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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
----------------------
FORM 10-Q
QUARTERLY REPORT PURSUANT TO SECTION 13 or 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the Quarterly Period Ended March 31, 1998
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Commission File Number 1-3880
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NATIONAL FUEL GAS COMPANY
(Exact name of registrant as specified in its charter)
New Jersey 13-1086010
---------- ----------
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
10 Lafayette Square
Buffalo, New York 14203
------------------- -----
(Address of principal executive offices) (Zip Code)
(716) 857-6980
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(Registrant's telephone number, including area code)
----------------------------------------------------
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 and (2) has been subject to such filing requirements for
the past 90 days. YES X NO
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Indicate the number of shares outstanding of each of the issuer's classes of
common stock, as of the latest practicable date:
Common stock, $1 par value, outstanding at April 30, 1998:
38,351,539 shares.
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<PAGE>
Company or Group of Companies for which Report is Filed:
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NATIONAL FUEL GAS COMPANY (Company or Registrant)
SUBSIDIARIES: National Fuel Gas Distribution Corporation (Distribution
Corporation)
National Fuel Gas Supply Corporation (Supply Corporation)
Seneca Resources Corporation (Seneca)
Highland Land & Minerals, Inc. (Highland)
Leidy Hub, Inc. (Leidy Hub)
Data-Track Account Services, Inc. (Data-Track)
National Fuel Resources, Inc. (NFR)
Horizon Energy Development, Inc. (Horizon)
Niagara Energy Trading Inc. (NET)
Niagara Independence Marketing Company (NIM)
Seneca Independence Pipeline Company (SIP)
Utility Constructors, Inc. (UCI)
INDEX
Part I. Financial Information Page
----------------------------- ----
Item 1. Financial Statements
a. Consolidated Statements of Income and Earnings
Reinvested in the Business - Three Months and
Six Months Ended March 31, 1998 and 1997 4 - 5
b. Consolidated Balance Sheets - March 31, 1998 and
September 30, 1997 6 - 7
c. Consolidated Statement of Cash Flows - Six
Months Ended March 31, 1998 and 1997 8
d. Notes to Consolidated Financial Statements 9 - 19
Item 2. Management's Discussion and Analysis of Financial
Condition and Results of Operations 19 - 41
Item 3. Quantitative and Qualitative Disclosures About Market Risk 41
Part II. Other Information
--------------------------
Item 1. Legal Proceedings *
Item 2. Changes in Securities 42
Item 3. Defaults Upon Senior Securities *
Item 4. Submission of Matters to a Vote of Security Holders 42
Item 5. Other Information *
Item 6. Exhibits and Reports on Form 8-K 43
Signature 44
* The Company has nothing to report under this item.
<PAGE>
This Form 10-Q contains "forward-looking statements" as defined by the Private
Securities Litigation Reform Act of 1995. Forward-looking statements should be
read with the cautionary statements included in this Form 10-Q at Item 2
"Management's Discussion and Analysis of Financial Condition and Results of
Operations" (MD&A), under the heading "Safe Harbor for Forward-Looking
Statements." Forward-looking statements are all statements other than statements
of historical fact, including, without limitation, those statements that are
designated with a "1" following the statement, as well as those statements that
are identified by the use of the words "anticipates," "estimates," "expects,"
"intends," "plans," "predicts," "projects," and similar expressions.
<PAGE>
Part I. - Financial Information
- -------------------------------
Item 1. - Financial Statements
- ------------------------------
National Fuel Gas Company
-------------------------
Consolidated Statements of Income and Earnings
----------------------------------------------
Reinvested in the Business
--------------------------
(Unaudited)
-----------
Three Months Ended
March 31,
------------------
1998 1997
---- ----
(Thousands of Dollars)
INCOME
Operating Revenues $462,648 $498,704
-------- --------
Operating Expenses
Purchased Gas 188,874 251,573
Fuel Used in Heat and Electric Generation 12,887 578
Operation 93,819 70,272
Maintenance 6,561 6,495
Property, Franchise and Other Taxes 30,680 35,676
Depreciation, Depletion and Amortization 26,798 29,096
Impairment of Oil and Gas Producing Properties 128,996 -
Income Taxes - Net (9,739) 34,202
-------- --------
478,876 427,892
-------- --------
Operating Income (Loss) (16,228) 70,812
Other Income 25,594 584
-------- --------
Income Before Interest Charges and
Minority Interest in Foreign Subsidiaries 9,366 71,396
-------- --------
Interest Charges
Interest on Long-Term Debt 11,115 10,178
Other Interest 17,111 4,109
-------- --------
28,226 14,287
-------- --------
Minority Interest in Foreign Subsidiaries (2,402) -
-------- --------
Net Income (Loss) Available for Common Stock (21,262) 57,109
EARNINGS REINVESTED IN THE BUSINESS
Balance at January 1 (1998, as restated) 484,431 445,554
-------- --------
463,169 502,663
Dividends on Common Stock
(1998 - $.435; 1997 - $.42) 16,604 15,967
-------- --------
Balance at March 31 $446,565 $486,696
======== ========
Earnings (Loss) Per Common Share:
Basic $(0.56) $1.50
====== =====
Diluted N/A $1.48
====== =====
Weighted Average Common Shares Outstanding:
Used in Basic Calculation 38,263,632 38,090,435
========== ==========
Used In Diluted Calculation N/A 38,463,700
========== ==========
N/A - Not applicable due to antidilution
See Notes to Consolidated Financial Statements
<PAGE>
Item 1. - Financial Statements (Cont.)
- --------------------------------------
National Fuel Gas Company
-------------------------
Consolidated Statements of Income and Earnings
----------------------------------------------
Reinvested in the Business
--------------------------
(Unaudited)
-----------
Six Months Ended
March 31,
------------------
1998 1997
---- ----
(Thousands of Dollars)
INCOME
Operating Revenues $833,669 $862,196
-------- --------
Operating Expenses
Purchased Gas 353,141 415,664
Fuel Used in Heat and Electric Generation 17,221 1,118
Operation 159,333 138,155
Maintenance 12,907 11,966
Property, Franchise and Other Taxes 54,891 60,233
Depreciation, Depletion and Amortization 57,918 55,685
Impairment of Oil and Gas Producing Properties 128,996 -
Income Taxes - Net 13,210 56,411
-------- --------
797,617 739,232
-------- --------
Operating Income 36,052 122,964
Other Income 26,762 1,322
-------- --------
Income Before Interest Charges and
Minority Interest in Foreign Subsidiaries 62,814 124,286
-------- --------
Interest Charges
Interest on Long-Term Debt 22,562 20,357
Other Interest 21,151 8,230
-------- --------
43,713 28,587
-------- --------
Minority Interest in Foreign Subsidiaries (2,829) -
-------- --------
Income Before Cumulative Effect 16,272 95,699
Cumulative Effect of Change in Accounting for Depletion (9,116) -
-------- --------
Net Income Available for Common Stock 7,156 95,699
EARNINGS REINVESTED IN THE BUSINESS
Balance at October 1 472,595 422,874
-------- --------
479,751 518,573
Dividends on Common Stock
(1998 - $.87; 1997 - $.84) 33,186 31,877
-------- --------
Balance at March 31 $446,565 $486,696
======== ========
Basic Earnings Per Common Share:
Income Before Cumulative Effect $0.43 $2.52
Cumulative Effect of Change in Accounting for Depletion (0.24) -
----- -----
Net Income Available for Common Stock $0.19 $2.52
===== =====
Diluted Earnings Per Common Share:
Income Before Cumulative Effect $0.42 $2.49
Cumulative Effect of Change in Accounting for Depletion (0.24) -
----- -----
Net Income Available for Common Stock $0.18 $2.49
===== =====
Weighted Average Common Shares Outstanding:
Used in Basic Calculation 38,230,331 38,020,555
========== ==========
Used in Diluted Calculation 38,673,312 38,369,701
========== ==========
See Notes to Consolidated Financial Statements
<PAGE>
Item 1. Financial Statements (Cont.)
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National Fuel Gas Company
-------------------------
Consolidated Balance Sheets
---------------------------
March 31,
1998 September 30,
(Unaudited) 1997
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(Thousands of Dollars)
ASSETS
Property, Plant and Equipment $2,881,283 $2,668,478
Less - Accumulated Depreciation, Depletion
and Amortization 869,214 849,112
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2,012,069 1,819,366
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Current Assets
Cash and Temporary Cash Investments 38,723 14,039
Receivables - Net 206,004 107,417
Unbilled Utility Revenue 38,013 20,433
Gas Stored Underground 7,741 29,856
Materials and Supplies - at average cost 22,919 19,115
Unrecovered Purchased Gas Costs 340 -
Prepayments 37,640 17,807
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351,380 208,667
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Other Assets
Recoverable Future Taxes 91,011 91,011
Unamortized Debt Expense 22,201 23,394
Other Regulatory Assets 46,619 48,350
Investment in Unconsolidated Foreign Subsidiary - 18,887
Deferred Charges 6,912 12,025
Other 76,347 45,631
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243,090 239,298
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$2,606,539 $2,267,331
========== ==========
See Notes to Consolidated Financial Statements
<PAGE>
Item 1. Financial Statements (Cont.)
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National Fuel Gas Company
-------------------------
Consolidated Balance Sheets
---------------------------
March 31,
1998 September 30,
(Unaudited) 1997
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(Thousands of Dollars)
CAPITALIZATION AND LIABILITIES
Capitalization:
Common Stock Equity
Common Stock, $1 Par Value
Authorized - 100,000,000 Shares; Issued
and Outstanding - 38,297,672 Shares and
38,165,888 Shares, Respectively $ 38,298 $ 38,166
Paid in Capital 408,703 405,028
Earnings Reinvested in the Business 446,565 472,595
Cumulative Translation Adjustment (1,175) (2,085)
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Total Common Stock Equity 892,391 913,704
Long-Term Debt, Net of Current Portion 543,410 581,640
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Total Capitalization 1,435,801 1,495,344
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Minority Interest in Foreign Subsidiaries 34,825 -
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Current and Accrued Liabilities
Notes Payable to Banks and
Commercial Paper 378,235 92,400
Current Portion of Long-Term Debt 153,572 103,359
Accounts Payable 63,316 74,105
Amounts Payable to Customers 3,704 10,516
Other Accruals and Current Liabilities 175,588 83,793
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774,415 364,173
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Deferred Credits
Accumulated Deferred Income Taxes 234,131 288,555
Taxes Refundable to Customers 19,427 19,427
Unamortized Investment Tax Credit 11,736 12,041
Other Deferred Credits 96,204 87,791
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361,498 407,814
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Commitments and Contingencies - -
---------- ----------
$2,606,539 $2,267,331
========== ==========
See Notes to Consolidated Financial Statements
<PAGE>
Item 1. - Financial Statements (Cont.)
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National Fuel Gas Company
-------------------------
Consolidated Statement of Cash Flows
------------------------------------
(Unaudited)
-----------
Six Months Ended
March 31,
------------------
1998 1997
---- ----
(Thousands of Dollars)
OPERATING ACTIVITIES
Net Income Available for Common Stock $ 7,156 $ 95,699
Adjustments to Reconcile Net Income to Net Cash
Provided by Operating Activities:
Cumulative Effect of Change in Accounting
for Depletion 9,116 -
Impairment of Oil and Gas Producing Properties 128,996 -
Depreciation, Depletion and Amortization 57,918 55,685
Deferred Income Taxes (48,890) 2,948
Minority Interest in Foreign Subsidiaries 2,829 -
Other (1,074) 5,322
Change in:
Receivables and Unbilled Utility Revenue (100,862) (157,544)
Gas Stored Underground and Materials and
Supplies 23,518 31,478
Unrecovered Purchased Gas Costs (340) (8,443)
Prepayments (19,134) 12,075
Accounts Payable (18,249) (4,184)
Amounts Payable to Customers (6,812) 3,152
Other Accruals and Current Liabilities 84,603 83,843
Other Assets and Liabilities - Net 3,882 25,708
-------- --------
Net Cash Provided by
Operating Activities 122,657 145,739
-------- --------
INVESTING ACTIVITIES
Capital Expenditures (220,889) (84,644)
Investment in Foreign Subsidiaries, Net of Cash
Acquired (75,963) -
Other 353 263
-------- --------
Net Cash Used in Investing Activities (296,499) (84,381)
-------- --------
FINANCING ACTIVITIES
Change in Notes Payable to Banks and Commercial
Paper 281,593 (26,500)
Reduction of Long-Term Debt (52,323) (367)
Dividends Paid on Common Stock (33,131) (31,752)
Proceeds from Issuance of Common Stock 2,387 6,965
-------- --------
Net Cash Provided by (Used in)
Financing Activities 198,526 (51,654)
--------- --------
Net Increase in Cash and
Temporary Cash Investments 24,684 9,704
Cash and Temporary Cash Investments
at October 1 14,039 19,320
-------- --------
Cash and Temporary Cash Investments at March 31 $ 38,723 $ 29,024
======== ========
See Notes to Consolidated Financial Statements
<PAGE>
Item 1. Financial Statements (Cont.)
- -------------------------------------
National Fuel Gas Company
-------------------------
Notes to Consolidated Financial Statements
------------------------------------------
Note 1 - Summary of Significant Accounting Policies
Principles of Consolidation. During the quarter ended March 31, 1998, Horizon's
wholly-owned subsidiary, Horizon Energy Development B.V. (Horizon B.V.) (name
changed from Beheer-En-Beleggingsmaatschappij Bruwabel, B.V. in April 1998)
acquired a 75.3% ownership interest in Prvni severozapadni teplarenska, a.s.
(PSZT). PSZT is a wholesale power and district heating company located in the
northern Bohemia region of the Czech Republic. The Company consolidates PSZT
into its accounts.
