- ------------------------------------------------------------------------------- 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, 1998 ------------- Commission File Number 1-3880 ----------------------------- NATIONAL FUEL GAS COMPANY (Exact name of registrant as specified in its charter) New Jersey 13-1086010 ---------- ---------- (State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification No.) 10 Lafayette Square Buffalo, New York 14203 ----------------- ----- (Address of principal executive offices) (Zip Code) (716) 857-6980 -------------- (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 the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date: Common stock, $1 par value, outstanding at July 31, 1998: 38,446,311 shares. - -------------------------------------------------------------------------------
Company or Group of Companies for which Report is Filed: - ------------------------------------------------------- NATIONAL FUEL GAS COMPANY (Company or Registrant) DIRECT SUBSIDIARIES: National Fuel Gas Distribution Corporation (Distribution Corporation) National Fuel Gas Supply Corporation (Supply Corporation) Seneca Resources Corporation (Seneca) Highland Land & Minerals, Inc. (Highland) Leidy Hub, Inc. (Leidy Hub) Data-Track Account Services, Inc. (Data-Track) National Fuel Resources, Inc. (NFR) Horizon Energy Development, Inc. (Horizon) Upstate Energy Inc. (Upstate) Niagara Independence Marketing Company (NIM) Seneca Independence Pipeline Company (SIP) Utility Constructors, Inc. (UCI) INDEX Part I. Financial Information Page ----------------------------- ---- Item 1. Financial Statements a. Consolidated Statements of Income and Earnings Reinvested in the Business - Three Months and Nine Months Ended June 30, 1998 and 1997 4 - 5 b. Consolidated Balance Sheets - June 30, 1998 and September 30, 1997 6 - 7 c. Consolidated Statement of Cash Flows - Nine Months Ended June 30, 1998 and 1997 8 d. Notes to Consolidated Financial Statements 9 - 19 Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations 19 - 41 Item 3. Quantitative and Qualitative Disclosures About Market Risk 41 Part II. Other Information -------------------------- Item 1. Legal Proceedings * Item 2. Changes in Securities 41 Item 3. Defaults Upon Senior Securities * Item 4. Submission of Matters to a Vote of Security Holders * Item 5. Other Information 41 Item 6. Exhibits and Reports on Form 8-K 42 Signature 43 * The Company has nothing to report under this item.
This Form 10-Q contains "forward-looking statements" as defined by the Private Securities Litigation Reform Act of 1995. Forward-looking statements should be read with the cautionary statements included in this Form 10-Q at Item 2 "Management's Discussion and Analysis of Financial Condition and Results of Operations" (MD&A), under the heading "Safe Harbor for Forward-Looking Statements." Forward-looking statements are all statements other than statements of historical fact, including, without limitation, those statements that are designated with a "1" following the statement, as well as those statements that are identified by the use of the words "anticipates," "estimates," "expects," "intends," "plans," "predicts," "projects," and similar expressions.
Part I. - Financial Information - ------------------------------- Item 1. - Financial Statements - ------------------------------ National Fuel Gas Company ------------------------- Consolidated Statements of Income and Earnings ---------------------------------------------- Reinvested in the Business -------------------------- (Unaudited) ----------- Three Months Ended June 30, ------------------ 1998 1997 ---- ---- (Thousands of Dollars, Except Per Share Amounts) INCOME Operating Revenues $242,447 $246,051 -------- -------- Operating Expenses Purchased Gas 65,088 82,954 Fuel Used in Heat and Electric Generation 8,789 245 Operation 64,792 59,448 Maintenance 6,440 6,334 Property, Franchise and Other Taxes 20,716 23,194 Depreciation, Depletion and Amortization 31,019 29,286 Income Taxes - Net 11,877 13,307 -------- -------- 208,721 214,768 Operating Income 33,726 31,283 Other Income 5,651 1,275 -------- -------- Income Before Interest Charges and Minority Interest in Foreign Subsidiaries 39,377 32,558 -------- -------- Interest Charges Interest on Long-Term Debt 14,636 10,418 Other Interest 5,427 3,235 -------- -------- 20,063 13,653 Minority Interest in Foreign Subsidiaries (207) - --------- -------- Net Income Available for Common Stock 19,107 18,905 EARNINGS REINVESTED IN THE BUSINESS Balance at April 1 446,565 486,696 -------- -------- 465,672 505,601 Dividends on Common Stock (1998 - $.45; 1997 - $.435) 17,224 16,541 -------- -------- Balance at June 30 $448,448 $489,060 ======== ======== Earnings Per Common Share: Basic $0.50 $0.50 ===== ===== Diluted $0.49 $0.49 ===== ===== Weighted Average Common Shares Outstanding: Used in Basic Calculation 38,358,065 38,141,019 ========== ========== Used in Diluted Calculation 38,719,074 38,485,420 ========== ========== See Notes to Consolidated Financial Statements
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, ----------------- (Thousands of Dollars, Except Per Share Amounts) 1998 1997 ---- ---- INCOME Operating Revenues $1,076,116 $1,108,247 ---------- ---------- Operating Expenses Purchased Gas 418,228 498,617 Fuel Used in Heat and Electric Generation 26,010 1,363 Operation 224,128 197,603 Maintenance 19,347 18,300 Property, Franchise and Other Taxes 75,607 83,427 Depreciation, Depletion and Amortization 88,936 84,971 Impairment of Oil and Gas Producing Properties 128,996 - Income Taxes - Net 25,085 69,719 ---------- ---------- 1,006,337 954,000 ---------- ---------- Operating Income 69,779 154,247 Other Income 32,413 2,598 ---------- ---------- Income Before Interest Charges and Minority Interest in Foreign Subsidiaries 102,192 156,845 ---------- ---------- Interest Charges Interest on Long-Term Debt 37,517 30,882 Other Interest 26,260 11,358 ---------- ---------- 63,777 42,240 ---------- ---------- Minority Interest in Foreign Subsidiaries (3,036) - ---------- ---------- Income Before Cumulative Effect 35,379 114,605 Cumulative Effect of Change in Accounting for Depletion (9,116) - ---------- ---------- Net Income Available for Common Stock 26,263 114,605 EARNINGS REINVESTED IN THE BUSINESS Balance at October 1 472,595 422,874 ---------- ---------- 498,858 537,479 Dividends on Common Stock (1998 - $1.32; 1997 - $1.275) 50,410 48,419 ---------- ---------- Balance at June 30 $448,448 $489,060 ========== ========== Basic Earnings Per Common Share: Income Before Cumulative Effect $0.93 $3.01 Cumulative Effect of Change in Accounting for Depletion (0.24) - ----- ----- Net Income Available for Common Stock $0.69 $3.01 ===== ===== Diluted Earnings Per Common Share: Income Before Cumulative Effect $0.92 $2.98 Cumulative Effect of Change in Accounting for Depletion (0.24) - ----- ----- Net Income Available for Common Stock $0.68 $2.98 ===== ===== Weighted Average Common Shares Outstanding: Used in Basic Calculation 38,272,907 38,060,709 ========== ========== Used in Diluted Calculation 38,688,564 38,408,273 ========== ========== See Notes to Consolidated Financial Statements
Item 1. Financial Statements (Cont.) - ------------------------------------ National Fuel Gas Company ------------------------- Consolidated Balance Sheets --------------------------- June 30, 1998 September 30, (Unaudited) 1997 ----------- ------------- (Thousands of Dollars) ASSETS Property, Plant and Equipment $3,082,496 $2,668,478 Less - Accumulated Depreciation, Depletion and Amortization 910,642 849,112 ---------- ---------- 2,171,854 1,819,366 ---------- ---------- Current Assets Cash and Temporary Cash Investments 38,910 14,039 Receivables - Net 138,402 107,417 Unbilled Utility Revenue 13,444 20,433 Gas Stored Underground 17,133 29,856 Materials and Supplies - at average cost 23,134 19,115 Prepayments 30,080 17,807 ---------- ---------- 261,103 208,667 ---------- ---------- Other Assets Recoverable Future Taxes 91,011 91,011 Unamortized Debt Expense 22,878 23,394 Other Regulatory Assets 49,981 48,350 Investment in Unconsolidated Foreign Subsidiary - 18,887 Deferred Charges 9,521 12,025 Other 73,869 45,631 ---------- ---------- 247,260 239,298 ---------- ---------- $2,680,217 $2,267,331 ========== ========== See Notes to Consolidated Financial Statements
Item 1. Financial Statements (Cont.) - ------------------------------------ National Fuel Gas Company ------------------------- Consolidated Balance Sheets --------------------------- June 30, 1998 September 30, (Unaudited) 1997 ----------- ------------- (Thousands of Dollars) CAPITALIZATION AND LIABILITIES Capitalization: Common Stock Equity Common Stock, $1 Par Value Authorized - 200,000,000 Shares; Issued and Outstanding - 38,388,902 Shares and 38,165,888 Shares, Respectively $ 38,389 $ 38,166 Paid in Capital 412,925 405,028 Earnings Reinvested in the Business 448,448 472,595 Cumulative Translation Adjustment (1,059) (2,085) ----------- ---------- Total Common Stock Equity 898,703 913,704 Long-Term Debt, Net of Current Portion 795,968 581,640 ---------- ---------- Total Capitalization 1,694,671 1,495,344 ---------- ---------- Minority Interest in Foreign Subsidiaries 23,902 - ---------- ---------- Current and Accrued Liabilities Notes Payable to Banks and Commercial Paper 201,900 92,400 Current Portion of Long-Term Debt 153,437 103,359 Accounts Payable 70,189 74,105 Amounts Payable to Customers 15,519 10,516 Other Accruals and Current Liabilities 146,659 83,793 ---------- ---------- 587,704 364,173 ---------- ---------- Deferred Credits Accumulated Deferred Income Taxes 241,059 288,555 Taxes Refundable to Customers 19,427 19,427 Unamortized Investment Tax Credit 11,584 12,041 Other Deferred Credits 101,870 87,791 ---------- ---------- 373,940 407,814 ---------- ---------- Commitments and Contingencies - - ---------- ---------- $2,680,217 $2,267,331 ========== ========== See Notes to Consolidated Financial Statements
Item 1. - Financial Statements (Cont.) - -------------------------------------- National Fuel Gas Company ------------------------- Consolidated Statement of Cash Flows ------------------------------------ (Unaudited) ----------- Nine Months Ended June 30, ----------------- (Thousands of Dollars) 1998 1997 ---- ---- OPERATING ACTIVITIES Net Income Available for Common Stock $ 26,263 $114,605 Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities: Cumulative Effect of Change in Accounting for Depletion 9,116 - Impairment of Oil and Gas Producing Properties 128,996 - Depreciation, Depletion and Amortization 88,936 84,971 Deferred Income Taxes (44,829) 3,909 Minority Interest in Foreign Subsidiaries 3,036 - Other (215) 4,540 Change in: Receivables and Unbilled Utility Revenue (6,357) (62,034) Gas Stored Underground and Materials and Supplies 14,422 26,116 Unrecovered Purchased Gas Costs - (233) Prepayments (8,930) 13,907 Accounts Payable (14,237) (10,245) Amounts Payable to Customers 5,003 2,170 Other Accruals and Current Liabilities 40,088 61,629 Other Assets and Liabilities - Net 1,332 31,539 -------- -------- Net Cash Provided by Operating Activities 242,624 270,874 -------- -------- INVESTING ACTIVITIES Capital Expenditures (315,223) (134,292) Investment in Subsidiaries, Net of Cash Acquired (111,179) (21,605) Other 2,065 243 -------- -------- Net Cash Used in Investing Activities (424,337) (155,654) -------- -------- FINANCING ACTIVITIES Change in Notes Payable to Banks and Commercial Paper 105,187 (67,600) Proceeds from Issuance of Long-Term Debt 198,750 - Reduction of Long-Term Debt (53,048) (785) Dividends Paid on Common Stock (49,734) (47,718) Proceeds from Issuance of Common Stock 5,429 6,930 -------- -------- Net Cash Provided by (Used in) Financing Activities 206,584 (109,173) -------- -------- Net Increase in Cash and Temporary Cash Investments 24,871 6,047 Cash and Temporary Cash Investments at October 1 14,039 19,320 -------- -------- Cash and Temporary Cash Investments at June 30 $ 38,910 $ 25,367 ======== ======== See Notes to Consolidated Financial Statements
Item 1. Financial Statements (Cont.) - ------------------------------------- National Fuel Gas Company ------------------------- Notes to Consolidated Financial Statements ------------------------------------------ Note 1 - Summary of Significant Accounting Policies Principles of Consolidation. During the quarter ended June 30, 1998, Horizon's wholly-owned subsidiary, Horizon Energy Development B.V. (Horizon B.V.) (name changed from Beheer-En-Beleggingsmaatschappij Bruwabel, B.V. in April 1998) increased its ownership interest in Prvni severozapadni teplarenska, a.s. (PSZT) from 75.3% at March 31, 1998 to 85.9% at June 30, 1998. Horizon B.V. also increased its ownership interest in Severoceske Teplarny, a.s. and its subsidiaries (SCT) from 75.2% at March 31, 1998 to 82.7% at June 30, 1998. The Company consolidates both PSZT and SCT into its accounts. The equity method was used to account for Horizon B.V.'s minority ownership interest in SCT during fiscal 1997. The acquisitions of SCT and PSZT have been accounted for in accordance with the purchase method as specified by Accounting Principles Board Opinion Number 16, "Business Combinations" (APB 16). The acquisitions resulted in approximately $20.6 million of goodwill, which is being amortized over a twenty year period. This goodwill ($20.1 million at June 30, 1998) is recorded in Other Assets in the Company's Consolidated Balance Sheet at June 30, 1998. The final amount of goodwill may be subject to further purchase price adjustments. "Minority Interest in Foreign Subsidiaries" represents the minority stockholders' share of the equity and net income of SCT and PSZT. Quarterly Earnings. The Company, in its opinion, has included all adjustments that are necessary for a fair statement of the results of operations for the reported periods. The consolidated financial statements and notes thereto, included herein, should be read in conjunction with the financial statements and notes for the years ended September 30, 1997, 1996 and 1995 that are included in the Company's combined Annual Report to Shareholders/Form 10-K for 1997. The fiscal 1998 consolidated financial statements will be examined by the Company's independent accountants after the end of the fiscal year. The earnings for the nine months ended June 30, 1998 (exclusive of the cumulative effect of a change in accounting for depletion and the impairment of oil and gas producing properties, both of which are discussed below) should not be taken as a prediction of earnings for the entire fiscal year ending September 30, 1998. Most of the Company's business is seasonal in nature and is influenced by weather conditions. Because of the seasonal nature of the Company's heating business, earnings during the winter months normally represent a substantial part of earnings for the entire fiscal year. Earnings during the summer months tend to decline and may reach a point where expenses exceed revenues. The impact of abnormal weather on earnings during the heating season is partially reduced by the operation of a weather normalization clause (WNC) included in Distribution Corporation's New York tariff. The WNC is effective for October through May billings. Distribution Corporation's tariff for its Pennsylvania jurisdiction does not have a WNC. In addition, Supply Corporation's straight fixed-variable rate design, which allows for recovery of substantially
Item 1. Financial Statements (Cont.) - ------------------------------------- all fixed costs in the demand or reservation charge, reduces the earnings impact of weather fluctuations. Cumulative Effect of Change in Accounting. Effective October 1, 1997, Seneca changed its method of depletion for oil and gas properties from the gross revenue method to the units of production method. The new method was adopted because it provides a better measure of depletion expense and is the preferable method used by oil and gas producing companies. Seneca's recent acquisition activities have increased its size and scope of operations in relation to those of the Company. Consequently, the change in method was warranted at such time. (See further discussion of acquisitions in Note 6 - Acquisition of HarCor Energy Inc. (HarCor) and in Item 2, Management's Discussion and Analysis under "Exploration and Production".) The units of production method has been applied retroactively to prior years to determine the cumulative effect through October 1, 1997. This cumulative effect reduced earnings for the nine months ended June 30, 1998, by $9.1 million, net of income tax. Depletion of oil and gas properties for the quarter and nine months ended June 30, 1998, has been computed under the units of production method. The effect of the change from the gross revenue method to the units of production method increased net income for the quarter ended June 30, 1998 by $879,000 ($0.02 per common share, basic and diluted). For the nine months ended June 30, 1998, the effect of the change increased income before cumulative effect and net income by $1,716,000 ($0.04 per common share, basic and diluted). Pro forma amounts for the three months ended June 30, 1997 and the nine months ended June 30, 1998 and 1997 shown below, assume the retroactive application of the new depletion method. Actual amounts for the three months ended June 30 1998 are also shown for comparative purposes. Three Months Nine Months Ended Ended June 30, June 30, --------------- -------------- 1998 1997 1998 1997 ---- ---- ---- ---- (Thousands of Dollars, except per share amounts) Net Income Available for Common Stock $19,107 $19,007 $35,379 $114,604 ======= ======= ======= ======== Earnings Per Common Share: Basic $0.50 $0.50 $0.93 $3.01 ===== ===== ===== ===== Diluted $0.49 $0.49 $0.92 $2.98 ===== ===== ===== ===== Oil and Gas Exploration and Development Costs. Oil and Gas property acquisition, exploration and development costs are capitalized under the full-cost method of accounting as prescribed by the Securities and Exchange Commission (SEC). All costs directly associated with property acquisition, exploration and development activities are capitalized, with the principal limitation that such capitalized amounts not exceed the present value of estimated future net revenues (discounted at 10%) from production of proved gas and oil reserves plus the lower of cost or market of unevaluated Item 1. Financial Statements (Cont.)
Item 1. Financial Statements (Cont.) - ------------------------------------ properties, net of related income tax effect (the full-cost ceiling). Future net revenue is estimated based on end-of-quarter prices adjusted for contracted price changes. If capitalized costs exceed the full-cost ceiling at the end of any quarter, a permanent impairment is required to be charged to earnings in that quarter. Such a charge has no effect on the Company's cash flow. The surplus of crude oil world-wide has caused oil prices to drop to their lowest level in recent years, and gas prices continue to be negatively impacted by the warmer than normal 1997/1998 winter. Due to these price declines, Seneca's capitalized costs under the full-cost method of accounting exceeded the full-cost ceiling at March 31, 1998. Seneca was required to recognize an impairment of its oil and gas producing properties in the quarter ended March 31, 1998. This charge amounted to $129.0 million (pretax) and reduced net income for the nine months ended June 30, 1998 by $79.1 million ($2.07 per common share, basic; $2.04 per common share, diluted). No impairment charge was required for the quarter ended June 30, 1998. Consolidated Statement of Cash Flows. For purposes of the Consolidated Statement of Cash Flows, the Company considers all highly liquid debt instruments purchased with a maturity of generally three months or less to be cash equivalents. Cash interest payments during the nine months ended June 30, 1998 and 1997 amounted to $38.0 million and $35.0 million, respectively. Net income taxes paid during the nine months ended June 30, 1998 and 1997 amounted to $33.0 million and $55.2 million, respectively. Details of the SCT, PSZT and HarCor stock acquisitions during the nine months ended June 30, 1998, are as follows (dollars in millions): SCT PSZT HarCor Total Assets acquired $71.0 $143.5 $104.5 $319.0 Liabilities assumed (27.2) (79.6) (72.1) (178.9) Existing investment at acquisition (18.9) - - (18.9) Cash acquired at acquisition (6.3) (0.9) (2.8) (10.0) ----- ----- ----- ------ Cash paid, net of cash acquired $18.6 $63.0 $29.6 $111.2 ===== ===== ===== ====== Reclassification. Certain prior year amounts have been reclassified to conform with current year presentation. Earnings per Common Share. Basic earnings per common share is computed by dividing income available for common stock by the weighted average number of common shares outstanding for the period. Diluted earnings per common share reflects the potential dilution that could occur if securities or other contracts to issue common stock were exercised or converted into common stock. Such additional shares are added to the denominator of the basic earnings per common share calculation in order to calculate diluted earnings per common share. The only potentially dilutive securities the Company has outstanding are stock options. The diluted weighted average shares outstanding shown on the Consolidated Statement of Income reflects the potential dilution as a result of these stock options. Such dilution was determined using the Treasury Stock Method as required by Statement of Financial Accounting Standards No. 128, "Earnings per Share."
Item 1. Financial Statements (Cont.) - ------------------------------------- New Accounting Pronouncements: Employers' Disclosures about Pensions and Other Postretirement Benefits. In February 1998, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standard No. 132, "Employers' Disclosures about Pensions and Other Postretirement Benefits" (SFAS 132). SFAS 132 supersedes the disclosure requirements in SFAS 87, "Employers' Accounting for Pensions", SFAS 88, "Employers' Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits", and SFAS 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions". SFAS 132 does not change the measurement or recognition of the Company's pension or other postretirement benefit plans. SFAS 132 standardizes the disclosure requirements for pension and other postretirement benefits to the extent practicable, requires additional information on changes in the benefit obligations and fair values of plan assets that will facilitate financial analysis and eliminates certain disclosures that are no longer useful under SFAS 87, 88 and 106. The Statement is effective for fiscal year 1999. Earlier application is encouraged. SFAS 132 requires restatement of disclosures for prior periods for comparative purposes. Accounting for Derivative Instruments and Hedging Activities. In June 1998, the FASB issued SFAS 133, "Accounting for Derivative Instruments and Hedging Activities" (SFAS 133). SFAS 133 establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities. It requires that an entity recognize all derivatives as either assets or liabilities in the statement of financial position and measure those instruments at fair value. The intended use of the derivative and its designation as either (1) hedging the exposure to changes in the fair value of a recognized asset or liability or a firm commitment, (2) hedging the exposure to variable cash flows of a forecasted transaction, or (3) hedging the foreign currency exposure of a net investment in a foreign operation, will determine when the gains or losses on the derivatives are to be reported in earnings and when they are to be reported as a component of comprehensive income. The Company is required to adopt SFAS 133 in the first quarter of fiscal 2000. However, earlier application is permitted. Initial application of SFAS 133 should be as of the beginning of a fiscal quarter, at which time hedging relationships must be designated and documented in accordance with the provisions of SFAS 133. SFAS 133 is not to be applied retroactively to financial statements of prior periods. Management is currently in the process of determining the impact on the Company of adopting SFAS 133.
