- -------------------------------------------------------------------------------- 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, 1999 ------------- 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, 1999: 38,798,310 shares. - --------------------------------------------------------------------------------
Company or Group of Companies for which Report is Filed: - -------------------------------------------------------- NATIONAL FUEL GAS COMPANY (Company or Registrant) SUBSIDIARIES: National Fuel Gas Distribution Corporation (Distribution Corporation) National Fuel Gas Supply Corporation (Supply Corporation) Seneca Resources Corporation (Seneca) Highland Land & Minerals, Inc. (Highland) Leidy Hub, Inc. (Leidy Hub) Data-Track Account Services, Inc. (Data-Track) National Fuel Resources, Inc. (NFR) Horizon Energy Development, Inc. (Horizon) Upstate Energy, Inc. (Upstate) Niagara Independence Marketing Company (NIM) Seneca Independence Pipeline Company (SIP) Utility Constructors, Inc. (UCI) NFR Power, Inc. 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, 1999 and 1998 4 - 5 b. Consolidated Balance Sheets - June 30, 1999 and September 30, 1998 6 - 7 c. Consolidated Statements of Cash Flows - Nine Months Ended June 30, 1999 and 1998 8 d. Consolidated Statements of Comprehensive Income - Three Months and Nine Months Ended June 30, 1999 and 1998 9 e. Notes to Consolidated Financial Statements 10 - 16 Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations 17 - 40 Item 3. Quantitative and Qualitative Disclosures About Market Risk 40 Part II. Other Information -------------------------- Item 1. Legal Proceedings * Item 2. Changes in Securities 40 Item 3. Defaults Upon Senior Securities * Item 4. Submission of Matters to a Vote of Security Holders * Item 5. Other Information 40 - 41 Item 6. Exhibits and Reports on Form 8-K 41 Signature 42 * The Company has nothing to report under this item.
Reference to "the Company" in this report means the Registrant or the Registrant and its subsidiaries collectively, as appropriate in the context of the disclosure. All references to a certain year in this report are to the Company's fiscal year ended September 30 of that year, unless otherwise noted. This Form 10-Q contains "forward-looking statements" 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, ------------------ 1999 1998 ---- ---- (Thousands of Dollars, Except Per Common Share Amounts) INCOME Operating Revenues $248,658 $243,130 -------- -------- Operating Expenses Purchased Gas 64,449 65,088 Fuel Used in Heat and Electric Generation 9,530 11,650 Operation 76,163 62,614 Maintenance 5,753 6,440 Property, Franchise and Other Taxes 20,817 20,716 Depreciation, Depletion and Amortization 32,880 31,019 Income Taxes - Net 7,747 11,877 -------- -------- 217,339 209,404 -------- -------- Operating Income 31,319 33,726 Other Income 1,584 5,651 -------- -------- Income Before Interest Charges and Minority Interest in Foreign Subsidiaries 32,903 39,377 -------- -------- Interest Charges Interest on Long-Term Debt 16,180 14,636 Other Interest 5,231 5,427 -------- -------- 21,411 20,063 -------- -------- Minority Interest in Foreign Subsidiaries 348 (207) -------- -------- Net Income Available for Common Stock 11,840 19,107 EARNINGS REINVESTED IN THE BUSINESS Balance at April 1 492,233 446,565 -------- -------- 504,073 465,672 Dividends on Common Stock (1999 - $.465; 1998 - $.45) 17,974 17,224 -------- -------- Balance at June 30 $486,099 $448,448 ======== ======== Earnings Per Common Share: Basic $ 0.31 $ 0.50 ====== ====== Diluted $ 0.30 $ 0.49 ====== ====== Weighted Average Common Shares Outstanding: Used in Basic Calculation 38,662,728 38,358,065 ========== ========== Used In Diluted Calculation 39,000,553 38,719,074 ========== ========== 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, ------------------ 1999 1998 ---- ---- (Thousands of Dollars, Except Per Common Share Amounts) INCOME Operating Revenues $1,072,484 $1,070,592 ---------- ---------- Operating Expenses Purchased Gas 377,273 418,228 Fuel Used in Heat and Electric Generation 47,311 30,160 Operation 228,586 214,454 Maintenance 17,400 19,347 Property, Franchise and Other Taxes 73,504 75,607 Depreciation, Depletion and Amortization 96,455 88,936 Impairment of Oil and Gas Producing Properties - 128,996 Income Taxes - Net 60,327 25,085 ---------- ---------- 900,856 1,000,813 ---------- ---------- Operating Income 171,628 69,779 Other Income 7,901 32,413 ---------- ---------- Income Before Interest Charges and Minority Interest in Foreign Subsidiaries 179,529 102,192 ---------- ---------- Interest Charges Interest on Long-Term Debt 49,630 37,517 Other Interest 16,755 26,260 ---------- ---------- 66,385 63,777 ---------- ---------- Minority Interest in Foreign Subsidiaries (2,540) (3,036) ---------- ---------- Income Before Cumulative Effect 110,604 35,379 Cumulative Effect of Change in Accounting for Depletion - (9,116) ---------- ---------- Net Income Available for Common Stock 110,604 26,263 EARNINGS REINVESTED IN THE BUSINESS Balance at October 1 428,112 472,595 ---------- ---------- 538,716 498,858 Dividends on Common Stock (1999 - $1.365; 1998 - $1.32) 52,617 50,410 ---------- ---------- Balance at June 30 $ 486,099 $ 448,448 ========== ========== Basic Earnings Per Common Share: Income Before Cumulative Effect $2.86 $ 0.93 Cumulative Effect of Change in Accounting for Depletion - (0.24) ----- ------ Net Income Available for Common Stock $2.86 $ 0.69 ===== ====== Diluted Earnings Per Common Share: Income Before Cumulative Effect $2.84 $ 0.92 Cumulative Effect of Change in Accounting for Depletion - (0.24) ----- ------ Net Income Available for Common Stock $2.84 $ 0.68 ===== ====== Weighted Average Common Shares Outstanding: Used in Basic Calculation 38,619,120 38,272,907 ========== ========== Used in Diluted Calculation 38,969,822 38,688,564 ========== ========== See Notes to Consolidated Financial Statements
