In addition, the regulated utility is able to specifically earn and recover its pre-tax cost of capital related to the varying level of the storage gas inventory balance it carries in each of the three jurisdictions in which it operates.
     Variations in the timing of collections of gas costs under the regulated utility’s gas cost recovery mechanisms and the level of refunds from pipeline companies that will be returned to customers can significantly affect short-term cash requirements.
     The Company and Washington Gas utilize short-term debt in the form of commercial paper or unsecured short-term bank loans to fund seasonal requirements. The Company’s policy is to maintain back-up bank credit facilities in an amount equal to or greater than its expected maximum

33


 

WGL Holdings, Inc.
Part I — Financial Information
Item 2 — Management’s Discussion and Analysis of
Financial Condition and Results of Operations (continued)
commercial paper position. As of June 30, 2005, Washington Gas and WGL Holdings each had a credit agreement with a group of commercial banks in the amount of $175 million in support of their short-term debt requirements. The credit facility for Washington Gas expires on April 28, 2009, and permits the regulated utility to request prior to April 28, 2008, and the banks to approve, an additional line of credit of $100 million above the original credit limit, for a maximum potential total of $275 million. WGL Holdings’ credit facility expires on April 27, 2007, and permits the Company to request prior to April 28, 2006, and the banks to approve, an additional line of credit of $50 million above the original credit limit, for a maximum potential total of $225 million. As of June 30, 2005, there were no outstanding borrowings under either the Washington Gas or WGL Holdings credit facility.
     The Company had outstanding notes payable through the issuance of commercial paper of $26.7 million at June 30, 2005, as compared to $95.6 million outstanding at September 30, 2004. Substantially all of the outstanding notes payable balance at June 30, 2005 was commercial paper issued by WGL Holdings. Of the outstanding notes payable balance at September 30, 2004, $76.9 million was commercial paper issued by WGL Holdings and $18.7 million was commercial paper issued by Washington Gas.
     Long-Term Cash Requirements and Related Financing
     The Company’s long-term cash requirements primarily depend upon the level of capital expenditures, long-term debt maturity requirements and decisions to refinance long-term debt. Historically, the Company has devoted the majority of its capital expenditures to adding new regulated utility customers in its existing service area. However, as a result of recent operating issues in Prince George’s County, Maryland described later in Management’s Discussion, the Company forecasts a greater level of replacement capital expenditures over the next two and one-half years (refer to the “Capital Expenditures” section of Management’s Discussion). At June 30, 2005, Washington Gas was authorized to issue up to $213.0 million of long-term debt under a shelf registration that was declared effective by the Securities and Exchange Commission on April 24, 2003. On May 20, 2003, Washington Gas executed a Distribution Agreement with certain financial institutions for the issuance and sale of debt securities included in the shelf registration statement.
     During the nine months ended June 30, 2005, Washington Gas retired a total of $60.5 million of Medium-Term Notes (MTNs). On March 7, 2005, Washington Gas, through exercise of a call option, retired $20.0 million of MTNs. The MTNs redeemed were $10.0 million of 7.76 percent MTNs and $10.0 million of 7.75 percent MTNs that had a nominal maturity date in March 2025. On June 9, 2005, Washington Gas, through exercise of a call option, retired $20.0 million of 6.50 percent MTNs that had a nominal maturity date in June 2025. Additionally, on June 20, 2005, Washington Gas retired $20.5 million of 7.45 percent MTNs that matured on the same date. Washington Gas paid the applicable accrued interest on each debt retirement date.
     On August 4, 2005, Washington Gas agreed to sell $20.0 million of 4.83 percent MTNs due August 2015 to replace the MTNs retired on March 7, 2005, as discussed above. The issuance of this $20.0 million of MTNs is expected to occur on August 9, 2005. On August 8, 2005, Washington Gas agreed to sell $40.5 million of 5.44 percent MTNs due August 2025 to replace the MTNs retired in June 2005, as discussed above. The issuance of this $40.5 million of MTNs is expected to occur on August 11, 2005. Concurrent with the decision to sell the $20.0 million of 4.83 percent MTNs, Washington Gas is expected to pay $364,000 on August 9, 2005 associated with the settlement of a forward-starting swap that has a notional principal of $20.0 million. Similarly, concurrent with the decision to sell the $40.5 million of 5.44 percent MTNs, Washington Gas is expected to pay $2.2 million on August 11, 2005 associated with the settlement of a forward-starting swap that has a notional principal of $40.5 million (refer to the “Market Risk—Interest-Rate Risk” section of Management’s Discussion). The effective cost of the newly-issued debt, after considering the amount paid related to the two forward-starting swaps, is expected to be 5.15 percent and 5.99 percent for the $20.0 million and $40.5 million debt issuances, respectively.

34


 

WGL Holdings, Inc.
Part I — Financial Information
Item 2 — Management’s Discussion and Analysis of
Financial Condition and Results of Operations (continued)
     Security Ratings
     The table below reflects the current credit ratings for the outstanding debt instruments of WGL Holdings and Washington Gas. Changes in credit ratings may affect the Company’s and Washington Gas’ cost of short-term and long-term debt and their access to the credit markets.
Credit Ratings for Outstanding Debt Instruments
 
    WGL Holdings, Inc.   Washington Gas  
    Unsecured       Unsecured      
    Medium-Term   Commercial   Medium-Term   Commercial  
Rating Service   Notes (Indicative)*   Paper   Notes   Paper  
 
Fitch Ratings
  A+   F1   AA-     F1+  
Moody’s Investors Service
  **   Not-Prime   A2     P-1  
Standard & Poor’s Ratings Services***
  AA-   A-1   AA-     A-1  
 
* Indicates the ratings that may be applicable if WGL Holdings were to issue unsecured medium-term notes.
 
** Unpublished.
 
*** This agency has held a negative outlook on the long-term debt ratings of WGL Holdings and Washington Gas since July 2, 2004.
     Contractual Obligations, Off-Balance Sheet Arrangements and Other Commercial Commitments
     The Company has certain contractual obligations incurred in the normal course of business that require it to make fixed and determinable payments in the future. These commitments include long-term debt, lease obligations, unconditional purchase obligations for pipeline capacity, transportation and storage services, and certain natural gas and electricity commodity commitments.
     Reference is made to the “Contractual Obligations, Off-Balance Sheet Arrangements and Other Commercial Commitments” section of Management’s Discussion in the Company’s Annual Report on Form 10-K for the fiscal year ended September 30, 2004, for a detailed discussion of these contractual obligations. Note 5 of the Notes to Consolidated Financial Statements in the Company’s 2004 Annual Report on Form 10-K includes a discussion of long-term debt, including debt maturities. Reference is made to Note 14 of the Notes to Consolidated Financial Statements in the Company’s 2004 Annual Report on Form 10-K that reflects information about the various contracts of Washington Gas and WGEServices. Additionally, refer to Note 10—Commitments and Contingencies of the Notes to Consolidated Financial Statements in this Form 10-Q.
     Financial Guarantees. WGL Holdings has guaranteed payments primarily for certain purchases of natural gas and electricity on behalf of the retail energy-marketing segment. At June 30, 2005, these guarantees totaled $170.9 million. Termination of these guarantees is coincident with the satisfaction of all obligations of WGEServices covered by the guarantees. WGL Holdings also had guarantees totaling $5.0 million at June 30, 2005 that were made on behalf of certain of its non-utility subsidiaries associated with their banking transactions. For all of its financial guarantees, WGL Holdings may cancel any or all future obligations imposed by the guarantees upon written notice to the counterparty, but WGL Holdings would continue to be responsible for the obligations that had been created under the guarantees prior to the effective date of the cancellation.
     Construction Project Financing. In October 2000, Washington Gas contracted with the U.S. General Services Administration (GSA) to construct certain facilities at the GSA central plant in Washington, D.C. Payments to Washington Gas for this construction were to be made by the GSA over a 15-year period. In November 2000, Washington Gas and General Electric Capital Assurance Company (GEFA) entered into a long-term financing arrangement, whereby GEFA funded this construction project. Under the terms of this financing arrangement, Washington Gas assigned to GEFA the 15-year stream of payments due from the GSA. The final amount of this long-term financing arrangement, including amendments, change orders, origination fees and capitalized finance charges was $69.4 million. As the long-term financing from GEFA was funded, Washington

35


 

WGL Holdings, Inc.
Part I — Financial Information
Item 2 — Management’s Discussion and Analysis of
Financial Condition and Results of Operations (continued)
Gas established a note receivable representing the GSA’s obligation to remit principal and interest. Upon completion and acceptance of phases of the construction project, Washington Gas accounted for the transfer of the financed asset as an extinguishment of long-term debt and removed both the note receivable and long-term financing from its financial statements. In December 2004, all remaining work under the construction project was fully accepted by the GSA. Accordingly, the remaining note receivable and corresponding long-term note payable related to the GSA construction project were removed from the Company’s financial statements at December 31, 2004. As a result of GSA’s final acceptance, GEFA has no further recourse against the Company related to the extinguished long-term debt.
     Prince George’s County, Maryland Operating Issues. On April 1, 2005, Washington Gas reported a significant increase in the number of natural gas leaks on its distribution system in a portion of Prince George’s County, Maryland. Washington Gas determined that these leaks resulted from the shrinkage of seals located in mechanical couplings that connect sections of distribution mains and services. Given the increase in the number of gas leaks, Washington Gas announced that it would replace gas service lines and rehabilitate gas mains that contain the applicable mechanical couplings in the affected area of the distribution system in Prince George’s County (the rehabilitation project). Washington Gas also indicated that it was investigating the reasons for the degradation of the seals in the couplings that were causing the increase in gas leaks in the affected area of Prince George’s County.
     On April 22, 2005, Washington Gas announced its plan to address all leaks in the affected area within approximately six months of their being identified. Washington Gas indicated that it expected to rehabilitate or replace all other applicable coupled service lines and distribution mains in the affected area of Prince George’s County area by the end of December 2007, even if no leaks have been detected.
     On April 27, 2005, Washington Gas updated its estimated cost for the rehabilitation project to $137 million, including up to $50 million for paving costs related to the required work. Washington Gas also announced that it expected to account for all costs of this project in Prince George’s County as capital expenditures. This expectation was confirmed by an Accounting Order granted by the Public Service Commission of Maryland (PSC of MD) on June 1, 2005. The Order enables Washington Gas to capitalize certain costs of encapsulating couplings used to rehabilitate certain mains that would normally be recorded as maintenance expense, absent the substantial nature of this project (refer to the “Regulatory Matters—Maryland Jurisdiction” section of Management’s Discussion for Washington Gas for a further discussion of this regulatory matter).
     The current cost estimate for the rehabilitation project, including paving costs, has been revised to $144 million. This is a significant increase in planned capital expenditures in fiscal years 2006 through 2008 (refer to the “Liquidity and Capital Resources—Capital Expenditures” section of Management’s Discussion for a table of projected capital expenditures). This current cost estimate does not consider any changes in costs associated with potential remediation steps discussed below. The actual costs that will be incurred for the work associated with this project could differ materially from the cost estimates discussed herein. However, Washington Gas believes it has the financial resources necessary to fund this project due to its current strong cash position, and the financing options it has available.
     Mechanical couplings identical to the couplings in Prince George’s County are located in other portions of Washington Gas’ distribution system, including Virginia, other areas of Maryland, and the District of Columbia. These mechanical couplings were routinely installed on the Washington Gas system from the 1940’s to the early 1970’s. To date, Washington Gas has not experienced any

36


 

WGL Holdings, Inc.
Part I — Financial Information
Item 2 — Management’s Discussion and Analysis of
Financial Condition and Results of Operations (continued)
pattern of leaks in these other areas that is comparable to the leak pattern encountered in the affected area of Prince George’s County.
     Management of Washington Gas believes that the costs to be incurred related to this matter are necessary to provide safe and reliable utility service. Management believes that costs such as these are normally recognized in the ratemaking process as reasonable. At the present time, Washington Gas has not requested regulatory recovery of these costs that will be incurred. However, Washington Gas is considering the effect of these capital expenditures on its ability to earn its allowed rate of return in Maryland, and is evaluating the most appropriate regulatory option to enable full and timely recovery of, and return on, the amounts to be expended. There can be no assurance at this time that recovery in rates will be allowed or at what point in time such recovery may begin to be reflected in rates. Significant negative effects on earnings in future years could result if such costs are incurred and recovery in rates is not allowed.
     Washington Gas received a report dated July 1, 2005 from ENVIRON International Corporation (Environ or consultant), working with Polymer Solutions, Inc. and Akron Rubber Development Laboratory that describes the results of its investigation of the causes of the leaks of the couplings in Prince George’s County. The report of Environ is filed as an exhibit to this Form 10-Q. All statements made herein regarding the report of Environ are intended to provide a summary of the material aspects of the report and should be considered in the full context of the complete report of Environ. The report of Environ should be read in conjunction with this summary for a full and more complete understanding of the issues. The report of Environ is available in its entirety on WGL Holding’s website, www.wglholdings.com.
     Environ conducted its investigation by: (1) gathering information regarding coupling design and materials, installation practices, leak patterns, gas compositions, geological information, and the experiences of other local distribution companies with similar equipment; (2) developing a list of plausible physical and chemical mechanisms which could contribute to the observed leak patterns in the field; (3) constructing a working hypothesis for the observed coupling leaks; (4) designing and conducting experiments to develop the required data to evaluate the hypothesis; and (5) reviewing the experimental data, as well as other information collected during the assignment, to make its best assessment of the most likely causes of the increased leak rate.
     The experiments conducted included exposure tests, in which various seals were immersed in different gas environments for fixed periods, with detailed dimensional, weight and hardness measurements being made before, during and after exposure. A key feature of these tests was the evaluation of a set of seals that had been exposed to a reference pipeline gas composition for a fixed period and was then switched to a liquefied natural gas (LNG) composition like that contained in the gas coming out of the Dominion Cove Point (Dominion or Cove Point) LNG terminal for a further period. Other sets of seals remained in the reference pipeline gas environment.
     As detailed in the study, tests were conducted on rubber seals removed from leaking and non-leaking mechanical couplings in Prince George’s County to determine an explanation for the failure rates. The investigation reviewed a number of potential causes of failures, including humidity; ground conditions; coupling design; construction techniques and skills; age; and quality and type of materials installed. Many items were ruled out or identified as possible contributors.
     Based on the work conducted to date, Environ concludes that there is a combination of three contributing factors to the higher leak rates of seals on couplings. One of these is the change in the gas composition resulting from a change in the gas supply arising from the reactivation of the Cove Point terminal. The Cove Point gas has a lower concentration of heavy hydrocarbons (HHCs) than

37


 

WGL Holdings, Inc.
Part I — Financial Information
Item 2 — Management’s Discussion and Analysis of
Financial Condition and Results of Operations (continued)
domestic natural gas. A characteristic of the rubber material comprising the seals in the couplings is the ability of the seals to both adsorb and desorb HHCs. When seals are exposed to higher levels of HHCs they swell in size and cause a tighter seal. However, when gas is introduced that has a lower level of HHCs, the seals shrink in size and there is a greater propensity for those seals to cause the couplings to leak.
     Also considered as contributing factors to a higher failure rate for seals of this nature are the age of the couplings and the colder ground temperature during winter periods. However, both the age of the couplings and the ground temperature are common to couplings in other areas of Washington Gas’ service territory where leak patterns have not been observed like those in the affected area of Prince George’s County.
     The relevant change that explains the higher incidence of leaks in the affected area of Prince George’s County is the composition of the gas resulting from the introduction of Cove Point gas. The Cove Point gas manifests such a change in composition because, during its processing into a liquid prior to importation, certain HHCs are required to be removed. These same HHCs, which are present in domestic natural gas, had previously enabled the flexibility and sealing capability of the rubber seals during their in-service life. The higher failure rate of the rubber seals in the specific geographic area of Prince George’s County results from the proximity of Washington Gas’ larger gate stations to the pipelines (gate stations are entrance points to Washington Gas’ distribution system from a pipeline) that receive Cove Point gas from the LNG terminal for delivery to Washington Gas.
     The Environ report also documents that the adsorption/desorption of HHCs by seal materials is a reversible process. Based on discussions between management and Environ, and examination of testing data and conclusions of another utility that had a similar experience, Washington Gas expects that it is highly possible to reverse the known condition of the seals in the affected area of Prince George’s County, and prevent the emergence of premature failures of mechanical couplings located in the affected area and elsewhere in Washington Gas’ service territory that receives supplies of Cove Point gas and has mechanical couplings. Washington Gas has requested that the consultant recommend to Washington Gas the optimal gas composition that will cause the effect of the Cove Point gas to reverse the conditions noted to date and that will avoid premature seal shrinkage in the affected area in Prince George’s County and elsewhere on the system. After Washington Gas has received this information from the consultant on the optimal gas composition, it will evaluate its ability to achieve a gas mixture in which this optimal level can be attained.
     The results of the Environ study have different implications for different parts of Washington Gas’ distribution system. In addition to the natural gas being taken directly from the Cove Point pipeline to serve the area that has been affected in Prince George’s County, Washington Gas has five other gate stations served by the Cove Point pipeline where Cove Point gas is brought into Washington Gas’ distribution system for re-delivery, in total, to a significant number of customers other than those customers in the affected area of Prince George’s County. Cove Point gas that is not delivered through one of the six Washington Gas gate stations on the Cove Point pipeline, is delivered into three interconnected pipelines. Washington Gas has over 20 gate stations attached to these three interconnected pipelines where Cove Point gas, in various levels of blending with domestic natural gas, is delivered to Washington Gas.
     Washington Gas has not experienced any change in historical leak levels in parts of the system outside of the affected area of Prince George’s County. However, the volume of natural gas coming through the Cove Point pipeline is likely to increase by 80 percent in 2008, and a large portion of that gas may come into the Washington Gas system. Such gas deliveries will come into the Washington Gas system directly from gate stations on the Cove Point pipeline as well as through gate stations on