During the quarter ended December 31, 1997, Horizon B.V. increased
its ownership interest in Severoceske Teplarny, a.s. and its subsidiaries (SCT)
from 36.8% at September 30, 1997 to 70.8% at December 31, 1997. A tender offer
to SCT's minority shareholders completed in April 1998 has increased Horizon
B.V.'s ownership interest to 82.6% (75.2% at March 31, 1998). The Company
consolidates SCT into its accounts. The equity method was used to account for
Horizon B.V.'s investment in SCT during fiscal 1997.
The acquisitions of SCT and PSZT have been accounted for in
accordance with the purchase method as specified by Accounting Principles Board
Opinion Number 16, "Business Combinations" (APB 16). The acquisitions resulted
in approximately $23.2 million of goodwill, which is being amortized over a
twenty year period. This goodwill ($22.9 million at March 31, 1998) is recorded
in Other Assets in the Company's Consolidated Balance Sheet at March 31, 1998.
The final amount of goodwill is subject to further purchase price adjustments.
"Minority Interest in Foreign Subsidiaries" represents the minority
stockholders' share of the equity and net income of SCT and PSZT.
Quarterly Earnings. The Company, in its opinion, has included all adjustments
that are necessary for a fair statement of the results of operations for the
reported periods. The consolidated financial statements and notes thereto,
included herein, should be read in conjunction with the financial statements and
notes for the years ended September 30, 1997, 1996 and 1995, that are included
in the Company's combined Annual Report to Shareholders/Form 10-K for 1997. The
fiscal 1998 consolidated financial statements will be examined by the Company's
independent accountants after the end of the fiscal year.
The earnings for the six months ended March 31, 1998 (exclusive of
the cumulative effect of a change in accounting for depletion and the impairment
of oil and gas producing properties, both of which are discussed below) should
not be taken as a prediction of earnings for the entire fiscal year ending
September 30, 1998. Most of the Company's business is seasonal in nature and is
influenced by weather conditions. Because of the seasonal nature of the
Company's heating business, earnings during the winter months normally represent
a substantial part of earnings for the entire fiscal year. The impact of
abnormal weather on earnings during the heating season is partially reduced by
the operation of a weather normalization clause included in Distribution
Corporation's New York tariff. The weather normalization clause is effective for
October through May billings. Distribution Corporation's
<PAGE>
Item 1. Financial Statements (Cont.)
- -------------------------------------
tariff for its Pennsylvania jurisdiction does not have a weather normalization
clause. In addition, Supply Corporation's straight fixed-variable rate design,
which allows for recovery of substantially all fixed costs in the demand or
reservation charge, reduces the earnings impact of weather.
Cumulative Effect of Change in Accounting. Effective October 1, 1997, Seneca
changed its method of depletion for oil and gas properties from the gross
revenue method to the units of production method. The new method was adopted
because it provides a better measure of depletion expense and is the preferable
method used by oil and gas producing companies. Seneca's recent acquisition
activities will increase its size and scope of operations in relation to those
of the Company, making now the appropriate time for the change in depletion
methods. (See further discussion of acquisitions in Note 6 - Acquisition of
HarCor Energy, Inc. and in Item 2, Management's Discussion and Analysis under
"Exploration and Production".) The units of production method has been applied
retroactively to prior years to determine the cumulative effect through October
1, 1997. This cumulative effect reduced earnings by $9.1 million, net of income
tax. Depletion of oil and gas properties for the quarter and six months ended
March 31, 1998, has been computed under the newly adopted units of production
method. The effect of the change from the gross revenue method to the units of
production method increased net income for the quarter ended March 31, 1998 by
$130,000. For the six months ended March 31, 1998, the effect of the change
increased income before cumulative effect and net income by $837,000 ($0.02 per
common share, basic and diluted).
Since the Company changed its method of depletion for oil and gas
producing properties in the second quarter of its fiscal year, the first quarter
ended December 31, 1997, is restated as follows:
Three Months Ended
December 31, 1997
--------------------
Original Restated
-------- --------
(Thousands of Dollars, except per share amounts)
Income Before Cumulative Effect $36,827 $37,534
Cumulative Effect of Change in Accounting - (9,116)
------- -------
Net Income Available for Common Stock $36,827 $28,418
======= =======
Basic Earnings Per Common Share:
Income Before Cumulative Effect $0.96 $0.98
Cumulative Effect of Change in Accounting - (0.24)
----- -----
Net Income Available for Common Stock $0.96 $0.74
===== =====
Diluted Earnings Per Common Share:
Income Before Cumulative Effect $0.95 $0.97
Cumulative Effect of Change in Accounting - (0.24)
----- ------
Net Income Available for Common Stock $0.95 $0.73
===== =====
<PAGE>
Item 1. Financial Statements (Cont.)
- -------------------------------------
Pro forma amounts shown below, assume the retroactive application of the new
depletion method:
<TABLE>
<CAPTION>
Three Months Three Months Six Months
Ended Ended Ended
December 31, March 31, March 31,
-------------- ------------- -------------
1997 1996 1998 1997 1998 1997
---- ---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C> <C>
Pro Forma Amounts:
(Thousands of Dollars,
except per share amounts)
Net Income (Loss)
Available for
Common Stock $37,534 $37,960 $(21,262) $ 57,637 $16,272 $95,597
======= ======= ======== ======== ======= =======
Earnings (Loss)
Per Common Share:
Basic $ 0.98 $ 1.00 $ (0.56) $ 1.51 $ 0.43 $ 2.51
======= ======= ======== ======== ======= =======
Diluted $ 0.97 $ 0.99 $ N/A $ 1.50 $ 0.42 $ 2.49
======= ======= ========= ======== ======= =======
</TABLE>
N/A - Not applicable due to antidilution
Oil and Gas Exploration and Development Costs. Oil and Gas property acquisition,
exploration and development costs are capitalized under the full-cost method of
accounting as prescribed by the Securities and Exchange Commission (SEC). All
costs directly associated with property acquisition, exploration and development
activities are capitalized, with the principal limitation that such capitalized
amounts not exceed the present value of estimated future net revenues
(discounted at 10%) from production of proved gas and oil reserves plus the
lower of cost or market of unevaluated properties, net of related income tax
effect (the full-cost ceiling). Future net revenue is estimated based on
end-of-quarter prices adjusted for contracted price changes. If capitalized
costs exceed the full-cost ceiling at the end of any quarter, a permanent
impairment is required to be charged to earnings in that quarter. Such a charge
has no effect on the Company's cash flow.
The surplus of crude oil world-wide has caused oil prices to drop to
their lowest level in recent years, and gas prices have been negatively impacted
by a warmer than normal winter. Due to these price declines, Seneca's
capitalized costs under the full-cost method of accounting exceeded the
full-cost ceiling at March 31, 1998. Seneca was required to recognize an
impairment of its oil and gas producing properties. This charge amounted to
$129.0 million (pretax) and reduced net income for the quarter and six months
ended March 31, 1998, by $79.1 million ($2.07 per common share, basic; $2.05 per
common share, for the six months ended March 31, 1998, on a diluted basis).
Consolidated Statement of Cash Flows. For purposes of the Consolidated Statement
of Cash Flows, the Company considers all highly liquid debt instruments
purchased with a maturity of generally three months or less to be cash
equivalents. Cash interest payments during the six months ended March 31, 1998
and 1997, amounted to $30.5 million and $26.7 million, respectively. Net income
taxes paid during the six months ended March 31, 1998 and 1997 amounted to $20.4
million and $40.9 million, respectively.
<PAGE>
Item 1. Financial Statements (Cont.)
- -------------------------------------
Details of the SCT and PSZT acquisitions during the six months ended
March 31, 1998, are as follows (dollars in millions):
<TABLE>
<CAPTION>
SCT PSZT Total
--- ---- -----
<S> <C> <C> <C>
Assets acquired $74.4 $144.4 $218.8
Liabilities assumed (32.3) (84.4) (116.7)
Existing investment at acquisition (18.9) - (18.9)
Cash acquired at acquisition (6.3) (0.9) (7.2)
----- ------ ------
Cash paid, net of cash acquired $16.9 $ 59.1 $ 76.0
===== ====== ======
</TABLE>
Reclassification. Certain prior year amounts have been reclassified to conform
with current year presentation.
Earnings per Common Share. Basic earnings per common share is computed by
dividing income available for common stock by the weighted average number of
common shares outstanding for the period. Diluted earnings per common share
reflects the potential dilution that could occur if securities or other
contracts to issue common stock were exercised or converted into common stock.
Such additional shares are added to the denominator of the basic earnings per
common share calculation in order to calculate diluted earnings per common
share. The only potentially dilutive securities the Company has outstanding are
stock options. The diluted weighted average shares outstanding shown on the
Consolidated Statement of Income reflects the potential dilution as a result of
these stock options. Such dilution was determined using the Treasury Stock
Method as required by Statement of Financial Accounting Standards No. 128,
"Earnings per Share."
Note 2 - Income Taxes
The components of federal and state income taxes included in the
Consolidated Statement of Income are as follows (in thousands):
Six Months Ended
March 31,
----------------
1998 1997
---- ----
Operating Expenses:
Current Income Taxes -
Federal $52,235 $48,590
State 5,242 4,873
Foreign 4,623 -
Deferred Income Taxes (48,890) 2,948
------- -------
13,210 56,411
Other Income:
Deferred Investment Tax Credit (305) (335)
Minority Interest in Foreign Subsidiaries (1,457) -
Cumulative Effect of Change in Accounting (5,736) -
------- -------
Total Income Taxes $ 5,712 $56,076
======= =======
<PAGE>
Item 1. Financial Statements (Cont.)
- -------------------------------------
Total income taxes as reported differ from the amounts that were
computed by applying the federal income tax rate to income before income taxes.
The following is a reconciliation of this difference (in thousands):
Six Months Ended
March 31,
----------------
1998 1997
---- ----
Net income available for common stock $ 7,156 $ 95,699
Total income taxes 5,712 56,076
-------- --------
Income before income taxes $ 12,868 $151,775
======== ========
Income tax expense, computed at
statutory rate of 35% $ 4,504 $ 53,121
Increase (reduction) in taxes resulting from:
Current state income taxes, net of federal
income tax benefit 3,407 3,165
Depreciation 1,225 851
Miscellaneous (3,424) (1,061)
-------- --------
Total Income Taxes $ 5,712 $ 56,076
======== ========
Significant components of the Company's deferred tax liabilities
(assets) were as follows (in thousands):
At March 31, 1998 At September 30, 1997
---------------------- -----------------------
Deferred Tax Liabilities:
Excess of tax over book
depreciation $135,569 $190,913
Exploration and
intangible well
drilling costs 127,898 117,759
Other 61,786 62,189
-------- --------
Total Deferred Tax
Liabilities 325,253 370,861
-------- --------
Deferred Tax Assets:
Overheads capitalized
for tax purposes (20,998) (19,406)
Other (70,124) (62,900)
--------- --------
Total Deferred Tax
Assets (91,122) (82,306)
-------- --------
Total Net Deferred
Income Taxes $234,131 $288,555
======== ========
The primary issues related to Internal Revenue Service audits of the
Company for the years 1977 - 1994 were settled early in calendar 1998. Net
income for the quarter and six months ended March 31, 1998 was increased by
approximately $5 million as a result of interest, net of tax and other
adjustments, related to this settlement.
<PAGE>
Item 1. Financial Statements (Cont.)
- -------------------------------------
Note 3 - Capitalization
Common Stock. At the Annual Meeting of Shareholders in February 1998, the
Company's shareholders voted to increase the number of shares of authorized
Company common stock from 100,000,000 shares to 200,000,000 shares. This change
became effective April 3, 1998, upon the filing of a certificate of amendment
with the Secretary of State of the State of New Jersey.
During the six months ended March 31, 1998, the Company issued
131,784 shares of common stock under the Company's stock award and option plans
including 7,609 shares of restricted stock.
On December 11, 1997, 658,500 stock options were granted under the
stock award and option plans at an exercise price of $44.875 per share.
Effective April 1, 1998, the Company's section 401(k) Plans, Dividend
Reinvestment Plan and Customer Stock Purchase Plan began utilizing original
issue shares of Company common stock.
Preferred Stock. At the Annual Meeting of Shareholders in February 1998, the
Company's shareholders voted to eliminate the Company's authorized 3,200,000
shares of $25 par value preferred stock and replace it with an authorized amount
of 10,000,000 shares of $1 par value preferred stock. This change became
effective April 3, 1998, upon the filing of a certificate of amendment with the
Secretary of State of the State of New Jersey. The Company does not have any
preferred stock outstanding at this time.
Long-Term Debt. SCT has a term loan in the amount of 145 million Czech Koruna
(CZK) which translates to $4.3 million as of March 31, 1998. The principal will
be paid in quarterly installments over the term of the loan, which matures in
June 2006. The interest rate on this loan is set at the six month PRIBOR (Prague
Interbank Offered Rate) rate plus 1%, which was 16.77% as of March 31, 1998. Two
additional SCT loans, in the aggregate amount of CZK 13.6 million ($0.4
million), are outstanding. Each of these loans has an interest rate set at the
Komercni Banka, a.s. rate plus 1.5%, which was 17.3% as of March 31, 1998. The
principal on these two additional loans will be paid in quarterly installments
over the term of the loans, one of which matures in December 1999 and the other
in December 2000.
PSZT has U.S. dollar denominated debt in the amount of $50.6 million
as of March 31, 1998. The functional currency of PSZT is the Czech Koruna. Since
this debt must be repaid in U.S. dollars, a change in exchange rates between the
Czech Koruna and the U.S. dollar may increase or decrease the amount of Czech
Koruna required to repay the debt, resulting in a corresponding gain or loss to
be recognized in the income statement. During the quarter ended March 31, 1998,
the Czech Koruna increased in value in relation to the U.S. dollar. Accordingly,
PSZT recognized a pretax gain of approximately $2.3 million, which is included
in Other Income in the Consolidated Statement of Income. Subsequent exchange
rate changes over the term of the loan may result in the recognition of
additional gains or losses. The principal of this debt will be paid in quarterly
installments over the period of March 2000 - December 2004. The interest rate on
this debt is set at the six month LIBOR (London Interbank Offered Rates) rate
plus 2.2%, which was 8.04% as of March 31, 1998.