Item 1. Financial Statements (Cont.) ---------------------------- National Fuel Gas Company ------------------------- Consolidated Balance Sheets --------------------------- June 30, 1999 September 30, (Unaudited) 1998 ----------- ------------- (Thousands of Dollars) ASSETS Property, Plant and Equipment $3,330,839 $3,186,853 Less - Accumulated Depreciation, Depletion and Amortization 1,003,818 938,716 ---------- ---------- 2,327,021 2,248,137 ---------- ---------- Current Assets Cash and Temporary Cash Investments 35,848 30,437 Receivables - Net 139,303 82,336 Unbilled Utility Revenue 13,023 15,403 Gas Stored Underground 20,737 31,661 Materials and Supplies - at average cost 23,069 24,609 Unrecovered Purchased Gas Costs - 6,316 Prepayments 26,026 19,755 ---------- ---------- 258,006 210,517 ---------- ---------- Other Assets Recoverable Future Taxes 88,302 88,303 Unamortized Debt Expense 21,771 22,295 Other Regulatory Assets 40,915 41,735 Deferred Charges 13,736 8,619 Other 77,413 64,853 ---------- ---------- 242,137 225,805 ---------- ---------- $2,827,164 $2,684,459 ========== ========== See Notes to Consolidated Financial Statements
Item 1. Financial Statements (Cont.) ---------------------------- National Fuel Gas Company ------------------------- Consolidated Balance Sheets --------------------------- June 30, 1999 September 30, (Unaudited) 1998 ----------- ------------- (Thousands of Dollars) CAPITALIZATION AND LIABILITIES Capitalization: Common Stock Equity Common Stock, $1 Par Value Authorized - 200,000,000 Shares; Issued and Outstanding - 38,750,428 Shares and 38,468,795 Shares, Respectively $ 38,751 $ 38,469 Paid in Capital 428,273 416,239 Earnings Reinvested in the Business 486,099 428,112 Cumulative Translation Adjustment (9,454) 7,265 ---------- ---------- Total Common Stock Equity 943,669 890,085 Long-Term Debt, Net of Current Portion 726,272 693,021 ---------- ---------- Total Capitalization 1,669,941 1,583,106 ---------- ---------- Minority Interest in Foreign Subsidiaries 24,346 25,479 ---------- ---------- Current and Accrued Liabilities Notes Payable to Banks and Commercial Paper 351,000 326,300 Current Portion of Long-Term Debt 159,696 216,929 Accounts Payable 44,966 59,933 Amounts Payable to Customers 21,484 5,781 Other Accruals and Current Liabilities 125,666 80,480 ---------- ---------- 702,812 689,423 ---------- ---------- Deferred Credits Accumulated Deferred Income Taxes 269,855 258,222 Taxes Refundable to Customers 18,404 18,404 Unamortized Investment Tax Credit 11,782 11,372 Other Deferred Credits 130,024 98,453 ---------- ---------- 430,065 386,451 ---------- ---------- Commitments and Contingencies - - ---------- ---------- $2,827,164 $2,684,459 ========== ========== See Notes to Consolidated Financial Statements
Item 1. Financial Statements (Cont.) ---------------------------- National Fuel Gas Company ------------------------- Consolidated Statements of Cash Flows ------------------------------------- (Unaudited) ----------- Nine Months Ended June 30, ------------------ 1999 1998 ---- ---- (Thousands of Dollars) OPERATING ACTIVITIES Net Income Available for Common Stock $110,604 $ 26,263 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 96,455 88,936 Deferred Income Taxes 12,912 (44,829) Minority Interest in Foreign Subsidiaries 2,540 3,036 Other 5,597 (215) Change in: Receivables and Unbilled Utility Revenue (56,195) (6,357) Gas Stored Underground and Materials and Supplies 11,659 14,422 Unrecovered Purchased Gas Costs 6,316 - Prepayments (6,284) (8,930) Accounts Payable (13,234) (14,237) Amounts Payable to Customers 15,703 5,003 Other Accruals and Current Liabilities 46,637 40,088 Other Assets (12,203) (11,470) Other Liabilities 31,576 12,802 -------- -------- Net Cash Provided by Operating Activities 252,083 242,624 -------- -------- INVESTING ACTIVITIES Capital Expenditures (209,918) (315,223) Investment in Subsidiaries, Net of Cash Acquired - (111,179) Other (114) 2,065 -------- -------- Net Cash Used in Investing Activities (210,032) (424,337) -------- -------- FINANCING ACTIVITIES Change in Notes Payable to Banks and Commercial Paper 24,700 105,187 Net Proceeds from Issuance of Long-Term Debt 98,736 198,750 Reduction of Long-Term Debt (115,365) (53,048) Dividends Paid on Common Stock (51,904) (49,734) Proceeds from Issuance of Common Stock 7,921 5,429 -------- -------- Net Cash Provided by (Used in) Financing Activities (35,912) 206,584 --------- -------- Effect of Exchange Rates on Cash (728) - --------- -------- Net Increase in Cash and Temporary Cash Investments 5,411 24,871 Cash and Temporary Cash Investments at October 1 30,437 14,039 -------- -------- Cash and Temporary Cash Investments at June 30 $ 35,848 $ 38,910 ======== ======== See Notes to Consolidated Financial Statements
Item 1. Financial Statements (Cont.) ---------------------------- National Fuel Gas Company ------------------------- Consolidated Statements of Comprehensive Income ----------------------------------------------- (Unaudited) ----------- Three Months Ended June 30, ------------------ 1999 1998 ---- ---- (Thousands of Dollars) Net Income Available for Common Stock $ 11,840 $ 19,107 Other Comprehensive Income, Net of Tax: Cumulative Translation Adjustment 2,326 116 -------- -------- Comprehensive Income Available for Common Stock $ 14,166 $ 19,223 ======== ======== Nine Months Ended June 30, ----------------- 1999 1998 ---- ---- (Thousands of Dollars) Net Income Available for Common Stock $110,604 $ 26,263 Other Comprehensive Income (Loss), Net of Tax: Cumulative Translation Adjustment (16,719) 1,026 -------- -------- Comprehensive Income Available for Common Stock $ 93,885 $ 27,289 ======== ======== 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. The consolidated financial statements include the accounts of the Company and its majority owned subsidiaries. The equity method is used to account for the Company's investment in minority owned entities. All significant intercompany balances and transactions have been eliminated where appropriate. The preparation of the consolidated financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements, as well as the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Quarterly Earnings. The Company, in its opinion, has included all adjustments that are necessary for a fair statement of the results of operations for the reported periods. The consolidated financial statements and notes thereto, included herein, should be read in conjunction with the financial statements and notes for the years ended September 30, 1998, 1997 and 1996, that are included in the Company's combined Annual Report to Shareholders/Form 10-K for 1998. The 1999 consolidated financial statements will be examined by the Company's independent accountants after the end of the year. The earnings for the nine months ended June 30, 1999 should not be taken as a prediction of earnings for the entire year ending September 30, 1999. 