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 June 30, 2003
Commission File Number 1-3880
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 | 14203 |
| Buffalo, New York | (Zip Code) |
(Address of principal executive offices)
(716)
857-7000
(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
Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act). YES X NO
Indicate the number 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 July 31, 2003: 81,331,544 shares.
| DIRECT SUBSIDIARIES: | National Fuel Gas Distribution Corporation (Distribution Corporation) |
| National Fuel Gas Supply Corporation (Supply Corporation) | |
| Seneca Resources Corporation (Seneca) | |
| Highland Forest Resources, Inc. (Highland) | |
| Leidy Hub, Inc. (Leidy Hub) | |
| Data-Track Account Services, Inc. (Data-Track) | |
| National Fuel Resources, Inc. (NFR) | |
| Horizon Energy Development, Inc. (Horizon) | |
| Upstate Energy Inc. (Upstate) | |
| Horizon Power, Inc. (Horizon Power) | |
| Niagara Independence Marketing Company (NIM) | |
| Seneca Independence Pipeline Company (SIP) |
INDEX
Part I. Financial InformationReference to the “Company” in this report means the Registrant or the Registrant and its subsidiaries collectively, as appropriate in the context of the disclosure. All references to a certain year in this report are to the Company’s fiscal year ended September 30 of that year, unless otherwise noted.
This Form 10-Q contains “forward-looking statements” within the meaning of Section 21E of the Securities Exchange Act of 1934. Forward-looking statements should be read with the cautionary statements and important factors 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 an asterisk (“*”) 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.
Part I. Financial Information
National Fuel Gas Company
Consolidated Statements of Income and Earnings
Reinvested in the Business
(Unaudited)
Three Months Ended
June 30,
(Dollars in Thousands, Except Per Common Share Amounts) 2003 2002
------------------ -----------------
INCOME
Operating Revenues $449,530 $350,123
- ------------------------------------------------------------------------------- ------------------ -----------------
Operating Expenses
Purchased Gas 212,863 111,287
Fuel Used in Heat and Electric Generation 10,820 10,029
Operation and Maintenance 90,635 94,316
Property, Franchise and Other Taxes 20,730 18,562
Depreciation, Depletion and Amortization 47,259 44,816
Impairment of Oil and Gas Producing Properties 31,812 -
Income Taxes 9,150 13,756
- ------------------------------------------------------------------------------- ------------------ -----------------
423,269 292,766
- ------------------------------------------------------------------------------- ------------------ -----------------
Operating Income 26,261 57,357
Operations of Unconsolidated Subsidiaries:
Income (Loss) (39) (173)
Impairment of Investment in Partnership - (15,167)
- ------------------------------------------------------------------------------- ------------------ -----------------
(39) (15,340)
- ------------------------------------------------------------------------------- ------------------ -----------------
Other Income 1,070 1,463
- ------------------------------------------------------------------------------- ------------------ -----------------
Income Before Interest Charges and
Minority Interest in Foreign Subsidiaries 27,292 43,480
- ------------------------------------------------------------------------------- ------------------ -----------------
Interest Charges
Interest on Long-Term Debt 23,117 23,133
Other Interest 2,833 3,013
- ------------------------------------------------------------------------------- ------------------ -----------------
25,950 26,146
- ------------------------------------------------------------------------------- ------------------ -----------------
Minority Interest in Foreign Subsidiaries 877 342
- ------------------------------------------------------------------------------- ------------------ -----------------
Net Income Available for Common Stock 2,219 17,676
EARNINGS REINVESTED IN THE BUSINESS
Balance at April 1 626,161 568,446
- ------------------------------------------------------------------------------- ------------------ -----------------
628,380 586,122
Dividends on Common Stock
(2003 - $0.27 per share; 2002 - $0.26 per share) 21,884 20,770
- ------------------------------------------------------------------------------- ------------------ -----------------
Balance at June 30 $606,496 $565,352
=============================================================================== ================== =================
Earnings Per Common Share:
Basic $0.03 $0.22
=============================================================================== ================== =================
Diluted $0.03 $0.22
=============================================================================== ================== =================
Weighted Average Common Shares Outstanding:
Used in Basic Calculation 80,890,982 79,966,075
=============================================================================== ================== =================
Used in Diluted Calculation 81,914,060 80,840,436
=============================================================================== ================== =================
See Notes to Condensed Consolidated Financial Statements
National Fuel Gas Company
Consolidated Statements of Income and Earnings
Reinvested in the Business
(Unaudited)
Nine Months Ended
June 30,
(Dollars in Thousands, Except Per Common Share Amounts) 2003 2002
----------------- -----------------
INCOME
Operating Revenues $1,738,302 $1,219,887
- -------------------------------------------------------------------------------- ----------------- -----------------
Operating Expenses
Purchased Gas 870,034 413,909
Fuel Used in Heat and Electric Generation 52,970 42,576
Operation and Maintenance 285,491 299,794
Property, Franchise and Other Taxes 64,084 55,875
Depreciation, Depletion and Amortization 142,168 131,976
Impairment of Oil and Gas Producing Properties 31,812 -
Income Taxes 87,062 70,274
- -------------------------------------------------------------------------------- ----------------- -----------------
1,533,621 1,014,404
- -------------------------------------------------------------------------------- ----------------- -----------------
Operating Income 204,681 205,483
Operations of Unconsolidated Subsidiaries:
Income (Loss) 489 (423)
Impairment of Investment in Partnership - (15,167)
- -------------------------------------------------------------------------------- ----------------- -----------------
489 (15,590)
- -------------------------------------------------------------------------------- ----------------- -----------------
Other Income 5,448 4,745
- -------------------------------------------------------------------------------- ----------------- -----------------
Income Before Interest Charges and
Minority Interest in Foreign Subsidiaries 210,618 194,638
- -------------------------------------------------------------------------------- ----------------- -----------------
Interest Charges
Interest on Long-Term Debt 69,741 68,285
Other Interest 9,333 11,919
- -------------------------------------------------------------------------------- ----------------- -----------------
79,074 80,204
- -------------------------------------------------------------------------------- ----------------- -----------------
Minority Interest in Foreign Subsidiaries (1,853) (1,627)
- -------------------------------------------------------------------------------- ----------------- -----------------
Income Before Cumulative Effect of Changes in Accounting 129,691 112,807
Cumulative Effect of Changes in Accounting (8,892) -
- -------------------------------------------------------------------------------- ----------------- -----------------
Net Income Available for Common Stock 120,799 112,807
EARNINGS REINVESTED IN THE BUSINESS
Balance at October 1 549,397 513,488
- -------------------------------------------------------------------------------- ----------------- -----------------
670,196 626,295
Dividends on Common Stock
(2003 - $0.79; 2002 - $0.765) 63,700 60,943
- -------------------------------------------------------------------------------- ----------------- -----------------
Balance at June 30 $606,496 $565,352
================================================================================ ================= =================
Earnings Per Common Share:
Basic:
Income Before Cumulative Effect of Changes in Accounting $1.61 $1.42
Cumulative Effect of Changes in Accounting (0.11) -
- -------------------------------------------------------------------------------- ----------------- -----------------
Net Income Available for Common Stock $1.50 $1.42
================================================================================ ================= =================
Diluted:
Income Before Cumulative Effect of Changes in Accounting $1.60 $1.40
Cumulative Effect of Changes in Accounting (0.11) -
- -------------------------------------------------------------------------------- ----------------- -----------------
Net Income Available for Common Stock $1.49 $1.40
================================================================================ ================= =================
Weighted Average Common Shares Outstanding:
Used in Basic Calculation 80,627,319 79,700,002
================================================================================ ================= =================
Used in Diluted Calculation 81,095,757 80,673,096
================================================================================ ================= =================
See Notes to Condensed Consolidated Financial Statements
National Fuel Gas Company
Consolidated Balance Sheets
(Unaudited)
June 30, September 30,
2003 2002
-------------------- -------------------
(Thousands of Dollars)
ASSETS
Property, Plant and Equipment $4,990,251 $4,512,651
Less - Accumulated Depreciation, Depletion
and Amortization 1,881,623 1,667,906
- ---------------------------------------------------------------------------- -------------------- -------------------
3,108,628 2,844,745
- ---------------------------------------------------------------------------- -------------------- -------------------
Current Assets
Cash and Temporary Cash Investments 51,825 22,216
Receivables - Net 216,798 95,510
Unbilled Utility Revenue 20,120 21,918
Gas Stored Underground 19,716 77,250
Materials and Supplies - at average cost 33,348 31,582
Unrecovered Purchased Gas Costs 14,178 12,431
Prepayments 34,439 41,354
Fair Value of Derivative Financial Instruments 1,435 3,807
- ---------------------------------------------------------------------------- -------------------- -------------------
391,859 306,068
- ---------------------------------------------------------------------------- -------------------- -------------------
Other Assets
Recoverable Future Taxes 86,797 82,385
Unamortized Debt Expense 23,064 20,635
Other Regulatory Assets 56,604 26,104
Deferred Charges 5,458 5,914
Other Investments 71,126 65,090
Investments in Unconsolidated Subsidiaries 16,400 16,753
Goodwill 5,652 8,255
Intangible Assets 51,865 11,451
Other 14,594 13,909
- ---------------------------------------------------------------------------- -------------------- -------------------
331,560 250,496
- ---------------------------------------------------------------------------- -------------------- -------------------
$3,832,047 $3,401,309
============================================================================ ==================== ===================
See Notes to Condensed Consolidated Financial Statements
National Fuel Gas Company
Consolidated Balance Sheets
(Unaudited)
June 30, September 30,
2003 2002
-------------------- -------------------
(Thousands of Dollars)
CAPITALIZATION AND LIABILITIES
Capitalization:
Comprehensive Shareholders' Equity
Common Stock, $1 Par Value
Authorized - 200,000,000 Shares; Issued
and Outstanding - 81,189,567 Shares and
80,264,734 Shares, Respectively $ 81,190 $ 80,265
Paid in Capital 473,184 446,832
Earnings Reinvested in the Business 606,496 549,397
- ---------------------------------------------------------------------------- -------------------- -------------------
Total Common Shareholder Equity
Before Items of Other Comprehensive Loss 1,160,870 1,076,494
Accumulated Other Comprehensive Loss (13,973) (69,636)
- ---------------------------------------------------------------------------- ------------------- -------------------
Total Comprehensive Shareholders' Equity 1,146,897 1,006,858
Long-Term Debt, Net of Current Portion 1,251,961 1,145,341
- ---------------------------------------------------------------------------- -------------------- -------------------
Total Capitalization 2,398,858 2,152,199
- ---------------------------------------------------------------------------- -------------------- -------------------
Minority Interest in Foreign Subsidiaries 34,212 28,785
- ---------------------------------------------------------------------------- -------------------- -------------------
Current and Accrued Liabilities
Notes Payable to Banks and
Commercial Paper 321,600 265,386
Current Portion of Long-Term Debt 141,691 160,564
Accounts Payable 143,574 100,886
Amounts Payable to Customers 12,907 -
Other Accruals and Current Liabilities 166,057 121,518
Fair Value of Derivative Financial Instruments 37,120 31,204
- ---------------------------------------------------------------------------- -------------------- -------------------
822,949 679,558
- ---------------------------------------------------------------------------- -------------------- -------------------
Deferred Credits
Accumulated Deferred Income Taxes 371,335 356,220
Taxes Refundable to Customers 15,596 15,596
Unamortized Investment Tax Credit 8,375 8,897
Other Regulatory Liabilities 75,984 82,676
Asset Retirement Obligation 39,791 -
Other Deferred Credits 64,947 77,378
- ---------------------------------------------------------------------------- -------------------- -------------------
576,028 540,767
- ---------------------------------------------------------------------------- -------------------- -------------------
Commitments and Contingencies - -
- ---------------------------------------------------------------------------- -------------------- -------------------
$3,832,047 $3,401,309
============================================================================ ==================== ===================
See Notes to Condensed Consolidated Financial Statements
National Fuel Gas Company
Consolidated Statements of Cash Flows
(Unaudited)
Nine Months Ended
June 30,
(Thousands of Dollars) 2003 2002
------------------- ---------------------
OPERATING ACTIVITIES
Net Income Available for Common Stock $120,799 $112,807
Adjustments to Reconcile Net Income to Net Cash
Provided by Operating Activities:
Depreciation, Depletion and Amortization 142,168 131,976
Impairment of Oil and Gas Producing Properties 31,812 -