38


 

WGL Holdings, Inc.
Part I — Financial Information
Item 2 — Management’s Discussion and Analysis of
Financial Condition and Results of Operations (continued)
the pipelines that interconnect with Cove Point and receive large volumes of the Cove Point gas. Accordingly, Washington Gas is considering alternative approaches to address the currently affected areas of Prince George’s County, as well as the potential effect of Cove Point gas on other portions of Washington Gas’ distribution system affected by the delivery of Cove Point gas in various concentrations at other gate stations.
     The first potential approach is for Dominion to condition all gas leaving the Cove Point terminal by restoring HHCs that were previously removed from the natural gas during the liquefaction process. Such an approach would require equipment to store, condition and inject HHCs at the terminal. As such, it is likely that the cost of this approach could be reflected in the rates charged by Cove Point for LNG terminal and transportation service. Such rates would be subject to the approval of the Federal Energy Regulatory Commission. This potential approach would require no significant additional investment by Washington Gas downstream at each city gate because all natural gas coming from the Cove Point facility would be interchangeable with domestic natural gas, including gas delivered into the affected area of Prince George’s County. However, even if this approach is implemented, Washington Gas will continue to proceed with its current rehabilitation and special leak surveys of the affected area of Prince George’s County until it has been determined that the situation in the affected area of Prince George’s County has reversed itself. Washington Gas will have to obtain Dominion’s cooperation and support to implement this approach.
     The second potential approach, to be implemented to serve areas that receive relatively large quantities of Cove Point gas and that have mechanically coupled pipe, is to develop a coordinated approach with Cove Point, the LNG shippers and the interconnected interstate pipelines that connect to the Cove Point line, to blend domestically produced natural gas into any stream of Cove Point gas that is distributed by the Cove Point facility and flows into the interconnected pipelines and then into Washington Gas’ distribution system. Such blending, if it can be achieved at appropriate levels, will introduce HHCs present in the domestic sources of natural gas flowing on the interconnected pipelines. Additional studies are underway to confirm the blending requirements. Washington Gas will only be able to implement this approach with the cooperation of all or some of the parties mentioned in this paragraph.
     The third potential approach would be the installation of equipment at each of the gate stations that are most likely to receive a relatively large concentration of Cove Point gas (seven stations in total) and add HHCs into the gas stream before it is introduced into Washington Gas’ distribution system. The process of re-injecting HHCs that have been removed for liquefaction purposes back into the distribution system is a normal and customary step in many LNG peak-shaving plants. Currently, because of the high concentration of Cove Point gas being received at the gate station that serves the affected area of Prince George’s County, Washington Gas has begun to plan for the construction of such a facility to inject HHCs at this particular gate station. Although the installation of the equipment at this gate station may reverse or partially reverse the effect of the Cove Point gas on the distribution system in the affected part of Prince George’s County and reduce the current cost estimate of $144 million, Washington Gas plans to continue the rehabilitation of the area in Prince George’s County and to continue the special leak surveys until there is appropriate evidence that the desired reversal has occurred. Washington Gas does not need to construct similar facilities at the other six gate stations until Cove Point gas flows increase in 2008. It may not need to construct them at all if one or a combination of the other two potential approaches discussed above is implemented. Washington Gas has significant control, over the majority of the land, facilities and logistics required to implement this approach, subject to attaining any necessary permitting or matters of that kind.
     The concept of such a facility is similar in design to Washington Gas’ existing process of odorizing natural gas by injecting natural gas with a chemical that gives it its unique odor. Although small in

39


 

WGL Holdings, Inc.
Part I — Financial Information
Item 2 — Management’s Discussion and Analysis of
Financial Condition and Results of Operations (continued)
scale, odorizing natural gas is an automated process completed at each gate station. Facilities needed for injecting HHCs would include a storage tank for the liquid, metering, pumping and injecting equipment. The estimated cost of the acquisition and installation of equipment needed to inject HHCs into the gas stream at Washington Gas gate stations is $1 million at each station, for a total of $7 million at all gate stations at which such facilities will potentially be installed. Washington Gas expects that these facilities’ costs should be includible in the rate base upon which Washington Gas is allowed to earn an allowed rate of return. The $7 million cost does not include the cost of the HHCs which Washington Gas anticipates should be includible in its purchased gas adjustment charge.
     Although Washington Gas believes that each of the three potential approaches described above is reasonable and practical to implement, Washington Gas will only be able to identify the best approach after consultation with the Cove Point terminal operator, the LNG shippers, and the owners of the interstate pipelines. A combination of the three potential approaches may also enable the most effective solution to the gas interchangeability issue.
     Washington Gas is committed to the use of natural gas from the Cove Point terminal to satisfy the needs of its customers. Washington Gas will work cooperatively with Dominion Cove Point LNG, the shippers who bring LNG into the Cove Point terminal and the interstate pipelines that deliver gas to Washington Gas in order to achieve and implement an appropriate solution to the issue of gas interchangeability affecting its system.
     Cash Flows Provided by Operating Activities
     The primary drivers for the Company’s operating cash flows are cash payments received from gas customers, offset by payments made by the Company for gas costs, for operation and maintenance expenses, taxes and interest costs. Current interest expense reflects the favorable effect of relatively low short-term interest rates, a condition that has begun to change as short-term interest rates have risen.
     During the first six months of the Company’s fiscal year, the Company typically generates more net income than its annual net income (net losses are normally generated in the last six months of the fiscal year) due to the significant volumes of natural gas that are delivered by the regulated utility during the winter heating season. Variations in the level of net income reported for the six-month period ended March 31 may be significant because of the variability of weather and other related factors from one period in a year to the same period in the subsequent year. Generating large sales volumes during the six-month period ended March 31 increases accounts receivable from the level at September 30; likewise, accounts payable increases to pay providers of the natural gas commodity. Accounts payable for the natural gas commodity can also vary significantly from one period to the next because of the volatility in the price of natural gas. Storage gas inventories, which usually peak by November 1, are largely drawn down in the six months ended March 31, and provide a source of cash as this asset is used to satisfy winter sales demand. Gas costs due from or to customers and deferred purchased gas costs, which represent the difference between gas costs that have been paid to suppliers and what has been collected from customers, can also cause significant variations in operating cash flows from period to period.
     During the last six months of the Company’s fiscal year, after the winter heating season, the Company will generally report a seasonal net loss due to reduced demand for natural gas during this period. Additionally, many of the Company’s assets, which were generated during the heating season, are converted into cash. The Company generally uses this cash to reduce and sometimes eliminate short-term debt, and acquire storage gas for the next heating season.

40


 

WGL Holdings, Inc.
Part I — Financial Information
Item 2 — Management’s Discussion and Analysis of
Financial Condition and Results of Operations (continued)
     Net cash provided by operating activities totaled $314.7 million for the first nine months of fiscal year 2005. A description of certain material changes in working capital from September 30, 2004 to June 30, 2005 is listed below:
    Accounts receivable and accrued utility revenues increased $25.2 million from September 30, 2004, primarily due to the increase in sales that resulted during the Company’s heating season. Rising gas costs also increased uses of cash for accounts receivable.
   
    Storage gas inventory levels decreased $88.9 million from September 30, 2004 as volumes were withdrawn to satisfy the sales demand during the 2004-2005 winter heating season, and have not yet been replenished to the levels necessary to accommodate the 2005-2006 winter heating season.
     Cash Flows Used in Financing Activities
     Cash flows used in financing activities were $177.4 million for the nine months ended June 30, 2005. During the current nine-month period, the Company retired $60.5 million of MTNs. A decrease in notes payable of $69.0 million, coupled with a common stock dividend payment of $47.8 million, were additional uses of cash.
     Cash Flows Used in Investing Activities
     During the nine months ended June 30, 2005, cash flows used in investing activities totaled $75.1 million, $72.2 million of which were for capital expenditures made on behalf of the regulated utility.
     Capital Expenditures
     The Company has revised its five-year capital expenditures budget from $670.7 million, as reported in its Annual Report on Form 10-K for the fiscal year ended September 30, 2004, to a revised total of $799.7 million to be expended during fiscal years 2005 through 2009. The increase in this budget primarily reflects the $144 million in costs that are currently estimated to be expended in connection with the rehabilitation project in Prince George’s County.
     The following table depicts the Company’s revised capital expenditures budget for fiscal years 2005 through 2009.
Projected Capital Expenditures
 
    Fiscal Year Ending September 30,        
(In millions)   2005     2006     2007     2008     2009     Total  
 
New business
  $ 61.7     $ 64.6     $ 66.0     $ 66.3     $ 63.8     $ 322.4  
Replacements
    40.1       88.3       89.2       54.9       36.6       309.1  
Other
    29.7       44.3       36.2       30.6       27.4       168.2  
 
Total
  $ 131.5     $ 197.2     $ 191.4     $ 151.8     $ 127.8     $ 799.7  
 
     Included in the table above is $60 million of capital expenditures to construct a necessary, new source of supply to support customers beginning during the winter of 2008-2009 and beyond. Those expenditures are for constructing a one billion cubic foot liquefied natural gas storage facility on the land used for former storage facilities in Chillum, Maryland. Management believes that the construction of this liquefied natural gas storage project represents the lowest cost and most operationally desirable system supply for its customers. However, residents neighboring the planned

41


 

WGL Holdings, Inc.
Part I — Financial Information
Item 2 — Management’s Discussion and Analysis of
Financial Condition and Results of Operations (continued)
site, as well as their elected officials, have voiced concerns with and opposition to this project. The next best alternative would require that the Company make significant enhancements to its transmission and distribution systems and retain much costlier firm transportation or firm storage services from interstate pipelines every day of the year, thus increasing gas costs to customers. At the present time, management cannot predict whether the liquefied natural gas storage facility will be built. In any event, it is the opinion of management that it will have the necessary supply and deliverability of that supply in some form to provide for the future growth of its customer base and the pressure requirements on its distribution system.
     CREDIT RISK
     Regulated Utility Operations
     Certain suppliers that sell gas to Washington Gas have either relatively low credit ratings or are not rated by major credit rating agencies. In the event of a supplier’s failure to deliver contracted volumes of gas, the regulated utility may need to replace those volumes at prevailing market prices, which may be higher than the original transaction prices, and pass these costs through to its sales customers under the purchased gas cost adjustment mechanisms (refer to the “Market Risk—Price Risk Related to the Regulated Utility Operations” section of Management’s Discussion). To manage this supplier credit risk, Washington Gas screens suppliers’ creditworthiness and asks suppliers as necessary for financial assurances including, but not limited to, letters of credit and parental guarantees, to mitigate adverse price exposures that could occur if a supplier defaults.
     Retail Energy-Marketing Operations
     Certain suppliers that sell natural gas or electricity to WGEServices have either relatively low credit ratings or are not rated by major credit rating agencies. Depending on the future ability of these suppliers to deliver natural gas or electricity under existing contracts, WGEServices could be financially exposed for the difference between the price at which WGEServices has contracted to buy these commodities, and the replacement cost of these commodities that may need to be purchased. WGEServices has a wholesale supplier credit policy that is designed to mitigate wholesale credit risks through a requirement for credit enhancements. Per the terms of this policy, WGEServices has obtained credit enhancements from certain of its suppliers.
     For a further discussion of the credit risk associated with WGEServices’ electricity suppliers, refer to the “Market Risk—Price Risk Related to Retail Energy-Marketing Operations” section of Management’s Discussion.
     MARKET RISK
     The Company is exposed to various forms of market risk. The following discussion describes the Company’s exposure to commodity price risk and interest-rate risk.
     Price Risk Related to Regulated Utility Operations
     Washington Gas actively manages its gas supply portfolio to balance its sales and delivery obligations. The regulated utility includes the cost of the natural gas commodity and pipeline services in the purchased gas costs that it includes in firm customers’ rates, subject to regulatory review. The regulated utility’s jurisdictional tariffs contain gas cost mechanisms that allow it to recover the invoice cost of gas applicable to firm customers.

42


 

WGL Holdings, Inc.
Part I — Financial Information
Item 2 — Management’s Discussion and Analysis of
Financial Condition and Results of Operations (continued)
     In order to mitigate commodity price risk for its firm customers, Washington Gas has specific regulatory approval in the District of Columbia, Maryland and Virginia to hedge contracts for a limited portion of its natural gas purchases. These regulatory approvals are pursuant to pilot programs, and the Company is seeking to continue these programs. Additionally, the regulated utility purchases natural gas under contracts that provide for volumetric variability. Certain of these contracts are required to be recorded at fair value (refer to Note 7 of the Notes to Consolidated Financial Statements—Derivative Instruments for a discussion of the accounting for these derivative instruments). As of June 30, 2005 and September 30, 2004, the Company recorded a payable on its balance sheet reflecting a fair value loss of $3.6 million and $8.2 million, respectively, related to its variable gas purchase contracts, with a corresponding amount recorded as a regulatory asset in accordance with regulatory accounting requirements for recoverable costs in each jurisdiction.
     The regulated utility also mitigates price risk by injecting natural gas into storage during the summer months when prices are generally lower and less volatile, and withdraws that gas during the winter heating season when prices are generally higher and more volatile.
     Price Risk Related to Retail Energy-Marketing Operations
     The Company’s retail energy-marketing subsidiary, WGEServices, sells natural gas and electricity to retail customers at both fixed prices and indexed prices. The Company must manage daily and seasonal demand fluctuations for these products. The volume and price risks are evaluated and measured separately for natural gas and electricity.
     Natural Gas
     WGEServices is exposed to market risk to the extent it does not closely match the timing and volume of natural gas it purchases with the related fixed price or indexed sales commitments. WGEServices’ risk management policies and procedures are designed to minimize these risks. WGEServices also faces risk in that approximately 60 percent of its annual natural gas sales volumes are subject to variations in customer demand caused by fluctuations in weather. Purchases of natural gas to fulfill retail sales commitments are made generally under fixed-volume contracts that are based on normal weather assumptions. If there is a significant deviation from normal weather that causes purchase commitments to differ significantly from sales levels, WGEServices may be required to buy incremental natural gas or sell excess natural gas at prices that negatively impact gross margins. WGEServices manages this volumetric risk by using storage gas inventory and peaking services offered to marketers by the regulated utilities that provide delivery service for WGEServices customers. WGEServices also manages price risk through the use of derivative instruments. At June 30, 2005 and September 30, 2004, these derivative instruments were recorded on the Company’s consolidated balance sheets as a fair value gain of $715,000 and $719,000, respectively. In connection with these derivative instruments, WGEServices recorded pre-tax losses of $233,000 and $876,000 for the three and nine months ended June 30, 2005, respectively. WGEServices recorded pre-tax gains of $214,000 and $699,000 for the three and nine months ended June 30, 2004, respectively.
     Electricity
     Full Requirements Supply. For a portion of its electricity supply, WGEServices limits its volumetric and price risks by purchasing full requirements services from its wholesale electricity suppliers under master purchase and sale agreements, including electric energy, capacity and certain ancillary services, for resale to retail electric customers. WGEServices’ full requirements wholesale suppliers assume the risk for any volume and price risks associated with sales made by WGEServices. WGEServices’ principal supplier of full requirements electricity is Mirant Americas Energy Marketing

43


 