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 year. The impact of abnormal weather on earnings during the heating season is partially reduced by the operation of a weather normalization clause included in Distribution Corporation's New York tariff. The weather normalization clause is effective for October through May billings. Distribution Corporation's tariff for its Pennsylvania jurisdiction does not include a weather normalization clause. In addition, Supply Corporation's straight fixed-variable rate design, which allows for recovery of substantially all fixed costs in the demand or reservation charge, reduces the earnings impact of weather 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 units of production method was applied retroactively to prior years to determine the cumulative effect through October 1, 1997. This cumulative effect reduced earnings for 1998 by $9.1 million, net of income tax.
Item 1. Financial Statements (Cont.) ---------------------------- 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). Due to significant declines in oil prices in 1998, Seneca's capitalized costs under the full-cost method of accounting exceeded the full-cost ceiling at March 31, 1998. Accordingly, 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). Consolidated Statements of Cash Flows. For purposes of the Consolidated Statements 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, 1999 and 1998, amounted to $64.1 million and $38.0 million, respectively. Income taxes paid during the nine months ended June 30, 1999 and 1998 amounted to $30.4 million and $55.4 million, respectively. During the nine months ended June 30, 1999, the Company received a $1.0 million refund of taxes and interest from the Internal Revenue Service (IRS) stemming from the final settlement of the audits of years 1977-1994. During the nine months ended June 30, 1998, the Company received a $22.4 million refund of taxes and interest from the IRS stemming from the aforementioned settlement. 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.) ---------------------------- 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, ----------------- 1999 1998 ---- ---- Operating Expenses: Current Income Taxes - Federal $35,940 $59,208 State 6,050 6,814 Deferred Income Taxes - Federal 13,585 (41,132) State 1,706 (3,697) Foreign Income Taxes 3,046 3,892 ------- ------- 60,327 25,085 Other Income: Deferred Investment Tax Credit (499) (457) Minority Interest in Foreign Subsidiaries (705) (1,576) Cumulative Effect of Change in Accounting - (5,737) ------- ------- Total Income Taxes $59,123 $17,315 ======= ======= 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, ----------------- 1999 1998 ---- ---- Net income available for common stock $110,604 $ 26,263 Total income taxes 59,123 17,315 -------- -------- Income before income taxes $169,727 $ 43,578 ======== ======== Income tax expense, computed at federal statutory rate of 35% $ 59,404 $ 15,252 Increase (reduction) in taxes resulting from: State income taxes 5,045 1,488 Depreciation 1,492 1,738 Prior years tax adjustment (1,329) 3,021 Foreign tax in excess of (less than) federal statutory rate (2,620) 10 Miscellaneous (2,869) (4,194) --------- -------- Total Income Taxes $ 59,123 $ 17,315 ======== ========
Item 1. Financial Statements (Cont.) ---------------------------- Significant components of the Company's deferred tax liabilities (assets) were as follows (in thousands): At June 30, 1999 At September 30, 1998 ---------------- --------------------- Deferred Tax Liabilities: Abandonments $ 18,951 $ 15,545 Excess of tax over book depreciation 140,051 132,138 Exploration and intangible well drilling costs 163,302 147,795 Other 41,855 42,109 -------- -------- Total Deferred Tax Liabilities 364,159 337,587 -------- -------- Deferred Tax Assets: Overheads capitalized for tax purposes (24,793) (22,484) Other (69,511) (56,881) -------- -------- Total Deferred Tax Assets (94,304) (79,365) -------- -------- Total Net Deferred Income Taxes $269,855 $258,222 ======== ======== The primary issues related to Internal Revenue Service audits of the Company for the years 1977 - 1994 were settled during March 1998 with the settlement of remaining issues related to these same audits occurring in December 1998. Net income for the nine months ended June 30, 1999 and 1998 were increased by approximately $3.9 and $5.0 million, respectively, as a result of interest, net of tax and other adjustments, related to these settlements. Note 3 - Capitalization Common Stock. During the nine months ended June 30, 1999, the Company issued 94,255 shares of common stock under the Company's section 401(k) Plans, 88,446 shares to participants in the Company's Dividend Reinvestment Plan and 26,399 shares to participants in the Company's Customer Stock Purchase Plan. Additionally, 72,533 shares of common stock were issued under the Company's stock option and award plans, including 6,580 shares of restricted stock. On December 10, 1998, 615,500 stock options were granted at an exercise price of $46.0625 per share. Shareholder Rights Plan. The Company's shareholder rights plan (the "Plan") was adopted in 1996, and is described in the Company's combined Annual Report to Shareholders/Form 10-K for the year ended September 30, 1998 at Note D (Capitalization) to the financial statements which are found in Item 8. The Plan was amended effective April 30, 1999, and is now embodied in an Amended and Restated Rights Agreement, which was included as Exhibit 10.2 to the Company's Form 10-Q for the period ended March 31, 1999.
