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, 2004
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.) |
| 6363 Main Street | 14221 |
| Williamsville, 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, 2004: 82,575,324 shares.
1
Company or Group of Companies for which Report is Filed:
| 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) | |
| Horizon LFG, Inc. (Horizon LFG) (the name was changed from Upstate Energy in April 2004) | |
| Horizon Power, Inc. (Horizon Power) |
INDEX
Part I. Financial Information2
. The Company has nothing to report under this item.
Reference 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.
3
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4
Part I. Financial Information
National Fuel Gas Company
Consolidated Statements of Income and Earnings
Reinvested in the Business
(Unaudited)
Three Months Ended
June 30,
(Thousands of Dollars, Except Per Common Share Amounts) 2004 2003
------------------ -----------------
INCOME
Operating Revenues $419,006 $449,530
- ------------------------------------------------------------------------------- ------------------ -----------------
Operating Expenses
Purchased Gas 174,907 212,863
Fuel Used in Heat and Electric Generation 12,918 10,820
Operation and Maintenance 92,469 90,635
Property, Franchise and Other Taxes 17,785 20,730
Depreciation, Depletion and Amortization 47,351 47,259
Impairment of Oil and Gas Producing Properties - 31,812
- ------------------------------------------------------------------------------- ------------------ -----------------
345,430 414,119
Adjustment of Gain on Sale of Timber Properties (1,252) -
- ------------------------------------------------------------------------------- ------------------ -----------------
Operating Income 72,324 35,411
Other Income (Expense):
Income (Loss) from Unconsolidated Subsidiaries 306 (39)
Other Income 2,078 1,070
Interest Expense on Long-Term Debt (20,379) (23,117)
Other Interest Expense (1,095) (2,833)
- ------------------------------------------------------------------------------- ------------------ -----------------
Income Before Income Taxes and
Minority Interest in Foreign Subsidiaries 53,234 10,492
Income Tax Expense 20,963 9,150
Minority Interest in Foreign Subsidiaries (292) (877)
- ------------------------------------------------------------------------------- ------------------ -----------------
Net Income Available for Common Stock 32,563 2,219
EARNINGS REINVESTED IN THE BUSINESS
Balance at April 1 724,855 626,161
- ------------------------------------------------------------------------------- ------------------ -----------------
757,418 628,380
Dividends on Common Stock
(2004 - $0.28 per share; 2003 - $0.27 per share) 23,036 21,884
- ------------------------------------------------------------------------------- ------------------ -----------------
Balance at June 30 $734,382 $606,496
=============================================================================== ================== =================
Earnings Per Common Share:
Basic $0.40 $0.03
=============================================================================== ================== =================
Diluted $0.39 $0.03
=============================================================================== ================== =================
Weighted Average Common Shares Outstanding:
Used in Basic Calculation 82,178,424 80,890,982
=============================================================================== ================== =================
Used in Diluted Calculation 83,119,373 81,914,060
=============================================================================== ================== =================
See Notes to Condensed Consolidated Financial Statements
5
Item 1. Financial Statements (Cont.)
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) 2004 2003
----------------- -----------------
INCOME
Operating Revenues $1,753,197 $1,738,302
- -------------------------------------------------------------------------------- ----------------- -----------------
Operating Expenses
Purchased Gas 871,593 870,034
Fuel Used in Heat and Electric Generation 58,027 52,970
Operation and Maintenance 312,335 285,491
Property, Franchise and Other Taxes 56,172 64,084
Depreciation, Depletion and Amortization 141,768 142,168
Impairment of Oil and Gas Producing Properties - 31,812
- -------------------------------------------------------------------------------- ----------------- -----------------
1,439,895 1,446,559
Adjustment of Gain on Sale of Timber Properties (1,252) -
Adjustment of Loss on Sale of Oil and Gas Producing Properties 4,645 -
- -------------------------------------------------------------------------------- ----------------- -----------------
Operating Income 316,695 291,743
Other Income (Expense):
Income from Unconsolidated Subsidiaries 403 489
Other Income 5,096 5,448
Interest Expense on Long-Term Debt (64,651) (69,741)
Other Interest Expense (4,830) (9,333)
- -------------------------------------------------------------------------------- ----------------- -----------------
Income Before Income Taxes and
Minority Interest in Foreign Subsidiaries 252,713 218,606
Income Tax Expense 90,503 87,062
Minority Interest in Foreign Subsidiaries 3,378 1,853
- -------------------------------------------------------------------------------- ----------------- -----------------
Income Before Cumulative Effect of Changes in Accounting 158,832 129,691
Cumulative Effect of Changes in Accounting - (8,892)
- -------------------------------------------------------------------------------- ----------------- -----------------
Net Income Available for Common Stock 158,832 120,799
EARNINGS REINVESTED IN THE BUSINESS
Balance at October 1 642,690 549,397
- -------------------------------------------------------------------------------- ----------------- -----------------
801,522 670,196
Dividends on Common Stock
(2004 - $0.82; 2003 - $0.79) 67,140 63,700
- -------------------------------------------------------------------------------- ----------------- -----------------
Balance at June 30 $734,382 $606,496
================================================================================ ================= =================
Earnings Per Common Share:
Basic:
Income Before Cumulative Effect of Changes in Accounting $1.94 $1.61
Cumulative Effect of Changes in Accounting - (0.11)
- -------------------------------------------------------------------------------- ----------------- -----------------
Net Income Available for Common Stock $1.94 $1.50
================================================================================ ================= =================
Diluted:
Income Before Cumulative Effect of Changes in Accounting $1.92 $1.60
Cumulative Effect of Changes in Accounting - (0.11)
- -------------------------------------------------------------------------------- ----------------- -----------------
Net Income Available for Common Stock $1.92 $1.49
================================================================================ ================= =================
Weighted Average Common Shares Outstanding:
Used in Basic Calculation 81,848,043 80,627,319
================================================================================ ================= =================
Used in Diluted Calculation 82,717,332 81,095,757
================================================================================ ================= =================
See Notes to Condensed Consolidated Financial Statements
6
Item 1. Financial Statements (Cont.)
National Fuel Gas Company
Consolidated Balance Sheets
(Unaudited)
June 30, September 30,
2004 2003
-------------------- -------------------
(Thousands of Dollars)
ASSETS
Property, Plant and Equipment $4,792,980 $4,657,343
Less - Accumulated Depreciation, Depletion
and Amortization 1,794,745 1,658,256
- ---------------------------------------------------------------------------- -------------------- -------------------
2,998,235 2,999,087
- ---------------------------------------------------------------------------- -------------------- -------------------
Current Assets
Cash and Temporary Cash Investments 76,912 51,421
Receivables - Net of Allowance for Uncollectible Accounts of
$19,664 and $17,943, Respectively 209,840 136,532
Unbilled Utility Revenue 17,882 20,568
Gas Stored Underground 23,500 89,640
Materials and Supplies - at average cost 42,709 32,311
Unrecovered Purchased Gas Costs 1,076 28,692
Prepayments 29,618 43,225
Fair Value of Derivative Financial Instruments - 1,698
- ---------------------------------------------------------------------------- -------------------- -------------------
401,537 404,087
- ---------------------------------------------------------------------------- -------------------- -------------------
Other Assets
Recoverable Future Taxes 84,818 84,818
Unamortized Debt Expense 20,034 22,119
Other Regulatory Assets 65,357 49,616
Deferred Charges 9,738 7,528
Other Investments 71,987 64,025
Investments in Unconsolidated Subsidiaries 16,064 16,425
Goodwill 5,476 5,476
Intangible Assets 47,763 49,664
Other 17,259 18,195
- ---------------------------------------------------------------------------- -------------------- -------------------
338,496 317,866
- ---------------------------------------------------------------------------- -------------------- -------------------
$3,738,268 $3,721,040
============================================================================ ==================== ===================
See Notes to Condensed Consolidated Financial Statements
7
Item 1. Financial Statements (Cont.)
National Fuel Gas Company
Consolidated Balance Sheets
(Unaudited)
June 30, September 30,
2004 2003
-------------------- -------------------
(Thousands of Dollars)
CAPITALIZATION AND LIABILITIES
Capitalization:
Comprehensive Shareholders' Equity
Common Stock, $1 Par Value
Authorized - 200,000,000 Shares; Issued
and Outstanding - 82,376,120 Shares and
81,438,290 Shares, Respectively $ 82,376 $ 81,438
Paid in Capital 496,349 478,799
Earnings Reinvested in the Business 734,382 642,690
- ---------------------------------------------------------------------------- -------------------- -------------------
Total Common Shareholder Equity Before
Items of Other Comprehensive Loss 1,313,107 1,202,927
Accumulated Other Comprehensive Loss (75,345) (65,537)
- ---------------------------------------------------------------------------- ------------------- -------------------
Total Comprehensive Shareholders' Equity 1,237,762 1,137,390
Long-Term Debt, Net of Current Portion 1,136,773 1,147,779
- ---------------------------------------------------------------------------- -------------------- -------------------
Total Capitalization 2,374,535 2,285,169
- ---------------------------------------------------------------------------- -------------------- -------------------
Minority Interest in Foreign Subsidiaries 37,350 33,281
- ---------------------------------------------------------------------------- -------------------- -------------------
Current and Accrued Liabilities
Notes Payable to Banks and
Commercial Paper 39,900 118,200
Current Portion of Long-Term Debt 114,110 241,731
Accounts Payable 115,886 118,904
Amounts Payable to Customers 22,253 692
Other Accruals and Current Liabilities 175,512 52,851
Fair Value of Derivative Financial Instruments 52,289 17,928
- ---------------------------------------------------------------------------- -------------------- -------------------
519,950 550,306
- ---------------------------------------------------------------------------- -------------------- -------------------
Deferred Credits
Accumulated Deferred Income Taxes 402,781 423,282
Taxes Refundable to Customers 13,519 13,519
Unamortized Investment Tax Credit 7,673 8,199
Cost of Removal Regulatory Liability 88,977 84,821
Other Regulatory Liabilities 62,283 69,867
Pension Liability 149,572 154,871
Asset Retirement Obligation 27,445 27,493
Other Deferred Credits 54,183 70,232
- ---------------------------------------------------------------------------- -------------------- -------------------
806,433 852,284
- ---------------------------------------------------------------------------- -------------------- -------------------
Commitments and Contingencies - -
- ---------------------------------------------------------------------------- -------------------- -------------------
$3,738,268 $3,721,040
============================================================================ ==================== ===================
See Notes to Condensed Consolidated Financial Statements
8
Item 1. Financial Statements (Cont.)
National Fuel Gas Company
Consolidated Statement of Cash Flows
(Unaudited)
Nine Months Ended
June 30,
(Thousands of Dollars) 2004 2003
------------------- ---------------------
OPERATING ACTIVITIES
Net Income Available for Common Stock $158,832 $120,799
Adjustments to Reconcile Net Income to Net Cash
Provided by Operating Activities:
Adjustment of Gain on Sale of Timber Properties 1,252 -
Adjustment of Loss on Sale of Oil and Gas Producing
Properties (4,645) -
Depreciation, Depletion and Amortization 141,768 142,168
Impairment of Oil and Gas Producing Properties - 31,812
Deferred Income Taxes (8,993) 4,378
Cumulative Effect of Changes in Accounting - 8,892
Income from Unconsolidated Subsidiaries, Net of
Cash Distributions 361 727
Minority Interest in Foreign Subsidiaries 3,378 1,853
Other (148) 2,480
Change in:
Receivables and Unbilled Utility Revenue (73,998) (112,439)
Gas Stored Underground and Materials and
Supplies 55,917 56,582
Unrecovered Purchased Gas Costs 27,616 (1,747)
Prepayments 13,619 9,666
Accounts Payable (3,094) 38,716
Amounts Payable to Customers 21,561 12,907
Other Accruals and Current Liabilities 122,000 46,343
Other Assets (21,194) (32,485)
Other Liabilities (25,997) (12,823)
- ---------------------------------------------------------------------------- ------------------- ---------------------
Net Cash Provided by Operating Activities 408,235 317,829
- ---------------------------------------------------------------------------- ------------------- ---------------------
INVESTING ACTIVITIES
Capital Expenditures (122,295) (96,838)
Investment in Subsidiaries, Net of Cash Acquired - (228,888)
Investment in Partnerships - (375)
Net Proceeds from Sale of Oil and Gas Producing Properties 5,062 -
Other 2,073 3,069
- ---------------------------------------------------------------------------- ------------------- ---------------------
Net Cash Used in Investing Activities (115,160) (323,032)
- ---------------------------------------------------------------------------- ------------------- ---------------------
FINANCING ACTIVITIES
Change in Notes Payable to Banks and Commercial Paper (78,300) 55,778
Net Proceeds from Issuance of Long-Term Debt - 248,513
Reduction of Long-Term Debt (139,441) (223,581)
Dividends Paid on Common Stock (66,056) (62,646)
Proceeds from Issuance of Common Stock 14,597 12,733
- ---------------------------------------------------------------------------- ------------------- ---------------------
Net Cash Provided by (Used in) Financing Activities (269,200) 30,797
- ---------------------------------------------------------------------------- ------------------- ---------------------
Effect of Exchange Rates on Cash 1,616 4,015
- ---------------------------------------------------------------------------- ------------------- ---------------------
Net Increase in Cash and Temporary Cash Investments 25,491 29,609
Cash and Temporary Cash Investments at October 1 51,421 22,216
- ---------------------------------------------------------------------------- ------------------- ---------------------
Cash and Temporary Cash Investments at June 30 $76,912 $51,825
============================================================================ =================== =====================
See Notes to Condensed Consolidated Financial Statements
9
Item 1. Financial Statements (Cont.)
National Fuel Gas Company
Consolidated Statements of Comprehensive Income
(Unaudited)
Three Months Ended
June 30,
(Thousands of Dollars) 2004 2003
------------- -------------------
Net Income Available for Common Stock $32,563 $2,219
- ----------------------------------------------------------------------------- --- -------------- -- ----------------
Other Comprehensive Income (Loss), Before Tax:
Foreign Currency Translation Adjustment 1,665 31,458
Unrealized Gain on Securities Available for Sale
Arising During the Period 767 1,451
Unrealized Loss on Derivative Financial Instruments
Arising During the Period (26,111) (14,412)
Reclassification Adjustment for Realized Losses on
Derivative Financial Instruments in Net Income 15,088 16,784
- ----------------------------------------------------------------------------- --- -------------- -- ----------------
Other Comprehensive Income Before Tax (8,591) 35,281
- ----------------------------------------------------------------------------- --- -------------- -- ----------------
Income Tax Expense Related to Unrealized Gain on
Securities Available for Sale Arising During the Period 268 508
Income Tax Benefit Related to Unrealized Loss on
Derivative Financial Instruments Arising During the Period (9,912) (5,381)
Reclassification Adjustment for Income Tax Benefit on
Realized Losses on Derivative Financial Instruments
In Net Income 5,085 6,357
- ----------------------------------------------------------------------------- --- -------------- -- ----------------
Income Taxes - Net (4,559) 1,484
- ----------------------------------------------------------------------------- --- -------------- -- ----------------
Other Comprehensive Income (Loss) (4,032) 33,797
- ----------------------------------------------------------------------------- --- -------------- -- ----------------
Comprehensive Income $28,531 $36,016
============================================================================= === ============== == ================
Nine Months Ended
June 30,
(Thousands of Dollars) 2004 2003
------------- -------------------
Net Income Available for Common Stock $158,832 $120,799
- ----------------------------------------------------------------------------- --- -------------- -- ----------------
Other Comprehensive Income (Loss), Before Tax:
Foreign Currency Translation Adjustment 10,464 54,562
Unrealized Gain on Securities Available for Sale
Arising During the Period 3,160 2,180
Unrealized Loss on Derivative Financial
Instruments Arising During the Period (68,423) (55,966)
Reclassification Adjustment for Realized Losses on
Derivative Financial Instruments in Net Income 31,883 56,155
- ----------------------------------------------------------------------------- --- -------------- -- ----------------
Other Comprehensive Income (Loss), Before Tax (22,916) 56,931
- ----------------------------------------------------------------------------- --- -------------- -- ----------------
Income Tax Expense Related to Unrealized Gain on
Securities Available for Sale Arising During the Period 1,106 762
Income Tax Benefit Related to Unrealized Loss on
Derivative Financial Instruments Arising During the Period (25,799) (21,289)
Reclassification Adjustment for Income Tax Benefit on
Realized Losses from Derivative Financial Instruments
In Net Income 11,585 21,795
- ----------------------------------------------------------------------------- --- -------------- -- ----------------
Income Taxes - Net (13,108) 1,268
- ----------------------------------------------------------------------------- --- -------------- -- ----------------
Other Comprehensive Income (Loss) (9,808) 55,663
- ----------------------------------------------------------------------------- --- -------------- -- ----------------
Comprehensive Income $149,024 $176,462
============================================================================= === ============== == ================
See Notes to Condensed Consolidated Financial Statements
10
Item 1. Financial Statements (Cont.)
National Fuel Gas Company
Notes to Condensed Consolidated Financial Statements
(Unaudited)
Note 1 — Summary of Significant Accounting Policies
Principles of Consolidation. The Company consolidates its majority owned entities. The equity method is used to account for minority owned entities. All significant intercompany balances and transactions are eliminated.The preparation of the consolidated financial statements in conformity with accounting principles generally accepted in the United States of America (GAAP) 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.
Earnings for Interim Periods. The Company, in its opinion, has included all adjustments that are necessary for a fair statement of the results of operations for the reported periods. The consolidated financial statements and notes thereto, included herein, should be read in conjunction with the financial statements and notes for the years ended September 30, 2003, 2002 and 2001 that are included in the Company’s 2003 Form 10-K. The 2004 consolidated financial statements will be examined by the Company’s independent accountants after the end of the fiscal year.
The earnings for the nine months ended June 30, 2004 should not be taken as a prediction of earnings for the entire fiscal year ending September 30, 2004. Most of the business of the Utility, International, and Energy Marketing segments is seasonal in nature and is influenced by weather conditions. Due to the seasonal nature of the heating business in the Utility, International, and Energy Marketing segments, earnings during the winter months normally represent a substantial part of the earnings in those segments for the entire fiscal year.
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 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. SFAS 143 was applied retroactively to prior years to determine the cumulative effect through October 1, 2002. This cumulative effect reduced earnings for the nine months ended June 30, 2003 by $0.6 million, net of income tax.
In the Company’s Utility and Pipeline and Storage segments, the costs of removing plant are collected from customers through depreciation expense. These removal costs are not a legal retirement obligation in accordance with SFAS 143. Rather, they represent a regulatory liability. However, SFAS 143 required that such costs of removal be reclassified from accumulated depreciation to other regulatory liabilities. Such costs are reflected on the Consolidated Balance Sheets as Cost of Removal Regulatory Liability.
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. As a result of the impairment test, the Company recognized an impairment of $8.3 million. In accordance with SFAS 142, this impairment was reported as a cumulative effect of change in accounting and is reflected in the nine months ended June 30, 2003.
11
Item 1. Financial Statements (Cont.)
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), net of related tax effect, are as follows (in thousands):
At June 30, 2004 At September 30, 2003
---------------- ---------------------
Minimum Pension Liability Adjustment $(90,446) $(90,446)
Cumulative Foreign Currency
Translation Adjustment 40,514 30,050
Net Unrealized Loss on Derivative
Financial Instruments (29,198) (6,872)
Net Unrealized Gain on Securities
Available for Sale 3,785 1,731
--------- ---------
Accumulated Other Comprehensive Loss $(75,345) $(65,537)
========= =========
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 Statements of Income and Earnings Reinvested in the Business reflects the potential dilution as a result 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, 2004 and 2003, 2,690,547 and 4,419,288 stock options, respectively, were excluded since they are antidilutive. For the nine months ended June 30, 2004 and 2003, 4,417,138 and 8,591,095 stock options, respectively, were excluded since they are antidilutive.
Stock-Based Compensation. The Company accounts for stock-based compensation using the intrinsic value method specified by Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees” and related interpretations. Under that method, no compensation expense was recognized for options granted under the Company’s stock option plans for the quarter and nine months ended June 30, 2004 and 2003.
12
Item 1. Financial Statements (Cont.)
Had compensation expense been determined based on fair value at the grant dates, which is the accounting treatment specified by SFAS 123, “Accounting for 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) 2004 2003 2004 2003
---- ---- ---- ----
Net Income Available for
Common Stock as Reported $32,563 $2,219 $158,832 $120,799
Deduct:
Total Compensation
Expense Determined Based
on Fair Value at the Grant
Dates 322 537 1,354 2,701
-------- ------- --------- ---------
Pro Forma Net Income Available
For Common Stock $32,241 $1,682 $157,478 $118,098
======== ======= ========= =========
Earnings Per Common Share:
Basic - As Reported $0.40 $0.03 $1.94 $1.50
Basic - Pro Forma $0.39 $0.02 $1.92 $1.46
Diluted - As Reported $0.39 $0.03 $1.92 $1.49
Diluted - Pro Forma $0.39 $0.02 $1.90 $1.46
“Net Income Available for Common Stock as Reported” in the pro forma information shown above includes compensation expense related to restricted stock awards. Such compensation expense amounted to $0.2 million and $0.3 million for the quarters ended June 30, 2004 and June 30, 2003, respectively. For the nine months ended June 30, 2004 and June 30, 2003, such compensation expense amounted to $0.7 million and $0.8 million, respectively.
During the quarter ended March 31, 2004, the Company recorded a $4.6 million earnings benefit related to the Company’s 2003 sale of Canadian oil properties. When the Company closed that transaction in September 2003, the initial proceeds it received were subject to adjustment based on actual working capital and the resolution of certain income tax matters. During the quarter ended March 31, 2004, the Company resolved those items with the buyer and, as a result, received an additional $4.6 million (U. S. dollars) of sales proceeds, which it recorded in the Adjustment of Loss on Sale of Oil and Gas Producing Properties line on the income statement.
During the quarter ended June 30, 2004, the Company received final timber cruise information (inventory) on the 70,000 acres of timber properties sold in 2003. Based on that information, the Company determined that property records pertaining to $1.3 million ($0.8 million after tax) of timber property were not properly shown as having been transferred to the purchaser. As a result, the Company removed those assets from its property records and adjusted the previously recognized gain downward by recognizing a pre-tax loss of $1.3 million. The Company recorded this adjustment in the Adjustment of Gain on Sale of Timber Properties line on the income statement.
13
Item 1. Financial Statements (Cont.)
The components of federal, state and foreign income taxes included in the Consolidated Statement of Income are as follows (in thousands):
Nine Months Ended
June 30,
2004 2003
------------------- --------------------
Operating Expenses:
Current Income Taxes
Federal $72,458 $64,095
State 22,285 16,187
Foreign 4,753 2,402
Deferred Income Taxes
Federal (5,468) (794)
State (3,948) (553)
Foreign 423 5,725
- ---------------------------------------------------------------------------- ------------------- --------------------
90,503 87,062
Other Income:
Deferred Investment Tax Credit (523) (519)
Minority Interest in Foreign Subsidiaries (133) (1,027)
Cumulative Effect of Change in Accounting - (354)
- ---------------------------------------------------------------------------- ------------------- --------------------
Total Income Taxes $89,847 $85,162
============================================================================ =================== ====================
The U.S. and foreign components of income before income taxes are as follows (in thousands):
Nine Months Ended
June 30,
2004 2003
------------------- --------------------
U.S. $214,330 $209,901
Foreign 34,349 (3,940)
- ---------------------------------------------------------------------------- ------------------- --------------------
$248,679 $205,961
============================================================================ =================== ====================
14
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,
2004 2003
------------------- --------------------
Income tax expense, computed at
statutory rate of 35% $87,038 $72,086
Increase (reduction) in taxes resulting from:
State income taxes 11,919 10,162
Depreciation 792 1,109
Foreign tax differential (1,806) 4,354
Foreign tax rate reduction (1) (5,174) -
Miscellaneous (2,922) (2,549)
- ---------------------------------------------------------------------------- ------------------- --------------------
Total Income Taxes $89,847 $85,162
============================================================================ =================== ====================
(1) During the quarter ended December 31, 2003, legislation was enacted in the Czech Republic which reduces the corporate statutory income tax rate from 31% to 24% over a three-year period. This amount reflects a reduction in deferred income taxes that were provided in prior years when a higher statutory tax rate was in effect.
Significant components of the Company’s deferred tax liabilities (assets) were as follows (in thousands):
At June 30, 2004 At September 30, 2003
--------------------------------- ----------------------------
Deferred Tax Liabilities:
Property, Plant and Equipment $542,668 $519,578
Other 27,333 21,532
- ------------------------------------------------------ --------------------------------- ----------------------------
Total Deferred Tax Liabilities 570,001 541,110
- ------------------------------------------------------ --------------------------------- ----------------------------
Deferred Tax Assets:
Minimum Pension Liability Adjustment (48,701) (48,701)
Capital Loss Carryover (14,848) (18,607)
Other (108,369) (56,877)
- ------------------------------------------------------ --------------------------------- ----------------------------
(171,918) (124,185)
Valuation Allowance 4,698 6,357
- ------------------------------------------------------ --------------------------------- ----------------------------
Total Deferred Tax Assets (167,220) (117,828)
- ------------------------------------------------------ --------------------------------- ----------------------------
Total Net Deferred Income Taxes $402,781 $423,282
====================================================== ================================= ============================
A capital loss carryover of $42.4 million existed at June 30, 2004, which expires if not utilized by September 30, 2008. Although realization is not assured, management estimates that a portion of the deferred tax asset associated with this carryover will be realized during the carryover period, and a valuation allowance is recorded for the remaining portion. Adjustments to the valuation allowance may be necessary in the future if estimates of capital gain income are revised.
15
Item 1. Financial Statements (Cont.)
Common Stock. During the nine months ended June 30, 2004, the Company issued 937,830 shares of common stock under the Company’s stock and benefit plans.
Environmental Matters. The Company is subject to various federal, state and local laws and regulations relating to the protection of the environment. The Company has established procedures for 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, 2004, the Company has estimated its remaining clean-up costs related to former manufactured gas plant sites and third party waste disposal sites will be $14.0 million. This liability has been recorded on the Consolidated Balance Sheet at June 30, 2004. Other than as discussed in Note G of the Company’s 2003 Form 10-K (referred to below), the Company is currently not aware of any material additional exposure to environmental liabilities. However, changes in environmental regulations or other adverse factors could impact the Company.
For further discussion refer to Note G – Commitments and Contingencies under the heading “Environmental Matters” in Item 8 of the Company’s 2003 Form 10-K.
Other. 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 litigation or regulatory matters could have a material effect on earnings and cash flows in the quarterly and annual period of resolution, none of this litigation, and none of these regulatory matters, are expected to change materially the Company’s present liquidity position, nor have a material adverse effect on the financial condition of the Company.
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 Company’s 2003 Form 10-K. There have been no material changes in the amount of assets for any operating segment from the amounts disclosed in the Company’s 2003 Form 10-K.
16
Item 1. Financial Statements (Cont.)
Quarter Ended June 30, 2004 (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 $206,492 $29,553 $76,992 $22,122 $67,376 $13,071 $415,606 $3,400 $ - $419,006
Intersegment
Revenues $ 3,059 $20,895 $ - $ - $ - $ - $23,954 $ - $ (23,954) $ -
Segment Profit:
Net Income (Loss) $ 4,167 $12,063 $14,822 $ (1,612) $ 1,241 $ 652 $31,333 $ 394 $ 836 $32,563
Nine Months Ended June 30, 2004 (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 $1,029,638 $92,420 $225,594 $112,723 $240,732 $41,622 $1,742,729 $10,468 $ - $1,753,197
Intersegment
Revenues $ 13,487 $65,625 $ - $ - $ - $ 2 $ 79,114 $ - $ (79,114) $ -
Segment Profit:
Net Income (Loss) $ 53,772 $36,233 $44,065 $12,981 $ 5,588 $3,871 $ 156,510 $1,350 $ 972 $ 158,832
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
Revenues $15,738 $67,991 - - - - $83,729 - $(83,729) -
Segment Profit:
Income (Loss)
Before
Cumulative
Effect of
Changes in
Accounting $67,096 $34,947 $7,591 $4,896 $6,131 $8,730 $129,391 $(70) $370 $129,691
17
Item 1. Financial Statements (Cont.)
The components of the Company’s intangible assets were as follows (in thousands):
At September 30,
At June 30, 2004 2003
----------------------------------------- -----------------
Gross Net Net
Carrying Accumulated Carrying Carrying
At June 30, 2004 (Thousands) Amount Amortization Amount Amount
--------- ------------- -------- ---------
Intangible Assets Subject to Amortization
Long-Term Transportation Contracts $ 8,580 $(1,514) $ 7,066 $ 7,867
Long-Term Gas Purchase Contracts 31,864 (1,442) 30,422 31,522
Intangible Assets Not Subject to Amortization
Retirement Plan Intangible Asset 10,275 - 10,275 10,275
-------- -------- -------- ---------
$50,719 $(2,956) $47,763 $ 49,664
======== ======== ======== =========
Aggregate Amortization Expense (Thousands)
Three Months Ended June 30, 2004 $ 666
Nine Months Ended June 30, 2004 $ 1,902
Amortization expense for the long-term transportation contracts is estimated to be $0.3 million for the remainder of 2004 and $1.1 million annually for 2005, 2006, 2007 and 2008. Amortization in 2009 is estimated to be $0.5 million.
Amortization expense for the long-term gas purchase contracts is estimated to be $0.4 million for the remainder of 2004 and $1.6 million annually for 2005, 2006, 2007, 2008 and 2009.
Three months ended June 30,
Retirement Plan Other Post-Retirement Benefits
--------------- ------------------------------
2004 2003 2004 2003
---- ---- ---- ----
Service Cost $ 3,649 $ 3,261 $ 1,649 $ 1,461
Interest Cost 10,141 10,242 6,885 6,531
Expected Return on Plan Assets (12,070) (11,815) (3,453) (3,067)
Amortization of Prior Service Cost 276 294 1 1
Amortization of Transition Amount - (929) 1,782 1,782
Amortization of Losses 2,360 558 5,381 3,716
Net Amortization and Deferral
For Regulatory Purposes (Including
Volumetric Adjustments) (1) 435 1,042 (4,706) (7,081)
-------- -------- -------- --------
Net Periodic Benefit Cost $ 4,791 $ 2,653 $ 7,539 $ 3,343
======= ======== ======== ========
18
Item 1. Financial Statements (Concl.)
Nine months ended June 30,
Retirement Plan Other Post-Retirement Benefits
--------------- ------------------------------
2004 2003 2004 2003
---- ---- ---- ----
Service Cost $10,948 $ 9,783 $ 4,948 $ 4,383
Interest Cost 30,424 30,726 20,656 19,593
Expected Return on Plan Assets (36,211) (35,445) (10,360) (9,201)
Amortization of Prior Service Cost 827 882 3 3
Amortization of Transition Amount - (2,787) 5,345 5,346
Amortization of Losses 7,078 1,674 16,144 11,149
Net Amortization and Deferral
for Regulatory Purposes (Including
Volumetric Adjustments) (1) 1,049 4,368 (7,179) (13,434)
-------- -------- -------- --------
Net Periodic Benefit Cost $14,115 $ 9,201 $29,557 $17,839
======== ======== ======== ========
(1) The Company’s policy is to record retirement plan and other post-retirement benefit costs in the Utility segment on a volumetric basis to reflect the fact that the Utility segment experiences higher volumes of natural gas in the winter months and lower volumes of natural gas sales in the summer months.
During the nine months ended June 30, 2004, the Company contributed to its retirement plan and post-retirement benefit plan $37.1 million and $38.3 million, respectively. The Company expects to contribute an additional $3.1 million to its post-retirement benefit plan in the fourth quarter of 2004.
On December 8, 2003, the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the Act) was signed into law. The provisions of the Act provide for a federal subsidy for plans that provide prescription drug benefits and meet certain qualifications. The Company’s net periodic benefit cost for other post-retirement benefits recorded in the three months and nine months ended June 30, 2004 does not reflect the effects of the Act. In May 2004, the Financial Accounting Standards Board issued Staff Position (FSP) 106-2, "Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003." FSP 106-2 provides accounting and disclosure requirements regarding the effect of the federal subsidy provided by the Act and is effective for the first interim or annual period beginning after June 15, 2004.
In January 2004, a participant of the Company’s nonqualified defined benefit plan received a $23.0 million lump sum payment under a provision of an agreement previously entered into between the Company and the participant. Under GAAP, this payment was considered to be a partial settlement of the projected benefit obligation of the plan. Accordingly, GAAP required that a pro rata portion of the plan’s unrecognized actuarial losses resulting from experience different from that assumed and from changes in assumptions be currently recognized. Therefore, $9.9 million before tax ($6.4 million, after tax) was recognized as a settlement expense (included in Operation and Maintenance Expense on the income statement) during the quarter ended March 31, 2004.
19
For a complete discussion of critical accounting policies, refer to “Critical Accounting Policies” in Item 7 of the Company’s 2003 Form 10-K. There have been no subsequent changes to that disclosure.
The Company’s earnings were $32.6 million for the quarter ended June 30, 2004 compared to earnings of $2.2 million for the quarter ended June 30, 2003. The increase in earnings is primarily the result of higher earnings in the Exploration and Production, International, Energy Marketing, and Pipeline and Storage segments, partially offset by lower earnings in the Utility and Timber segments, as shown in the table below. Earnings in the Timber segment for the quarter ended June 30, 2004 were reduced by $0.8 million related to an adjustment to the Company’s August 2003 sale of timber properties.
The Company’s earnings were $158.8 million for the nine months ended June 30, 2004 compared to earnings of $120.8 million for the nine months ended June 30, 2003. The increase in earnings of $38.0 million is primarily the result of higher earnings in the Exploration and Production, International, and Pipeline and Storage segments, partially offset by lower earnings in the Utility, Timber and Energy Marketing segments, as shown in the table below. Earnings in the Exploration and Production segment for the nine months ended June 30, 2004 included a $4.6 million (after tax) benefit related to the Company’s September 2003 sale of Canadian oil properties. Also, earnings in the Exploration and Production segment for the nine months ended June 30, 2003 included a reduction to earnings in the amount of $22.6 million, representing an impairment charge of $22.6 million related to this segment’s Canadian oil and gas assets. Earnings in the International segment for the nine months ended June 30, 2004 included a $5.2 million reduction to deferred income tax expense resulting from a change in the statutory income tax rate in the Czech Republic. Also, International segment earnings for the nine months ended June 30, 2003 included a reduction to earnings in the amount of $8.3 million representing the cumulative effect of a change in accounting for goodwill. As mentioned above, Timber segment earnings for the nine months ended June 30, 2004 were reduced by $0.8 million related to an adjustment to the Company’s August 2003 sale of timber properties. Earnings for the nine months ended June 30, 2004 included $6.4 million (after tax) of expense associated with the settlement of a pension obligation. The $6.4 million (after tax) of expense was allocated among segments as follows: $2.2 million to the Utility segment, ($1.2 million in the New York jurisdiction and $1.0 million in the Pennsylvania jurisdiction), $2.0 million to the Pipeline and Storage segment ($1.8 million to Supply Corporation and $0.2 million to Empire State Pipeline), $0.9 million to the Exploration and Production segment, $0.4 million to the International segment, $0.3 million to the Energy Marketing segment and $0.6 million to the Corporate and All Other categories.
Additional discussion of earnings in each of the business segments can be found in the business segment information that follows.
20
Earnings (Loss) by Segment
- ------------------------------------ ------------------------------------------- -------------------------------------------
Three Months Ended Nine Months Ended
June 30, June 30,
- ------------------------------------ ------------------------------------------- -------------------------------------------
Increase/ Increase/
(Thousands) 2004 2003 (Decrease) 2004 2003 (Decrease)
- ------------------------------------ ------------- ------------- --------------- ------------- ------------- ---------------
Utility $4,167 $8,088 $(3,921) $53,772 $ 67,096 $(13,324)
Pipeline and Storage 12,063 11,648 415 36,233 34,947 1,286
Exploration and Production 14,822 (15,435) 30,257 44,065 6,954 37,111
International (1,612) (3,466) 1,854 12,981 (3,359) 16,340
Energy Marketing 1,241 (67) 1,308 5,588 6,131 (543)
Timber 652 988 (336) 3,871 8,730 (4,859)
- ------------------------------------ ------------- ------------- --------------- ------------- ------------- ---------------
Total Reportable Segments 31,333 1,756 29,577 156,510 120,499 36,011
All Other 394 (124) 518 1,350 (70) 1,420
Corporate 836 587 249 972 370 602
- ------------------------------------ ------------- ------------- --------------- ------------- ------------- ---------------
Total Consolidated $32,563 $2,219 $30,344 $158,832 $120,799 $38,033
- ------------------------------------ ------------- ------------- --------------- ------------- ------------- ---------------
Utility
Utility Operating Revenues
- ------------------------------- ------------------------------------------ ---------------------------------------------
Three Months Ended Nine Months Ended
June 30, June 30,
- ------------------------------- ------------------------------------------ ---------------------------------------------
Increase/ Increase/
(Thousands) 2004 2003 (Decrease) 2004 2003 (Decrease)
- ------------------------------- ------------- ------------- -------------- --------------- -------------- --------------
Retail Sales Revenues:
Residential $136,324 $149,748 $(13,424) $739,797 $730,892 $8,905
Commercial 20,846 23,437 (2,591) 127,130 127,537 (407)
Industrial 5,701 5,583 118 15,701 18,656 (2,955)
- ------------------------------- ------------- ------------- -------------- --------------- -------------- --------------
162,871 178,768 (15,897) 882,628 877,085 5,543
- ------------------------------- ------------- ------------- -------------- --------------- -------------- --------------
Off-System Sales 28,034 28,688 (654) 91,236 86,763 4,473
Transportation 17,605 18,162 (557) 68,084 74,395 (6,311)
Other 1,041 382 659 1,177 (5,187) 6,364
- ------------------------------- ------------- ------------- -------------- --------------- -------------- --------------
$209,551 $226,000 $(16,449) $1,043,125 $1,033,056 $10,069
- ------------------------------- ------------- ------------- -------------- --------------- -------------- --------------
Utility Throughput
- ------------------------------- ------------------------------------------- --------------------------------------------
Three Months Ended Nine Months Ended
June 30, June 30,
- ------------------------------- ------------------------------------------- --------------------------------------------
Increase/ Increase/
(MMcf) 2004 2003 (Decrease) 2004 2003 (Decrease)
- ------------------------------- ------------- -------------- -------------- -------------- -------------- --------------
Retail Sales:
Residential 10,899 12,172 (1,273) 65,791 71,740 (5,949)
Commercial 1,812 2,069 (257) 12,019 13,367 (1,348)
Industrial 797 654 143 2,050 2,900 (850)
- ------------------------------- ------------- -------------- -------------- -------------- -------------- --------------
13,508 14,895 (1,387) 79,860 88,007 (8,147)
- ------------------------------- ------------- -------------- -------------- -------------- -------------- --------------
Off-System Sales 4,151 4,587 (436) 14,254 14,196 58
Transportation 13,923 14,510 (587) 51,597 55,496 (3,899)
------------------------------- ------------- -------------- -------------- -------------- -------------- --------------
31,582 33,992 (2,410) 145,711 157,699 (11,988)
- ------------------------------- ------------- -------------- -------------- -------------- -------------- --------------
21
Degree Days
- ---------------------------------- -------------- -------------- -------------------- --------------------------------
Percent Warmer
Three Months Ended Than
--------------------------------
June 30 Normal 2004 2003 Normal Prior Year
- ---------------------------------- -------------- -------------- -------------------- ----------------- --------------
Buffalo 927 884 1,028 4.6 14.0
Erie 885 786 987 11.2 20.4
- ---------------------------------- -------------- -------------- -------------------- ----------------- --------------
Nine Months Ended
June 30
- ---------------------------------- -------------- -------------- -------------------- ----------------- --------------
Buffalo 6,551 6,474 7,030 1.2 7.9
Erie 6,142 5,991 6,673 2.5 10.2
- ---------------------------------- -------------- -------------- -------------------- ----------------- --------------
Operating revenues for the Utility segment decreased $16.4 million for the quarter ended June 30, 2004 as compared with the quarter ended June 30, 2003. The decrease for the quarter was primarily the result of lower retail sales volumes due to warmer weather in its Pennsylvania jurisdiction and lower customer usage per account. A rate increase in Pennsylvania partially offset these negative factors. On January 15, 2004, Distribution Corporation implemented the October 16, 2003 Settlement Agreement with the Pennsylvania Public Utility Commission (PaPUC), which among other things, provided for a $3.5 million annual base rate increase in revenues. For the quarter ended June 30, 2004, the base rate adjustment contributed $0.7 million to revenues.
Operating revenues for the Utility segment increased $10.1 million for the nine months ended June 30, 2004 as compared with the nine months ended June 30, 2003. The increase for the nine months ended June 30, 2004 was primarily the result of higher retail, off-system and other revenues. The increase in retail sales revenues was largely a function of the recovery of higher gas costs, which more than offset lower retail sales volumes, as shown above. Warmer weather and lower customer usage per account were the major factors in the decrease in retail sales volumes. The base rate increase in Pennsylvania, as discussed above, contributed $1.9 million to the revenue increase for the nine months ended June 30, 2004. Higher gas prices for off-system sales contributed to an increase in off-system sales revenues. However, due to profit sharing with retail customers, any margins resulting from off-system sales are minimal. The increase in other revenues reflects an estimated refund provision of $8.1 million recorded in the Utility’s New York jurisdiction during the nine months ended June 30, 2003 that did not recur during the nine months ended June 30, 2004. The refund provision related to a three-year rate settlement approved by the State of New York Public Service Commission (NYPSC), which extended from October 1, 2000 to September 30, 2003. In accordance with the settlement, the Utility segment was required to share with customers 50% of earnings above a predetermined level. As discussed further in the “Rate Matters” section of this Item, the settlement with the NYPSC was extended for a one-year period commencing October 1, 2003. Partially offsetting these increases to revenues, transportation revenues decreased because of lower volumes being transported as a result of warmer weather.
The Utility segment’s earnings for the quarter ended June 30, 2004 were $4.2 million, a decrease of $3.9 million when compared with the quarter ended June 30, 2003. In the New York jurisdiction, earnings decreased by $1.5 million principally due to a $2.3 million (after tax) decrease in margin on retail sales and transportation services and a $0.9 million (after tax) increase in operation and maintenance expense. The decrease in margin was caused principally by gas cost timing differences that occurred in the third and fourth quarters of 2003 ($1.6 million after tax) and a decrease in usage per account ($0.4 million after tax). The increase in operation and maintenance expense was driven mostly by pension and other post-retirement expense, which increased as the result of the one-year settlement extension (referred to above), which requires the Company to record an additional $8.0 million (before tax) of pension and other post-retirement expense for the year ended September 30, 2004 without a corresponding increase in revenues. Partially offsetting these decreases to earnings, the New York
22
jurisdiction experienced lower interest expense ($1.4 million after tax). For the Pennsylvania jurisdiction, earnings decreased by $2.4 million principally due to a $1.9 million (after tax) increase in operation and maintenance expense and a $0.7 million (after tax) decrease in margin resulting from warmer weather (which was 20% warmer than the prior year). The increase in operation and maintenance expense, which was mostly due to an increase in pension and other post-retirement expenses, was partially mitigated by the rate increase discussed above ($0.5 million after tax). The impact of weather variations on earnings 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 for the New York rate jurisdiction. For the quarter ended June 30, 2004, the WNC preserved $0.9 million of earnings since the weather was warmer than normal. Weather did not have a significant impact during the quarter ended June 30, 2003.
The Utility segment’s earnings for the nine months ended June 30, 2004 were $53.8 million, a decrease of $13.3 million when compared with the earnings of $67.1 million for the nine months ended June 30, 2003. In the New York jurisdiction, earnings decreased by $7.6 million principally due to a $8.1 million (after tax) increase in operation and maintenance expense and a $7.6 million (after tax) decrease in margin on retail sales and transportation services. Approximately $1.2 million (after tax) of the increase in operation and maintenance expense was related to the settlement of a pension obligation. The remainder of the increase in operation and maintenance expense was driven mostly by an increase in pension and other post-retirement expense, as discussed above, combined with higher bad debt expense. The decrease in margin was largely due to out-of-period regulatory adjustments and gas cost timing differences that occurred in the third and fourth quarters of 2003 ($3.9 million after tax) and a decrease in usage per account ($2.2 million after tax). Partially offsetting these decreases was lower interest expense of $2.2 million (after tax) and the fact that earnings for the nine months ended June 30, 2003 included a $5.3 million (after tax) refund provision recorded under the previously mentioned earnings sharing mechanism established by the settlement with the NYPSC. No such refund provision was required for the nine months ended June 30, 2004. For the Pennsylvania jurisdiction, earnings decreased by $5.7 million principally due to a $4.7 million (after tax) increase in operation and maintenance expense and a $2.7 million (after tax) decrease in margin resulting from warmer weather. The increase in operation and maintenance expense, mostly due to an increase in pension and other post-retirement expenses, was partially mitigated by the rate increase discussed above ($1.2 million after tax). The increase in pension and other post-retirement expenses included $1.0 million (after tax) of expense associated with the settlement of a pension obligation. The impact of weather variations on earnings in the New York jurisdiction is mitigated by that jurisdiction’s WNC. For the nine months ended June 30, 2004, the WNC preserved $1.0 million of earnings since the weather was warmer than normal. For the nine months ended June 30, 2003, the WNC reduced earnings by $3.8 million since the weather was colder than normal.
Pipeline and Storage
Pipeline and Storage Operating Revenues
- ------------------------------------ ---------------------------------------- -------------------------------------------
Three Months Ended Nine Months Ended
June 30, June 30,
- ------------------------------------ ---------------------------------------- -------------------------------------------
Increase/ Increase/
(Thousands) 2004 2003 (Decrease) 2004 2003 (Decrease)
- ------------------------------------ ------------ ------------ -------------- --------------- ------------ --------------
Firm Transportation $28,929 $30,054 $(1,125) $92,194 $80,250 $11,944
Interruptible Transportation 785 1,142 (357) 2,323 2,643 (320)
- ------------------------------------ ------------ ------------ -------------- --------------- ------------ --------------
29,714 31,196 (1,482) 94,517 82,893 11,624
- ------------------------------------ ------------ ------------ -------------- --------------- ------------ --------------
Firm Storage Service 15,961 15,779 182 47,774 47,382 392
Other 4,773 4,133 640 15,754 15,736 18
- ------------------------------------ ------------ ------------ -------------- --------------- ------------ --------------
$50,448 $51,108 $(660) $158,045 $146,011 $12,034
- ------------------------------------ ------------ ------------ -------------- --------------- ------------ --------------
23
Pipeline and Storage Throughput
- ------------------------------------ ---------------------------------------- -------------------------------------------
Three Months Ended Nine Months Ended
June 30, June 30,
- ------------------------------------ ---------------------------------------- -------------------------------------------
Increase/ Increase/
(MMcf) 2004 2003 (Decrease) 2004 2003 (Decrease)
- ------------------------------------ ------------ ------------ -------------- --------------- ------------ --------------
Firm Transportation 66,140 69,932 (3,792) 284,351 285,080 (729)
Interruptible Transportation 6,995 3,173 3,822 10,891 7,487 3,404
- ------------------------------------ ------------ ------------ -------------- --------------- ------------ --------------
73,135 73,105 30 295,242 292,567 2,675
- ------------------------------------ ------------ ------------ -------------- --------------- ------------ --------------
Operating revenues for the Pipeline and Storage segment decreased $0.7 million for the quarter ended June 30, 2004 as compared with the quarter ended June 30, 2003 primarily due to lower transportation revenues of $1.5 million (primarily Supply Corporation revenues). The decrease in transportation revenues largely reflects lower rates charged for firm gathering services and the Utility segment’s cancellation of a portion of its firm transportation capacity. Firm gathering rates are adjusted annually in January and will increase or decrease depending on the level of interruptible gathering revenues collected in the preceding calendar year. The Utility segment’s decision to cancel a portion of its firm transportation capacity was based on lower usage in its service territory. Supply Corporation believes it will be able to remarket this capacity.* This decrease was partially offset by higher revenues from unbundled pipeline sales and open access transportation of $1.2 million (reported as part of other revenues in the table above).
Operating revenues for the Pipeline and Storage segment increased $12.0 million for the nine months ended June 30, 2004 as compared with the nine months ended June 30, 2003. The acquisition of Empire State Pipeline (Empire) from Duke Energy Corporation on February 6, 2003 was a significant factor in the revenue increase. For the nine months ended June 30, 2004, Empire recorded operating revenues of $25.6 million. From February 6, 2003 to June 30, 2003, Empire recorded operating revenues of $13.5 million. Additionally, revenues from unbundled pipeline sales and open access transportation increased $3.0 million for the nine months ended June 30, 2004. These increases were partially offset by lower cashout revenues of $0.9 million (reported as part of other revenues in the table above). Cashout revenues represent a cash resolution of a gas imbalance whereby a customer pays Supply Corporation for gas the customer receives in excess of amounts delivered into Supply Corporation’s system by the customer’s shipper. Cashout revenues are completely offset by purchased gas expense.
Earnings in the Pipeline and Storage segment for the quarter ended June 30, 2004 increased $0.4 million as compared with the quarter ended June 30, 2003. The earnings impact of higher revenues from unbundled pipeline sales and open access transportation of $0.8 million (after tax) and lower interest expense ($0.9 million after tax) was largely offset by the earnings impact of lower transportation revenues ($1.0 million after tax).
The Pipeline and Storage segment’s earnings for the nine months ended June 30, 2004 were $36.2 million, an increase of $1.3 million when compared with earnings of $34.9 million for the nine months ended June 30, 2003. This increase can be attributed primarily to the earnings impact of an increase in revenues from unbundled pipeline sales and open access transportation of $2.0 million (after tax) as well as the increased earnings contribution from Empire of $2.3 million. Also, Supply Corporation experienced an earnings impact associated with lower interest expense of $1.0 million (after tax). Offsetting these increases, Supply Corporation recorded additional expense during the quarter ended March 31, 2004 associated with the settlement of a pension obligation, of which the earnings impact was $1.8 million (after tax), and experienced an earnings impact associated with higher operation and maintenance expense of $1.1 million (after tax) associated mostly with higher pension and other post-retirement benefits.
24
Exploration and Production
Exploration and Production Operating Revenues
- ----------------------------------- ---------------------------------------- -----------------------------------------
Three Months Ended Nine Months Ended
June 30, June 30,
- ----------------------------------- ---------------------------------------- -----------------------------------------
Increase/ Increase/
(Thousands) 2004 2003 (Decrease) 2004 2003 (Decrease)
- ----------------------------------- ------------ ------------ -------------- ------------- ------------ --------------
Gas (after Hedging) $43,947 $38,934 $5,013 $130,240 $116,682 $13,558
Oil (after Hedging) 31,354 34,244 (2,890) 90,009 111,740 (21,731)
Gas Processing Plant 6,980 7,518 (538) 20,609 22,090 (1,481)
Other 842 922 (80) 1,607 601 1,006
Intrasegment Elimination (1) (6,131) (5,866) (265) (16,871) (17,378) 507
- ----------------------------------- ------------ ------------ -------------- ------------- ------------ --------------
$76,992 $75,752 $1,240 $225,594 $233,735 $(8,141)
- ----------------------------------- ------------ ------------ -------------- ------------- ------------ --------------
(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/
2004 2003 (Decrease) 2004 2003 (Decrease)
- ---------------------------------------------- ---------- ---------- -------------- ------------ ---------- --------------
Gas Production (million cubic feet - MMcf)
Gulf Coast 4,563 4,280 283 14,050 14,839 (789)
West Coast 1,018 1,081 (63) 3,018 3,382 (364)
Appalachia 1,208 1,448 (240) 3,894 3,836 58
Canada 1,578 1,249 329 4,874 4,280 594
- ---------------------------------------------- ---------- ---------- -------------- ------------ ---------- --------------
8,367 8,058 309 25,836 26,337 (501)
- ---------------------------------------------- ---------- ---------- -------------- ------------ ---------- --------------
Oil Production (thousands of barrels-Mbbl)
Gulf Coast 395 330 65 1,184 1,121 63
West Coast 651 712 (61) 2,012 2,179 (167)
Appalachia 4 3 1 15 7 8
Canada 89 573 (484) 253 1,817 (1,564)
- ---------------------------------------------- ---------- ---------- -------------- ------------ ---------- --------------
1,139 1,618 (479) 3,464 5,124 (1,660)
- ---------------------------------------------- ---------- ---------- -------------- ------------ ---------- --------------
25
Average Prices
- ----------------------------------------- --------------------------------------- ----------------------------------------
Three Months Ended Nine Months Ended
June 30, June 30,
- ----------------------------------------- --------------------------------------- ----------------------------------------
Increase/ Increase/
2004 2003 (Decrease) 2004 2003 (Decrease)
- ----------------------------------------- ----------- ----------- --------------- ------------ ------------ --------------
Average Gas Price/Mcf
Gulf Coast $6.06 $5.52 $0.54 $5.52 $5.42 $0.10
West Coast $5.87 $5.30 $0.57 $5.44 $5.01 $0.43
Appalachia $6.23 $5.98 $0.25 $5.88 $4.92 $0.96
Canada $5.02 $5.55 $(0.53) $4.86 $4.81 $0.05
Weighted Average $5.87 $5.58 $0.29 $5.44 $5.19 $0.25
Weighted Average After
Hedging $5.25 $4.83 $0.42 $5.04 $4.43 $0.61
Average Oil Price/bbl
Gulf Coast $36.80 $28.02 $8.78 $33.43 $29.23 $4.20
West Coast $33.56 $24.44 $9.12 $30.26 $26.08 $4.18
Appalachia $32.55 $30.51 $2.04 $29.50 $28.79 $0.71
Canada $32.25 $25.36 $6.89 $29.50 $26.19 $3.31
Weighted Average $34.58 $25.51 $9.07 $31.28 $26.81 $4.47
Weighted Average After
Hedging $27.53 $21.16 $6.37 $25.98 $21.81 $4.17
- ----------------------------------------- ----------- ----------- --------------- ------------ ------------ --------------
Operating revenues for the Exploration and Production segment increased $1.2 million for the quarter ended June 30, 2004 as compared with the quarter ended June 30, 2003. Gas production revenue after hedging increased $5.0 million due to higher weighted average prices after hedging ($0.42 per Mcf), combined with a 309 MMcf increase in production. Oil production revenue after hedging decreased $2.9 million due primarily to a 479 Mbbl decline in production offset partly by higher weighted average prices after hedging ($6.37 per barrel). Canadian oil production decreased by approximately 484 Mbbl, which was mostly the result of the September 2003 sale of the Company’s Southeast Saskatchewan oil properties.
Operating revenues for the Exploration and Production segment decreased $8.1 million for the nine months ended June 30, 2004 as compared with the nine months ended June 30, 2003. Oil production revenue after hedging decreased $21.7 million due to a 1,660 Mbbl decline in production offset partly by higher weighted average prices after hedging ($4.17 per barrel). Gas production revenue after hedging increased $13.6 million. Increases in the weighted average price of gas after hedging ($0.61 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 789 MMcf decline), which is consistent with the expected decline rates in the region. Lower West Coast production (a 364 MMcf decline), down mainly due to a decline in this segment’s South Lost Hills wells, was more than offset by a 594 MMcf increase in Canadian production. The increase in Canada is attributable to additional drilling in East Central Alberta. The decline in the South Lost Hills wells was attributable to delays in getting new wells into production.
The Exploration and Production segment’s earnings for the quarter ended June 30, 2004 were $14.8 million, an increase of $30.2 million when compared with a loss of $15.4 million for the quarter ended June 30, 2003. 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 which did not recur during the quarter ended June 30, 2004. The impact of higher oil and gas revenues increased earnings by $1.4 million (after tax). Lower operating expenses, of which
26
the earnings impact was $5.0 million (after tax), was the other major factor in the Exploration and Production segment’s earnings increase. The decrease in operating expenses, which was mostly lease operating expenses, was principally the result of the September 2003 sale of the Company’s Southeast Saskatchewan oil properties.
The Exploration and Production segment’s earnings for the nine months ended June 30, 2004 were $44.1 million, an increase of $37.1 million when compared with earnings of $7.0 million for the nine months ended June 30, 2003. As discussed above, the after tax impairment charge of $22.6 million recorded during the nine months ended June 30, 2003, which did not recur during the nine months ended June 30, 2004 was the main reason for the earnings increase. The increase also includes a $4.6 million earnings benefit related to the Company’s September 2003 sale of its Southeast Saskatchewan oil properties. When the transaction closed, the initial proceeds received were subject to an adjustment based on actual working capital and the resolution of certain income tax matters. During the quarter ended March 31, 2004, those items were resolved with the buyer and, as a result, the Company received an additional $4.6 million (U.S. dollars) of sales proceeds, which is recorded in the Adjustment of Loss on Sale of Oil and Gas Producing Properties line on the income statement. Also contributing to the increase was the fact that earnings for the nine months ended June 30, 2003 included a reduction to earnings in the amount of $0.6 million representing the cumulative effect of a change in accounting for plugging and abandonment costs that did not recur in the nine months ended June 30, 2004. Additionally, decreases in depletion, lease operating, and interest expense of $4.2 million (after tax), $10.7 million (after tax), and $1.5 million (after tax), respectively, more than offset a $5.3 million (after tax) decrease in oil and gas revenues, discussed above, and a $2.0 million increase in income tax expense due to a higher effective tax rate. The decrease in depletion and lease operating expenses primarily reflects the absence of the Company’s former Southeast Saskatchewan oil properties from results of operations for the nine months ended June 30, 2004. The decrease in interest expense was the result of lower debt balances. The higher effective tax rate resulted from the elimination of cross-border intercompany loans as a result of the sale of the Company’s Southeast Saskatchewan oil properties.
International
International Operating Revenues
- -------------------------------------- ------------------------------------------- -------------------------------------------
Three Months Ended Nine Months Ended
June 30, June 30,
- -------------------------------------- ------------------------------------------- -------------------------------------------
Increase/ Increase/
(Thousands) 2004 2003 (Decrease) 2004 2003 (Decrease)
- -------------------------------------- ------------- ------------- -------------- ------------- ------------- ---------------
Heating $12,680 $10,182 $2,498 $81,990 $75,055 $6,935
Electricity 8,428 6,294 2,134 27,593 24,326 3,267
Other 1,014 772 242 3,140 2,638 502
-------------------------------------- ------------- ------------- --------------- ------------- ------------- ---------------
$22,122 $17,248 $4,874 $112,723 $102,019 $10,704
- -------------------------------------- ------------- ------------- --------------- ------------- ------------- ---------------
International Heating and Electric Volumes
- -------------------------------------- ------------------------------------------- -------------------------------------------
Three Months Ended Nine Months Ended
June 30, June 30,
- -------------------------------------- ------------------------------------------- -------------------------------------------
Increase/ Increase/
2004 2003 (Decrease) 2004 2003 (Decrease)
- -------------------------------------- ------------- ------------- -------------- ------------- ------------- ---------------
Heating Sales (Gigajoules) (1) 1,221,736 1,144,220 77,516 7,965,921 8,203,420 (237,499)
Electricity Sales
(megawatt hours) 254,454 203,582 50,872 836,375 800,630 35,745
- -------------------------------------- ------------- ------------- --------------- ------------- ------------- ---------------
(1) Gigajoules = one billion joules. A joule is a unit of energy.
27
Operating revenues for the International segment increased $4.9 million for the quarter ended June 30, 2004 as compared with the quarter ended June 30, 2003. Colder weather was the main reason for the revenue increase. Weather in the quarter ended June 30, 2004 was approximately 22% colder than the quarter ended June 30, 2003, resulting in higher heating and electric volumes.
Operating revenues for the International segment increased $10.7 million for the nine months ended June 30, 2004 as compared with the nine months ended June 30, 2003. Overall, although revenues in Czech korunas (CZK) were lower compared with the prior year, an increase in the value of the CZK as compared to the U.S. dollar caused operating revenues denominated in U.S. dollars to increase. Revenues in CZK were lower primarily because the nine months ended June 30, 2004 was warmer than the nine months ended June 30, 2003, which is reflected in the lower heating volumes shown in the table above.
The International segment’s loss of $1.6 million for the quarter ended June 30, 2004 was $1.9 million less than the loss of $3.5 million recorded for the quarter ended June 30, 2003. Higher heat and electric margins due to colder weather were the primary reasons for the improvement.
The International segment’s earnings for the nine months ended June 30, 2004 were $13.0 million compared with a loss of $3.4 million for the nine months ended June 30, 2003. The increase can partly be attributed to a $5.2 million benefit to deferred income tax expense resulting from a change in the statutory income tax rate in the Czech Republic. During the quarter ended December 31, 2003, the government in the Czech Republic enacted legislation that gradually reduces the corporate statutory income tax from 31% to 24% (the reduction will be phased in over a three-year period). In accordance with accounting principles generally accepted in the United States of America (GAAP), the full $5.2 million benefit resulting from the change in the income tax rate was reflected as a reduction to deferred income tax expense in December 2003. Also contributing to the earnings increase, the nine months ended June 30, 2003 included a non-recurring $8.3 million impairment charge resulting from the Company’s change in accounting for goodwill. The remaining increase can be attributed to lower interest expense and an increase in the value of the CZK compared to the U.S. dollar.
Energy Marketing
Energy Marketing Operating Revenues
- ----------------------------------- -------------------------------------------- ----------------------------------------
Three Months Ended Nine Months Ended
June 30, June 30,
- ----------------------------------- -------------------------------------------- ----------------------------------------
Increase/ Increase/
(Thousands) 2004 2003 (Decrease) 2004 2003 (Decrease)
- ----------------------------------- ------------- -------------- ------------- ------------ ------------ --------------
Natural Gas (after Hedging) $67,374 $93,910 $(26,536) $240,701 $262,444 $(21,743)
Other 2 56 (54) 31 98 (67)
- ----------------------------------- ------------- -------------- --------------- ------------ ------------ --------------
$67,376 $93,966 $(26,590) $240,732 $262,542 $(21,810)
- ----------------------------------- ------------- -------------- --------------- ------------ ------------ --------------
Energy Marketing Volumes
- ----------------------------------- -------------------------------------------- ----------------------------------------
Three Months Ended Nine Months Ended
June 30, June 30,
- ----------------------------------- -------------------------------------------- ----------------------------------------
Increase/ Increase/
2004 2003 (Decrease) 2004 2003 (Decrease)
- ----------------------------------- ------------- -------------- ------------- ----------- ------------- --------------
Natural Gas - (MMcf) 9,918 11,945 (2,027) 35,908 38,417 (2,509)
- ----------------------------------- ------------- -------------- --------------- ----------- ------------- --------------
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Operating revenues for the Energy Marketing segment decreased $26.6 million and $21.8 million, respectively, for the quarter and nine months ended June 30, 2004, as compared with the quarter and nine months ended June 30, 2003. These decreases primarily reflect lower gas sales revenue due to lower throughput, which was the result of warmer weather and the migration of several large volume customers to other marketers.
The Energy Marketing segment’s earnings for the quarter ended June 30, 2004 were $1.2 million, an increase of $1.3 when compared with a loss of $0.1 million for the quarter ended June 30, 2003. The increase in earnings is mainly due to higher margins. Margins in the quarter ended June 30, 2003 were adversely affected by the combined effects of local distribution company operational constraints, price volatility and weather related demand swings. These factors did not recur in the quarter ended June 30, 2004. This improvement to margins was somewhat offset by lower throughput, which was the result of warmer weather and the migration of several large volume customers to other marketers.
The Energy Marketing segment’s earnings for the nine months ended June 30, 2004 were $5.6 million, a decrease of $0.5 million when compared with earnings of $6.1 million for the nine months ended June 30, 2003. The decrease primarily reflects lower margin on gas sales caused by warmer weather, the migration of several large volume customers to other marketers and the current high commodity pricing environment. These factors were partially offset by the positive impact of the non-recurrence of the operational constraints, price volatility and demand swings experienced during the quarter ended June 30, 2003.
Timber
Timber Operating Revenues
- ------------------------------- ------------------------------------------- ---------------------------------------------
Three Months Ended Nine Months Ended
June 30, June 30,
- ------------------------------- ------------------------------------------- ---------------------------------------------
Increase/ Increase/
(Thousands) 2004 2003 (Decrease) 2004 2003 (Decrease)
- ------------------------------- -------------- ------------- ------------ --------------- ------------- ---------------
Log Sales $4,434 $3,601 $833 $16,833 $22,051 $(5,218)
Green Lumber Sales 1,345 1,137 208 4,464 4,699 (235)
Kiln Dry Lumber Sales 7,115 6,324 791 19,647 15,634 4,013
Other 177 193 (16) 680 741 (61)
- ------------------------------- -------------- ------------- -------------- --------------- ------------- ---------------
Operating Revenues $13,071 $11,255 $1,816 $41,624 $43,125 $(1,501)
- ------------------------------- -------------- ------------- -------------- --------------- ------------- ---------------
Timber Board Feet
- ------------------------------- ------------------------------------------- ---------------------------------------------
Three Months Ended Nine Months Ended
June 30, June 30,
- ------------------------------- ------------------------------------------- ---------------------------------------------
Increase/ Increase/
(Thousands) 2004 2003 (Decrease) 2004 2003 (Decrease)
- ------------------------------- -------------- ------------- ------------ --------------- ------------- ---------------
Log Sales 1,392 1,091 301 5,208 6,828 (1,620)
Green Lumber Sales 1,956 2,296 (340) 7,154 9,312 (2,158)
Kiln Dry Lumber Sales 3,824 3,766 58 10,909 9,847 1,062
- ------------------------------- --------------- ------------- -------------- --------------- ------------- ---------------
7,172 7,153 19 23,271 25,987 (2,716)
- ------------------------------- -------------- ------------- -------------- --------------- ------------- ---------------
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Operating revenues for the Timber segment increased $1.8 million for the quarter ended June 30, 2004 as compared with the quarter ended June 30, 2003. The increase for the quarter can largely be attributed to higher sales of cherry veneer logs which command higher than average prices and higher sales of kiln dry lumber.
Operating revenues for the Timber segment decreased $1.5 million for the nine months ended June 30, 2004 as compared with the nine months ended June 30, 2003. The decrease in log sales was principally due to the Company’s August 2003 sale of approximately 70,000 acres of low cost basis timber property. Partially offsetting this decrease was a $4.0 million increase in the sale of kiln dry lumber, which was caused by an increase in activity at the Company’s mill operations. As a result of the sale discussed above, a larger percentage of timber processed in the Company’s facilities is now purchased from third parties.
The Timber segment’s earnings for the quarter ended June 30, 2003 were $0.7 million, a decrease of $0.3 million when compared with earnings of $1.0 million for the quarter ended June 30, 2003. The decrease is primarily due to a $0.8 million (after tax) adjustment to the Company’s August 2003 sale of timber properties discussed above. During the quarter ended June 30, 2004, the Company received final timber cruise information of the properties it sold and, based on that information, determined that property records pertaining to $1.3 million ($0.8 million after tax) of timber property were not properly shown as having been transferred to the purchaser. As a result, the Company removed those assets from its property records and adjusted the previously recognized gain downward by recognizing a pre tax loss of $1.3 million. This decrease was partially offset by higher margins from cherry veneer logs. The increase in kiln dry lumber was largely offset by an increase in costs associated with purchased timber.
The Timber segment’s earnings for the nine months ended June 30, 2004 were $3.9 million, a decrease of $4.8 million when compared with earnings of $8.7 million for the nine months ended June 30, 2003. The decrease was principally due to the sale of 70,000 acres of timber property, as mentioned above. While sales of cherry logs were higher during the quarter ended June 30, 2004, over the nine months they decreased by approximately 1.3 million board feet or 30% from the prior year. While kiln dry lumber sales increased, this benefit was largely offset by an increase in costs associated with purchased timber. The earnings decrease also reflects the adjustment to the Company’s fiscal 2003 sale of timber properties, as discussed above.
The Company’s unconsolidated subsidiaries consist of equity method investments that Horizon Power has made 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. 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. Seneca Energy, Model City, and ESNE sell electricity into the New York power grid.
Income from unconsolidated subsidiaries increased $0.3 million for the quarter ended June 30, 2004 as compared with the quarter ended June 30, 2003. This increase primarily reflects a lower loss from the Company’s investment in ESNE ($0.2 million) and higher income from the Company’s investment in Model City ($0.1 million).
Income from unconsolidated subsidiaries decreased $0.1 million for the nine months ended June 30, 2004 as compared with the nine months ended June 30, 2003. This decrease primarily reflects a lower loss from the Company’s investment in ESNE ($0.2 million) offset by lower income from the Company’s investment in Seneca Energy ($0.3 million).
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Interest on long-term debt decreased $2.7 million and $5.1 million, respectively, for the quarter and nine months ended June 30, 2004 as compared with the quarter and nine months ended June 30, 2003. These decreases can be attributed primarily to lower average amounts of long-term debt outstanding and lower weighted average interest rates.
Other interest charges decreased $1.7 million and $4.5 million, respectively, for the quarter and nine months ended June 30, 2004 as compared with the quarter and nine months ended June 30, 2003. These decreases resulted mainly from a decrease in the average amount of short-term debt outstanding.
The Company’s primary sources of cash during the nine-month period ended June 30, 2004 consisted of cash provided by operating activities. This source of cash was 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. Noncash items include depreciation, depletion and amortization, deferred income taxes, cumulative effect of changes in accounting, income or loss from unconsolidated subsidiaries net of cash distributions, adjustment of loss on sale of oil and gas producing properties, adjustment of gain on sale of timber properties, 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.
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 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.” The 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 and no cost collars in an attempt to manage this energy commodity price risk.
Net cash provided by operating activities totaled $408.2 million for the nine months ended June 30, 2004, an increase of $90.4 million compared with $317.8 million provided by operating activities for the nine months ended June 30, 2003. Lower working capital requirements in the Utility and Energy Marketing segments were the main reasons for this increase. The Exploration and Production segment also experienced an increase in cash flow from operations. Partially offsetting these increases, the
31
Corporate operation experienced a significant cash outflow in January 2004 due to a $23.0 million lump sum payment to a participant of the Company’s nonqualified defined benefit plan under a provision of an agreement previously entered into between the Company and the participant. Under GAAP, this payment was considered to be a partial settlement of the projected benefit obligation of the plan. Accordingly, GAAP required that the pro rata portion of the plan’s unrecognized actuarial losses resulting from experience different from that assumed and from changes in assumptions ($9.9 million before tax; $6.4 million after tax) be recognized as a settlement expense during the quarter ended March 31, 2004, as discussed above in Results of Operations.
Expenditures for Long-Lived Assets. Expenditures for long-lived assets include additions to property, plant and equipment.
The Company’s expenditures for long-lived assets totaled $122.3 million during the nine months ended June 30, 2004. The table below presents these expenditures:
- --------------------------------------------- --- ---------------- --------------------- --------------------------
Nine Months Ended June 30, 2004
(in millions of dollars)
- --------------------------------------------- --- ---------------- --------------------- --------------------------
Expenditures for
Long-Lived Assets
- --------------------------------------------- --- ---------------- --------------------- --------------------------
Utility $38.7
Pipeline and Storage 13.7
Exploration and Production 58.1
International 4.1
Timber 2.2
All Other and Corporate 5.5
- --------------------------------------------- --- ---------------- --------------------- --------------------------
Total $122.3
- --------------------------------------------- --- ---------------- --------------------- --------------------------
Utility
The majority of the Utility capital expenditures for the nine months ended June 30, 2004 were made for replacement of mains and main extensions, as well as for the replacement of service lines.
Pipeline and Storage
The majority of the Pipeline and Storage capital expenditures were made for additions, improvements, and replacements to this segment’s transmission and storage systems.
The Company and TransCanada PipeLines Limited are no longer pursuing together the pipeline project known as the Northwinds Project, due to insufficient long-term shipper commitments. The Northwinds Project would have moved gas from Canada to Leidy, Pennsylvania, from where the gas could have moved to various locations in the Northeast. Instead, as announced in February 2004, the Company is pursuing a project to expand its natural gas pipeline operations to serve new markets in New York and elsewhere in the Northeast by extending the Empire State Pipeline.* This proposed extension project will provide an upstream supply link for Phase I of the Millenium Pipeline and will transport Canadian and other natural gas supplies to downstream customers, including KeySpan Gas East Corporation, which has entered into a precedent agreement to be a major shipper, subject to the satisfaction of various conditions.* The pipeline extension will be designed to move at least 250 MMcf of natural gas per day.* The preliminary estimate of the cost for developing the Empire extension project is $140 million and the targeted in-service date is late in calendar 2006.*
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Exploration and Production
The Exploration and Production segment capital expenditures for the nine months ended June 30, 2004 included approximately $24.2 million (U.S. Dollar equivalent) for Canada, $15.8 million for the Gulf Coast region ($15.5 million for the off-shore program in the Gulf of Mexico), $11.0 million for the West Coast region and $7.1 million for the Appalachian region. These amounts included approximately $8.4 million spent to develop proved undeveloped reserves.
International
The majority of the International segment capital expenditures for the nine months ended June 30, 2004 were concentrated on improvements and replacements within the district heating and power generation plants in the Czech Republic.
Timber
The majority of the Timber segment capital expenditures for the nine months ended June 30, 2004 were made for purchases of equipment for Highland’s sawmill and kiln operations.
All Other and Corporate
The majority of the All Other and Corporate capital expenditures for the nine months ended June 30, 2004 were made for construction and improvements to the Company’s new headquarters building.
The Company continuously evaluates capital expenditures and possible investments in corporations and other entities. 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.*
Consolidated short-term debt decreased $78.3 million during the nine months ended June 30, 2004. The Company continues to consider short-term debt (consisting of short-term notes payable to banks and commercial paper) an important source of cash for temporarily financing capital expenditures and investments in corporations and other entities, 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. At June 30, 2004, the Company had outstanding short-term notes payable to banks and commercial paper of $35.3 million and $4.6 million, respectively. The Company has Securities and Exchange Commission (SEC) authorization under the Public Utility Holding Company Act of 1935, as amended (Holding Company Act), to borrow and have outstanding as much as $750.0 million of short-term debt at any time through December 31, 2005. As for bank loans, the Company maintains a number of individual (bi-lateral) uncommitted or discretionary lines of credit with certain financial institutions for general corporate purposes. Borrowings under these lines of credit are made at competitive market rates. Each of these credit lines, which aggregate to $400.0 million, is revocable at the option of the financial institution and is reviewed on an annual basis. The Company anticipates that these lines of credit will continue to be renewed.* 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 credit facility totaling $220.0 million. Of that amount, $110.0 million is committed to the Company through September 26, 2004 and $110.0 million is committed to the Company through September 30, 2005.
33
Under the Company’s committed credit facility, the Company has agreed that its debt to capitalization ratio will not, at the last day of any fiscal quarter, exceed .625 from October 1, 2003 through September 30, 2004 and .60 from October 1, 2004 and thereafter. At June 30, 2004, the Company’s debt to capitalization ratio (as calculated under the facility) was .51. The constraints specified in the committed credit facility would permit an additional $289.6 million in short-term and/or long-term debt to be outstanding before the Company’s debt to capitalization ratio would exceed .625. 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.*
Under the Company’s existing indenture covenants, at June 30, 2004, the Company would have been permitted to issue up to a maximum of $576.0 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 present liquidity position is believed to be adequate to satisfy known demands.*
The Company’s indenture pursuant to which $499.0 million (or 40%) of the Company’s long-term debt (as of June 30, 2004) 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, unless cured or waived.
The Company’s $220.0 million committed 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 and would restrict the Company’s ability to borrow 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 $20.0 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, 2004, the Company had no debt outstanding under the committed credit facility.
The Company also has authorization from the SEC, under the Holding Company Act, to issue long-term debt securities and equity securities in an aggregate amount of up to $1.5 billion during the order’s authorization period, which commenced in November 2002 and extends to December 31, 2005. The Company has an effective registration statement on file with the SEC under which it has available capacity to issue an additional $550.0 million of debt and equity securities 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 (subject to the debt to capitalization ratio constraints noted above). Any offer and sale of the above mentioned $550.0 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 amounts and timing of the issuance and sale of debt or equity securities will depend on market conditions, credit facility requirements, indenture requirements, regulatory authorizations and the capital requirements of the Company.
34
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 $23.6 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 unconsolidated subsidiaries, which are accounted for under the equity method, have capital leases of electric generating equipment having a remaining lease commitment of approximately $10.4 million. The Company has guaranteed 50% or $5.2 million of these capital lease commitments.
The following table summarizes the Company’s contractual financial commitments at June 30, 2004 and the twelve-month periods over which they occur:
- ------------------------------ -----------------------------------------------------------------------------------------------
Payments by Expected Maturity Dates
-----------------------------------------------------------------------------------------------
(Millions of Dollars) 2004 - 2005 - 2006 - 2007 - 2008 -
2005 2006 2007 2008 2009 Thereafter Total
- ------------------------------ ------------ ----------- ------------ ------------ -------------- -------------- --------------
Long-Term Debt $114.1 $14.1 $10.5 $209.3 $106.4 $796.5 $1,250.9
Short-Term Bank Notes $35.3 - - - - - $35.3
Commercial Paper $4.6 - - - - - $4.6
Operating Lease
Commitments $6.4 $4.9 $3.8 $3.0 $2.6 $2.9 $23.6
Capital Lease
Commitments $0.8 $1.0 $1.1 $0.6 $0.7 $1.0 $5.2
- ------------------------------ ------------ ----------- ------------ ------------ -------------- -------------- --------------
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 quarterly and annual period of resolution, none of this litigation, and none of these regulatory matters, are expected to change materially the Company’s present liquidity position, nor have a material adverse effect on the financial condition of the Company.*
For a complete discussion of market risk sensitive instruments, refer to “Market Risk Sensitive Instruments” in Item 7 of the Company’s 2003 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 in effect in each of the jurisdictions as approved by the appropriate regulatory authorities.
35
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 established rates for the three-year period ending September 30, 2003. 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 was approved by the NYPSC in an order issued on September 18, 2003. As approved, the Settlement continued existing base rates, but reduced the level above which earnings are shared 50/50 with customers from the previous 11.5% return on equity to 11.0%. In addition, the Settlement increased the combined pension and other post-retirement benefit expense by $8.0 million, without a corresponding increase in revenues. Most other features of Distribution Corporation’s service remained largely unchanged. In April, 2004 Distribution Corporation commenced confidential settlement negotiations with the NYPSC and other parties concerning, among other things, its revenue requirement for the year ending September 30, 2005. NYPSC Staff suspended negotiations and Distribution Corporation plans to file a base rate case in the fourth quarter of 2004 to increase annual operating revenues effective in the fourth quarter of 2005.*
On June 1, 2004, Distribution Corporation submitted a filing to the NYPSC supporting the removal of a $5 million annual bill credit originally established under the terms of the Agreement. If approved, the bill credit would no longer be applied to customer bills after October 1, 2004, and Distribution Corporation’s revenues would increase by $5 million annually. The NYPSC may accept, reject or modify Distribution Corporation’s request, and therefore the Company is unable to ascertain the outcome of the bill credit proceeding at this time.
On September 20, 2001, the NYPSC issued an order under which Distribution Corporation was directed to show cause why an action for penalties of $19.0 million should not be commenced against it for alleged violations of consumer protection requirements. On December 3, 2001, Distribution Corporation filed its response which vigorously asserted that the allegations lacked merit. Distribution Corporation continues to so believe. On July 28, 2004, the NYPSC concluded the investigation of issues raised in the order without assessing any fines or penalties. As part of the settlement of the NYPSC’s investigation, Distribution Corporation will commit $1.5 million to a new program designed to assist low-income customers who are transitioning from public assistance. Distribution Corporation has also agreed to incur costs of up to $0.3 million for an audit of customer service practices. The NYPSC has agreed not to seek any penalties should any violations be uncovered during the audit. For a discussion of related legal matters, refer to Part II, Item 1, “Legal Proceedings.”
On April 16, 2003, Distribution Corporation filed a request with the 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 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. On October 16, 2003, the parties reached a settlement of all issues. The settlement was submitted to the Administrative Law Judge, who, on November 17, 2003, issued a decision recommending adoption of the settlement. The settlement provides for a base rate increase of $3.5 million and authorizes deferral accounting for pension and other post-retirement benefit expenses. The settlement was approved by the PaPUC on December 18, 2003, and rates became effective January 15, 2004. Distribution Corporation has determined a need for additional rate relief and accordingly plans to file a request in the fourth quarter of 2004 to increase annual operating revenue effective no later than the third quarter of 2005.*
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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 November 25, 2003, the FERC issued Order 2004 “Standards of Conduct for Transmission Providers”, which it clarified in Order 2004-A on April 16, 2004 and Order 2004-B on August 2, 2004. Order 2004, which is scheduled to go into effect September 22, 2004, regulates the conduct of transmission providers (such as Supply Corporation) with their “energy affiliates.” The FERC broadened the definition of “energy affiliates” to include any affiliate of a transmission provider if that affiliate engages in or is involved in transmission (gas or electric) transactions, or manages or controls transmission capacity, or buys, sells, trades or administers natural gas or electric energy or engages in financial transactions relating to the sale or transmission of natural gas or electricity. Supply Corporation’s principal energy affiliates will be Seneca Resources, NFR and, possibly, Distribution Corporation.* Order 2004 provides that companies may request waivers, which the Company has done with respect to Distribution Corporation and is awaiting rulings. Order 2004 also provides an exemption for local distribution companies that are affiliated with interstate pipelines (such as Distribution Corporation), but the exemption is limited, with very minor exceptions, to local distribution corporations that do not make any off-system sales and do not purchase gas in ways FERC considers to be “financial or futures transactions or hedging.” Distribution Corporation currently does make such off-system sales and some of its gas purchase arrangements might be considered by FERC to be “financial or futures transactions or hedging.” Supply Corporation and Distribution Corporation would like to continue operating as they do, whether by waiver, amendment or further clarification of the new rules, or by complying with the requirements applicable if Distribution Corporation were an energy affiliate. Treating Distribution Corporation as an energy affiliate, without any waivers, would require changes in the way Supply Corporation and Distribution Corporation operate which would decrease efficiency, but probably would not increase capital or operating expenses to an extent that would be material to the financial condition of the Company.* Until there is further clarification from the FERC on the scope of these exemptions and rulings on the Company’s waiver requests, the Company is unable to predict the ultimate impact Order 2004 will have on the Company. Pending such clarification, Distribution Corporation currently plans in the short term to stop making off-systm sales, effective September 22, 2004.* The Company does not expect that such a change would have a material effect on the Company's results of operations, as margins resulting from off-system sales are minimal as a result of profit sharing with retail customers.*
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.
Environmental Matters. The Company is subject to various federal, state and local laws and regulations relating to the protection of the environment. The Company has established procedures for 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, 2004, the Company has estimated its remaining clean-up costs related to former manufactured gas plant sites and third party waste disposal sites will be $14.0 million.* This liability has been recorded on the Consolidated Balance Sheet at June 30, 2004. Other than discussed in Note G of the Company’s 2003 Form 10-K (referred to below), the Company is currently not aware of any material additional exposure to environmental liabilities. However, changes in environmental regulations or other factors could adversely impact the Company.*
37
For further discussion refer to Note G — Commitments and Contingencies under the heading “Environmental Matters” in Item 8 of the Company’s 2003 Form 10-K, and to Part II, Item 1, “Legal Proceedings.”
The Company is including the following cautionary statement in this Form 10-Q to make applicable and take advantage of the safe harbor provisions of the Private Securities Litigation Reform Act of 1995 for any forward-looking statements made by, or on behalf of, the Company. Forward-looking statements include statements concerning plans, objectives, goals, projections, strategies, future events or performance, and underlying assumptions and other statements that 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 in this report, including, without limitation, those that are designated with an asterisk (“*”) and those which are identified by the use of the words “anticipates,” “estimates,” “expects,” “intends,” “plans,” “predicts,” “projects,” and similar expressions are “forward-looking” statements as defined in the Private Securities Litigation Reform Act of 1995 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:
| 1. | Changes in economic conditions, including economic disruptions caused by terrorist activities or acts of war;S |
| 2. | Changes in demographic patterns and weather conditions, including the occurrence of severe weather; |
| 3. | Changes in the availability and/or price of natural gas, oil, and coal; |
| 4. | Inability to obtain new customers or retain existing ones; |
| 5. | Significant changes in competitive factors affecting the Company; |
| 6. | Governmental/regulatory actions, initiatives and proceedings, including those affecting acquisitions, financings, allowed rates of return, industry and rate structure, franchise renewal, and environmental/safety requirements; |
| 7. | Unanticipated impacts of restructuring initiatives in the natural gas and electric industries; |
| 8. | Significant changes from expectations in actual capital expenditures and operating expenses and unanticipated project delays or changes in project costs; |
| 9. | The nature and projected profitability of pending and potential projects and other investments; |
| 10. | Occurrences affecting the Company’s ability to obtain funds from operations, debt or equity to finance needed capital expenditures and other investments; |
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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations (Concl.)
| 11. | Uncertainty of oil and gas reserve estimates; |
| 12. | Ability to successfully identify and finance acquisitions and ability to operate and integrate existing and any subsequently acquired business or properties; |
| 13. | Ability to successfully identify, drill for and produce economically viable natural gas and oil reserves; |
| 14. | Significant changes from expectations in the Company’s actual production levels for natural gas or oil; |
| 15. | Changes in the availability and/or price of derivative financial instruments; |
| 16. | Changes in the price of natural gas or oil and the effect of such changes on the accounting treatment or valuation of financial instruments or the Company’s natural gas and oil reserves; |
| 17. | Inability of the various counterparties to meet their obligations with respect to the Company’s financial instruments; |
| 18. | Regarding foreign operations, changes in trade and monetary policies, inflation and exchange rates, taxes, operating conditions, laws and regulations related to foreign operations, and political and governmental changes; |
| 19. | Significant changes in tax rates or policies or in rates of inflation or interest; |
| 20. | Significant changes in the Company’s relationship with its employees or contractors and the potential adverse effects if labor disputes, grievances or shortages were to occur; |
| 21. | Changes in accounting principles or the application of such principles to the Company; |
| 22. | Changes in laws and regulations to which the Company is subject, including tax, environmental, safety and employment laws and regulations; or |
| 23. | The cost and effects of legal and administrative claims against the Company. |
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.
The following information includes the evaluation of disclosure controls and procedures by the Company’s Chief Executive Officer and Principal Financial Officer, along with any significant changes in internal controls of the Company.
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
39
Item 4. Controls and Procedures (Concl.)
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 Principal Financial Officer, 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 Principal Financial Officer concluded that the Company’s disclosure controls and procedures were effective as of the end 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 generally accepted accounting principles in the United States of America. There were no changes in the Company’s internal control over financial reporting that occurred during the period 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 Information
In 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. Discovery has begun on the merits of the claims and the case will eventually be tried or settled.
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. The 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-defendant. Distribution Corporation believes and will vigorously assert that the plaintiff’s allegations lack merit. The Court changed venue of the action to New York State Supreme Court, Erie County. The litigation is in the early stages of discovery. For a discussion of a related matter before the NYPSC, refer to Part I, Item 2 — MD&A of this report under the heading “Rate Matters.”
On December 22, 2003, the Pennsylvania Department of Environmental Protection (DEP) issued an order to Seneca to halt its timber harvesting operations on 21,000 acres in Cameron, Elk and McKean
40
Item 1. Legal Proceedings (Concl.)
counties in Pennsylvania. The order asserts certain violations of DEP regulations concerning erosion, sedimentation and stream crossings. The order requires Seneca to apply for certain permits, control erosion, submit plans for removal of water encroachments not included in permit applications, notify the DEP of additional current or planned timber harvesting operations, and grant the DEP access to timber acreage. On January 9, 2004, Seneca filed with the Pennsylvania Environmental Hearing Board (Hearing Board) a notice of appeal, objecting to each finding and order contained in the order, and asserting that the DEP’s findings are factually incorrect, an arbitrary exercise of the DEP’s functions and duties, and contrary to law. Also on January 9, 2004, Seneca filed with the Hearing Board a petition requesting a stay of operation of portions of the order. On January 16, 2004, the parties settled Seneca’s request for a stay. Seneca has resumed its timber harvesting operations pursuant to the terms of the settlement. The settlement preserves various issues raised by the DEP’s order for a hearing on the merits of Seneca’s notice of appeal. Seneca is engaged in negotiations to resolve this dispute on acceptable terms, and litigation deadlines have been extended to accommodate those discussions.
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 6 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 litigation or regulatory matters could have a material effect on earnings and cash flows in the quarterly and annual period of resolution, none of this litigation, and none of these regulatory matters, are expected to change materially the Company’s present liquidity position, nor have a material adverse effect on the financial condition of the Company.*
On April 1, 2004, the Company issued a total of 1,800 unregistered shares of Company common stock to the six non-employee directors of the Company, 300 shares to each such director. All of these shares were issued as partial consideration for the directors’ services during the quarter ended June 30, 2004, 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.
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Issuer Purchases of Equity Securities
- ------------------------- ---------------------- ---------------------- ---------------------- ----------------------
Total Number of Maximum Number
Shares Purchased as of Shares that May
Part of Publicly Yet Be Purchased
Total Number of Announced Share Under Share
Shares Average Price Repurchase Plans or Repurchase Plans
Period Purchased (a) Paid per Share Programs or Programs
- ------------------------- ---------------------- ---------------------- ---------------------- ----------------------
Apr. 1 - 30, 2004 22,414 $24.53 - -
- ------------------------- ---------------------- ---------------------- ---------------------- ----------------------
May 1 - 31, 2004 107,611 $25.18 - -
- ------------------------- ---------------------- ---------------------- ---------------------- ----------------------
June 1 - 30, 2004 55,263 $25.03 - -
- ------------------------- ---------------------- ---------------------- ---------------------- ----------------------
Total 185,288 $25.06 - -
- ------------------------- ---------------------- ---------------------- ---------------------- ----------------------
(a) Represents shares of common stock of the Company purchased by the Company in connection with employee award and option plans, pursuant to which option holders and/or holders of restricted stock tendered shares of common stock for the payment of option exercise prices and/or applicable withholding taxes.
(a) Exhibits
Exhibit
Number Description of Exhibit
------- ----------------------
12 Statements regarding Computation of Ratios:
Ratio of Earnings to Fixed Charges for the Twelve Months Ended June 30, 2004 and the Fiscal Years
Ended September 30, 1999 through 2003.
31.1 Written statements of Chief Executive Officer pursuant to Rule 13a-14(a) or Rule 15d-14(a) under
the Securities Exchange Act of 1934.
31.2 Written statements of Principal Financial Officer pursuant to Rule 13a-14(a) or Rule 15d-14(a)
under the Securities Exchange Act of 1934.
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,
2004 and 2003.
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(b) Reports on Form 8-K
A report on Form 8-K dated March 31, 2004 was furnished to the SEC on April 1, 2004 regarding a
press release issued by the Company concerning the retirement of Joseph P. Pawlowski, its
Treasurer, Principal Financial Officer and Principal Accounting Officer; the appointment of Ronald
J. Tanski as Treasurer and Principal Financial Officer; and the appointment of Karen M. Camiolo as
Controller and Principal Accounting Officer. This information was furnished under Item 9, "Regulation
FD Disclosure."
A report on Form 8-K dated April 27, 2004 was furnished to the SEC on April 28, 2004 regarding a
press release issued by the Company concerning earnings for the quarter ended March 31, 2004. The
report was furnished under Item 12, "Results of Operations and Financial Condition."
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SIGNATURES
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/ R. J. Tanski
-----------------------------------------
R. J. Tanski
Treasurer and Principal Financial Officer
/s/ K. M. Camiolo
-------------------------------------------
K. M. Camiolo
Controller and Principal Accounting Officer
Date: August 9, 2004
44
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, 2004 and the Fiscal Years Ended
September 30, 1999 through 2003
Exhibit 31.1 Written statements of Chief Executive Officer pursuant to Rule 13a-14(a) or
Rule 15d-14(a) under the Securities Exchange Act of 1934.
Exhibit 31.2 Written statements of Principal Financial Officer pursuant to Rule 13a-14(a) or
Rule 15d-14(a) under the Securities Exchange Act of 1934.
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 June 30, 2004
and 2003