<PAGE>
Item 1. Financial Statements (Cont.)
- -------------------------------------
PSZT also has long-term debentures in the amount of CZK 300 million
($8.9 million). The debentures mature in December 1999 and bear an interest rate
of 13%.
Note 4 - Derivative Financial Instruments
The Company, in its Exploration and Production operations, has
entered into certain price swap agreements to manage a portion of the market
risk associated with fluctuations in the price of natural gas and crude oil,
thereby providing more stability to the operating results of that business
segment. These agreements are not held for trading purposes. The price swap
agreements call for the Company to receive monthly payments from (or make
payments to) other parties based upon the difference between a fixed and a
variable price as specified by the agreement. The variable price is either a
crude oil price quoted on the New York Mercantile Exchange or a quoted natural
gas price in "Inside FERC." These variable prices are highly correlated with the
market prices received by the Company for its natural gas and crude oil
production.
The following summarizes the Company's activity under price swap
agreements for the quarter and six-month periods ended March 31, 1998 and 1997,
respectively:
Quarter Ended Quarter Ended
March 31, 1998 March 31, 1997
-------------- --------------
Natural Gas Price Swap Agreements:
Notional Amount - Equivalent Billion
Cubic Feet (Bcf) 5.7 5.9
Range of Fixed Prices per Thousand Cubic
Feet (Mcf) $2.00 - $2.55 $1.77 - $2.06
Weighted Average Fixed Price per Mcf $2.20 $1.90
Range of Variable Prices per Mcf $2.01 - $2.35 $1.77 - $4.08
Weighted Average Variable Price per Mcf $2.22 $2.87
Loss $(136,000) $(5,714,000)
Crude Oil Price Swap Agreements:
Notional Amount - Equivalent
Barrels (bbl) 219,000 360,000
Range of Fixed Prices per bbl $17.50 - $20.56 $17.40 - $18.71
Weighted Average Fixed Price per bbl $19.04 $18.02
Range of Variable Prices per bbl $15.04 - $16.73 $20.97 - $25.18
Weighted Average Variable Price per bbl $15.95 $22.78
Gain (Loss) $677,000 $(1,713,000)
<PAGE>
Item 1. Financial Statements (Cont.)
- -------------------------------------
Six Months Ended Six Months Ended
March 31, 1998 March 31, 1997
---------------- ----------------
Natural Gas Price Swap Agreements:
Notional Amount - Equivalent Bcf 13.1 12.4
Range of Fixed Prices per Mcf $1.77 - $2.55 $1.71 - $2.10
Weighted Average Fixed Price per Mcf $2.07 $1.93
Range of Variable Prices per Mcf $2.01 - $3.44 $1.77 - $4.11
Weighted Average Variable Price per Mcf $2.68 $2.91
Loss $(8,085,000) $(12,176,000)
Crude Oil Price Swap Agreements:
Notional Amount - Equivalent bbl 453,000 670,000
Range of Fixed Prices per bbl $17.50 - $20.56 $17.40 - $18.71
Weighted Average Fixed Price per bbl $18.62 $17.97
Range of Variable Prices per bbl $15.04 - $21.28 $20.97 - $25.18
Weighted Average Variable Price per bbl $18.01 $23.59
Gain (Loss) $239,000 $(3,806,000)
The Company had the following price swap agreements outstanding at
March 31, 1998.
Natural Gas Price Swap Agreements:
Notional Amount Range of Fixed Weighted Average
Fiscal Year (Equivalent Bcf) Prices Per Mcf Fixed Price Per Mcf
- ----------- ---------------- -------------- -------------------
1998 11.4 $2.00 - $2.35 $2.17
1999 14.0 $2.00 - $2.47 $2.28
2000 2.4 $2.29 - $2.47 $2.37
----
27.8
====
Crude Oil Price Swap Agreements:
Notional Amount Range of Fixed Weighted Average
Fiscal Year (Equivalent bbl) Prices Per bbl Fixed Price Per bbl
- ----------- ---------------- -------------- -------------------
1998 438,000 $17.50 - $20.56 $19.04
1999 135,000 $19.30 - $20.56 $19.86
-------
573,000
=======
Gains or losses from these price swap agreements are accrued in
operating revenues on the Consolidated Statement of Income at the contract
settlement dates. At March 31, 1998, the Company had an unrecognized loss of
approximately $7.1 million related to the price swap agreements which are offset
by corresponding unrecognized gains from the Company's anticipated natural gas
and crude oil production over the terms of the price swap agreements.
The Company, through its natural gas marketing operations,
participates in the natural gas futures market to manage a portion of the market
risk associated with fluctuations in the price of natural gas. Such futures are
not held for trading purposes. At March 31, 1998, the Company had the following
futures contracts outstanding:
<PAGE>
Item 1. Financial Statements (Cont.)
- -------------------------------------
Long "Buy" Positions
Notional Amount Range of Fixed Weighted Average
Fiscal Year (Equivalent Bcf) Prices Per Mcf Fixed Price Per Mcf
- ----------- ---------------- -------------- -------------------
1998 5.0 $2.04 - $2.60 $2.37
1999 2.2 $2.04 - $2.75 $2.50
---
7.2
===
Short "Sell" Positions
Notional Amount Range of Fixed Weighted Average
Fiscal Year (Equivalent Bcf) Prices Per Mcf Fixed Price Per Mcf
- ----------- ---------------- -------------- -------------------
1998 3.9 $2.20 - $2.63 $2.45
1999 .2 $2.38 - $2.42 $2.41
---
4.1
===
Gains or losses from natural gas futures are recorded in Other
Deferred Credits on the Consolidated Balance Sheet until the hedged commodity
transaction occurs, at which point they are reflected in operating revenues in
the Consolidated Statement of Income. At March 31, 1998, the Company had
unrealized gains of approximately $1.4 million related to these futures
contracts. The Company recorded a loss of approximately $0.1 million during the
quarter ended March 31, 1998 and a gain of approximately $1.7 million during the
quarter ended March 31, 1997. The Company recorded gains of approximately $1.2
million and $1.7 million for the six months ended March 31, 1998 and 1997,
respectively. Since these futures contracts qualify and have been designated as
hedges, any gains or losses resulting from market price changes are
substantially offset by the related commodity transaction.
The Company has SEC authority to enter into hedging transactions
related to all or a portion of its existing or anticipated debt. The notional
amounts of the hedging instruments may not exceed the amount of the Company's
outstanding debt. No such hedging transactions were entered into during the
quarter ended March 31, 1998 and none are currently outstanding.
Credit Risk. Credit risk relates to the risk of loss that the Company would
incur as a result of nonperformance by counterparties pursuant to the terms of
their contractual obligations under the price swap agreements and futures
contracts they have issued. The Company is exposed to such credit risk when
fluctuations in natural gas and crude oil market prices result in the Company
recognizing gains on the price swap agreements and futures contracts that it has
entered into. When credit risk arises, such risk to the Company is mitigated by
the fact that the counterparties, or the parent companies of such
counterparties, are investment grade financial institutions. In those instances
where the Company is not dealing directly with the parent company, the Company
has obtained guarantees from the parent company of the counterparty that has
issued the price swap agreements. Accordingly, the Company does not anticipate
any material impact to its financial position, results of operations or cash
flow as a result of nonperformance by counterparties.
<PAGE>
Item 1. Financial Statements (Cont.)
- -------------------------------------
Note 5 - Commitments and Contingencies
Environmental Matters. The Company is subject to various federal, state and
local laws and regulations relating to the protection of the environment. The
Company has established procedures for on-going evaluation of its operations to
identify potential environmental exposures and assure compliance with regulatory
policies and procedures.
It is the Company's policy to accrue estimated environmental clean-up
costs when such amounts can reasonably be estimated and it is probable that the
Company will be required to incur such costs. Distribution Corporation has
estimated that clean-up costs related to several former manufactured gas plant
sites and several other waste disposal sites may range from $14.0 million to
$15.0 million. At March 31, 1998, Distribution Corporation has recorded the
minimum liability of $14.0 million. The approximate 50% increase in the
liability since September 30, 1997 mainly relates to changing circumstances and
revised estimates for one particular former manufactured gas plant site. The
ultimate cost to Distribution Corporation with respect to the remediation of all
sites will depend on such factors as the remediation plan selected, the extent
of the site contamination, the number of additional potentially responsible
parties at each site and the portion, if any, attributed to Distribution
Corporation. The Company is currently not aware of any material additional
exposure to environmental liabilities. However, changes in environmental
regulations or other factors could adversely impact the Company.
In New York and Pennsylvania, Distribution Corporation is recovering
site investigation and remediation costs in rates. Accordingly, the Consolidated
Balance Sheet at March 31, 1998 includes related regulatory assets in the amount
of approximately $13.3 million. For further discussion, see disclosure in Note H
- - Commitments and Contingencies under the heading "Environmental Matters" in
Item 8 of the Company's 1997 Form 10-K.
Other. The Company is involved in litigation arising in the normal course of
business. The Company is involved in regulatory matters arising in the normal
course of business that involve rate base, cost of service and purchased gas
cost issues. While the resolution of such litigation or regulatory matters could
have a material effect on earnings and cash flows, none of this litigation, and
none of these regulatory matters, is expected to have a material effect on the
financial condition of the Company at this time.
Note 6 - Acquisition of HarCor Energy, Inc.
In May 1998, Seneca West Corporation (Seneca West), a wholly-owned
subsidiary of Seneca, completed a tender offer (an offer of $2.00 per share) for
the outstanding shares of HarCor Energy, Inc. (HarCor). Preliminary information
supplied by the depository for the offer indicate that approximately 95% of the
outstanding shares of HarCor common stock were tendered in accordance with the
tender offer. Seneca West gave notice to the depository that Seneca West
accepted for payment all of the shares of HarCor common stock. The cost of
acquiring these shares is approximately $31 million.
<PAGE>
Item 1. Financial Statements (Cont.)
- -------------------------------------
The tender offer was commenced pursuant to the terms of an Agreement
and Plan of Merger among HarCor, Seneca and Seneca West which provides for the
merger of Seneca West with and into HarCor following the successful consummation
of the tender offer. Accordingly, all shares of HarCor common stock that were
not purchased pursuant to the tender offer will be converted in the merger into
the right to receive $2.00 per share. Seneca West intends to consummate the
merger before the end of 1998. The conversion of the remaining shares would cost
Seneca West approximately $1.6 million.
Seneca West's acquisition of HarCor will be accounted for in accordance
with the purchase method as specified by APB 16. HarCor's results of operations
will be incorporated into the Company's consolidated financial statements for
the period subsequent to the completion of the tender offer in May 1998.
The HarCor oil and gas properties are located on the west side of the
San Joaquin Basin in California. These properties are unique for California in
that they produce higher gravity oil than is generally found in this area, as
well as producing natural gas. Included in this acquisition is approximately $54
million of 14 7/8% senior secured debt and other liabilities of HarCor.
Item 2. Management's Discussion and Analysis of Financial Condition and
---------------------------------------------------------------
Results of Operations
---------------------
RESULTS OF OPERATIONS
Earnings.
The Company experienced a loss of $21.3 million, or $0.56 per common
share, for the quarter ended March 31, 1998. This loss includes a non-cash
impairment of Seneca's oil and gas assets in the amount of $79.1 million
(after-tax). Without this item, the quarter's earnings would have been $57.8
million, or $1.51 per common share ($1.49 per common share on a diluted basis).
This compares with earnings of $57.1 million, or $1.50 per common share ($1.48
per common share on a diluted basis), for the quarter ended March 31, 1997.
The Company's earnings were $7.2 million, or $0.19 per common share
($0.18 per common share on a diluted basis), for the six months ended March 31,
1998. This includes the non-cash impairment of Seneca's oil and gas assets,
noted above, as well as the cumulative effect through October 1, 1997, of a
change in depletion methods for Seneca's oil and gas assets in the amount of
$9.1 million, or $0.24 per common share. Without these two non-cash items,
earnings for the six months ended March 31, 1998 would have been $95.4 million,
or $2.50 per common share ($2.47 per common share on a diluted
<PAGE>
Item 2. Management's Discussion and Analysis of Financial Condition and
---------------------------------------------------------------
Results of Operations (Cont.)
-----------------------------
basis). This compares with earnings of $95.7 million, or $2.52 per common share
($2.49 per common share on a diluted basis), for the six months ended March 31,
1997.
The slight increase in earnings for the quarter (exclusive of the
asset impairment noted above) as compared with the prior year's quarter resulted
from higher earnings in the Exploration and Production, International, and
Pipeline and Storage segments offset in part by lower earnings in the Utility
segment.
In the Exploration and Production segment, earnings are up (exclusive
of the asset impairment noted above) due to Seneca's portion of interest income
related to the recent settlement of the primary issues of IRS audits for the
years 1977 - 1994. Partly offsetting this increase was lower income from
operations mainly because of lower production and prices of both oil and gas.
The International segment has experienced increases in earnings
resulting from Horizon's share of earnings from its two main investments in
district heating and power generation operations located in the Czech Republic.
In the Pipeline and Storage segment, earnings are up due to Supply
Corporation's portion of interest income related to the previously mentioned
recent settlement of IRS audits. Additional income taxes related to certain
unsettled issues were also recorded. Mostly offsetting the net increase related
to the IRS audits was lower revenue from unbundled pipeline sales and open
access transportation and reserves established for preliminary costs incurred to
date related to proposed pipeline projects. Certain of these costs for which
reserves were established may be recovered at a future date.
In the Utility segment, earnings are down from the prior year mainly
because of the impact of warmer weather in the Pennsylvania jurisdiction and the
consequent overall lower normalized gas usage per customer account. In addition,
the Utility segment incurred interest expense, net of related rate recovery,
related to the previously mentioned recent settlement of IRS audits.