Item 1. Financial Statements (Cont.) - ------------------------------------ Note 2 - Income Taxes The components of federal and state income taxes included in the Consolidated Statement of Income are as follows (in thousands): Nine Months Ended June 30, ----------------- 1998 1997 ---- ---- Operating Expenses: Current Income Taxes - Federal $59,208 $59,199 State 6,814 6,611 Foreign 3,892 - Deferred Income Taxes (44,829) 3,909 -------- ------- 25,085 69,719 Other Income: Deferred Investment Tax Credit (457) (502) Minority Interest in Foreign Subsidiaries (1,576) - Cumulative Effect of Change in Accounting (5,737) - -------- ------- Total Income Taxes $17,315 $69,217 ======= ======= 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, ----------------- 1998 1997 ---- ---- Net income available for common stock $ 26,263 $114,605 Total income taxes 17,315 69,217 -------- -------- Income before income taxes $ 43,578 $183,822 ======== ======== Income tax expense, computed at statutory rate of 35% $ 15,252 $ 64,338 Increase (reduction) in taxes resulting from: Current state income taxes, net of federal income tax benefit 4,429 4,165 Depreciation 1,738 1,972 Miscellaneous (4,104) (1,258) --------- -------- Total Income Taxes $ 17,315 $ 69,217 ======== ========
Item 1. Financial Statements (Cont.) - ------------------------------------ Significant components of the Company's deferred tax liabilities (assets) were as follows (in thousands): At June 30, 1998 At September 30, 1997 ------------------- ----------------------- Deferred Tax Liabilities: Excess of tax over book depreciation $137,207 $190,913 Exploration and intangible well drilling costs 135,481 117,759 Other 52,161 62,189 -------- -------- Total Deferred Tax Liabilities 324,849 370,861 -------- -------- Deferred Tax Assets: Overheads capitalized for tax purposes (21,768) (19,406) Other (62,022) (62,900) --------- -------- Total Deferred Tax Assets (83,790) (82,306) --------- -------- Total Net Deferred Income Taxes $241,059 $288,555 ======== ======== The primary issues related to Internal Revenue Service audits of the Company for the years 1977 - 1994 were settled early in calendar year 1998. Net income for the nine months ended June 30, 1998 was increased by approximately $5 million as a result of interest, net of tax and other adjustments, related to this settlement. Note 3 - Capitalization Common Stock. During the nine months ended June 30, 1998, the Company issued 22,194 shares of common stock under the Company's section 401(k) Plans, 28,796 shares to participants in the Company's Dividend Reinvestment Plan and 9,334 shares to participants in the Company's Customer Stock Purchase Plan. Additionally, 162,690 shares of common stock were issued under the Company's stock option and stock award plans. On December 11, 1997, 658,500 stock options were granted at an exercise price of $44.875 per share. On June 18, 1998, 111,500 stock options were granted at an exercise price of $41.875. At the Annual Meeting of Shareholders in February 1998, the Company's shareholders voted to increase the number of shares of authorized Company common stock from 100,000,000 shares to 200,000,000 shares. This change became effective April 3, 1998, upon the filing of a certificate of amendment with the Secretary of State of the State of New Jersey. Preferred Stock. At the Annual Meeting of Shareholders in February 1998, the Company's shareholders voted to eliminate the Company's authorized 3,200,000 shares of $25 par value preferred stock and replace it with an authorized amount of 10,000,000 shares of $1 par value preferred stock. This change became effective April 3, 1998, upon the filing of a certificate of amendment
Item 1. Financial Statements (Cont.) - ----------------------------------- with the Secretary of State of the State of New Jersey. The Company does not have any preferred stock outstanding at this time. Long-Term Debt. In May 1998, the Company issued $200.0 million of 6.303% medium-term notes due to mature in May 2008. After deducting underwriting discounts and commission, the net proceeds to the Company amounted to $198.8 million. SCT has term loans amounting to 153.2 million Czech Koruna (CZK), which translates to $4.6 million as of June 30, 1998. The principal of these loans will be paid in quarterly installments over the term of the loans, the last of which matures in June 2006. The interest rates on these loans ranged from 16.03% to 16.95% at June 30, 1998. PSZT has U.S. dollar denominated debt in the amount of $50.6 million as of June 30, 1998. During the quarter ended June 30, 1998, the Czech Koruna increased in value in relation to the U.S. dollar. Accordingly, PSZT recognized a pretax gain of approximately $1.2 million, which is included in Other Income in the Consolidated Statement of Income. Since acquiring PSZT in February 1998, an exchange rate gain of $3.4 million (pretax) has been recorded concerning PSZT's U.S. dollar denominated debt. Subsequent exchange rate changes over the term of the loan may result in the recognition of additional gains or losses. The principal of this debt will be paid in quarterly installments over the period of March 2000 - December 2004. The interest rate on this debt was 7.98% at of June 30, 1998. PSZT also has long-term debentures in the amount of CZK 300 million ($9.1 million). The debentures mature in December 1999 and bear an interest rate of 13%. As a result of the acquisition of HarCor, the Consolidated Balance Sheet at June 30, 1998, includes approximately $53 million of HarCor's senior secured debt (See note 6 for further discussion). Note 4 - Derivative Financial Instruments Seneca has entered into certain price swap agreements to manage a portion of the market risk associated with fluctuations in the price of natural gas and crude oil, thereby providing more stability to the operating results of that business segment. These agreements are not held for trading purposes. The price swap agreements call for Seneca to receive monthly payments from (or make payments to) other parties based upon the difference between a fixed and a variable price as specified by the agreement. The variable price is either a crude oil price quoted on the New York Mercantile Exchange or a quoted natural gas price in "Inside FERC." These variable prices are highly correlated with the market prices received by Seneca for its natural gas and crude oil production. The following summarizes Seneca's activity under price swap agreements for the quarter and nine-month periods ended June 30, 1998 and 1997, respectively:
Item 1. Financial Statements (Cont.) - ------------------------------------ Quarter Ended Quarter Ended June 30, 1998 June 30, 1997 ------------- ------------- Natural Gas Price Swap Agreements: Notional Amount - Equivalent Billion Cubic Feet (Bcf) 6.0 6.3 Range of Fixed Prices per Thousand Cubic Feet (Mcf) $2.00 - $2.84 $1.77 - $2.06 Weighted Average Fixed Price per Mcf $2.25 $1.90 Range of Variable Prices per Mcf $2.06 - $2.41 $1.84 - $2.41 Weighted Average Variable Price per Mcf $2.27 $2.13 Loss $($82,000) $(1,421,000) Crude Oil Price Swap Agreements: Notional Amount - Equivalent Barrels (bbl) 219,000 360,500 Range of Fixed Prices per bbl $17.50 - $20.56 $17.40 - $18.71 Weighted Average Fixed Price per bbl $19.04 $18.02 Range of Variable Prices per bbl $13.67 - $15.47 $19.22 - $20.87 Weighted Average Variable Price per bbl $14.69 $19.94 Gain (Loss) $982,000 $(692,000) Nine Months Ended Nine Months Ended June 30, 1998 June 30, 1997 ----------------- ----------------- Natural Gas Price Swap Agreements: Notional Amount - Equivalent Bcf 19.1 18.7 Range of Fixed Prices per Mcf $1.77 - $2.84 $1.71 - $2.10 Weighted Average Fixed Price per Mcf $2.13 $1.92 Range of Variable Prices per Mcf $2.01 - $3.44 $1.77 - $4.11 Weighted Average Variable Price per Mcf $2.55 $2.65 Loss $(8,167,000) $(13,597,000) Crude Oil Price Swap Agreements: Notional Amount - Equivalent bbl 672,000 1,030,500 Range of Fixed Prices per bbl $17.50 - $20.56 $17.40 - $18.71 Weighted Average Fixed Price per bbl $18.76 $17.99 Range of Variable Prices per bbl $13.67 - $21.28 $19.22 - $25.18 Weighted Average Variable Price per bbl $16.93 $22.31 Gain (Loss) $1,221,000 $(4,498,000) Seneca had the following price swap agreements outstanding at June 30, 1998. Natural Gas Price Swap Agreements: Notional Amount Range of Fixed Weighted Average Fiscal Year (Equivalent Bcf) Prices Per Mcf Fixed Price Per Mcf - ----------- ---------------- -------------- ------------------- 1998 7.3 $2.00 - $2.84 $2.28 1999 17.5 $2.00 - $2.50 $2.31 2000 3.1 $2.29 - $2.47 $2.37 ---- 27.9 ====
Item 1. Financial Statements (Cont.) - ------------------------------------ Crude Oil Price Swap Agreements: Notional Amount Range of Fixed Weighted Average Fiscal Year (Equivalent bbl) Prices Per bbl Fixed Price Per bbl - ----------- ---------------- -------------- ------------------- 1998 219,000 $17.50 - $20.56 $19.04 1999 135,000 $19.30 - $20.56 $19.86 ------- 354,000 ======= Gains or losses from these price swap agreements are accrued in operating revenues on the Consolidated Statement of Income at the contract settlement dates. At June 30, 1998, Seneca had an unrecognized gain of approximately $0.1 million related to the price swap agreements which are offset by corresponding unrecognized losses from Seneca's anticipated natural gas and crude oil production over the terms of the price swap agreements. NFR participates in the natural gas futures market to manage a portion of the market risk associated with fluctuations in the price of natural gas. Such futures are not held for trading purposes. At June 30, 1998, NFR had the following futures contracts outstanding: Long "Buy" Positions Notional Amount Range of Fixed Weighted Average Fiscal Year (Equivalent Bcf) Prices Per Mcf Fixed Price Per Mcf - ----------- ---------------- -------------- ------------------- 1998 3.7 $2.04 - $2.70 $2.33 1999 4.6 $2.04 - $2.96 $2.57 2000 1.0 $2.45 - $2.74 $2.66 --- 9.3 === Short "Sell" Positions Notional Amount Range of Fixed Weighted Average Fiscal Year (Equivalent Bcf) Prices Per Mcf Fixed Price Per Mcf - ----------- ---------------- -------------- ------------------- 1998 2.2 $2.11 - $2.76 $2.46 1999 0.7 $2.38 - $2.77 $2.67 --- 2.9 === Gains or losses from natural gas futures are recorded in Other Deferred Credits on the Consolidated Balance Sheet until the hedged commodity transaction occurs, at which point they are reflected in operating revenues in the Consolidated Statement of Income. At June 30, 1998, NFR had unrealized gains of approximately $1.7 million related to these futures contracts. NFR had a minimal gain for the quarter ended June 30, 1998 and recorded losses of approximately $0.3 million for the quarter ended June 30, 1997. NFR recorded gains of approximately $1.3 million and $1.2 million for the nine months ended June 30, 1998 and 1997, respectively. Since these futures contracts qualify and have been designated as hedges, any gains or losses resulting from market price changes are substantially offset by the related commodity transaction.
Item 1. Financial Statements (Cont.) - ------------------------------------ The Company has SEC authority to enter into hedging transactions related to all or a portion of its existing or anticipated debt. The notional amounts of the hedging instruments may not exceed the amount of the Company's outstanding debt. No such hedging transactions were entered into during the quarter ended June 30, 1998 and none are currently outstanding. Credit Risk. Credit risk relates to the risk of loss that the Company would incur as a result of nonperformance by counterparties pursuant to the terms of their contractual obligations under the price swap agreements and futures contracts they have issued. The Company is exposed to such credit risk when fluctuations in natural gas and crude oil market prices result in the Company recognizing gains on the price swap agreements and futures contracts that it has entered into. When credit risk arises, such risk to the Company is mitigated by the fact that the counterparties, or the parent companies of such counterparties, are investment grade financial institutions. In those instances where the Company is not dealing directly with the parent company, the Company has obtained guarantees from the parent company of the counterparty that has issued the price swap agreements. Accordingly, the Company does not anticipate any material impact to its financial position, results of operations or cash flow as a result of nonperformance by counterparties. Note 5 - Commitments and Contingencies Environmental Matters. The Company is subject to various federal, state and local laws and regulations relating to the protection of the environment. The Company has established procedures for on-going evaluation of its operations to identify potential environmental exposures and assure compliance with regulatory policies and procedures. It is the Company's policy to accrue estimated environmental clean-up costs when such amounts can reasonably be estimated and it is probable that the Company will be required to incur such costs. Distribution Corporation has estimated that clean-up costs related to several former manufactured gas plant sites and several other waste disposal sites may range from $13.7 million to $14.7 million. At June 30, 1998, Distribution Corporation has recorded the minimum liability of $13.7 million. The approximate 50% increase in the liability since September 30, 1997 mainly relates to changing circumstances and revised estimates for one particular former manufactured gas plant site. The ultimate cost to Distribution Corporation with respect to the remediation of all sites will depend on such factors as the remediation plan selected, the extent of the site contamination, the number of additional potentially responsible parties at each site and the portion, if any, attributed to Distribution Corporation. The Company is currently not aware of any material additional exposure to environmental liabilities. However, changes in environmental regulations or other factors could adversely impact the Company. In New York and Pennsylvania, Distribution Corporation is recovering site investigation and remediation costs in rates. Accordingly, the Consolidated Balance Sheet at June 30, 1998 includes related regulatory assets in the amount of approximately $13.0 million. For further discussion, see
Item 1. Financial Statements (Cont.) - ----------------------------------- disclosure in Note H - Commitments and Contingencies under the heading "Environmental Matters" in Item 8 of the Company's 1997 Form 10-K. Other. The Company is involved in litigation arising in the normal course of business. The Company is involved in regulatory matters arising in the normal course of business that involve rate base, cost of service and purchased gas cost issues. While the resolution of such litigation or regulatory matters could have a material effect on earnings and cash flows, none of this litigation, and none of these regulatory matters, is expected to have a material effect on the financial condition of the Company at this time. Note 6 - Acquisition of HarCor Energy, Inc. In May 1998, Seneca West Corporation (Seneca West), a wholly-owned subsidiary of Seneca, completed a tender offer (an offer of $2.00 per share) for the outstanding shares of HarCor. The tender offer was commenced pursuant to the terms of an Agreement and Plan of Merger among HarCor, Seneca and Seneca West which provided for the merger of Seneca West with and into HarCor following the successful consummation of the tender offer. Approximately 95% of the outstanding shares of HarCor common stock were tendered in accordance with the tender offer. Accordingly, Seneca West has been merged with and into HarCor and the common stock that was not purchased pursuant to the tender offer was converted in the merger into the right to receive $2.00 per share. The cost of the tender offer and subsequent conversion of the remaining shares of HarCor was approximately $32.4 million. The acquisition of HarCor was accounted for in accordance with the purchase method as specified by APB 16. HarCor's results of operations were incorporated into the Company's consolidated financial statements for the period subsequent to the completion of the tender offer in May 1998. As a result of the acquisition, the Consolidated Balance Sheet at June 30, 1998 includes approximately $53 million of HarCor's senior secured debt. This debt is payable semi-annually on January 15 and July 15 of each year. The debt is redeemable, in whole or in part, at the option of HarCor at any time on or after July 15, 1999 at the following redemption prices: 1999 - 110% of the principal amount; 2000 - 107% of the principal amount; 2001 and thereafter - 100% of the principal amount. An opening balance sheet adjustment has been made such that the effective interest rate recognized by the Company regarding this debt will be approximately 5.875%. Item 2. Management's Discussion and Analysis of Financial Condition and - ------------------------------------------------------------------------ Results of Operations --------------------- RESULTS OF OPERATIONS Earnings. The Company earnings were $19.1 million, or $0.50 per common share ($0.49 per share on a diluted basis), for the quarter ended June 30, 1998. This compares with earnings of $18.9 million, or $.50 per common share ($0.49 per common share on a diluted basis), for the quarter ended June 30, 1997.
Item 2. Management's Discussion and Analysis of Financial Condition and - ------------------------------------------------------------------------ Results of Operations (Cont.) ----------------------------- The Company's earnings were $26.3 million, or $0.69 per common share ($0.68 per common share on a diluted basis), for the nine months ended June 30, 1998. This includes the non-cash impairment of Seneca's oil and gas assets, in the amount of $79.1 million (after tax) as well as the cumulative effect through October 1, 1997, of a change in depletion methods for Seneca's oil and gas assets in the amount of $9.1 million, or $0.24 per common share. Without these two non-cash items, earnings for the nine months ended June 30, 1998, would have been $114.5 million, or $3.00 per common share ($2.96 per common share on a diluted basis). This compares with earnings of $114.6 million, or $3.01 per common share ($2.98 per common share on a diluted basis), for the nine months ended June 30, 1997. The earnings for the nine months ended June 30, 1998 also reflect $5.0 million of after tax income from the settlement of the primary issues relating to IRS audits of years 1977-1994. Discussion of Quarter Results. Overall, earnings for the quarter were basically flat when compared with the prior year's quarter, with increases in earnings of the Pipeline and Storage segment and a lower loss experienced in the International segment, offset by lower earnings in the Utility, Exploration and Production and Other Nonregulated segments. In the Pipeline and Storage segment, earnings were up due mainly to lower operation and maintenance (O&M) expense and a buyout of a firm transportation agreement by a customer in the amount of $2.5 million which was received during the quarter. Partly offsetting these positive impacts to earnings were lower revenue from unbundled pipeline sales and open access transportation. The International segment is realizing increases from Horizon's share of earnings from its two main investments in district heating and power generation operations located in the Czech Republic. Horizon initially acquired 36.8% of Severoceske Teplarny, a.s. (SCT) in fiscal 1997, and increased its ownership during fiscal 1998 to 82.7% by June 30, 1998. Also in this fiscal year, Horizon invested in Prvni severozapadni teplarenska, a.s. (PSZT), and owned an 85.9% interest at June 30, 1998. However, the additional cost of debt to fund these acquisitions has reduced results for the quarter to a slight loss position. Although the Utility segment continues to benefit from lower O&M expense, the impact of warmer than normal weather during the quarter, and the consequent overall lower usage per account, has again taken its toll on the earnings of this segment. In the New York jurisdiction, the Weather Normalization Clause (WNC) is not available to mitigate weather impacts subsequent to the May billing cycle. In the Pennyslvania jurisdiction, there is no WNC. In the Exploration and Production segment, earnings are down mainly because of low oil prices and additional expenses of operating the properties acquired in the Whittier, HarCor Energy Inc. (HarCor) and Bakersfield Energy Resources (BER) acquisitions, as well as higher interest costs related to these acquisition activities. These factors more than offset the positive
Item 2. Management's Discussion and Analysis of Financial Condition and - ------------------------------------------------------------------------ Results of Operations (Cont.) ----------------------------- contribution to earnings that resulted from higher production of both oil and gas and higher gas prices. The production increases are mainly attributable to the properties acquired as noted above. The Other Nonregulated segment's earnings are down mainly because of lower margins and higher expenses of the natural gas marketing operations and lower earnings of the timber operations. Discussion Of Nine-Months Results. Earnings for the nine months ended June 30, 1998 (exclusive of the two nonrecurring items noted above) were also basically flat when compared with the prior year. Lower earnings of the Utility and Exploration and Production segments were offset by higher earnings of the International and Pipeline and Storage segments. The Utility segment showed lower year-to-date earnings because of warmer weather and lower gas usage. The Exploration and Production segment had lower year-to-date earnings mainly because of lower overall production and prices and higher expenses. The International segment's earnings increased because of its share of earnings from its investments in the Czech Republic. The settlement of the primary issues relating to IRS audits provided a positive contribution to earnings in the Pipeline and Storage segment as well as the Exploration and Production segment, while reducing the earnings of the Utility segment. In addition, the Pipeline and Storage segment's year-to-date earnings also benefited from the previously mentioned customer contract buyout. Discussion Of Asset Impairment And Cumulative Effect Of A Change In Depletion Method. Seneca follows the full-cost method of accounting for its oil and gas operations. Under this method, capitalized costs are limited by a present worth calculation of future revenues from oil and gas assets (full-cost ceiling). The surplus of crude oil world-wide has caused oil prices to drop to their lowest level in recent years, and gas prices continue to be negatively impacted by the warmer than normal 1997/1998 winter. As a result of these lower prices, a non-cash asset impairment of $129 million (pretax) was recorded as of March 31, 1998. No impairment charge was required for the quarter ended June 30, 1998. Effective October 1, 1997, Seneca changed its method of depletion for oil and gas properties from the gross revenue method to the units of production method. The new method was adopted because it provides a better measure of depletion expense and is the preferable method used by oil and gas producing companies. Seneca's recent acquisition activities have increased its size and scope of operations in relation to those of the Company. Consequently, the change in method was warranted at such time. The units of production method has been applied retroactively to prior years to determine the cumulative effect through October 1, 1997. This cumulative effect reduced earnings for the nine months ended June 30, 1998, by $9.1 million, net of income taxes. Depletion of oil and gas properties for the quarter and nine months ended June 30, 1998, has been computed under the units of production method. Additional discussion of this accounting change is included in Note 1 "Summary of Significant Accounting Policies."
Item 2. Management's Discussion and Analysis of Financial Condition and - ------------------------------------------------------------------------ Results of Operations (Cont.) ---------------------------- OPERATING REVENUES (in thousands) Three Months Ended Nine Months Ended June 30, June 30, ------------------------- ------------------------- 1998 1997 % Change 1998 1997 % Change ---- ---- -------- ---- ---- -------- Utility Retail Revenues: Residential $100,816 $126,809 (20.5) $553,950 $642,067 (13.7) Commercial 17,831 29,085 (38.7) 114,512 154,699 (26.0) Industrial 3,478 3,901 (10.8) 15,137 19,110 (20.8) -------- -------- -------- -------- 122,125 159,795 (23.6) 683,599 815,876 (16.2) Off-System Sales 9,201 6,661 38.1 39,972 37,337 7.1 Transportation 15,196 13,242 14.8 52,710 41,430 27.2 Other (618) 723 (185.5) 2,834 1,358 108.7 --------- -------- -------- -------- 145,904 180,421 (19.1) 779,115 896,001 (13.0) -------- -------- -------- -------- Pipeline and Storage Storage Service 15,315 15,711 (2.5) 47,785 48,402 (1.3) Transportation 22,756 22,479 1.2 71,218 71,058 0.2 Other 3,252 4,924 (34.0) 10,509 11,809 (11.0) -------- -------- -------- -------- 41,323 43,114 (4.2) 129,512 131,269 (1.3) -------- -------- -------- -------- Exploration and Production 36,802 27,842 32.2 86,330 90,220 (4.3) -------- -------- -------- -------- International 18,639 321 NM 72,786 1,845 NM -------- -------- -------- -------- Other Nonregulated 24,054 18,462 30.3 85,380 70,002 22.0 -------- -------- -------- -------- Less-Intersegment Revenues 24,275 24,109 0.7 77,007 81,090 (5.0) -------- -------- -------- -------- $242,447 $246,051 (1.5) $1,076,116 $1,108,247 (2.9) ======== ======== ========== ========== OPERATING INCOME (LOSS) BEFORE INCOME TAXES (in thousands) Three Months Ended Nine Months Ended June 30, June 30, ------------------------- ------------------------ 1998 1997 % Change 1998 1997 % Change ---- ---- -------- ---- ---- -------- Utility $ 12,956 $ 15,750 (17.7) $132,810 $134,774 (1.5) Pipeline and Storage 19,960 20,404 (2.2) 56,976 58,188 (2.1) Exploration and Production* 11,859 8,369 41.7 (104,507) 32,815 NM International 794 (782) 201.5 7,704 (2,369) NM Other Nonregulated 124 1,269 (90.2) 3,063 2,458 24.6 Corporate (90) (420) 78.6 (1,182) (1,900) 37.8 -------- ------- --------- -------- $ 45,603 $ 44,590 2.3 $ 94,864 $223,966 (57.6) ======== ======== ======== ======== *Nine months ended June 30, 1998 includes non-cash impairment charge of $128,996,000. NM = Not meaningful.
Item 2. Management's Discussion and Analysis of Financial Condition and - ------------------------------------------------------------------------ Results of Operations (Cont.) ---------------------------- SYSTEM NATURAL GAS VOLUMES (millions of cubic feet-MMcf) Three Months Ended Nine Months Ended June 30, June 30, ------------------------ ------------------------- 1998 1997 % Change 1998 1997 % Change ---- ---- -------- ---- ---- -------- Utility Gas Sales Residential 10,739 15,954 (32.7) 66,749 79,478 (16.0) Commercial 2,219 4,189 (47.0) 15,406 21,178 (27.3) Industrial 884 1,059 (16.5) 3,353 4,082 (17.9) Off-System 3,484 3,041 14.6 14,432 11,469 25.8 ------- ------ ------ ------- 17,326 24,243 (28.5) 99,940 116,207 (14.0) ------- ------ ------ ------- Non-Utility Gas Sales Production(in equivalent MMcf) 15,840 12,395 27.8 36,293 37,048 (2.0) ------- ------- ------ ------- Total Gas Sales 33,166 36,638 (9.5) 136,233 153,255 (11.1) ------- ------- ------- ------- Transportation Utility 14,690 15,270 (3.8) 50,022 48,306 3.6 Pipeline and Storage 59,281 59,443 (0.3) 255,174 254,537 0.3 Nonregulated 262 260 0.8 538 320 68.1 ------- ------- ------- ------- 74,233 74,973 (1.0) 305,734 303,163 0.8 ------ ------ ------- ------- Marketing Volumes 6,176 5,854 5.5 20,696 17,674 17.1 ------- ------- ------- ------- Less-Inter and Intrasegment Volumes: Transportation 22,796 27,553 (17.3) 125,539 138,218 (9.2) Production 1,001 1,072 (6.6) 3,059 3,225 (5.1) ------- ------- ------- ------- 23,797 28,625 (16.9) 128,598 141,443 (9.1) ------- ------- ------- ------- Total System Natural Gas Volumes 89,778 88,840 1.1 334,065 332,649 0.4 ======= ====== ======= ======= Utility. Operating revenues for the Utility segment decreased $34.5 million and $116.9 million for the quarter and nine months ended June 30, 1998, respectively, as compared with the same periods a year ago. These decreases primarily reflect the recovery of lower gas costs which resulted from a decrease in gas sales (a 6.9 billion cubic feet (Bcf) decrease and a 16.3 Bcf decrease for the quarter and nine months ended June 30, 1998, respectively). While the decrease in gas sales also reflects, in part, the migration of certain retail customers to transportation service in both the New York and Pennsylvania jurisdictions, as a result of new aggregator services, the major reason for the decrease stems from warmer weather (see Degree Days table below). The switch to new aggregator services is discussed further in the "Rate Matters" section that follows.
Item 2. Management's Discussion and Analysis of Financial Condition and - ------------------------------------------------------------------------ Results of Operations (Cont.) ---------------------------- The impact on operating revenue of a general base rate increase in the New York jurisdiction effective October 1, 1997 ($7.2 million on an annual basis) was mostly mitigated by the recognition of a refund provision of $1.8 million for the quarter and $4.9 million year-to-date to the Utility's customers for a 50% sharing of earnings over a predetermined level in accordance with the New York rate settlement of July 1996. The cumulative estimated refund provision liability, including amounts accrued in fiscal 1997, is $7.9 million. The final amount owed to customers, if any, will not be known until after September 30, 1998, which is the conclusion of the settlement period. In addition, operating revenues in the year-to-date period ended June 30, 1998, include $6.0 million of revenue recorded by the Utility segment's New York jurisdiction related to the previously mentioned recent settlement of IRS audits. This $6.0 million represents the rate recovery of interest expense as allowed by the New York rate settlement of July 1996. Both this revenue and the refund provision are included in the "Other" category in the Utility section of the Operating Revenues table above. Operating income before income taxes for the Utility segment decreased $2.8 million and $2.0 million for the quarter and nine months ended June 30, 1998, respectively, as compared to the same periods a year ago. Excluding the $6 million of rate recovery of interest expense related to the IRS audits, as noted above (this rate recovery is offset 100% by interest expense, included below the operating income line), the Utility segment's pretax operating income decreased $8.0 million for the nine months ended June 30, 1998. The decrease in operating income before income taxes for the quarter and nine months ended June 30, 1998, resulted primarily from the negative impact of warmer weather and the related decrease in normalized gas usage per customer account. Partly offsetting this decrease in operating income before income taxes, the Utility segment continues to experience decreases in O&M expense (a 8.4% and 5.7% decline for the quarter and nine months ended June 30, 1998, respectively) relating primarily to benefit, labor and outside services expense reduction. The negative impact of warmer weather directly impacts the operating income of the Pennsylvania jurisdiction since Pennsylvania does not have a WNC. The impact of the warmer weather experienced by the New York jurisdiction was tempered by the WNC through May billing cycles each year. Thus, about half of May's sales, as well as June's sales are not covered by the WNC. During the prior year this segment benefited during the non-weather normalized period as a result of the colder weather, while this year the warmer weather negatively impacted the Utility's operating results.
Item 2. Management's Discussion and Analysis of Financial Condition and - ------------------------------------------------------------------------ Results of Operations (Cont.) ---------------------------- Degree Days Three Months Ended June 30: - -------------------------- Percent (Warmer) Colder in 1998 Than Normal 1998 1997 Normal 1997 - --------------------------------------------------------------------- Buffalo 919 738 1,151 (19.7) (35.9) Erie 880 695 1,125 (21.0) (38.2) Nine Months Ended June 30: - ------------------------- Buffalo 6,525 5,817 6,601 (10.9) (11.9) Erie 6,123 5,338 6,248 (12.8) (14.6) - --------------------------------------------------------------------- Pipeline and Storage. Operating income before income taxes for the Pipeline and Storage segment decreased $0.4 million and $1.2 million for the quarter and nine months ended June 30, 1998, respectively, as compared with the same periods a year ago. For both the quarter and nine months ended, the decrease is primarily attributable to lower revenue from unbundled pipeline sales and open access transportation, offset in part by lower O&M expense. The decrease in O&M expense for the quarter is primarily the result of lower employee benefits and outside service costs. The decrease in O&M expense for the nine months ended June 30, 1998, is primarily the result of lower employee benefits, labor and outside service costs, as well as the reversal of a portion of a reserve set up in a prior period for the Laurel Fields Storage Project. The Pipeline and Storage segment was able to recapture approximately $1.0 million by selling preliminary engineering, survey, environmental and archeological information from the Laurel Fields Project to the Independence Pipeline Company, which intends to build a 370-mile interstate pipeline system designed to transport approximately 900,000 dekatherms (Dth) per day of natural gas from Defiance, Ohio to Leidy, Pennsylvania (the Independence Pipeline project is discussed further under "Investing Cash Flow", subheading "Pipeline and Storage"). Partially offsetting these decreases in O&M expense, was the establishment of reserves for preliminary survey and investigation costs associated with the Niagara Expansion and Green Canyon projects. (The Niagara Expansion and Green Canyon projects are discussed further under "Investing Cash Flow", subheading "Pipeline and Storage"). Certain of these costs for which reserves have been established may be recovered at a future date.1 In addition, Supply Corporation recognized a base gas loss at its Zoar Storage Field. In total, these three items amounted to $3.7 million, pretax. While transportation volumes in this segment decreased 0.2 Bcf and increased 0.6 Bcf, respectively, for the quarter and nine months ended June 30, 1998, the change in volumes did not have a significant impact on earnings as a result of Supply Corporation's straight fixed-variable (SFV) rate design.
Item 2. Management's Discussion and Analysis of Financial Condition and - ------------------------------------------------------------------------ Results of Operations (Cont.) ---------------------------- Exploration and Production. Operating income before income taxes from the Company's Exploration and Production segment increased $3.5 million for the quarter ended June 30, 1998, compared with the same period a year ago. This increase resulted from higher oil and gas revenues during the quarter, a net gain on hedging activities (versus a loss in the prior year) and lower depletion expense. These items were partly offset by higher lease operating expense. Oil and gas revenues increased mainly as a result of West Coast production from the properties acquired in the Whittier, HarCor and BER acquisitions. Increases in Gulf Coast gas production as well as higher overall gas prices also helped increase revenues for the quarter while significantly lower oil prices reduced the current quarter's revenues (see tables below for production and price information). The decrease in depletion expense is the result of a lower depletion rate, determined under the units of production method, because of the significant addition to reserves resulting from the Whittier, HarCor and BER acquisitions, as well as the continued success in adding new reserves from exploratory drilling. The change in depletion method, made effective October 1, 1997, from the gross revenue method to the units of production method, also lowered depletion expense for the quarter. See further discussion of this change in accounting method in Note 1 - "Summary of Significant Accounting Policies." Lease operating expense increased mainly because of the additional expenses of operating the newly acquired properties. For the nine months ended June 30, 1998, operating income before income taxes for the Exploration and Production segment decreased $137.3 million, compared with the same period a year ago. Excluding the $129 million non-cash impairment of this segment's oil and gas assets, as discussed previously, operating income before income taxes decreased $8.3 million as compared with the prior year's period. This decrease resulted from lower oil and gas revenues and higher lease operating expense offset in part by lower depletion expense and lower hedging losses. Gas revenues are lower as a result of lower prices and overall production in the Gulf Coast, offset in part by increased prices and production in the West Coast. Oil revenues are down overall primarily as a result of the significant decrease in prices. The decrease in depletion expense and increase in lease operating expense was mainly caused by the reasons noted in the quarter discussion above. Hedging activities resulted in a net pretax gain of $0.9 million and a net pretax loss of $6.9 million for the quarter and nine months ended June 30, 1998, respectively. For the quarter and nine months ended June 30, 1997, hedging activities resulted in pretax losses of $2.1 million and $18.1 million, respectively. Refer to further discussion of the Company's hedging activities under "Financing Cash Flow" and in Note 4 - Derivative Financial Instruments.
Item 2. Management's Discussion and Analysis of Financial Condition and - ------------------------------------------------------------------------ Results of Operations (Cont.) ---------------------------- PRODUCTION VOLUMES Exploration and Production. Three Months Ended Nine Months Ended June 30, June 30, ------------------ ----------------- 1998 1997 % Change 1998 1997 % Change ---- ---- -------- ---- ---- -------- Gas Production - (MMcf) Gulf Coast 8,552 8,137 5.1 21,253 23,658 (10.2) West Coast 697 293 137.9 1,109 844 31.4 Appalachia 1,193 1,246 (4.3) 3,677 3,820 (3.7) ----- ----- ------ ------ 10,442 9,676 7.9 26,039 28,322 (8.1) ====== ===== ====== ====== Oil Production - (Thousands of Barrels) Gulf Coast 312 327 (4.6) 921 1,073 (14.2) West Coast 586 124 372.6 780 374 108.6 Appalachia 2 2 - 8 7 14.3 --- --- ---- ----- 900 453 98.7 1,709 1,454 17.5 === === ===== ===== WEIGHTED AVERAGE PRICES Exploration and Production. Three Months Ended Nine Months Ended June 30, June 30, ------------------ ----------------- 1998 1997 % Change 1998 1997 % Change ---- ---- -------- ---- ---- -------- Weighted Avg. Gas Price/Mcf Gulf Coast $2.29 $2.19 4.6 $2.52 $2.68 (6.0) West Coast $2.19 $1.53 43.1 $2.17 $1.81 19.9 Appalachia $2.72 $2.30 18.3 $2.95 $2.92 1.0 Weighted Average $2.33 $2.18 6.9 $2.57 $2.69 (4.5) Weighted Average After Hedging $2.32 $2.03 14.3 $2.25 $2.21 1.8 Weighted Avg. Oil Price/bbl Gulf Coast $12.70 $19.36 (34.4) $15.54 $22.16 (29.9) West Coast $ 8.75 $16.79 (47.9) $10.10 $19.21 (47.4) Appalachia $14.85 $19.61 (24.3) $17.00 $22.03 (22.8) Weighted Average $10.13 $18.66 (45.7) $13.06 $21.40 (39.0) Weighted Average After Hedging $11.22 $17.13 (34.5) $13.78 $18.31 (24.7) International. Operating income before income taxes for the International segment increased $1.6 million and $10.1 million for the quarter and the nine-months ended June 30, 1998, respectively, compared with the same periods a year ago. This increase, as well as the significant revenue increase shown in the "Operating Revenue" table above, reflects current quarter and year-to-date results including 100% of the revenues and pretax operating income of SCT, as well as 100% of the revenues and pretax operating income of PSZT for February through June 1998. Both SCT and PSZT have district heating and power generation operations located in the northern part of the Czech Republic. Horizon first
Item 2. Management's Discussion and Analysis of Financial Condition and - ------------------------------------------------------------------------ Results of Operations (Cont.) ---------------------------- acquired a 34% interest in SCT in April 1997 and increased its ownership to 82.7% as of June 30, 1998. In January 1998, Horizon signed an agreement to acquire 75.3% of the outstanding shares of PSZT. The acquisition was completed in February 1998 and Horizon owned 85.9% of PSZT as of June 30, 1998. The minority interests in SCT and PSZT are shown separately on the Consolidated Statement of Income after operating results. The prior year's June quarter reflected no operating income from SCT or PSZT. The following table summarizes the heating sales and electricity sales of SCT and PSZT for the quarter and fiscal year ended June 30, 1998: Three Months Ended June 30: Heating Sales 1,442,736 Gigajoules* (1.4 Bcf Equivalent) Electricity Sales 252,931 Megawatts Nine Months Ended June 30: Heating Sales 6,139,033 Gigajoules*(5.8 Bcf Equivalent) Electricity Sales 496,331 Megawatts *Gigajoules = one billion joules. A joule is a unit of energy. Because of the change in the nature of operations of the International segment during the past year, operating income comparisons between the current period and prior periods may not be meaningful. Future revenues from district heating operations are expected to fluctuate with changes in weather. The Company expects that rates charged for heating operations in the Czech Republic will continue to be monitored by the Czech Ministry of Finance.1 Other Nonregulated. Operating income before income taxes associated with this segment decreased $1.1 million for the quarter ended June 30, 1998 and increased $0.6 million for the nine-months ended June 30, 1998, compared with the same periods a year ago. The decrease for the quarter can be primarily attributed to increased operating expenses in the Company's timber operations, as well as decreased margin and increased operating expense for NFR, the Company's gas marketing subsidiary. The increase for the nine-months ended can be primarily attributed to increased performance by the Company's timber operations offset by decreased margin and increased O&M for NFR. Income Taxes. Income taxes decreased $1.4 million and $44.6 million, respectively, for the quarter and nine months ended June 30, 1998, primarily as a result of a decrease in pretax income (pretax income before cumulative effect, for the nine months ended June 30, 1998). Other Income. Other income increased $4.4 million and $29.8 million, respectively, for the quarter and nine months ended June 30, 1998. The increase in other income for the quarter resulted from a buyout of a firm transportation agreement by a Pipeline and Storage segment customer in the amount of $2.5 million which was received by Supply Corporation during the quarter. In addition, other income
Item 2. Management's Discussion and Analysis of Financial Condition and - ----------------------------------------------------------------------- Results of Operations (Cont.) ---------------------------- for the quarter includes a gain of approximately $1.2 million associated with U.S. dollar denominated debt carried on the balance sheet of PSZT (see further discussion regarding this PSZT debt in Item 1, Note 3- Capitalization), as well as interest income on temporary cash investments of SCT and PSZT. The increase for the nine months is due to the same reasons noted in the quarter (the gain on U.S. dollar denominated debt was $3.4 million for the nine month period), as well as $18.5 million of interest income which resulted from the recent settlement of IRS audits. Interest Charges. Total interest charges increased $6.4 million and $21.5 million for the quarter and nine months ended June 30, 1998, respectively. Other interest increased $2.2 million and $14.9 million for the quarter and nine-month period, respectively. The increase for both the quarter and nine-month period relates primarily to an increase in the average amount of short-term debt outstanding. Short-term debt was utilized to fund the acquisition activities in the International and Exploration and Production segments, until a portion was replaced with long-term debt in May 1998 (see below). In addition, the increase in other interest for the nine months resulted from interest expense related to the previously mentioned settlement of IRS audits (total interest expense related to the IRS audits amounted to $11.7 million). Interest on long-term debt increased $4.2 million and $6.6 million for the quarter and nine-month period, respectively, mainly because of a higher average amount of long-term debt outstanding compared to the same periods a year ago. Contributing to the higher outstanding debt balance was the issuance of the $200.0 million of medium-term notes in May 1998. Also contributing to the higher outstanding debt balance was the borrowings of Horizon's subsidiaries, PSZT and SCT, as well as approximately $53 million of HarCor's senior secured debt. (See further discussion regarding HarCor debt in Item 1, Note 3-Capitalization and Note 6-Acquisition of HarCor Energy, Inc.). CAPITAL RESOURCES AND LIQUIDITY The Company's primary sources of cash during the nine-month period consisted of cash provided by operating activities and short-term bank loans and commercial paper. Operating Cash Flow. Internally generated cash from operating activities consists of net income available for common stock, adjusted for non-cash expenses, non-cash income and changes in operating assets and liabilities. Non-cash items include the cumulative effect of a change in accounting for depletion, the impairment of oil and gas producing properties, depreciation, depletion and amortization, deferred income taxes, minority interest in foreign subsidiaries and allowance for funds used during construction. Cash provided by operating activities in the Utility and the Pipeline and Storage segments may vary substantially from period to period because of the impact of rate cases. In the Utility segment, supplier refunds, over- or
Item 2. Management's Discussion and Analysis of Financial Condition and - ------------------------------------------------------------------------ Results of Operations (Cont.) ---------------------------- under-recovered purchased gas costs and weather also significantly impact cash flow. The Company considers supplier refunds and over-recovered purchased gas costs as a substitute for short-term borrowings. The impact of weather on cash flow is tempered in the Utility segment's New York rate jurisdiction by its WNC and in the Pipeline and Storage segment by Supply Corporation's SFV rate design. Because of the seasonal nature of the Company's heating business, revenues are relatively high during the nine months ended June 30 and receivables historically increase from September to June because of winter weather. The storage gas inventory normally declines during the first and second quarters of the fiscal year and is replenished during the third and fourth quarters. For storage gas inventory accounted for under the last-in, first-out (LIFO) method, the current cost of replacing gas withdrawn from storage is recorded in the Consolidated Statement of Income and a reserve for gas replacement is recorded in the Consolidated Balance Sheet and is included under the caption "Other Accruals and Current Liabilities." Such reserve is reduced as the inventory is replenished. Net cash provided by operating activities totaled $242.6 million for the nine months ended June 30, 1998, a decrease of $28.3 million compared with $270.9 million provided by operating activities for the nine months ended June 30, 1997. The majority of this decrease occurred in the Utility segment. The Utility segment experienced a decrease in cash receipts from gas sales and transportation service (sales were down mainly due to warmer weather), an increase in cash payments for property, franchise and other taxes (primarily due to timing) and an increase in interest payments (primarily related to the recent settlement of IRS audits). These decreases to cash were partially offset by lower cash payments for gas purchases. Partly offsetting the decreases experienced by the Utility segment was an increase in cash provided by operating activities of the Pipeline and Storage, Exploration and Production and International segments. The Pipeline and Storage segment experienced an increase in cash provided by operating activities primarily because of interest income resulting from the recent settlement of IRS audits combined with cash received from a customer resulting from a buyout of a firm transportation agreement. The Exploration and Production segment experienced an increase in cash provided from operations primarily because of interest income resulting from the aforementioned IRS settlement, a decrease in cash outlays for hedging transactions as well as a decrease in cash outlays for federal taxes. These increases to cash were partly offset by lower cash receipts from the sale of oil and gas combined with higher operating costs (primarily due to the Whittier, HarCor and BER acquisitions). The increase to cash provided by operating activities in the International segment is a result of the operations of SCT and PSZT. Investing Cash Flow. Capital Expenditures and Other Investing Activities - --------------------------------------------------- Capital expenditures represent the Company's additions to property, plant and equipment and are exclusive of other investments in corporations
Item 2. Management's Discussion and Analysis of Financial Condition and - ------------------------------------------------------------------------ Results of Operations (Cont.) ---------------------------- (stock acquisitions) and/or partnerships. Such investments are treated separately in the Statement of Cash Flows and further discussed in the segment discussion below. The Company's capital expenditures and other investments totaled $441.6 million during the nine months ended June 30, 1998. The following table summarizes the Company's capital expenditures and other investments by business segment: Other Total Capital Investments Capital Expenditures through Expenditures and through 6/30/98 6/30/98 Other Investments --------------- ----------- ----------------- Utility $ 36.3 $ - $ 36.3 Pipeline and Storage 15.2 5.2 20.4 Exploration and Production 249.6 32.4 282.0 International 9.4 88.8 98.2 Other Nonregulated 4.7 - 4.7 ------ ------ ------ $315.2 $126.4 $441.6 ====== ====== ====== Utility - ------- The bulk of the Utility capital expenditures were made for replacement of mains and main extensions, as well as for the replacement of service lines. Pipeline and Storage - -------------------- The bulk of the Pipeline and Storage capital expenditures were made for additions, improvements, and replacements to this segment's transmission and storage systems. Approximately $2.3 million was spent on the 1998 Niagara Expansion Project. As part of this expansion, Supply Corporation began transportation service for an additional 25,000 Dth per day in November 1997. In April 1998, Supply Corporation received Federal Energy Regulatory Commission (FERC) approval concerning an additional 23,000 Dth per day expansion of firm winter only capacity. Supply Corporation anticipates beginning transportation service for the additional 23,000 Dth per day in November 1998.1 As there has not been much interest in further expansion in this area at this time, the Company established a reserve in March 1998 for approximately $1.7 million (pretax) related to preliminary survey and investigation costs associated with the proposed 1999 Niagara Expansion Project. Seneca Independence Pipeline Company (SIP) has made a $5.2 million investment in 1998 representing a one-third general partnership interest, in Independence Pipeline Company, a Delaware general partnership. This investment was financed with short-term borrowings. Independence Pipeline Company intends to build a 370 mile natural gas Pipeline from Defiance, Ohio to Leidy, Pennsylvania at an estimated cost of $675 million.1 If the Independence Pipeline Project is not constructed, SIP's share of the development costs (including SIP's investment in Independence Pipeline Company) is estimated not to exceed $6.0 million to $8.0 million.1
Item 2. Management's Discussion and Analysis of Financial Condition and - ------------------------------------------------------------------------ Results of Operations (Cont.) ---------------------------- In November 1996, Supply Corporation entered into a Memorandum of Understanding (the MOU) with Green Canyon Gathering Company, a subsidiary of El Paso Energy regarding a project to develop, construct, finance, own and operate natural gas gathering and processing facilities offshore and onshore Louisiana, at an estimated total cost of approximately $200 million.1 The MOU has been amended several times since then. In April 1998, Green Canyon Gathering Company notified Supply Corporation that it wished to withdraw from the project. Based on a lack of shippers willing to contract for this service, the Company had already decided that it would be prudent to establish a reserve of approximately $1.0 million (pretax) for preliminary survey and investigation costs incurred on the project. This reserve was recorded in March 1998. Exploration and Production - -------------------------- In March 1998, Seneca acquired properties in the Midway-Sunset and North Lost Hills field in the San Joaquin Basin of California from the Whittier Trust Company for approximately $140 million. This acquisition is included in the Exploration and Production capital expenditure amount in the table above. In June 1998, Seneca acquired the oil and gas assets of the BER, which are located in the South Lost Hills Field in the San Joaquin Valley near Bakersfield, California. The purchase price was approximately $30.0 million for BER's 25% ownership. These properties produce gas and high gravity oil, include a gas processing plant and associated pipelines, and provide opportunities for additional drilling and development.1 This acquisition is included in the Exploration and Production capital expenditure amount in the table above. Other Exploration and Production segment capital expenditures included approximately $63.2 million on the offshore program in the Gulf of Mexico, including offshore drilling expenditures, offshore construction, lease acqusition costs and geological and geophysical expenditures. Offshore exploratory drilling was concentrated on High Island 179, High Island A356, Vermilion 309 and South March Island 122. Offshore construction occurred primarily at West Cameron 540 and Vermilion 309. Lease acquisition costs resulted from successful bidding on fourteen state of Texas and two federal lease tracts in the Gulf of Mexico. Offshore geological and geophysical expenditures were made for purchases of 3-D seismic data. The remaining $16.4 million capital expenditures included onshore drilling and construction costs for wells located in Louisiana, Texas and California as well as onshore geological and geophysical costs, including the purchase of certain 3-D seismic data. In May 1998, Seneca West Corporation (Seneca West), a wholly-owned subsidiary of Seneca, completed a tender offer (an offer of $2.00 per share) for the outstanding shares of HarCor. The tender offer was commenced pursuant to the terms of an Agreement and Plan of Merger among HarCor, Seneca and Seneca West which provided for the merger of Seneca West with and into HarCor following the successful consummation of the tender offer. Approximately 95% of the outstanding shares of HarCor common stock were tendered in accordance with the tender offer. Accordingly, Seneca West has been merged with and into HarCor and the common stock that was not purchased pursuant to the tender offer was converted in the merger into the right to receive $2.00 per share.
Item 2. Management's Discussion and Analysis of Financial Condition and - ------------------------------------------------------------------------ Results of Operations (Cont.) ---------------------------- The cost of the tender offer and subsequent conversion of the remaining shares of HarCor was approximately $32.4 million. As a result of this acquisition, the Consolidated Balance Sheet at June 30, 1998 includes approximately $53 million of HarCor's senior secured debt. This debt is payable semi-annually on January 15 and July 15 of each year. The debt is redeemable, in whole or in part, at the option of HarCor at any time on or after July 15, 1999 at the following redemption prices: 1999-110% of the principal amount; 2000-107% of the principal amount; 2001 and thereafter - 100% of the principal amount. An opening balance sheet adjustment has been made such that the effective interest rate recognized by the Company regarding this debt will be approximately 5.875%. The HarCor oil and gas properties are the remaining 75% ownership of the same properties as the BER acquisition discussed above, located on the west side of the San Joaquin Basin in California. The acquisitions of Whittier, HarCor and BER were initially financed using short-term borrowings. Subsequently, approximately $120 million of short-term borrowings were replaced with long-term borrowings. These acquisitions complement the Exploration and Production segment's reserve mix, bringing its new reserve base to approximately 712 Bcf equivalent, of which 55% is oil and 45% is gas. Capital expenditures for the quarter ended September 30, 1998 in the Exploration and Production segment are expected to be approximately $40.0 million with approximately 84% being spent in the Gulf Coast region.1 International - ------------- In Fiscal 1998, Horizon B.V. acquired additional shares of SCT thereby increasing its equity interest in SCT to 82.7% as of June 30, 1998. The cost of acquiring these additional shares was approximately $24.9 million. In February 1998, Horizon B.V. acquired a 75.3% equity interest in PSZT and subsequently increased its ownership interest to 85.9% as of June 30, 1998. The cost of acquiring the shares of PSZT was approximately $63.9 million. Short-term borrowings were initially used to finance the acquisition costs of SCT and PSZT. Subsequently, approximately $80 million of short-term borrowings were replaced with long-term borrowings. The bulk of the International segment capital expenditures were made by PSZT for the reconstruction of boilers at its heating plant to comply with stricter clean air standards. Short-term borrowings and cash from operations were used to finance these capital expenditures. Going forward, it is anticipated that up to an additional $38 million (approximately $6 million for the remaining three months of 1998) will be spent on this reconstruction project, which will extend into fiscal 2000.1 The Company anticipates financing these expenditures with short-term borrowings.1 Horizon B.V.'s investment in the Czech Republic is valued in Czech Korunas, and as such, this investment is subject to currency exchange risk when the Czech Korunas are translated into U.S. Dollars. During the nine months ended June 30, 1998, the Czech Koruna increased in value in relation to
Item 2. Management's Discussion and Analysis of Financial Condition and - ------------------------------------------------------------------------ Results of Operations (Cont.) ---------------------------- the U.S. dollar, resulting in a $1.0 million positive adjustment to the Cumulative Translation Adjustment. Further valuation changes to the Czech Koruna would result in corresponding positive or negative adjustments to the Cumulative Translation Adjustment. Management cannot predict whether the Czech Koruna will increase or decrease in value against the U.S. Dollar.1 Other Nonregulated - ------------------ Other Nonregulated capital expenditures consisted primarily of equipment and timber purchases for Highland's existing sawmill and kiln operations as well as the purchase of a new sawmill in Brookville, Pennsylvania. The capital expenditures also included the purchase of furniture, equipment and computer hardware and software for the office location of the NFR's gas marketing operation. Other - ----- Other cash provided by or used in investing activities primarily reflects cash received on the sale of various subsidiaries investments in property, plant and equipment, cash received on the sale of the Company's interest in Enerchange, L.L.C., a natural gas hub partnership, and cash used to make an initial investment in Independence Pipeline Company. The capital expenditure programs of the Company's subsidiaries are under continuous review. The amounts are subject to modification for opportunities in the natural gas industry such as the acquisition of attractive oil and gas properties or storage facilities and the expansion of transmission line capacities. While the majority of capital expenditures in the Utility segment are necessitated by the continued need for replacement and upgrading of mains and service lines, the magnitude of future capital expenditures in the Company's other business segments depends, to a large degree, upon market conditions.1 Financing Cash Flow. Consolidated short-term debt increased by $109.5 million during the first nine months of fiscal 1998. The Company continues to consider short-term bank loans and commercial paper important sources of cash for temporarily financing capital expenditures and investments in corporations and/or partnerships, gas-in-storage inventory, unrecovered purchased gas costs, exploration and development expenditures and other working capital needs. In addition, the Company considers supplier refunds and over-recovered purchased gas costs as a substitute for short-term debt. Fluctuations in these items can have a significant impact on the amount and timing of short-term debt. At June 30, 1998, the Company had authorization from the SEC under a shelf registration filed pursuant to the Securities Act of 1933, to issue and sell up to $200.0 million of debentures and/or medium-term notes. In March 1998, the Company obtained authorization from the SEC, under the Public Utility Holding Company Act of 1935, to issue, in the aggregate, long-term debt securities and equity securities amounting to $2.0 billion during the order's authorization period, which extends to December 31, 2002. In May 1998, the Company issued $200.0 million of 6.303% medium-term notes due to mature in May 2008. After deducting underwriting discounts and
Item 2. Management's Discussion and Analysis of Financial Condition and - ------------------------------------------------------------------------ Results of Operations (Cont.) ---------------------------- commissions, the net proceeds to the Company amounted to $198.8 million. The Company used the proceeds to reduce short-term debt which resulted from acquisition activities in the International and Exploration and Production segments. The Company's indenture contains covenants which limit, among other things, the incurrence of funded debt. Funded debt basically is indebtedness maturing more than one year after the date of issuance. Because of the impairment of oil and gas properties recorded by the Company in March 1998, these covenants will restrict the Company's ability to issue substantial amounts of additional funded debt, with certain exceptions, until the third quarter of fiscal 1999. This will not, however, limit the Company's issuance of funded debt to refund existing funded debt. The Company has adequate financing resources available to meet expected operating and capital requirements.1 At June 30, 1998, the Company had regulatory authorizations and unused short-term credit lines that would have permitted it to borrow an additional $548.1 million of short-term debt. Seneca has entered into certain price swap agreements to manage a portion of the market risk associated with fluctuations in the market price of natural gas and crude oil. These price swap agreements are not held for trading purposes. During the quarter ended June 30, 1998, Seneca utilized natural gas and crude oil swap agreements with notional amounts of 6.0 equivalent Bcf and 219,000 equivalent bbl, respectively. These hedging activities resulted in the recognition of a pretax gain of approximately $0.9 million. For the nine months ended June 30, 1998, Seneca utilized natural gas and crude oil swap agreements with notional amounts of 19.1 equivalent Bcf and 672,000 equivalent bbl, respectively. These hedging activities resulted in the recognition of a pretax loss of approximately $6.9 million. These hedging gains or losses are offset by lower or higher prices received for actual natural gas and crude oil production. At June 30, 1998, Seneca had natural gas swap agreements outstanding with a notional amount of approximately 27.9 equivalent Bcf at prices ranging from $2.00 per Mcf to $2.84 per Mcf. The weighted average fixed price of these swap agreements is approximately $2.31 per Mcf. Seneca also had crude oil swap agreements outstanding at June 30, 1998 with a notional amount of 354,000 equivalent bbl at prices ranging from $17.50 per bbl to $20.56 per bbl. The weighted average fixed price of these swap agreements is approximately $19.35 per bbl. NFR participates in the natural gas futures market to manage a portion of the market risk associated with fluctuations in the price of natural gas. Such futures are not held for trading purposes. During the quarter ended June 30, 1998, NFR recognized a minimal pretax gain related to such futures contracts. For the nine months ended June 30, 1998, NFR recorded a pretax gain of approximately $1.3 million. Since these futures contracts qualify and have been designated as hedges, any gains or losses resulting from market price changes are substantially offset by the related commodity transaction.
Item 2. Management's Discussion and Analysis of Financial Condition and - ------------------------------------------------------------------------ Results of Operations (Cont.) ---------------------------- At June 30, 1998, NFR had long positions in the futures market amounting to a notional amount of 9.3 Bcf at prices ranging from $2.04 per Mcf to $2.96 per Mcf. The weighted average contract price of these futures contracts is approximately $2.48 per Mcf. NFR had short positions in the futures market amounting to a notional amount of 2.9 Bcf at prices ranging from $2.11 per Mcf to $2.77 per Mcf. The weighted average contract price of these futures contracts is approximately $2.51 per Mcf. In addition, the Company has SEC authority to enter into certain hedging transactions related to its borrowings. For further discussion, refer to Note 4 - Derivative Financial Instruments. The Company's credit risk is the risk of loss that the Company would incur as a result of nonperformance by counterparties pursuant to the terms of their contractual obligations related to derivative financial instruments. The Company does not anticipate any material impact to its financial position, results of operations or cash flow as a result of nonperformance by counterparties.1 For further discussion, refer to Note 4 - Derivative Financial Instruments. The Company is involved in litigation arising in the normal course of business. The Company is involved in regulatory matters arising in the normal course of business that involve rate base, cost of service and purchased gas cost issues, among other things. While the resolution of such litigation or regulatory matters could have a material effect on earnings and cash flows in the year of resolution, none of this litigation and none of these regulatory matters are expected to change materially the Company's present liquidity position, nor have a material adverse effect on the financial condition of the Company at this time.1 RATE MATTERS Utility Operation. New York Jurisdiction - --------------------- In November 1995, Distribution Corporation filed in its New York jurisdiction a request for an annual rate increase of $28.9 million with a requested return on equity of 11.5%. A two-year settlement with the parties in this rate proceeding was approved by the Public Service Commission of the State of New York (PSC). Effective October 1, 1996 and October 1, 1997, Distribution Corporation received annual base rate increases of $7.2 million. The settlement did not specify a rate of return on equity. Generally, earnings above a 12% return on equity (excluding certain items and determined on a cumulative basis over the three years ending September 30, 1998) will be shared equally between shareholders and ratepayers. As a result of this sharing mechanism, Distribution Corporation recorded an estimated cumulative refund provision to its customers of $3.0 million ($2.0 million after-tax) during the fourth quarter of 1997. An additional $4.9 million ($3.2 million after-tax) was accrued during the nine months ended June 30, 1998. The final amount owed to customers, if any, will not be known until the conclusion of the settlement period. Recently, management has been meeting with the PSC staff and other interested parties on modifying and/or extending the current
Item 2. Management's Discussion and Analysis of Financial Condition and - ------------------------------------------------------------------------ Results of Operations (Cont.) ---------------------------- two-year rate settlement that ends on September 30, 1998. The Company cannot predict the outcome at this time. By an order issued on September 4, 1997, the PSC directed the state's local distribution companies (LDCs) to file a "plan for competition" addressing issues relating to disposition of upstream assets in light of anticipated growth in small volume transportation conversions. On April 1, 1998, Distribution Corporation filed its plan. Distribution Corporation's plan responds to questions posed by the PSC on such issues as upstream capacity contracts, encouraging competition, assessing strandable costs and designing remedies, if necessary. In addition, Distribution Corporation explained that, in order to assure reliability, maintain operational flexibility and avoid stranded costs, upstream capacity currently held for sales obligations should be allocated to marketers serving customers converting to transportation service. This proceeding remains pending before the PSC. On April 3, 1998, Distribution Corporation filed comments in a PSC generic proceeding addressing gas transportation rates for electric generators. This case arose in response to concerns by the PSC regarding the effects of gas transportation costs on electric rates ultimately paid by retail customers. Distribution Corporation argued, among other things, that the current rate setting policy, established in 1991, should remain unchanged for LDCs facing competitive bypass threats. Distribution Corporation believes that the PSC may be focusing its attention on transfer pricing arrangements between gas and electric divisions of combination utilities. Staff for the PSC has informally expressed that existing generation and co-generation contracts will not be disturbed by the outcome of this proceeding. The PSC issued a notice on April 7, 1998 that it is considering the revision of its regulations governing the operation of the Gas Adjustment Clause (GAC). As described by the PSC, the revised rules would allow the GAC to more accurately reflect gas prices. The revised rules would also allow LDCs to recover risk management costs through the GAC. On June 5, 1998, Distribution Corporation filed comments in the GAC docket raising several concerns with the PSC's proposed revisions. New York's gas industry restructuring effort continues to develop at a slow pace. As of July 15, 1998, 35,811 small volume customers across the state chose aggregator services over their utility. In Distribution Corporation's service territory, 4,572 small volume customers (out of over 500,000) are purchasing gas from fifteen aggregators, for a total annual load of just over 3.6 Bcf. The Distribution Corporation's marketing affiliate, NFR, is one of the participating aggregators. Pennsylvania Jurisdiction - ------------------------- Distribution Corporation currently does not have a rate case on file with the Pennsylvania Public Utility Commission (PaPUC). Management will continue to monitor its financial position in the Pennsylvania jurisdiction to determine the necessity of filing a rate case in the future. Effective October 1, 1997, Distribution Corporation commenced a PaPUC approved customer choice pilot program called Energy Select. Energy Select, which will last until April 1, 1999, allows approximately 19,000 small
Item 2. Management's Discussion and Analysis of Financial Condition and - ------------------------------------------------------------------------ Results of Operations (Cont.) ---------------------------- commercial and residential customers of Distribution Corporation in the greater Sharon, Pennsylvania area to purchase gas supplies from qualified, participating non-utility suppliers (or marketers) of gas. Distribution Corporation is not a supplier of gas in this pilot. Under Energy Select, Distribution Corporation will continue to deliver the gas to the customer's home or business and will remain responsible for reading customer meters, the safety and maintenance of its pipeline system and responding to gas emergencies. NFR is a participating supplier in Energy Select. A gas restructuring bill (Senate Bill No. 943) was introduced in the Pennsylvania General Assembly proposing to amend the Public Utility Code to allow all retail customers, including residential, the ability to choose their own gas supplier. Senate Bill No. 943 was not enacted into law in 1997. However, in December 1997, the Chairman of the PaPUC convened a collaborative of gas industry interests to develop a consensus bill using Senate Bill No. 943 as the starting point. As a member of the utility interest group, Distribution Corporation is and will continue to be an active participant in the collaborative. The Company is not able to predict the outcome of the bill. Base rate adjustments in both the New York and Pennsylvania jurisdictions do not reflect the recovery of purchased gas costs. Such costs are recovered through operation of the purchased gas adjustment clauses of the regulatory authorities having jurisdiction. Pipeline and Storage. Supply Corporation currently does not have a rate case on file with the FERC. Its last case was settled with the FERC in February 1996. As part of that settlement, Supply Corporation agreed not to seek recovery of revenues related to certain terminated service from storage customers until April 1, 2000, as long as the terminations were not greater than approximately 30% of the terminable service. Management has been successful in marketing and obtaining executed contracts for such terminated storage service and does not anticipate a problem in obtaining executed contracts for additional terminated storage service as it arises.1 OTHER MATTERS Environmental Matters. The Company is subject to various federal, state and local laws and regulations relating to the protection of the environment. The Company has established procedures for on-going evaluation of its operations to identify potential environmental exposures and assure compliance with regulatory policies and procedures. It is the Company's policy to accrue estimated environmental clean-up costs when such amounts can reasonably be estimated and it is probable that the Company will be required to incur such costs. Distribution Corporation has estimated that clean-up costs related to several former manufactured gas plant sites and several other waste disposal sites may be in the range of $13.7 million to $14.7 million.1 At June 30, 1998, Distribution Corporation has recorded the minimum liability of $13.7 million. The approximate 50% increase in the liability since September 30, 1997 mainly relates to changing circumstances and revised estimates for one particular former manufactured gas plant site. The ultimate cost to Distribution Corporation with respect to the remediation of all sites will depend on such factors as the remediation plan selected, the extent of the site contamination, the number of additional
Item 2. Management's Discussion and Analysis of Financial Condition and - ------------------------------------------------------------------------ Results of Operations (Cont.) ---------------------------- potentially responsible parties at each site and the portion, if any, attributed to Distribution Corporation.1 The Company is currently not aware of any material additional exposure to environmental liabilities. However, changes in environmental regulations or other factors could adversely impact the Company. In New York and Pennsylvania, Distribution Corporation is recovering site investigation and remediation costs in rates. For further discussion, see disclosure in Note H - Commitments and Contingencies under the heading "Environmental Matters" in Item 8 of the Company's 1997 Form 10-K. New Accounting Pronouncements. In 1998, the Financial Accounting Standards Board issued new pronouncements that will impact the Company: Statement of Financial Accounting Standards (SFAS) No. 132, "Employers' Disclosures about Pensions and Other Postretirement Benefits" and SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities." For further discussion refer to Note 1 - "Summary of Significant Accounting Policies." Year 2000. The Company is in the process of preparing all of its computer systems to be Year 2000 compliant. Management has completed a detailed analysis of its computer systems to identify the systems that could be affected and has developed a conversion plan to resolve the issue. For various vendor supplied software, the Company is in the process of obtaining upgrades that are Year 2000 compliant. For internally developed software, changes to such software are being made and tested. The cost of upgrading both vendor supplied and internally developed systems is being expensed as incurred. Management estimates that such cost will total approximately $2.2 million, of which approximately $1.0 million has been incurred to date and $1.2 million remains to be spent.1 The Company's goal is to have its computer systems Year 2000 compliant early in calendar 1999.1 However, the Company has no control over the systems of third parties with whom it interfaces. While major third parties have been put on notice that the Company expects their products and services to perform as expected after January 1, 2000, the Company cannot predict the potential adverse consequences to the Company that could result if such third parties are not Year 2000 compliant.1 Safe Harbor for Forward-Looking Statements. The Company is including the following cautionary statement in this Form 10-Q to make applicable and take advantage of the safe harbor provisions of the Private Securities Litigation Reform Act of 1995 for any forward-looking statements made by, or on behalf of, the Company. Forward-looking statements include statements concerning plans, objectives, goals, strategies, future events or performance, and underlying assumptions and other statements which are other than statements of historical facts. From time to time, the Company may publish or otherwise make available forward-looking statements of this nature. All such subsequent forward-looking statements, whether written or oral and whether made by or on behalf of the Company, are also expressly qualified by these cautionary statements. Certain statements contained herein, including those which are designated with a "1", are forward-looking statements and accordingly involve risks and uncertainties which could cause actual results or outcomes to differ materially from those expressed in the forward-looking statements. The forward-looking statements contained herein are based on various assumptions, many of which are based, in turn, upon further assumptions. The Company's expectations, beliefs and projections are expressed in good faith and are believed by the Company to have a reasonable basis, including without
Item 2. Management's Discussion and Analysis of Financial Condition and - -------------------------------------------------------------------------- Results of Operations (Cont.) ---------------------------- limitation, management's examination of historical operating trends, data contained in the Company's records and other data available from third parties, but there can be no assurance that management's expectations, beliefs or projections will result or be achieved or accomplished. In addition to other factors and matters discussed elsewhere herein, the following are important factors that, in the view of the Company, could cause actual results to differ materially from those discussed in the forward-looking statement: 1. Changes in economic conditions, demographic patterns and weather conditions 2. Changes in the availability and/or price of natural gas and oil 3. Inability to obtain new customers or retain existing ones 4. Significant changes in competitive factors affecting the Company 5. Governmental/regulatory actions and initiatives, including those affecting financings, allowed rates of return, industry and rate structure, franchise renewal, and environmental/safety requirements 6. Unanticipated impacts of restructuring initiatives in the natural gas and electric industries 7. Significant changes from expectations in actual capital expenditures and operating expenses and unanticipated project delays 8. Occurrences affecting the Company's ability to obtain funds from operations, debt or equity to finance needed capital expenditures and other investments 9. Ability to successfully identify and finance oil and gas property acquisitions and ability to operate existing and any subsequently acquired properties 10. Ability to successfully identify, drill for and produce economically viable natural gas and oil reserves 11. Changes in the availability and/or price of derivative financial instruments 12. Inability of the various counterparties to meet their obligations with respect to the Company's financial instrument 13. Regarding foreign operations - changes in foreign trade and monetary policies, laws and regulations related to foreign operations, political and governmental changes, inflation and exchange rates, taxes and operating conditions 14. Significant changes in tax rates or policies or in rates of inflation or interest 15. Significant changes in the Company's relationship with its employees and the potential adverse effects if labor disputes or grievances were to occur
Item 2. Management's Discussion and Analysis of Financial Condition and - ----------------------------------------------------------------------- Results of Operations (Cont.) ---------------------------- 16. Changes in accounting principles and/or the application of such principles to the Company 17. Unanticipated problems related to the Company's internal Year 2000 initiative as well as potential adverse consequences related to third party Year 2000 compliance. The Company disclaims any obligation to update any forward-looking statements to reflect events or circumstances after the date hereof. Item 3. Quantitative and Qualitative Disclosures About Market Risk - ------------------------------------------------------------------- Not applicable. Part II. Other Information - --------------------------- Item 2. Changes in Securities - ------------------------------ On April 1, 1998, the Company issued 700 unregistered shares of Company common stock to the seven non-employee directors of the Company. These shares were issued as partial consideration for the directors' service as directors during the quarter ended June 30, 1998, pursuant to the Company's Retainer Policy for Non-Employee Directors. These transactions were exempt from registration by Section 4(2) of the Securities Act of 1933, as amended, as transactions not involving any public offering. Item 5. Other Information - -------------------------- Rule 14a-4(c) of the Securities and Exchange Commission's proxy rules allows the Company to use discretionary voting authority to vote on a matter coming before an annual meeting of stockholders which is not included in the Company's proxy statement, if the Company does not have notice of the matter at least 45 days before the date on which the Company first mailed its proxy materials for the prior year's annual meeting of stockholders. In addition, discretionary voting authority may generally also be used if the Company receives timely notice of such matter (as described in the preceeding sentence) and if, in the proxy statement, the Company describes the nature of such matter and how the Company intends to exercise its discretion to vote on such matter. Accordingly, for the 1999 Annual Meeting of Stockholders, which is scheduled to be held on or about February 18, 1999, any such notice must be submitted to the Company at the principal offices of the Company on or before November 16, 1998. This requirement is separate and apart from the Securities and Exchange Commission's requirements that a stockholder must meet in order to have a stockholder proposal included in the Company's proxy statement and form of proxy. As described in the Company's proxy statement for its 1998 Annual Meeting, specific proposals of stockholders intended to be presented at the 1999 Annual Meeting of Stockholders must be received at the principal offices of the Company no later than September 2, 1998 in order to be considered for inclusion in the Company's proxy materials relating to that meeting.
Item 6. Exhibits and Reports on Form 8-K - ----------------------------------------- (a) Exhibits Exhibit Number Description of Exhibit ------- ---------------------- (3i) Certificate of Amendment of Restated Certificate of Incorporation dated April 2, 1998 (12) Statements regarding Computation of Ratios: Ratio of Earnings to Fixed Charges for the Twelve Months Ended June 30, 1998 and the Fiscal Years Ended September 30, 1993 through 1997. (27.1) Financial Data Schedule for the Nine Months Ended June 30, 1998. (99) National Fuel Gas Company Consolidated Statement of Income for the Twelve Months Ended June 30, 1998 and 1997. (b) Reports on Form 8-K Report on Form 8-K was filed on May 1, 1998. Date of Report - April 29, 1998 Item 7 - Financial Statements and Exhibits Exhibit - News Release of the Company Dated April 29, 1998
SIGNATURE --------- Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. NATIONAL FUEL GAS COMPANY ------------------------- (Registrant) /s/Joseph P. Pawlowski --------------------------------------- Joseph P. Pawlowski Treasurer and Principal Accounting Officer Date: August 14, 1998
EXHIBIT INDEX (Form 10Q) Exhibit 3(i) Certificate of Ammendment of Restated Certificate of Incorporation dated April 2, 1998 Exhibit 12 Statements regarding Computation of Ratios: Ratio of Earnings to Fixed Charges for the Twelve Months Ended June 30, 1998 and the Fiscal Years Ended September 30, 1993 through 1997. Exhibit 27 Financial Data Schedule for the Nine Months Ended June 30, 1998. Exhibit 99 National Fuel Gas Company Consolidated Statement of Income for the Twelve Months Ended June 30, 1998 and 1997.