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