The slight decrease in earnings for the six months ended March 31,
1998 (exclusive of the asset impairment and cumulative effect of a change in
depletion methods noted above) as compared with the prior year's six month
period, reflects lower earnings of the Utility and the Exploration and
Production segments, mostly offset by higher earnings in the International and
Pipeline and Storage segments. Both the Utility and Exploration and Production
segments were negatively impacted by warmer than normal weather, which reduced
demand and prices. The International segment's earnings increased because of its
share of earnings from its investments in the Czech Republic. Consistent with
the discussion above concerning quarterly earnings, the impact of the settlement
of the primary issues relating to IRS audits contributed to higher earnings in
the Pipeline and Storage segment and partially offset the decreased earnings in
the Exploration and Production segment, while reducing the earnings of the
Utility segment.
A more detailed discussion of current period results can be found in
the business segment information that follows.
<PAGE>
Item 2. Management's Discussion and Analysis of Financial Condition and
---------------------------------------------------------------
Results of Operations (Cont.)
-----------------------------
Discussion Of Asset Impairment And Cumulative Effect Of A Change In Depletion
Method.
Seneca follows the full-cost method of accounting for its oil and gas
operations. Under this method, capitalized costs are limited by a present worth
calculation of future revenues from oil and gas assets (full-cost ceiling). The
surplus of crude oil world-wide has caused oil prices to drop to their lowest
level in recent years, and gas prices have been negatively impacted by a warmer
than normal winter. As a result of these lower prices, a non-cash asset
impairment of $129 million (pretax) was recorded as of March 31, 1998.
Effective October 1, 1997, Seneca changed its method of depletion for
oil and gas properties from the gross revenue method to the units of production
method. The new method was adopted because it provides a better measure of
depletion expense and is the preferable method used by oil and gas producing
companies. Seneca's recent acquisition activities will increase its size and
scope of operations in relation to those of the Company1 making now the
appropriate time for the change in depletion methods. The units of production
method has been applied retroactively to prior years to determine the cumulative
effect through October 1, 1997. This cumulative effect reduced earnings by $9.1
million, net of income taxes. Depletion of oil and gas properties for the
quarter and six months ended March 31, 1998, has been computed under the newly
adopted units of production method. Since Seneca changed its method of depletion
for its oil and gas producing properties in the second quarter of its fiscal
year, the first quarter financial results of the Company have been restated.
This restatement, as well as additional discussion of this accounting change, is
included in Note 1 "Summary of Significant Accounting Policies."
<PAGE>
Item 2. Management's Discussion and Analysis of Financial Condition and
---------------------------------------------------------------
Results of Operations (Cont.)
-----------------------------
<TABLE>
<CAPTION>
OPERATING REVENUES
(in thousands)
Three Months Ended Six Months Ended
March 31, March 31,
------------------------- -------------------------
1998 1997 % Change 1998 1997 % Change
---- ---- -------- ---- ---- --------
<S> <C> <C> <C> <C> <C> <C>
Utility
Retail Revenues:
Residential $243,398 $301,632 (19.3) $453,134 $515,258 (12.1)
Commercial 51,480 74,959 (31.3) 96,681 125,614 (23.0)
Industrial 5,247 8,980 (41.6) 11,659 15,209 (23.3)
-------- -------- -------- --------
300,125 385,571 (22.2) 561,474 656,081 (14.4)
Off-System Sales 16,021 15,818 1.3 30,771 30,676 0.3
Transportation 22,337 16,946 31.8 37,514 28,188 33.1
Other 3,887 (374) 11.4 3,452 635 NM
-------- -------- -------- --------
342,370 417,961 (18.1) 633,211 715,580 (11.5)
-------- -------- -------- --------
Pipeline and Storage
Storage Service 15,984 16,304 (2.0) 32,469 32,691 (0.7)
Transportation 24,695 24,397 1.2 48,463 48,579 (0.2)
Other 1,653 2,960 (44.2) 7,257 6,885 5.4
-------- -------- -------- --------
42,332 43,661 (3.0) 88,189 88,155 -
-------- -------- -------- --------
Exploration and
Production 24,819 32,297 (23.2) 49,528 62,379 (20.6)
-------- -------- -------- --------
International 42,558 796 NM 54,147 1,524 NM
-------- -------- -------- --------
Other Nonregulated 37,149 35,794 3.8 61,326 51,540 19.0
-------- -------- -------- --------
Less-Intersegment
Revenues 26,580 31,805 (16.4) 52,732 56,982 (7.5)
-------- -------- -------- --------
$462,648 $498,704 (7.2) $833,669 $862,196 (3.3)
======== ======== ======== ========
</TABLE>
<TABLE>
<CAPTION>
OPERATING INCOME (LOSS) BEFORE
INCOME TAXES
(in thousands)
Three Months Ended Six Months Ended
March 31, March 31,
------------------------- -----------------
1998 1997 % Change 1998 1997 % Change
---- ---- -------- ---- ---- --------
<S> <C> <C> <C> <C> <C> <C>
Utility $ 72,378 $ 73,299 (1.3) $119,854 $119,023 0.7
Pipeline and Storage 14,166 18,320 (22.7) 37,016 37,783 (2.0)
Exploration and
Production* (119,815) 11,870 NM (116,368) 24,446 NM
International 6,024 1,504 NM 6,909 (1,587) NM
Other Nonregulated 1,870 790 136.7 2,943 1,189 147.5
Corporate (590) (769) 23.3 (1,092) (1,479) 26.2
-------- -------- --------- --------
$(25,967) $105,014 (124.7) $ 49,262 $179,375 (72.5)
======== ======== ======== ========
</TABLE>
*1998 includes non-cash impairment charge of $128,996,000.
NM = Not meaningful.
<PAGE>
Item 2. Management's Discussion and Analysis of Financial Condition and
---------------------------------------------------------------
Results of Operations (Cont.)
-----------------------------
<TABLE>
<CAPTION>
SYSTEM NATURAL GAS VOLUMES
(millions of cubic feet-MMcf)
Three Months Ended Six Months Ended
March 31, March 31,
------------------------ -------------------------
1998 1997 % Change 1998 1997 % Change
---- ---- -------- ---- ---- --------
<S> <C> <C> <C> <C> <C> <C>
Utility Gas Sales
Residential 31,221 37,720 (17.2) 56,010 63,524 (11.8)
Commercial 7,273 10,153 (28.4) 13,187 16,989 (22.4)
Industrial 1,227 1,725 (28.9) 2,469 3,023 (18.3)
Off-System 6,470 4,381 47.7 10,948 8,428 29.9
------- ------ ------- -------
46,191 53,979 (14.4) 82,614 91,964 (10.2)
------- ------ ------- -------
Non-Utility Gas Sales
Production(in
equivalent MMcf) 9,563 12,284 (22.2) 20,453 24,652 (17.0)
------- ------- ------- -------
Total Gas Sales 55,754 66,263 (15.9) 103,067 116,616 (11.6)
------- ------- ------- -------
Transportation
Utility 20,682 19,149 8.0 35,332 33,036 6.9
Pipeline and Storage 101,490 109,093 (7.0) 195,893 195,093 0.4
Nonregulated - 60 NM 276 60 NM
------- ------- ------- -------
122,172 128,302 (4.8) 231,501 228,189 1.5
------- ------- ------- -------
Marketing Volumes 9,339 7,304 27.9 14,520 11,820 22.8
------- ------- ------- -------
Less-Inter and
Intrasegment Volumes:
Transportation 58,351 66,982 (12.9) 102,743 110,665 (7.2)
Production 1,064 1,038 2.5 2,058 2,154 (4.5)
------- ------- ------- -------
59,415 68,020 (12.7) 104,801 112,819 (7.1)
------- ------- ------- -------
Total System Natural Gas
Volumes 127,850 133,849 (4.5) 244,287 243,806 0.2
======= ======= ======= =======
</TABLE>
NM = Not meaningful.
<PAGE>
Item 2. Management's Discussion and Analysis of Financial Condition and
---------------------------------------------------------------
Results of Operations (Cont.)
-----------------------------
Utility.
Operating revenues for the Utility segment decreased $75.6 million
and $82.4 million for the quarter and six months ended March 31, 1998,
respectively, as compared with the same periods a year ago. These decreases
primarily reflect the recovery of lower gas costs which resulted from a decrease
in gas sales (a 7.8 billion cubic feet (Bcf) decrease and a 9.4 Bcf decrease for
the quarter and six months ended March 31, 1998, respectively), and a decrease
in the average cost of purchased gas ($3.77 per thousand cubic feet (Mcf) and
$4.47 per Mcf during the quarters ended March 31, 1998 and 1997, respectively,
and $4.11 per Mcf and $4.57 per Mcf during the six months ended March 31, 1998
and 1997, respectively). While the decrease in gas sales also reflects, in part,
the migration of certain retail customers to transportation service in both the
New York and Pennsylvania jurisdictions, as a result of new aggregator services,
the major reason for the decrease stems from warmer weather and lower normalized
gas usage per customer account. The switch to new aggregator services is
discussed further in the "Rate Matters" section that follows.
The impact on operating revenue of a general base rate increase in
the New York jurisdiction effective October 1, 1997 ($7.2 million on an annual
basis) was mostly mitigated by the recognition of a refund provision of $2.0
million for the quarter and $3.1 million year-to-date to the Utility's customers
for a 50% sharing of earnings over a predetermined amount in accordance with the
New York rate settlement of July 1996. The cumulative estimated refund provision
liability, including amounts accrued in fiscal 1997, is $6.1 million. The final
amount owed to customers, if any, will not be known until after September 30,
1998, which is the conclusion of the settlement period. In addition, operating
revenues in the quarter and year-to-date ended March 31, 1998, include $6.0
million of revenue recorded by the Utility segment's New York jurisdiction
related to the previously mentioned recent settlement of IRS audits. This $6.0
million represents the rate recovery of interest expense as allowed by the New
York rate settlement of July 1996. Both this revenue and the refund provision
are included in the "Other" category in the Utility section of the Operating
Revenues table above.
Operating income before income taxes for the Utility segment decreased
$0.9 million for the quarter ended March 31, 1998, and increased $0.8 million
for the six months ended March 31, 1998, as compared to the same periods a year
ago. Excluding the $6 million of rate recovery of interest expense related to
the IRS audits, as noted above (this rate recovery is offset 100% by interest
expense, included below the operating income line), the Utility segment's pretax
operating income decreased $6.9 million and $5.2 million for the quarter and six
months ended March 31, 1998, respectively. This decrease resulted primarily from
the negative impact of warmer weather and the related decrease in normalized gas
usage per customer account. Partly offsetting this, the Utility segment
continues to experience decreases in operation and maintenance expense ( a 3.4%
and 4.6% decline for the quarter and six months ended March 31, 1998,
respectively) relating primarily to benefit and labor expense reduction. The
negative impact of warmer weather was greatest in the Pennsylvania jurisdiction,
since Pennsylvania does not have a weather normalization clause (WNC). The
impact of warmer weather experienced by the New York jurisdiction was tempered
by the WNC, which preserved pretax operating income of $9.8 million and $8.4
million for the quarter and six
<PAGE>
Item 2. Management's Discussion and Analysis of Financial Condition and
---------------------------------------------------------------
Results of Operations (Cont.)
-----------------------------
months ended March 31, 1998, respectively. For the quarter and six months ended
March 31, 1997, the WNC preserved pretax operating income of $4.4 million and
$3.5 million, respectively.
Degree Days
Three Months Ended March 31:
---------------------------
Percent (Warmer) Colder
in 1998 Than
Normal 1998 1997 Normal 1997
- ----------------------------------------------------------------
Buffalo 3,344 2,785 3,194 (16.7) (12.8)
Erie 3,198 2,547 2,996 (20.4) (15.0)
Six Months Ended March 31:
-------------------------
Buffalo 5,606 5,079 5,450 (9.4) (6.8)
Erie 5,243 4,643 5,123 (11.4) (9.4)
- -----------------------------------------------------------------
Pipeline and Storage.
Operating income before income taxes for the Pipeline and Storage
segment decreased $4.2 million and $0.8 million for the quarter and six months
ended March 31, 1998, respectively, as compared with the same periods a year
ago. For the quarter, the decrease is primarily attributable to the
establishment of reserves for preliminary survey and investigation costs
associated with the Niagara Expansion and Green Canyon projects. (The Niagara
Expansion and Green Canyon projects are discussed further under "Investing Cash
Flow", subheading "Pipeline and Storage.") Certain of these costs for which
reserves were established may be recovered at a future date.1 In addition,
Supply Corporation recognized a base gas loss at its Zoar storage field. In
total, these three items amounted to $3.7 million, pretax. Also during the
quarter, Supply Corporation had lower revenue from unbundled pipeline sales and
open access transportation.
The decrease for the six months ended March 31, 1998, is primarily
attributable to the reserves and base gas loss discussed above, offset in part
by the reversal of a portion of a reserve set up in a prior period for the
Laurel Fields Storage Project. The Pipeline and Storage segment was able to
recapture approximately $1.0 million by selling preliminary engineering, survey,
environmental, and archeological information from the Laurel Fields Project to
the Independence Pipeline Company, which intends to build a 370-mile interstate
pipeline system designed to transport about 900,000 dekatherms (Dth) per day of
natural gas from Defiance, Ohio to Leidy, Pennsylvania (the Independence
Pipeline project is discussed further under "Investing Cash Flow", subheading
"Pipeline and Storage.")
<PAGE>
Item 2. Management's Discussion and Analysis of Financial Condition and
---------------------------------------------------------------
Results of Operations (Cont.)
-----------------------------
While transportation volumes in this segment decreased 7.6 Bcf and
increased 0.8 Bcf, respectively, for the quarter and six months ended March 31,
1998, the change in volumes did not have a significant impact on earnings as a
result of Supply Corporation's straight fixed-variable (SFV) rate design.
Exploration and Production.