WGL Holdings, Inc.
Part I — Financial Information
Item 2 — Management’s Discussion and Analysis of
Financial Condition and Results of Operations (continued)
L.P. (MAEM), an indirect wholly owned subsidiary of Mirant Corporation (Mirant).
     On July 14, 2003, Mirant and substantially all of its subsidiaries filed voluntary petitions for reorganization under Chapter 11 of the U.S. Bankruptcy Code. MAEM was included in these bankruptcy filings. Since the bankruptcy filing, MAEM has continued to honor its supply obligations to WGEServices. The majority of the obligations to WGEServices under the pre-bankruptcy petition MAEM contracts expired on or before December 31, 2004, and the remainder of these contracts will expire by the end of October 2005. Future performance by MAEM may be subject to further developments in the bankruptcy proceedings.
     The performance risk associated with the pre-bankruptcy petition MAEM contracts is mitigated through a Security and Escrow agreement entered into between WGEServices and MAEM prior to the bankruptcy filing. Under the Security and Escrow agreement, WGEServices has access to collateral that was intended to cover the difference between the current market price of electricity and the price at which WGEServices has contracted to buy electricity from MAEM. WGEServices has the contractual right to draw on the escrow funds in the account (which totaled $102,000 and $3.0 million as of June 30, 2005 and September 30, 2004, respectively) if the pre-bankruptcy petition contracts between WGEServices and MAEM are terminated. Accordingly, WGEServices is potentially exposed to any excess damages above this escrow account balance in the event of contract rejection.
     On January 19, 2005, Mirant filed a plan of reorganization in connection with its bankruptcy. The plan proposes that upon MAEM’s emergence from bankruptcy, any pre-bankruptcy petition executory contracts not expressly assumed would be rejected. At this time, WGEServices’ pre-bankruptcy petition contracts have not been expressly assumed, and there is no assurance that they will be.
     Should MAEM reject WGEServices’ pre-bankruptcy petition contracts either prior to or at the time of its emergence from bankruptcy, WGEServices estimates that its potential exposure would not be material to its results of operations or financial position. This estimate of WGEServices’ exposure to contract termination is based upon acquiring supply, priced at forward electricity prices through the expiration of the existing sales contracts. The actual exposure for WGEServices may differ from the estimate due to the timing of contract terminations, deviations from normal weather, changes in future market conditions or other factors.
     In October 2003, WGEServices and MAEM signed a post-bankruptcy petition contract that enables WGEServices to renew expiring contracts with its current electric customers and to make purchases for new customers. These post-bankruptcy petition contracts include provisions that allow WGEServices to net payables to MAEM against any damages that might result from default on the part of MAEM, and allow WGEServices to request collateral under certain situations.
     WGEServices has made efforts to reduce its reliance on a single supplier. In addition to MAEM, WGEServices has separate master purchase and sale agreements under which it purchases full requirements services from other wholesale electricity suppliers. These electric suppliers either have investment grade credit ratings or provide guarantees from companies with investment grade credit ratings. Electric suppliers other than MAEM accounted for less than ten percent of WGEServices’ full requirements electric purchases for the nine months ended June 30, 2005.
     Non-Full Requirements Supply. In order to improve its competitive position and to further diversify its electricity supply sources, commencing in the third quarter of fiscal year 2005, WGEServices began procuring electricity supply under contract structures other than full requirements contracts. WGEServices is assembling the various components of supply, including electric energy, capacity, ancillary services and transmission service from multiple suppliers to match its customer

44


 

WGL Holdings, Inc.
Part I — Financial Information
Item 2 — Management’s Discussion and Analysis of
Financial Condition and Results of Operations (continued)
requirements. In addition to improving its competitive position, this new strategy reduces the potential credit exposure that WGEServices otherwise faced when dealing almost exclusively with MAEM.
     In purchasing non-full requirements electric services, WGEServices is exposed to price risk to the extent it does not procure electricity at prices that allow for a sufficient gross margin on its retail electric sales commitments. WGEServices’ electric business also is exposed to fluctuations in weather. These non-full requirements purchases generally are made under fixed-volume contracts that are based on certain weather assumptions. If there are significant deviations in weather from these assumptions, WGEServices could be exposed to hourly price and volume risk that negatively impact gross margins. At June 30, 2005, approximately one-half of the WGEServices electric supply portfolio was provided under non-full requirements contracts.
     Value-At-Risk
     WGEServices also measures the market risk of its energy commodity portfolio and employs risk control mechanisms to measure and determine mitigating steps related to market risk, including the determination and review of value-at-risk. Value-at-risk is an estimate of the maximum loss that can be expected at some level of probability if a portfolio is held for a given time period. Based on a 95 percent confidence interval for a one-day holding period, WGEServices’ value-at-risk at June 30, 2005 was approximately $117,000 and $80,000 related to its natural gas portfolio and electric portfolio, respectively. WGEServices also calculates the value of its open position related to natural gas and electric, which measures the amount of additional transactions that would be required to close the volumetric differential between its purchase and sales commitments. As of June 30, 2005, WGEServices would have had to increase its forward purchase commitments by approximately $3.2 million to close its open position related to natural gas, and increase its sales commitments by approximately $1.8 million to close its open position related to its electric portfolio. WGEServices’ value-at-risk and value of open position calculations related to its electric portfolio result from WGEServices’ new procurement strategy for purchasing non-full requirements electric services as discussed above.
     Interest-Rate Risk
     The Company is exposed to interest-rate risk associated with its debt financing costs. The Company utilizes derivative financial instruments from time to time in order to minimize its exposure to interest-rate risk.
     In September 2004, Washington Gas entered into two forward-starting swaps with an aggregate notional principal amount of $60.5 million. These swaps were intended to mitigate a substantial portion of the risk of rising interest rates associated with anticipated future debt issuances and will terminate concurrent with the execution of these debt issuances. The forward-starting swaps were designated as cash flow hedges in accordance with Statement of Financial Accounting Standard No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended, and are carried at fair value. At June 30, 2005 and September 30, 2004, these swaps had a fair value loss totaling $5.3 million and $475,000, respectively. Concurrent with the decision to sell $20.0 million of 4.83 percent MTNs on August 4, 2005, Washington Gas agreed to terminate $20.0 million of the total $60.5 million aggregate notional principal amount of the forward-starting swaps discussed above. Washington Gas is expected to pay $364,000 on August 9, 2005 associated with the settlement of this hedge agreement. Similarly, concurrent with the decision to sell $40.5 million of 5.44 percent MTNs on August 8, 2005, Washington Gas agreed to terminate the remaining $40.5 million notional principal amount of the forward-starting swaps. Washington Gas is expected to pay $2.2 million on August 11, 2005 associated with the settlement of this hedge agreement. Refer to the “Liquidity and Capital Resources—Long-Term Cash Requirements and Related Financing” section of Management’s Discussion. Also refer to Note 7 of the Notes to Consolidated Financing Statements—Derivative Instruments for a further discussion of the accounting for these transactions.

45


 

WGL Holdings, Inc.
Part I — Financial Information
Item 2 — Management’s Discussion and Analysis of
Financial Condition and Results of Operations (continued)
     In July 2005, Washington Gas entered into two forward-starting swaps with an aggregate notional principal amount of $50.0 million. These swaps are intended to mitigate a substantial portion of the risk of rising interest rates associated with anticipated future debt issuances, and are scheduled to terminate concurrent with the execution of these debt issuances that are planned for May 2006.
     As discussed in this report, the Company and Washington Gas utilize commercial paper to satisfy short-term borrowing requirements. Short-term interest rates had been relatively low in relation to historical levels. Actions and communications by the Federal Reserve in the past year, however, have resulted in increases in short-term interest rates and have signaled a likely continuation of these increases. Increases in short-term interest rates may reduce the profitability of the Company and Washington Gas to the extent those higher interest rates are not timely reflected in utility rates or the prices charged by WGEServices.
     OTHER MATTERS
     WGL Holdings, Inc. is a registered holding company as defined by the Public Utilities Holding Company Act of 1935 (PUHCA). On August 8, 2005, the President of the United States of America signed the Energy Policy Act of 2005 (EPA 2005), which adopts many broad energy policy provisions including significant funding for consumers and business for energy related activities, energy related tax credits, accelerated depreciation for certain natural gas utility infrastructure investments and which contains the repeal of the PUHCA. The Company continues to evaluate the EPA 2005 but it expects to benefit from several provisions embedded in the legislation that will support the Company’s efforts to promote energy efficiency in a manner that supports customers and shareholders.

46


 

Washington Gas Light Company
Part I – Financial Information
Item 2 – Management’s Discussion and Analysis of
Financial Condition and Results of Operations (continued)
WASHINGTON GAS LIGHT COMPANY
     This section of Management’s Discussion focuses on the financial position and results of operations of Washington Gas for the reported periods. In many cases, explanations for the changes in financial position and results of operations for both WGL Holdings and Washington Gas are substantially the same.
     RESULTS OF OPERATIONS Three Months Ended June 30, 2005 vs. June 30, 2004
     Summary Results
     Washington Gas reported a seasonal net loss applicable to common stock of $11.0 million for the three months ended June 30, 2005 as compared to a net loss of $4.2 million for the same period of the prior fiscal year.
     Utility Net Revenues
     Net revenues for Washington Gas were $88.1 million for the current quarter, as compared to net revenues of $88.7 million for the same quarter in fiscal year 2004. Net revenues for the third quarter of fiscal year 2005 were favorably affected by the addition of 23,336 active customer meters, an increase of 2.4 percent, from the end of the comparable quarter of the prior fiscal year. This growth was more than offset by the effect of a Virginia rate increase that was in effect in the prior year’s third quarter but that was not in effect in the third quarter of the current fiscal year. As further discussed below, weather had a negligible effect on operating results for both the current and prior fiscal year’s third quarter. Key gas delivery, weather and meter statistics are shown in the table below for the three months ended June 30, 2005 and 2004.
                                 
Gas Deliveries, Weather and Meter Statistics  
    Three Months Ended             Percent  
    June 30,             Increase  
    2005     2004     Variance     (Decrease)  
 
Gas Sales and Deliveries (thousands of therms)
                               
Firm
                               
Gas Sold and Delivered
    104,036       99,571       4,465       4.5  
Gas Delivered for Others
    63,562       65,377       (1,815 )     (2.8 )
 
Total Firm
    167,598       164,948       2,650       1.6  
 
Interruptible
                               
Gas Sold and Delivered
    1,771       1,388       383       27.6  
Gas Delivered for Others
    53,061       53,772       (711 )     (1.3 )
 
Total Interruptible
    54,832       55,160       (328 )     (0.6 )
 
Electric Generation—Delivered for Others
    16,370       9,823       6,547       66.7  
 
Total Deliveries
    238,800       229,931       8,869       3.9  
 
Degree Days
                               
Actual
    365       301       64       21.3  
Normal
    306       303       3       1.0  
Percent Colder Than Normal
    19.3 %     (0.7 )%     n/a       n/a  
Active Customer Meters (end of period)
    1,010,272       986,936       23,336       2.4  
New Customer Meters Added
    5,637       6,871       (1,234 )     (18.0 )
 

47


 

Washington Gas Light Company
Part I – Financial Information
Item 2 – Management’s Discussion and Analysis of
Financial Condition and Results of Operations (continued)
     Gas Service to Firm Customers. The level of gas delivered to firm customers is highly sensitive to weather variability as a large portion of the natural gas delivered by Washington Gas is used for space heating. The regulated utility’s rates are based on normal weather, and none of the tariffs for the jurisdictions in which it operates currently has a weather normalization provision (refer to the “Regulatory Matters” section of Management’s Discussion). Nonetheless, declining block rates in the regulated utility’s Maryland and Virginia jurisdictions, and the existence of a fixed demand charge in all jurisdictions to collect a portion of revenues, reduce the effect that variations from normal weather have on net revenues.
     During the quarter ended June 30, 2005, firm therm deliveries increased 2.7 million therms, or 1.6 percent, to 167.6 million therms delivered during the third quarter of fiscal year 2005. However, weather was 21.3 percent colder in the current quarter than in the same quarter last fiscal year. As such, there was a low correlation between the 1.6 percent increase in firm therm deliveries and the 21.3 percent colder weather during the current quarter. Given that quarters ending on June 30 include shoulder months in which the Company is coming out of the primary portion of its winter heating season, weather patterns may become erratic and some space-heating customers may turn off their furnaces for the remainder of the heating season upon the first significant rise in temperatures. Thus, usage patterns may not highly correlate with the level of degree days in periods that include shoulder months.
     Many customers choose to buy the natural gas commodity from third-party marketers, rather than purchase the natural gas commodity and delivery service from Washington Gas on a “bundled” basis. Gas delivered to firm customers but purchased from third-party marketers represented 37.9 percent of total firm therms delivered during the quarter ended June 30, 2005, compared to 39.6 percent delivered during the quarter ended June 30, 2004. On a per unit basis, Washington Gas earns the same net revenues from delivering gas for others as it earns from bundled gas sales in which customers purchase both the natural gas commodity and the associated delivery service from Washington Gas. Therefore, the regulated utility does not experience any loss in net revenues when customers choose to purchase the natural gas commodity from a third-party marketer.
     Gas Service to Interruptible Customers. Washington Gas must curtail or interrupt service to this class of customers when the demand by firm customers exceeds specified levels. Therm deliveries to interruptible customers during the third quarter of fiscal year 2005 were relatively unchanged when compared to the same quarter of the last fiscal year.
     The effect on net income of any changes in delivered volumes and prices to the interruptible class is limited by margin-sharing arrangements that are included in Washington Gas’ rate designs. Under these arrangements, except as noted below as it relates to Virginia operations, Washington Gas shares a majority of the margins earned on interruptible gas sales and deliveries with firm customers after a gross margin threshold is reached. A portion of the fixed costs for servicing interruptible customers is collected through the firm customers’ rate design. In the Virginia jurisdiction, rates for customers using interruptible delivery service are based on a traditional cost of service approach, and Washington Gas retains all revenues from interruptible delivery service. However, for a few customers who have been grandfathered into a previously approved bundled interruptible rate design, there is some sharing of those revenues with firm customers but the volumes are small and the amounts of revenues are not material to the financial statements or results of operations.
     Gas Service for Electric Generation. Washington Gas sells and/or delivers natural gas for use at two electric generation facilities in Maryland that are each owned by companies independent of WGL Holdings. During the current quarter, deliveries to these customers increased 66.7 percent to 16.4 million therms, reflecting the increased use by these customers of natural gas primarily due to the higher price of alternative fuels. Washington Gas shares a significant majority of the margins earned

48


 

Washington Gas Light Company
Part I – Financial Information
Item 2 – Management’s Discussion and Analysis of
Financial Condition and Results of Operations (continued)
from gas deliveries to these customers with firm customers. Therefore, changes in the volume of interruptible gas deliveries to these customers do not materially affect either net revenues or net income.
     Utility Operating Expenses
     Operation and Maintenance Expenses. Operation and maintenance expenses of $62.5 million for the three months ended June 30, 2005 were $4.8 million, or 8.4 percent, higher than the same period in the prior fiscal year. This increase primarily reflects: (i) higher labor expenses; (ii) increased employee benefits expenses principally related to post-retirement benefits and group insurance costs for active employees; (iii) greater expenses associated with performing the initial assessment of internal controls in accordance with Section 404 of the Sarbanes-Oxley Act and (iv) higher expenses for uncollectible accounts. Higher labor expenses during the current quarter were due in part to increased overtime incurred in connection with the response to issues that arose in a portion of the Company’s distribution system in Prince George’s County, Maryland such as special leak surveys, emergency response site visits and repairs. The increase in labor expenses for the current quarter were tempered by fewer employees, reduced employee severance costs, and the inclusion in the third quarter of fiscal year 2004 of an accrual of $2.4 million for unusual operational expenses that did not recur in the current quarter.
     Depreciation and Amortization. Depreciation and amortization expense was $22.5 million for the third quarter of fiscal year 2005, an increase of $1.7 million, or 8.2 percent, from the same quarter of the prior fiscal year. Of this increase, $1.3 million relates to a reduction in deprecation expense in the third quarter of fiscal year 2004 in connection with implementing a Maryland rate order.
     Income Tax Benefits. Income tax benefits were enhanced in the current quarter due to a higher pre-tax loss. However, much of this effect was offset by a higher estimated annual effective income tax rate.
     Interest Expense
     The explanations for changes in Washington Gas’ interest expense are substantially the same as the explanations included in Management’s Discussion for WGL Holdings. Those explanations are incorporated herein by reference into this discussion.
     RESULTS OF OPERATIONS Nine Months Ended June 30, 2005 vs. June 30, 2004
     Summary Results
     For the first nine months of fiscal year 2005, Washington Gas reported net income applicable to common stock of $103.6 million, as compared to net income of $106.8 million for the same period of the prior fiscal year.
     Utility Net Revenues
     Net revenues for Washington Gas were $478.3 million for the current nine-month period, as compared to net revenues of $482.6 million for the corresponding period in the prior fiscal year. Revenues for the current nine-month period primarily reflect lower natural gas deliveries to firm customers despite the fact that weather was relatively unchanged for the nine months ended June 30, 2005 when compared to the same period in fiscal year 2004, as further discussed below. Favorably contributing to net revenues for the current nine-month period was a 2.4 percent increase in active

49


 

Washington Gas Light Company
Part I – Financial Information
Item 2 – Management’s Discussion and Analysis of
Financial Condition and Results of Operations (continued)
customer meters, coupled with the favorable effect of changes in rates charged to customers that were implemented in Maryland on November 6, 2003 and the District of Columbia on November 24, 2003. This benefit was mostly offset by the impact of an anticipated Virginia rate increase that went into effect on February 26, 2004, subject to refund, and was included in net revenues for the nine months ended June 30, 2004, but that was not in effect during the nine months ended June 30, 2005 as a result of a Virginia rate order issued after June 30, 2004 (refer to the “Regulatory Matters—Virginia Jurisdiction” section of Management’s Discussion for Washington Gas). Key gas delivery, weather and meter statistics are shown in the table below for the nine months ended June 30, 2005 and 2004.
                                 