Item 1. Financial Statements (Cont.) ---------------------------- Long-Term Debt. In February 1999, the Company issued $100.0 million of 6.0% medium-term notes due to mature in March 2009. After deducting underwriting discounts and commissions, the net proceeds to the Company amounted to $98.7 million. The proceeds of this debt issuance were used to redeem $100.0 million of 5.58% medium-term notes which matured in March 1999. In July 1999, the Company issued $100.0 million of 6.82% medium-term notes due to mature in August 2004. After deducting underwriting discounts and commissions, the net proceeds to the Company amounted to $99.5 million. The proceeds of this debt issuance were used to redeem $50 million of 7.25% medium-term notes which matured in July 1999 and to complete the redemption of HarCor's 14.875% Senior Secured Notes, which is discussed below. In March 1999, the Company redeemed $10.3 million of HarCor Energy, Inc.'s (HarCor) 14.875% Senior Secured Notes through an open market purchase. HarCor is a wholly-owned subsidiary of Seneca. The total cost of this redemption was $11.9 million, which included a redemption price of 110% and accrued interest. In July 1999, the Company redeemed the remaining $43.5 million of HarCor's 14.875% Senior Secured Notes. The total cost of this redemption was $51.0 million, which included a redemption price of 110% and accrued interest. As noted above, this redemption was financed primarily by proceeds from the Company's July 1999 issuance of 6.82% medium-term notes. The redemption premiums were accrued on the opening balance sheet when HarCor was acquired in 1998. Note 4 - Derivative Financial Instruments Seneca has entered into certain price swap agreements and options to manage a portion of the market risk associated with fluctuations in the price of natural gas and crude oil, in an effort to provide more stability to its operating results. These agreements and options are not held for trading purposes. The price swap agreements call for Seneca to receive monthly payments from (or make payment 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. At June 30, 1999, Seneca had natural gas price swap agreements covering a notional amount of 17.9 Bcf extending through 2002 at a weighted average fixed rate of $2.45 per Mcf. Seneca also had crude oil price swap agreements covering a notional amount of 1,550,000 bbls extending through 2001 at a fixed rate of $17.76 per bbl. Gains or losses from these price swap agreements are accrued in Operating Revenues on the Consolidated Statement of Income at the contract settlement dates. Seneca recognized gains of $0.3 million and $6.2 million related to its price swap agreements during the quarter and nine months ended June 30, 1999, respectively. During the quarter ended June 30, 1998, Seneca recognized gains of $0.9 million related to its price swap agreements. For the nine months ended June 30, 1998, Seneca recognized losses of $6.9 million related to its price swap agreements. The unrealized net loss on these natural gas and crude oil price swap agreements was $2.4 million at June 30, 1999.
Item 1. Financial Statements (Cont.) ---------------------------- At June 30, 1999, Seneca had the following options outstanding: Weighted Average Type of Option Notional Amount Strike Price - -------------- --------------- ---------------- Written Call Options* 13.9 Bcf or $2.62/Mcf or 732,000 bbls $18.00/bbl Written Call Option 19.1 Bcf $2.65/Mcf Written Put Option 1,100,000 bbls $12.50/bbl Purchased Call Option 1,832,000 bbls $20.00/bbl *The counterparty has a choice between a natural gas call option and a crude oil call option, depending on whichever option has a greater value to the counterparty. Seneca's call and put options are being marked-to-market on a quarterly basis with gains or losses recorded in Operating Revenues on the Consolidated Statement of Income. The mark-to-market adjustment for the quarter and nine months ended June 30, 1999 was a loss of $1.1 million, which was recorded in Operating Revenues on the Consolidated Statement of Income. The fair value of the call and put options at June 30, 1999 was a net liability of $3.4 million. None of the options were exercised during the quarter ended June 30, 1999. For the nine months ended June 30, 1999, a portion of the written put options were exercised, resulting in a minimal payment of $28,000 to the counterparty. The Company is exposed to credit risk on the price swap agreements that Seneca has entered into as well as on the call options that Seneca has purchased. Credit risk relates to the risk of loss that the Company would incur as a result of nonperformance by Seneca's counterparties of their contractual obligations pursuant to the price swap agreements. To mitigate such credit risk, before entering into a price swap agreement with a new counterparty, management performs a credit check and prepares a report indicating the results of the credit investigation. This report must be approved by Seneca's board of directors after which a Master Swap Agreement is executed between Seneca and the counterparty. On an ongoing basis, periodic reports are prepared by management to monitor counterparty credit exposure. In the case of the call options that Seneca purchased, the counterparty selected was one in which Seneca currently has a Master Swap Agreement, meaning that a credit investigation had been completed and continues to be monitored. Considering the procedures in place, the Company does not anticipate any material impact to its financial position, results of operations, or cash flows as a result of nonperformance by counterparties. NFR utilizes exchange-traded futures and options to manage a portion of the market risk associated with fluctuations in the price of natural gas. Such futures and options are not held for trading purposes. At June 30, 1999, NFR had natural gas futures contracts related to gas purchase and sale commitments covering 7.2 Bcf of gas on a net basis extending through 2000 at a weighted average contract price of $2.40 per Mcf. NFR also had sold natural gas options related to gas purchase and sale commitments covering 3.3 Bcf of gas on a net basis extending through 2000 at a weighted average strike price of $2.68 per Mcf. 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, 1999, NFR had deferred gains of $3.0 million related to these futures contracts and options. NFR recognized net losses of $1.1 million related to futures contracts and options
Item 1. Financial Statements (Cont.) ---------------------------- during the quarter ended June 30, 1999. For the quarter ended June 30, 1998, NFR recognized a minimal gain. NFR recognized net losses of $6.5 million related to futures contracts and options for the nine months ended June 30, 1999. For the nine months ended June 30, 1998, NFR recognized net gains of $1.3 million. Since these futures contracts and options qualify and have been designated as hedges these net losses and gains were substantially offset by the related commodity transaction. 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 the ongoing evaluation of its operations in order 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 (investigation and remediation) 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 its clean-up costs related to former manufactured gas plant sites and third party waste disposal sites will be in the range of $9.1 million to $10.1 million. At June 30, 1999, Distribution Corporation has recorded the minimum liability of $9.1 million. The Company is currently not aware of any material additional exposure to environmental liabilities. However, adverse changes in environmental regulations or other factors could impact the Company. In New York and Pennsylvania, Distribution Corporation is recovering site investigation and remediation costs in rates. Accordingly, the Consolidated Balance Sheet at June 30, 1999 includes related regulatory assets in the amount of approximately $11.7 million. The Company, in its international operations in the Czech Republic, is in the process of constructing new fluidized-bed boilers at the district heating and power generation plant of Prvni severozapadni teplarenska, a.s. (PSZT) in order to comply with certain clean air standards mandated by the Czech Republic government. Capital expenditures related to this construction incurred by PSZT for the nine months ended June 30, 1999 were approximately $20.4 million. An additional $12.6 million is budgeted for this construction for the remainder of 1999. For further discussion, refer to Note H - Commitments and Contingencies under the heading "Environmental Matters" in Item 8 of the Company's 1998 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 adverse effect on the financial condition of the Company at this time.