Impairment of Investment in Partnership - 15,167
Cumulative Effect of Changes in Accounting 8,892 -
Deferred Income Taxes 4,378 30,380
(Income) Loss from Unconsolidated Subsidiaries, Net of
Cash Distributions 727 836
Minority Interest in Foreign Subsidiaries 1,853 1,627
Other 2,480 4,703
Change in:
Receivables and Unbilled Utility Revenue (112,439) 1,273
Gas Stored Underground and Materials and
Supplies 56,582 62,202
Unrecovered Purchased Gas Costs (1,747) (14,344)
Prepayments 9,666 3,000
Accounts Payable 38,716 (21,185)
Amounts Payable to Customers 12,907 (51,223)
Other Accruals and Current Liabilities 46,343 163
Other Assets (32,485) 13,119
Other Liabilities (12,823) 14,496
- ---------------------------------------------------------------------------- ------------------- ---------------------
Net Cash Provided by Operating Activities 317,829 304,997
- ---------------------------------------------------------------------------- ------------------- ---------------------
INVESTING ACTIVITIES
Capital Expenditures (96,838) (175,585)
Investment in Subsidiaries, Net of Cash Acquired (228,888) -
Investment in Partnerships (375) (536)
Other 3,069 19,931
- ---------------------------------------------------------------------------- ------------------- ---------------------
Net Cash Used in Investing Activities (323,032) (156,190)
- ---------------------------------------------------------------------------- ------------------- ---------------------
FINANCING ACTIVITIES
Change in Notes Payable to Banks and Commercial Paper 55,778 (256,488)
Net Proceeds from Issuance of Long-Term Debt 248,513 148,977
Reduction of Long-Term Debt (223,581) (4,767)
Dividends Paid on Common Stock (62,646) (60,204)
Proceeds from Issuance of Common Stock 12,733 7,839
- ---------------------------------------------------------------------------- ------------------- ---------------------
Net Cash Provided by (Used in) Financing 30,797 (164,643)
Activities
- ---------------------------------------------------------------------------- ------------------- ---------------------
Effect of Exchange Rates on Cash 4,015 1,820
- ---------------------------------------------------------------------------- ------------------- ---------------------
Net Increase (Decrease) in Cash and Temporary Cash
Investments 29,609 (14,016)
Cash and Temporary Cash Investments at October 1 22,216 36,227
- ---------------------------------------------------------------------------- ------------------- ---------------------
Cash and Temporary Cash Investments at June 30 $51,825 $22,211
============================================================================ =================== =====================
See Notes to Condensed Consolidated Financial Statements
National Fuel Gas Company
Consolidated Statement of Comprehensive Income
(Unaudited)
Three Months Ended
June 30,
(Thousands of Dollars) 2003 2002
------------------------------------
Net Income Available for Common Stock $2,219 $17,676
- --------------------------------------------------------------------------------------------------------------------
Other Comprehensive Income, Before Tax:
Foreign Currency Translation Adjustment 31,458 36,751
Unrealized Gain (Loss) on Securities Available for Sale
Arising During the Period 1,451 (508)
Unrealized Loss on Derivative Financial
Instruments Arising During the Period (14,412) (2,874)
Reclassification Adjustment for Realized (Gains) Losses on
Derivative Financial Instruments in Net Income 16,784 (47)
- --------------------------------------------------------------------------------------------------------------------
Other Comprehensive Income Before Tax 35,281 33,322
- --------------------------------------------------------------------------------------------------------------------
Income Tax Expense (Benefit) Related to Unrealized Gain (Loss) on
Securities Available for Sale Arising During the Period 508 (178)
Income Tax Benefit Related to Unrealized Loss on
Derivative Financial Instruments Arising During the Period (5,381) (1,135)
Reclassification Adjustment for Income Tax Benefit on
Realized (Gains) Losses on Derivative Financial Instruments
In Net Income 6,357 60
- --------------------------------------------------------------------------------------------------------------------
Income Taxes - Net 1,484 (1,253)
- --------------------------------------------------------------------------------------------------------------------
Other Comprehensive Income Net of Tax 33,797 34,575
- --------------------------------------------------------------------------------------------------------------------
Comprehensive Income $36,016 $52,251
====================================================================================================================
Nine Months Ended
June 30,
(Thousands of Dollars) 2003 2002
---------------------------------
Net Income Available for Common Stock $120,799 $112,807
- --------------------------------------------------------------------------------------------------------------------
Other Comprehensive Income (Loss), Before Tax:
Foreign Currency Translation Adjustment 54,562 39,966
Unrealized Gain on Securities Available for Sale
Arising During the Period 2,180 230
Unrealized Loss on Derivative Financial
Instruments Arising During the Period (55,966) (26,096)
Reclassification Adjustment for Realized (Gains) Losses on
Derivative Financial Instruments in Net Income 56,155 (21,451)
- --------------------------------------------------------------------------------------------------------------------
Other Comprehensive Income (Loss), Before Tax 56,931 (7,351)
- --------------------------------------------------------------------------------------------------------------------
Income Tax Expense Related to Unrealized Gain on
Securities Available for Sale Arising During the Period 762 80
Income Tax Benefit Related to Unrealized Loss on
Derivative Financial Instruments Arising During the Period (21,289) (10,815)
Reclassification Adjustment for Income Tax (Expense) Benefit on
Realized (Gains) Losses on Derivative Financial Instruments
In Net Income 21,795 (8,684)
- --------------------------------------------------------------------------------------------------------------------
Income Taxes - Net 1,268 (19,419)
- --------------------------------------------------------------------------------------------------------------------
Other Comprehensive Income Net of Tax 55,663 12,068
- --------------------------------------------------------------------------------------------------------------------
Comprehensive Income $176,462 $124,875
====================================================================================================================
See Notes to Condensed Consolidated Financial Statements
National Fuel Gas Company
Notes to Condensed Consolidated Financial Statements
The preparation of the consolidated financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
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, must be read in conjunction with the financial statements and notes for the years ended September 30, 2002, 2001 and 2000 that are included in the Company’s 2002 Form 10-K. The 2003 consolidated financial statements will be examined by the Company’s independent auditors after the end of the fiscal year.
The earnings for the nine months ended June 30, 2003 should not be taken as a prediction of earnings for the entire fiscal year ending September 30, 2003. Most of the Utility segment’s business is seasonal in nature and is influenced by weather conditions. Because of the seasonal nature of the Utility segment’s heating business, earnings during the winter months normally represent a substantial part of the Utility segment’s 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 (WNC) included in Distribution Corporation’s New York tariff. The WNC is effective for October through May billings. Distribution Corporation’s tariff for its Pennsylvania jurisdiction does not have a WNC. While the Pipeline and Storage segment’s business is influenced by weather conditions, 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 fluctuations.
Cumulative Effect of Changes in Accounting. Effective October 1, 2002, the Company adopted the Financial Accounting Standards Board’s (FASB) Statement of Financial Accounting Standards (SFAS) No. 143, “Accounting for Asset Retirement Obligations” (SFAS 143). SFAS 143 requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred. When the liability is initially recorded, the entity capitalizes the estimated cost of retiring the asset as part of the carrying amount of the related long-lived asset. Over time, the liability is adjusted to its present value each period and the capitalized cost is depreciated over the useful life of the related asset. In the Company’s case, SFAS 143 changed the accounting for plugging and abandonment costs associated with the Exploration and Production segment’s crude oil and natural gas wells. In prior fiscal years, the Company accounted for plugging and abandonment costs using Securities and Exchange Commission full cost accounting rules. SFAS 143 was calculated retroactively to determine the cumulative effect through October 1, 2002. This cumulative effect reduced earnings for the quarter ended December 31, 2002 and the nine months ended June 30, 2003 by $0.6 million, net of income tax. If the new method of accounting for plugging and abandonment costs had been effective for the quarter and nine months ended June 30, 2002, there would not have been a material change to net income available for common stock for the quarter and nine months ended June 30, 2002.
Item 1. Financial Statements (Cont.)Effective October 1, 2002, the Company adopted SFAS No. 142, “Goodwill and Other Intangible Assets” (SFAS 142). In accordance with SFAS 142, the Company stopped amortization of goodwill and tested it for impairment as of October 1, 2002. The Company’s goodwill balance as of October 1, 2002 totaled $8.3 million and is related to the Company’s investments in the Czech Republic, which are included in the International segment. As a result of the impairment test, the Company recognized an impairment of $8.3 million, or $0.10 per diluted share. The Company used discounted cash flows to estimate the fair value of its goodwill and determined that the goodwill had no remaining value. Based on projected restructuring in the Czech electricity market, the Company cannot be assured that the level of future cash flows from the Company’s investments in the Czech Republic will attain the level that was originally forecasted. In accordance with SFAS 142, this impairment has been reported as a cumulative effect of change in accounting retroactive to the quarter ended December 31, 2002. As such, the Company’s reported earnings for the quarter ended December 31, 2002 were reduced from $46.3 million ($0.57 per basic and diluted share) to $38.0 million ($0.47 per basic and diluted share). While the quarter and nine months ended June 30, 2003 did not have any amortization expense associated with goodwill, the quarter and nine months ended June 30, 2002 had $138,867 and $416,602, respectively, of goodwill amortization expense.
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.
Reclassification. Certain prior year amounts have been reclassified to conform with current year presentation.
Accumulated Other Comprehensive Income (Loss). The components of Accumulated Other Comprehensive Income (Loss) are as follows (in thousands):
At June 30, 2003 At September 30, 2002
---------------- ---------------------
Minimum Pension Liability Adjustment $(34,435) $(34,435)
Cumulative Foreign Currency Translation Adjustment 39,747 (14,815)
Net Unrealized Loss on Derivative
Financial Instruments (20,862) (20,545)
Net Unrealized Gain on Securities
Available for Sale 1,577 159
-------- --------
Accumulated Other Comprehensive Loss $(13,973) $(69,636)
======== ========
Stock Option and Stock Award Plans. The Company has various stock option and stock award plans which provide or provided for the issuance of one or more of the following to key employees: incentive stock options, nonqualified stock options, stock appreciation rights, restricted stock, performance units or performance shares. Stock options under all plans have exercise prices equal to the average market price of Company common stock on the date of grant, and generally no option is exercisable less than one year or more than ten years after the date of each grant. On June 5, 2003, 108,500 stock options were granted at an exercise price of $25.89 per share.
For the quarter and nine months ended June 30, 2003 and June 30, 2002, no compensation expense was recognized for options granted under these plans since the Company accounts for these plans under the recognition and measurement principles of Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees" and related interpretations. Had compensation expense for stock options granted under the Company's stock option and stock award plans been determined based on fair value at the grant dates, which is the accounting treatment specified by SFAS 123, "Accounting for
Item 1. Financial Statements (Cont.)Stock-Based Compensation," the Company's net income and earnings per share would have been reduced to the pro forma amounts below:
Three Months Ended Nine Months Ended
(Thousands of Dollars, Except Per June 30, June 30,
Common Share Amounts) 2003 2002 2003 2002
---- ---- ---- ----
Net Income Available for
Common Stock as Reported $2,219 $17,676 $120,799 $112,807
Deduct: Total Compensation
Expense Determined Based
on Fair Value at the Grant
Dates 537 1,469 2,701 3,232
------ ------- -------- --------
Pro Forma Net Income Available
For Common Stock $1,682 $16,207 $118,098 $109,575
====== ======= ======== ========
Earnings Per Common Share:
Basic - As Reported $0.03 $0.22 $1.50 $1.42
Basic - Pro Forma $0.02 $0.20 $1.46 $1.37
Diluted - As Reported $0.03 $0.22 $1.49 $1.40
Diluted - Pro Forma $0.02 $0.20 $1.46 $1.36
“Net Income Available for Common Stock as Reported” in the pro forma information shown above includes compensation expense related to restricted stock awards. For the quarter and nine months ended June 30, 2003, such compensation expense amounted to $0.3 million and $0.8 million, respectively. For the quarter and nine months ended June 30, 2002, such compensation expense amounted to $0.3 million and $0.4 million respectively.
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. 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 that could result from the exercise of these stock options as determined using the Treasury Stock Method. Stock options that are antidilutive are excluded from the calculation of diluted earnings per common share. For the quarters ended June 30, 2003 and 2002, 4,419,288 and 4,464,200 stock options, respectively, were excluded as being antidilutive. For the nine months ended June 30, 2003 and 2002, 8,591,095 and 3,415,922 stock options, respectively, were excluded as being antidilutive.
Item 1. Financial Statements (Cont.)The components of federal and state income taxes included in the Consolidated Statement of Income are as follows (in thousands):
Nine Months Ended
June 30,
2003 2002
------------------- --------------------
Operating Expenses:
Current Income Taxes
Federal $64,095 $27,331
State 16,187 8,119
Foreign 2,402 4,444
Deferred Income Taxes
Federal (794) 24,098
State (553) 4,028
Foreign 5,725 2,254
------------------- --------------------
87,062 70,274
Other Income:
Deferred Investment Tax Credit (519) (523)
Minority Interest in Foreign Subsidiaries (1,027) (635)
Cumulative Effect of Change in Accounting (354) -
------------------- --------------------
Total Income Taxes $85,162 $69,116
=================== ====================
The U.S. and foreign components of income before income taxes are as follows (in thousands):
Nine Months Ended
June 30,
2003 2002
------------------- --------------------
U.S. $209,901 $161,874
Foreign (3,940) 20,049
------------------- --------------------
$205,961 $181,923
=================== ====================
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):
Nine Months Ended
June 30,
2003 2002
------------------- --------------------
Income tax expense, computed at
statutory rate of 35% $72,086 $63,673
Increase (reduction) in taxes resulting from:
State income taxes 10,162 7,886
Depreciation 1,109 1,205
Foreign tax differential 4,354 (953)
Miscellaneous (2,549) (2,695)
------------------- --------------------
Total Income Taxes $85,162 $69,116
=================== ====================
Significant components of the Company's deferred tax liabilities (assets) were as follows (in thousands):
At June 30, 2003 At September 30, 2002
--------------------------------- ----------------------------
Deferred Tax Liabilities:
Property, Plant and Equipment $448,247 $417,673
Other 14,545 27,930
--------------------------------- ----------------------------
Total Deferred Tax Liabilities $462,792 $445,603
--------------------------------- ----------------------------
Deferred Tax Assets:
Other (91,457) (89,383)
--------------------------------- ----------------------------
Total Deferred Tax Assets (91,457) (89,383)
--------------------------------- ----------------------------
Total Net Deferred Income Taxes $371,335 $356,220
================================= ============================
Common Stock. During the nine months ended June 30, 2003, the Company issued 928,277 shares of common stock under the Company’s stock and benefit plans. The Company also repurchased and cancelled 3,444 shares of common stock.
Long-Term Debt. In February 2003, the Company issued $250.0 million of 5.25% long-term notes due in March 2013. After deducting underwriting discounts and commissions, the net proceeds to the Company amounted to approximately $248.5 million. The proceeds of this debt issuance were used to refund $150.0 million of 7.30% medium-term notes which matured in February 2003. The remaining proceeds were used to reduce short-term borrowings.
In March 2003, the Company redeemed $50.0 million of 8.48% medium-term notes at a redemption price of $52.5 million. The Company also redeemed $2.3 million of 6.214% medium-term notes in March 2003 at a redemption price of $2.25 million.
Item 1. Financial Statements (Cont.)Environmental Matters. The Company is subject to various federal, state and local laws and regulations (including those of the Czech Republic) relating to the protection of the environment. The Company has established procedures for the ongoing evaluation of its operations to identify potential environmental exposures and comply with regulatory policies and procedures. It is the Company’s policy to accrue estimated environmental clean-up costs (investigation and remediation) when such amounts can reasonably be estimated and it is probable that the Company will be required to incur such costs. At June 30, 2003, the Company has estimated its remaining clean-up costs related to former manufactured gas plant sites and third party waste disposal sites will be in the range of $5.1 million to $6.1 million. The minimum liability of $5.1 million has been recorded on the Consolidated Balance Sheet at June 30, 2003. Other than discussed in Note H of the 2002 Form 10-K (referred to below), the Company is currently not aware of any material additional exposure to environmental liabilities. However, adverse changes in environmental regulations or other factors could impact the Company.
For further discussion refer to Note H – Commitments and Contingencies under the heading “Environmental Matters” in Item 8 of the Company’s 2002 Form 10-K.
Other. In July 2003, Seneca entered into a purchase and sale agreement to sell its Southeast Saskatchewan oil properties in Canada for approximately $80 million. This sale is expected to close by September 30, 2003. When the transaction closes, the Company expects to record an after tax loss on the sale in the range of $50 million to $60 million.
The Company is involved in litigation arising in the normal course of business. Also in the normal course of business, the Company is involved in tax, regulatory and other governmental audits, inspections, investigations and other proceedings that involve state and federal taxes, safety, compliance with regulations, rate base, cost of service and purchased gas cost issues, among other things. While the resolution of such matters could have a material effect on earnings and cash flows in the year of resolution, none of these 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.
Note 5 – Business Segment Information. The Company has six reportable segments: Utility, Pipeline and Storage, Exploration and Production, International, Energy Marketing, and Timber. The breakdown of the Company’s reportable segments is based upon a combination of factors including differences in products and services, regulatory environment and geographic factors.
The data presented in the tables below reflect the reportable segments and reconciliations to consolidated amounts. There have been no changes in the basis of segmentation nor in the basis of measuring segment profit or loss from those used in the 2002 Form 10-K. In February 2003, the Pipeline and Storage segment’s acquisition of the Empire State Pipeline (Empire) increased assets by $257.6 million. In the All Other category, the June 2003 acquisition of all of the partnership interests in Toro Partners, L.P. (Toro) increased assets by approximately $47.7 million. See further discussion of these acquisitions in Note 6-Acquisitions. In June 2003, the Exploration and Production segment recorded an impairment related to its Canadian oil and gas assets. This impairment reduced assets by $31.8 million.
Item 1. Financial Statements (Cont.)
Quarter Ended June 30, 2003 (Thousands)
- ------------------------------------------------------------------------------------------------------------------------------------------------------------
Exploration Total Corporate and
Pipeline and Energy Reportable Intersegment Total
Utility and Storage Production International Marketing Timber Segments All Other Eliminations Consolidated
- --------------------------------------------------------------------------------------------------------------------------------------------
Revenue from
External Customers $222,621 $27,848 $75,752 $17,248 $93,966 $11,255 $448,690 $840 - $449,530
Intersegment
Revenues $3,379 $23,260 - - - - $26,639 - $(26,639) -
Segment Profit:
Net Income (Loss)
$8,088 $11,648 $(15,435) $(3,466) $(67) $988 $1,756 $(124) $587 $2,219
Nine Months Ended June 30, 2003 (Thousands)
- --------------------------------------------------------------------------------------------------------------------------------------------
Exploration Total Corporate and
Pipeline and Energy Reportable Intersegment Total
Utility and Storage Production International Marketing Timber Segments All Other Eliminations Consolidated
- --------------------------------------------------------------------------------------------------------------------------------------------
Revenue from
External Customers $1,017,318 $78,020 $233,735 $102,019 $262,542 $43,125 $1,736,759 $1,543 - $1,738,302
Intersegment $15,738 $67,991 - - - - $83,729 - $(83,729) -
Revenues
Segment Profit:
Income (Loss)
Before
Cumulative Effect $67,096 $34,947 $7,591 $4,896 $6,131 $8,730 $129,391 $(70) $370 $129,691
of Changes in
Accounting
Quarter Ended June 30, 2002 (Thousands)
- --------------------------------------------------------------------------------------------------------------------------------------------
Exploration Total Corporate and
Pipeline and Energy Reportable Intersegment Total
Utility and Storage Production International Marketing Timber Segments All Other Eliminations Consolidated
- -------------------------------------------------------------------------------------------------------------------------------------------
Revenue from
External $172,993 $19,774 $84,079 $17,554 $42,468 $12,064 $348,932 $1,191 - $350,123
Customers
Intersegment
Revenues $2,701 $21,642 - - - - $24,343 - ($24,343) -
Segment Profit:
Net Income (Loss) $5,711 ($535) $11,232 ($3,284) $2,474 $2,726 $18,324 ($102) ($546) $17,676
Nine Months Ended June 30, 2002 (Thousands)
- --------------------------------------------------------------------------------------------------------------------------------------------
Exploration Total Corporate and
Pipeline and Energy Reportable Intersegment Total
Utility and Storage Production International Marketing Timber Segments All Other Eliminations Consolidated
- --------------------------------------------------------------------------------------------------------------------------------------------
Revenue from
External $680,374 $60,487 $232,283 $82,737 $127,389 $34,294 $1,217,564 $2,323 - $1,219,887
Customers
Intersegment
Revenues $15,329 $65,962 - - - - $81,291 $7,340 ($88,631) -
Segment Profit:
Net Income (Loss) $59,455 $19,280 $21,381 $1,482 $6,940 $5,964 $114,502 ($564) ($1,131) $112,807
Item 1. Financial Statements (Cont.)Note 6 – Acquisitions. On February 6, 2003, the Company acquired Empire from a subsidiary of Duke Energy Corporation for $189.2 million in cash (including cash acquired) plus $57.8 million of project debt. The acquisition, which was made through Highland (a direct subsidiary of the Company having timber property and sawmill operations in New York and Pennsylvania), consisted of acquiring 100% of two companies. Each of these companies has 50% ownership of Empire, which is a joint venture. Empire’s results of operations were incorporated into the Company’s consolidated financial statements for the period subsequent to the completion of the acquisition on February 6, 2003. Empire is a 157-mile, 24-inch pipeline that begins at the United States/Canadian border at the Chippawa Channel of the Niagara River near Buffalo, New York, which is within the Company’s service territory, and terminates in Central New York just north of Syracuse, New York. Empire can transport 525 million cubic feet of gas per day and currently has almost all of its capacity under contract, with a substantial portion being long-term contracts. Empire delivers natural gas supplies to major industrial companies, utilities (including the Company’s Utility segment), and power producers. The Company believes that the acquisition of Empire better positions the Company to bring Canadian gas supplies into the East Coast markets of the United States as demand for natural gas along the East Coast increases. Details of the acquisition are as follows (all figures in thousands):
Assets Acquired (see Condensed Balance Sheet below) $257,573
Liabilities Assumed (see Condensed Balance Sheet below) (68,368)
Cash Acquired at Acquisition (8,053)
--------
Cash Paid, Net of Cash Acquired $181,152
========
Condensed Balance Sheet:
Property, Plant and Equipment $220,792
Current Assets 14,984
Goodwill 5,652
Intangible Assets 8,580
Other Assets 7,565
--------
Total Assets $257,573
========
Equity $189,205
Long-Term Debt, Net of Current Portion 48,433
--------
Total Capitalization 237,638
Current Liabilities 15,441
Other Liabilities 4,494
--------
Total Capitalization and Liabilities $257,573
========
The intangible assets referred to above in the condensed balance sheet represent the fair value of various long-term transportation contracts with Empire's customers. For the quarter ended June 30, 2003, amortization expense on these intangible assets amounted to $0.3 million. For the period of February 6, 2003 to June 30, 2003, amortization expense amounted to $0.5 million. The intangible assets balance at June 30, 2003 was $8.1 million. For the quarter ended September 30, 2003, amortization expense is estimated to be approximately $0.3 million. Amortization expense is estimated to be approximately $1.1 million annually for 2004, 2005, 2006, 2007 and 2008.
On June 3, 2003, the Company acquired for approximately $47.7 million in cash all of the partnership interests in Toro, a company which owns and operates eight short-distance landfill gas pipeline companies that purchase, transport and resell landfill gas to customers in six Midwestern states in the United States. Toro's results of operations were incorporated into the Company's consolidated financial statements for the period subsequent to the completion of the acquisition on June 3, 2003. The existing landfill gas purchase and sale agreements at these facilities will remain in place. In addition,
Item 1. Financial Statements (Concl.)
the Company believes there are opportunities for expansion at many of these locations. The acquisition consisted of approximately $15.3 million in property, plant and equipment and $32.4 million in intangible assets. The intangible assets represent the fair value of various long-term gas purchase contracts with the various landfills. For the period of June 3, 2003 to June 30, 2003, amortization expense on these intangible assets amounted to $0.1 million. The intangible assets balance at June 30, 2003 was $32.3 million. For the quarter ended September 30, 2003, amortization expense is estimated to be approximately $0.4 million. Amortization expense is estimated to be approximately $1.6 million annually for 2004, 2005, 2006, 2007 and 2008.
Note 7 - Subsequent Event. On August 1, 2003, the Company's timber subsidiary, Highland, completed the sale of approximately 70,000 acres of its timber property located in various counties in Pennsylvania and Allegany County in New York. The sale price was approximately $186.3 million and the Company will be recording a pre-tax gain on this sale of approximately $167.0 million during the quarter ended September 30, 2003.
For a complete discussion of critical accounting policies, refer to “Critical Accounting Policies” in Item 7 of the Company’s 2002 Form 10-K. There have been no subsequent changes to that disclosure.
The Company's earnings were $2.2 million, or $0.03 per common share (basic and diluted), for the quarter ended June 30, 2003. This compares with earnings of $17.7 million, or $0.22 per common share (basic and diluted), for the quarter ended June 30, 2002. The decrease in earnings of approximately $15.5 million is primarily the result of a loss in the Exploration and Production segment, partially offset by an earnings increase in the Pipeline and Storage segment, as shown in the table below. The earnings fluctuations in the Exploration and Production segment and the Pipeline and Storage segment are impacted by two events. During the quarter ended June 30, 2003, the Exploration and Production segment recorded an after-tax impairment charge of $22.6 million ($0.28 per common share on a basic and diluted basis) related to its Canadian oil and gas assets, which is discussed below. During the quarter ended June 30, 2002, the Pipeline and Storage segment recorded an after-tax impairment charge of $9.9 million ($0.12 per common share on a basic and diluted basis) related to the Company's investment in the Independence Pipeline Company.
The Company's earnings were $120.8 million, or $1.50 per common share ($1.49 per common share on a diluted basis), for the nine months ended June 30, 2003. This compares with earnings of $112.8 million, or $1.42 per common share ($1.40 per common share on a diluted basis), for the nine months ended June 30, 2002. The increase in earnings of $8.0 million is primarily the result of higher earnings in the Utility segment and Pipeline and Storage segment partially offset by lower earnings in the Exploration and Production segment and International segment, as shown in the table below. This earnings fluctuation is impacted by four events. As discussed above, the Exploration and Production segment and the Pipeline and Storage segment recorded impairment charges during the quarters ended June 30, 2003 and 2002, respectively. Also, earnings for the nine months ended June 30, 2003 included a reduction to earnings in the amount of $8.3 million ($0.10 per common share on a basic and diluted
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations (Cont.)
basis), representing the cumulative effect of a change in accounting for goodwill in the Company's International segment. Earnings for the nine months ended June 30, 2003 also included a reduction to earnings in the amount of $0.6 million ($0.01 per common share on a basic and diluted basis) representing the cumulative effect of a change in accounting for plugging and abandonment costs in the Company's Exploration and Production segment. For a more complete discussion of the cumulative effect of changes in accounting, refer to Note 1 - Summary of Significant Accounting Policies in Item 1 of this report.
The Company, in its Exploration and Production segment, follows the full cost method of accounting for its oil and gas operations. In accordance with this methodology, the Company is required to perform a quarterly ceiling test. Under the ceiling test, the present value of future revenues from the Company's oil and gas reserves is compared (on a country-by-country basis) with the book value of those reserves at the balance sheet date. If the book value of the reserves in any country exceeds the present value of the associated future revenues, a non-cash charge must be recorded to write down the book value of the reserves to their present value. Because of downward revisions to crude oil reserves as well as the decline in crude oil prices since March 31, 2003, the book value of the Company's Canadian properties exceeded the present value of the associated future revenues at June 30, 2003. Consequently, Seneca recorded an after-tax impairment charge of $22.6 million during the quarter ended June 30, 2003. For a more complete discussion of the full cost method of accounting, refer to "Oil and Gas Exploration and Development Costs" under "Critical Accounting Policies" in Item 7 of the Company's 2002 Form 10-K.
Additional discussion of earnings in each of the business segments can be found in the business segment information that follows. The Exploration and Production section discusses the planned sale of the Company's Southeast Saskatchewan oil properties in Canada, and the Timber section discusses the completion of the sale of 70,000 acres of timber property on August 1, 2003.
Earnings by Segment
- ------------------------------------ ------------------------------------------- -------------------------------------------
Three Months Ended Nine Months Ended
June 30, June 30,
- ------------------------------------ ------------- ------------- --------------- ------------- ------------- ---------------
Increase/ Increase/
(Thousands) 2003 2002 (Decrease) 2003 2002 (Decrease)
- ------------------------------------ ------------- ------------- --------------- ------------- ------------- ---------------
Utility $8,088 $5,711 $ 2,377 $ 67,096 $ 59,455 $7,641
Pipeline and Storage 11,648 (535) 12,183 34,947 19,280 15,667
Exploration and Production (15,435) 11,232 (26,667) 6,954 21,381 (14,427)
International (3,466) (3,284) (182) (3,359) 1,482 (4,841)
Energy Marketing (67) 2,474 (2,541) 6,131 6,940 (809)
Timber 988 2,726 (1,738) 8,730 5,964 2,766
- ------------------------------------ ------------- ------------- --------------- ------------- ------------- ---------------
Total Reportable Segments 1,756 18,324 (16,568) 120,499 114,502 5,997
All Other (124) (102) (22) (70) (564) 494
Corporate 587 (546) 1,133 370 (1,131) 1,501
- ------------------------------------ ------------- ------------- --------------- ------------- ------------- ---------------
Total Consolidated $2,219 $17,676 $(15,457) $120,799 $112,807 $7,992
- ------------------------------------ ------------- ------------- --------------- ------------- ------------- ---------------
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations (Cont.)
Utility
Utility Operating Revenues
- ------------------------------- ------------------------------------------- -------------------------------------------
Three Months Ended Nine Months Ended
June 30, June 30,
- ------------------------------- ------------- -------------- -------------- --------------- ------------ --------------
Increase/ Increase/
(Thousands) 2003 2002 (Decrease) 2003 2002 (Decrease)
- ------------------------------- ------------- -------------- -------------- --------------- ------------ --------------
Retail Sales Revenues:
Residential $149,748 $116,781 $32,967 $730,892 $482,461 $248,431
Commercial 23,437 18,048 5,389 127,537 78,947 48,590
Industrial 5,583 4,210 1,373 18,656 12,304 6,352
- ------------------------------- ------------- -------------- -------------- --------------- ------------ --------------
178,768 139,039 39,729 877,085 573,712 303,373
- ------------------------------- ------------- -------------- -------------- --------------- ------------ --------------
Off-System Sales 28,688 19,349 9,339 86,763 52,201 34,562
Transportation 18,162 18,472 (310) 74,395 71,452 2,943
Other 382 (1,166) 1,548 (5,187) (1,662) (3,525)
- ------------------------------- ------------- -------------- -------------- --------------- ------------ --------------
$226,000 $175,694 $50,306 $1,033,056 $695,703 $337,353
- ------------------------------- ------------- -------------- -------------- --------------- ------------ --------------
Utility Throughput
- ------------------------------- ------------------------------------------- -------------------------------------------
Three Months Ended Nine Months Ended
June 30, June 30,
- ------------------------------- ------------- -------------- -------------- ------------ --------------- --------------
Increase/ Increase/
(MMcf) 2003 2002 (Decrease) 2003 2002 (Decrease)
- ------------------------------- ------------- -------------- -------------- ------------ --------------- --------------
Retail Sales:
Residential 12,172 12,747 (575) 71,740 60,338 11,402
Commercial 2,069 2,199 (130) 13,367 10,794 2,573
Industrial 654 866 (212) 2,900 2,458 442
- ------------------------------- ------------- -------------- -------------- ------------ --------------- --------------
14,895 15,812 (917) 88,007 73,590 14,417
- ------------------------------- ------------- -------------- -------------- ------------ --------------- --------------
Off-System Sales 4,587 5,279 (692) 14,196 16,879 (2,683)
Transportation 14,510 15,482 (972) 55,496 51,991 3,505
- ------------------------------- ------------- -------------- -------------- ------------ --------------- --------------
33,992 36,573 (2,581) 157,699 142,460 15,239
- ------------------------------- ------------- -------------- -------------- ------------ --------------- --------------
Operating revenues for the Utility segment increased $50.3 million for the quarter ended June 30, 2003 as compared with the quarter ended June 30, 2002. The increase for the quarter was primarily the result of increases in the average cost of purchased gas ($7.23 and $4.59 per thousand cubic feet (Mcf) during the quarters ended June 30, 2003 and 2002, respectively). Partially offsetting this impact, lower retail sales and transportation volumes due to lower customer usage per account caused revenues to decline. The increase in off-system sales revenues was largely due to higher gas prices which more than offset lower volumes. Due to profit sharing with retail customers, the margins resulting from off-system sales are minimal. The increase in other revenues reflects an estimated refund provision of $1.8 million recorded in the Utility’s New York jurisdiction during the quarter ended June 30, 2002 that did not recur during the quarter ended June 30, 2003. The refund provision relates to a 50% sharing with customers of earnings over a predetermined amount. This earnings sharing mechanism is in accordance with the New York Rate Settlement that went into effect October 1, 2000. The final refund for the New York Rate Settlement will not be known until the end of 2003.
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations (Cont.)
Operating revenues for the Utility segment increased $337.4 million for the nine months ended June 30, 2003 as compared with the nine months ended June 30, 2002. The increase for the nine months ended June 30, 2003 was primarily the result of increases in the average cost of purchased gas ($6.95 and $4.64 per Mcf for the nine months ended June 30, 2003 and 2002, respectively) and higher retail sales volumes and transportation volumes. Colder weather, as shown in the table below, was the major factor for the increase in retail sales volumes and transportation volumes. As discussed above, the increase in off-system sales revenues was largely due to higher gas prices which more than offset lower volumes. The decrease to other revenue reflects a higher estimated refund provision under the earnings sharing mechanism discussed above. During the nine months ended June 30, 2003, an estimated refund provision of $8.1 million was recorded while an estimated refund provision of $5.3 million was recorded during the nine months ended June 30, 2002.
The Utility segment’s earnings for the quarter ended June 30, 2003 were $8.1 million, an increase of $2.4 million when compared with the quarter ended June 30, 2002. The principal contributor to this increase was a $1.2 million after tax refund provision ($1.8 million pre tax, as discussed above) recorded during the quarter ended June 30, 2002 that did not recur during the quarter ended June 30, 2003. Lower operation and maintenance expense and a lower effective income tax rate also contributed to the improvement in earnings. Weather did not have a significant impact on earnings quarter to quarter.
The Utility segment’s earnings for the nine months ended June 30, 2003 were $67.1 million, an increase of $7.6 million when compared with the earnings of $59.5 million for the nine months ended June 30, 2002. The major factor for this increase was the impact of weather, which in the Pennsylvania jurisdiction was approximately 26% colder than the nine months ended June 30, 2002. The impact of weather variations in the New York jurisdiction is mitigated by that jurisdiction’s weather normalization clause (WNC). The WNC in New York, which covers the eight month period from October through May, has had a stabilizing effect on earnings. In periods of colder than normal weather, the WNC benefits Distribution Corporation’s New York customers. For October 2002 through May 2003, the WNC reduced New York ratepayers’ bills by approximately $5.9 million because it was colder than normal. For October 2001 through May 2002, the WNC increased New York ratepayers’ bills by approximately $15.3 million because it was warmer than normal.
Degree Days
- ---------------------------------- -------------- -------------- -------------------- --------------------------------
Percent (Warmer)
Three Months Ended Colder Than
--------------------------------
June 30 Normal 2003 2002 Normal Prior Year
- ---------------------------------- -------------- -------------- -------------------- ----------------- --------------
Buffalo 956 1,028 1,039 7.5% (1.1%)
Erie 867 987 926 13.8% 6.6%
- ---------------------------------- -------------- -------------- -------------------- ----------------- --------------
Nine Months Ended
June 30
- ---------------------------------- -------------- -------------- -------------------- ----------------- --------------
Buffalo 6,617 7,030 5,753 6.2% 22.2%
Erie 6,036 6,673 5,283 10.6% 26.3%
- ---------------------------------- -------------- -------------- -------------------- ----------------- --------------
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations (Cont.)
Pipeline and Storage
Pipeline and Storage Operating Revenues
- ------------------------------------ ---------------------------------------- -------------------------------------------
Three Months Ended Nine Months Ended
June 30, June 30,
- ------------------------------------ ------------ ------------ -------------- --------------- ------------ --------------
Increase/ Increase/
(Thousands) 2003 2002 (Decrease) 2003 2002 (Decrease)
- ------------------------------------ ------------ ------------ -------------- --------------- ------------ --------------
Firm Transportation $30,054 $21,782 $8,272 $80,250 $66,875 $13,375
Interruptible Transportation 1,142 941 201 2,643 2,448 195
- ------------------------------------ ------------ ------------ -------------- --------------- ------------ --------------
31,196 22,723 8,473 82,893 69,323 13,570
- ------------------------------------ ------------ ------------ -------------- --------------- ------------ --------------
Firm Storage Service 15,779 16,217 (438) 47,382 47,234 148
Interruptible Storage Service (13) - (13) 12 7 5
- ------------------------------------ ------------ ------------ -------------- --------------- ------------ --------------
15,766 16,217 (451) 47,394 47,241 153
- ------------------------------------ ------------ ------------ -------------- --------------- ------------ --------------
Other 4,146 2,476 1,670 15,724 9,885 5,839
- ------------------------------------ ------------ ------------ -------------- --------------- ------------ --------------
$51,108 $41,416 $9,692 $146,011 $126,449 $19,562
- ------------------------------------ ------------ ------------ -------------- --------------- ------------ --------------
Pipeline and Storage Throughput
- ------------------------------------ ---------------------------------------- -------------------------------------------
Three Months Ended Nine Months Ended
June 30, June 30,
- ------------------------------------ ------------ ------------ -------------- --------------- ------------ --------------
Increase/ Increase/
(MMcf) 2003 2002 (Decrease) 2003 2002 (Decrease)
- ------------------------------------ ------------ ------------ -------------- --------------- ------------ --------------
Firm Transportation 69,932 63,504 6,428 285,080 234,942 50,138
Interruptible Transportation 3,173 1,384 1,789 7,487 5,251 2,236
- ------------------------------------ ------------ ------------ -------------- --------------- ------------ --------------
73,105 64,888 8,217 292,567 240,193 52,374
- ------------------------------------ ------------ ------------ -------------- --------------- ------------ --------------
Operating revenues for the Pipeline and Storage segment increased $9.7 million and $19.6 million, respectively, for the quarter and nine months ended June 30, 2003 as compared with the quarter and nine months ended June 30, 2002. The acquisition of Empire State Pipeline (Empire) from Duke Energy Corporation on February 6, 2003 was a significant factor in these revenue increases. For the quarter ended June 30, 2003, Empire recorded operating revenues of $7.7 million ($7.5 million in firm transportation revenues, $0.1 million in interruptible transportation revenues, and $0.1 million in other revenues). For the period of February 6, 2003 to June 30, 2003, Empire recorded operating revenues of $13.5 million ($12.5 million in firm transportation revenues, $0.7 million in interruptible transportation revenues, and $0.3 million in other revenues). Supply Corporation’s revenue from unbundled pipeline sales and open access transportation (included in other revenues) was the other major factor in the revenue increase for the quarter and nine month periods. For the quarter and nine months ended June 30, 2003, revenue from unbundled pipeline sales and open access transportation increased $2.1 million and $4.9 million, respectively. Higher volumes and higher natural gas commodity prices were the reasons for the increase in revenue from unbundled pipeline sales and open access transportation.
The Pipeline and Storage segment’s earnings for the quarter ended June 30, 2003 were $11.6 million, an increase of $12.1 million when compared with a loss of $0.5 million for the quarter ended June 30, 2002. As previously discussed, during the quarter ended June 30, 2002, the Pipeline and Storage segment recorded an after tax impairment charge of $9.9 million related to the Company’s investment in
Item 2.Management’s Discussion and Analysis of Financial Condition and Results of Operations (Cont.)the Independence Pipeline Company. Higher revenues from unbundled pipeline sales and open access transportation were also a factor in this earnings increase. Earnings also increased due to the acquisition of Empire, which contributed $0.9 million to earnings for the quarter ended June 30, 2003.
The Pipeline and Storage segment’s earnings for the nine months ended June 30, 2003 were $34.9 million, an increase of $15.6 million when compared with earnings of $19.3 million for the nine months ended June 30, 2002. As discussed above, the after-tax impairment charge of $9.9 million recorded during the quarter ended June 30, 2002, was the major factor in this increase. Higher revenues from unbundled pipeline sales and open access transportation combined with the earnings contribution from Empire were the other major factors.
Exploration and Production
Exploration and Production Operating Revenues
- ----------------------------------- ---------------------------------------- -----------------------------------------
Three Months Ended Nine Months Ended
June 30, June 30,
- ----------------------------------- ------------ ------------ -------------- ------------- ------------ --------------
Increase/ Increase/
(Thousands) 2003 2002 (Decrease) 2003 2002 (Decrease)
- ----------------------------------- ------------ ------------ -------------- ------------- ------------ --------------
Gas (after Hedging) $38,934 $39,335 $(401) $116,682 $111,244 $5,438
Oil (after Hedging) 34,244 43,823 (9,579) 111,740 112,633 (893)
Gas Processing Plant 7,518 4,356 3,162 22,090 11,918 10,172
Other 922 578 344 601 6,554 (5,953)
Intrasegment Elimination(1) (5,866) (4,013) (1,853) (17,378) (10,066) (7,312)
- ----------------------------------- ------------ ------------ -------------- ------------- ------------ --------------
$75,752 $84,079 $(8,327) $233,735 $232,283 $1,452
- ----------------------------------- ------------ ------------ -------------- ------------- ------------ --------------
(1) Represents the elimination of certain West Coast gas production revenue included in "Gas (after Hedging)" in the
table above that is sold to the gas processing plant shown in the table above. An
elimination for the same dollar amount is made to reduce the gas processing plant's purchased gas expense.
- ----------------------------------------- --------------------------------------- ----------------------------------------
Production Volumes Three Months Ended Nine Months Ended
June 30, June 30,
- ----------------------------------------- ---------- ------------ --------------- ------------ ------------ --------------
Increase/ Increase/
2003 2002 (Decrease) 2003 2002 (Decrease)
- ----------------------------------------- ---------- ------------ --------------- ------------ ------------ --------------
Gas Production (MMcf)
Gulf Coast 4,280 6,779 (2,499) 14,839 19,576 (4,737)
West Coast 1,081 1,211 (130) 3,382 3,654 (272)
Appalachia 1,448 1,108 340 3,836 3,309 527
Canada 1,249 1,447 (198) 4,280 5,088 (808)
- ----------------------------------------- ---------- ------------ --------------- ------------ ------------ --------------
8,058 10,545 (2,487) 26,337 31,627 (5,290)
- ----------------------------------------- ---------- ------------ --------------- ------------ ------------ --------------
Oil Production (thousands of barrels)
Gulf Coast 330 519 (189) 1,121 1,411 (290)
West Coast 712 759 (47) 2,179 2,255 (76)
Appalachia 3 2 1 7 4 3
Canada 573 703 (130) 1,817 2,191 (374)
- ----------------------------------------- ---------- ------------ --------------- ------------ ------------ --------------
1,618 1,983 (365) 5,124 5,861 (737)
- ----------------------------------------- ---------- ------------ --------------- ------------ ------------ --------------
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations (Cont.)
Average Prices
- ----------------------------------------- --------------------------------------- ----------------------------------------
Three Months Ended Nine Months Ended
June 30, June 30,
- ----------------------------------------- --------------------------------------- ----------------------------------------
Increase/ Increase/
2003 2002 (Decrease) 2003 2002 (Decrease)
- ----------------------------------------- ----------- ----------- --------------- ------------ ------------ --------------
Average Gas Price/Mcf
Gulf Coast $5.52 $3.37 $2.15 $5.42 $2.74 $2.68
West Coast $5.30 $3.35 $1.95 $5.01 $2.68 $2.33
Appalachia $5.98 $3.75 $2.23 $4.92 $3.75 $1.17
Canada $5.55 $3.04 $2.51 $4.81 $2.32 $2.49
Weighted Average $5.58 $3.36 $2.22 $5.19 $2.77 $2.42
Weighted Average After
Hedging $4.83 $3.73 $1.10 $4.43 $3.52 $0.91
Average Oil Price/bbl
Gulf Coast $28.02 $24.92 $3.10 $29.23 $21.59 $7.64
West Coast $24.44 $22.56 $1.88 $26.08 $18.37 $7.71
Appalachia $30.51 $23.31 $7.20 $28.79 $22.99 $5.80
Canada $25.36 $23.24 $2.12 $26.19 $18.28 $7.91
Weighted Average $25.51 $23.42 $2.09 $26.81 $19.12 $7.69
Weighted Average After
Hedging $21.16 $22.10 $(0.94) $21.81 $19.22 $2.59
- ----------------------------------------- ----------- ----------- --------------- ------------ ------------ --------------
Operating revenues for the Exploration and Production segment decreased $8.3 million for the quarter ended June 30, 2003 as compared with the quarter ended June 30, 2002. Oil production revenue after hedging decreased $9.6 million due to lower weighted average prices after hedging ($0.94 per bbl), combined with a 365,000 barrel decline in production. Gas production revenue after hedging decreased $0.4 million due primarily to a decrease in gas production (2,487 MMcf) offset partly by an increase in the weighted average price of gas after hedging ($1.10 per Mcf) received for this production. Most of the decline in gas production occurred in the Gulf Coast of Mexico (a 2,499 MMcf decline). The Company had anticipated some of this decline in gas and oil production due to its plan to phase out of the Gulf Coast region. Other factors in the overall production decrease included an outside-operated offshore pipeline leak that required four key producing blocks to be shut-in for ten days, and a decline in drilling activity in Canada related to a decision to sell the Company’s Southeast Saskatchewan oil properties, which is discussed further below. Gas processing plant revenues increased $3.2 million due to significantly higher gas prices (because there is a similar increase in purchased gas expense, the impact on earnings is insignificant).
Operating revenues for the Exploration and Production segment increased $1.5 million for the nine months ended June 30, 2003 as compared with the nine months ended June 30, 2002. Oil production revenue after hedging decreased $0.9 million due to a 737,000 barrel decline in production offset partly by higher weighted average prices after hedging ($2.59 per barrel). Gas production revenue after hedging increased $5.4 million. Increases in the weighted average price of gas after hedging ($0.91 per Mcf) more than offset an overall decrease in gas production. Most of the decrease in gas production occurred in the Gulf Coast of Mexico (a 4,737 MMcf decline). As discussed above, the plan to phase out of the Gulf Coast region, the shut-in of production due to an offshore pipeline leak, and lower drilling activity in Canada contributed to this decrease in oil and gas production. Also, earlier in the year certain
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations (Cont.)
production in the Gulf Coast region was shut-in during Hurricane Lili and some of those wells have not returned to pre-hurricane production levels. Gas processing plant revenues increased $10.2 million due to significantly higher gas prices (because there is a similar increase in purchased gas expense, the impact on earnings is insignificant). For the nine months ended June 30, 2002, positive mark-to-market adjustments on derivative financial instruments amounted to $3.4 million. For the nine months ended June 30, 2003, the Exploration and Production segment experienced negative mark-to-market adjustments on derivative financial instruments of $1.6 million. This change in mark-to-market adjustments was the main reason for a $6.0 million decrease in other revenues.
The Exploration and Production segment experienced a loss of $15.4 million for the quarter ended June 30, 2003, a decrease of $26.6 million when compared with earnings of $11.2 million for the quarter ended June 30, 2002. As previously discussed, during the quarter ended June 30, 2003, the Exploration and Production segment recorded an after tax impairment charge of $22.6 million related to its Canadian oil and gas assets. Lower oil and gas production also contributed to the earnings decrease. Another factor was $1.3 million of income recorded in the quarter ended June 30, 2002 associated with the reversal of a portion of a reserve for the Company’s exposure to Enron Corp.
The Exploration and Production segment’s earnings for the nine months ended June 30, 2003 were $7.0 million, a decrease of $14.4 million when compared with earnings of $21.4 million for the nine months ended June 30, 2002. As discussed above, the after tax impairment charge of $22.6 million was the main reason for the earnings decrease. Higher production revenues, due mostly to a dramatic increase in crude oil and natural gas prices, partially offset the impairment. Also, the nine months ended June 30, 2002 included a net $0.9 million charge recorded to reserve for the Company’s exposure to Enron Corp.
In July 2003, Seneca entered into a purchase and sale agreement to sell its Southeast Saskatchewan oil properties in Canada for approximately $80 million. This sale is expected to close by September 30, 2003.* When the transaction closes, the Company expects to record an after tax loss on the sale in the range of $50 million to $60 million.*
The Company estimates that Seneca’s fiscal 2004 natural gas and oil production will be approximately 57 to 62 billion cubic feet equivalent (BCFE).
International
International Operating Revenues
- -------------------------------------- ------------------------------------------- -------------------------------------------
Three Months Ended Nine Months Ended
June 30, June 30,
- -------------------------------------- ------------------------------------------- -------------------------------------------
Increase/ Increase/
(Thousands) 2003 2002 (Decrease) 2003 2002 (Decrease)
- -------------------------------------- ------------- ------------- -------------- ------------- ------------- ---------------
Heating $10,182 $10,091 $91 $75,055 $59,181 $15,874
Electricity 6,294 6,723 (429) 24,326 21,372 2,954
Other 772 740 32 2,638 2,184 454
- -------------------------------------- ------------- ------------- --------------- ------------- ------------- ---------------
$17,248 $17,554 $(306) $102,019 $82,737 $19,282
- -------------------------------------- ------------- ------------- --------------- ------------- ------------- ---------------
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations (Cont.)
International Heating and Electric Volumes
- -------------------------------------- ------------------------------------------- -------------------------------------------
Three Months Ended Nine Months Ended
June 30, June 30,
- -------------------------------------- ------------- ------------- --------------- ------------- ------------- ---------------
Increase/ Increase/
2003 2002 (Decrease) 2003 2002 (Decrease)
- -------------------------------------- ------------- ------------- --------------- ------------- ------------- ---------------
Heating Sales (Gigajoules) (1) 1,144,220 1,251,064 (106,844) 8,203,420 8,016,670 186,750
Electricity Sales
(megawatt hours) 203,582 238,417 (34,835) 800,630 789,002 11,628
- -------------------------------------- ------------- ------------- --------------- ------------- ------------- ---------------
(1) Gigajoules = one billion joules. A joule is a unit of energy.
Operating revenues for the International segment decreased $0.3 million for the quarter ended June 30, 2003 as compared with the quarter ended June 30, 2002. Warmer weather was the main reason for the revenue decrease. Boilers used to generate heat serve as a source for generating electricity. Due to the warm weather, the boilers were not running as much as they were in the prior year's quarter, resulting in lower heating volumes and electric volumes. Most of this impact was offset, however, by a significant improvement in the Czech Koruna (CZK) compared to the U.S. dollar.
Operating revenues for the International segment increased $19.3 million for the nine months ended June 30, 2003 as compared with the nine months ended June 30, 2002. Colder weather was the main reason for the increase in revenues. Operating revenues also benefited from a significant improvement in the CZK compared to the U.S. dollar.
The International segment's loss for the quarter ended June 30, 2003 was basically flat with the quarter ended June 30, 2002. Lower heat and electric margins due to warmer weather were largely offset by lower project development costs.
The International segment recorded a loss of $3.4 million for the nine months ended June 30, 2003 compared to earnings of $1.5 million in the nine months ended June 30, 2002. This decrease can be attributed primarily to an $8.3 million reduction to earnings, representing the cumulative effect of a change in accounting for goodwill. The Company's goodwill balance as of October 1, 2002 totaled $8.3 million and was related to the Company's investments in the Czech Republic, which are included in the International segment. In accordance with SFAS 142, the Company stopped amortization of goodwill and tested its goodwill for impairment as of October 1, 2002. In accordance with SFAS 142, this impairment was reported as a cumulative effect of a change in accounting in the quarter ended December 31, 2002. Partially offsetting the negative impact of the impairment, earnings benefited from colder weather, higher heating service rates and an increase in the value of the CZK compared to the U.S. dollar.
Item 2.Management’s Discussion and Analysis of Financial Condition and Results of Operations (Cont.)
Energy Marketing
Energy Marketing Operating Revenues
- ----------------------------------- -------------------------------------------- ----------------------------------------
Three Months Ended Nine Months Ended
June 30, June 30,
- ----------------------------------- ------------- -------------- --------------- ------------ ------------ --------------
Increase/ Increase/
(Thousands) 2003 2002 (Decrease) 2003 2002 (Decrease)
- ----------------------------------- ------------- -------------- --------------- ------------ ------------ --------------
Natural Gas (after Hedging) $93,910 $42,406 $51,504 $262,444 $127,422 $135,022
Other 56 62 (6) 98 (33) 131
- ----------------------------------- ------------- -------------- --------------- ------------ ------------ --------------
$93,966 $42,468 $51,498 $262,542 $127,389 $135,153
- ----------------------------------- ------------- -------------- --------------- ------------ ------------ --------------
Energy Marketing Volumes
- ----------------------------------- -------------------------------------------- ----------------------------------------
Three Months Ended Nine Months Ended
June 30, June 30,
- ----------------------------------- ------------- -------------- --------------- ----------- ------------- --------------
Increase/ Increase/
2003 2002 (Decrease) 2003 2002 (Decrease)
- ----------------------------------- ------------- -------------- --------------- ----------- ------------- --------------
Natural Gas - (MMcf) 11,945 8,975 2,970 38,607 27,950 10,657
- ----------------------------------- ------------- -------------- --------------- ----------- ------------- --------------
Operating revenues for the Energy Marketing segment increased $51.5 million and $135.2 million, respectively, for the quarter and nine months ended June 30, 2003, as compared with the quarter and nine months ended June 30, 2002. These increases primarily reflect higher gas sales revenue due to the increased price of natural gas. The increases also reflect an increase in volumes as a result of the addition of several high volume customers and colder weather, primarily in the first and second quarters of 2003, in western New York and northwestern Pennsylvania.
Earnings in the Energy Marketing segment decreased $2.5 million and $0.8 million, respectively, for the quarter and nine months ended June 30, 2003 as compared with the quarter and nine months ended June 30, 2002. These decreases primarily reflect lower margins on gas sales, primarily due to end of winter local distribution company operational constraints, combined with price volatility and weather related demand swings.
Timber
Timber Operating Revenues
- ------------------------------- ------------------------------------------- ---------------------------------------------
Three Months Ended Nine Months Ended
June 30, June 30,
- ------------------------------- -------------- ------------- -------------- --------------- ------------- ---------------
Increase/ Increase/
(Thousands) 2003 2002 (Decrease) 2003 2002 (Decrease)
- ------------------------------- -------------- ------------- -------------- --------------- ------------- ---------------
Log Sales $3,601 $5,642 $(2,041) $22,051 $16,645 $5,406
Green Lumber Sales 1,137 1,476 (339) 4,699 5,114 (415)
Kiln Dry Lumber Sales 6,324 4,021 2,303 15,634 11,159 4,475
Other 193 925 (732) 741 1,376 (635)
- ------------------------------- -------------- ------------- -------------- --------------- ------------- ---------------
Operating Revenues $11,255 $12,064 $(809) $43,125 $34,294 $8,831
- ------------------------------- -------------- ------------- -------------- --------------- ------------- ---------------
Item 2.Management’s Discussion and Analysis of Financial Condition and Results
of Operations (Cont.)
Timber Board Feet
- ------------------------------- ------------------------------------------- ---------------------------------------------
Three Months Ended Nine Months Ended
June 30, June 30,
- ------------------------------- -------------- ------------- -------------- --------------- ------------- ---------------
Increase/ Increase/
(Thousands) 2003 2002 (Decrease) 2003 2002 (Decrease)
- ------------------------------- -------------- ------------- -------------- --------------- ------------- ---------------
Log Sales 1,091 1,794 (703) 6,828 6,221 607
Green Lumber Sales 2,296 3,146 (850) 9,312 9,812 (500)
Kiln Dry Lumber Sales 3,766 2,841 925 9,847 7,771 2,076
- ------------------------------- -------------- ------------- -------------- --------------- ------------- ---------------
7,153 7,781 (628) 25,987 23,804 2,183
- ------------------------------- -------------- ------------- -------------- --------------- ------------- ---------------
Operating revenues for the Timber segment decreased $0.8 million for the quarter ended June 30, 2003, as compared with the quarter ended June 30, 2002. The decrease for the quarter can largely be attributed to lower sales of cherry veneer logs which command higher than average prices. Also, the quarter ended June 30, 2002 included a gain of $0.7 million on the sale of standing timber. This gain is reflected in other revenues in the table above.
Operating revenues for the Timber segment increased $8.8 million for the nine months ended June 30, 2003, as compared with the nine months ended June 30, 2002. The increase can largely be attributed to higher sales of cherry veneer logs which command higher than average prices. Higher kiln dry lumber sales also contributed to the increase.
The Timber segment’s earnings for the quarter ended June 30, 2003 were $1.0 million, a decrease of $1.7 million when compared with earnings of $2.7 million for the quarter ended June 30, 2002. The decrease is primarily due to lower margins resulting from lower sales of cherry veneer logs, which command higher than average margins. The decrease in log sales was mostly a result of lower timber harvesting. The decision to harvest less was partly made in anticipation of the Company’s August 1, 2003 sale of approximately 70,000 acres of timber property, which is discussed below under “Capital Resources and Liquidity – Investing Cash Flow-Timber.” The wet weather experienced during the quarter ended June 30, 2003 also restricted the Company’s ability to harvest its timber properties.
The Timber segment’s earnings for the nine months ended June 30, 2003 were $8.7 million, an increase of $2.7 million when compared with earnings of $6.0 million for the nine months ended June 30, 2002. The increase is primarily due to higher margins resulting from higher sales of cherry veneer logs and lumber during the first two quarters of 2003, partially offset by the factors discussed above for the third quarter.
The Company’s unconsolidated subsidiaries consist of equity method investments in Seneca Energy II, LLC, (Seneca Energy), Model City Energy, LLC (Model City), and Energy Systems North East, LLC (ESNE). The Company has 50% ownership interests in each of these entities. In each case, the other 50% ownership interests are held by single entities. Seneca Energy and Model City generate and sell electricity using methane gas obtained from landfills owned by outside parties. ESNE generates electricity from an 80-megawatt, combined cycle, natural gas-fired power plant in North East, Pennsylvania. ESNE sells its electricity into the New York power grid. The Company, in its Pipeline and
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations (Cont.)Storage segment, also had a 33-1/3% equity method investment in Independence Pipeline Company which was written off in the quarter ended June 30, 2002. The Independence write-off of $15.2 million ($9.9 million after tax) is recorded on the Consolidated Statement of Income as Impairment of Investment in Partnership.
The loss from unconsolidated subsidiaries decreased $0.1 million for the quarter ended June 30, 2003 compared with the quarter ended June 30, 2002. This improvement can largely be attributed to increases in income from the Company’s investments in Seneca Energy and Model City.
Income (Loss) from unconsolidated subsidiaries increased $0.9 million for the nine months ended June 30, 2003 compared with the nine months ended June 30, 2002. This increase is largely attributable to increases in income from the Company’s investments in Seneca Energy and Model City.
Interest on long-term debt was flat for the quarter ended June 30, 2003 as compared with the quarter ended June 30, 2002. Higher average amounts of long-term debt outstanding were largely offset by lower weighted average interest rates.
Interest on long-term debt increased $1.5 million for the nine months ended June 30, 2003 as compared with the nine months ended June 30, 2002. The increase can be attributed primarily to higher average amounts of long-term debt outstanding which more than offset lower weighted average interest rates.
Other interest charges decreased $0.2 million and $2.6 million, respectively, for the quarter and nine months ended June 30, 2003 as compared with the quarter and nine months ended June 30, 2002. These decreases resulted mainly from lower weighted average interest rates.
The Company’s primary sources of cash during the nine-month period ended June 30, 2003 consisted of cash provided by operating activities and long-term debt. These sources were supplemented by issuances of common stock under the Company’s stock and benefit plans.
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 depreciation, depletion and amortization, deferred income taxes, impairment of oil and gas properties, impairment of investment in partnership, income or loss from unconsolidated subsidiaries net of cash distributions, and minority interest in foreign subsidiaries.
Cash provided by operating activities in the Utility and the Pipeline and Storage segments may vary 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 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 straight fixed-variable rate design.
Item 2.Management’s Discussion and Analysis of Financial Condition and Results of Operations (Cont.)Because of the seasonal nature of the heating business in the Utility, Energy Marketing and International segments, revenues in these segments are relatively high during the heating season, primarily the first and second quarters of the fiscal year, and receivables historically increase during these periods from what was receivable at September 30.
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 Statements of Income and a reserve for gas replacement is recorded in the Consolidated Balance Sheets and is included under the caption “Other Accruals and Current Liabilities.” Such reserve is reduced as the inventory is replenished.
Cash provided by operating activities in the Exploration and Production segment may vary from period to period as a result of changes in the commodity prices of natural gas and crude oil. The Company uses various derivative financial instruments, including price swap agreements, no cost collars and options in an attempt to manage this energy commodity price risk.
Net cash provided by operating activities totaled $317.8 million for the nine months ended June 30, 2003, an increase of $12.8 million compared with $305.0 million provided by operating activities for the nine months ended June 30, 2002. Higher cash receipts from the sale of oil and gas in the Exploration and Production segment and lower working capital requirements in the International segment were the main contributors to this increase. Higher working capital requirements in the Energy Marketing segment partially offset this increase.
Expenditures for long-lived assets include additions to property, plant and equipment (capital expenditures) and investments in corporations (stock acquisitions) or partnerships, net of any cash acquired.
The Company’s expenditures for long-lived assets totaled $326.1 million during the nine months ended June 30, 2003. The table below presents these expenditures:
- --------------------------------------------- --- ---------------- --------------------- -----------------------------
Nine Months Ended June 30, 2003
(in millions of dollars)
- --------------------------------------------- --- ---------------- --------------------- -----------------------------
Investments in Total
Capital Corporations Expenditures for
Expenditures And Partnerships Long-Lived Assets
- --------------------------------------------- --- ---------------- --------------------- --------------------------
Utility $36.0 $ - $36.0
Pipeline and Storage 13.6 181.2 (1) 194.8
Exploration and Production 43.3 - 43.3
International 1.7 - 1.7
Timber 1.7 - 0.2
All Other - 48.1 48.1
Corporate 0.3 - 0.3
- --------------------------------------------- --- ---------------- --------------------- --------------------------
Corporate $96.8 $229.3 $326.1
- --------------------------------------------- --- ---------------- --------------------- --------------------------
(1) Investment amount is net of $8.0 million of cash acquired.
Item 2.Management’s Discussion and Analysis of Financial Condition and Results
of Operations (Cont.)
Utility
The majority 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 StorageThe majority of the Pipeline and Storage capital expenditures were made for additions, improvements, and replacements to this segment's transmission and storage systems.
On February 6, 2003, the Company acquired the Empire State Pipeline (Empire) from a subsidiary of Duke Energy Corporation for $189.2 million in cash (including cash acquired) plus $57.8 million of project debt. The acquisition, which was made through Highland (a direct subsidiary having timber property and sawmill operations in New York and Pennsylvania), consisted of acquiring 100% of two companies. Each of these companies has 50% ownership of Empire, which is a joint venture. Empire's results of operations were incorporated into the Company's consolidated financial statements for the period subsequent to the completion of the acquisition on February 6, 2003. Empire is a 157-mile, 24-inch pipeline that begins at the United States/Canadian border at the Chippawa Channel of the Niagara River near Buffalo, New York, which is within the Company's service territory, and terminates in Central New York just north of Syracuse, New York. Empire can transport 525 million cubic feet of gas per day and currently has almost all of its capacity under contract, with a substantial portion being long-term contracts. Empire delivers natural gas supplies to major industrial companies, utilities (including the Company's Utility segment) and power producers. Empire better positions the Company to bring Canadian gas supplies into the East Coast markets of the United States as demand for natural gas along the East Coast increases.* The initial financing of the acquisition was accomplished through short-term borrowings. These short-term borrowings were repaid when the Company completed the sale of 70,000 acres of timber property on August 1, 2003. The sale of this timber property is discussed below under "Timber."
The Company also continues to explore various opportunities to expand its capabilities to transport gas to the East Coast, either through the Supply Corporation or Empire systems or in partnership with others. This includes the proposed Northwinds Pipeline that the Company and TransCanada PipeLines Limited are pursuing. This project would be a 215-mile, 30-inch natural gas pipeline that would originate in Kirkwall, Ontario, cross into the United States near Buffalo, New York and follow a southerly route to its destination in the Ellisburg-Leidy area in Pennsylvania.* The Company did not incur any material costs associated with this project during the nine months ended June 30, 2003. The initial capacity of the pipeline would be approximately 500 million cubic feet of natural gas per day with the estimated cost of the pipeline ranging from $350-$400 million.* If the pipeline is constructed, it is possible that a significant amount of the construction costs would be financed by banks or other financial institutions with the pipeline serving as collateral for the financing arrangement.*
Exploration and ProductionThe Exploration and Production segment capital expenditures for the nine months ended June 30, 2003 included approximately $34.7 million for on-shore drilling construction and recompletion costs for wells located in Louisiana, Texas, California and Canada as well as onshore geological and geophysical costs and fixed asset purchases. Of the $34.7 million amount, $22.1 million was spent on the Exploration and Production segment's Canadian properties. The Exploration and Production segment's capital expenditures also included approximately $8.6 million for Seneca's offshore program in the Gulf of
Item 2.Management’s Discussion and Analysis of Financial Condition and Results of Operations (Cont.)Mexico. The Company expects Exploration and Production segment capital expenditures for 2004 to be approximately $90 million.*
In July 2003, Seneca entered into a purchase and sale agreement to sell its Southeast Saskatchewan oil properties in Canada for approximately $80 million. This sale is expected to close by September 30, 2003.* When the transaction closes, the Company expects to record an after tax loss on the sale in the range of $50 million to $60 million.* It is anticipated that the after-tax proceeds from the sale will be used to repay short-term borrowings.*
InternationalThe majority of the International segment capital expenditures were concentrated in improvements and replacements within the district heating and power generation plants in the Czech Republic.
TimberThe majority of the Timber segment capital expenditures were made for purchases of land and timber for Seneca's timber operations, as well as equipment for Highland's sawmill and kiln operations.
As discussed above, the Company announced in March 2003 that its timber subsidiary, Highland, signed a purchase agreement to sell approximately 70,000 acres of its timber property located in various counties in Pennsylvania and Allegany County in New York. This sale was completed on August 1, 2003 for a sale price of approximately $186.3 million. The Company will be recording a pre-tax gain on this sale of approximately $167.0 million during the quarter ended September 30, 2003.* The Company used the proceeds from this sale to repay short-term borrowings in connection with the Empire acquisition.
All OtherOn June 3, 2003, the Company acquired for approximately $47.7 million in cash all of the partnership interests in Toro Partners, L.P. (Toro), a Dallas, Texas-based company, which owns and operates eight short-distance landfill gas pipeline companies that purchase, transport and resell landfill gas to customers in six Midwestern states in the United States. The financing of the acquisition was accomplished through short-term borrowings.
In May 2003, the Company and its partner each made an equity contribution of $0.4 million into Seneca Energy. The Company financed its contribution by reinvesting a distribution from Seneca Energy. This represents the Company's 50% equity interest in the construction of a 3.2 megawatt electric generation facility at the Ontario County Landfill in Ontario County, New York. Construction is anticipated to be complete in September 2003 for a total cost of $3.4 million.* Of the total project cost, $2.6 million will be financed by a bank with the equipment at the facility serving as collateral for the financing arrangement.*
The Company continuously evaluates capital expenditures and investments in corporations and partnerships. The amounts are subject to modification for opportunities such as the acquisition of attractive oil and gas properties, timber 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 or other investments in the Company's other business segments depends, to a large degree, upon market conditions.*
Financing Cash Flow.In February 2003, the Company issued $250.0 million of 5.25% long-term notes due in March 2013. After deducting underwriting discounts and commissions, the net proceeds to the Company amounted to approximately $248.5 million. The proceeds of this debt issuance were used to refund $150.0 million of
Item 2.Management’s Discussion and Analysis of Financial Condition and Results of Operations (Cont.)7.30% medium-term notes which matured in February 2003. The remaining proceeds were used to reduce short-term borrowings.
In March 2003, the Company redeemed $50.0 million of 8.48% medium-term notes at a redemption price of $52.5 million. The Company also redeemed $2.3 million of 6.214% medium-term notes in March 2003 at a redemption price of $2.25 million. The Company used short-term borrowings to redeem this debt.
Consolidated short-term debt increased $56.2 million during the nine months ended June 30, 2003. The temporary use of short-term debt to finance the acquisition of Empire was the main reason for this increase. As discussed above, the Company used the proceeds from the sale of timber properties, which was completed on August 1, 2003, to repay short-term debt incurred in connection with the Empire acquisition. The Company continues to consider short-term debt an important source 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. Fluctuations in these items can have a significant impact on the amount and timing of short-term debt. The Company has Securities and Exchange Commission (SEC) authorization under the Public Utility Holding Company Act of 1935, as amended, to borrow and have outstanding as much as $750.0 million of short-term debt at any time through December 31, 2005. The total amount available to be issued under the Company's commercial paper program is $200.0 million. The commercial paper program is backed by a committed $220 million, 364-day/3-year credit facility. Under this committed credit facility, the Company has agreed that its debt to capitalization ratio will not at the last day of any fiscal quarter, exceed .65 from September 30, 2002 through September 30, 2003, .625 from October 1, 2003 through September 30, 2004 and .60 from October 1, 2004 and thereafter. At June 30, 2003, the Company's debt to capitalization ratio was .60. Given the constraints specified in the committed credit facility, the issuance of an additional $145.0 million and $74.0 million in short-term and/or long-term debt would bring the Company's debt to capitalization ratio to .65 and .625, respectively. With regards to the Company's short-term notes payable to banks, the Company utilizes uncommitted bank lines of credit aggregating to $415.0 million. These uncommitted bank lines of credit are revocable at the option of the financial institutions and are reviewed on an annual basis. The Company anticipates that these lines of credit will continue to be renewed.* If a downgrade in any of the Company's credit ratings were to occur, access to the commercial paper markets might not be possible.* However, the Company expects that it could borrow under its uncommitted bank lines of credit or rely upon other liquidity sources, including cash provided by operations.* At June 30, 2003, the Company had outstanding short-term notes payable to banks and commercial paper of $152.3 million and $169.3 million, respectively.
The Company's present liquidity position is believed to be adequate to satisfy known demands.* Under the Company's existing indenture covenants, at June 30, 2003, the Company would have been permitted to issue up to a maximum of $301.0 million in additional long-term unsecured indebtedness at then current market interest rates (further limited by the debt to capitalization ratio constraints noted in the previous paragraph) in addition to being able to issue new indebtedness to replace maturing debt.
The Company's indenture pursuant to which $624 million (or 45%) of the Company's long-term debt (as of June 30, 2003) was issued contains a cross-default provision whereby the failure by the Company to perform certain obligations under other borrowing arrangements could trigger an obligation to repay the debt outstanding under the indenture. In particular, a repayment obligation could be triggered if the Company fails (i) to pay any scheduled principal or interest on any debt under any other indenture or agreement or (ii) to perform any other term in any other such indenture or agreement, and the effect of the failure causes, or would permit the holders of the debt to cause, the debt to become due prior to its stated maturity.
The Company's committed $220 million, 364-day/3-year credit facility also contains a cross-default provision whereby the failure by the Company or its significant subsidiaries to make payments under other borrowing arrangements, or the occurrence of certain events affecting those other borrowing arrangements, could trigger an obligation to repay any amounts outstanding under the committed credit facility. In particular, a repayment obligation could be triggered if (i) the Company or its significant subsidiaries fail to make a payment when due of any principal or interest on any other indebtedness aggregating $20 million or more or (ii) an event occurs that causes, or would permit the holders of such indebtedness to cause, such indebtedness to become due prior to its stated maturity. As of June 30, 2003, the Company had no debt outstanding under the committed credit facility.
Item 2.Management’s Discussion and Analysis of Financial Condition and Results of Operations (Cont.)The Company also has authorization from the SEC, under the Public Utility Holding Company Act of 1935, to issue long-term debt securities and equity securities in amounts not exceeding $1.5 billion at any one time outstanding during the order's authorization period, which extends to December 31, 2005. In January 2003, the Company registered $800 million of debt and equity securities under the Securities Act of 1933. After the February 2003 debt issuance discussed above, the Company has available capacity to issue an additional $550 million of debt and equity securities registered under the Securities Act of 1933. The Company may sell all or a portion of the remaining registered securities if warranted by market conditions and the Company's capital requirements. Any offer and sale of the above mentioned $550 million of debt and equity securities will be made only by means of a prospectus meeting the requirements of the Securities Act of 1933 and the rules and regulations thereunder.
The Company has entered into certain off-balance sheet financing arrangements. These financing arrangements are primarily operating and capital leases. The Company's consolidated subsidiaries have operating leases, the majority of which are with the Utility and the Pipeline and Storage segments, having a remaining lease commitment of approximately $30.4 million. These leases have been entered into for the use of vehicles, construction tools, meters, computer equipment and other items and are accounted for as operating leases. The Company's minority owned entities, which are accounted for under the equity method, have capital leases of electric generating equipment having a remaining lease commitment of approximately $10.6 million. The Company has guaranteed 50% or $5.3 million of these capital lease commitments.
The following table summarizes the Company's expected future contractual cash obligations as of June 30, 2003, and the twelve-month periods over which they occur:
- ------------------------------ -----------------------------------------------------------------------------------------------
Payments by Expected Maturity Dates
-----------------------------------------------------------------------------------------------
------------ ----------- ------------ ------------ -------------- -------------- --------------
2003- 2004 - 2005 - 2006 - 2007 -
(Millions of Dollars) 2004 2005 2006 2007 2008 Thereafter Total
- ------------------------------ ------------ ----------- ------------ ------------ -------------- -------------- --------------
Long-Term Debt $141.7 $115.3 $13.9 $10.5 $209.3 $903.0 $1,393.7
Short-Term Bank Notes $152.3 $ - $ - $ - $ - $ - $152.3
Commercial Paper $169.3 $ - $ - $ - $ - $ - $169.3
Operating Lease
Commitments $7.7 $6.3 $4.8 $3.6 $2.9 $5.1 $30.4
Capital Lease
Commitments $0.8 $0.9 $1.0 $0.8 $0.6 $1.2 $5.3
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The Company has made certain other guarantees on behalf of its subsidiaries. The guarantees relate primarily to: (i) obligations under derivative financial instruments, which are included on the consolidated balance sheet in accordance with SFAS 133 (see Item 2, MD&A under the headings “Critical Accounting Policies” and “Accounting for Derivative Financial Instruments”); (ii) Utility segment obligations to purchase gas to be resold in its regulated business in accordance with established regulatory mechanisms to pass through the cost of that gas to its retail customers; (iii) NFR obligations to purchase gas or to purchase gas transportation/storage services where the amounts actually due on those obligations each month are included on the consolidated balance sheet as a current liability; and (iv) other obligations which are reflected on the consolidated balance sheet. The Company believes that the likelihood it would be required to make payments under the guarantees is remote, and therefore has not included them on the table above.*
Item 2.Management’s Discussion and Analysis of Financial Condition and Results of Operations (Cont.)The Company is involved in litigation arising in the normal course of business. Also in the normal course of business, the Company is involved in tax, regulatory and other governmental audits, inspections, investigations and other proceedings that involve state and federal taxes, safety, compliance with regulations, rate base, cost of service and purchased gas cost issues, among other things. While the resolution of such matters could have a material effect on earnings and cash flows in the year of resolution, none of these 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.*
For a complete discussion of market risk sensitive instruments, refer to “Market Risk Sensitive Instruments” in Item 7 of the Company’s 2002 Form 10-K. There have been no subsequent material changes to the Company’s exposure to market risk sensitive instruments.
Base rate adjustments 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 appropriate regulatory authorities.
On October 11, 2000, the NYPSC approved a settlement agreement (Agreement) between Distribution Corporation, Staff of the Department of Public Service, the New York State Consumer Protection Board and Multiple Intervenors (an advocate for large commercial and industrial customers) (collectively, “Parties”) that establishes rates for a three-year period beginning October 1, 2000. For a complete discussion of this Agreement, refer to “Rate Matters” in Item 7 of the Company’s 2002 Form 10-K. On July 25, 2003, the Parties and other interests executed a settlement agreement (“Settlement”) to extend the terms of the Agreement and Distribution Corporation’s restructuring plan one year commencing October 1, 2003. The Settlement proposes to continue existing base rates, and reduce the level above which earnings are shared 50/50 with customers from the current 11.5% return on equity to 11.0%. In addition, the Settlement proposes to increase the combined pension and other post employment benefit expense by $8 million, without a corresponding increase in revenues. Most other features of Distribution Corporation’s service remain largely unchanged. The Settlement has been submitted to an Administrative Law Judge for review prior to a decision by the NYPSC which is expected prior to September 30, 2003.*
On September 20, 2001, the NYPSC issued an order under which Distribution Corporation was directed to show cause why an action for penalties of $19 million should not be commenced against it for alleged violations of consumer protection requirements. According to the NYPSC and intervenors, the alleged violations may have caused or contributed to the death of an individual in an unheated apartment. On December 3, 2001, Distribution Corporation filed its response and requested that the NYPSC either close (dismiss) the Show Cause proceeding based on the evidence presented in Distribution’s response, or hold investigatory hearings “to demonstrate that a penalty action is unwarranted.” On July 25, 2002 the NYPSC issued an order granting Distribution Corporation’s request for hearings, and referred the matter to an administrative law judge for scheduling and other matters. The adoption of a procedural schedule has been adjourned because the major parties to the proceeding have begun settlement discussions. The Company believes and will continue to vigorously assert that the NYPSC’s allegations lack merit.
Item 2.Management’s Discussion and Analysis of Financial Condition and Results of Operations (Cont.)On April 16, 2003, Distribution Corporation filed a request with the Pennsylvania Public Utility Commission (PaPUC) to increase annual operating revenues by $16.5 million to cover increases in the cost of providing service, to be effective June 15, 2003. The PaPUC suspended the effective date according to the usual procedures, to January 15, 2004. Distribution Corporation filed this request for several reasons including increases in the costs associated with Distribution Corporation’s ongoing construction program as well as increases in uncollectible accounts and personnel expenses.
Supply Corporation currently does not have a rate case on file with the Federal Energy Regulatory Commission (FERC). Management will continue to monitor Supply Corporation’s financial position to determine the necessity of filing a rate case in the future.
On May 7, 2003, Supply Corporation entered into a Stipulation and Consent Agreement with the FERC Office of Market Oversight and Investigations to resolve the FERC investigation described in “Rate Matters” in Item 7 of the Company’s 2002 Form 10-K. On May 19, 2003, FERC issued an order approving the Stipulation and Consent Agreement. The settlement provides, among other things, that:
(i) Supply Corporation does not admit any violations of applicable laws or regulations;
(ii) Supply Corporation asserts that neither Supply nor any of its affiliates were unjustly enriched by, received a
competitive advantage, or otherwise profited from the alleged activities described in
the Stipulation and Consent Agreement, and that there was no ascertainable harm to
any shipper, potential shipper or the public;
(iii) FERC release any and all claims relating to the allegations described in the Stipulation and Consent Agreement;
(iv) Supply Corporation will implement fully and follow the three-year "Compliance Plan" attached to the Stipulation
and Consent Agreement, which plan requires the establishment of various internal
procedures, and various training, reviewing and reporting; and
(v) Supply Corporation will pay to the U.S. Treasury $0.3 million to cover the costs of the audit and investigation
(paid in June 2003).
Empire currently does not have a rate case on file with the NYPSC. Management will continue to monitor its financial position in the New York jurisdiction to determine the necessity of filing a rate case in the future.
The Company is subject to various federal, state and local laws and regulations (including those of the Czech Republic) relating to the protection of the environment. The Company has established procedures for the ongoing evaluation of its operations to identify potential environmental exposures and comply with
Item 2.Management’s Discussion and Analysis of Financial Condition and Results of Operations (Cont.)regulatory policies and procedures. It is the Company’s policy to accrue estimated environmental clean-up costs (investigation and remediation) when such amounts can reasonably be estimated and it is probable that the Company will be required to incur such costs. At June 30, 2003, the Company has estimated its remaining clean-up costs related to former manufactured gas plant sites and third party waste disposal sites will be in the range of $5.1 million to $6.1 million.* The minimum liability of $5.1 million has been recorded on the Consolidated Balance Sheet at June 30, 2003. Other than discussed in Note H of the 2002 Form 10-K (referred to below), the Company is currently not aware of any material additional exposure to environmental liabilities. However, adverse changes in environmental regulations or other factors could impact the Company.*
For further discussion refer to Note H - Commitments and Contingencies under the heading “Environmental Matters” in Item 8 of the Company’s 2002 Form 10-K.
During 2004, the Company anticipates settling a portion of a retirement plan's obligation for $23 million.* If the obligation is settled, generally accepted accounting principles will require the Company to recognize as expense approximately $8 million (after tax) of previously deferred actuarial losses associated with the plan.
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 Section 21E of the Securities Exchange Act of 1934 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 without limitation those which are designated with an asterisk (“*”), 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 statements:
The Company disclaims any obligation to update any forward-looking statements to reflect events or circumstances after the date hereof.
Refer to the "Market Risk Sensitive Instruments" section in Item 2 - Management's Discussion and Analysis of Financial Condition and Results of Operations.
Evaluation of disclosure controls and procedures
The term “disclosure controls and procedures” is defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934 (Exchange Act.) These rules refer to the controls and other procedures of a company that are designed to ensure that information required to be disclosed by a company in the reports that it files under the Exchange Act is recorded, processed, summarized and reported within required time periods. The Company’s management, including the Chief Executive Officer and Treasurer, evaluated the effectiveness of the Company’s disclosure controls and procedures as of the end of the period covered by this report. Based upon that evaluation, the Company’s Chief Executive Officer and Treasurer concluded that the Company’s disclosure controls and procedures were effective as of the period covered by this report.
Changes in internal controls over financial reporting
The Company maintains a system of internal control over financial reporting that is designed to provide reasonable assurance that the Company’s transactions are properly authorized, the Company’s assets are safeguarded against unauthorized or improper use, and the Company’s transactions are properly recorded and reported to permit preparation of the Company’s financial statements in conformity with GAAP. There were no changes in the Company’s internal control over financial reporting that occurred during the quarter covered by this report that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.
Part II. Other InformationIn an action instituted in the New York State Supreme Court, Chautauqua County on January 31, 2000 against Seneca, NFR and “National Fuel Gas Corporation,” Donald J. and Margaret Ortel and Brian and Judith Rapp, “individually and on behalf of all those similarly situated,” allege, in an amended complaint which adds National Fuel Gas Company as a party defendant that (a) Seneca underpaid royalties due under leases operated by it, and (b) Seneca’s co-defendants (i) fraudulently participated in and concealed such alleged underpayment, and (ii) induced Seneca’s alleged breach of such leases. Plaintiffs seek an accounting, declaratory and related injunctive relief, and compensatory and exemplary damages. Defendants have denied each of plaintiffs’ material substantive allegations and set up twenty-five affirmative defenses in separate verified answers.
A motion was made by plaintiffs on July 15, 2002 to certify a class comprising all persons presently and formerly entitled to receive royalties on the sale of natural gas produced and sold from wells operated in New York by Seneca (and its predecessor Empire Exploration, Inc). On December 23, 2002, the court granted certification of the proposed class, as modified to exclude those leaseholders whose leases provide for calculation of royalties based upon a flat fee, or flat fee per cubic foot of gas produced. The court’s order states that there are approximately 749 potential class members.
In an action instituted in the New York State Supreme Court, Kings County on February 18, 2003 against Distribution Corporation and Paul J. Hissin, an unaffiliated third party, plaintiff Donna Fordham-Coleman, as administratrix of the estate of Velma Arlene Fordham, alleges that Distribution Corporation’s denial of natural gas service in November 2000 to the plaintiff’s decedent, Velma Arlene Fordham, caused decedent’s death in February 2001. Plaintiff seeks damages for wrongful death and pain and suffering, plus punitive damages. Distribution Corporation has denied plaintiff’s material allegations, set up seven affirmative defenses in separate verified answers and filed a cross-claim against the co-
Item 1. Legal Proceedings (Concl.)defendant. Distribution Corporation believes and will vigorously assert that plaintiff's allegations lack merit. For a discussion of a related matter before the NYPSC, refer to Part I, Item 2 - MD&A of this report under the heading "Regulatory Matters."
The Company believes, based on the information presently known, that the ultimate resolution of these matters, individually or in the aggregate, will not be material to the consolidated financial condition, results of operations, or cash flow of the Company.* No assurances can be given, however, as to the ultimate outcomes of these matters, and it is possible that the outcomes, individually or in the aggregate, could be material to results of operations or cash flow for a particular quarter or annual period.*
For a discussion of various environmental matters, refer to Part I, Item 1 at Note 4 and Part I, Item 2 – MD&A of this report under the heading “Environmental Matters.”
The Company is involved in litigation arising in the normal course of business. Also in the normal course of business, the Company is involved in tax, regulatory and other governmental audits, inspections, investigations and other proceedings that involve state and federal taxes, safety, compliance with regulations, rate base, cost of service and purchased gas cost issues, among other things. While the resolution of such matters could have a material effect on earnings and cash flows in the year of resolution, none of these 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.*
On April 1, 2003, the Company issued a total of 2,400 unregistered shares of Company common stock to the eight non-employee directors of the Company, 300 shares to each such director. The shares were issued as partial consideration for the directors’ services during the quarter ended June 30, 2003, 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 transactions not involving a public offering.
(a) Exhibits
Exhibit
Number Description of Exhibit
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12 Statements regarding Computation of Ratios:
Ratio of Earnings to Fixed Charges for the Twelve Months Ended June 30, 2003 and the
Fiscal Years Ended September 30, 1998 through 2002.
31.1 Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2 Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
Item 6. Exhibits and Reports on Form 8-K (Concl.)
32 Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99 National Fuel Gas Company Consolidated Statement of Income for the
Twelve Months Ended June 30, 2003 and 2002.
(b) Reports on Form 8-K
A report on Form 8-K dated April 24, 2003 was filed on April 30, 2003 regarding a
press release issued by the Company concerning earnings for the quarter ended March
31, 2003 and a conference call on April 25, 2003. This information was filed under
Item 9, "Regulation FD Disclosure," and Item 12, "Results of Operations and Financial
Condition." An exhibit was filed under Item 7, "Financial Statements and Exhibits."
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, Principal Financial Officer
and Principal Accounting Officer
Date: August 14, 2003
EXHIBIT INDEX
(Form 10-Q)
Exhibit 12 Statements regarding Computation of Ratios:
Ratio of Earnings to Fixed Charges for the Twelve
Months Ended June 30, 2003 and the Fiscal Years Ended
September 30, 1998 through 2002
Exhibit 31.1 Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
Exhibit 31.2 Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
Exhibit 32 Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
Exhibit 99 National Fuel Gas Company Consolidated Statement of
Income for the Twelve Months Ended Juhe 30, 2003
and 2002