Gas Deliveries, Weather and Meter Statistics  
    Nine Months Ended             Percent  
    June 30,             Increase  
    2005     2004     Variance     (Decrease)  
 
Gas Sales and Deliveries (thousands of therms)
                               
Firm
                               
Gas Sold and Delivered
    793,108       798,357       (5,249 )     (0.7 )
Gas Delivered for Others
    395,947       418,188       (22,241 )     (5.3 )
 
Total Firm
    1,189,055       1,216,545       (27,490 )     (2.3 )
 
Interruptible
                               
Gas Sold and Delivered
    6,340       6,362       (22 )     (0.3 )
Gas Delivered for Others
    230,501       221,056       9,445       4.3  
 
Total Interruptible
    236,841       227,418       9,423       4.1  
 
Electric Generation—Delivered for Others
    34,879       31,540       3,339       10.6  
 
Total Deliveries
    1,460,775       1,475,503       (14,728 )     (1.0 )
 
Degree Days
                               
Actual
    4,018       4,017       1        
Normal
    3,782       3,775       7       0.2  
Percent Colder Than Normal
    6.2 %     6.4 %     n/a       n/a  
Active Customer Meters (end of period)
    1,010,272       986,936       23,336       2.4  
New Customer Meters Added
    19,936       22,752       (2,816 )     (12.4 )
 
     Gas Service to Firm Customers. During the nine months ended June 30, 2005, total gas deliveries to firm customers were 1.189 billion therms, a decrease of 27.5 million therms, or 2.3 percent, in deliveries from the same period last year. Although heating degree days were relatively unchanged, natural gas deliveries declined by 2.3 percent. Weather for the nine months ended June 30, 2005 was 6.2 percent colder than normal, as compared to 6.4 percent colder than normal for the same period last year. The decrease in natural gas deliveries to firm customers is due, in part, to warmer weather experienced primarily during the second quarter of fiscal year 2005, the most significant period of the Company’s winter-heating season. However, during the current nine-month period (particularly in the shoulder months of October and November within the first quarter, and the shoulder months of April and May within the third quarter), Washington Gas experienced lower natural gas deliveries because the increase in heating degree days did not correlate highly with the change in the volume of gas delivered.
     Gas Service to Interruptible Customers. Therm deliveries to interruptible customers increased 4.1 percent during the first nine months of fiscal year 2005 when compared to the same period last fiscal year, primarily reflecting a reduction in the curtailment of interruptible service due to warmer weather in the second quarter of the current fiscal year.
     Gas Service for Electric Generation. During the current nine-month period, deliveries to the two

50


 

Washington Gas Light Company
Part I – Financial Information
Item 2 – Management’s Discussion and Analysis of
Financial Condition and Results of Operations (continued)
electric generation facilities in Maryland increased 10.6 percent to 34.9 million therms, reflecting the increased use by these customers of natural gas primarily due to the higher price of alternative fuels.
     Utility Operating Expenses
     Operation and Maintenance Expenses . Operation and maintenance expenses of $178.7 million for the first nine months of fiscal year 2005 were $3.9 million, or 2.2 percent, higher than the same period last year. The increased expenses primarily reflect: (i) higher employee benefits expenses principally related to post-retirement benefits and group insurance costs for active employees; (ii) increased overtime associated with work being performed in Prince George’s County, Maryland; (iii) higher expenses associated with performing the initial assessment of internal controls in accordance with Section 404 of the Sarbanes-Oxley Act and (iv) higher expenses for uncollectible accounts. These increased expenses were partially offset by fewer employees, reduced employee severance costs, and an accrual of $2.4 million recorded in the 2004 nine-month period for unusual operational expenses that were not incurred in the current nine-month period.
     Depreciation and Amortization. Depreciation and amortization expense was $65.7 million for the current nine-month period, a decrease of $2.9 million, or 4.2 percent, from the same period of the prior fiscal year. The lower expense is attributable to a reversal in the current nine-month period of $1.0 million of depreciation expense that was previously estimated and recorded in fiscal year 2004 related to the performance of an earnings test required by the SCC of VA’s December 18, 2003 Final Order. The year-over-year reduction in expense is also due to the inclusion in the first nine months of fiscal year 2004 of depreciation expense of $3.5 million (pre-tax) applicable to a prior period pursuant to the SCC of VA’s December 18, 2003 Virginia Final Order. This was partially offset by an increase in depreciation and amortization expense in the current nine-month period primarily related to increased investment in property, plant and equipment.
     Income Taxes. The regulated utility also benefited during the current year-to-date period from reduced income tax expense due to a lower pre-tax income, as well as a lower estimated annual effective income tax rate (primarily attributable to a greater amount of non-taxable benefits associated with a Medicare prescription drug subsidy).
     Interest Expense
     The explanations for changes in Washington Gas’ interest expense are substantially the same as the explanations included in the Management’s Discussion for WGL Holdings. Those explanations are incorporated herein by reference into this discussion.
     LIQUIDITY AND CAPITAL RESOURCES
     Liquidity and capital resources for Washington Gas are substantially the same as the liquidity and capital resources discussion included in the Management’s Discussion for WGL Holdings (except for certain items and transactions that pertain to WGL Holdings and its unregulated subsidiaries) that, therefore, are incorporated herein by reference into this discussion.
     REGULATORY MATTERS
     Washington Gas’ operating results for the nine months ended June 30, 2005, when compared to the same period of the prior fiscal year, benefited from the effect of favorable regulatory decisions that were implemented in Maryland on November 6, 2003 and the District of Columbia on November 24, 2003. This benefit was mostly offset by the impact of an anticipated Virginia rate increase that was

51


 

Washington Gas Light Company
Part I – Financial Information
Item 2 – Management’s Discussion and Analysis of
Financial Condition and Results of Operations (continued)
included in operating results for the first nine months of fiscal year 2004, but that was not in effect during the current nine-month period. Certain regulatory matters in the Maryland and Virginia jurisdictions are discussed below. For a further discussion of regulatory matters in all jurisdictions, refer to the Company’s fiscal year 2004 Annual Report on Form 10-K.
     Maryland Jurisdiction
     In the “Contractual Obligations, Off-Balance Sheet Arrangements and Other Commercial Commitments” section of Management’s Discussion for WGL Holdings, there is a substantial discussion of issues related to Prince George’s County, Maryland. The following description of an Accounting Order issued by the PSC of MD must be considered in conjunction with the entire context of these matters as described in the above-referenced section of Management’s Discussion.
     On April 28, 2005, Washington Gas filed a request for an Accounting Order with the PSC of MD in connection with the rehabilitation project to be performed in Prince George’s County, Maryland to address natural gas leaks (refer to the “Liquidity and Capital Resources—Contractual Obligations, Off-Balance Sheet Arrangements and Other Commercial Commitments” section of Management’s Discussion for WGL Holdings). Pursuant to this filing, Washington Gas specifically requested that the PSC of MD issue an Accounting Order to ratify Washington Gas’ interpretation of the applicable regulatory guidelines regarding the accounting treatment of the estimated $13 million of costs of encapsulating couplings on mains in the affected areas of Prince George’s County which, according to Washington Gas’ interpretation, should be recorded as capital expenditures. After considering this matter at the June 1, 2005 Administrative Meeting of the PSC of MD, the PSC of MD granted Washington Gas’ request for an Accounting Order with the understanding that the accounting treatment will not be determinative of ratemaking treatment, and the PSC of MD retains jurisdiction to adopt any ratemaking treatment it deems appropriate.
     On July 6, 2005, a Hearing Examiner of the PSC of MD issued a Proposed Order to accept an Unopposed Stipulation and Agreement (Stipulation), filed by Washington Gas and three other participants with the PSC of MD on May 18, 2005. On August 8, 2005, the Unopposed Stipulation and Agreement included in the Proposed Order became final. The Stipulation resolves outstanding issues from a Final Order issued by the PSC of MD on October 31, 2003, regarding the manner in which interruptible transportation service is charged to Maryland customers. The Stipulation also requests approval by the PSC of MD of a revenue normalization adjustment (RNA) mechanism, a billing adjustment mechanism that is designed to stabilize the level of distribution charge revenues received from customers. It generally moderates factors that influence the volatility of customers’ bills each month, the largest being the effect of weather on customer usage. The Stipulation also allows for the impact of the RNA on Washington Gas’ risk and rate of return to be evaluated in the next rate case. The RNA becomes effective on October 1, 2005.
     Virginia Jurisdiction
     On December 18, 2003, the SCC of VA issued a Final Order in response to an application filed by Washington Gas on June 14, 2002 to increase annual revenues in Virginia. The Final Order granted Washington Gas an increase in annual revenues of $9.9 million, reflecting an allowed rate of return on common equity of 10.50 percent and an overall rate of return of 8.44 percent. In the Final Order, the SCC of VA ordered that the implementation date of new depreciation rates should be January 1, 2002, as opposed to November 12, 2002, as originally requested and implemented by Washington Gas. This required Washington Gas to record additional depreciation expense in the quarter ended December 31, 2003 of approximately $3.5 million, on a pre-tax basis, that related to the period from January 1, 2002 through November 11, 2002.

52


 

Washington Gas Light Company
Part I – Financial Information
Item 2 – Management’s Discussion and Analysis of
Financial Condition and Results of Operations (continued)
     The SCC of VA also ordered Washington Gas to reduce its rate base related to net utility plant by $28 million, which is net of accumulated deferred income taxes of $14 million, and to establish an equivalent regulatory asset that the Company has done for regulatory accounting purposes only. This regulatory asset represents the difference between the accumulated reserve for depreciation recorded on the books of Washington Gas and a theoretical reserve that was derived by the Staff of the SCC of VA (VA Staff) as part of its review of Washington Gas’ depreciation rates, less accumulated deferred income taxes. This regulatory asset is being amortized, for regulatory accounting purposes only, as a component of depreciation expense over 32 years pursuant to the Final Order. The SCC of VA provided for both a return on, and a return of, this regulatory asset established for regulatory accounting purposes.
     In approving the treatment described in the preceding paragraph, the SCC of VA further ordered that an annual “earnings test” be performed to determine if Washington Gas has earned in excess of its allowed rate of return on common equity for its Virginia operations. The current procedure for performing this earnings test does not normalize the actual return on equity for the effect of weather over the applicable twelve-month period. To the extent that Washington Gas earns in excess of its allowed return on equity in any annual earnings test period, Washington Gas is required to increase depreciation expense (after considering the impact of income tax benefits) and increase the accumulated reserve for depreciation for the amount of the actual earnings in excess of the earnings produced by the 10.50 percent allowed return on equity. Under the SCC of VA’s requirements for performing earnings tests, if weather is warmer than normal in a particular annual earnings test period, Washington Gas is not allowed to restore any amount of earnings previously eliminated as a result of this earnings test. These annual earnings tests will continue to be performed until the $28 million difference between the accumulated reserve for depreciation recorded on Washington Gas’ books and the theoretical reserve derived by the VA Staff, net of accumulated deferred income taxes, is eliminated or the level of the regulatory asset established for regulatory accounting purposes is adjusted as a result of a future depreciation study. On March 17, 2005, the VA Staff filed a report with the SCC of VA in connection with Washington Gas’ earnings test for the twelve-month period ended December 31, 2003. The VA Staff’s report concluded that Washington Gas did not earn in excess of its allowed return on equity during this period, and recommended that Washington Gas not be required to record any additional depreciation expense related to its earnings for the twelve-month period ended December 31, 2003. On April 26, 2005, the SCC of VA issued an Order that concurred with the VA Staff’s recommendation. As a result, Washington Gas reversed $1.0 million of depreciation expense, on a pre-tax basis, in the nine months ended June 30, 2005 that had been previously recorded in fiscal year 2004 related to this earnings test.
     On January 27, 2004, Washington Gas filed an expedited rate case with the SCC of VA to increase annual revenues in Virginia by $19.6 million, with an overall rate of return of 8.70 percent and a 10.50 percent return on equity. On February 26, 2004, based upon expedited rate case filing procedures, Washington Gas placed the proposed revenue increase into effect, subject to refund, pending the SCC of VA’s final decision in the proceeding.
     On September 27, 2004, the SCC of VA issued a Final Order approving a Stipulation that resolved all issues related to Washington Gas’ January 27, 2004 expedited rate case application filed with the SCC of VA. The Stipulation ordered no change in Washington Gas’ annual base revenues, and for Washington Gas to maintain its allowed rate of return on common equity of 10.50 percent and overall rate of return of 8.44 percent that had been approved by the December 18, 2003 Final Order as previously discussed. Accordingly, refunds to customers, with interest, were made during the December 2004 billing cycle for the amount of the proposed annual revenue increase that had been collected since February 26, 2004. Based on the terms of the Stipulation, the Company implemented billing rates commencing October 4, 2004 that reflected the level of annual revenues determined in

53


 

Washington Gas Light Company
Part I – Financial Information
Item 2 – Management’s Discussion and Analysis of
Financial Condition and Results of Operations (concluded)
the December 18, 2003 Final Order, and implemented the agreed upon changes in rate design that were contained in the Stipulation.
     The Stipulation also provided for a one-time credit to all Virginia customers of $3.2 million for certain liabilities that were previously recorded by Washington Gas. This one-time credit was made to customers during the January 2005 billing cycle. Providing this credit to customers did not have an effect on the earnings of the Company or Washington Gas in the three or nine months ended June 30, 2005. The Stipulation also required Washington Gas to file with the SCC of VA annual earnings test calculations based on a twelve-month period ended December 31; such calculations are being estimated by the Company quarterly, and when appropriate, accounting adjustments are being recorded.
     On January 31, 2005, Washington Gas filed a proposed Weather Normalization Adjustment clause (WNA) with the SCC of VA to be implemented as an experimental pilot program. If approved by the SCC of VA, the WNA is intended to reduce the effect of weather volatility both on customers’ bills and on the Company’s earnings. The proposed implementation date of the WNA by Washington Gas is January 1, 2006, with the first adjustments to customer bills proposed to occur in the first quarter of fiscal year 2007. On April 14, 2005, the Board of Supervisors of Fairfax County, Virginia filed testimony in response to the proposed WNA, recommending that Washington Gas’ proposal as an experimental pilot program be denied, and that Washington Gas re-file its request for a WNA as part of a normal rate review proceeding that would also reflect an appropriate reduction in Washington Gas’ allowed return on common equity in consideration for its reduced business risk that is expected to result from implementing the WNA. On April 29, 2005, the Apartment and Office Building Association of Metropolitan Washington (AOBA) and the Division of Consumer Counsel of the Office of the Attorney General of Virginia (Consumer Counsel) filed testimony opposing the proposed WNA. AOBA recommended, among other things, that Washington Gas not be permitted to implement the WNA as an experimental program, and that adjustments be made to reduce Washington Gas’ allowed return on common equity and base rates to reflect its reduced business risk. In its testimony, Consumer Counsel claimed, among other things, that the proposed WNA would provide significant benefits to Washington Gas with very limited benefits to customers. The Staff of the SCC of VA filed testimony opposing the WNA on May 16, 2005, and Washington Gas filed rebuttal testimony on June 2, 2005. Public hearings occurred on June 9-10, 2005 and post-hearing briefs are due on August 10, 2005.

54


 

WGL Holdings, Inc.
Washington Gas Light Company

Part I – Financial Information
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
     The following issues related to the Company’s market risk are included under Item 2, Management’s Discussion and Analysis of Financial Condition and Results of Operations, and are incorporated herein by reference into this discussion. Also refer to Item 7A in the Company’s 2004 Annual Report on Form 10-K.
  Price Risk Related to Regulated Utility Operations
 
  Price Risk Related to Retail Energy-Marketing Operations
 
  Interest-Rate Risk
ITEM 4. CONTROLS AND PROCEDURES
     Senior management, including the Chairman and Chief Executive Officer and the Vice President and Chief Financial Officer, evaluated the effectiveness of WGL Holdings’ and Washington Gas’ disclosure controls and procedures as of June 30, 2005. Based on this evaluation process, the Chairman and Chief Executive Officer and the Vice President and Chief Financial Officer have concluded that WGL Holdings’ and Washington Gas’ disclosure controls and procedures are effective. There have been no changes in the Registrants’ internal control over financial reporting during the quarter ended June 30, 2005 that have materially affected, or are reasonably likely to materially affect, the registrants’ internal control over financial reporting.

55


 

WGL Holdings, Inc.
Washington Gas Light Company

Part II – Other Information
PART II. OTHER INFORMATION
ITEM 6. EXHIBITS
Exhibits:
     
23
  Consent of ENVIRON International Corporation.
 
   
31.1
  Certification of James H. DeGraffenreidt, Jr., the Chairman and Chief Executive Officer of WGL Holdings, Inc., pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
 
   
31.2
  Certification of Frederic M. Kline, the Vice President and Chief Financial Officer of WGL Holdings, Inc., pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
 
   
31.3
  Certification of James H. DeGraffenreidt, Jr., the Chairman and Chief Executive Officer of Washington Gas Light Company, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
 
   
31.4
  Certification of Frederic M. Kline, the Vice President and Chief Financial Officer of Washington Gas Light Company, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
 
   
32.1
  Certification of James H. DeGraffenreidt, Jr., the Chairman and Chief Executive Officer, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
 
   
32.2
  Certification of Frederic M. Kline, the Vice President and Chief Financial Officer, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
 
   
99.1
  Computation of Ratio of Earnings to Fixed Charges—WGL Holdings, Inc.
 
   
99.2
  Computation of Ratio of Earnings to Fixed Charges and Preferred Stock Dividends—WGL Holdings, Inc.
 
   
99.3
  Computation of Ratio of Earnings to Fixed Charges—Washington Gas Light Company.
 
   
99.4
  Computation of Ratio of Earnings to Fixed Charges and Preferred Stock Dividends—Washington Gas Light Company.
 
   
99.5
  Report of ENVIRON International Corporation dated July 1, 2005.

56


 

WGL Holdings, Inc.
Washington Gas Light Company
Signature
Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrants have duly caused this report to be signed on their behalf by the undersigned, thereunto duly authorized.
         
 
  WGL HOLDINGS, INC.    
 