Item 2. Management's Discussion and Analysis of Financial Condition and --------------------------------------------------------------- Results of Operations --------------------- Earnings. The Company's earnings were $11.8 million, or $0.31 per common share ($0.30 per common share on a diluted basis), for the third quarter ended June 30, 1999. This compares with earnings of $19.1 million, or $0.50 per common share ($0.49 per common share on a diluted basis), for the quarter ended June 30, 1998. The Company's earnings were $110.6 million, or $2.86 per common share ($2.84 per common share on a diluted basis), for the nine months ended June 30, 1999. This compares with earnings of $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. Earnings for the nine months ended June 30, 1998 included a non-cash impairment of the Exploration and Production segment's oil and gas assets and a non-cash cumulative effect of a change in accounting. Last year's accounting change, which was a change in depletion methods for the Exploration and Production segment's oil and gas assets, had a negative $9.1 million (after-tax), or $0.24 per common share, non-cash cumulative effect through 1997, which was recorded in the first quarter of 1998. Excluding these two non-cash special 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). Discussion of Quarter Results. Except for the Other Nonregulated segment, which showed higher earnings in its timber and natural gas marketing operations, earnings decreased in all other segments for the quarter as compared with the prior year's quarter. The rebound in the market price of the Company's stock during the quarter ended June 30, 1999 (the price increased from $39.25 per common share on March 31, 1999 to $48.50 per common share on June 30, 1999), while benefiting shareholders, carried with it the required recognition of $5.9 million of expense for stock appreciation rights (SARs). This expense is spread across all segments. In the prior year's quarter, the Company's stock price decreased from $47.00 per common share on March 31, 1998 to $43.56 per common share at June 30, 1998. This resulted in the reduction of the SAR liability and related expense by $3.2 million in the quarter ended June 30, 1998. For the nine months ended June 30, 1999, the expense related to SARs of $1.5 million was not as significant as in the quarter since it reflects the stock price increase from September 30, 1998 ($47.00 per common share) to the price at June 30, 1999 ($48.50 per common share). For the nine months ended June 30, 1998, there was a minimal reduction of the SAR liability and related expense since the stock price at September 30, 1997 ($44.00 per common share) was close to the price at June 30, 1998 ($43.56 per common share). In the Pipeline and Storage and Utility segments, earnings were down because of the SARs expense, as discussed above, and because of $1.6 million of expense associated with an early retirement offer effective in May 1999. In addition, a buyout of a firm transportation agreement by a customer in the amount of $2.5 million made a positive contribution to the Pipeline and Storage segment's earnings in the third quarter of last year. Had it not been for the early retirement charge and the SARs, the Utility segment would have shown an increase in earnings in spite of a rate reduction in New York that became effective October 1, 1998 and a reduction in revenues due to the setting up of a special reserve to be applied against incremental costs resulting from the New York Public Service Commission's (PSC) gas restructuring efforts. Weather that was colder than the prior year's quarter and lower operation and maintenance (O&M) expenses (exclusive of the SARs and early retirement) benefited the Utility's earnings.
