-----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, E5ozhsAYZF+Em4Skq6cMHy8zM0kqGzWynNS/DdIs38zopp9syHvQ92KWKw8E5xXg VP6K9Lco63Q/f9pUt//nVg== 0000893220-96-000649.txt : 19960501 0000893220-96-000649.hdr.sgml : 19960501 ACCESSION NUMBER: 0000893220-96-000649 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 4 CONFORMED PERIOD OF REPORT: 19960331 FILED AS OF DATE: 19960430 SROS: NONE FILER: COMPANY DATA: COMPANY CONFORMED NAME: COLUMBIA GAS SYSTEM INC CENTRAL INDEX KEY: 0000022099 STANDARD INDUSTRIAL CLASSIFICATION: NATURAL GAS TRANSMISSION & DISTRIBUTION [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: 96553763 BUSINESS ADDRESS: STREET 1: 20 MONTCHANIN RD CITY: WILMINGTON STATE: DE ZIP: 19807 BUSINESS PHONE: 3024295000 10-Q 1 FORM 10-Q COLUMBIA GAS SYSTEM, INC. 1 UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 FORM 10-Q QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) /X/ OF THE SECURITIES EXCHANGE ACT OF 1934 For the Quarterly period ended March 31, 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 of organization) Identification No.) 20 Montchanin Road, Wilmington, Delaware 19807 ----------------------------------------------------------------- (Address of principal executive office) (Zip Code) Registrant's telephone number, including area code (302) 429-5000 -------------- 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 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: 55,015,505 shares outstanding at March 31, 1996. 2 THE COLUMBIA GAS SYSTEM, INC. AND SUBSIDIARIES FORM 10-Q QUARTERLY REPORT FOR THE QUARTER ENDED MARCH 31, 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 Financial Condition and Results of Operations 8 PART II OTHER INFORMATION - ------- ----------------- Item 1 Legal Proceedings 25 Item 2 Changes in Securities 27 Item 3 Defaults Upon Senior Securities 27 Item 4 Submission of Matters to a Vote of Security Holders 27 Item 5 Other Information 28 Item 6 Exhibits and Reports on Form 8-K 28 Signature 29
3 PART 1 - FINANCIAL INFORMATION ITEM 1 - FINANCIAL STATEMENTS The Columbia Gas System, Inc. and Subsidiaries STATEMENTS OF CONSOLIDATED INCOME (unaudited)
Three Months Ended March 31 ----------------------------- 1996 1995 --------- --------- (millions) OPERATING REVENUES Gas sales $1,002.3 $ 838.2 Transportation 142.6 126.7 Other 58.1 65.8 ----------- --------- Total Operating Revenues 1,203.0 1,030.7 ----------- --------- OPERATING EXPENSES Products purchased 551.8 441.1 Operation 206.8 208.1 Maintenance 23.9 22.6 Depreciation and depletion 68.1 83.7 Other taxes 74.2 75.3 ---------- --------- Total Operating Expenses 924.8 830.8 ---------- --------- OPERATING INCOME 278.2 199.9 ---------- ---------- OTHER INCOME (DEDUCTIONS) Interest income and other, net 3.1 6.0 Interest expense and related charges* (43.7) (5.5) Reorganization items, net - 10.7 --------- ---------- Total Other Income (Deductions) (40.6) 11.2 --------- ---------- INCOME BEFORE INCOME TAXES 237.6 211.1 Income Taxes 86.3 82.3 ---------- ---------- NET INCOME $ 151.3 $ 128.8 ========== ========== EARNINGS PER SHARE OF COMMON STOCK $ 2.99 $ 2.55 ========== ========== AVERAGE COMMON SHARES OUTSTANDING (thousands) 50,662 50,563
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements. * Due to the bankruptcy filings, interest expense of approximately $65 million was not recorded for the three months ended March 31, 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 ------------------------------------------ March 31, 1996 December 31, 1995 ------------------- ----------------- (unaudited) ASSETS (millions) PROPERTY, PLANT AND EQUIPMENT Gas utility and other plant, at original cost $6,801.1 $ 6,903.2 Accumulated depreciation and depletion (3,269.0) (3,322.0) --------- ---------- Net Gas Utility and Other Plant 3,532.1 3,581.2 --------- ---------- Oil and gas producing properties, full cost method 516.3 516.3 Accumulated depletion (145.6) (141.1) --------- ---------- Net Oil and Gas Producing Properties 370.7 375.2 --------- ---------- Net Property, Plant and Equipment 3,902.8 3,956.4 --------- ---------- INVESTMENTS AND OTHER ASSETS 350.1 354.6 --------- ---------- CURRENT ASSETS Cash and temporary cash investments 31.0 8.0 Accounts receivable, net 661.7 511.0 Income tax refund 310.4 271.5 Gas inventory 3.6 172.3 Other inventories - at average cost 44.6 41.5 Prepayments 56.9 56.9 Regulatory assets 70.8 76.5 Other 203.3 138.2 -------- ---------- Total Current Assets 1,382.3 1,275.9 --------- ---------- REGULATORY ASSETS 419.1 422.0 DEFERRED CHARGES 49.7 48.1 --------- ---------- TOTAL ASSETS $6,104.0 $ 6,057.0 ========= ========== CAPITALIZATION AND LIABILITIES CAPITALIZATION Common stock equity $1,499.2 $ 1,114.0 Preferred stock - 399.9 Long-term debt 2,004.2 2,004.5 --------- ---------- Total Capitalization 3,503.4 3,518.4 --------- ---------- CURRENT LIABILITIES Short-term debt 315.0 338.9 Accounts and drafts payable 202.8 215.7 Accrued taxes 334.4 271.3 Accrued interest 131.9 94.3 Estimated rate refunds 89.0 96.1 Estimated supplier obligations 164.4 178.3 Overrecovered gas costs 10.8 41.7 Transportation and exchange gas payable 68.0 46.7 Other 298.5 295.6 --------- ---------- Total Current Liabilities 1,614.8 1,578.6 --------- ---------- OTHER LIABILITIES AND DEFERRED CREDITS Income taxes, noncurrent 511.4 468.6 Postretirement benefits other than pensions 201.2 208.2 Regulatory liabilities 44.8 44.9 Other 228.4 238.3 --------- ---------- Total Other Liabilities and Deferred Credits 985.8 960.0 --------- ---------- TOTAL CAPITALIZATION AND LIABILITIES $6,104.0 $ 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)
Three Months Ended March 31 -------------------------- 1996 1995 --------- --------- (millions) OPERATIONS ACTIVITIES Net income $ 151.3 $ 128.8 Adjustments for items not requiring (providing) cash: Depreciation and depletion 68.1 83.7 Deferred income taxes 23.6 13.4 Other - net* (29.2) 3.2 Change in components of working capital: Accounts receivable (142.7) (55.8) Income tax refunds (38.8) - Gas inventory 168.7 139.9 Prepayments 45.7 27.2 Accounts payable (86.6) (10.7) Accrued taxes 117.9 30.6 Accrued interest 110.7 - Estimated rate refunds (7.1) (16.1) Estimated supplier obligations (13.9) (5.0) Under/Overrecovered gas costs (40.0) 119.3 Exchange gas payable 25.8 (10.5) Other working capital (53.3) (1.4) --------- ---------- Net Cash From Operations 300.2 446.6 --------- ---------- INVESTMENT ACTIVITIES Capital expenditures (53.5) (78.0) Deposit received on the sale of Columbia Development 9.7 - Other investments - net 18.7 0.5 --------- ---------- Net Investment Activities (25.1) (77.5) --------- ---------- FINANCING ACTIVITIES Retirement of preferred stock (400.0) - Retirement of long-term debt (0.4) (0.3) Dividends paid (7.4) - Issuance of common stock 241.6 - Net decrease in revolving credit facility (23.8) - Other financing activities (62.1) (27.0) --------- ---------- Net Financing Activities (252.1) (27.3) --------- ---------- Increase in Cash and Temporary Cash Investments 23.0 341.8 Cash and temporary cash investments at beginning of year 8.0 1,481.8 --------- ---------- Cash and temporary cash investments at March 31** $ 31.0 $ 1,823.6 ========= ========== SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION Cash paid for interest 6.5 0.3 Cash paid for income taxes (net of refunds) (1.2) (0.7)
The accompanying Notes to Consolidated Financial Statements are an integral part of these statements. * Includes changes in Liabilities Subject to Chapter 11 Proceedings of $4.2 million in 1995. ** The Corporation considers all highly liquid debt instruments to be cash equivalents. 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 ------------------------------------- March 31, December 31, 1996 1995 ----------------- ---------------- (unaudited) (millions) COMMON STOCK EQUITY Common stock, $10 par value, authorized 100,000,000 shares, outstanding 55,015,505 shares and 49,204,025 respectively $ 550.2 $ 506.2 Additional paid in capital 735.2 595.8 Retained earnings 213.8 69.8 Less: Cost of treasury stock (1,416,155 shares outstanding as of December 31, 1995) - 57.8 --------- --------- TOTAL COMMON STOCK EQUITY $ 1,499.2 $ 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. 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 that 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 an Initial Report and 5 8 PART 1 - FINANCIAL INFORMATION ITEM 1 - FINANCIAL STATEMENTS (CONTINUED) Recommendations of the Claims Mediator on Generic Issues for Natural Gas Contract Claims and a Supplement to Initial Report and Recommendations of the Claims Mediator (Report) and directed producer claimants to submit recalculated claims prepared pursuant to the instructions contained in the Report. The recommendations and instructions set out in the Report have not been considered by the Bankruptcy Court. In mid-1995, most producers with which Columbia Transmission had not yet negotiated settlements liquidating their claims submitted recalculated claims to the claims mediator. As submitted, those recalculated claims initially 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. The claims estimation procedures remain in place for use in the post-confirmation liquidation of producer claims. The claims estimation process is now proceeding with discovery, motions for dismissal or summary judgement and evidentiary hearings before the claims mediator with respect to individual producer claims, including claim-specific issues not addressed by the Report. Motions are being filed by Columbia Transmission with the Bankruptcy Court based on the recommendations of the claims mediator to determine the amounts at which particular claims will be allowed. All parties have rights of appellate review with respect to the resulting orders of the Bankruptcy Court. 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 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 payment of the remaining distributions to producers, 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. Issuance of Common Stock In March 1996, Columbia made a public offering of five million shares of its common stock at an offering price of $43 per share. In addition, the underwriters exercised an option to purchase 750,000 additional shares of common stock on the same terms and conditions to cover over-allotments. Net proceeds to Columbia from the offering, including the over-allotment, were approximately $239.2 million. The proceeds were used to pay down a portion of the short-term debt that Columbia incurred in February 1996 to redeem $200 million of Preferred Stock, Series A (Series A - Preferred Stock) and $200 million of Convertible Preferred Stock, Series B (Series B - Preferred Stock) issued in November 1995. 4. Sale of Southwest Oil and Gas Subsidiary On April 30, 1996, (effective December 31, 1995) Columbia sold Columbia Gas Development Corporation (Columbia Development) to a privately-held exploration and production concern 6 9 PART 1 - FINANCIAL INFORMATION ITEM 1 - FINANCIAL STATEMENTS (CONTINUED) for approximately $200 million in cash. 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. 7 10 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 Ended March 31 --------------------------------- 1996 1995 --------- --------- (millions) Transmission $ 85.6 $ 76.6 Distribution 168.0 116.2 Oil and Gas 10.8 (0.1) Other Energy 16.7 7.9 Corporate (2.9) (0.7) --------- --------- TOTAL $ 278.2 $ 199.9 ========= =========
DEGREE DAYS (DISTRIBUTION SERVICE TERRITORY) Actual 3,102 2,758 Normal 2,979 2,947 % Colder (warmer) than normal 4 (6) % Colder (warmer) than prior period 13 (12)
8 11 PART 1 - FINANCIAL INFORMATION ITEM 2 - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED) CONSOLIDATED RESULTS Net Income Columbia's first quarter net income was $151.3 million, or $2.99 per share, up $22.5 million, or $0.44 per share over last year. After adjusting the first quarter of 1995 for unrecorded interest and bankruptcy-related costs, net income for the current period was $56.1 million higher than last year. The improvement primarily reflects the beneficial effect of colder weather that increased throughput for the distribution segment, higher prices for natural gas production and increased propane sales. Also improving results for 1996 were higher rates in effect for Columbia Transmission and four of the five distribution subsidiaries. Revenues For the first three months of 1996, operating revenues of $1,203 million, were up $172.3 million over the first quarter of 1995, principally reflecting the beneficial effect of colder weather that resulted in additional sales for the distribution segment, higher wellhead prices for natural gas production and increased propane sales. Higher rates for Columbia Transmission and the distribution subsidiaries also contributed to increased revenues. Columbia Transmission implemented new rates, subject to refund, in February 1996. Partially offsetting these increases were $5.4 million of revenues in 1995 for Ozark pipeline partnership exit fees recorded by Columbia Gulf Transmission Company (Columbia Gulf). Expenses Operating expenses of $924.8 million, increased $94 million over last year due to additional natural gas purchases reflecting the increased sales. Depreciation and depletion expense decreased by $15.6 million reflecting $18 million lower depletion expense attributable to reduced depletable plant due to the sale of Columbia Development and higher natural gas prices for CNR. These reductions were partially offset by $2.4 million higher depreciation expense due to additional plant in service and higher depreciation rates for the regulated subsidiaries. Operation and maintenance expense was relatively unchanged from last year. Other Income (Deductions) Other Income (Deductions) reduced income $40.6 million for the first three months of 1996, whereas in the first quarter in 1995, income was improved $11.2 million. This $51.8 million decrease from last year was largely due to recording $43.7 million of interest expense in the current period. In the same period last year, while Columbia was in Chapter 11, interest expense was not recorded. In addition, in the first three months of 1995 income was improved from bankruptcy-related reorganization items that included $18.9 million of interest earned on cash accumulated while in Chapter 11, partially offset by $8.2 million of expense for professional fees. Liquidity and Capital Resources Cash from operations for the first quarter of 1996 was $300.2 million, a decrease of $146.4 million from last year, due largely to an underrecovery of gas costs in the current period. This underrecovery resulted from the sharp rise in gas prices during 1996 that exceeded the distribution 9 12 PART 1 - FINANCIAL INFORMATION ITEM 2 - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED) CONSOLIDATED RESULTS (CONTINUED) subsidiaries' allowed recovery level. These higher costs will be recovered through 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 at that time led to an overrecovered position. Partially offsetting this decrease to cash from operations was the favorable effect of colder weather that increased sales for the distribution subsidiaries and raised prices for natural gas production. Also, improving cash were higher base rates in effect for the regulated subsidiaries. Columbia maintains an unsecured bank revolving credit facility (Credit Facility) which permits borrowings up to $1 billion. Scheduled quarterly reductions of $25 million of the committed amount start December 31, 1997 and will reduce the Credit Facility to $700 million by September 30, 2000. The Credit Facility provides for the issuance of up to $100 million of letters of credit. Borrowings under the Credit Facility were used in February 1996, to partially effect the redemption of the 5.22% Series B-Preferred Stock and 7.89% Series A-Preferred Stock issued pursuant to Columbia's approved Plan of Reorganization. On November 22, 1995, Columbia filed a shelf registration with the SEC requesting authorization to issue up to $1 billion in aggregate of debentures, common stock or preferred stock in one or more series. In March 1996, Columbia issued 5,750,000 shares of common stock consisting of 4,333,845 newly issued shares and 1,416,155 shares previously held as treasury stock. The proceeds of $239.2 million from the issuance were used to reduce borrowings incurred under the Credit Facility for the redemption of Series B-Preferred Stock and Series A - - Preferred Stock in February 1996. As of March 31, 1996, Columbia had $315 million of borrowings and $64.1 million of letters of credit outstanding under the Credit Facility. In addition, on April 30, 1996, Columbia sold Columbia Development for approximately $200 million in cash. The funds generated from the sale of Columbia Development were used to reduce borrowings under the Credit Facility. In addition, Columbia filed its 1995 Federal Income Tax return which included a net operating loss carryback claim to recover approximately $270 million of income tax from the Internal Revenue Service (IRS). This claim, net of other adjustments and liabilities related to IRS issues, resulted in a cash refund in April 1996, of approximately $213 million. Columbia believes that future ongoing cash requirements will be met with internally generated funds, amounts available under the Credit Facility and additional potential drawdowns under the shelf registration, although no further issuances under the shelf registration are currently contemplated. Relocation of Corporate Headquarters In March 1996, Columbia announced that it would relocate approximately 140 management and staff positions in its corporate headquarters from Wilmington, Delaware, to northern Virginia. Management and the Board of Directors had determined that certain of Columbia's headquarters and staff functions should be centralized and relocated in its market area to achieve certain operating 10 13 PART 1 - FINANCIAL INFORMATION ITEM 2 - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED) CONSOLIDATED RESULTS (CONTINUED) efficiencies. In the third quarter of 1996 the corporate headquarters will be moved to a temporary location in Reston, Virginia, while a new corporate building is constructed nearby. Approximately 150 management and staff positions from Columbia Transmission's headquarters in Charleston, West Virginia, will also be relocated to the permanent building when it is completed in late 1997. 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 Ended March 31 ---------------------------------- 1996 1995 -------- --------- (millions) OPERATING REVENUES Transportation revenues $ 183.0 $ 159.3 Storage revenues 38.7 29.5 Other revenues 4.2 14.4 -------- -------- Total Operating Revenues 225.9 203.2 -------- -------- OPERATING EXPENSES Operation and maintenance 97.8 86.9 Depreciation 27.0 25.7 Other taxes 15.5 14.0 -------- -------- Total Operating Expenses 140.3 126.6 -------- -------- OPERATING INCOME $ 85.6 $ 76.6 ======== ======== THROUGHPUT (BCF) Transportation Columbia Transmission Market Area 429.5 401.2 Columbia Gulf Main-line 170.2 154.9 Short-haul 69.3 50.7 Intrasegment eliminations (166.5) (151.3) -------- -------- Total Throughput 502.5 455.5 ======== ========
12 15 PART 1 - FINANCIAL INFORMATION ITEM 2 - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED) TRANSMISSION OPERATIONS (CONTINUED) Marketing Initiatives In February 1996, Columbia Transmission filed with the Federal Energy Regulatory Commission (FERC) for authorization to expand its pipeline and storage systems to serve the increasing needs of customers. As discussed in the 1995 Form 10-K, Columbia Transmission has signed 15-year agreements with 23 customers for approximately 500,000 Mcf per day (Mcf/d) of additional firm service to be phased in over a three-year period commencing November 1, 1997. Approximately 82% of the increased firm agreements are for storage service and related transportation from storage to customers during the winter periods. The balance of the increased service is firm transportation. Also in February 1996, Columbia Transmission received FERC approval to provide approximately 23,000 Mcf/d of firm transportation service to a cogeneration facility in Brandywine, Maryland. Service is anticipated to commence in the fall of 1996. Columbia Transmission's Rate Filing On August 1, 1995, Columbia Transmission filed with FERC its first general rate case since 1991, requesting an increase in annual revenues of approximately $147 million, including recovery of Columbia Transmission's net investment in gathering and gas processing facilities over five years. Numerous protests were filed, but with FERC authorization, new rates were implemented on February 1, 1996, subject to refund. However, Columbia Transmission agreed not to implement 25% of the requested rate increase for at least four months in an effort to reach a timely resolution of the issues. The establishment of a new level of cost recovery for environmental expenses was removed from the normal procedural schedule and will be pursued separately from the other rate case issues, with a hearing date expected in May 1997. Sale of Storage Base Gas In late 1994, FERC authorized Columbia Transmission to temporarily deactivate storage operations at its Majorsville-Heard storage fields in southwestern Pennsylvania and northern West Virginia. Columbia Transmission sought this authorization to have the flexibility necessary to respond to active coal mining occurring in its storage area that had impacted its storage operations. As a result, Columbia Transmission had excess base storage gas from these fields that it no longer needed for its operations. On March 5, 1996, Columbia Transmission was permitted by FERC to proceed with the retirement of 9 Bcf of base gas from the Majorsville-Heard storage area. The base gas was sold at current market prices for approximately $19 million. However, FERC deferred ruling on Columbia Transmission's proposal that it be permitted to retain the gain on the retirement of this base gas until FERC completed an evaluation of comments received from interested parties. Columbia Transmission has deferred the recording of any income associated with this issue, pending the final FERC ruling. 13 16 PART 1 - FINANCIAL INFORMATION ITEM 2 - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED) TRANSMISSION OPERATIONS (CONTINUED) Recovery of Columbia Gulf Pre-November 1994 Transportation Costs In 1995, Columbia Transmission sought to recover approximately $39 million of unrecovered transportation costs billed to it by Columbia Gulf. After a technical conference, the FERC ruled on April 2, 1996, that Columbia Gulf was entitled to bill its prudently incurred costs to Columbia Transmission under the cost-of-service tariff, and that Columbia Transmission was entitled to flow such amounts through to its customers. The FERC also ruled that $20 million of these costs were recoverable subject to audit and set for hearing approximately $19 million of environmental costs. Gathering Facilities FERC Order No. 636, requires natural gas pipelines to unbundle gathering costs and services from other transportation services. Columbia Transmission has determined that such services are not essential to its ongoing transportation activities. Accordingly, Columbia Transmission will exit the gathering business and dispose of the related assets. Columbia Transmission has provided gathering services for a significant portion of gas produced by its affiliate, CNR. Columbia Transmission will transfer certain gathering facilities for net book value to CNR. Columbia Transmission anticipates filing for FERC approval to transfer the facilities in the second quarter of 1996 and completing the transfer by the end of the year. Columbia Transmission is also actively pursuing discussions with various parties concerning the sale of its remaining gathering assets. Order 94 In January 1994, the FERC rejected on rehearing prior orders approving settlements between Columbia Transmission and four of its upstream pipeline suppliers. These settlements permitted the pipelines to direct bill Columbia Transmission for production-related costs authorized under FERC Order No. 94 (Order 94), provided Columbia Transmission could recover the costs from its customers. After reversing a previous ruling and determining that Columbia Transmission's 1985 Purchase Gas Adjustment Settlement bars such recovery, the FERC held that the pipelines are not entitled to bill any Order 94 charges to Columbia Transmission. The FERC ordered the upstream pipelines to refund the principal amounts of all Order 94 collections received from Columbia Transmission, but waived any requirement that these pipelines pay interest on the refunds. All issues related to Order 94, resulting from FERC's January 1994 ruling, have been resolved. Still pending is a separate FERC order issued in February 1995, that directed another former upstream pipeline supplier, Transcontinental Gas Pipe Line Corporation (Transco), to refund to Columbia Transmission principal Order 94 amounts it had previously collected from Columbia Transmission. Transco refunded to Columbia Transmission approximately $7 million in May 1995; however, Transco is appealing the FERC order to the U.S. District Court of Appeals. Oral arguments were held in March 1996. 14 17 PART 1 - FINANCIAL INFORMATION ITEM 2 - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED) TRANSMISSION OPERATIONS (CONTINUED) Volumes Total throughput for the first quarter increased by 47 Bcf, to 502.5 Bcf compared to last year. Market area transportation for the first three months of 1996 increased 28.3 Bcf, or 7%, reflecting colder weather in the current period compared to the same period last year. During the first quarter of 1996, weather was 4% colder than normal and 13% colder than the same period in 1995. Colder weather also led to higher Mainline and Short-haul transportation, up 15.3 Bcf and 18.6 Bcf, or 10% and 37%, respectively. Also increasing Short-haul transportation were increased marketing efforts and an increase in offshore gas supply at Vermillion, Eugene Island, Garden Banks and West Cameron. Operating Revenues Total operating revenues for the first quarter of 1996 of $225.9 million were up $22.7 million over last year. After adjusting for revenues related to the recovery of transportation and other costs that are fully offset in operating expenses, operating revenues increased approximately $14 million over 1995. This increase was primarily due to the implementation of higher rates for Columbia Transmission that became effective February 1, 1996, subject to refund. Further contributing to the increase were higher rates for Columbia Gulf resulting from the FERC - approved rate settlement in July 1995, and higher throughput on the Columbia Gulf production area facilities resulting from colder weather in the current period. In the first quarter of 1995, a non-recurring $5.4 million improvement was recorded by Columbia Gulf for its portion of the Ozark partnership's exit fees. Columbia Gulf sold its interests in the Ozark pipeline partnership in the second quarter of 1995. Operating Income Operating income of $85.6 million, increased $9 million over last year primarily due to the $22.7 million higher operating revenues, partially offset by $13.7 million higher operating expenses reflecting increased depreciation rates, higher property taxes and increases in operation and maintenance expenses. 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 Ended March 31 ---------------------------- 1996 1995 -------- -------- (millions) NET REVENUES Sales revenues $ 856.7 $ 767.1 Less: Cost of gas sold 518.7 475.4 --------- -------- Net Sales Revenues 338.0 291.7 --------- -------- Transportation revenues 35.9 33.6 Less: Associated gas costs 3.2 3.1 --------- -------- Net Transportation Revenues 32.7 30.5 --------- -------- Net Revenue 370.7 322.2 --------- -------- OPERATING EXPENSES Operation and maintenance 116.5 118.3 Depreciation 31.6 30.9 Other taxes 54.6 56.8 --------- -------- Total Operating Expenses 202.7 206.0 --------- -------- OPERATING INCOME $ 168.0 $ 116.2 ========= ======== THROUGHPUT (BCF) Sales Residential 102.7 90.4 Commercial 42.3 36.6 Industrial and other 3.5 3.0 -------- -------- Total Sales 148.5 130.0 Transportation 71.7 76.8 -------- -------- Total Throughput 220.2 206.8 -------- -------- Off-System Sales 4.4 3.1 -------- -------- Total Sold or Transported 224.6 209.9 ======== ======== SOURCES OF GAS FOR THROUGHPUT (BCF) Sources of Gas Sold Spot Market* 79.0 46.6 Producers 16.2 19.8 Storage withdrawals 68.5 69.0 Other (10.8) (2.3) -------- -------- Total Sources of Gas Sold 152.9 133.1 Transportation received for delivery to customers 71.7 76.8 -------- -------- Total Sources 224.6 209.9 ======== ========
*Purchase contracts of less than one year 16 19 PART 1 - FINANCIAL INFORMATION ITEM 2 - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED) DISTRIBUTION OPERATIONS (CONTINUED) Market Conditions Weather for the first quarter of 1996 was 13% colder than last year and 4% colder than normal. The 1995-96 winter heating season, which extends from November through March, was 23% colder than the same period last year, as well as 8% colder than normal. The distribution subsidiaries (Distribution) maintained full service to firm sales customers without curtailments or interruption throughout this period. Regulatory Matters Columbia Gas of Ohio, Inc.'s (Columbia of Ohio) 1994 rate case settlement provided for a review of the company's revenue requirements by the collaborative group, composed of diverse interested parties (Collaborative), for the purpose of evaluating the need to adjust base rates at May 1, 1996. The Collaborative provides for a more cooperative environment, thereby possibly avoiding lengthy and costly litigation. On March 8, 1996, Columbia of Ohio filed an "Announcement of Collaborative Process" through which it notified the Public Utilities Commission of Ohio (PUCO) that the Collaborative has commenced the review process which could possibly result in a recommendation for an adjustment to Columbia of Ohio's base rates in 1996. In March 1996, the PUCO also ruled that no refunds were necessary for amounts previously collected by Columbia of Ohio under the terms of a pilot weather normalization program (WNA). This program was discontinued in 1995; however, complaints were filed by consumer groups and others requesting refunds of iamounts collected under WNA. The PUCO has determined that the amounts collected while the WNA was in effect were appropriate and that the complaints against Columbia of Ohio should be dismissed. Distribution continues to make inroads in gaining acceptance of non-traditional regulatory treatment of gas purchase related transactions. The Pennsylvania Public Utility Commission approved Columbia Gas of Pennsylvania, Inc.'s (Columbia of Pennsylvania) request for a capacity release incentive program that includes a mechanism allowing Columbia's shareholders to benefit from any proceeds generated beyond an established benchmark. This program would allow Columbia of Pennsylvania to sell excess upstream pipeline capacity that it had previously reserved, but is currently not necessary to meet customer requirements. This program supplements Columbia of Pennsylvania's existing off-system sales and gas procurement incentive programs. The Maryland Public Service Commission approved a two-year pilot program to implement off-system sales, capacity release and gas procurement incentive programs. In Virginia, legislation was enacted that will allow gas utilities in the state to propose new performance-based rate making methods. The law, which becomes effective July 1, 1996, provides utilities the opportunity to propose rates based on company standards of excellence in customer service, management performance, operations and gas supply purchasing. Similar legislation has been passed by the Ohio House of Representatives. 17 20 PART 1 - FINANCIAL INFORMATION ITEM 2 - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED) DISTRIBUTION OPERATIONS (CONTINUED) Gas Supply Distribution's gas supply portfolio, with its large storage component, has the flexibility to accommodate the impact of weather variations on traditional customer demand as well as provide opportunities to increase revenues through incentive off-system sales programs. Off-system sales and exchange transactions outside of Distribution's traditional market areas totaled over 15 Bcf in the first quarter resulting in pre-tax income of $0.9 million, an increase of approximately 11 Bcf and $0.8 million, respectively, from the prior year. The income effect of off-system sales and exchange activity is expected to increase significantly as off-system incentives are approved by other regulatory bodies. The cold weather during the first quarter of 1996 increased the need for capacity to serve customers and therefore reduced opportunities to release unused capacity. Proceeds from these transactions totaled $ 5.2 million, a decrease of $1.2 million from the prior year, and were recorded as a reduction to gas costs. Once established benchmarks are exceeded, a share of the proceeds generated would improve income under approved incentive programs. These benchmarks are tied to various levels of unused capacity being released with a larger percentage of the income being retained as the level increases. As discussed on the previous page under "Regulatory Matters", Distribution has been successful in convincing the regulatory commissions in some of its jurisdictions, that this type of incentive program benefits both the distribution company and the customers. Distribution continues to work with the regulatory commissions in areas it serves that do not have approved programs in place. Volumes First quarter 1996 throughput of 224.6 Bcf, increased 14.7 Bcf over the same period last year due to the favorable effect of higher residential and commercial tariff sales attributable to 13% colder weather and customer growth. This increase was mitigated by reduced industrial transportation that resulted from interruptions by upstream suppliers due to capacity constraints caused by the colder weather. Net Revenues Net revenues for the current quarter were $370.7 million, up $48.5 million over the first quarter of 1995, primarily reflecting $34 million from increased throughput and $11 million for higher rates in effect in four of the five jurisdictions that Distribution serves. The remaining increase was largely due to higher revenue surcharges that are offset in expense and have no effect on operating income. Operating Income Increased net revenues of $48.5 million was the principal reason that operating income of $168 million increased $51.8 million over last year. Operating expenses of $202.7 million for the current period were essentially unchanged from last year. Benefits gained through the implementation of cost discipline programs and the streamlining of operations have helped to slow the rise in operating costs. 18 21 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 Ended March 31 ----------------------------- 1996 1995 -------- --------- (millions) OPERATING REVENUES Gas $ 27.7 $ 36.7 Oil and liquids 1.2 11.9 -------- ------- Total Operating Revenues 28.9 48.6 -------- ------- OPERATING EXPENSES Operation and maintenance 8.9 21.0 Depreciation and depletion 6.9 24.9 Other taxes 2.3 2.8 -------- ------- Total Operating Expenses 18.1 48.7 -------- ------- OPERATING INCOME (LOSS) $ 10.8 $ (0.1) ======== ======= GAS PRODUCTION STATISTICS Production (Bcf) Appalachian 8.5 9.1 Southwest - 8.6 --------- -------- Total 8.5 17.7 ========= ======== Average Price ($/Mcf) Appalachian 3.14 2.27 Southwest - 1.75 --------- -------- Total 3.14 2.02 ========= ======== OIL AND LIQUIDS PRODUCTION STATISTICS Production (000Bbls) Appalachian 70 78 Southwest - 664 -------- -------- Total 70 742 ======== ======== Average Price ($/Bbl) Appalachian 16.71 15.97 Southwest - 16.11 -------- -------- Total 16.71 16.10 ======== ========
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 (CONTINUED) Sale of Southwest Oil and Gas Subsidiary On April 30, 1996, (effective December 31, 1995) Columbia sold Columbia Development to a privately-held exploration and production concern for approximately $200 million in cash. 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. Gathering Facilities Under Order No. 636, the natural gas pipeline industry is required to eventually unbundle gathering services from other transportation services. Columbia Transmission provides transportation services, including gathering services, for a significant portion of gas produced by CNR. As part of its unbundling, Columbia Transmission will transfer certain gathering facilities to CNR. Columbia Transmission anticipates filing for FERC approval to transfer the facilities in the second quarter of 1996 and completing the transfer by the end of the year. Drilling Activity Through the first quarter of 1996, CNR had participated in five wells in Ohio and one well in West Virginia of which three have been successful. CNR's 1996 capital program provided for the participation in joint venture prospects in Ohio where preliminary work has been completed on prospect sitings and a delivery infrastructure. It is anticipated that this activity will still occur in 1996, once the evaluation is completed. Volumes For the three months ended March 31, 1996, gas production was 8.5 Bcf, a decrease of 9.2 Bcf from last year. After adjusting for Columbia Development, which is no longer included in the consolidated results, gas volumes declined slightly by 0.6 Bcf due to curtailments caused by required repairs and normal production declines. CNR's operations are focused in the Appalachian area where reserves predominately consist of natural gas. CNR's oil and liquids production during the current quarter was 70,000 barrels, a decrease of 8,000 barrels. Revenues Gas revenues for the first quarter of 1996 of $27.7 million, decreased $9 million from the same period last year. After adjusting for Columbia Development, gas revenues for CNR increased by $8.7 million due to a significant increase in natural gas prices. Average Appalachian gas prices in the first quarter of $3.14 per Mcf, increased $0.87 per Mcf or 38% from the same period last year. These higher prices were due to colder weather in the eastern United States. 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) Revenues from oil and liquids production for the three months ended March 31, 1996, were $1.2 million, down $10.7 million from last year. After adjusting for Columbia Development, oil and liquids production revenues were relatively unchanged. Operating Income (Loss) For the current quarter, operating income was $10.8 million compared to an operating loss of $100,000 in the same quarter last year. The improvement was largely attributable to lower depletion expense of $18 million due to reduced depletable plant resulting from the sale of Columbia Development and higher average gas prices for CNR. The higher average prices also increased CNR's revenues $8.7 million. 21 24 PART 1 - FINANCIAL INFORMATION ITEM 2 - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED) OTHER ENERGY OPERATIONS
Three Months Ended March 31 --------------------------- 1996 1995 -------- --------- (millions) NET REVENUES Gas marketing revenues $ 158.1 $ 58.7 Less: Products purchased 149.9 56.9 ------- ------- Net Gas Marketing Revenues 8.2 1.8 ------- ------- Propane revenues 32.3 25.5 Less: Products purchased 17.9 14.1 ------- ------- Net Propane Revenues 14.4 11.4 ------- ------- Other Revenues 20.5 19.8 ------- ------- Net Revenues 43.1 33.0 ------- ------- OPERATING EXPENSES Operation and maintenance 22.4 21.4 Depreciation and depletion 2.3 2.1 Other taxes 1.7 1.6 ------- ------- Total Operating Expenses 26.4 25.1 ------- ------- OPERATING INCOME $ 16.7 $ 7.9 ======= ======= PROPANE SALES (MILLIONS OF GALLONS) Retail 15.0 11.6 Wholesale and Other 16.2 17.7 ------- -------- Total Propane Sales 31.2 29.3 ======== =======
22 25 PART 1 - FINANCIAL INFORMATION ITEM 2 - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED) OTHER ENERGY OPERATIONS (CONTINUED) Fuel Management Services Columbia Energy Services Corporation (Columbia Energy Services), Columbia's nonregulated energy marketer, has agreed to provide fuel management services for a 240-megawatt natural gas-fueled independent power project in Louisa County, Virginia. As fuel manager, Columbia Energy Services will be responsible for developing, implementing and administering a comprehensive program to provide year-round natural gas and fuel oil supplies for the project. It will also arrange natural gas dispatching and transportation services and supervise gas contract administration and coordination efforts. Columbia Energy Services provides similar fuel management for a 340-megawatt power project in Chesapeake, Virginia. In addition, Columbia Energy Services has agreed to provide fuel management services for the Honda of America Manufacturing, Inc. plants in Ohio, beginning in May 1996. As fuel manager, Columbia Energy Services will be responsible for developing and implementing a program to analyze and monitor the natural gas requirements, assist in procuring the least cost and most reliable supplies, coordinate all dispatching and transportation services, and handle all measurement, accounting and billing matters. Columbia Energy Services will also assist in the development of energy acquisition strategies and monitor federal and state regulatory activities that could affect site operations. Energy Related Services Columbia Energy Services recently formed a wholly-owned subsidiary, Columbia Service Partners, Inc., to provide a variety of new services to both homeowners and businesses. The new company will initially focus on nongas needs of Distribution's customers. During the second quarter of 1996 it will phase in appliance and gas line repair and other warranty programs to residential customers. Later it expects to complement these services with warranty and energy management services to commercial and industrial customers. These new programs are part of Columbia's ongoing effort to become a full service provider of energy and energy-related services. Cogeneration and Related Services TriStar Ventures Corporation (TriStar) has investments in four cogeneration projects, with a combined total capacity of nearly 300 megawatts, of which TriStar has ownership interests that average approximately 36%. During the first quarter of 1996, these plants produced a total of 378,000 megawatt hours of electricity compared to 348,100 in the same period last year. In addition to its investments, TriStar provides administrative, accounting and fuel management services to three of these facilities. In 1995, TriStar assumed operation of a power gathering station that provides electricity and steam energy for a large warehouse in Ohio. TriStar also provides fuel management and accounting services for this facility. Propane Operations Columbia's two propane subsidiaries, Columbia Propane Corporation and Commonwealth Propane, Inc. serve approximately 74,300 customers in Kentucky, Maryland, New York, North Carolina, 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) Ohio, Pennsylvania, Virginia and West Virginia. The propane subsidiaries continue to focus on higher-margin residential markets including the use of propane service to secure new markets until natural gas service is available. To promote the sale of propane, the subsidiaries have expanded their extended warranty program for new and existing appliances as well as their cylinder exchange program, which allows customers purchasing propane to exchange their old cylinders for reconditioned cylinders. Cove Point Facility Columbia LNG Corporation (Columbia LNG) is a partner with subsidiaries of Potomac Electric Power Company in Cove Point LNG Limited Partnership (Cove Point LNG). Cove Point LNG owns and operates one of the largest liquefied natural gas (LNG) peaking and storage facilities in the United States located at Cove Point, Maryland. Commercial operation of the Cove Point facility began in September 1995. In early 1996 Cove Point LNG initiated a new marketing program offering, at a competitive discount, more than 2.2 million dekatherms of firm peaking service to new customers in the Southwest. Through this and other marketing activities, Cove Point anticipates a substantial level of increased utilization of its liquefaction and firm storage capability during the 1996-1997 operating year. Net Revenues Net revenues for the three months ended March 31, 1996, of $43.1 million, increased by $10.1 million from the same period last year primarily due to the impact of colder weather this year. Net revenues for the gas marketing subsidiary increased $6.4 million reflecting increased margins and volumes sold while net revenues from propane operations increased $3 million reflecting increased weather-generated throughput. Other net revenues increased $0.7 million primarily due to increased revenues from TriStar's cogeneration investments and management services. Operating Income Operating income for the first quarter of 1996 was $16.7 million, up $8.8 million from last year as the significant increase in net revenues due to the colder weather was only partially offset by an increase of $1.3 million in operating expenses. 24 27 PART II - OTHER INFORMATION ITEM 1 - LEGAL PROCEEDINGS No new 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, except as follows: I. Bankruptcy Matters A. Producer Contract Disputes 1. Daniel Garshman v. Columbia Gas Transmission Corporation, No. ATL-L-000172-99 (Sup. Ct. N.J. 1993). Following trial, the New Jersey State Court decided that certain investors in Appalachian producers did not have third party beneficiary status. On December 6, 1995, the Bankruptcy Court entered an order disallowing a class action proof of claim, since it was duplicative of their individual claims. Bankruptcy Court action on the individual claims is deferred pending the appeal of the State Court order. Briefing on the cross-appeals of the State Court order was completed on March 5, 1996. 2. New Bremen Corp. v. Columbia Gas Transmission Corp and Columbia Gulf Transmission Co., No. 88V-631 (Dist. Ct Austin County, TX). In this state court action, concerning the interpretation of a producer contract subject to the estimation proceedings in the Bankruptcy Court, the U.S. District Court in Texas, on March 12, 1996 acting upon a motion filed by Columbia Transmission, entered an order finding that there was no just reason to delay entry of judgment under Rule 54(b) and therefore, entered final judgment of its August 11, 1995 order which granted Columbia Transmission's motion for partial summary judgement. New Bremen Corp. is expected to appeal. II. Regulatory Matters. A. Tennessee Gas Pipeline Take-Or-Pay Transition Cost Recovery Filing. Federal Energy Regulatory Commission (FERC) Docket No. RP96-61. In this proceeding in which Columbia Transmission is protesting a direct bill from Tennessee Gas Pipeline Company, which could result in approximately $5 million of exposure, briefing is substantially complete. B. Direct Billing of Past Period Production and Production Related Costs. 1. Columbia Gas Transmission Corp. v. FERC, C. A. No. 94-1727 (U.S. Ct. of App., D.C. Cir.) These are proceedings before FERC, on remand from the Court of Appeals, to settle billing by upstream suppliers of prior period production related costs. The refund report and request to terminate proceedings in connection with the Texas Gas settlement was approved February 14, 1996, and related appeals were dismissed. On March 29, 1996, Columbia Transmission entered into an agreement with Panhandle Eastern Pipeline Company (Panhandle) to resolve the issues in FERC Docket Nos. RP85-203. Under the settlement, Panhandle refunded a principal amount of approximately $2 million plus post-February 1, 1994 interest of approximately $0.4 million and Panhandle and Columbia Transmission agreed to retain all amounts collected from each other pursuant to the FERC's February 11, 25 28 PART II - OTHER INFORMATION ITEM 1 - LEGAL PROCEEDINGS 1993 order approving a prior settlement. Appeals remain pending with respect to Transcontinental Gas Pipeline Corporation. Briefs have been filed and oral argument was held on March 19, 1996. C. Transportation Costs Recovery Adjustment (TCRA) 1. Columbia Gas Transmission Corp. FERC Docket No. RP95-196 and UGI Utilities, Inc. v. Columbia Gulf Transmission Co. and Columbia Gas Transmission Corp., FERC Docket No. RP95-397. Protests have been filed in this docket questioning the recovery of certain costs paid to Columbia Gulf. An order was issued April 2, 1996 generally denying all protests and denying UGI's request for a rehearing. The FERC did, however, establish hearing procedures concerning whether Columbia Gulf's environmental costs were prudently incurred. A prehearing conference was held on April 22, 1996. The FERC also directed its Staff to audit Columbia Gulf's non-environmental costs to assure that they were appropriately billed to Columbia Transmission. III. Insurance Coverage Litigation A. Columbia Gas Transmission Corp. v. Aetna Casualty & Surety Co., C.A. No. 94-C-454 (Kanawha W. Va. Cir. Ct. filed March 14, 1994). Columbia Transmission filed a complaint in West Virginia State Court seeking a declaratory judgment that its insurance policies provide coverage for environmental cleanup costs. All insurers have responded to the complaints. The case is currently stayed under the evergreen provision of the agreed scheduling order entered by the Court on November 29, 1995, in order to allow informal discussions among the parties. The parties have also entered into an agreed order concerning a special discovery master which was also entered by the Court. B. Columbia Gulf Transmission Co. v. Aetna Casualty & Surety Co., C.A. No. 95-C-177 (Kanawha W. Va. Cir. Ct. filed January 19, 1995). Columbia Gulf filed a complaint in West Virginia State Court seeking a declaratory judgment that its insurance policies provide coverage for environmental cleanup costs. All insurers have responded to the complaints. The case is currently stayed under the evergreen provision of the agreed scheduling order entered by the Court on November 29, 1995, in order to allow informal discussions among the parties. The parties have also entered into an agreed order concerning a special discovery master which was also entered by the Court. 26 29 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 The Annual Meeting of Stockholders of The Columbia Gas System, Inc. was held on April 26, 1996. Stockholders of record at the close of business on February 29, 1996, were entitled to notice of, and to vote at, the meeting. On the record date, Columbia had outstanding 49,221,845 shares of common stock, each of which was entitled to one vote at the meeting. The election of five directors each to serve a term of three years, the election of Arthur Andersen LLP as independent public accountants and the adoption of a Long-Term Incentive Plan and a Phantom Stock Plan were voted upon and approved by the requisite number of shares present in person or by proxy at the meeting. The following is a summary of the results of that meeting: A. Election of Directors
Name of Director Votes For Votes Withheld - ---------------- --------- -------------- Robert H. Beeby 38,257,651 884,181 Malcolm T. Hopkins 38,682,296 459,535 William E. Lavery 38,722,142 419,689 Oliver G. Richard III 38,668,731 473,101 William R. Wilson 38,695,125 446,707
B. Election of Arthur Andersen LLP as independent public accountants:
Votes For Votes Against Abstain --------- ------------- ------- 38,277,245 753,900 110,686
C. Approval of a Long-Term Incentive Plan
Votes For Votes Against Abstain --------- ------------- ------- 23,486,957 8,231,259 443,571
27 30 PART II - OTHER INFORMATION (CONTINUED) D. Approval of a Phantom Stock Plan for Outside Directors in lieu of retirement benefits.
Votes For Votes Against Abstain --------- ------------- ------- 34,650,294 3,857,275 634,263
Item 5. Other Information None Item 6. Exhibits and Reports on Form 8-K
Exhibit Number ------- 11 Statement re Computation of Per Share Earnings 12 Statements of Ratio of Earnings to Fixed Charges and Preferred Stock Dividends 27 Financial Data Schedule
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 April 12, 1996
28 31 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: April 30, 1996 By: /s/ RICHARD E. LOWE --------------------------------- R. E. Lowe Vice President, Controller and Chief Accounting Officer 29 EX-11 2 STATEMENTS 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 Twelve Months Ended Ended March 31, March 31, ---------------- ------------------ 1996 1995 1996 1995 ------ ------ ------ ----- Computation for Statements of Consolidated - ------------------------------------------ Income ($ in millions) - ---------------------- Income (Loss) before extraordinary item . . . . . . . . . . . . . 151.3 128.8 (409.8) 234.8 Extraordinary item . . . . . . . . . . . . . . . . . . . . . . . - - 71.6 - - ------------------------------------------------------------------------------------------------------------------------------------ Net income (loss) . . . . . . . . . . . . . . . . . . . . . . . . 151.3 128.8 (338.2) 234.8 - ------------------------------------------------------------------------------------------------------------------------------------ Earnings (Loss) per share of common stock (based on average shares outstanding) ($) Before extraordinary item . . . . . . . . . . . . . . . . . . . . 2.99 2.55 (8.09) 4.64 Extraordinary item . . . . . . . . . . . . . . . . . . . . . . . - - 1.41 - - ------------------------------------------------------------------------------------------------------------------------------------ Earnings (Loss) on common stock . . . . . . . . . . . . . . . . . 2.99 2.55 (6.68) 4.64 ==================================================================================================================================== - ------------------------------------------------------------------------------------------------------------------------------------ Additional computation of average common shares outstanding (thousands) (NOTE) - ------------------------------------------------------------------------------------------------------------------------------------ Average shares of common stock outstanding . . . . . . . . . . . 50,662 50,563 50,603 50,561 Incremental common shares applicable to common stock based on the common stock daily average market price: Applicable to contingent stock awards . . . . . . . . . . . . . 60 - - 2 - ------------------------------------------------------------------------------------------------------------------------------------ Average common shares as adjusted . . . . . . . . . . . . . . . . 50,722 50,563 50,603 50,563 ==================================================================================================================================== Average shares of common stock outstanding . . . . . . . . . . . 50,662 50,563 50,603 50,561 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 . . . . . . . . . . . . . 74 - - 2 - ------------------------------------------------------------------------------------------------------------------------------------ Average common shares assuming full dilution . . . . . . . . . . 50,736 50,563 50,603 50,563 Earnings (Loss) per share of common stock as adjusted: Before extraordinary item . . . . . . . . . . . . . . . . . . . . 2.98 2.55 (8.09) 4.64 Extraordinary item . . . . . . . . . . . . . . . . . . . . . . . - - 1.41 - - ------------------------------------------------------------------------------------------------------------------------------------ Earnings (Loss) on common stock as adjusted ($) . . . . . . . . . 2.98 2.55 (6.68) 4.64 ==================================================================================================================================== Earnings (Loss) per common shares assuming full dilution: Before extraordinary item . . . . . . . . . . . . . . . . . . . . 2.98 2.55 (8.09) 4.64 Extraordinary item . . . . . . . . . . . . . . . . . . . . . . . - - 1.41 - - ------------------------------------------------------------------------------------------------------------------------------------ Earnings (Loss) on common stock assuming full dilution ($) . . . 2.98 2.55 (6.68) 4.64 ====================================================================================================================================
NOTE These calculations are submitted in accordance with the Securities Exchange Act of 1934 Release No. 9083 although not required by footnote 2 to paragraph 14 of Accounting Principles Opinion No. 15 because they result in dilution of less than 3%. EX-12 3 STATEMENTS OF RATIO OF EARNINGS TO FIXED CHARGES 1 Exhibit 12 THE COLUMBIA GAS SYSTEM, INC. AND SUBSIDIARIES Statements of Ratio of Earnings to Fixed Charges and Preferred Stock Dividends ($ in millions)
Twelve Months Ended March 31, --------------- 1996 1995 ------- -------- Consolidated Income (Loss) from Continuing Operations before Income Taxes, Extraordinary Item and Cumulative Effect of Accounting Change . . . . . . . . . . . . . . . . . . . . (616.6) 234.8 Adjustments: Interest during construction . . . . . . . . . . . . . . . . (20.4) - Distributed (Undistributed) equity income . . . . . . . . . . (2.8) (6.8) Fixed charges . . . . . . . . . . . . . . . . . . . . . . . . 1,079.4 37.1 -------- --------- Earnings Available . . . . . . . . . . . . . . . . . . . . 439.6 265.1 -------- --------- Fixed Charges: Interest on long-term and short-term debt . . . . . . . . . . 1,028.3 0.2 Other interest . . . . . . . . . . . . . . . . . . . . . . . 51.1 36.9 -------- --------- Total Fixed Charges before Adjustments *, ** . . . . . . . 1,079.4 37.1 -------- --------- Adjustments: Gain/(Loss) on reacquired debt . . . . . . . . . . . . . . . - - -------- --------- Total Fixed Charges . . . . . . . . . . . . . . . . . . . . 1,079.4 37.1 -------- --------- Ratio of Earnings Before Taxes to Fixed Charges . . . . . . . . N/A(a) 7.14 =========== ========= Twelve Months Ended December 31, ------------------------------------------------------- 1995 1994 1993 1992 1991 -------- -------- -------- -------- ------ Consolidated Income (Loss) from Continuing Operations before Income Taxes, Extraordinary Item and Cumulative Effect of Accounting Change . . . . . . . . . . . . . . . . . . . . (643.0) 392.2 288.1 161.4 (1,205.8) Adjustments: Interest during construction . . . . . . . . . . . . . . . . (20.2) - - - (3.4) Distributed (Undistributed) equity income . . . . . . . . . . (7.9) (0.9) (0.1) (0.1) (2.4) Fixed charges . . . . . . . . . . . . . . . . . . . . . . . . 1,040.8 14.8 101.5 13.7 139.9 -------- ------- --------- ------ ---------- Earnings Available . . . . . . . . . . . . . . . . . . . . 369.7 406.1 389.5 175.0 (1,071.7) -------- ------- --------- ------ ---------- Fixed Charges: Interest on long-term and short-term debt . . . . . . . . . . 987.2 0.7 3.1 4.9 112.4 Other interest . . . . . . . . . . . . . . . . . . . . . . . 53.6 14.1 98.4 8.8 27.6 -------- ------- --------- ------ ---------- Total Fixed Charges before Adjustments *, ** . . . . . . . 1,040.8 14.8 101.5 13.7 140.0 -------- ------- --------- ------ ---------- Adjustments: Gain/(Loss) on reacquired debt . . . . . . . . . . . . . . . - - - - (0.1) -------- ------- --------- ------ --------- Total Fixed Charges . . . . . . . . . . . . . . . . . . . . 1,040.8 14.8 101.5 13.7 139.9 -------- ------- --------- ------ --------- Ratio of Earnings Before Taxes to Fixed Charges . . . . . . . . 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 additi onal $639.8, $671.1 and $1,211.6 million of earnings, for the twelve months ended March 31, 1996 and the twelve months ended December 31, 1995 and 1991 respectively. * This amount excludes approximately $240 million interest expense not recorded in the twelve months ended March 31, 1995, and $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 milli on 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 March 31, 1996, as reported in Form 10-Q. ** This amount excludes $8.6 million of interest expense not recorded wit h respect to the registrant's guarantee of LESOP Trust's debentures for the twelve months ended March 31, 1995. Also excluded are $8.6 million, $ 8.6 million, $8.6 million and $15.5 million of interest expense not record ed 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 22099 The Columbia Gas System, Inc. and Subsidiaries 1,000 3-MOS December 31, 1995 January 1, 1996 March 31, 1996 Per Book 3,532,100 720,800 1,382,300 49,700 419,100 6,104,000 550,200 735,200 213,800 1,499,200 0 0 2,004,200 0 0 0 500 0 2,700 0 2,600,600 6,104,000 1,203,000 86,300 924,800 924,800 278,200 3,100 281,300 43,700 151,300 0 151,300 0 0 300,200 2.99 2.99
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