       
 
  and    
 
       
 
  WASHINGTON GAS LIGHT COMPANY    
 
  (Co-Registrants)    
 
       
 
       
Date:           August 9, 2005          
  /s/ Mark P. O’Flynn    
 
  Mark P. O’Flynn    
 
  Controller    
 
  (Principal Accounting Officer)    

57

exv23
 

Exhibit 23
CONSENT OF ENVIRON INTERNATIONAL CORPORATION
     Environ International Corporation hereby consents to the incorporation by reference in the Registration Statements on Form S-8 (“333-104571”, “333-104572”, “333-104573”) and on Form S-3 (“333-61199”) and (“333-126620”) of WGL Holdings Inc. and the Registration Statement on Form S-3 (“333-104574”) of Washington Gas Light Company of the reference to us and our report under the caption “Item II. — Management’s Discussion and Analysis of Financial Condition and Results of Operations” appearing in the Quarterly Report on Form 10-Q of Washington Gas Light Company and of WGL Holdings, Inc. for the quarter ended June 30, 2005.
         
 
  Respectfully submitted,    
 
       
 
  /s/ Roberto Pellizzari         
 
  Name: Roberto Pellizzari    
 
  Title: Principal    
Date: 8/5/2005

 

exv31w1
 

Exhibit 31.1
CERTIFICATION OF WGL HOLDINGS, INC.
I, James H. DeGraffenreidt, Jr., certify that:
1.   I have reviewed this quarterly report on Form 10-Q of WGL Holdings, Inc. and Washington Gas Light Company;
 
2.   Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
 
3.   Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
 
4.   The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:
  a)   Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
 
  b)   Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
 
  c)   Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.   The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors:
  a)   All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
 
  b)   Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
Date: August 8, 2005
/s/ James H. DeGraffenreidt, Jr.
James H. DeGraffenreidt, Jr.
Chairman and Chief Executive Officer

 

exv31w2
 

Exhibit 31.2
CERTIFICATION OF WGL HOLDINGS, INC.
I, Frederic M. Kline, certify that:
1.   I have reviewed this quarterly report on Form 10-Q of WGL Holdings, Inc. and Washington Gas Light Company;
 
2.   Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
 
3.   Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
 
4.   The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:
  a)   Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
 
  b)   Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
 
  c)   Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.   The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors:
  a)   All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
 
  b)   Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
Date: August 9, 2005
/s/ Frederic M. Kline
Frederic M. Kline
Vice President and Chief Financial Officer

 

exv31w3
 

Exhibit 31.3
CERTIFICATION OF WASHINGTON GAS LIGHT COMPANY
I, James H. DeGraffenreidt, Jr., certify that:
1.   I have reviewed this quarterly report on Form 10-Q of WGL Holdings, Inc. and Washington Gas Light Company;
 
2.   Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
 
3.   Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
 
4.   The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:
  a)   Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
 
  b)   Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
 
  c)   Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.   The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors:
  a)   All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
 
  b)   Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
Date: August 8, 2005
/s/ James H. DeGraffenreidt, Jr.
James H. DeGraffenreidt, Jr.
Chairman and Chief Executive Officer

 

exv31w4
 

Exhibit 31.4
CERTIFICATION OF WASHINGTON GAS LIGHT COMPANY
I, Frederic M. Kline, certify that:
1.   I have reviewed this quarterly report on Form 10-Q of WGL Holdings, Inc. and Washington Gas Light Company;
 
2.   Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
 
3.   Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
 
4.   The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:
  a)   Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
 
  b)   Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
 
  c)   Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.   The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors:
  a)   All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
 
  b)   Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
Date: August 9, 2005
/s/ Frederic M. Kline
Frederic M. Kline
Vice President and Chief Financial Officer

 

exv32w1
 

Exhibit 32.1
CERTIFICATION OF THE CHAIRMAN AND CHIEF EXECUTIVE OFFICER
PURSUANT TO 18 U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
     In connection with the combined Quarterly Report of WGL Holdings, Inc. and Washington Gas Light Company (the “Companies”) on Form 10-Q for the quarterly period ended June 30, 2005 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), James H. DeGraffenreidt, Jr., Chairman and Chief Executive Officer of the Companies, hereby certifies, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, to the best of his knowledge, that:
  (1)   The Report fully complies with the requirements of Section 13(a) of the Securities Exchange Act of 1934; and
 
  (2)   The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Companies.
     This certification is being made for the exclusive purpose of compliance by the Chairman and Chief Executive Officer of the Companies with the requirements of Section 906 of the Sarbanes-Oxley Act of 2002, and may not be disclosed, distributed, or used by any person for any reason other than as specifically required by law.
/s/ James H. DeGraffenreidt, Jr.
James H. DeGraffenreidt, Jr.
Chairman and Chief Executive Officer
August 8, 2005

 

exv32w2
 

Exhibit 32.2
CERTIFICATION OF THE VICE PRESIDENT AND CHIEF FINANCIAL OFFICER
PURSUANT TO 18 U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
     In connection with the combined Quarterly Report of WGL Holdings, Inc. and Washington Gas Light Company (the “Companies”) on Form 10-Q for the quarterly period ended June 30, 2005 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), Frederic M. Kline, Vice President and Chief Financial Officer of the Companies, hereby certifies, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, to the best of his knowledge, that:
  (1)   The Report fully complies with the requirements of Section 13(a) of the Securities Exchange Act of 1934; and
 
  (2)   The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Companies.
     This certification is being made for the exclusive purpose of compliance by the Vice President and Chief Financial Officer of the Companies with the requirements of Section 906 of the Sarbanes-Oxley Act of 2002, and may not be disclosed, distributed, or used by any person for any reason other than as specifically required by law.
/s/ Frederic M. Kline
Frederic M. Kline
Vice President and Chief Financial Officer
August 9, 2005

 

exv99w1
 

Exhibit 99.1
WGL HOLDINGS, INC. AND SUBSIDIARIES
Computation of Ratio of Earnings to Fixed Charges (Unaudited)
($ in thousands)
Twelve Months Ended June 30, 2005
         
FIXED CHARGES:
       
Interest Expense
  $ 41,671  
Amortization of Debt Premium, Discount and Expense
    522  
Interest Component of Rentals
    1,256  
 
     
Total Fixed Charges
  $ 43,449  
 
     
 
       
EARNINGS:
       
Net Income before Dividends on Preferred Stock
  $ 98,195  
Add:
       
Income Taxes Applicable to Utility Operating Income
    53,870  
Income Taxes Applicable to Non-Utility Operating Income and Other Income (Expenses)-Net
    7,700  
Total Fixed Charges
    43,449  
 
     
Total Earnings
  $ 203,214  
 
     
 
       
Ratio of Earnings to Fixed Charges
    4.7  
 
     

 

exv99w2
 

Exhibit 99.2
WGL HOLDINGS, INC. AND SUBSIDIARIES
Computation of Ratio of Earnings to Fixed Charges
And Preferred Stock Dividends (Unaudited)
($ in thousands)
Twelve Months Ended June 30, 2005
         
FIXED CHARGES AND PRE-TAX PREFERRED STOCK DIVIDENDS:
       
Preferred Stock Dividends
  $ 1,320  
Effective Income Tax Rate
    0.3854  
Complement of Effective Income Tax Rate (1-Tax Rate)
    0.6146  
Pre-Tax Preferred Stock Dividends
  $ 2,148  
 
     
 
       
FIXED CHARGES:
       
Interest Expense
  $ 41,671  
Amortization of Debt Premium, Discount and Expense
    522  
Interest Component of Rentals
    1,256  
 
     
Total Fixed Charges
    43,449  
Pre-Tax Preferred Stock Dividends
    2,148  
 
     
Total Fixed Charges and Preferred Stock Dividends
  $ 45,597  
 
     
 
       
EARNINGS:
       
Net Income before Dividends on Preferred Stock
  $ 98,195  
Add:
       
Income Taxes Applicable to Utility Operating Income
    53,870  
Income Taxes Applicable to Non-Utility Operating Income and Other Income (Expenses)-Net
    7,700  
Total Fixed Charges
    43,449  
 
     
Total Earnings
  $ 203,214  
 
     
 
       
Ratio of Earnings to Fixed Charges and Preferred Dividends
    4.5  
 
     

 

exv99w3
 

Exhibit 99.3
WASHINGTON GAS LIGHT COMPANY
Computation of Ratio of Earnings to Fixed Charges (Unaudited)
($ in thousands)
Twelve Months Ended June 30, 2005
         
FIXED CHARGES:
       
Interest Expense
  $ 40,152  
Amortization of Debt Premium, Discount and Expense
    522  
Interest Component of Rentals
    968  
 
     
Total Fixed Charges
  $ 41,642  
 
     
 
       
EARNINGS:
       
Net Income before Dividends on Preferred Stock
  $ 93,430  
Add:
       
Income Taxes Applicable to Utility Operating Income
    53,655  
Income Taxes Applicable to Non-Utility Operating Income and Other Income (Expenses)-Net
    (788 )
Total Fixed Charges
    41,642  
 
     
Total Earnings
  $ 187,939  
 
     
 
       
Ratio of Earnings to Fixed Charges
    4.5  
 
     

 

exv99w4
 

Exhibit 99.4
WASHINGTON GAS LIGHT COMPANY
Computation of Ratio of Earnings to Fixed Charges
And Preferred Stock Dividends (Unaudited)
($ in thousands)
Twelve Months Ended June 30, 2005
         
FIXED CHARGES AND PRE-TAX PREFERRED STOCK DIVIDENDS:
       
Preferred Stock Dividends
  $ 1,320  
Effective Income Tax Rate
    0.3614  
Complement of Effective Income Tax Rate (1-Tax Rate)
    0.6386  
Pre-Tax Preferred Stock Dividends
  $ 2,067  
 
     
 
       
FIXED CHARGES:
       
Interest Expense
  $ 40,152  
Amortization of Debt Premium, Discount and Expense
    522  
Interest Component of Rentals
    968  
 
     
Total Fixed Charges
    41,642  
Pre-Tax Preferred Stock Dividends
    2,067  
 
     
Total Fixed Charges and Preferred Stock Dividends
  $ 43,709  
 
     
 
       
EARNINGS:
       
Net Income before Dividends on Preferred Stock
  $ 93,430  
Add:
       
Income Taxes Applicable to Utility Operating Income
    53,655  
Income Taxes Applicable to Non-Utility Operating Income and Other Income (Expenses)-Net
    (788 )
Total Fixed Charges
    41,642  
 
     
Total Earnings
  $ 187,939  
 
     
 
       
Ratio of Earnings to Fixed Charges and Preferred Dividends
    4.3  
 
     

 

exv99w5
 

Exhibit 99.5

Investigation of the Causes of Leaks in Natural Gas Pipeline
Compression Couplings

Report prepared for:

Washington Gas Company
6801 Industrial Road
Springfield, VA 22151

Report prepared by:

ENVIRON International Corporation
274 Main Street
Groton, MA 01450

July 1, 2005

(ENVIRON LOGO)

 


 

DISCLAIMER

     This report has been prepared exclusively for use by Washington Gas and may not be relied upon by any other person or entity without ENVIRON’s express written permission. The conclusions presented in this report represent ENVIRON’s best professional judgment based upon the information available and conditions existing as of the date of the report. In performing its assignment, ENVIRON relied upon publicly available information, information provided by Washington Gas and information provided by third parties. Accordingly, the conclusions in the report are valid only to the extent that the information provided to ENVIRON was accurate and complete.

 


 

Table of Contents

         
Executive Summary
    1  
 
       
1. Introduction & Background
    4  
 
       
2. Possible Causes of Increased Leak Incidents
    7  
2.1 Potential Contributing Factors
    7  
2.2 Working Hypothesis
    13  
 
       
3. Experimental Program
    14  
3.1 Polymer Solutions, Inc. Tests
    14  
3.1.1 Approach
    14  
3.1.2 Test Results
    16  
3.2 Akron Rubber Development Lab Tests
    21  
3.2.1 Approach
    21  
3.2.2 Test Results
    22  
 
       
4. Other Investigations
    25  
4.1 LILCO Experience
    25  
4.2 Ground Movement
    26  
4.3 Historical Data
    28  
 
       
5. Conclusions
    32  

 


 

Executive Summary

In the last two heating seasons, Washington Gas (WG) experienced an unusually high number of leaks in particular areas of their distribution network. The couplings affected include 2 inch and 3/4 inch Dresser Style 90 couplings with styrene butadiene rubber (SBR) elastomer seals and 2 inch and 3/4 inch Normac couplings with nitrile rubber (NBR) elastomer seals. These couplings were installed between approximately 1958 and 1974.

In both seasons, the increased incidence of leaks occurred in Prince Georges County, MD. Based on composition measurements and system gas flow models, the affected region of the WG system was known to be supplied primarily with re-vaporized LNG from the Cove Point terminal. Other parts of the WG network, which did not receive significant amounts of LNG, experienced typical seasonal leak rates. WG commenced distribution of the Cove Point LNG in August 2003. The high incidence of leaks was first noted in early December 2003 and returned to approximately normal levels in March 2004. A similar pattern was observed the following heating season, with an increase in leaks being reported from November 2004 to March 2005.

Washington Gas retained the services of ENVIRON International Corp. (Environ), working with Polymer Solutions, Inc (PSI) and Akron Rubber Development Laboratory (ARDL) to conduct an investigation into the most likely causes of the increased leak rates. At the outset of our study, potential contributors to this increased leak rate included the effects of changes in gas composition (due to introduction of re-vaporized LNG), historical installation practices, the age of the installed couplings and ground movement due to earthquakes or other causes.

The team has conducted an investigation of the increased leak rates by:

  Gathering information regarding the coupling design and materials, installation practices, leak patterns, gas compositions, geological information, and other LDC experiences with similar equipment;
 
  Developing a list of all plausible physical and chemical mechanisms which could contribute to the observed leak patterns in the field;
 
  Constructing a working hypothesis for the observed coupling leaks;
 
  Designing and conducting experiments to develop the required data to evaluate the hypothesis; and
 
  Reviewing the experimental data, as well as all other information collected during the assignment, and making our best assessment of the most likely causes of the increased leak rate.

The experiments conducted included exposure tests, in which various seals were immersed in different gas environments for fixed periods, with detailed dimensional,

1


 

weight and hardness measurements being made before, during and after exposure. In addition we conducted compression stress relaxation tests, in which the retained sealing force produced by the elastomer seal material was measured in different gas environments as a function of time. A key feature of all of these tests was the evaluation of a set of seals that had been exposed to a reference pipeline gas composition for a fixed period and was then switched to the Cove Point LNG environment for a further period. Other sets of seals remained in the reference pipeline gas environment.

Based on the work we have conducted to date, we believe that a combination of factors contribute to the observed spikes in leaks. Three factors have been identified as contributors:

  Aging Seals. Seals of various rubber formulations have been in service in the WG network for 30 to 50 years. A small fraction of these seals will have undergone compression stress relation to the point of sealing only marginally.
 
  A Change in Gas Composition. The change to a gas that has a lower concentration of pentane and higher molecular-weight (C5+) compounds, caused a slight shrinkage in some seals due to de-sorption of previously adsorbed C5+ compounds (especially those seals with an elastomer formulation with a high solvent swell index, a measure of their propensity to adsorb hydrocarbons and increase in volume).
 
  A Temperature Decrease. The onset of winter caused a further slight seal shrinkage as the ground cooled, due to differential thermal expansion effects in the coupling.

In addition, the use of hot coal tar as an encapsulant during installation is regarded as a potential contributing factor, in that it may have overheated some seals causing changes in physical properties of the rubbers.

Our conclusion is supported by data from our experiments and can be explained by invoking known physical and chemical mechanisms. It is also very similar to the conclusion reached by LILCO regarding an increased rate of leaks experienced in 1992-3 on Long Island shortly after taking receipt of gas from the Iroquois pipeline.

The adsorption and desorption of heavy hydrocarbons by elastomer seal materials is a reversible process. In further experiments we hope to demonstrate the potential for restoring sealing force by doping the LNG with small quantities of hexanes and/or pentanes.

Key points to note from our test work include:

  Elastomers are viscoelastic in nature and as the word implies, exhibit both elastic behavior as well as viscous behavior. The elastic property is associated with energy storage under deformation: this provides the sealing force. On the other hand, the viscous effects cause a decrease in the stored energy over time. This is known as stress relaxation: the change in stress with time when the elastomer is held under constant strain. This effect causes a decrease in the contact sealing force over time.

2


 

  The process of natural gas liquefaction and re-vaporization results in a lower C5+ content (mostly pentanes and hexanes) in the re-vaporized LNG than that of the pipeline gas. The gases used in our experiments demonstrated this difference: concentrations of C5+ hydrocarbons were 1053 ppm in the Shenandoah pipeline gas versus 105 ppm in the Cove Point gas.
 
  The elastomer in the seals can adsorb and desorb pentane, hexane, and other higher hydrocarbons, resulting in dimensional changes on the order of a few percent to a few tens of percent (if immersed in liquid hexane). In fact, hexane swell tests are a standard way of characterizing synthetic rubbers. Likewise a change from pipeline to LNG gases can result in desorbing of pentane/hexane and a concomitant shrinking of the elastomer seal, leading to a reduction in sealing force.
 
  Differences in weight change, volume change and micro-hardness change were observed between seals exposed to the pipeline gas and those exposed to the re-vaporized Cove Point LNG. Those exposed to LNG show a slight increase in hardness, a slight decrease in weight and a slight decrease in volume compared to those exposed to pipeline gas. These differences are consistent with increased adsorption of C5+ compounds by the seals in the pipeline gas environment
 
  The compression stress relaxation tests demonstrated that the change from the pipeline gas environment to the re-vaporized LNG environment can affect the retained sealing force of both the SBR (Dresser) and NBR (Normac) seals. The impact appears to be greater on the NBR material than on the SBR material. The direction of the observed effect supports the hypothesis that the change to a lower C5+ gas caused seal shrinkage, and that this can be a contributing factor to the increased rate of leakage of compression couplings.
 
  The elastomer seal has a much greater coefficient of thermal expansion than the steel pipe or coupling. Thus as the ground temperature undergoes its seasonal cycles, the seal will grow and shrink relative to the pipe, increasing and decreasing sealing force. In the mid-Atlantic region, the temperature at depths of 2 – 4 feet can fluctuate by ±15 to ±20°F over the course of a year, depending on depth and soil type. The temperature drop of 30 to 40°F from summer to winter is significant and may contribute just enough additional elastomer shrinkage in marginal seals to produce a leak in winter.

We also observed that there are at least two different formulations of NBR elastomer present in the Normac couplings in Prince Georges County. One shows a much greater volume swell in hexane than the other and would therefore be expected to be more susceptible to effects of changes in gas composition. Also worthy of note is the fact that there is a much higher incidence of leaks in couplings installed in the years when Normac couplings represented a significant fraction of the total number installed.

The LILCO (now Keyspan) experience on Long Island in 1992-1993 also appears very relevant. The independent lab retained by LILCO concluded that the reduction in heavy hydrocarbon concentrations as the transition from Transco to Iroquois gas occurred was indeed the proximate cause of the rash of leaks experienced in Normac service couplings.

3


 

1. Introduction & Background

In the last two heating seasons, Washington Gas (WG) experienced an unusually high number of leaks in particular areas of their distribution network. The couplings affected include 2 inch and 3/4 inch Dresser Style 90 couplings with styrene butadiene rubber (SBR) elastomer seals and 2 inch and 3/4 inch Normac couplings with nitrile butadiene rubber (NBR) elastomer seals. These couplings were installed between approximately 1958 and 1974. For reference, Figure 1 shows a 2” Normac coupling after removal from the ground. Figure 2 shows a cross section of a Dresser coupling, illustrating the location and configuration of the elastomer seal (the Normac couplings are very similar in arrangement). Figure 3 shows a seal from a 2” Normac coupling.

(NORMAC COUPLING PHOTO)

     
Figure 1
  Two-inch Normac coupling, after removal of tar coating.

(DRESSER COUPLING PHOTO)

     
Figure 2
  Cross-section of Dresser coupling, showing location of elastomer seal.

4


 

(NBR SEAL PHOTO)

     
Figure 3
  NBR seal from a 2” Normac coupling.

In both seasons, the increased incidence of leaks occurred in Prince Georges County, Maryland. Based on composition measurements and system gas flow models, the affected region of the WG system was known to be supplied primarily with re-vaporized LNG from the Cove Point terminal. Other parts of the WG network, which did not receive significant amounts of LNG, experienced typical seasonal leak rates WG commenced distribution of the Cove Point LNG in August 2003. The high incidence of leaks was first noted in early December 2003 and returned to approximately normal levels in March 2004. A similar pattern was observed the following heating season, with an increase in leaks being reported from November 2004 to March 2005.

Washington Gas retained the services of ENVIRON International Corp. (Environ), working with Polymer Solutions, Inc (PSI) and with Akron Rubber Development Laboratory (ARDL) to conduct an investigation into the most likely causes of the increased leak rates. Potential contributors to this increased leak rate include the effects of changes in gas composition (due to introduction of re-vaporized LNG), historical installation practices, the age of the installed couplings and ground movement due to earthquakes. The team has conducted an investigation of the increased leak rates, following the approach described below:

1. Information Gathering

Working with Washington Gas staff, we began by gathering and compiling information regarding:

  Current and the historical leak problems and patterns in the WG system.

5


 

  Current & historical pipeline gas compositions, humidities, pressures and temperatures.
 
  Geological information.
 
  Coupling design and materials specifications.
 
  Coupling installation procedures.
 
  Coupling purchase history.

2. Identification of Potential Leak Mechanisms & Design of Experiments

We reviewed the data gathered and then proposed a set of candidate explanations for the increase in leak incidents. We considered all plausible physical and chemical mechanisms. We then identified additional data required to support or eliminate a particular scenario from consideration. We designed and performed laboratory and field tests, as well as conducting further research to provide this data.

3. Experimental Investigations

Three sets of experiments were conducted at PSI and at ARDL. ARDL focused on compression stress relaxation measurements in both continuous and non-continuous tests. PSI conducted physical and chemical characterizations of both leaking and non-leaking seals, as well as measuring compression set for various seal samples. In addition, PSI supported in-stream exposure testing conducted by WG staff. These tests are discussed in detail in Section 3.

4. Review of Data and Assessment of Likely Cause

Following the conclusion of the experiments, we reviewed the experimental data, as well as all other information collected during the assignment, and made an assessment of the most likely causes of the increased leak rate. We looked for corroborating evidence from known industry experiences.

6


 

2. Possible Causes of Increased Leak Incidents

2.1 Potential Contributing Factors

Following the initial data collection, we identified fifteen potential causes of, or contributing factors to, the increased incidence of leaks in the Normac and Dresser couplings. They are summarized in Table 1 and discussed in turn below.

1. Humidity Change

The process of liquefaction and re-vaporization of natural gas results in a lower water content in the re-vaporized gas than that in pipeline gas. WG data shows that the LNG water content to be an order of magnitude lower than that of pipeline gas (~10 ppm vs 110 – 176 ppm). The elastomer in the seals can adsorb and desorb water, resulting in volume changes on the order of a few percent when immersed in liquid water (this is a much smaller effect than the volume swell caused by immersion in hexane, see below).

Thus a change from pipeline to LNG gases can in principle result in desorbing of water and a concomitant shrinking of the elastomer seal. However, it should be noted that the humidity levels in both gases are extremely low, and consequently this would be expected to be a very small effect and not a likely primary cause. It is considered a possible contributor.

2. Change in Pentane and Higher Molecular Weight Hydrocarbon Content

The process of natural gas liquefaction and re-vaporization results in a lower C5+ content in the re-vaporized LNG than that of the pipeline gas. The hourly composition data provided to us (from Gardiner Road gate) shows approximately an order of magnitude reduction in average C5 plus C6 content as the Cove Point gas was introduced, from ~2000 ppm (C5+C6) to ~200 ppm (C5+C6), see Figure 4.

The elastomer in the seals can adsorb and desorb pentane, hexane, and other higher hydrocarbons, resulting in dimensional changes on the order of a few percent to a few tens of percent (if immersed in liquid hexane). In fact, hexane swell tests are a standard way of characterizing synthetic rubbers.

Thus a change from pipeline to LNG gases can result in desorbing of previously adsorbed pentane/hexane and a concomitant shrinking of the elastomer seal. This factor was suggested as the most likely cause of increased leaks in Normac couplings in the LILCO system during the 1992-3 timeframe. This factor was identified as worthy of experimental investigation.

7


 

     
Table 1
  Potential Causes of and Contributing Factors to Increased Leak Incidence
             
#   Factor   Mechanism   Location-Specific?
1
  Humidity change   Elastomer desorbs water & shrinks as gas
humidity decreases, reducing sealing force
  Yes — local to regions experiencing humidity change
2
  C5+ change   Elastomer desorbs C5+ & shrinks as gas
composition changes, reducing sealing force
  Yes — local to regions experiencing composition change
3
  C2, C3, C4 change   Change in elastomer dimensions due to change in interaction   Yes — local to regions experiencing composition change
4
  Compression stress relaxation   CSR leads to reduced sealing force over time   Unlikely — all elastomers will experience CSR, but can be a contributing factor
5
  Loss of plasticizer   Plasticizer leaches out in HC environment,
affecting elastomer properties
  Possibly — if leachant is only in certain gas compositions
6
  Ground conditions   Ground movement (e.g. due to excessive water) disturbs joint   Yes — local to specific subsurface conditions
7
  Earthquake   Ground movement disturbs joint   Unlikely but could be local to specific formations
8
  Installation practice   Under/over-tightening, incorrect pipe alignment   Yes — could be specific contractors or crews
9
  Hot tar application   Over-temperature due to excessive tar leads to change in elastomer properties   Possibly — could be affected by differing practices between installation crews
10
  Pressure increase   Increased pressure overcomes sealing force   Yes — local to regions experiencing pressure increase
11
  Sealing surface corrosion   Pitting of sealing surface leading to leaks   Yes — local to regions exposed to corrosive agent or encapsulation failure
12
  Low temperatures   Temperature drop reduces sealing force due   Unlikely — all couplings are at same depth in
 
      to differential thermal expansion   same climate zone
13
  Obsolescence   Elastomer life has expired, can no longer
provide sealing force
  No
14
  Off-spec batch of couplings   Off-spec parts causing leak   Unlikely — parts were stocked centrally
15
  Coupling design   Design inappropriate for application   No

3. Change in Ethane, Propane and Butane Content

Depending on the source of the LNG, it can also differ in ethane, propane and butane content relative to pipeline gas. In addition, the hourly ethane and propane content can vary significantly as different LNG blends are introduced from the import terminal. The hourly composition data from Gardiner Gate showed ethane content varying between ~3% and ~7% and propane between ~0.4% and ~0.7% as different LNGs were supplied. The periods of high ethane and propane concentration corresponded to increases in nitrogen content, indicating the presence of a higher heating value LNG for which nitrogen blending was required. The background ethane and propane concentrations for the pipeline gas were approximately 3% and 0.6%, respectively. Butane concentrations are typically very low in the LNGs (less than 0.05%) compared to ~0.2% in the pipeline gas.

However, a literature search identified no reports of the effects of changes in C2 – C4 content on elastomer properties, and no plausible mechanism has been identified. In contrast, the effects of heavier hydrocarbons are well documented in the literature and even form part of several standard rubber characterization tests. This effect is therefore not considered a likely cause.

8


 

(HEXANE + PENTANES CHART)

     
Figure 4
  Change in (C5+C6) concentration at Gardiner Gate after start of LNG transmission in August 2003.

4. Compression Stress Relaxation

Elastomers are viscoelastic in nature and as the word implies, exhibit both elastic behavior as well as viscous behavior. The elastic property is associated with energy storage under deformation: this provides the sealing force. On the other hand, the viscous effects cause a decrease in the stored energy over time. This is known as stress relaxation: the change in stress with time when the elastomer is held under constant strain. This effect causes a decrease in the contact sealing force over time. Figure 5 provides illustrative data for an accelerated (high-temperature) test of various elastomers.

All elastomers exhibit this behavior to varying degrees: this is a universally applicable background phenomenon occurring within all the couplings in the WG system. However, it is worth noting that NBR exhibits the lowest retained sealing force among a range of modern elastomers (see Figure 5). It is possible that further physical changes to the stress-relaxed seals (caused for example by desorption of water or C5+) could then cause a marginal seal to leak. This factor was identified as worthy of experimental investigation and a likely contributor.

9


 

(RETENTION SEALING FORCE CHART)

     
Figure 5
  Illustrative compression stress relaxation in various elastomers: Nitrile Rubber (NBR), Fluorosilicone (FVMQ), Silicone (VMQ), Fluoroelastomer (FKM), and Perfluoroelastomer (FFKM). (Accelerated tests conducted at high temperature.) Source: PSP, Inc.
 
 

5. Loss of Plasticizer

It was considered possible that constituents of the gas stream may cause plasticizer to leach out of the elastomer, Plasticizers tend to be added to rubber compounds as process aids to enhance softness, flexibility, and processability. A rubber that was soaked in a liquid plasticizer would swell just as it would in a liquid solvent. Therefore, if plasticizer were to leach out over time, the material would be expected to shrink slightly and become stiffer and harder, potentially leading to a drop in sealing force. This phenomenon could be exacerbated by a change in the gas composition to which the elastomer is exposed. No specific mechanism that is dependent on constituents known to be different between pipeline gas and LNG has been identified, however, and this is considered an unlikely contributor.

6. Ground Conditions

Local soil conditions, combined with, for example, unusually high rainfall, could cause local ground motion, which in turn could cause pipe coupling motion leading to a leak. There is some evidence of ground motion in clay soils in Prince Georges County, as well as other counties in Maryland and Virginia. So-called marine clays are widely dispersed in the area (for example, Fairfax County, VA publishes a guide to foundation problems

10


 

caused by clay swelling and shrinking for homeowners) and there does not appear to be a correlation with or evidence of particular problems in PG County. This is considered an unlikely contributor.

7. Earthquake

An earthquake can also cause local ground motion leading to coupling leaks. Once again, it would be important to examine local sub-surface conditions to determine regions likely to experience greater or lesser degrees of ground motion and to correlate those regions with locations of leaking couplings. Given that the epicenter of the most recent sizeable earthquake was close to Richmond, VA, it is exceedingly unlikely that WG’s network in Prince Georges County Maryland would have been preferentially affected over those regions of WG service area in Virginia. After examining ground conditions and reviewing available earthquake data, this potential cause was dismissed (see Section 5).

8. Installation Practice

It is considered possible that there were differences in installation practices by year and area. The challenge in investigating this potential cause of the problem is the lack of availability of detailed installation records which would allow correlation of leak incidents with installation practices. Also, given that the couplings in the WG system have performed well for decades, it is unlikely that installation practices could be the proximate cause of a leak. If installation differences are a contributing factor, then it will only be due to their influence in establishing a range of states of seal in the coupling population before the commencement of LNG transmission. That is, certain couplings, in service for decades, were marginal in sealing performance and could be made to leak by another change in the system (for example, change of gas composition, temperature changes, etc). This is considered a possible contributing factor.

9. Effect of Hot Tar Application

The WG specifications for installing wrapped steel mains call for encapsulation of the coupling with hot coal tar (or “enamel”). The recommended tar temperature for pouring is 400 °F. It is therefore possible that excessive amounts of hot tar surrounding the coupling could provide a large enough thermal pulse to raise the seal temperature excessively. This is obviously closely related to No. 8 above, Installation Practice. Excessive seal temperatures caused by hot tar application could lead to post curing of the material, resulting in a higher extent of cure and thus cure shrinkage. This would result in reduced sealing force. The effect of hot tar application on coupling torque was noted in a WG memo from 1967. Couplings were tightened to a set torque and the retained torque (i.e. the torque required to loosen the coupling) was noted after different time periods. It was observed that the torque loss (i.e. the difference between the original tightening torque and the torque required to loosen the coupling) after a few hours on a fitting treated with hot tar was equivalent to that lost over many weeks on a fitting not so treated. This is considered a possible contributing factor.

11


 

10. Increase in Supply Pressure

Operation at increased pressure can obviously overcome marginal sealing force, leading to leaks. However the most recent pressure increases in the region affected were approximately 20 years ago, with no attendant leak epidemic reported. In recent years the pressures in the affected parts of the system have not been increased, so this factor can be dismissed.

11. Corrosion of Sealing Surfaces

Corrosion can lead to surface pitting and leaking of the couplings, despite no degradation in overall elastomer properties. Corrosion could be caused by inadequate cathodic protection, or inadequate sealing of the coupling with tar or wax. Observations of couplings removed from the field indicate no signs of corrosion. Also, there is no reason to suppose that corrosion would occur preferentially in PG County (absent evidence of differences in installation practices). This factor can be dismissed.

12. Low Temperatures

The elastomer seal has a much greater coefficient of thermal expansion than the steel pipe or coupling. Thus as the ground temperature undergoes its seasonal cycles, the seal will grow and shrink relative to the pipe, increasing and decreasing sealing force. In the mid-Atlantic region, the temperature at depths of 2 – 4 feet can fluctuate by ±15 to ±20°F over the course of a year, depending on depth and soil type. The temperature drop of 30 to 40°F from summer to winter is significant and may contribute just enough additional elastomer shrinkage in marginal seals to produce a leak.

Examining the hourly composition data from Gardiner Gate, the weekly fluctuations in concentrations in the summer appear to very similar to those in the winter. Yet, the summer leak rate is much lower than the winter leak rate. It is therefore possible that the winter drop in ground temperature is the proximate cause of leaks in a subset of marginal seals. Contributors to the marginal state of the seals could include improper installation, over-temperature, a long period of stress relaxation, and desorption of moisture and C5+ compounds. Reduced ground temperatures in winter are considered a likely contributor.

13. Obsolescence

The couplings in question were installed between ~1958 and ~1974. It is not known what their expected service life was at the time of installation, but by any standard this is a long service. However, if general obsolescence of the couplings is at fault, then one would certainly not expect increased leak rates in local areas. General obsolescence is not a likely contributor.

14. Off-Spec Batch of Couplings

There exists the possibility that the couplings that are leaking did not meet specifications in some manner. However, this begs the question of timing – why would they leak these last two winters? – and location – why only PG County? The use of a central store of parts for all expansion projects suggests that if they existed, such off-spec couplings

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would be widely dispersed across the network. It is conceivable, however, that off-spec couplings form that subset which when exposed to other factors (time, composition changes and thermal cycling) develop leaks. This is a possible contributor.

15. Coupling Design

It is possible that the coupling designs were inappropriate for the application. The fact that these couplings have performed adequately over all these years and that the leaks are localized strongly suggests this is not a likely contributor.