Item 2. Management's Discussion and Analysis of Financial Condition and --------------------------------------------------------------- Results of Operations (Cont.) ----------------------------- The International segment's decreased earnings reflect its Czech Republic operations where warmer weather and lower margins on heat and electric sales negatively impacted earnings. In addition, the prior year's quarter included a gain of approximately $1.2 million associated with U.S. dollar denominated debt. In the Exploration and Production segment, earnings were down slightly. Higher interest expense associated with the acquisitions made in the prior year impacted earnings this quarter. Partly offsetting this was an increase in oil prices, after hedging, which were higher than the prior year's quarter by $2.80 barrel (a 25% increase) and an increase in both oil and gas production. Discussion of Nine-Months Results. Excluding both the non-cash impairment and the cumulative effect of a change in accounting from the prior year's period, the decrease in earnings for the nine months ended June 30, 1999 as compared with the prior year's period was the result of lower earnings in the Exploration and Production and Pipeline and Storage segments offset in part by higher earnings in the Utility, International and Other Nonregulated segments. In the Exploration and Production segment, earnings are down primarily because of this segment's portion of interest income recognized last year related to the settlement of the primary issues of IRS audits of years 1977-1994. In addition, earnings year-to-date reflect low oil and gas prices experienced through most of the first part of this year and higher interest, as discussed above. In the Pipeline and Storage segment, lower earnings resulted from the expense associated with early retirement offers effective in December 1998 and May 1999, the previously mentioned buyout of a firm transportation agreement by a customer in the prior year, and the impact of the above noted settlement of IRS audits, which had a greater positive effect on earnings of this segment in the prior year-to-date period. Partly offsetting these items, the prior year's results reflect recognition of several reserves related to proposed pipeline projects and a storage loss that did not recur this year. In the Utility segment, earnings were up because the settlement of the primary issues of IRS audits had a negative impact on earnings in the prior year while adjustments made relating to the final settlement of these audits had a positive impact to earnings in the current year. Absent the IRS audit items, operating results of the Utility segment are actually down from the prior year as slightly colder weather (which mainly benefits the Pennsylvania jurisdiction) and lower O&M expense were not enough to offset the effects of the New York rate decrease, the special gas restructuring reserve and the expense associated with early retirement offers effective in December 1998 and May 1999. The International segment's higher earnings reflect nine months of results from one of its investments in the Czech Republic, while the prior year's period only includes five months. Earnings in the Other Nonregulated segment continue to benefit from timber and natural gas marketing operations. A more detailed discussion of current period results can be found in the business segment information that follows.
Item 2. Management's Discussion and Analysis of Financial Condition and --------------------------------------------------------------- Results of Operations (Cont.) ----------------------------- <TABLE> <CAPTION> OPERATING REVENUES (in thousands) Three Months Ended Nine Months Ended June 30, June 30, ------------------------- --------------------------- 1999 1998 % Change 1999 1998 % Change ---- ---- -------- ---- ---- -------- <S> <C> <C> <C> <C> <C> <C> Utility Retail Revenues: Residential $100,924 $100,816 0.1 $ 521,457 $ 553,950 (5.9) Commercial 15,214 17,831 (14.7) 93,444 114,512 (18.4) Industrial 2,618 3,478 (24.7) 11,988 15,137 (20.8) -------- -------- ---------- ---------- 118,756 122,125 (2.8) 626,889 683,599 (8.3) Off-System Sales 5,401 9,201 (41.3) 22,897 39,972 (42.7) Transportation 19,331 15,196 27.2 65,996 52,710 25.2 Other (292) (618) 52.8 (4,932) 2,834 (274.0) -------- -------- ---------- ---------- 143,196 145,904 (1.9) 710,850 779,115 (8.8) -------- -------- ---------- ---------- Pipeline and Storage Storage Service 15,663 15,315 2.3 47,289 47,785 (1.0) Transportation 22,054 22,756 (3.1) 69,946 71,218 (1.8) Other 2,752 3,252 (15.4) 9,441 10,509 (10.2) -------- -------- ---------- ---------- 40,469 41,323 (2.1) 126,676 129,512 (2.2) -------- -------- ---------- ---------- Exploration and Production 40,162 36,802 9.1 105,450 86,330 22.1 -------- -------- ---------- ---------- International 16,089 19,322 (16.7) 97,166 67,262 44.5 -------- -------- ---------- ---------- Other Nonregulated 32,410 24,054 34.7 107,899 85,380 26.4 -------- -------- ---------- ---------- Less-Intersegment Revenues 23,668 24,275 (2.5) 75,557 77,007 (1.9) -------- -------- ---------- ---------- $248,658 $243,130 2.3 $1,072,484 $1,070,592 0.2 ======== ======== ========== ========== </TABLE> <TABLE> <CAPTION> OPERATING INCOME (LOSS) BEFORE INCOME TAXES (in thousands) Three Months Ended Nine Months Ended June 30, June 30, ------------------------- ------------------------- 1999 1998 % Change 1999 1998 % Change ---- ---- -------- ---- ---- -------- <S> <C> <C> <C> <C> <C> <C> Utility $ 12,640 $ 12,956 (2.4) $121,123 $132,810 (8.8) Pipeline and Storage 14,256 19,960 (28.6) 53,633 56,976 (5.9) Exploration and Production* 12,640 11,859 6.6 29,796 (104,507) 128.5 International (1,941) 794 NM 18,675 7,704 142.4 Other Nonregulated 2,419 124 NM 10,481 3,063 242.2 Corporate (948) (90) NM (1,753) (1,182) (48.3) -------- -------- -------- -------- $ 39,066 $ 45,603 (14.3) $231,955 $ 94,864 144.5 ======== ======== ======== ======== </TABLE> *The nine months ended June 30, 1998 includes a 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.) ----------------------------- <TABLE> <CAPTION> SYSTEM NATURAL GAS VOLUMES (millions of cubic feet-MMcf) Three Months Ended Nine Months Ended June 30, June 30, ------------------------ ------------------------- 1999 1998 % Change 1999 1998 % Change ---- ---- -------- ---- ---- -------- <S> <C> <C> <C> <C> <C> <C> Utility Gas Sales Retail Sales: Residential 11,222 10,739 4.5 66,199 66,749 (0.8) Commercial 1,926 2,219 (13.2) 13,055 15,406 (15.3) Industrial 747 884 (15.5) 2,978 3,353 (11.2) ------- ------- ------- ------- 13,895 13,842 0.4 82,232 85,508 (3.8) Off-System 2,223 3,484 (36.2) 10,195 14,432 (29.4) ------- ------- ------- ------- 16,118 17,326 (7.0) 92,427 99,940 (7.5) ------- ------- ------- ------- Non-Utility Gas Sales Production(in equivalent MMcf) 16,759 15,840 5.8 45,607 36,293 25.7 ------- ------- ------- ------- Total Gas Sales 32,877 33,166 (0.9) 138,034 136,233 1.3 ------- ------- ------- ------- Transportation Utility 15,608 14,690 6.2 53,638 50,022 7.2 Pipeline and Storage 54,388 59,281 (8.3) 244,494 255,174 (4.2) Nonregulated 16 262 (93.9) 337 538 (37.4) ------- ------- ------- ------- 70,012 74,233 (5.7) 298,469 305,734 (2.4) ------- ------- ------- ------- Marketing Volumes 8,875 6,176 43.7 29,214 20,696 41.2 ------- ------- ------- ------- Less-Inter and Intrasegment Volumes: Transportation 23,649 22,796 3.7 133,301 125,539 6.2 Production 578 1,001 (42.3) 2,438 3,059 (20.3) ------- ------- ------- ------- 24,227 23,797 1.8 135,739 128,598 5.6 ------- ------- ------- ------- Total System Natural Gas Volumes 87,537 89,778 (2.5) 329,978 334,065 (1.2) ======= ======= ======= ======= </TABLE>
Item 2. Management's Discussion and Analysis of Financial Condition and --------------------------------------------------------------- Results of Operations (Cont.) ----------------------------- Utility. Operating revenues for the Utility segment decreased $2.7 million for the quarter ended June 30, 1999, as compared with the same period a year ago. This resulted from a reduction in retail and off-system gas sales revenue of $3.3 million and $3.8 million, respectively, offset in part by an increase in transportation revenue of $4.1 million. In addition, other operating revenue increased $0.3 million. The decrease in retail gas revenue was caused primarily by the general base rate decrease in the New York jurisdiction effective October 1, 1998. Retail gas sales volumes have increased slightly from the prior year's quarter, although higher volumes sold due to colder weather have been partly offset by a reduction in sales volumes due to the migration of certain retail customers to transportation service in both the New York and Pennsylvania jurisdictions. This is the result of customers turning to marketers for their gas supplies while using Distribution Corporation for gas transportation service. (Restructuring in the Utility segment's service territory is further discussed in the "Rate Matters" section that follows.) Transportation revenues and volumes are up as a result of the migration from retail service and because of colder weather. Off-system revenues are down due to lower volumes sold. The margins resulting from off-system sales are minimal. Operating revenues for the Utility segment decreased $68.3 million for the nine months ended June 30, 1999, as compared with the same period a year ago. This resulted from a reduction in retail and off-system gas sales revenue of $56.7 million and $17.1 million, respectively, and a reduction in other operating revenue of $7.8 million. These decreases were partly offset by an increase in transportation revenue of $13.3 million. The decrease in retail gas revenue was caused by the recovery of lower gas costs and the general base rate decrease in the New York jurisdiction effective October 1, 1998. The recovery of lower gas costs resulted from both lower retail volumes sold of 3.3 billion cubic feet (Bcf) and a lower average cost of purchased gas (the average cost of purchased gas was $3.64 per Mcf and $4.03 per Mcf, for the nine months ended June 30, 1999 and 1998, respectively). Despite weather that was colder than the prior year, retail volumes sold decreased, mainly due to the migration from retail to transportation service noted above. Transportation revenues increased and volumes are up 3.6 Bcf as a result of this migration and because of colder weather. Off-system revenues are down due to lower volumes sold. The decrease in other operating revenue of $7.8 million is due primarily to a $6.5 million gas restructuring reserve reducing revenue in the current nine month period, $6.0 million of revenue recorded in 1998 as a result of the settlement of IRS audits and $0.5 million of a revenue reduction in the current year due to a final IRS audit settlement. These items are offset in part by a $4.9 million refund provision recorded in the prior year's nine month period. The gas restructuring reserve is to be applied against incremental costs resulting from the PSC's gas restructuring efforts (the PSC's gas restructuring efforts are further discussed in the "Rate Matters" section that follows). The revenue related to the IRS audits represents the rate recovery of interest expense as allowed by the New York rate settlement of July 1996. The refund provision recorded in the prior year's period was for a 50% sharing with customers of earnings over a predetermined amount in
Item 2. Management's Discussion and Analysis of Financial Condition and --------------------------------------------------------------- Results of Operations (Cont.) ----------------------------- accordance with the New York rate settlement of July 1996. All of these items are included in the "Other" category in the Utility section of the Operating Revenues table above. Operating income before income taxes for the Utility segment decreased $0.3 million for the quarter ended June 30, 1999, as compared with the same period a year ago. This decrease reflects higher O&M ($4.0 million) and higher other operating expenses ($0.3 million) which were only partially offset by higher margin on gas and transportation sales of approximately $4.0 million (i.e., lower revenues, as noted above, more than offset by lower purchased gas costs). An item that increased margin by lowering gas costs was an adjustment for lost and unaccounted-for (LAUF) gas in the New York jurisdiction related to 1998. Since Distribution Corporation's earnings in 1998 were above the predetermined amount in accordance with the New York rate settlement of July 1996, 50% of the LAUF adjustment will be shared with customers and 50% (or $1.6 million) was recognized as a reduction in gas cost in June 1999. Higher O&M for the quarter includes higher SARs expense of $3.8 million and the expense related to the early retirement offer effective in May 1999 of $1.0 million. Partly offsetting these two major items was a reduction in other O&M expense of $0.8 million, including labor savings. Operating income before income taxes for the Utility segment decreased $11.7 million for the nine months ended June 30, 1999, as compared with the same period a year ago. Excluding the $6.0 million of rate recovery of interest expense related to the IRS audits in 1998, as well as $0.5 million of a revenue reduction in 1999 due to a final IRS audit settlement, as noted in the revenue discussion above (this rate recovery is offset 100% by interest expense, included below the operating income line), the Utility segment's pretax operating income decreased $5.2 million. This decrease reflects a lower margin on gas and transportation sales of approximately $3.1 million (i.e., lower revenues, as noted above, partly offset by lower purchased gas costs) and higher O&M ($2.4 million) offset in part by lower other operating expenses ($0.3 million). Although the LAUF gain is included in the margin for the nine months ended June 30, 1999, the lower margin reflects the previously mentioned rate reduction and gas restructuring reserve in New York. Higher O&M for the nine month period includes higher expense related to the early retirement offers effective in December 1998 and May 1999 of $5.6 million. Partly offsetting this major item was a reduction in other O&M expense of $3.2 million, including labor savings.
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 1999 Than Normal 1999 1998 Normal 1998 - ---------------------------------------------------------------------- Buffalo 982 816 738 (16.9) 10.6 Erie 880 755 695 (14.2) 8.6 Nine Months Ended June 30: -------------------------- Buffalo 6,647 6,065 5,817 (8.8) 4.3 Erie 6,123 5,513 5,338 (10.0) 3.3 - ---------------------------------------------------------------------- Pipeline and Storage. Operating income before income taxes for the Pipeline and Storage segment decreased $5.7 million and $3.3 million for the quarter and nine months ended June 30, 1999, respectively, as compared with the same periods a year ago. For the quarter, the decrease is primarily attributable to higher SARs expense of $4.0 million, expense related to the early retirement offer effective May 1, 1999 of $0.6 million and an accrual for a gas imbalance payable of $1.0 million. The decrease in operating income before income taxes for the nine months ended June 30, 1999, is primarily attributable to lower revenue from interruptible transportation and storage service, lower revenues from unbundled pipeline sales and open access transportation and the accrual for the gas imbalance payable, noted above. These items account for the majority of the $2.8 million revenue decrease of this segment. This combined with increased depreciation and other taxes offset in part by lower O&M expense reduced pretax operating income by $3.3 million. The reduction in O&M is partially attributable to certain reserves and base gas loss recorded in 1998. In the previous year, reserves were established for preliminary survey and investigation costs associated with the Niagara Expansion and Green Canyon projects. In addition, last year's period includes a base gas loss at the Zoar storage field. In total, these three items amounted to $3.7 million. Partly offsetting these reductions in O&M was the reversal of a reserve for a storage project in the first quarter of 1998 in the amount of $1.0 million and expense related to the early retirement offers in December 1998 and May 1999 of $1.4 million. Transportation volumes in this segment decreased 4.9 Bcf and 10.7 Bcf, respectively, for the quarter and nine months ended June 30, 1999. For the quarter, the majority of the volume decrease relates to firm contracted volumes and thus 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. For the nine month period, 9.5 Bcf of the 10.7 Bcf volume decrease relates to lower interruptible transportation. This decrease reduced Supply Corporation's revenues by $0.5 million.
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 $0.8 million for the quarter ended June 30, 1999, compared with the same period a year ago. This increase resulted primarily from higher oil prices and production and lower lease operating costs. Oil prices after hedging were higher than the prices for the prior year's quarter by $2.80 per bbl. The production increase came mainly from the properties acquired in the HarCor Energy, Inc. (HarCor), Whittier Trust Company (Whittier) and Bakersfield Energy Resources (BER) acquisitions in the prior year. There was also increased production in the Gulf Coast, primarily new production at Vermilion 309 and Vermilion 253. Lease operating costs decreased as a result of management's effort to reduce costs. The increases to operating income before income taxes noted above were partly offset by lower gas revenues, a mark-to-market adjustment for written options (see further discussion in Note 4 - - Derivative Financial Instruments), higher depletion expense and higher general and administrative costs. Gas revenues are down primarily due to lower gas prices, offset slightly by higher production. The weighted average gas price after hedging decreased $0.08 per Mcf, while production increased 209 MMcf. General and administrative costs are up primarily due to the SARs expense. For the nine months ended June 30, 1999, operating income before income taxes for the Exploration and Production segment increased $134.3 million, compared with the same period a year ago. Excluding the prior year's $129 million non-cash impairment of this segment's oil and gas assets, as discussed previously, operating income before income taxes for the nine months ended June 30, 1999, increased $5.3 million as compared with the prior year's same period. This increase on a year-to-date basis, was mainly caused by higher oil and gas production, due to the acquisitions on the West Coast in 1998, and new production on certain Gulf Coast properties. However, lower weighted average oil and gas prices, after hedging, higher lease operating costs, a mark-to-market adjustment for written options (see further discussion in Note 4 - - Derivative Financial Instruments) and higher depletion expense, partly offset the positive impacts of this higher production. PRODUCTION VOLUMES Exploration and Production. Three Months Ended Nine Months Ended June 30, June 30, ----------------------- ----------------------- 1999 1998 % Change 1999 1998 % Change ---- ---- -------- ---- ---- -------- Gas Production - (MMcf) Gulf Coast 8,532 8,552 (0.2) 21,473 21,253 1.0 West Coast 1,050 697 50.6 2,839 1,109 156.0 Appalachia 1,069 1,193 (10.4) 3,381 3,677 (8.1) ------ ------ ------ ------ 10,651 10,442 2.0 27,693 26,039 6.4 ====== ====== ====== ====== Oil Production - (Thousands of Barrels) Gulf Coast 352 312 12.8 1,022 921 11.0 West Coast 664 586 13.3 1,957 780 150.9 Appalachia 2 2 - 7 8 (12.5) ----- --- ----- ----- 1,018 900 13.1 2,986 1,709 74.7 ===== === ===== =====
Item 2. Management's Discussion and Analysis of Financial Condition and --------------------------------------------------------------- Results of Operations (Cont.) ----------------------------- AVERAGE PRICES Exploration and Production. Three Months Ended Nine Months Ended June 30, June 30, ----------------------- ----------------------- 1999 1998 % Change 1999 1998 % Change ---- ---- -------- ---- ---- -------- Average Gas Price/Mcf Gulf Coast $2.19 $2.29 (4.4) $1.99 $2.52 (21.0) West Coast $2.30 $2.19 5.0 $2.17 $2.17 - Appalachia $2.31 $2.72 (15.1) $2.42 $2.95 (18.0) