-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, QgxSdnF9DBROg+D4ULWYD9DlIoh6nK/Z4PlPojs/JVQG1xeNBUvWMxWVO2rjEx+A llivBmEoiNqkGtXaMbs0HQ== 0000893220-96-001781.txt : 19961205 0000893220-96-001781.hdr.sgml : 19961205 ACCESSION NUMBER: 0000893220-96-001781 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 4 CONFORMED PERIOD OF REPORT: 19960930 FILED AS OF DATE: 19961031 SROS: NONE FILER: COMPANY DATA: COMPANY CONFORMED NAME: COLUMBIA GAS SYSTEM INC CENTRAL INDEX KEY: 0000022099 STANDARD INDUSTRIAL CLASSIFICATION: 4923 IRS NUMBER: 131594808 STATE OF INCORPORATION: DE FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-Q SEC ACT: 1934 Act SEC FILE NUMBER: 001-01098 FILM NUMBER: 96651003 BUSINESS ADDRESS: STREET 1: 12355 SUNRISE VALLEY DRIVE STREET 2: SUITE 300 CITY: RESTON STATE: VA ZIP: 20191-3458 BUSINESS PHONE: 7032950394 MAIL ADDRESS: STREET 1: 12355 SUNRISE VALLEY DRIVE STREET 2: SUITE 300 CITY: RESTON STATE: VA ZIP: 20191-3458 10-Q 1 FORM 10-Q, THE COLUMBIA GAS SYSTEM, INC. 1 FORM 10-Q SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 /X/ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the Quarterly period ended September 30, 1996 / / TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the Transition period from ______ to ______ Commission file number 1-1098 THE COLUMBIA GAS SYSTEM, INC. ------------------------------------------------------ (Exact Name of Registrant as Specified in its Charter) Delaware 13-1594808 ------------------------------- ------------------- (State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification No.) 12355 Sunrise Valley Drive, Suite 300, Reston, VA 20191-3420 ------------------------------------------------------------ (Address of principal executive offices) (Zip Code) Registrant's telephone number, including area code (703) 295-0300 Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes X No ----- ------ Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date: Common Stock, $10 Par Value: 55,206,184 shares outstanding at September 30, 1996. 2 THE COLUMBIA GAS SYSTEM, INC. AND SUBSIDIARIES FORM 10-Q QUARTERLY REPORT FOR THE QUARTER ENDED SEPTEMBER 30, 1996 TABLE OF CONTENTS
Page ---- PART I FINANCIAL INFORMATION Item 1 Financial Statements Statements of Consolidated Income 1 Condensed Consolidated Balance Sheets 2 Consolidated Statements of Cash Flows 3 Consolidated Statements of Common Stock Equity 4 Notes 5 Item 2 Management's Discussion and Analysis of 7 Financial Condition and Results of Operations PART II OTHER INFORMATION Item 1 Legal Proceedings 25 Item 2 Changes in Securities 29 Item 3 Defaults Upon Senior Securities 29 Item 4 Submission of Matters to a Vote of Security Holders 29 Item 5 Other Information 29 Item 6 Exhibits and Reports on Form 8-K 29 Signature 30
3 PART 1 - FINANCIAL INFORMATION ITEM 1 - FINANCIAL STATEMENTS The Columbia Gas System, Inc. and Subsidiaries STATEMENTS OF CONSOLIDATED INCOME (LOSS) (unaudited)
THREE MONTHS NINE MONTHS ENDED SEPTEMBER 30, ENDED SEPTEMBER 30, ------------------- ------------------- 1996 1995 1996 1995 ---- ---- ---- ---- (MILLIONS) OPERATING REVENUES Gas sales $ 315.3 $ 213.8 $1,749.6 $1,353.9 Transportation 99.6 101.5 355.5 337.0 Other 35.9 51.0 131.1 160.7 ------- ------- -------- -------- Total Operating Revenues 450.8 366.3 2,236.2 1,851.6 ------- ------- -------- -------- OPERATING EXPENSES Products purchased 144.0 40.4 901.7 570.3 Operation 182.2 189.0 603.6 599.0 Maintenance 27.8 31.4 79.1 84.8 Depreciation and depletion 38.8 56.6 157.8 200.2 Other taxes 37.1 34.6 158.9 156.2 ------- ------- -------- -------- Total Operating Expenses 429.9 352.0 1,901.1 1,610.5 ------- ------- -------- -------- OPERATING INCOME 20.9 14.3 335.1 241.1 ------- ------- -------- -------- OTHER INCOME (DEDUCTIONS) Interest income and other, net 22.2 3.7 39.0 12.5 Interest expense and related charges* (51.8) (4.1) (134.7) (16.3) Reorganization items, net - 18.9 - 51.4 ------- ------- -------- -------- Total Other Income (Deductions) (29.6) 18.5 (95.7) 47.6 ------- ------- -------- -------- INCOME (LOSS) BEFORE INCOME TAXES (8.7) 32.8 239.4 288.7 Income Taxes (2.6) 13.5 86.0 109.7 ------- ------- -------- -------- NET INCOME (LOSS) $ (6.1) $ 19.3 $ 153.4 $ 179.0 ======= ======= ======== ======== EARNINGS (LOSS) PER SHARE OF COMMON STOCK $ (0.11) $ 0.38 $ 2.88 $ 3.54 ======= ======= ======== ======== DIVIDENDS PAID PER SHARE OF COMMON STOCK $ 0.15 $ - $ 0.45 $ - AVERAGE COMMON SHARES OUTSTANDING (thousands) 55,165 50,574 53,340 50,569
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements. * Due to the bankruptcy filings, interest expense of approximately $67 million was not recorded for the three months ended September 30, 1995, and approximately $199 million was not recorded for the nine months ended September 30, 1995. Reference is made to the accompanying Notes and Management's Discussion and Analysis for information related to the 1991 to 1995 Chapter 11 bankruptcy proceedings involving The Columbia Gas System, Inc. and Columbia Gas Transmission Corporation (a wholly-owned subsidiary). 1 4 PART 1 - FINANCIAL INFORMATION ITEM 1 - FINANCIAL STATEMENTS (CONTINUED) The Columbia Gas System, Inc. and Subsidiaries CONDENSED CONSOLIDATED BALANCE SHEETS
As of ------------------------------------------ September 30, 1996 December 31, 1995 ------------------ ----------------- (unaudited) (millions) ASSETS PROPERTY, PLANT AND EQUIPMENT Gas utility and other plant, at original cost $ 6,891.1 $ 6,903.2 Accumulated depreciation and depletion (3,307.7) (3,322.0) --------- --------- Net Gas Utility and Other Plant 3,583.4 3,581.2 --------- --------- Oil and gas producing properties, full cost method 516.2 516.3 Accumulated depletion (155.3) (141.1) --------- --------- Net Oil and Gas Producing Properties 360.9 375.2 --------- --------- Net Property, Plant and Equipment 3,944.3 3,956.4 --------- --------- INVESTMENTS AND OTHER ASSETS 106.8 354.6 --------- --------- CURRENT ASSETS Cash and temporary cash investments 19.1 8.0 Accounts receivable, net 261.8 511.0 Income tax refund - 271.5 Gas inventory 316.5 172.3 Other inventories - at average cost 45.5 41.5 Prepayments 60.6 56.9 Regulatory assets 63.2 76.5 Other 263.5 138.2 --------- --------- Total Current Assets 1,030.2 1,275.9 --------- --------- REGULATORY ASSETS 420.9 422.0 DEFERRED CHARGES 47.9 48.1 --------- --------- TOTAL ASSETS $ 5,550.1 $ 6,057.0 ========= ========= CAPITALIZATION AND LIABILITIES CAPITALIZATION Common stock equity $ 1,491.1 $ 1,114.0 Preferred stock - 399.9 Long-term debt 2,004.0 2,004.5 --------- --------- Total Capitalization 3,495.1 3,518.4 --------- --------- CURRENT LIABILITIES Short-term debt 110.0 338.9 Accounts and drafts payable 156.0 215.7 Accrued taxes 166.0 271.3 Accrued interest 54.8 94.3 Estimated rate refunds 104.4 96.1 Estimated supplier obligations 121.2 178.3 Transportation and exchange gas payable 40.9 46.7 Other 337.9 337.3 --------- --------- Total Current Liabilities 1,091.2 1,578.6 --------- --------- OTHER LIABILITIES AND DEFERRED CREDITS Income taxes, noncurrent 516.5 468.6 Postretirement benefits other than pensions 174.1 208.2 Regulatory liabilities 44.1 44.9 Other 229.1 238.3 --------- --------- Total Other Liabilities and Deferred Credits 963.8 960.0 --------- --------- TOTAL CAPITALIZATION AND LIABILITIES $ 5,550.1 $ 6,057.0 ========= =========
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements. 2 5 PART 1 - FINANCIAL INFORMATION ITEM 1 - FINANCIAL STATEMENTS (CONTINUED) The Columbia Gas System, Inc. and Subsidiaries CONSOLIDATED STATEMENTS OF CASH FLOWS (unaudited)
Nine Months Ended September 30, --------------------------------- 1996 1995 ---- ---- (millions) OPERATIONS ACTIVITIES Net Income $ 153.4 $ 179.0 Adjustments for items not requiring (providing) cash: Depreciation and depletion 157.9 200.2 Deferred income taxes 31.7 71.4 Other - net* 39.5 (11.5) Change in components of working capital: Accounts receivable 270.3 234.9 Income tax refunds 271.5 - Gas inventory (144.2) (33.7) Prepayments (3.2) 59.0 Accounts payable (12.8) (16.0) Accrued taxes (125.5) (78.9) Accrued interest (39.7) (0.8) Estimated rate refunds 8.3 (75.4) Estimated supplier obligations (57.1) (9.9) Under/Overrecovered gas costs (128.9) 42.4 Exchange gas payable (7.8) 9.1 Other working capital 64.1 (11.9) --------- --------- Net Cash From Operations 477.5 557.9 --------- --------- INVESTMENT ACTIVITIES Capital expenditures (202.6) (270.6) Net Proceeds received on the sale of Columbia Development 190.9 - Other investments - net 11.6 6.1 --------- --------- Net Investment Activities (0.1) (264.5) --------- --------- FINANCING ACTIVITIES Retirement of preferred stock (400.0) - Retirement of long-term debt (0.8) (0.5) Dividends paid (23.9) - Issuance of common stock 248.4 - Net decrease in revolving credit facility (228.9) - Other financing activities (61.1) (15.1) --------- --------- Net Financing Activities (466.3) (15.6) --------- --------- Increase in Cash and Temporary Cash Investments 11.1 277.8 Cash and temporary cash investments at beginning of year 8.0 1,481.8 --------- --------- Cash and temporary cash investments at September 30** $ 19.1 $ 1,759.6 ========= ========= SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION Cash paid for interest 79.7 0.4 Cash paid for income taxes (net of refunds) (158.6) 40.8
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements. * 1995 includes changes in Liabilities Subject to Chapter 11 Proceedings of $4.2 million. **The Corporation considers all highly liquid debt instruments to be cash equivalents. Reference is made to the accompanying Notes and Management's Discussion and Analysis for information related to the 1991 to 1995 Chapter 11 bankruptcy proceedings involving The Columbia Gas System, Inc. and Columbia Gas Transmission Corporation (a wholly-owned subsidiary). 3 6 PART 1 - FINANCIAL INFORMATION ITEM 1 - FINANCIAL STATEMENTS (CONTINUED) The Columbia Gas System, Inc. and Subsidiaries CONSOLIDATED STATEMENTS OF COMMON STOCK EQUITY