2.2 Working Hypothesis

Based on our review of the information available to us at the beginning of our investigation, we developed a working hypothesis for the most likely causes of the increased leak rates, as follows:

  1.   One or more of several factors led to a subset of couplings that had sub-optimal sealing performance at the time of installation.
 
  2.   All couplings reach an equilibrium degree of elastomer swelling due to adsorption of moisture and C5+ compounds from pipeline gas.
 
  3.   All couplings undergo compression stress relaxation over the years of operation, reducing sealing force progressively. There develops, over time, a distribution of states of seal in the coupling population, including a normal rate of leaks.
 
  4.   In certain parts of the network, exposure to LNG results in elastomer shrinking, due to desorption of moisture and C5+. This results in a set of seals that are marginal.
 
  5.   As the winter season starts, the ground temperature falls, resulting in additional shrinkage of the elastomer, leading to leaks in the marginal seals.
 
  6.   As spring comes and the ground temperature increases, the leak reporting rate falls back to the historical norm.

A set of experiments which take into account the factors considered the most likely contributors were then designed to test this hypothesis. These factors relate to effects of gas composition changes, and were tested in three sets of experiments: the WG basket exposure tests, the Polymer Solutions Inc (PSI) pressure vessel exposure tests and the Akron Rubber Development Laboratory (ARDL) stress relaxation tests. These will be discussed below.

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3. Experimental Program

The overall approach was to understand the effect of a change of gas environment (from pipeline gas to Cove Point gas) on the physical properties of the seals. We were particularly interested in changes in those properties which contribute to the sealing performance of the elastomer, notably the effects on elastomer hardness, volume swell and compression stress relaxation (a measure of the sealing force). In order to be able to draw conclusions from these exposure tests, it was also necessary to perform baseline physical and chemical characterization of the seals. Care was taken in setting up these experiments to ensure that the test conditions were indeed representative of the field conditions and that samples from the field were well characterized.

3.1 Polymer Solutions, Inc. Tests

3.1.1 Approach

PSI conducted a broad range of chemical and physical characterizations of a variety of field samples before, during and after exposure to a variety of gas compositions. Some of the exposure tests were performed in-house at PSI, some were performed in the WG pipeline system itself and some (the compression stress relaxation tests) were conducted at ARDL. PSI performed the detailed physical and chemical characterization of all samples used in the various exposure tests.

Initial Physical and Chemical Characterization. Leaking and non-leaking Normac and Dresser couplings were removed from the field by WG staff and shipped to PSI for inspection and analysis. PSI staff photo-documented and measured the couplings before and after disassembly to remove the seals. They also conducted detailed chemical analyses of the seals to determine (a) if the specimens used in the testing were NBR or SBR, and (b) if there were any differences in the extractables, glass transition temperature or filler levels between among the various seals. By extractables, we mean materials such as uncured rubber, antioxidants, plasticizers, etc, which are identified and quantified by chemical extraction from the seal, followed by chemical analysis. The glass transition temperature, Tg, is the temperature at which the polymer changes from a hard, glass-like state to a rubber-like state. The term filler refers to minerals such as silica or clay, which are typically used in rubber compounding.

A small piece of several seal samples were removed for Fourier Transform Infra-Red (FTIR) spectroscopy. The purpose of the FTIR analysis was to confirm the elastomer types of the Dresser and Normac seals. The results indicate that the Normac seals are a Nitrile (NBR) based elastomer, as indicated by a strong nitrile peak in the spectrum. The Dresser seals, on the other hand, are comprised of a different elastomer, SBR, as indicated on the back of the seal and evidenced by the FTIR spectra.

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Gas Exposure Tests. PSI conducted gas exposure tests to understand the effects that the pipeline gas and the Cove Point LNG have on reference SBR and NBR compounds as well as the NBR and SBR seals from the field. The original properties and aged properties (weight, volume, specific gravity and micro-hardness) of the four samples (NBR and SBR, leaking and non-leaking) were measured. At PSI the aging was accomplished by immersing the samples in pressure vessels charged to ~40 psi with the various gases. At the WG field locations, the aging was accomplished by affixing the samples to a strainer basket which was immersed in the gas pipeline flow.

In addition to the material property data, PSI also collected compression set data for all samples. The samples were compressed by 25 percent: i.e. the compressed height is 0.75 times the original height. Then after a fixed time period (typically one week (168 hours) or two weeks (336 hours)) the compression is released and the rebounded height is measured after 30 minutes. The percent set is a percentage of the initial compression state. Thus, for a 100 percent set, the rebounded height is equal to the compressed height. A material with a zero percent set results from the material rebounding to its original height. Compression set can also be related to the mechanical behavior of seals in operating couplings.

Five types of seals were investigated under three gas conditions at PSI and at the WG field locations. The gas conditions were:

  Pipeline gas (at PSI it was Shenandoah, at WG field location it was Rockville.)
 
  Cove Point LNG.
 
  One week in the pipeline gas followed by one week in Cove Point LNG.

Samples of a leaking Normac seal, a leaking Dresser seal, a new NBR o-ring, a new SBR Dresser seal, and a blue gasket were prepared for immersion testing in two Washington Gas field locations as well as in pressure vessels at PSI using the gases supplied by Washington Gas. The immersions were sampled at one and two week intervals in the pipeline gas, one and two week intervals in the Cove Point gas, and a third set was immersed for 1 week in the pipeline gas followed by one week in the Cove Point gas. All tests were performed in triplicate – reported standard deviations are based on the results for the three samples.

The only differences in the two approaches are the location of the samples and the pressure. The WG field locations were at ~300 psi, whereas the vessel tests at PSI were conducted at ~40 psi. To simulate gas exchange in the lab, the pressure vessel was evacuated and refilled approximately three times a day.

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3.1.2 Test Results

Gas Exposure Tests

Gas chromatograph/mass spectrometer analyses were made of the tests gases used in the PSI and ARDL exposure tests. The gas compositions are presented in Table 2. Of note are the relative concentrations of C5+ hydrocarbons: 1053 ppm in the Shenandoah pipeline gas versus 105 ppm in the Cove Point gas. Also presented are the gas compositions for the in-stream exposure tests conducted at the Rockville and Gardiner Road gate stations in the WG network. C5+ hydrocarbons were 850 ppm on average at the Rockville location (pipeline gas) and 188 ppm on average at the White Plains location (LNG). C5+ concentrations at Rockville varied between 470 and 1296 ppm during the two week test period.

     
Table 2
  Gas compositions for exposure tests at PSI, ARDL and in-stream at WG (concentrations in volume %, ND = Not Detected)
                                 
    PSI & ARDL Exposure Tests   WG In-Stream Exposure Tests
    LNG   Pipeline   LNG   Pipeline
Constituent   (Cove Point)   (Shenandoah)   (White Plains)   (Rockville)
Methane
    95.600       94.142       96.696       94.910  
Ethane
    3.540       3.039       2.804       3.220  
Propane
    0.400       0.662       0.395       0.599  
Iso-butane
    0.025       0.094       0.043       0.069  
Normal-butane
    0.019       0.135       0.030       0.094  
Iso-pentane
    0.006       0.044       0.007       0.026  
Normal-pentane
    0.004       0.033       0.004       0.019  
C6+
  ND     0.029       0.007       0.039  
Nitrogen
    0.405       0.776       0.012       0.603  
Carbon Dioxide
  ND     1.047       0.002       0.419  

Weight Change. Table 3 shows the weight percent uptake or increase for two week immersion tests at both PSI and the WG field locations. An increase in weight would occur if the sample adsorbed material from the gas stream (for example, pentane or higher hydrocarbons). A weight loss would occur from physical abrasion (only possible in the case of the in-stream exposure tests at WG) or the loss of a plasticizer or volatile material from within the compound. Since these materials were previously used, it is also possible that adsorbed material from service that could desorb in the gas stream and cause a weight loss during testing.

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All aged field samples exposed to Cove Point gas for two weeks showed a weight loss. Two of the aged field samples exposed to pipeline gas for two weeks showed a weight gain and two showed a slight weight loss (much less than that shown by the Cove Point samples). All four aged field samples exposed to pipeline gas for one week and Cove Point gas for one week showed a weight loss, though less than those exposed to Cove Point gas for two weeks. There is a clear difference in the behavior of the samples exposed to the Cove Point gas and those exposed to the pipeline gas.

Volume Change. Table 4 show the percent volume change for the two-week immersion tests at both PSI and the WG field locations. All aged field samples exposed to Cove Point gas for two weeks showed a volume decrease. Three of the aged field samples exposed to pipeline gas for two weeks showed a volume increase and one showed a

     
Table 3.
  Percent weight uptake after 2 weeks in the corresponding gas streams. Aging conducted at PSI (in the vessels) is shown in light yellow and that at Washington Gas in dark yellow.
                                                 
    Percent Weight Uptake,   Percent Weight Uptake,   Percent Weight Uptake,
    Cove Point LNG   Pipeline Gas   Combined 1+1 Week
            Standard           Standard           Standard
Sample   Percent   Deviation   Percent   Deviation   Percent   Deviation
PSI — Leaking NBR
    -1.21       .06       -0.56       .06       -0.75       .07  
WG — Leaking NBR
    -2.60       .09       0.95       .10       -1.82       .34  
PSI — Leaking SBR
    -1.06       .13       -0.12       .29       -0.36       .30  
WG — Leaking SBR
    -2.62       .01       1.37       .11       -1.44       .03  
     
Table 4.
  Percent volume change within the samples after 2 weeks in the corresponding gas streams. Aging conducted at PSI (in the vessels) is shown in light yellow and that at Washington Gas in dark yellow.
                                                 
    Percent Volume   Percent Volume Change,   Percent Volume Change,
    Change, Cove Point LNG   Pipeline Gas   Combined 1+1 Week
            Standard           Standard           Standard
Sample   Percent   Deviation   Percent   Deviation   Percent   Deviation
PSI — Leaking NBR
    -1.53       .28       -0.28       .03       -0.79       .08  
WG — Leaking NBR
    -1.23       .88       2.39       .17       -0.10       .47  
PSI — Leaking SBR
    -1.27       .10       0.16       .30       -0.47       .46  
WG — Leaking SBR
    -2.83       .07       3.02       .17       -1.06       .10  

slight volume decrease (much less than that shown by the Cove Point samples). All four aged field samples exposed to pipeline gas for one week and Cove Point gas for one week showed a volume decrease.

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Micro-hardness. Micro-hardness measurements (see Table 5) were also made on these seals. The hardness data showed very little differences, as deviations of 0.5-1 pts in hardness index are normal. However, it was observed that two of four aged field samples exposed to Cove Point gas for two weeks showed a slight hardness increase. All four of the aged field samples exposed to pipeline gas for two weeks showed a slight hardness decrease. Two of four aged field samples exposed to pipeline gas for one week and Cove Point gas for one week showed a slight hardness increase. Three of four samples exposed to Cove Point gas for two weeks showed a hardness increase in excess of the standard deviation in the measurement, whereas those exposed to pipeline gas or both gases generally showed small changes comparable to the standard deviation. A decrease in hardness is indicative of adsorption swelling, whereas an increase in hardness is indicative of desorption (drying) and/or increased cross-linking.

     
Table 5.
  Micro-hardness changes within the samples after 2 week in the corresponding gas streams. Aging conducted at PSI (in the vessels) is shown in light yellow and that at Washington Gas in dark yellow.
                                                 
    Delta Shore M,   Delta Shore M,   Delta Shore M,
    Cove Point LNG   Pipeline Gas   Combined 1+1 Week
    Delta   Standard   Delta   Standard   Delta   Standard
Sample   Shore M   Deviation   Shore M   Deviation   Shore M   Deviation
PSI — Leaking NBR
    -0.5       0.5       -0.3       1.0       -0.5       0.9  
WG — Leaking NBR
    2.5       0.9       -0.5       0.5       1.3       0.6  
PSI — Leaking SBR
    -0.7       0.3       -0.2       1.3       -0.5       0.5  
WG — Leaking SBR
    1.5       0.5       -0.2       1.2       0.5       1.7  
     
Table 6.
  Compression set of the samples after 2 weeks in the corresponding gas streams at room temperature.
                                 
            Cove Point   Pipeline   Combined
Sample   Air   LNG   Gas   1+1 Week
2005-059-22
                               
(New Dresser — SBR)
    3.8 %     4.2 %     3.5 %     3.1 %
2005-059-03
                               
(NBR O-Ring)
    3.9 %     4.9 %     4.4 %     3.9 %
2005-059-07 Side B
                               
(Leaking Normac — NBR)
    12.6 %     12.4 %     13.2 %     9.4 %
2005-059-05 C2 Side B
                               
(Leaking Dresser — SBR)
    5.4 %     5.0 %     3.1 %     4.6 %

Compression Set. The machined seals utilized for the compression set test were nominally 0.5 inch long strips and the o-rings strips were approximately 1" long. The two-week compression set data in Table 6 shows some significant differences. The NBR

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sealing material has approximately twice the compression set of the SBR sealing material. This means that once the NBR is compressed it remains in a compressed state and does not rebound as much as the SBR sealing material. It is difficult to compare the NBR O-ring to the leaking NBR seal due to the shape differences. However, the leaking and non-leaking NBR seals used in the Normac couplings show similar compression sets. Based on the one and two-week compression set data none of the seals show a significant effect based on the gas environment. This is not unexpected, as compression set measurements generally can not be used to show the effects of small changes in properties.

Physical and Chemical Testing

Solvent Swell. Swell tests were performed separately in chloroform and in hexane. Samples were immersed at room temperature for periods of 70 hours and 168 hours and then removed for weighing and measuring. The hexane swell data in Table 7 shows some interesting differences between the leaking and non-leaking NBR seals. The non-leaking NBR seals have a significantly lower hexane swell and a different specific gravity than their leaking counterparts. The leaking SBR seals have high hexane swell indices also, comparable to those of the leaking NBR seals.

Each measurement was done in triplicate and the standard deviation for the volume swell measurements were approximately ±1 percent. This suggests that there may have been more than one type of NBR seal being used during this time period. A higher state of cure or a different NBR compound with higher acrylonitrile content would cause a lower swell in hexane. It also suggests that those materials that adsorb higher levels of hexane would also be most susceptible to physical changes from variations of the gas supply composition due to absorption and desorption.

Differential scanning calorimetry. Differential scanning calorimetry (DSC) was conducted on most of the couplings. This technique can detect a variety of thermal transitions of a material (such as melting temperature, crystallization temperature, glass transition temperature) as well as other thermal phenomena. In rubber compounds, such as the coupling seals, DSC will typically only detect glass transitions. The glass transition temperature is related to the type and grade of elastomer used. Above this temperature (typically sub-ambient for rubbers), the material will exhibit rubber-like properties. However, below this temperature it becomes very stiff and glass-like. Plasticizers and low molecular weight additives (oils and other organic compounds) can reduce the glass transition temperature of a compound below that of the pure elastomer. This provides improved low temperature resistance with added flexibility down to lower temperatures.

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Table 7.
  Volume swell comparison of seal types when immersed in hexane for 70 hours.
                 
            Percent   Percent
Sample   Seal Type   Leaking   Weight Change   Volume Change
2005-059-06   Dresser — SBR   Yes   18.1   40.4
2005-059-05C2B
  Dresser — SBR   Yes     8.4   22.1
2005-059-01   Normac — NBR   No     0.8     4.7
2005-059-01A   Normac — NBR   No     1.0     4.1
2005-059-29   Normac — NBR   No     0.6     3.7
2005-059-08   Normac — NBR   Yes   12.5   29.5
2005-059-07B   Normac — NBR   Yes   11.3   27.3
2005-059-09A   Normac — NBR   Yes     8.4   22.1
2005-059-11A   Normac — NBR   Yes   13.8   33.1
     
Table 8.
  Glass transition temperatures of the seals with dates of installation shown. Only sample 2005-059-12 (a leaking Normac), which was installed on 1/29/1965, was not tested.
                     
                    Date
Sample   Seal Type   Leaking   Tg 1 ( ºC)   Tg 2 ( ºC)   Installed
2005-059-05c2b
  Dresser — SBR   Yes   -49     Unknown
2005-059-06b   Dresser — SBR   Yes   -51     Unknown
2005-059-28a   Dresser — SBR   Yes   -51     6/25/1965
2005-059-28b   Dresser — SBR   Yes   -52     6/25/1965
2005-059-01   Normac — NBR   No   -28     Unknown
2005-059-29   Normac — NBR   No   -29     8/22/1965
2005-059-07b   Normac — NBR   Yes   -65   -16    1963
2005-059-08   Normac — NBR   Yes   -63   -12    9/21/1963
2005-059-09a   Normac — NBR   Yes   -65   -20    1/29/1964
2005-059-11a   Normac — NBR   Yes   -65   -17    1/29/1964
2005-059-26b   Normac — NBR   Yes   -32     9/9/1965
2005-059-27b   Normac — NBR   Yes   -61    -9   5/19/1965

Table 8 summarizes the glass transition temperature data for the rubber seals. All the Dresser SBR seals have a glass transition temperature (Tg) of nominally -50ºC. All the non-leaking Normac coupling NBR seals have a Tg of nominally -30ºC. However, all the

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leaking Normac couplings NBR seals exhibited two glass transition temperatures: one transition at -65ºC and one at nominally -20ºC. This data set indicates that the Normac couplings used by WG contained seals of at least two different NBR formulations.

It appears that the Normac seal types were changed around 1965 from a “two Tg” material to a “one Tg” material. The leaking Normac seals (2005-059-07 through 2005-059-11) show two Tg’s and were installed in 1963 or 1964. Other Normac couplings (2005-059-26 and 2005-059-29) exhibited one Tg and were installed in 1965. In addition, sample 2005-059-26 is the only single Tg Normac coupling that was submitted as leaking. It should be noted that the pre-1965 two-Tg NBR material in the leaking couplings was the formulation that showed high volume swells in hexane.

The change in formulation is further confirmed by Thermogravimetric Analysis (TGA) scans for a leaking and non-leaking Normac seal. This instrument consists of a microbalance suspended inside a temperature controlled furnace. The sample is placed on the microbalance and the temperature is progressively increased. The data generated is the percent weight remaining on the balance versus temperature. At lower temperatures, weight loss may arise from evaporation of residual moisture or solvent, but at higher temperatures it results from polymer decomposition. The beginning of this change is noted as the polymer degradation onset temperature.

The leaking seal had a lower polymer degradation onset temperature of 402ºC whereas the non-leaking seal was 451ºC. Both seals contained the same amount of mineral filler, as shown by the residual weight percent at 850ºC. However, the carbon black loading is different (measured by the difference in weight loss at 600ºC). The leaking seal has 25.4 weight percent carbon black compared to 29.2 percent for the non-leaking seal.

3.2 Akron Rubber Development Lab Tests

3.2.1 Approach

The compression stress relaxation (CSR) tests at ARDL measured sealing force using an industry-standard protocol (Compression Stress Relaxation, ASTM D6147/ (ISO 3384), Method B). It is possible to directly relate this measurement to the field behavior of the seals – the counterforce measured while subjecting the sample to constant strain is analogous to the sealing force provided by an elastomer seal in a tightened coupling.

In this test program we made use of three pressure vessels, each containing a number of NBR (Normac) and SBR (Dresser) sealing material samples installed in standard CSR jigs

  Vessel #1 contained three NBR samples and three SBR samples
 
  Vessel #2 contained three NBR samples
 
  Vessel #3 contained three SBR samples

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The instrument used was a Wykeham Farrance Compression Stress Relaxation Apparatus. The specimens tested were approximately cubical samples (8.15 mm x 8.15 mm x 6.55 mm) cut from aged elastomer seals. The samples were from seals that had been identified as leaking in the field.

A compressive strain of 25% was applied and all counterforce measurements were made at room temperature. At room temperature, the specimens were compressed to 25% strain within a 30 second period. Thirty minutes after this compression, with the jig/specimen assembly at room temperature, the initial counterforce measurement was made. In the same manner, subsequent counterforce measurements were made at room temperature after completion of 24, 48, 72, 168, 192, 216, 240, 336-hour time intervals. Testing was performed in triplicate using separate specimens.

At the start of testing all three vessels were filled with the pipeline gas to a pressure of 30 psig at ambient temperature. Sealing force measurements were made according to ARDL’s standard protocol for one week (i.e. after exposure for 30 min, 24 hr, 48 hr, 72 hr and 168 hr).

After 168 hours of exposure to the pipeline gas, Vessels #2 and #3 were switched to the Cove Point gas. Vessel #1 continued to use the pipeline gas. We again made force measurements according to the standard protocol for one week (again after an additional 30 min, 24 hr, 48 hr, 72 hr, 96 hr and 168 hr), and then weekly thereafter. In these tests, we were assessing whether the change from the pipeline gas to the Cove Point gas can cause a change in the measured sealing force.

Two separate CSR tests were run: the first test used a total of six NBR and six SBR samples, cut from one NBR and one SBR seal, and was run for 336 hours. The second test replicates the methodology of the first test, but using samples cut from a different NBR seal and a different SBR seal. This test has been run for 504 hours as of this writing, and is continuing. In both tests, half of the samples were switched to the LNG environment after 168 hours.

3.2.2 Test Results

The CSR test results are shown in Figures 6 and 7, below. The data are normalized such that the ratio of the measured counterforce to the initial counterforce is plotted as a function of time.

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NBR Only

(NBR SEALS CHART)

     
Figure 6
  Compression stress relaxation results for NBR seals. Test #1 was terminated after 336 hours. Test #2 is continuing.

SBR Only

(SBR SEALS CHART)

     
Figure 7
  Compression stress relaxation results for SBR seals. Test #1 was terminated after 336 hours. Test #2 is continuing.

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Several observations can be made on examination of the ARDL compression stress relaxation data:

  The NBR rubber relaxed considerably more than the SBR, whether exposed to the pipeline gas or the Cove Point LNG. This results in lower retained sealing forces in NBR-equipped Normac couplings than in SBR-equipped Dresser couplings of a similar vintage. This is consistent with the compression set data taken at PSI: the NBR material showed a higher compression set than the SBR material.
 
  In the first test, both the NBR and the SBR samples exposed to LNG showed a large reduction in sealing force at 336 hours relative to those that remained in the pipeline (or control) gas. The second test also showed a reduction in sealing force in the LNG environment, though less significant than in the first test. This slight reduction was also evident at 504 hours. The NBR material showed a more noticeable effect of the change to LNG than did the SBR material. These effects are consistent with the observed trends in volume, weight and hardness noted in the PSI tests.

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4. Other Investigations

4.1 LILCO Experience

In late January, 1992, LILCO begin to receive Canadian natural gas from the Iroquois pipeline through a gate station in western Suffolk county. Prior to this date, the region was supplied with gas from the Transcontinental (Transco) pipeline. Starting in February, 1992, LILCO began experiencing an increased number of leak reports. The leaks were traced to 3/4 inch Normac couplings used on gas services installed in the mid to late 1950s. LILCO retained the services of Lucius Pitkin, Inc. (LPI) to assist them in diagnosing the causes of the leaks. The LILCO response to the increased leak rate was investigated by the New York State Public Service Commission, which described the LPI work in its assessment.1

According to the NY PSC report, LPI concluded that the leaks in the couplings was due to the desorption of heavier hydrocarbons from the gaskets in the couplings, leading to a shrinkage in the gaskets, leading to a reduced sealing force and a leak path. The driving force for this desorption was the fact that the Iroquois gas contained significantly lower concentrations of heavy hydrocarbons compared to the Transco gas. This conclusion was based on a series of experiments conducted on seals removed from the field. LPI exposed seals to Transco and Iroquois (and other) gas environments and then performed weight measurements, dimensional analysis and load relaxation tests.

The change in C5+ content from Transco to Iroquois gas was from ~1500 to ~300 ppm, with C6+ being reduced from ~500 to ~100 ppm. This change in C5+ concentration is comparable to that experienced by WG in PG County with the change from pipeline gas to Cove Point LNG (see Table 9).

     
Table 9
  Comparison of changes in gas composition in the LILCO and Washington Gas systems (Concentrations in volume percent).
                                 
    LILCO   Washington Gas
    Transco   Iroquois   Shenandoah   Cove Point
Methane
    95.400       94.900       94.142       95.601  
Ethane
    2.380       2.200       3.039       3.540  
Propane
    0.560       0.230       0.662       0.400  
Butanes
    0.340       0.050       0.229       0.044  
Pentanes
    0.100       0.020       0.077       0.011  
C6+
    0.050       0.010       0.029       0.000  
Nitrogen
    0.300       1.800       0.776       0.405  
Carbon Dioxide
    0.850       0.700       1.047       0.000  
 
1   State of New York, Department of Public Service, Case 93-G-0401, Report dated July 26, 1993.

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4.2 Ground Movement

We evaluated the likely contribution of ground movement, caused either by earthquake or by excessive ground water factors. An earthquake of magnitude 4.5, occurred in December 2003, with an epicenter location in Virginia, approximately 155 km southwest of Prince Georges County. It is known that seismic induced ground motion can result in pipeline leaks and/or ruptures resulting from ground deformation under certain geologic and hydrogeologic conditions, given an earthquake of sufficient strength.

Leaks and/or ruptures in buried pipelines due to seismic impacts can result from either ground-strain due to seismic wave propagation or permanent ground deformation and failure (e.g., landslides, liquefaction, differential settling/subsidence) Buried pipeline damage is much more likely to result from permanent ground deformation (e.g., liquefaction), than from wave propagation effects.

Ground motion due to differential settling/subsidence of soils, is typically associated with earthquakes having a magnitude > 6.3. During the past 40 years, no earthquake within 200 km of Prince Georges County has exceeded a magnitude of 5.0; and only five earthquakes have exceeded a magnitude of 4.0. They are listed in Table 10

     
Table 10
  Earthquakes within 200 km of Prince Georges County, MD since 1984.
                     
                    Approx. Distance from Prince
    Month/       EQ   Georges County (City of
Year   Day   State   Magn.   Brandywine)
1984
  April 23   PA   4.4     ~145 km North
1984
  Aug. 17   VA   4.2     ~150 km Southwest
1994
  Jan. 16   PA   4.2     ~190 km North/Northeast
1994
  Jan. 16   PA   4.6     ~190 km North/Northeast
2003
  Dec. 9   VA   4.5     ~155 km South/Southwest

Ground liquefaction is associated with:

  Favorable near-surface geologic/soil conditions
 
  A shallow water table (< 30 feet)
 
  Earthquake intensities (Modified Mercalli Intensity, MMI) ³ VI2
 
2   Earthquake strength can be expressed both quantitatively in terms of magnitude (the Richter Scale) and qualitatively in terms of intensity (the Modified Mercalli Scale).

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Liquefaction is more likely to occur in unconsolidated water-saturated granular soils. In-situ soil tests are typically used to evaluate the potential for liquefaction. Although site-specific tests were not performed for this investigation, it is known that both Prince Georges County and the eastern portion of Fairfax County are underlain by un-consolidated gravel, sand, silt, and clay sediments, which increase in thickness towards the Chesapeake Bay. Therefore, it is possible that some soils in these areas may be susceptible to liquefaction given an earthquake of sufficient strength.

A shallow water table (within <30 feet of the ground surface) has also been associated with increased risk for liquefaction. Based on USGS well measurements, normal water table depth in Prince Georges County is < 30 feet (USGS Groundwater Database). Above-normal rainfall resulted in water table depths of < 20 feet in Prince Georges County during 1983/1984, 1993/1994, 1997/1998 and 2003.

Ground motion due to liquefaction is typically associated with earthquakes having an Modified Mercalli Intensity (MMI) ³ VI. The 2003 Virginia earthquake (magnitude 4.5) was felt in the Washington D.C. area. Although reported intensities at the epicenter (approximately 155 kilometers southwest of Prince Georges County) ranged from V to VI, see Figure 8, reported intensities in the Washington D.C. area ranged from II – IV, and are therefore very unlikely to have resulted in liquefaction of soils in this area which includes Prince Georges County. These intensities are defined as follows:

MMI II: Felt only by a few persons at rest, especially on upper floors of buildings. Delicately suspended objects may swing.

MMI III: Felt quite noticeably indoors, especially on upper floors of buildings, but many people do not recognize it as an earthquake. Standing motor cars may rock slightly. Vibration like passing truck. Duration estimated.

MMI IV: During the day felt indoors by many, outdoors by few. At night some awakened. Dishes, windows, and doors disturbed; walls make creaking sound. Sensation like heavy truck striking building. Standing motorcars rock noticeably.

In summary, we believe that the 2003 VA earthquake is unlikely to have resulted in sufficient ground motion to damage the utility pipelines in Prince Georges County for the following reasons:

  Ground subsidence is associated with earthquakes of greater magnitude (>6.3), much greater than the 2003 VA earthquake; and

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(COMMUNITY INTENSITY MAP)

     
Figure 8
  Reported intensities for December 2003 earthquake.

  Although geologic and hydrogeologic conditions in Prince Georges county suggest the potential for liquefaction, the observed intensity of the 2003 VA earthquake in the vicinity of the Prince Georges county (intensity range: II-IV) is very unlikely to have resulted in ground liquefaction.

4.3 Historical Data

A year-by-year analysis of the leaking couplings from the last two winters shows a clear peak in leaks in those installed in the timeframe 1962-1965, see Figure 9.

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Miles of Main and Leaks per Year

(MAINS AND LEAKS CHART)

     
Figure 9
  Miles of main installed by year and reported leaks for the last two heating seasons, plotted by year of installation of coupling.

However, this period was one of major expansion, and significant numbers of couplings were installed. The charts below (Figures 10 & 11) show the number of purchases of each manufacturer’s couplings by year for the 2 inch and 3/4 inch sizes. Figure 12 shows the percentage leak rate by year of installation. This data was developed by adding the leaks for each year of installation over the last two winters and dividing the total by the number of 3/4 inch and 2 inch couplings purchased that year. As we do not have installation data by year, we assume that couplings were installed in the year of purchase. The data in Figure 12 still shows that couplings installed in the period 1962-1965 are leaking at a higher rate than those installed later, though the difference in leak rate is not as pronounced when normalized by number of installations in this manner. This points to a difference in either product quality or installation practice in this timeframe.

It is worth noting that the installation years which are showing the highest leak rate (1962-1965) correspond to those years in which Normac purchases were approximately equivalent to Dresser purchases. In other years (with the exception of 3/4 inch purchases in 1968-1969), Normac couplings were not purchased. We do not have data on the relative leak rates of Normac and Dresser couplings over the last two winters.

Use of Normac couplings was discontinued by WG in 1966 and no further purchases of 2” Normac couplings were made. However, in 1968-1969, 3/4 inch Normac couplings were again used by WG.

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Figure 10
  Purchasing history for 3/4 inch couplings.

     
Figure 11
  Purchasing history for 2 inch couplings.

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(LEAK RATE CHART)

     
Figure 12
  Percentage leak rate (over last two winters) by year of coupling purchase and assumed installation.

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5. Conclusions

Several conclusions can be drawn from the experimental program and data review conducted thus far.

  Differences in weight change, volume change and micro-hardness change were observed between seals exposed to pipeline gas and those exposed to re-vaporized Cove Point LNG. Those exposed to LNG show a slight increase in hardness, a slight decrease in weight and a slight decrease in volume compared to those exposed to pipeline gas. These differences are consistent with desorption of C5+ compounds from the seals in the LNG environment.
 
  The change from the pipeline gas environment to the re-vaporized LNG environment can affect the retained sealing force of both the SBR (Dresser) and NBR (Normac) seals used in the compression couplings installed by WG between the 1950s and the 1970s. The impact appears to be greater on the NBR material than on the SBR material. The direction of the effect observed supports the hypothesis that the change to a lower C5+ gas caused seal shrinkage, and that this can be a contributing factor to the increased rate of leakage of compression couplings.
 
  There are at least two different formulations of NBR elastomer present in the Normac couplings in PG County. One shows a much greater volume swell in hexane than the other and would therefore be expected to be more susceptible to effects of changes in gas composition.
 
  There is a higher incidence of leaks in couplings installed in the years when Normac couplings represented a significant fraction of the total number installed.

The LILCO (now Keyspan) experience on Long Island in 1992-1993 appears very relevant. The independent lab retained by LILCO concluded that the reduction in heavy hydrocarbon concentrations as the transition from Transco to Iroquois gas occurred was indeed the proximate cause of the rash of leaks experienced in Normac service couplings.

The evidence supports our principal hypothesis, which is as follows:

  1.   All couplings undergo compression stress relaxation over the many years of operation, reducing sealing force progressively.
 
  2.   All couplings reach an equilibrium degree of elastomer swelling due to adsorption of moisture and C5+ compounds present in the pipeline gas.
 
  3.   In certain parts of the network, exposure to LNG results in slight elastomer shrinking, due to desorption of C5+.
 
  4.   These three factors result in a set of seals that are marginal.
 
  5.   As the winter season starts, the ground temperature falls, resulting in additional shrinkage of the elastomer, leading to leaks in the marginal seals.

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  6.   As spring comes, the ground temperature increases and the leak reporting rate falls back to the historical norm.

Our test results indicate that the change to LNG is a contributing factor, in that a change in gas composition causes shrinkage in the seals leading to a reduction in sealing force. However, the seal population in general contains a subset that is sealing marginally: this is evidenced by the normal rate of seal leaks in all parts of the WG network, including those which have not been exposed to LNG.

There is no fundamental incompatibility between re-vaporized LNG and the compounds used in the NBR and SBR seals used by Normac and Dresser. In fact, we would hypothesize that properly installed seals exposed only to re-vaporized LNG would function well for decades also.

Thus we conclude that a combination of factors contributes to the observed spikes in leaks:

  Aging Seals. Seals of various rubber formulations have been in service in the WG network for 30 to 50 years. A small fraction of these seals will have undergone compression stress relation to the point of sealing only marginally.
 
  A Change in Gas Composition. The change to a gas that has a lower concentration of C5+ compounds, caused a slight shrinkage in some seals due to de-sorption of previously adsorbed C5+ compounds (especially those seals with an elastomer formulation with a high solvent swell index).
 
  A Temperature Decrease. The onset of winter caused a further slight seal shrinkage as the ground cooled, due to differential thermal expansion effects in the coupling.

Finally, it should be noted that the adsorption/desorption of heavy hydrocarbons by elastomer seal materials is a reversible process. In further experiments we hope to demonstrate the potential for restoring sealing force by doping the LNG with small quantities of hexanes and/or pentanes.

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