Operating income before income taxes from the Company's Exploration and
Production segment decreased $131.7 million for the quarter ended March 31,
1998, compared with the same period a year ago. Excluding the $129 million
non-cash impairment of this segment's oil and gas assets, as discussed
previously, operating income before income taxes decreased $2.7 million as
compared with the prior year's quarter. This decrease resulted from lower oil
and gas revenues during the quarter, offset in part by a net gain on hedging
activities and by lower depletion expense. The oil and gas revenues declined as
a result of lower production and prices for the quarter ended March 31, 1998
compared to March 31, 1997 (see tables below). The expected decline in
production of West Cameron 552 and delays in drilling due to rig unavailability
were the major causes of the production decline. The decrease in depletion
expense resulted mainly from lower oil and gas production. The change in
depletion, made effective October 1, 1997, to change from the gross revenue
method to the units of production method, also lowered depletion expense for the
quarter. See further discussion of this change in accounting method in Note 1 -
"Summary of Significant Accounting Policies."
For the six months ended March 31, 1998, operating income before income
taxes for the Exploration and Production segment decreased $140.8 million,
compared with the same period a year ago. Excluding the $129 million non-cash
impairment of this segment's oil and gas assets, as discussed previously,
operating income before income taxes decreased $11.8 million as compared with
the prior year's quarter. This decrease on a year-to-date basis, was mainly
caused by the same reasons discussed above for the quarter except that on a
year-to-date basis net hedging gains were not experienced, but rather, lower net
hedging losses.
Hedging activities resulted in a net pretax gain of $0.5 million and a
net pretax loss of $7.8 million for the three and six months ended March 31,
1998, respectively. For the quarter and six months ended March 31, 1997, hedging
activities resulted in pretax losses of $7.4 million and $16.0 million,
respectively. Refer to further discussion of the Company's hedging activities
under "Financing Cash Flow" and in Note 4 - Derivative Financial Instruments.
<PAGE>
Item 2. Management's Discussion and Analysis of Financial Condition and
---------------------------------------------------------------
Results of Operations (Cont.)
-----------------------------
PRODUCTION VOLUMES
Exploration and Production.
Three Months Ended Six Months Ended
March 31, March 31,
----------------------- -----------------------
1998 1997 % Change 1998 1997 % Change
---- ---- -------- ---- ---- --------
Gas Production - (MMcf)
Gulf Coast 5,860 7,719 (24.1) 12,701 15,520 (18.2)
West Coast 157 337 (53.4) 412 551 (25.2)
Appalachia 1,276 1,293 (1.3) 2,484 2,574 (3.5)
----- ----- ------ ------
7,293 9,349 (22.0) 15,597 18,645 (16.3)
===== ===== ====== ======
Oil Production - (Thousands of Barrels)
Gulf Coast 296 362 (18.2) 610 746 (18.2)
West Coast 80 124 (35.5) 194 250 (22.4)
Appalachia 2 3 (33.3) 5 5 -
--- --- --- -----
378 489 (22.7) 809 1,001 (19.2)
=== === === =====
WEIGHTED AVERAGE PRICES
Exploration and Production.
Three Months Ended Six Months Ended
March 31, March 31,
----------------------- -----------------------
1998 1997 % Change 1998 1997 % Change
---- ---- -------- ---- ---- --------
Weighted Avg. Gas Price/Mcf
Gulf Coast $2.27 $2.96 (23.3) $2.68 $2.95 (9.2)
West Coast $1.69 $2.18 (22.5) $2.13 $1.96 8.7
Appalachia $3.10 $3.97 (21.9) $3.06 $3.22 (5.0)
Weighted Average $2.40 $3.07 (21.8) $2.73 $2.95 (7.5)
Weighted Average After
Hedging $2.38 $2.46 (3.3) $2.21 $2.30 (3.9)
Weighted Avg. Oil Price/bbl
Gulf Coast $14.83 $22.44 (33.9) $16.98 $23.39 (27.4)
West Coast $11.81 $19.97 (40.9) $14.20 $20.41 (30.4)
Appalachia $15.80 $23.16 (31.8) $17.93 $23.05 (22.2)
Weighted Average $14.19 $21.82 (35.0) $16.32 $22.64 (27.9)
Weighted Average After
Hedging $15.98 $18.32 (12.8) $16.62 $18.84 (11.8)
<PAGE>
Item 2. Management's Discussion and Analysis of Financial Condition and
---------------------------------------------------------------
Results of Operations (Cont.)
-----------------------------
International
Operating income before income taxes for the International segment increased
$4.5 million and $8.5 million for the quarter and the six-months ended March 31,
1998, respectively, compared with the same periods a year ago. This increase, as
well as the significant revenue increase shown on the "Operating Revenue" table
above, reflects current quarter and year-to-date results including 100% of the
revenues and pretax operating income of SCT, as well as 100% of the revenues and
pretax operating income of PSZT for February and March 1998. Both SCT and PSZT
have district heating and power generation operations located in the northern
part of the Czech Republic. Horizon first acquired a 34% interest in SCT in
April 1997 and increased its ownership to 75.2% as of March 31, 1998 (Horizon's
ownership interest increased to 82.6% in April 1998, upon completion of a tender
offer for minority owned shares). In January 1998, Horizon signed an agreement
to acquire 75.3% of the outstanding shares of PSZT. Except for some outstanding
closing requirements, the acquisition was completed in February 1998. The
minority interests in SCT and PSZT are shown separately on the Consolidated
Statement of Income after operating results. The prior year's March quarter
reflected no operating income from SCT or PSZT but included the positive impact
of the sale of Horizon's rights in a Pakistan power project. For the six months
ended March 31, 1997, this positive impact was mostly offset by nonrecurring
expenses associated with the dissolution of Sceptre Power Company, which were
incurred in the first quarter of 1997.
Because of the change in the nature of operations of the International
segment during the past year, operating income comparisons between the current
period and prior periods may not be meaningful. Future revenues from district
heating operations are expected to fluctuate with changes in weather. The
Company expects that rates charged for heating operations in the Czech Republic
will continue to be monitored by the Czech Ministry of Finance.1
Other Nonregulated.
Operating income before income taxes associated with this segment
increased $1.1 million and $1.8 million, respectively, for the quarter and
six-months ended March 31, 1998, compared with the same periods a year ago. The
increases can be attributed primarily to improved performance in the Company's
timber operations.
Income Taxes.
Income taxes decreased $43.9 million and $43.2 million, respectively,
for the quarter and six months ended March 31, 1998, primarily as a result of a
decrease in pretax income (pretax income before cumulative effect, for the six
months ended March 31, 1998).
Other Income.
Other income increased $25.0 million and $25.4 million, respectively,
for the quarter and six months ended March 31, 1998, mainly due to $18.5 million
of interest income resulting from the previously mentioned recent settlement of
IRS audits. In addition, Other Income for the quarter and six month period
includes a gain of approximately $2.3 million (pretax) associated
<PAGE>
Item 2. Management's Discussion and Analysis of Financial Condition and
---------------------------------------------------------------
Results of Operations (Cont.)
-----------------------------
with U.S. dollar denominated debt carried on the balance sheet of PSZT. See
further discussion regarding this PSZT debt in Item 1, Note 3 - Capitalization.
Interest Charges.
Total interest charges increased $13.9 million and $15.1 million for
the quarter and six months ended March 31, 1998, respectively. Other interest
increased $13.0 million and $12.9 million for the quarter and six-month period,
respectively, mainly as a result of interest expense related to the previously
mentioned settlement of IRS audits (total interest expense related to the IRS
audits amounted to $11.7 million). Interest on long-term debt increased $0.9
million and $2.2 million for the quarter and six-month period, respectively,
mainly because of a higher average amount of long-term debt outstanding compared
to the same periods a year ago.
CAPITAL RESOURCES AND LIQUIDITY
The Company's primary sources of cash during the six-month period
consisted of cash provided by operating activities and short-term bank loans and
commercial paper.
Operating Cash Flow
Internally generated cash from operating activities consists of net
income available for common stock, adjusted for non-cash expenses, non-cash
income and changes in operating assets and liabilities. Non-cash items include
the cumulative effect of a change in accounting for depletion, the impairment of
oil and gas producing properties, depreciation, depletion and amortization,
deferred income taxes, minority interest in foreign subsidiaries and allowance
for funds used during construction.
Cash provided by operating activities in the Utility and the Pipeline
and Storage segments may vary substantially from period to period because of the
impact of rate cases. In the Utility segment, supplier refunds, over- or
under-recovered purchased gas costs and weather also significantly impact cash
flow. The Company considers supplier refunds and over-recovered purchased gas
costs as a substitute for short-term borrowings. The impact of weather on cash
flow is tempered in the Utility segment's New York rate jurisdiction by its WNC
and in the Pipeline and Storage segment by Supply Corporation's SFV rate design.
Because of the seasonal nature of the Company's heating business,
revenues are relatively high during the six months ended March 31 and
receivables and unbilled utility revenue historically increase from September to
March because of winter weather.
The storage gas inventory normally declines during the first and second
quarters of the fiscal year and is replenished during the third and fourth
quarters. For storage gas inventory accounted for under the last-in, first-out
(LIFO) method, the current cost of replacing gas withdrawn from storage is
recorded in the Consolidated Statement of Income and a reserve for gas
replacement is recorded in the Consolidated Balance Sheet and is included
<PAGE>
Item 2. Management's Discussion and Analysis of Financial Condition and
---------------------------------------------------------------
Results of Operations (Cont.)
-----------------------------
under the caption "Other Accruals and Current Liabilities." Such reserve is
reduced as the inventory is replenished.
Net cash provided by operating activities totaled $122.7 million for
the six months ended March 31, 1998, a decrease of $23.0 million compared with
$145.7 million provided by operating activities for the six months ended March
31, 1997. The majority of this decrease occurred in the Utility segment and the
Exploration and Production segment. The Utility segment experienced a decrease
in cash receipts from gas sales and transportation service (sales were down
mainly due to warmer weather), a decrease in cash refunds received from upstream
pipelines and an increase in cash payments for property, franchise and other
taxes (primarily due to timing). These decreases to cash were partially offset
by lower cash payments for gas purchases. The Exploration and Production segment
experienced lower cash receipts from the sale of oil and gas as well as higher
operation costs. The impact of lower cash receipts from the sale of oil and gas
was partially mitigated by a decrease in cash outlays for hedging transactions
as well as a decrease in cash outlays for federal taxes. Partly offsetting the
net decreases experienced by the Utility and Exploration and Production
segments, the International segment experienced an increase in cash provided by
operating activities as a result of the operations of SCT and PSZT. Also, the
Corporate segment experienced an increase in cash provided by operating
activities primarily because of approximately $6 million received from the
Internal Revenue Service associated with the resolution of certain issues
related to the audits of 1977 - 1994.
Investing Cash Flow
Capital Expenditures and Other Investing Activities
- ---------------------------------------------------
Capital expenditures represent the Company's additions to property,
plant and equipment and are exclusive of investments in corporations (stock
acquisitions) and/or partnerships. Such investments are treated separately in
the Statement of Cash Flows and further discussed in the segment discussion
below.
The Company's actual capital expenditures totaled $220.9 million during
the six months ended March 31, 1998. Total expenditures for the six-month period
represent 104% of the total original capital expenditure budget for fiscal 1998
of $212.4 million. The following table summarizes the Company's capital
expenditures by business segment:
(in millions)
- -------------
Actual
Original Capital Estimated
Capital Expenditures Capital
Expenditure through Expenditures1
Budget 3/31/98 4/1/98 - 9/30/98
------ ------- ----------------
Utility $ 51.9 $ 25.2 $ 26.7
Pipeline and Storage 28.0 9.6 18.4
Exploration and Production 132.2 179.4 98.6
International - 5.2 18.0
Other Nonregulated 0.3 1.5 1.8
------ ------ ------
$212.4 $220.9 $163.5
====== ====== ======
<PAGE>
Item 2. Management's Discussion and Analysis of Financial Condition and
---------------------------------------------------------------
Results of Operations (Cont.)
-----------------------------
Utility
- -------
The bulk of the Utility capital expenditures were made for
replacement of mains and main extensions, as well as for the replacement of
service lines.
Pipeline and Storage
- --------------------
The bulk of the Pipeline and Storage capital expenditures were made
for additions, improvements, and replacements to this segment's transmission and
storage systems. Approximately $1.6 million was spent on the 1998 Niagara
Expansion Project. As part of this expansion, Supply Corporation began
transportation service for an additional 25,000 Dth per day in November 1997. In
April 1998, Supply Corporation received Federal Energy Regulatory Commission
(FERC) approval concerning an additional 23,000 Dth per day expansion of firm
winter only capacity. Supply Corporation anticipates beginning transportation
service for the additional 23,000 Dth per day in November 1998.1 As there has
not been much interest in further expansion in this area at this time, the
Company established a reserve in March 1998 for approximately $1.7 million
(pretax) related to preliminary survey and investigation costs associated with
the proposed 1999 Niagara Expansion Project.
In June 1997, the Company announced its intention to join as an equal
partner in the Independence Pipeline Project, which is designed to bring gas
from Defiance, Ohio to Leidy, Pennsylvania and is expected to cost $675
million.1 The Independence Pipeline Project as filed with the FERC will consist
of approximately 370 miles of 36-inch diameter pipe with an initial capacity of
approximately 900,000 Dth per day. In September 1997, the Company formed a new
subsidiary, Seneca Independence Pipeline Company (SIP), which agreed to
purchase, upon receipt of regulatory approval, a one-third general partnership
interest in Independence Pipeline Company, a Delaware general partnership. The
Company received Securities and Exchange Commission (SEC) approval in March 1998
and made an initial investment in Independence Pipeline Company of $3.9 million
in March 1998. This investment was financed with short-term borrowings. If the
Independence Pipeline Project is not constructed, SIP's share of the development
costs (including SIP's investment in Independence Pipeline Company) is estimated
not to exceed $6.0 million to $8.0 million.1
In November 1996, Supply Corporation entered into a Memorandum of
Understanding (the MOU) with Green Canyon Gathering Company, a subsidiary of El
Paso Energy regarding a project to develop, construct, finance, own and operate
natural gas gathering and processing facilities offshore and onshore Louisiana,
at an estimated total cost of approximately $200 million.1 The MOU has been
amended several times since then. In April 1998, Green Canyon Gathering Company
notified Supply Corporation that it wished to withdraw from the project. Based
on a lack of shippers willing to contract for this service, the Company had
already decided that it would be prudent to establish a reserve of approximately
$1.0 million (pretax) for preliminary survey and investigation costs incurred on
the project. This reserve was recorded in March 1998.
<PAGE>
Item 2. Management's Discussion and Analysis of Financial Condition and
---------------------------------------------------------------
Results of Operations (Cont.)
-----------------------------
Exploration and Production
- --------------------------
In March 1998, Seneca acquired properties in the Midway-Sunset and
Lost Hills field in the San Joaquin Basin of California from the Whittier Trust
Company for approximately $140 million. Short-term borrowings were used to
finance this acquisition. This acquisition will provide the Exploration and
Production segment with the opportunity to continue its focus on growth by
increasing its activities in domestic onshore areas.1 The acquisition of the
Whittier properties was not included in the original capital expenditure budget
shown above, but is included in the actual capital expenditures through March
31, 1998.
Other Exploration and Production segment capital expenditures
included approximately $29.7 million on the offshore program in the Gulf of
Mexico, including offshore drilling expenditures, offshore construction and
geological and geophysical expenditures. Offshore exploratory drilling was
concentrated on High Island 179 and High Island A356. Offshore construction
occurred primarily at West Cameron 540 and Vermilion 309. Offshore geological
and geophysical expenditures were made for purchases of 3-D seismic data.
The remaining $9.7 million capital expenditures included onshore
drilling and construction costs for wells located in Louisiana and Texas, as
well as onshore geological and geophysical costs, including the purchase of
certain 3-D seismic data.
In May 1998, Seneca West Corporation (Seneca West), a wholly-owned
subsidiary of Seneca, completed a tender offer (an offer of $2.00 per share) for
the outstanding shares of HarCor Energy, Inc. (HarCor). Preliminary information
supplied by the depository for the offer indicate that approximately 95% of the
outstanding shares of HarCor common stock were tendered in accordance with the
tender offer. Seneca West gave notice to the depository for the offer that
Seneca West accepted for payment all of the shares of HarCor common stock prior
to the expiration of the tender offer. The cost of acquiring these shares is
approximately $31 million. As this is a stock acquisition, no amounts are
included in any capital expenditure data shown in the tables above.
The tender offer was commenced pursuant to the terms of an Agreement
and Plan of Merger among HarCor, Seneca and Seneca West which provides for the
merger of Seneca West with and into HarCor following the successful consummation
of the tender offer. Accordingly, all shares of HarCor common stock that were
not purchased pursuant to the tender offer will be converted in the merger into
the right to receive $2.00 per share. Seneca West intends to consummate the
merger before the end of 1998.1 The conversion of the remaining shares would
cost Seneca West approximately $1.6 million. 1
The HarCor oil and gas properties are located on the west side of the
San Joaquin Basin in California. These properties are unique for California in
that they produce higher gravity oil than is generally found in this area, as
well as producing natural gas. Included in this acquisition is approximately $54
million of 14 7/8% senior secured debt and other liabilities of HarCor.
<PAGE>
Item 2. Management's Discussion and Analysis of Financial Condition and
---------------------------------------------------------------
Results of Operations (Cont.)
-----------------------------
In April 1998, Seneca announced the signing of a Letter of Intent to
acquire the oil and gas assets of the Bakersfield Energy Group, which are
located in the Lost Hills Field in the San Joaquin Valley near Bakersfield,
California. The purchase price is estimated to be approximately $30.0 million.1
These properties, which Bakersfield Energy operates, produce gas and high
gravity oil, include a gas processing plant and associated pipelines, and
provide opportunities for additional drilling and development.1 The assets are
jointly owned by Bakersfield Energy and HarCor. The sale is subject to
preparation and execution of a definitive agreement, obtaining all required
approvals, and completion of a satisfactory due diligence review of Bakersfield
Energy's assets, liabilities and business. Closing of the proposed sale is
expected to occur by June 1, 1998.1 The estimated acquisition price of
approximately $30.0 million is included in the estimated capital expenditures
budget for April 1 through September 30, 1998.
These acquisitions (Whittier and HarCor) and pending acquisition
(Bakersfield) will complement the Exploration and Production segment's reserve
mix, bringing its new reserve base to approximately 710 Bcf equivalent, of which
58% is oil and 42% is gas.1
The Company intends to issue long-term debt to replace the short-term
borrowings used to finance the acquisition costs associated with the Whittier
Trust Company properties and to finance most of the acquisition costs for the
HarCor common stock and the Bakersfield Energy oil and gas assets.1
International
- -------------
In February 1998, Horizon B.V. completed the acquisition of 75.3% of
the outstanding shares of PSZT, a company with district heating and wholesale
power generation operations located in Komorany, Czech Republic. The operations
of PSZT are in close proximity to SCT in the northern part of the Czech
Republic. For calendar 1996, PSZT reported profits of approximately $3.0
million. The purchase price was approximately $60 million and was financed with
short-term borrowings. The Czech Commercial Code requires that a shareholder
that achieves certain ownership interests in a company (50%, 66.66%, or 75%)
must extend a tender offer to the remaining minority shareholders of that
company. In April 1998, Horizon B.V. issued such a tender offer for the
remaining shares of PSZT which will remain open through the beginning of June
1998. If Horizon B.V. were to acquire the remaining 24.7% equity interest in
PSZT as a result of this tender offer, the maximum additional investment in PSZT
would be approximately 299 million Czech Koruna, which translates to
approximately $8.8 million at the March 31, 1998 exchange rate. Any shares
acquired through this tender offer would be financed with short-term borrowings.
As these are stock acquisitions, no amounts are included in any capital
expenditure data shown on the tables above.
The bulk of the International segment capital expenditures were made
by PSZT for the reconstruction of boilers at its heating plant to comply with
stricter clean air standards. Short-term borrowings and cash from operations
were used to finance these capital expenditures. Going forward, it is
anticipated that up to an additional $38 million (approximately $15 million for
the remaining six months of 1998) will be spent on this reconstruction project,
which will extend into fiscal 2000.1 The Company anticipates financing these
expenditures with short-term borrowings.1
<PAGE>
Item 2. Management's Discussion and Analysis of Financial Condition and
---------------------------------------------------------------
Results of Operations (Cont.)
-----------------------------
In December 1997, Horizon B.V. acquired an additional 34% equity
interest in SCT for $22.3 million, including legal and finders fees, thus
raising its total ownership to 70.8%. The acquisition was financed with
short-term borrowings. Horizon B.V. recently completed a tender offer in April
1998, increasing its ownership interest to 82.6% (75.2% at March 31, 1998). The
cost of this tender offer was approximately $2.5 million ($0.9 million through
March 31, 1998) and was financed with short-term borrowings. As these are stock
acquisitions, no amounts are included in any capital expenditure data shown in
the tables above.
Horizon B.V.'s investment in the Czech Republic is valued in Czech
Korunas, and as such, this investment is subject to currency exchange risk when
the Czech Korunas are translated into U.S. Dollars. During the six months ended
March 31, 1998, the Czech Koruna increased in value in relation to the U.S.
dollar, resulting in a $0.9 million positive adjustment to the Cumulative
Translation Adjustment. Further valuation changes to the Czech Koruna would
result in corresponding positive or negative adjustments to the Cumulative
Translation Adjustment. Management cannot predict whether the Czech Koruna will
increase or decrease in value against the U.S. Dollar.1
Other Nonregulated
- ------------------
Other Nonregulated capital expenditures consisted primarily of
equipment purchases for the Company's sawmill and kiln operations in
Pennsylvania as well as timber purchases. The capital expenditures also included
the purchase of furniture, equipment and computer hardware and software for the
office location of the Company's gas marketing operation.
Other
- -----
Other cash provided by or used in investing activities primarily
reflects cash received on the sale of the Company's investment in property,
plant and equipment, cash received on the sale of the Company's interest in
Enerchange, L.L.C., a natural gas hub partnership, and cash used to make an
initial investment in Independence Pipeline Company.
The Company's capital expenditure program is under continuous review.
The amounts are subject to modification for opportunities in the natural gas
industry such as the acquisition of attractive oil and gas properties or storage
facilities and the expansion of transmission line capacities. While the majority
of capital expenditures in the Utility segment are necessitated by the continued
need for replacement and upgrading of mains and service lines, the magnitude of
future capital expenditures in the Company's other business segments depends, to
a large degree, upon market conditions.1
Financing Cash Flow.
Consolidated short-term debt increased by $285.8 million during the
first six months of fiscal 1998. The Company continues to consider short-term
bank loans and commercial paper important sources of cash for temporarily
financing capital expenditures and investments in corporations and/or
partnerships, gas-in-storage inventory, unrecovered purchased gas costs,
exploration and development expenditures and other working capital needs. In
addition, the Company considers supplier refunds and over-recovered purchased
gas costs as a substitute for short-term debt. Fluctuations in these items can
have a significant impact on the amount and timing of short-term debt.
<PAGE>
Item 2. Management's Discussion and Analysis of Financial Condition and
---------------------------------------------------------------
Results of Operations (Cont.)
-----------------------------
At March 31, 1998, the Company had authorization from the SEC under a
shelf registration filed pursuant to the Securities Act of 1933, to issue and
sell up to $400 million of debentures and/or medium-term notes. In March 1998,
the Company obtained authorization from the SEC, under the Public Utility
Holding Company Act of 1935, to issue, in the aggregate, long-term debt
securities and equity securities amounting to $2.0 billion during the order's
authorization period, which extends from March 1998 to December 31, 2002. The
Company intends to issue approximately $200 million in medium-term notes in May
1998 and use the proceeds to repay short-term debt.1
The Company's indenture contains covenants which limit, among other
things, the incurrence of funded debt. Funded debt basically is indebtedness
maturing more than one year after the date of issuance. Because of the
impairment of oil and gas properties recorded by the Company in March 1998,
these covenants will restrict the Company's ability to issue substantial amounts
of additional funded debt, with certain exceptions, subsequent to the planned
May 1998 debt issuance, until the third quarter of fiscal 1999. This will not,
however, limit the Company's issuance of funded debt to refund existing funded
debt.
The Company has adequate financing resources available to meet expected
operating and capital requirements.1 At March 31, 1998, the Company had
regulatory authorizations and unused short-term credit lines that would have
permitted it to borrow an additional $371.8 million of short-term debt.
The Company, through Seneca, has entered into certain price swap
agreements to manage a portion of the market risk associated with fluctuations
in the market price of natural gas and crude oil. These price swap agreements
are not held for trading purposes. During the quarter ended March 31, 1998,
Seneca utilized natural gas and crude oil swap agreements with notional amounts
of 5.7 equivalent Bcf and 219,000 equivalent bbl, respectively. These hedging
activities resulted in the recognition of a pretax gain of approximately $0.5
million. For the six months ended March 31, 1998, Seneca utilized natural gas
and crude oil swap agreements with notional amounts of 13.1 equivalent Bcf and
453,000 equivalent bbl, respectively. These hedging activities resulted in the
recognition of a pretax loss of approximately $7.8 million. These hedging gains
or losses are offset by lower or higher prices received for actual natural gas
and crude oil production.
At March 31, 1998, Seneca had natural gas swap agreements outstanding
with a notional amount of approximately 27.8 equivalent Bcf at prices ranging
from $2.00 per Mcf to $2.47 per Mcf. The weighted average fixed price of these
swap agreements is approximately $2.24 per Mcf.
Seneca also had crude oil swap agreements outstanding at March 31,
1998 with a notional amount of 573,000 equivalent bbl at prices ranging from
$17.50 per bbl to $20.56 per bbl. The weighted average fixed price of these swap
agreements is approximately $19.23 per bbl.
The Company, through NFR, participates in the natural gas futures
market to manage a portion of the market risk associated with fluctuations in
the price of natural gas. Such futures are not held for trading purposes. During
the quarter ended March 31, 1998, NFR recognized a pretax loss of approximately
$0.1 million related to such futures contracts. For the six months ended March
31, 1998, NFR recorded a pretax gain of approximately $1.2
<PAGE>
Item 2. Management's Discussion and Analysis of Financial Condition and
---------------------------------------------------------------
Results of Operations (Cont.)
-----------------------------
million. Since these futures contracts qualify and have been designated as
hedges, any gains or losses resulting from market price changes are
substantially offset by the related commodity transaction.
At March 31, 1998, NFR had long positions in the futures market
amounting to a notional amount of 7.2 Bcf at prices ranging from $2.04 per Mcf
to $2.75 per Mcf. The weighted average contract price of these futures contracts
is approximately $2.41 per Mcf. NFR had short positions in the futures market
amounting to a notional amount of 4.1 Bcf at prices ranging from $2.20 per Mcf
to $2.63 per Mcf. The weighted average contract price of these futures contracts
is approximately $2.45 per Mcf.
In addition, the Company has SEC authority to enter into certain
hedging transactions related to its borrowings. For further discussion, refer to
Note 4 - Derivative Financial Instruments.
The Company's credit risk is the risk of loss that the Company would
incur as a result of nonperformance by counterparties pursuant to the terms of
their contractual obligations related to derivative financial instruments. The
Company does not anticipate any material impact to its financial position,
results of operations or cash flow as a result of nonperformance by
counterparties.1 For further discussion, refer to Note 4 - Derivative Financial
Instruments.
The Company is involved in litigation arising in the normal course of
business. The Company is involved in regulatory matters arising in the normal
course of business that involve rate base, cost of service and purchased gas
cost issues, among other things. While the resolution of such litigation or
regulatory matters could have a material effect on earnings and cash flows in
the year of resolution, none of this litigation and none of these regulatory
matters are expected to change materially the Company's present liquidity
position, nor have a material adverse effect on the financial condition of the
Company at this time.1
RATE MATTERS
Utility Operation
New York Jurisdiction
- ---------------------
In November 1995, Distribution Corporation filed in its New York jurisdiction a
request for an annual rate increase of $28.9 million with a requested return on
equity of 11.5%. A two-year settlement with the parties in this rate proceeding
was approved by the Public Service Commission of the State of New York (PSC).
Effective October 1, 1996 and October 1, 1997, Distribution Corporation received
annual base rate increases of $7.2 million. The settlement did not specify a
rate of return on equity. Generally, earnings above a 12% return on equity
(excluding certain items and determined on a cumulative basis over the three
years ending September 30, 1998) will be shared equally between shareholders and
ratepayers. As a result of this sharing mechanism, Distribution Corporation
recorded an estimated cumulative refund provision to its customers of $3.0
million ($2.0 million after-tax)
<PAGE>
Item 2. Management's Discussion and Analysis of Financial Condition and
---------------------------------------------------------------
Results of Operations (Cont.)
-----------------------------
during the fourth quarter of 1997. An additional $3.1 million ($2.0 million
after-tax) was accrued during the six months ended March 31, 1998. The final
amount owed to customers, if any, will not be known until the conclusion of the
settlement period.
In June 1997, the PSC issued an order requiring jurisdictional
utilities to file plans to offer heating customers a fixed price service option
for the 1997-1998 winter heating season. The order also directed the utilities
to submit proposals for increased supply diversity with a view toward fostering
price stability. Distribution Corporation's fixed price service option that was
approved by the PSC gave heating customers the opportunity to be guaranteed a
fixed unit price for natural gas during the billing period of December 1997
through April 1998. Approximately 11,000 heating customers chose the fixed price
service option. These customers ended up paying more for their gas than
customers who did not elect this option.
At a regular session on April 29, 1998, the PSC adopted an order
permitting the state's local distribution companies (LDCs) to offer the fixed
price option for winter 1998-99. The written order will be issued at a later
date. At this time, and pending an analysis of the written order, Distribution
Corporation has no plans to offer the fixed price option in the 1998-1999 winter
season.1 In the same docket, the PSC issued a Statement of Policy Regarding Gas
Purchasing Practices on April 28, 1998 ("Policy Statement"). The Policy
Statement directs LDCs to, among other things, consider "all the available
options for purchasing gas and assess the benefits of each approach." The intent
of the Policy Statement is to promote supply diversification, including "the use
of financial hedges," without "directing any particular mix of portfolio
options." Consistent with the regulatory theme underlying the fixed price
option, the Policy Statement further provides that "volatility of customer bills
is one of the [supply option] criteria, along with other factors such as cost
and reliability, that LDCs should consider in their supply purchasing
strategies."
By an order issued on September 4, 1997, the PSC directed the state's
LDCs to file a "plan for competition" addressing issues relating to disposition
of upstream assets in light of anticipated growth in small volume transportation
conversions. On April 1, 1998, Distribution Corporation filed its plan.
Distribution Corporation's plan responds to questions posed by the PSC on such
issues as upstream capacity contracts, encouraging competition, assessing
strandable costs and designing remedies, if necessary. In addition, Distribution
Corporation explained that in order to assure reliability, maintain operational
flexibility and avoid stranded costs, upstream capacity currently held for sales
obligations should be allocated to marketers serving customers converting to
transportation service.
On April 3, 1998, Distribution Corporation filed comments in a PSC
generic proceeding addressing gas transportation rates for electric generators.
This case arose in response to concerns by the PSC regarding the effects of gas
transportation costs on electric rates ultimately paid by retail customers.
Distribution Corporation argued, among other things, that the current rate
setting policy, established in 1991, should remain unchanged for LDCs facing
competitive bypass threats. Distribution Corporation believes
<PAGE>
Item 2. Management's Discussion and Analysis of Financial Condition and
---------------------------------------------------------------
Results of Operations (Cont.)
-----------------------------
that the PSC may be focusing its attention on transfer pricing arrangements
between gas and electric divisions of combination utilities. Staff for the PSC
has informally expressed that existing generation and co-generation contracts
will not be disturbed by the outcome of this proceeding.
The PSC issued a notice on April 7, 1998 that it is considering the
revision of its regulations governing the operation of the Gas Adjustment Clause
(GAC). As revised, the rules would, as described by the PSC, allow the GAC to
more accurately reflect gas prices. The revised rules would also allow LDCs to
recover risk management costs through the GAC. Management is currently analyzing
the impact of those and other changes proposed in the rule making. Distribution
Corporation plans to file comments in June 1998.1
New York's gas industry restructuring effort continues to develop at a
slow pace. As of April 8, 1998, 27,076 small volume customers across the state
chose aggregator services over their utility. In Distribution Corporation's
service territory, 3,595 small volume customers (out of over 500,000) are
purchasing gas from fourteen aggregators, for a total annual load of just over 3
Bcf. The Company's marketing affiliate, NFR, is one of the participating
aggregators. At the urging of the PSC, Distribution Corporation began to offer
storage release service to aggregators on June 27, 1997. Currently, Distribution
Corporation's is the only actual release storage service available in New York
State. Whether aggregators find the service attractive enough to increase
marketing activity remains to be seen.
On March 9, 1998, the PSC approved a new service classification,
effective April 1, 1998, designed to extend the benefits of transportation
service to social services recipients located in Erie and Chautauqua counties,
New York. The program, a two-year pilot, enables the counties to buy gas supply
from marketers on a competitive basis. Distribution Corporation will transport
the supplies to social services recipients enrolled in the program and receive
payment from the counties under a pre-established "voucher" protocol. The
program is designed so that if enrollment increases above current levels,
Distribution Corporation may experience a reduction in uncollectible accounts.
Pennsylvania Jurisdiction
- -------------------------
Distribution Corporation currently does not have a rate case on file
with the Pennsylvania Public Utility Commission (PaPUC). Management will
continue to monitor its financial position in the Pennsylvania jurisdiction to
determine the necessity of filing a rate case in the future.
Effective October 1, 1997, Distribution Corporation commenced a PaPUC
approved customer choice pilot program called Energy Select. Energy Select,
which will last one and one-half years (until April 1, 1999), allows
approximately 19,000 small commercial and residential customers of Distribution
Corporation in the greater Sharon, Pennsylvania area to purchase gas supplies
from qualified, participating non-utility suppliers (or marketers) of gas.
Distribution Corporation is not a supplier of gas in this pilot. Under Energy
Select, Distribution Corporation will continue to deliver the gas to the
customer's home or business and will remain responsible for reading customer
meters, the safety and maintenance of its pipeline system and responding to gas
emergencies. NFR is a participating supplier in Energy Select.
<PAGE>
Item 2. Management's Discussion and Analysis of Financial Condition and
---------------------------------------------------------------
Results of Operations (Cont.)
-----------------------------
A gas restructuring bill (Senate Bill No. 943) was introduced in the
Pennsylvania General Assembly proposing to amend the Public Utility Code to
allow all retail customers, including residential, the ability to choose their
own gas supplier. Senate Bill No. 943 was not enacted into law in 1997. However,
in December 1997, the Chairman of the PaPUC convened a collaborative of gas
industry interests to develop a consensus bill using Senate Bill No. 943 as the
starting point. As a member of the utility interest group, Distribution
Corporation is and will continue to be an active participant in the
collaborative. The Company is not able to predict the outcome of the bill.
General rate increases in both the New York and Pennsylvania
jurisdictions do not reflect the recovery of purchased gas costs. Such costs are
recovered through operation of the purchased gas adjustment clauses of the
regulatory authorities having jurisdiction.
Pipeline and Storage. Supply Corporation currently does not have a rate case on
file with the FERC. Its last case was settled with the FERC in February 1996. As
part of that settlement, Supply Corporation agreed not to seek recovery of
revenues related to certain terminated service from storage customers until
April 1, 2000, as long as the terminations were not greater than approximately
30% of the terminable service. Management has been successful in marketing and
obtaining executed contracts for such terminated storage service and does not
anticipate a problem in obtaining executed contracts for additional terminated
storage service as it arises.1
OTHER MATTERS
Environmental Matters. The Company is subject to various federal, state and
local laws and regulations relating to the protection of the environment. The
Company has established procedures for on-going evaluation of its operations to
identify potential environmental exposures and assure compliance with regulatory
policies and procedures.
It is the Company's policy to accrue estimated environmental clean-up
costs when such amounts can reasonably be estimated and it is probable that the
Company will be required to incur such costs. Distribution Corporation has
estimated that clean-up costs related to several former manufactured gas plant
sites and several other waste disposal sites may be in the range of $14.0
million to $15.0 million.1 At March 31, 1998, Distribution Corporation has
recorded the minimum liability of $14.0 million. The approximate 50% increase in
the liability since September 30, 1997 mainly relates to changing circumstances
and revised estimates for one particular former manufactured gas plant site. The
ultimate cost to Distribution Corporation with respect to the remediation of all
sites will depend on such factors as the remediation plan selected, the extent
of the site contamination, the number of additional potentially responsible
parties at each site and the portion, if any, attributed to Distribution
Corporation.1 The Company is currently not aware of any material additional
exposure to environmental liabilities. However, changes in environmental
regulations or other factors could adversely impact the Company.
<PAGE>
Item 2. Management's Discussion and Analysis of Financial Condition and
---------------------------------------------------------------
Results of Operations (Cont.)
-----------------------------
In New York and Pennsylvania, Distribution Corporation is recovering
site investigation and remediation costs in rates. For further discussion, see
disclosure in Note H - Commitments and Contingencies under the heading
"Environmental Matters" in Item 8 of the Company's 1997 Form 10-K.
Year 2000. The Company is in the process of preparing all of its computer
systems to be Year 2000 compliant. Management has completed a detailed analysis
of its computer systems to identify the systems that could be affected and has
developed a conversion plan to resolve the issue. For various vendor supplied
software, the Company is in the process of obtaining upgrades that are Year 2000
compliant. For internally developed software, changes to such software are being
made and tested. The cost of upgrading both vendor supplied and internally
developed systems is being expensed as incurred. Management estimates that such
cost will total approximately $1.3 million, of which approximately one-half has
been incurred to date and one-half remains to be spent.1 The Company's goal to
have its computer systems Year 2000 compliant early in calendar 1999.1 However,
the Company has no control over the systems of third parties with whom it
interfaces. While major third parties have been put on notice that the Company
expects their products and services to perform as expected after January 1,
2000, the Company cannot predict the potential adverse consequences to the
Company that could result if such third parties are not Year 2000 compliant.
Safe Harbor for Forward-Looking Statements. The Company is including the
following cautionary statement in this Form 10-Q to make applicable and take
advantage of the safe harbor provisions of the Private Securities Litigation
Reform Act of 1995 for any forward-looking statements made by, or on behalf of,
the Company. Forward-looking statements include statements concerning plans,
objectives, goals, strategies, future events or performance, and underlying
assumptions and other statements which are other than statements of historical
facts. From time to time, the Company may publish or otherwise make available
forward-looking statements of this nature. All such subsequent forward-looking
statements, whether written or oral and whether made by or on behalf of the
Company, are also expressly qualified by these cautionary statements. Certain
statements contained herein, including those which are designated with a "1",
are forward-looking statements and accordingly involve risks and uncertainties
which could cause actual results or outcomes to differ materially from those
expressed in the forward-looking statements. The forward-looking statements
contained herein are based on various assumptions, many of which are based, in
turn, upon further assumptions. The Company's expectations, beliefs and
projections are expressed in good faith and are believed by the Company to have
a reasonable basis, including without limitation, management's examination of
historical operating trends, data contained in the Company's records and other
data available from third parties, but there can be no assurance that
management's expectations, beliefs or projections will result or be achieved or
accomplished. In addition to other factors and matters discussed elsewhere
herein, the following are important factors that, in the view of the Company,
could cause actual results to differ materially from those discussed in the
forward-looking statement:
1. Changes in economic conditions, demographic patterns and weather
conditions
2. Changes in the availability and/or price of natural gas and oil
<PAGE>
Item 2. Management's Discussion and Analysis of Financial Condition and
---------------------------------------------------------------
Results of Operations (Concl.)
------------------------------
3. Inability to obtain new customers or retain existing ones
4. Significant changes in competitive factors affecting the Company
5. Governmental/regulatory actions and initiatives, including those affecting
financings, allowed rates of return, industry and rate structure,
franchise renewal, and environmental/safety requirements
6. Unanticipated impacts of restructuring initiatives in the natural gas and
electric industries
7. Significant changes from expectations in actual capital expenditures and
operating expenses and unanticipated project delays
8. Occurrences affecting the Company's ability to obtain funds from
operations, debt or equity to finance needed capital expenditures and
other investments
9. Ability to successfully identify and finance oil and gas property
acquisitions and ability to operate existing and any subsequently acquired
properties
10. Ability to successfully identify, drill for and produce economically
viable natural gas and oil reserves
11. Changes in the availability and/or price of derivative financial
instruments
12. Inability of the various counterparties to meet their obligations with
respect to the Company's financial instruments
13. Regarding foreign operations - changes in foreign trade and monetary
policies, laws and regulations related to foreign operations, political
and governmental changes, inflation and exchange rates, taxes and
operating conditions
14. Significant changes in tax rates or policies or in rates of inflation or
interest
15. Significant changes in the Company's relationship with its employees and
the potential adverse effects if labor disputes or grievances were to
occur
16. Changes in accounting principles and/or the application of such principles
to the Company
The Company disclaims any obligation to update any forward-looking
statements to reflect events or circumstances after the date hereof.
Item 3. Quantitative and Qualitative Disclosures About Market Risk
- -------------------------------------------------------------------
Not applicable.
<PAGE>
Part II. Other Information
- ---------------------------
Item 2. Changes in Securities
- ------------------------------
On January 1, 1998, the Company issued 723 unregistered shares of
Company common stock to the seven non-employee directors of the Company. These
shares were issued as partial consideration for the directors' service as
directors during the quarter ended March 31, 1998, pursuant to the Company's
Retainer Policy for Non-Employee Directors.
These transactions were exempt from registration by Section 4(2) of the
Securities Act of 1933, as amended, as transactions not involving any public
offering.
Item 4. Submission of Matters to a Vote of Security Holders
- ------------------------------------------------------------
The Annual Meeting of Shareholders of National Fuel Gas Company was
held on February 26, 1998. At that meeting, the shareholders elected directors
and appointed independent accountants.
The total votes were as follows:
Against Broker
For or Withheld Abstain Non-Votes
---------- ----------- ------- ---------
(i) Election of directors
to serve for a three-
year term:
- Philip C. Ackerman 31,829,812 575,100 - -
- James V. Glynn 31,718,115 686,797 - -
- Bernard S. Lee 31,847,790 557,122 - -
(ii) Appointment of Price
Waterhouse LLP as
independent accountants 31,951,312 222,582 231,018 -
(iii) Approval of Amendment
of the Restated
Certificate of
Incorporation to
increase the amount
of authorized Common
Stock 29,700,741 2,265,428 438,743 -
(iv) Approval of Amendment
of the Restated
Certificate of
Incorporation to
revise provisions
related to Preferred
Stock 18,323,995 8,874,937 729,062 4,476,918
<PAGE>
Item 6. Exhibits and Reports on Form 8-K
- -----------------------------------------
(a) Exhibits
Exhibit
Number Description of Exhibit
------ ----------------------
(12) Statements regarding Computation of Ratios:
Ratio of Earnings to Fixed Charges for the
Twelve Months Ended March 31, 1998 and the
Fiscal Years Ended September 30, 1993
through 1997.
(18) Letter regarding Change in Accounting
Principle
(27.1) Financial Data Schedule for the Six Months
Ended March 31, 1998.
(27.2) Financial Data Schedule, as Restated, for
the Three Months Ended December 31, 1997.
(99) National Fuel Gas Company Consolidated
Statement of Income for the Twelve
Months Ended March 31, 1998 and 1997.
(b) Reports on Form 8-K
None
<PAGE>
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.
NATIONAL FUEL GAS COMPANY
-------------------------
(Registrant)
/s/Joseph P. Pawlowski
-----------------------------
Joseph P. Pawlowski
Treasurer and
Principal Accounting Officer
Date: May 14, 1998
------------
<PAGE>
EXHIBIT INDEX
(Form 10Q)
Exhibit 12 Statements regarding Computation of Ratios:
Ratio of Earnings to Fixed Charges for the Twelve
Months Ended March 31, 1998 and the Fiscal Years
Ended September 30, 1993 through 1997.
Exhibit 18 Letter regarding Change in Accounting Principle
Exhibit 27-1 Financial Data Schedule for the Six Months Ended
March 31, 1998.
Exhibit 27-2 Financial Data Schedule, as Restated, for the Three
Months Ended December 31, 1997.
Exhibit 99 National Fuel Gas Company Consolidated Statement of
Income for the Twelve Months Ended March 31, 1998
and 1997.
<TABLE>
<CAPTION>
EXHIBIT 12
COMPUTATION OF RATIO OF
EARNINGS TO FIXED CHARGES
UNAUDITED
Twelve Months Fiscal Year Ended September 30
Ended -------------------------------------------------------
March 31, 1998 1997 1996 1995 1994 1993
<S> <C> <C> <C> <C> <C> <C>
------------------------------------------------------------------------------
(Thousands of Dollars)
EARNINGS:
Income Before Interest Charges and Minority
Interest in Foreign Subsidiaries (2) $108,311 $169,783 $159,599 $128,061 $127,885 $125,742
Allowance for Borrowed Funds Used in
Construction 173 346 205 195 209 174
Federal Income Tax 66,075 57,807 55,148 30,522 36,630 21,148
State Income Tax 7,435 7,067 7,266 4,905 6,309 2,979
Deferred Inc. Taxes - Net (3) (48,037) 3,800 3,907 8,452 4,853 16,919
Investment Tax Credit - Net (635) (665) (665) (672) (682) (693)
Rentals (1) 5,026 5,328 5,640 5,422 5,730 5,621
-------- ------- -------- -------- -------- --------
$138,348 $243,466 $231,100 $176,885 $180,934 $171,890
======== ======== ======== ======== ======== ========
FIXED CHARGES:
Interest & Amortization of Premium and
Discount of Funded Debt $44,336 $42,131 $40,872 $40,896 $36,699 $38,507
Interest on Commercial Paper and
Short-Term Notes Payable 8,762 8,808 7,872 6,745 5,599 7,465
Other Interest (2) 17,296 4,502 6,389 4,721 3,361 4,727
Rentals (1) 5,026 5,328 5,640 5,422 5,730 5,621
------- ------- ------- ------- ------- -------
$75,420 $60,769 $60,773 $57,784 $51,389 $56,320
======= ======= ======= ======= ======= =======
RATIO OF EARNINGS TO FIXED CHARGES 1.83 4.01 3.80 3.06 3.52 3.05
</TABLE>
Notes:
(1) Rentals shown above represent the portion of all rentals (other than
delay rentals) deemed representative of the interest factor.
(2) Twelve months ended March 31, 1998 and fiscal 1997, 1996, 1995, 1994
and 1993 reflect the reclassification of $1,716, $1,716, $1,716, $1,716,
$1,674 and $1,374, respectively, representing the loss on reacquired
debt amortized during each period, from Other Interest Charges to
Operation Expense.
(3) Deferred Income Taxes - Net for fiscal 1994 and for the twelve months
ended March 31, 1998, excludes deferred income taxes associated with the
cumulative effect of changes in accounting.
3600 Marine Midland Center Telephone 716 856 4650
Buffalo, New York 14203
PRICE WATERHOUSE LLP
May 6, 1998
To the Board of Directors
and Shareholders of
National Fuel Gas Company
Ladies and Gentlemen:
We have been furnished with a copy of the National Fuel Gas Company and its
subsidiaries' (the Company) Form 10-Q for the quarter ended March 31, 1998. Note
1 therein describes a change in the method of determining the amortization of
the capitalized costs of oil and gas assets from the gross revenue to the units
of production method. It should be understood that the preferability of one
acceptable method of amortization accounting over another has not been addressed
in any authoritative accounting literature and in arriving at our opinion
expressed below, we have relied on management's business planning and judgment.
Based upon our discussions with management and the stated reasons for the
change, we believe that such change represents, in your circumstances, the
adoption of a preferable alternative accounting principle for amortization in
conformity with Accounting Principles Board Opinion No. 20.
We have not made an audit in accordance with generally accepted auditing
standards of the financial statements of the Company for the three-month or
six-month periods ended March 31, 1998 or March 31, 1997 and, accordingly, we
express no opinion thereon or on the financial information filed as part of the
Form 10-Q of which this letter is to be an exhibit.
Yours very truly,
PRICE WATERHOUSE LLP
WARNING: THE EDGAR SYSTEM ENCOUNTERED ERROR(S) WHILE PROCESSING THIS SCHEDULE.
<TABLE> <S> <C>
<ARTICLE> UT
<LEGEND>
THE SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM NATIONAL FUEL
GAS COMPANY'S CONSOLIDATED FINANCIAL STATEMENTS AND IS QUALIFIED IN ITS ENTIRETY
BY REFERENCE TO SUCH FINANCIAL STATEMENTS.
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 06-MOS
<FISCAL-YEAR-END> SEP-30-1998
<PERIOD-START> OCT-01-1997
<PERIOD-END> MAR-31-1998
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 2,012,069
<OTHER-PROPERTY-AND-INVEST> 0
<TOTAL-CURRENT-ASSETS> 351,380
<TOTAL-DEFERRED-CHARGES> 6,912
<OTHER-ASSETS> 236,178
<TOTAL-ASSETS> 2,606,539
<COMMON> 38,298
<CAPITAL-SURPLUS-PAID-IN> 408,703
<RETAINED-EARNINGS> 446,565
<TOTAL-COMMON-STOCKHOLDERS-EQ> 892,391
0
0
<LONG-TERM-DEBT-NET> 543,410
<SHORT-TERM-NOTES> 283,235
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 95,000
<LONG-TERM-DEBT-CURRENT-PORT> 153,572
0
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 638,931
<TOT-CAPITALIZATION-AND-LIAB> 2,606,539
<GROSS-OPERATING-REVENUE> 833,669
<INCOME-TAX-EXPENSE> 13,210
<OTHER-OPERATING-EXPENSES> 784,407
<TOTAL-OPERATING-EXPENSES> 797,617
<OPERATING-INCOME-LOSS> 36,052
<OTHER-INCOME-NET> 26,762
<INCOME-BEFORE-INTEREST-EXPEN> 62,814
<TOTAL-INTEREST-EXPENSE> 43,713
<NET-INCOME> 7,156
0
<EARNINGS-AVAILABLE-FOR-COMM> 7,156
<COMMON-STOCK-DIVIDENDS> 33,186
<TOTAL-INTEREST-ON-BONDS> 0
<CASH-FLOW-OPERATIONS> 122,657
<EPS-PRIMARY> .19
<EPS-DILUTED> .18
</TABLE>
WARNING: THE EDGAR SYSTEM ENCOUNTERED ERROR(S) WHILE PROCESSING THIS SCHEDULE.
<TABLE> <S> <C>
<ARTICLE> UT
<LEGEND>
THE SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM NATIONAL FUEL
GAS COMPANY'S CONSOLIDATED FINANCIAL STATEMENTS AND IS QUALIFIED IN ITS ENTIRETY
BY REFERENCE TO SUCH FINANCIAL STATEMENTS.
</LEGEND>
<RESTATED>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 03-MOS
<FISCAL-YEAR-END> SEP-30-1998
<PERIOD-START> OCT-01-1997
<PERIOD-END> DEC-31-1997
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 1,864,779
<OTHER-PROPERTY-AND-INVEST> 0
<TOTAL-CURRENT-ASSETS> 327,250
<TOTAL-DEFERRED-CHARGES> 8,576
<OTHER-ASSETS> 213,405
<TOTAL-ASSETS> 2,414,010
<COMMON> 38,249
<CAPITAL-SURPLUS-PAID-IN> 407,938
<RETAINED-EARNINGS> 484,431
<TOTAL-COMMON-STOCKHOLDERS-EQ> 926,229
0
0
<LONG-TERM-DEBT-NET> 586,273
<SHORT-TERM-NOTES> 162,000
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 55,000
<LONG-TERM-DEBT-CURRENT-PORT> 53,027
0
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 631,481
<TOT-CAPITALIZATION-AND-LIAB> 2,414,010
<GROSS-OPERATING-REVENUE> 371,021
<INCOME-TAX-EXPENSE> 22,950
<OTHER-OPERATING-EXPENSES> 295,791
<TOTAL-OPERATING-EXPENSES> 318,741
<OPERATING-INCOME-LOSS> 52,280
<OTHER-INCOME-NET> 1,168
<INCOME-BEFORE-INTEREST-EXPEN> 53,448
<TOTAL-INTEREST-EXPENSE> 15,487
<NET-INCOME> 28,418
0
<EARNINGS-AVAILABLE-FOR-COMM> 28,418
<COMMON-STOCK-DIVIDENDS> 16,582
<TOTAL-INTEREST-ON-BONDS> 0
<CASH-FLOW-OPERATIONS> 17,072
<EPS-PRIMARY> .74
<EPS-DILUTED> .73
</TABLE>
Exhibit 99
Form 10-Q
March 31, 1998
NATIONAL FUEL GAS
CONSOLIDATED STATEMENT OF INCOME
(UNAUDITED)
Twelve Months Ended
March 31,
--------------------
1998 1997
(Thousands of Dollars)
INCOME
Operating Revenues $1,237,284 $1,261,509
---------- ----------
Operating Expenses
Purchased Gas 466,087 513,078
Fuel Used in Heat and Electric Generation 17,592 822
Operation 282,017 279,778
Maintenance 26,639 24,653
Property, Franchise and Other Taxes 95,207 100,231
Depreciation, Depletion and Amortization 113,883 108,363
Impairment of Oil & Gas Producing Properties 128,996 -
Income Taxes - Net 25,473 70,148
---------- ----------
1,155,894 1,097,073
---------- ----------
Operation Income 81,390 164,436
Other Income 28,637 3,385
---------- ----------
Income Before Interest Charges and
Minority Interest in Foreign Subsidiary 110,027 167,821
---------- ----------
Interest Charges
Interest on Long-Term Debt 44,336 41,354
Other Interest 27,601 14,180
---------- ----------
71,937 55,534
---------- ----------
Minority Interest in Foreign Subsidiary (2,829) -
---------- ----------
Income Before Cumulative Effect 35,261 112,287
Cumulative Effect of Change in Accounting for
Depletion (9,116) -
---------- ----------
Net Income Available for Common Stock $ 26,145 $ 112,287
========== ==========
Basic Earnings (Loss) Per Common Share
Income Before Cumulative Effect $ 0.92 $ 2.96
Cumulative Effect fo Change in Accounting
for Depletion (0.24) -
--------- ---------
Net Income Available for Common Stock $ 0.68 $ 2.96
========= =========
Diluted Earnings (Loss) Per Common Share
Income Before Cumulative Effect $ 0.91 $ 2.94
Cumulative Effect of Change in Accounting
for Depletion (0.24) -
--------- ---------
Net Income Available for Common Stock $ 0.67 $ 2.94
========= =========
Weighted Average Common Shares Outstanding
Used in Basic Calculation 38,188,112 37,875,142
========== ==========
Used in Diluted Calculation 38,591,405 38,172,308
========== ==========