As of -------------------------------------------- September 30, December 31, 1996 1995 --------------------- -------------------- (unaudited) (millions) COMMON STOCK EQUITY Common stock, $10 par value, authorized 100,000,000 shares, outstanding 55,206,184 shares and 49,204,025 shares, respectively $ 552.1 $ 506.2 Additional paid in capital 741.2 595.8 Retained earnings 199.3 69.8 Unearned employee compensation (1.5) - Cost of treasury stock (1,416,155 shares outstanding as of December 31, 1995) - (57.8) -------- -------- TOTAL COMMON STOCK EQUITY $1,491.1 $1,114.0 ======== ========
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements. 4 7 PART 1 - FINANCIAL INFORMATION ITEM 1 - FINANCIAL STATEMENTS (CONTINUED) The Columbia Gas System, Inc. and Subsidiaries NOTES 1. Basis of Accounting Presentation The accompanying unaudited condensed consolidated financial statements for The Columbia Gas System, Inc. (Columbia) reflect all normal recurring adjustments which are necessary, in the opinion of management, to present fairly the results of operations in accordance with generally accepted accounting principles. The accompanying financial statements should be read in conjunction with the financial statements and notes thereto included in Columbia's 1995 Annual Report on Form 10-K and 1996 First and Second Quarter Form 10-Qs. Income for interim periods may not be indicative of results for the calendar year due to weather variations and other factors. Certain reclassifications have been made to the 1995 financial statements to conform to the 1996 presentation. 2. Bankruptcy Matters On November 28, 1995, Columbia and its wholly-owned subsidiary, Columbia Gas Transmission Corporation (Columbia Transmission), emerged from Chapter 11 protection of the Federal Bankruptcy Code under the jurisdiction of the United States Bankruptcy Court for the District of Delaware (Bankruptcy Court). Both Columbia and Columbia Transmission had operated under Chapter 11 protection since July 31, 1991. Certain residual unresolved bankruptcy-related matters are still within the jurisdiction of the Bankruptcy Court. Unsettled Producer Claims Columbia Transmission's approved plan of reorganization (Plan) provided that producers who rejected settlement offers contained in Columbia Transmission's Plan may continue to litigate their claims under the Bankruptcy Court-approved claims estimation procedures, described below, and receive the same percentage payout on their allowed claims, when and if ultimately allowed, as received by the settling producers. Columbia Transmission's Plan further provided that the actual distribution percentage for all producer claims, which would not be less than 68.875% or greater than 72.5%, could not be determined until the total amount of contested producer claims is established, and until such time, 5% of the maximum amount (based on a 72.5% payout) to be distributed to producer claimants for allowed claims and to Columbia for unsecured debt will be withheld. Additional distributions, if any, will be made when the total amount of allowed producer claims has been determined. Producer Claims Estimation Process In 1992, the Bankruptcy Court approved the appointment of a claims mediator and the implementation of a claims estimation procedure for the quantification of claims arising from the rejection of above-market gas purchase contracts and other claims by producers related to gas purchase contracts with Columbia Transmission. In late 1994 and early 1995, the claims mediator issued initial and supplemental reports on Generic Issues for Natural Gas Contract 5 8 PART 1 - FINANCIAL INFORMATION ITEM 1 - FINANCIAL STATEMENTS (CONTINUED) Claims and directed producer claimants to submit recalculated claims. The recommendations and instructions set out in the reports have not been considered by the Bankruptcy Court. In mid-1995, most producers with which Columbia Transmission had not yet negotiated settlements submitted recalculated claims to the claims mediator. Those recalculated claims amounted to over $2 billion. Since mid- 1995, numerous additional producers have settled their claims and those settlements became final with the confirmation of Columbia Transmission's Plan. In addition, several recalculated claims have been amended by producer claimants, and several claims have been resolved by means of litigation within the claims estimation process. The claims estimation procedures remain in place for use in the post-confirmation liquidation of those producer claims that remain unresolved. The claims administrator is holding evidentiary hearings with respect to individual producer claims, including claim- specific issues not addressed by the report. Recommendations made by the claims mediator are subject to review by the Bankruptcy Court and all parties have rights of appellate review. When claims are allowed by the Bankruptcy Court and the allowances become final, Columbia Transmission will make distributions with respect to those claims pursuant to the Plan. The timing of this litigation process is impossible to predict. The 5% holdback from settling producers and a matching contribution by the reorganized Columbia Transmission will be used, to the extent necessary, to fund any distributions on producer claims ultimately liquidated in an aggregate amount in excess of those proposed by Columbia Transmission's Plan. If the holdback and matching contributions are exhausted, any further distribution would be funded entirely by Columbia Transmission. Columbia has guaranteed the payments to producers after exhaustion of the holdback amounts, either in cash or in Columbia's common stock. Based on the information received and evaluated to date, Columbia Transmission believes adequate reserves have been established for resolution of the remaining producer claims and the payment of any amounts ultimately due to producers with respect to the 5% holdback. 3. Sale of Southwest Oil and Gas Subsidiary On April 30, 1996, Columbia sold Columbia Gas Development Corporation (Columbia Development), effective December 31, 1995, to a privately-held exploration and production concern for approximately $200 million. Columbia Development had approximately 196 billion cubic feet equivalent of proved oil and natural gas reserves located in the Gulf of Mexico and on-shore continental United States. An estimated loss of $54.8 million after-tax was recorded in the fourth quarter of 1995 to reflect the sale of this subsidiary. In the second quarter of 1996 an adjustment was recorded that reduced the loss to $49.2 million. 6 9 PART 1 - FINANCIAL INFORMATION ITEM 2 - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS OPERATING INCOME (LOSS) BY SEGMENT
Three Months Nine Months Ended September 30, Ended September 30, ------------------- ------------------- 1996 1995 1996 1995 ---- ---- ---- ---- (millions) Transmission $ 36.0 $ 41.3 $ 160.4 $ 153.8 Distribution (19.3) (25.5) 145.7 82.8 Oil and Gas 5.4 (0.4) 22.6 (0.7) Other Energy 1.4 2.8 15.0 12.4 Corporate (2.6) (3.9) (8.6) (7.2) ------ ------ ------ ------ TOTAL $ 20.9 $ 14.3 $335.1 $241.1 ====== ====== ====== ======
DEGREE DAYS (DISTRIBUTION SERVICE TERRITORY)
Three Months Nine Months Ended September 30, Ended September 30, ------------------- ------------------- 1996 1995 1996 1995 ---- ---- ---- ---- Actual 103 102 3,910 3,484 Normal 41 41 3,600 3,568 % Colder (warmer) than normal 151 149 9 (2) % Colder (warmer) than prior period 1 4 12 (10)
7 10 PART 1 - FINANCIAL INFORMATION ITEM 2 - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED) CONSOLIDATED RESULTS Three Month Results Net Income (Loss) Columbia reported a third quarter net loss of $6.1 million, or $0.11 per share,whereas last year, when Columbia was in Chapter 11 and recorded no interest expense for prepetition debt obligations, net income was $19.3 million, or $0.38 per share. After adjusting for unrecorded interest and other unusual items, Columbia's third quarter 1996 results improved $11.5 million over the same period last year. In the current quarter, Columbia had an adjusted net loss of $3.6 million compared to an adjusted loss of $15.1 million in the third quarter of 1995. This improvement reflects higher rates for the regulated subsidiaries and increased wellhead prices for gas production. Also contributing to the increase was lower operation and maintenance expense due in part to efficiencies gained through recently implemented reengineering initiatives. The current period adjustments included $2.5 million for the after-tax effect of reengineering severance costs and the prior period included $34.4 million after-tax for bankruptcy-related issues, primarily interest costs not recorded. Unusual and Bankruptcy-Related Items After-tax effect on Net Income (millions)
Three Months Nine Months Ended September 30, Ended September 30, ------------------- -------------------- 1996 1995 1996 1995 ---- ---- ---- ---- Reported net income (loss) $(6.1) $ 19.3 $153.4 $179.0 Less (plus): Estimated interest costs not recorded - 42.9 - 126.3 Bankruptcy-related professional fees and related expenses - (8.5) - (23.1) Reengineering costs (2.5) - (21.1) - Adjustment to the sale of Columbia Development - - 5.6 - ----- ------ ------ ------ Total adjustments (2.5) 34.4 (15.5) 103.2 ----- ------ ------ ------ Net income (loss) after adjusting for unusual and bankruptcy items $(3.6) $(15.1) $168.9 $ 75.8 ===== ====== ====== ======
Revenues For the third quarter of 1996, operating revenues were $450.8 million, an $84.5 million increase over the same period last year, reflecting higher rates in place for Columbia Transmission, subject to regulatory approval, as well as higher rates for four of the five distribution subsidiaries, increased wellhead prices for gas production and additional sales by the gas marketing operations. Tempering these improvements was a decrease in oil and gas production revenues resulting from the sale of the southwest oil and gas subsidiary, Columbia Development, effective year end 1995. The third quarter last year was also improved by $6.8 million for revenues recorded for exit fees received by Columbia Gulf Transmission Company (Columbia Gulf). Expenses Operating expenses for the three months ended September 30, 1996, of $429.9 million, increased $77.9 million over last year due to $103.6 million higher product purchase expense primarily reflecting 8 11 PART 1 - FINANCIAL INFORMATION ITEM 2 - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED) CONSOLIDATED RESULTS (CONTINUED) increased gas purchased for resale by the gas marketing function. In addition, the current period included $3.9 million of restructuring expense and a charge recorded by Columbia Transmission to reflect an unfavorable court decision that overturned an earlier FERC ruling (see discussion on page 14 for more information). Partially offsetting these higher costs was lower operation and maintenance expense due to the sale of Columbia Development and the favorable effect of restructuring activities recently implemented that have reduced costs and improved customer service. The $17.8 million decrease in depreciation and depletion expense largely reflected the sale of Columbia Development. Higher franchise and property taxes were the principal reason for a $2.5 million increase in other taxes. Other Income (Deductions) Interest expense on long-term debt obligations of $35.1 million was the primary reason that Other Income (Deductions) reduced income $29.6 million in the current period. No interest expense was recorded in the same period last year due to Columbia's Chapter 11 status. Included in Interest Income and Other, Net for the current quarter was a $13.4 million adjustment to interest income associated with the court decision that overturned an earlier FERC ruling, mentioned above. This amount is offset in Interest Expense and Related Charges and has no effect on income. Also improving income was a $1.8 million gain on the sale of Columbia Gulf's interest in its Overthrust pipeline partnership. Other Income (Deductions) for the third quarter of 1995 improved income $18.5 million due to $29.2 million of interest earned on cash accumulated while in Chapter 11 partially offset by $10.3 million of professional fees and related services. Nine Month Results Net Income Reported net income for the nine months ended September 30, 1996, was $153.4 million, or $2.88 per share, compared to $179 million, or $3.54 per share last year. The 1995 results did not reflect interest expense on prepetition debt obligations, because Columbia was in Chapter 11. After adjusting for unusual items, colder weather and higher rates in effect during 1996 led to Columbia's year-to-date net income of $168.9 million, up $93.1 million. After adjustments, all of Columbia's segments had improved results. Included in unusual items for the first nine months of 1996 was $21.1 million for the after-tax effect of reengineering costs, primarily for severance expense, and a $5.6 million improvement to net income for a favorable adjustment to the sale of Columbia Development. Bankruptcy- related items in the prior period consisted of $126.3 million for the after-tax effect of not recording interest expense on prepetition debt obligations and a decrease to net income of $23.1 million for bankruptcy-related professional fees and related services. Revenues Operating Revenues for 1996 of $2,236.2 million increased $384.6 million over the first nine months of last year. Increased sales by the distribution subsidiaries and gas marketing operations, due in part to colder weather in early 1996, higher rates in effect for the regulated subsidiaries 9 12 PART 1 - FINANCIAL INFORMATION ITEM 2 - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED) CONSOLIDATED RESULTS (CONTINUED) as well as higher wellhead prices for Appalachian gas production more than offset the lower revenues resulting from the sale of Columbia Development. In addition, last year included $12.2 million of additional revenues recorded for exit fees paid to Columbia Gulf. Expenses Through September 30, 1996, operating expenses of $1,901.1 million, increased $290.6 million over last year due primarily to $331.4 million in higher product purchase expense reflecting increased sales requirements, higher gas prices and the unfavorable court decision mentioned previously. Also contributing to higher expenses was $32.5 million of severance costs recorded during 1996 as part of Columbia's reengineering initiatives to improve customer service and reduce costs. Partially offsetting these increases was the elimination of operation and maintenance expense associated with Columbia Development and the favorable effect of restructuring activities recently implemented. Also contributing to a decrease in expenses was $42.4 million lower depreciation and depletion expense as a result of reduced depletable plant due to the sale of Columbia Development, a lower depletion rate attributable to higher natural gas prices, partially offset by additional plant in service and higher depreciation rates for the regulated subsidiaries. Other Income (Deductions) Other Income (Deductions) reduced income $95.7 million for the first nine months of 1996, primarily reflecting interest expense on long-term debt of $105.4 million in the current period. Improving income this year was a $8.6 million favorable adjustment for the sale of Columbia Development and, as mentioned previously the gain on the sale of Columbia Gulf's Overthrust partnership. Increasing both Interest Income and Other, Net and Interest Expense and Related Charges was the $13.4 million adjustment for the unfavorable court decision also previously discussed. In the same period last year income was improved $47.6 million for Other Income (Deductions). In the first nine months of 1995 no interest expense was recorded due to the bankruptcy proceedings. Other prior year bankruptcy-related issues include $79.2 million of interest earned on cash accumulated while in Chapter 11, partially offset by $27.8 million for professional fees and related services expense. Liquidity and Capital Resources For the nine months ended September 30, 1996, cash from operations was $477.5 million, a decrease of $80.4 million from the same period last year primarily reflecting a lag in the recovery by the distribution subsidiaries of gas costs in the current period together with increased prepayments, higher payments for estimated supplier obligations and payment of accrued interest. The lag in recovering gas costs resulted from the rise in prices during 1996 that exceeded the distribution subsidiaries' current recovery levels. These higher costs will be recovered over the next several months through future adjustments to the commodity portion of rates as provided for under the regulatory process. Conversely, in the prior period when gas prices were decreasing, the rates in place for the distribution subsidiaries led to an overrecovered position. Columbia's 1995 Federal Income Tax return included a net operating loss carryback claim to recover income taxes and was the principal reason for a $271.5 million improvement in working capital for income tax refunds. This claim, net of other adjustments and liabilities to the Internal Revenue Service (IRS), resulted in a cash refund in April 1996 of approximately $213 million. 10 13 PART 1 - FINANCIAL INFORMATION ITEM 2 - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED) CONSOLIDATED RESULTS (CONTINUED) Cash also improved for the favorable effect of colder weather that increased sales for the distribution subsidiaries, as well as higher base rates in effect for the regulated subsidiaries. Columbia maintains a $1 billion unsecured bank revolving credit facility (Credit Facility) that provides for a combination of borrowings and letters of credit. Scheduled quarterly reductions of $25 million of the committed amount begin December 31, 1997, and will reduce the Credit Facility to $700 million by September 30, 2000. Borrowings under the Credit Facility were used in February 1996, to redeem the 5.22% Series B-Preferred Stock and 7.89% Series A-Preferred Stock issued pursuant to Columbia's approved Plan of Reorganization. As of September 30, 1996, Columbia had $79.4 million of letters of credit outstanding under the Credit Facility and $110 million of short-term borrowings. Columbia has an effective shelf registration statement on file with the U.S. Securities and Exchange Commission (SEC) for the issuance of up to $1 billion in aggregate amount of debentures, common stock or preferred stock in one or more series. In March 1996, Columbia issued 5,750,000 shares of common stock under the shelf registration. Proceeds of $239.2 million from the issuance were used to reduce borrowings incurred under the Credit Facility. On April 30, 1996, Columbia received approximately $191 million from the sale of Columbia Development. The funds generated from this sale were used to reduce borrowings under the Credit Facility. Columbia believes that future cash requirements for normal ongoing operations and capital expenditures will be met with internally generated funds and amounts available under the Credit Facility. No further issuances under the shelf registration are contemplated at this time. Restructuring Activities Through the first nine months of 1996, $32.5 million (pre-tax) of expense was recorded to reflect current and future reengineering-related costs, primarily for severance and benefits. This reengineering initiative, called Project Phoenix, began in 1995 to streamline operations and make them more efficient and cost-competitive. The beneficial effect of any efficiencies gained will be realized through improved profitability of Columbia's operations and reduced rates being charged to customers of the regulated subsidiaries. These activities are expected to be substantially completed and implemented over the next few months and will result in additional expense being recorded in the fourth quarter of this year and early 1997. It is anticipated that the additional expense to be recorded will be approximately half of the amount recorded through the third quarter. As indicated in the results of operations for the third quarter, Columbia is beginning to realize lower operation and maintenance costs as a result of implementing these reengineering initiatives in its various operations. It is anticipated that the favorable effect of these initiatives will continue in the future as additional phases of the program are implemented. Once the project is fully implemented, which is expected by the end of 1997, the total number of employees System-wide is anticipated to decrease by approximately 10% from the year-end 1995 level of nearly ten thousand. 11 14 PART 1 - FINANCIAL INFORMATION ITEM 2 - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED) TRANSMISSION OPERATIONS
THREE MONTHS NINE MONTHS ENDED SEPTEMBER 30, ENDED SEPTEMBER 30, ------------------- ------------------- 1996 1995 1996 1995 ---- ---- ---- ---- (MILLIONS) OPERATING REVENUES Transportation revenues $130.5 $130.3 $451.1 $424.9 Storage revenues 40.2 34.6 119.4 98.6 Other revenues 3.2 10.2 11.0 25.7 ------ ------ ------ ------ Total Operating Revenues 173.9 175.1 581.5 549.2 ------ ------ ------ ------ OPERATING EXPENSES Operation and maintenance 102.8 96.9 300.9 279.4 Depreciation 20.9 26.1 76.1 77.8 Other taxes 14.2 10.8 44.1 38.2 ------ ------ ------ ------ Total Operating Expenses 137.9 133.8 421.1 395.4 ------ ------ ------ ------ OPERATING INCOME $ 36.0 $ 41.3 $160.4 $153.8 ====== ====== ====== ====== THROUGHPUT (BCF) Transportation Columbia Transmission Market-area 161.1 171.8 788.2 767.7 Columbia Gulf Main-line 145.9 143.3 475.2 450.0 Short-haul 69.3 55.5 202.7 159.9 Intrasegment eliminations (145.1) (141.8) (469.8) (443.8) ------ ------ ------ ------ Total Throughput 231.2 228.8 996.3 933.8 ====== ====== ====== ======
12 15 PART 1 - FINANCIAL INFORMATION ITEM 2 - MANAGEMENT S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED) TRANSMISSION OPERATIONS (CONTINUED) Regulatory Matters Secondary Market Transactions On July 31, 1996, the FERC issued a notice of proposed rulemaking (NOPR) that would revise capacity release provisions to (1) improve the operation of the FERC's capacity release program, (2) eliminate the competitive bidding requirement for capacity release transactions and (3) permit pipelines to sell interruptible and short-term firm service and shippers to release capacity at rates above the maximum cost-based rate cap, when the pipeline or shipper has demonstrated that it does not exercise market power. Columbia Transmission and Columbia Gulf filed comments to the NOPR in October 1996. In conjunction with the NOPR, the FERC proposed a pilot program for the 1996 winter heating season (November 1, 1996 through March 31, 1997) to permit interim implementation of the proposed changes to help assess whether compliance with the criteria is indicative of a lack of market power. On August 30, 1996, Columbia Transmission and Columbia Gulf filed applications to participate in the pilot program. Several interventions and protests were filed with respect to Columbia Transmission's and Columbia Gulf's applications, and both companies responded thereto on October 18, 1996. Certain distribution companies served by Columbia Transmission and Columbia Gulf also filed applications to participate in the pilot program. Columbia Transmission's Rate Filing In August 1995, Columbia Transmission filed with the FERC its first general rate case since 1991, requesting an increase in annual revenues of approximately $147 million. Columbia Transmission also proposed to recover its net investment in gathering and certain gas processing facilities over a period of five years. The FERC authorized the new rates to be implemented on February 1, 1996, subject to refund. However, in an effort to reach a timely resolution of the issues included in the filing, Columbia Transmission agreed to collect only 75% of the requested rate increase for an interim period. On August 30, 1996, a partial settlement was filed with an Administrative Law Judge which, if approved, would resolve an issue relating to whether Columbia Transmission's system-wide rates should be changed to reflect mileage or other factors relating to the distance that natural gas is transported. The proposed settlement calls for Columbia Transmission to maintain its current system-wide rate structure through November 1, 2004. Negotiations are ongoing with interested parties on the remaining issues in Columbia Transmission's general rate case. Environmental matters have been placed on a separate procedural track from the remaining issues in the case. Order 94 In 1985, certain pipeline suppliers of Columbia Transmission made FERC filings to recover, through direct billings, certain retroactive charges paid to producers by those pipelines for production-related costs pursuant to FERC Order No. 94 (Order 94). These costs were in turn allocated to each pipeline customer based upon its purchases from the pipeline during the early 1980s. Columbia Transmission and other parties challenged the legality of the past purchase allocation methodology under these direct billing orders. Following numerous proceedings involving the FERC and D.C. Circuit Court of Appeals, approved settlements were implemented with all but one upstream pipeline supplier, Transcontinental Gas Pipe Line Corporation (Transco). Transco appealed a FERC order to the D.C. Circuit Court of Appeals which issued a decision on September 10, 1996. The court's decision reversed a prior determination by the FERC and directed that a previous settlement reached between Columbia Transmission and Transco be reinstated. Adequate reserves were established in the third quarter of 1996 by Columbia Transmission to reflect the court's decision. Columbia Transmission 13 16 PART 1 - FINANCIAL INFORMATION ITEM 2 - MANAGEMENT S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED) TRANSMISSION OPERATIONS (CONTINUED) believes that the Bankruptcy Court continues to have jurisdiction over this issue and thus is evaluating the order to consider further action, if any. Partnership Issues In September 1996, Columbia Gulf recorded a gain of approximately $1.8 million for the sale of its partnership interest in the Overthrust Pipeline System to Questar Pipeline Company. Columbia Gulf held an 18% interest in the partnership at the time of the sale. Overthrust Pipeline, located in Wyoming, is the western-most part of the Trailblazer Pipeline System, which was placed into service in 1982. Columbia Gulf originally entered into the investment to provide a gas supply source for Columbia Transmission. Under Order 636, Columbia Transmission discontinued its merchant function which eliminated its need for this supply source. Appeals of Order 636 As discussed in the 1995 Form 10-K, numerous parties have filed petitions for review of FERC Order No. 636 (Order 636) with the D.C. Circuit Court (Circuit Court). In July 1996 the Circuit Court issued an order that generally upheld the FERC's actions, but it remanded to the FERC certain aspects of Order 636. Motions for reconsideration of the court's order have been filed and responses made by the FERC and certain distribution companies. As a result of these proceedings, Order 636 may be modified or reversed in whole or in part; however, at this time it is impossible to predict the outcome. Volumes Throughput of 231.2 Bcf for the third quarter reflected a small increase of 2.4 Bcf over the same period last year due primarily to a 13.8 Bcf increase in short-haul transportation. These higher deliveries were due to additional transportation to third parties made possible through new interconnections in Louisiana. Market-area transportation was 10.7 Bcf lower than the prior year due to additional transportation services needed in 1995 by electric generation facilities to meet increased demand. For the first nine months of 1996, throughput of 996.3 Bcf increased 62.5 Bcf over 1995. This improvement included a 42.8 Bcf increase in short-haul deliveries due largely to increased offshore supply at Vermillion and Eugene Island and new interconnections in Louisiana. Also contributing to the increase was 20.5 Bcf higher market-area transportation reflecting colder weather early in 1996. Operating Revenues Total operating revenues of $173.9 million for the three months ended September 30, 1996, decreased $1.2 million from the same period last year. After adjusting for the recovery of upstream transportation costs and certain other issues that are offset in operating expense and have no effect on operating income, including a depreciation expense adjustment, operating revenues increased $1.1 million. This improvement primarily reflected higher rates for Columbia Transmission that resulted from the implementation of its new general rate case that became effective in early 1996, subject to refund. Largely offsetting this increase over last year was $6.8 million of revenues recorded in 1995 by Columbia Gulf for exit fee payments it received. Through September 30, 1996, operating revenues of $581.5 million were up $32.3 million over the same period last year primarily reflecting new rates in place for Columbia Transmission since February 1996. Increasing 1995 results were $12.2 million of revenues recorded by Columbia Gulf for exit fees. 14 17 PART 1 - FINANCIAL INFORMATION ITEM 2 - MANAGEMENT S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED) TRANSMISSION OPERATIONS (CONTINUED) Operating Income Third quarter 1996 operating income of $36 million was $5.3 million lower than the same period last year. After adjusting for items that have no effect on operating income, operating expenses increased $6.4 million due in large part to a court decision that overturned a previous FERC ruling and other tax expense increased $3.4 million primarily reflecting higher franchise and gross receipts taxes. Year-to-date through September 30, 1996, operating income of $160.4 million improved $6.6 million over 1995. Higher revenues of $32.3 million were partially offset by a $25.7 million increase in operating expenses due primarily to reengineering expense of $6.1 million, the unfavorable court decision mentioned above and higher franchise and property taxes. 15 18 PART 1 - FINANCIAL INFORMATION ITEM 2 - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED) DISTRIBUTION OPERATIONS
THREE MONTHS NINE MONTHS ENDED SEPTEMBER 30, ENDED SEPTEMBER 30, ------------------- ------------------- 1996 1995 1996 1995 ---- ---- ---- ---- (MILLIONS) NET REVENUES Sales revenues $171.5 $144.8 $1,328.1 $1,146.3 Less: Cost of gas sold 84.0 62.5 771.5 655.3 ------ ------ -------- -------- Net Sales Revenues 87.5 82.3 556.6 491.0 ------ ------ -------- -------- Transportation revenues 21.6 19.3 88.0 76.7 Less: Associated gas costs 3.2 2.1 10.6 7.3 ------ ------ -------- -------- Net Transportation Revenues 18.4 17.2 77.4 69.4 ------ ------ -------- -------- Net Revenues 105.9 99.5 634.0 560.4 ------ ------ -------- -------- OPERATING EXPENSES Operation and maintenance 97.5 98.2 332.6 323.6 Depreciation 7.9 6.8 51.7 48.3 Other taxes 19.8 20.0 104.0 105.7 ------ ------ -------- -------- Total Operating Expenses 125.2 125.0 488.3 477.6 ------ ------ -------- -------- OPERATING INCOME (LOSS) $(19.3) $(25.5) $ 145.7 $ 82.8 ====== ====== ======== ======== THROUGHPUT (BCF) Sales Residential 11.5 11.5 144.1 127.4 Commercial 5.1 5.3 59.2 52.0 Industrial and other 0.9 1.2 6.0 5.3 ------ ------ -------- -------- Total Sales 17.5 18.0 209.3 184.7 Transportation 52.1 55.1 183.8 190.6 ------ ------ -------- -------- Total Throughput 69.6 73.1 393.1 375.3 ------ ------ -------- -------- Off-System Sales 3.1 2.3 8.4 6.2 ------ ------ -------- -------- Total Sold or Transported 72.7 75.4 401.5 381.5 ====== ====== ======== ======== SOURCES OF GAS FOR THROUGHPUT (BCF) Sources of Gas Sold Spot market* 69.5 46.8 236.7 159.4 Producers 9.0 13.3 34.6 45.9 Storage withdrawals (injections) (54.9) (45.1) (47.0) (18.7) Other (3.0) 5.3 (6.6) 4.3 ------ ------ -------- -------- Total Sources of Gas Sold 20.6 20.3 217.7 190.9 Transportation received for delivery to customers 52.1 55.1 183.8 190.6 ------ ------ -------- -------- Total Sources 72.7 75.4 401.5 381.5 ====== ====== ======== ========
* Purchase contracts of less than one year. 16 19 PART 1 - FINANCIAL INFORMATION ITEM 2 - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITIONS AND RESULTS OF OPERATIONS (CONTINUED) DISTRIBUTION OPERATIONS (CONTINUED) Regulatory Matters As previously reported, the review of Columbia Gas of Ohio, Inc.'s (Columbia of Ohio) revenue requirements by a collaborative group composed of diverse interested parties (Collaborative) has been completed. In October 1996, Columbia of Ohio filed and unopposed settlement with the Public Utility Commission of Ohio (PUCO) to resolve its revenue requirement. The filing would permit Columbia of Ohio to retain up to $51 million over the next three years subject to an earnings limitation, under which a portion of any earnings above an industry composite allowed return on equity would be shared with customers. The revenues eligible for retention are approximately $11.5 million in 1996, $19.7 million in 1997 and $19.7 million in 1998. This revenue retention mechanism is in lieu of a base rate increase and does not result in any base rate increase for customers. Additionally, the setlement provides that Columbia of Ohio will not implement any increase in base rates before January 1, 1999. This filing is a part of an overall collaborative settlement which encompasses a "Customer Choice" transportation program for small customers. The initial program design includes options of unbundled services for participating marketers and full recovery of stranded costs. The tentative start date is April 1, 1997. The target location is the Toledo, Ohio, market area which includes approximately 159,000 residential customers and 11, 200 small commercial customers. PUCO rulings on both filings are expected in the near future. In August 1996, Columbia Gas of Pennsylvania, Inc. (Columbia of Pennsylvania) received Pennsylvania Public Utility Commission approval to make two changes in its tariff provisions. The first change provides a permanent, statewide residential transportation rate schedule. The second change initiates a two-year transportation pilot program for more than 36,000 residential and human needs customers in Washington County. The program, which begins on November 1, 1996, is one of the largest pilot programs currently in the United States. Sales Incentives Columbia Gas of Kentucky, Inc. (Columbia of Kentucky) received approval from the Kentucky Public Service Commission in July 1996 for its Incentive Plan on a two-year pilot basis effective August 1, 1996. Columbia Gas of Maryland, Inc. (Columbia of Maryland) and Columbia of Pennsylvania have similar incentive programs in place that allow them to retain a portion of the profits generated by off-system sales. Off-system sales are sales outside of the distribution subsidiaries' (Distribution's) traditional market areas. In the first nine months of 1996, Distribution had off-system sales and exchange volumes of approximately 13 Bcf resulting in pre-tax income of $3 million, an increase of 10.1 Bcf and $2.9 million, respectively, from the same period in 1995. Columbia of Ohio has deferred approximately $27.2 million of pre-tax income from off-system sales and exchange transactions pending a final PUCO decision regarding the treatment of these transactions.. Proceeds from releasing unused capacity totaled $10.6 million in the first nine months of 1996, down $600,000 from the same period in 1995. This year's colder weather increased the need for capacity to meet customer requirements and reduced opportunities to release any unused capacity. Except for a small amount retained by Columbia of Maryland, Distribution recorded these proceeds as a reduction in gas costs. Columbia of Pennsylvania has an approved incentive program that allows a portion of the proceeds to be retained once a benchmark has been reached. Columbia of Kentucky received approval for a similar capacity release incentive in the July 1996 order that granted it an off-system sales incentive. 17 20 PART 1 - FINANCIAL INFORMATION ITEM 2 - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITIONS AND RESULTS OF OPERATIONS (CONTINUED) DISTRIBUTION OPERATIONS (CONTINUED) Distribution continues to pursue incentive program authorization in Virginia. In Virginia, Commonwealth Gas Services, Inc.'s (Commonwealth Services) rate case settlement that was reached in early 1996 provided for a separate proceeding to consider gas supply and other incentive proposals. A hearing on these issues was held in September 1996, and the Hearing Examiner's report could be issued by year end. Environmental Matters Distribution's primary environmental issues relate to former manufactured gas plant sites. Distribution previously reported it had identified 14 former gas plant sites for which it may have some liability for clean up. During the third quarter of 1996, a fifteenth formerly owned manufactured gas plant site was identified. At this time, it is not possible to estimate the costs associated with this additional site. To the extent Distribution's site investigations have been conducted, remediation plans developed and any responsibility for remediation action established, the appropriate liabilities have been recorded. Regulatory assets have also been recorded for a majority of these costs as rate recovery has been allowed or is anticipated. Volumes For the quarter ended September 30, 1996, throughput of 72.7 Bcf was 2.7 Bcf lower than the same period last year as minor decreases in sales and transportation service were partially offset by higher off-system sales. For the first nine months of 1996, throughput increased 20 Bcf over 1995 to 401.5 Bcf. Sales increased 24.6 Bcf as residential and commercial tariff sales increased primarily due to colder weather. Transportation volumes decreased 6.8 Bcf reflecting reduced transportation service for power generation, the effect of increased pressure from competitive fuels due to higher natural gas prices and transportation capacity constraints. Increased usage within the manufacturing sector partially offset these reductions. Net Revenues Net revenues for the quarter ended September 30, 1996 were $105.9 million, an increase of $6.4_million over the third quarter of 1995. This increase includes $2.2 million from higher rates in effect in four of the five states that Distribution serves. The remaining increase was essentially due to higher revenue surcharges that are offset in expense and have no effect on income. For the first nine months of 1996, net revenues were $634 million, an increase of $73.6 million over 1995. Additional throughput contributed $49.1 million of the increase and higher rates produced another $17.4 million. Most of the remaining increase was attributable to higher revenue surcharges that are offset in expense. 18 21 PART 1 - FINANCIAL INFORMATION ITEM 2 - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITIONS AND RESULTS OF OPERATIONS (CONTINUED) DISTRIBUTION OPERATIONS (CONTINUED) Operating Income (Loss) Distribution experienced a seasonal operating loss of $19.3 million for the third quarter of 1996, a $6.2 million improvement over the operating loss in the third quarter of 1995. After adjusting for issues that are offset by revenue surcharges, this improvement primarily reflected higher rates in place and lower operation and maintenance expense, attributable to the implementation restructuring activities. Operating income for the first nine months of 1996 of $145.7 million was up $62.9 million from 1995 as the higher net revenues were partially offset by an increase of $10.7 million in operating expenses. Included in the higher operating expenses were restructuring costs of $15.9 million. Other operation and maintenance expenses decreased due to efficiencies and modernization efforts recently implemented. Plant additions contributed to the $3.4 million increase in depreciation expense while lower gross receipts, sales, and property taxes caused the $1.7 million decline in other taxes. 19 22 PART 1 - FINANCIAL INFORMATION ITEM 2 - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED) OIL AND GAS OPERATIONS
THREE MONTHS NINE MONTHS ENDED SEPTEMBER 30, ENDED SEPTEMBER 30, ------------------- ------------------- 1996 1995 1996 1995 ------ ----- ------ ----- (MILLIONS) OPERATING REVENUES Gas $ 21.6 $ 30.3 $ 72.8 $ 98.1 Oil and liquids 1.2 11.4 4.0 35.2 ------ ------ ------ ------ Total Operating Revenues 22.8 41.7 76.8 133.3 ------ ------ ------ ------ OPERATING EXPENSES Operation and maintenance 8.4 18.1 26.4 58.5 Depreciation and depletion 7.0 21.5 21.3 67.5 Other taxes 2.0 2.5 6.5 8.0 ------ ------ ------ ------ Total Operating Expenses 17.4 42.1 54.2 134.0 ------ ------ ------ ------ OPERATING INCOME (LOSS) $ 5.4 $ (0.4) $ 22.6 $ (0.7) ====== ====== ====== ====== GAS PRODUCTION STATISTICS Production (Bcf) Appalachian 8.0 7.9 24.6 25.1 Southwest - 8.0 - 24.7 ------ ------ ------ ------ Total 8.0 15.9 24.6 49.8 ====== ====== ====== ====== Average Price ($/Mcf) Appalachian 2.45 2.08 2.81 2.16 Southwest - 1.63 - 1.67 System 2.45 1.85 2.81 1.92 OIL AND LIQUIDS PRODUCTION STATISTICS Production (000Bbls) Appalachian 64 76 217 234 Southwest - 661 - 1,941 ------ ------ ------ ------ Total 64 737 217 2,175 ====== ====== ====== ====== Average Price ($/Bbl) Appalachian 19.35 16.01 18.40 16.29 Southwest - 15.30 - 16.11 System 19.35 15.37 18.40 16.13
20 23 PART 1 - FINANCIAL INFORMATION ITEM 2 - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED) OIL AND GAS OPERATIONS (CONTINUED) Merger of Columbia Coal Gasification Corporation On July 1, 1996, Columbia Coal Gasification Corporation was merged into Columbia Natural Resources, Inc. (Columbia Natural) in order to increase administrative and operating efficiencies. Drilling Activity In 1996, Columbia Natural participated in 28 wells with 10 completed during the third quarter. Of the wells completed in the third quarter, 5 were successful, adding 1.1 Bcf to reserves. A portion of drilling operations scheduled for 1996 has been deferred until 1997. This deferral was necessitated by a change in strategies used in determining the composition of the Columbia Natural's drilling program. New strategies result in tighter scheduling and more concerted development activities which are designed to lower average finding and development costs. The deferral of drilling activity in 1996 has allowed Columbia Natural's management to establish the new processes necessary to allow for additional drilling efforts in 1997. Volumes For the three months and nine months ended September 30, 1996, gas production was 8 Bcf and 24.6 Bcf compared to 15.9 Bcf and 49.8 Bcf, respectively, in 1995. After adjusting for the sale of Columbia Development, gas production for the current quarter and year-to-date results were essentially unchanged. Columbia Natural's oil and liquids production for both the three and nine month periods are down 12,000 and 17,000 barrels, respectively, from 1995. Oil and liquids production for Columbia Natural is incidental to its gas production activities. Revenues Gas revenues for the current year third quarter and year-to-date were $21.6 million and $72.8 million, a decrease of $8.7 million and $25.3 million, respectively, primarily due to the sale of Columbia Development. After adjusting for the sale, gas revenues increased $4.4 million for the three-month period and $16.1 million for the nine-month period, reflecting higher average prices due in large part to colder weather earlier in the year. Through the summer months gas prices continued to outpace last year's levels due to increased demand for natural gas by distribution companies to refill storage inventories. For the current three months average gas prices were $2.45 per mcf, an 18% improvement over the same period last year while for the first nine months of 1996 average gas prices of $2.81 per mcf were up 30%. Revenues from oil and liquids production for the three and nine months ended September 30, 1996, were $1.2 million and $4 million, down $10.2 million and $31.2 million, respectively. After adjusting for the sale of Columbia Development, oil and liquids production revenue were relatively unchanged in both periods. Operating Income (Loss) Operating income was $5.4 million and $22.6 million for the current quarter and year-to-date periods, respectively. In the same periods last year an operating loss was recorded of $400,000 and $700,000, respectively. The 1995 loss included results from Columbia Development. Reduced depletable plant 21 24 PART 1 - FINANCIAL INFORMATION ITEM 2 - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED) OIL AND GAS OPERATIONS (CONTINUED) resulting from the sale of Columbia Development and higher gas prices led to lower depletion expense of $14.5 million and $46.2 million for the three and nine month periods, respectively. Operation and maintenance expense for Columbia Natural was also lower reflecting improved efficiencies gained through the implementation of ongoing restructuring activities. 22 25 PART 1 - FINANCIAL INFORMATION ITEM 2 - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED) OTHER ENERGY OPERATIONS
THREE MONTHS NINE MONTHS ENDED SEPTEMBER 30, ENDED SEPTEMBER 30, ------------------- ------------------- 1996 1995 1996 1995 ---- ---- ---- ---- (MILLIONS) NET REVENUES Gas marketing revenues $151.9 $ 54.0 $462.3 $168.1 Less: Products purchased 149.7 52.3 449.1 163.2 ------ ------ ------ ------ Net Gas Marketing Revenues 2.2 1.7 13.2 4.9 ------ ------ ------ ------ Propane revenues 10.8 9.2 54.0 43.4 Less: Products purchased 6.9 5.3 31.1 24.2 ------ ------ ------ ------ Net Propane Revenues 3.9 3.9 22.9 19.2 ------ ------ ------ ------ Other Revenues 23.6 22.3 68.8 63.8 ------ ------ ------ ------ Net Revenues 29.7 27.9 104.9 87.9 ------ ------ ------ ------ OPERATING EXPENSES Operation and maintenance 25.1 21.8 79.0 65.2 Depreciation and depletion 2.3 2.1 6.8 6.2 Other taxes 0.9 1.2 4.1 4.1 ------ ------ ------ ------ Total Operating Expenses 28.3 25.1 89.9 75.5 ------ ------ ------ ------ OPERATING INCOME $ 1.4 $ 2.8 $ 15.0 $ 12.4 ====== ====== ====== ====== PROPANE SALES (MILLIONS OF GALLONS) Retail 8.9 7.3 42.0 34.4 Wholesale and Other 2.0 2.1 10.9 12.4 ------ ------ ------ ------ Total Propane Sales 10.9 9.4 52.9 46.8 ====== ====== ====== ======
23 26 PART 1 - FINANCIAL INFORMATION ITEM 2 - MANAGEMENT S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED) OTHER ENERGY OPERATIONS (CONTINUED) Net Revenues Net revenues for the third quarter of 1996 were $29.7 million, improving slightly from the same period last year. The increase is primarily attributable to an increase in gas marketing volumes, and increased usage for Columbia LNG's peaking services. Higher Columbia Gas System Service Corporation (Service Corporation) revenues reflect billings to affiliate companies for Service Corporation's restructuring costs. These improvements were tempered by lower gas marketing margins. For the nine months ended September 30, 1996, net revenues increased $17 million over the same period last year to $104.9 million, principally reflecting the favorable effect of colder weather on the various energy-related operations. Higher sales volumes and margins led to increased net revenues from gas marketing activities, up $8.3 million, and $3.7 million higher net revenues for propane operations. Other net revenues improved $5 million as the result of additional revenues for peaking services and Service Corporation charges to affiliates for services provided and recovery of restructuring costs. Operating Income Operating income of $1.4 million for the third quarter of 1996 was down $1.4 million from the same period last year reflecting restructuring costs for the Service Corporation and additional startup costs for Columbia Service Partners, Inc. Additional expenses associated with project development costs reduced operating income for cogeneration activities. For the nine months ended September 30, 1996, operating income was $15 million, an increase of $2.6 million over 1995 as colder weather increased gas marketing volumes and propane sales. These improvements were partially offset by restructuring expense in the current period. 24 27 PART II - OTHER INFORMATION ITEM 1 - LEGAL PROCEEDINGS No new reportable matters have arisen and there have been no material developments in any legal proceedings reported in Columbia's Annual Report on Form 10-K for the year ended December 31, 1995, or reported on Form 10-Q for the First or Second Quarter 1996, except as follows: I. Regulatory Matters Columbia Gas Transmission Corp., FERC Docket No. RP95-408 (August 1, 1995) On July 17, 1996, Columbia Gas Transmission Corporation ("Columbia Transmission") filed an appeal with the U.S. Court of Appeals for the D.C. Circuit (the "D.C. Circuit") (Case No. 96-1250) concerning the Federal Energy Regulatory Commission's ("FERC") rejection of Columbia Transmission's proposal to earn its allowed rate of return on certain gathering facilities. On August 30, 1996, Columbia Transmission and certain intervenors filed with the FERC a proposed partial settlement of distance-sensitive rate issues in Phase I of its rate case. Under that proposed settlement, Columbia Transmission would absorb $850,000 annually to resolve these issues. Settlement discussions among Columbia Transmission and certain intervenors continue. Columbia Gas Transmission Corp., FERC Docket No. CP96-386 (April 29, 1996) On July 3, 1996, Columbia Transmission filed a motion to approve Columbia Natural Resources, Inc.'s ("Columbia Natural") proposed default contracts for gathering facilities. On July 25, 1996, Columbia Transmission and Columbia Natural filed a joint answer to protests to the original filing. Four protests to Columbia Transmission's motion were filed on August 1, 1996. This motion may become moot in light of the Conoco v. FERC order issued by the D.C. Circuit on August 2, 1996, finding that the FERC exceeded its jurisdiction by requiring default contracts. Columbia Transmission is studying this issue. Columbia Transmission also has opened a data room as part of its effort to auction the remainder of its gathering facilities. On October 15, 1996, the FERC issued data requests in this proceeding to which Columbia Transmission and Columbia Natural plan to reply in November 1996. The Ohio Oil and Gas Association filed a motion to require replacement gathering contracts with shippers as a condition to abandonment. Columbia Transmission and Columbia Natural filed responses to that motion on October 21, 1996. Transcontinental Gas Pipe Line Corp., FERC Docket No. RP92-149, et al., appeal pending sub nom. Trunkline, et al. v. FERC, No. 94-1728 (U.S. Ct. of App. for the D.C. Cir.) (FERC Order No. 94 Costs) In 1992, Columbia Transmission reached settlements with upstream pipeline suppliers that permitted those suppliers to directly bill Columbia Transmission for production-related costs authorized under FERC Order No. 94 ("Order 94"), provided that Columbia Transmission could recover those costs from its customers. The settlements initially were approved in 1994 by FERC order. Subsequently, 25 28 PART II - OTHER INFORMATION ITEM 1 - LEGAL PROCEEDINGS after a rehearing of the matter, the FERC ruled that Columbia Transmission's 1985 Purchased Gas Adjustment settlement barred such recovery and that the settlements must be rejected. Accordingly, the upstream pipelines were ordered to refund to Columbia Transmission all Order 94 collections that they had received, but all interest on such payments through February 10, 1994 was forgiven. Appeals of both the initial and rehearing orders were filed in the D.C. Circuit. Settlements have been reached with all upstream pipeline suppliers with the exception of Transcontinental Gas Pipe Line Corporation ("Transco"). Approximately $7 million (plus interest) is at issue with Transco. Briefs in this matter were filed with the D.C. Circuit, and oral argument was held on March 19, 1996. On September 10, 1996, the D.C. Circuit Court of Appeals issued a decision which reversed a prior determination by the FERC and directed that a previous settlement reached between Columbia Transmission and Transco be reinstated. Reserves adequate in the opinion of management have been established in the third quarter of 1996 by Columbia Transmission to reflect the court's decision. Columbia Transmission believes that the Bankruptcy Court continues to have jurisdiction over this issue and thus is evaluating the order to consider further action, if any. Tennessee Gas Pipeline Co., FERC Docket No. RP96-61 (November 30, 1995) On November 30, 1995, Tennessee Gas Pipeline Company ("Tennessee Gas") made a filing to directly bill Columbia Transmission for $115,303 of new take-or-pay costs which, if it were approved, could have resulted in estimated total costs of $5 million to be billed to Columbia Transmission. Columbia Transmission opposed Tennessee Gas's filing. On July 22, 1996, the FERC issued an order holding that Tennessee Gas may not bill new take-or-pay costs to Columbia Transmission. On August 6, 1996, Tennessee Gas filed tariff sheets to comply with that order. No requests for a rehearing of that order were filed, thereby concluding this proceeding with respect to Columbia Transmission. 26 29 PART II - OTHER INFORMATION ITEM 1 - LEGAL PROCEEDINGS Secondary Market Transactions on Interstate Natural Gas Pipelines, FERC Docket No. RM96-14 (July 31, 1996) and Columbia Gas Transmission Corp. and Columbia Gulf Transmission Co., FERC Docket Nos. RP96-355 and RP96-356 (August 30, 1996) (Pilot Program Applications) On July 31, 1996, the FERC issued a notice of proposed rulemaking ("NOPR") that would revise capacity release provisions to (1) improve the operation of the FERC's capacity release program, (2) eliminate the competitive bidding requirement for capacity release transactions and (3) permit pipelines to sell interruptible and short-term firm service and shippers to release capacity at rates above the maximum cost-based rate cap, when the pipeline or shipper has demonstrated that it does not exercise market power. Columbia Transmission and Columbia Gulf filed comments to the NOPR in October 1996. In conjunction with the NOPR, the FERC proposed a pilot program for the 1996 winter heating season (November 1, 1996 through March 31, 1997) to permit interim implementation of the proposed changes to help assess whether compliance with the criteria is indicative of a lack of market power. On August 30, 1996, Columbia Transmission and Columbia Gulf filed applications to participate in the pilot program. Several interventions and protests were filed with respect to Columbia Transmission's and Columbia Gulf's applications, and both companies responded thereto on October 18, 1996. Distribution companies served by Columbia Transmission and Columbia Gulf that also filed applications to participate in the pilot program include Mountaineer Gas Co., National Fuel Gas Distribution Corp., Central Hudson Gas & Electric Corp. and Washington Gas Light Company. Columbia Gas Transmission Corp. and Columbia Gulf Transmission Co., FERC Docket Nos. RP96-390 and RP96-389 (Negotiated Rate Filings) Columbia Transmission and Columbia Gulf filed on September 25, 1996 revisions to tariff sheets to permit negotiated rate settlements (to become effective November 1, 1996) in accordance with the FERC's orders on similar pipeline filings and its Statement of Policy and Request for Comments and Alternatives to Traditional Cost-of-Service Ratemaking for Natural Gas Pipelines (FERC Docket No. RM95-6-000). Columbia Gas Transmission Corp., FERC Docket No. RP95-196, et al. and UGI, Inc. v. Columbia Gulf Transmission Co. and Columbia Gas Transmission Corp., FERC Docket No. RP95-392 (Transportation Costs Recovery Adjustment Filings) The Pennsylvania Office of Consumer Advocate and FERC staff filed testimony in this proceeding to determine whether certain Columbia Gulf environmental costs billed to Columbia Transmission under the T-1 Rate Schedule were prudently incurred. Columbia Gulf filed data requests on this testimony in October 1996. Columbia Transmission and Columbia Gulf filed on October 18, 1996 their joint narrative stipulation of issues. II. Bankruptcy Matters New Bremen Corp. v. Columbia Gas Transmission Corp. and Columbia Gulf Transmission Co., C.A. No. 88-V-631 (155th Jud. Dist. Ct. of Austin County, Texas) (November 16, 1988) This action, initially filed in Texas state court, was removed to the U.S. District Court for the Southern District of Texas, Houston District (the "Texas District Court") on January 10, 1989 (Civ. Action No. H-89-0072). The action concerns the interpretation of a producer contract subject to the estimation proceedings in the United States Bankruptcy Court for the District of Delaware (the 27 30 "Bankruptcy Court"). On March 12, 1996, the Texas District Court entered an order granting Columbia Transmission's motion for partial summary judgment. New Bremen Corp. appealed the Texas District Court's ruling to the U.S. Court of Appeals for the Fifth Circuit ("Fifth Circuit"). The issue on appeal (contract price interpretation) has been briefed. The Fifth Circuit is expected to schedule oral argument on this matter to be held during the week of December 2, 1996. In the Bankruptcy Court's estimation proceedings, the official claims mediator granted in October 1996 Columbia Transmission's motion for partial summary judgment with respect to that portion of New Bremen's claim which was asserted in the alternative to, and not at issue in, the matter of contract interpretation being addressed on appeal to the Fifth Circuit. New Ulm and Fox v. Mobil Oil Corp., et al., C.A. No. 88-V-655 (155th Jud. Dist. Ct. of Austin County, Texas) (December 20, 1988) On October 18, 1996, the Texas Supreme Court reversed in part the judgment of the Court of Appeals and rendered judgment in favor of Columbia Transmission on New Ulm's contract interpretation claim. The Texas Supreme Court also affirmed, in part, the appellate court's judgment by remanding New Ulm's fraud claim to the trial court for further proceedings. New Ulm has until November 4, 1996 to request a rehearing of the Texas Supreme Court's decision. Daniel Garshman v. Columbia Gas Transmission Corporation, No. ATL-L-000172-99 (Sup. Ct. of N.J., 1993) The Bankruptcy Court has approved the parties' resolution of this dispute. The resolution of this case does not have a material effect on the financial condition of The Columbia Gas System, Inc. ("Columbia"). III. Other Matters LG&E Natural Marketing Inc. v. Columbia Gulf Transmission Co. and Columbia Gas Transmission Corp. Case No. 1:96CV02238 (U.S. Dist. Ct. for the District of Columbia) and C.A. No. 96-CA07745 (Sup. Ct. of the District of Columbia) On September 27, 1996, LG&E Natural Marketing Inc. ("LG&E") filed virtually identical complaints in the United States District Court for the District of Columbia and the Superior Court of the District of Columbia (Civil Division). The complaints allege that Columbia Transmission and Columbia Gulf breached purported obligations to make certain pipeline transportation capacity available to LG&E. The complaints seek $10 million under each of a number of different counts and punitive and treble damages under some of them. Both cases were dismissed without prejudice. The parties are pursuing a mutually satisfactory business arrangement to resolve this matter. Management believes that the complaints' claims, should they be reasserted, do not represent a material exposure to Columbia. 28 31 PART II - OTHER INFORMATION Item 2. Changes in Securities None Item 3. Defaults Upon Senior Securities None Item 4. Submission of Matters to a Vote of Security Holders None. Item 5. Other Information None Item 6. Exhibits and Reports on Form 8-K a. Exhibits
Exhibit Number ------ 11 Statement re Computation of Per Share Earnings, a copy of which is attached hereto as PART II, EXHIBIT 11, pursuant to Regulation 229.601(b)(11). 12 Statements of Ratio of Earnings to Fixed Charges, a copy of which is attached hereto as PART II, EXHIBIT 12, pursuant to Regulation 229.601(b)(12). 27 Financial Data Schedule.
b. Reports on Form 8-K The following reports on Form 8-K were not previously reported.
Financial Item Statements Reported Included Date Filed -------- -------- ---------- 5 No October 11, 1996
29 32 SIGNATURE Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The Columbia Gas System, Inc. ----------------------------------- (Registrant) Date: October 31, 1996 By: /s/J. W. Grossman ------------------------------- J. W. Grossman Vice President and Controller (Chief Accounting Officer and duly authorized officer) 30 EX-11 2 STATEMENT RE COMPUTATION OF PER SHARE EARNINGS 1 Exhibit 11 THE COLUMBIA GAS SYSTEM, INC. AND SUBSIDIARIES Statements Re Computation of Per Share Earnings
THREE MONTHS NINE MONTHS ENDED ENDED SEPTEMBER 30, SEPTEMBER 30, ------------------- ------------------ 1996 1995 1996 1995 ---- ---- ---- ---- Computation for Statements of Consolidated Income ($ in millions) Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (6.1) 19.3 153.4 179.0 - - --------------------------------------------------------------------------------------------------------------------------------- Earnings per share of common stock (based on average shares outstanding) ($) Earnings on common stock . . . . . . . . . . . . . . . . . . . . . . . (0.11) 0.38 2.88 3.54 - - --------------------------------------------------------------------------------------------------------------------------------- Additional computation of average common shares outstanding (thousands) (NOTE) - - --------------------------------------------------------------------------------------------------------------------------------- Average shares of common stock outstanding . . . . . . . . . . . . . . 55,165 50,574 53,340 50,569 Incremental common shares applicable to common stock based on the common stock daily average market price: Applicable to contingent stock awards . . . . . . . . . . . . . . . . 10 15 10 8 Applicable to contingent stock options . . . . . . . . . . . . . . . 111 16 76 6 - - --------------------------------------------------------------------------------------------------------------------------------- Average common shares as adjusted . . . . . . . . . . . . . . . . . . . 55,286 50,605 53,426 50,583 - - --------------------------------------------------------------------------------------------------------------------------------- Average shares of common stock outstanding . . . . . . . . . . . . . . 55,165 50,574 53,340 50,569 Incremental common shares applicable to common stock based on the more dilutive of the common stock ending or daily average market price during the year: Applicable to contingent stock awards . . . . . . . . . . . . . . . . 10 15 10 8 Applicable to contingent stock options . . . . . . . . . . . . . . . 114 34 114 34 - - --------------------------------------------------------------------------------------------------------------------------------- Average common shares assuming full dilution . . . . . . . . . . . . . 55,289 50,623 53,464 50,611 - - --------------------------------------------------------------------------------------------------------------------------------- Earnings on common stock as adjusted ($) . . . . . . . . . . . . . . . (0.11) 0.38 2.87 3.54 - - --------------------------------------------------------------------------------------------------------------------------------- Earnings on common stock assuming full dilution ($) . . . . . . . . . . (0.11) 0.38 2.87 3.54 - - ---------------------------------------------------------------------------------------------------------------------------------
NOTE These calculations are submitted in accordance with the Securities Exchange Act of 1934 Release No. 9083 although not required by footnote 2 to paragraph 14 of Accounting Principles Opinion No. 15 because they result in dilution of less than 3%. 31 EX-12 3 STATEMENTS OF RATIO OF EARNINGS TO FIXED CHARGES 1 Exhibit 12 THE COLUMBIA GAS SYSTEM, INC. AND SUBSIDIARIES Statements of Ratio of Earnings to Fixed Charges ($ in millions)
TWELVE MONTHS TWELVE MONTHS ENDED SEPTEMBER 30, ENDED DECEMBER 31, ------------------- ------------------------------------------------- 1996 1995 1995 1994 1993 1992 1991 ---- ---- ---- ---- ---- ---- ---- Consolidated Income (Loss) from Continuing Operations before Income Taxes, Extraordinary Item and Cumulative Effect of Accounting Change . . . . . . . . . . . . . (692.3) 400.5 (643.0) 392.2 288.1 161.4 (1,205.8) Adjustments: Interest during construction . . . . . . . . . . . . (21.2) - (20.2) - - - (3.4) Distributed (Undistributed) equity income . . . . . . 3.6 (9.4) (7.9) (0.9) (0.1) (0.1) (2.4) Fixed charges . . . . . . . . . . . . . . . . . . . 1,160.8 22.5 1,040.8 14.8 101.5 13.7 139.9 ------- ------- ------- ------- ------- ------- ------- Earnings Available . . . . . . . . . . . . . . . . 450.9 413.6 369.7 406.1 389.5 175.0 (1,071.7) ------- ------- ------- ------- ------- ------- ------- Fixed Charges: Interest on long-term and short-term debt 1,100.1 0.4 987.2 0.7 3.1 4.9 112.4 Other interest . . . . . . . . . . . . . . . . . . . 60.7 22.1 53.6 14.1 98.4 8.8 27.6 ------- ------- ------- ------- ------- ------- ------- Total Fixed Charges before Adjustments*,**. . . . . 1,160.8 22.5 1,040.8 14.8 101.5 13.7 140.0 ------- ------- ------- ------- ------- ------- ------- Adjustments: Gain/(Loss) on reacquired debt . . . . . . . . . . . - - - - - - (0.1) ------- ------- ------- ------- ------- ------- ------- Total Fixed Charges . . . . . . . . . . . . . . . 1,160.8 22.5 1,040.8 14.8 101.5 13.7 139.9 ------- ------- ------- ------- ------- ------- ------- Ratio of Earnings Before Taxes to Fixed Charges N/A(a) 18.38 N/A(a) 27.44 3.84 12.77 N/A(a)
(a)To achieve a one-to-one coverage, the Corporation would need an additional $709.9, $671.1 and $1,211.6 million of earnings, for the twelve months ended September 30, 1996, and the twelve months ended December 31, 1995 and 1991, respectively. * This amount excludes approximately $261 million interest expense not recorded in the twelve months ended September 30, 1995, $230 million, $210 million, $204 million and $86 million of interest expense not recorded for 1994, 1993, 1992 and 1991. Includes interest expense of $982.9 million including write-off of unamortized discounts on debentures recorded in 1995. Reference is made to the Statements of Consolidated Income for the quarterly period ended September 30, 1996, as reported in Form 10-Q. ** This amount excludes $8.6 million of interest expense not recorded with respect to the registrant's guarantee of LESOP Trust's debentures for the twelve months ended September 30, 1995. Also excluded are $8.6 million, $8.6 million, $8.6 million and $15.5 million of interest expense not recorded with respect to the registrant's guarantee of LESOP Trust's debentures for the twelve months ended December 31, 1994, 1993, 1992 and 1991, respectively. EX-27 4 FINANCIAL DATA SCHEDULE WARNING: THE EDGAR SYSTEM ENCOUNTERED ERROR(S) WHILE PROCESSING THIS SCHEDULE.
UT 0000022099 THE COLUMBIA GAS SYSTEM, INC. AND SUBSIDIARIES 3-MOS 9-MOS DEC-31-1995 DEC-31-1995 JUL-01-1996 JAN-01-1996 SEP-30-1996 SEP-30-1996 PER-BOOK PER-BOOK 3,583,400 3,583,400 467,700 467,700 1,030,200 1,030,200 47,900 47,900 420,900 420,900 5,550,100 5,550,100 522,100 522,100 741,200 741,200 199,300 199,300 1,491,100 1,491,100 0 0 0 0 2,004,000 2,004,000 0 0 0 0 0 0 0 0 0 0 2,600 2,600 0 0 2,055,000 2,055,000 5,550,100 5,550,100 450,800 2,236,200 (2,600) 86,000 429,900 1,901,100 429,900 1,901,100 20,900 335,100 22,300 39,100 43,200 374,200 51,900 134,800 (6,100) 153,400 0 0 (6,100) 153,400 0.15 0.45 35,104 105,312 (76,700) 477,500 (0.11) 2.87 (0.11) 2.87
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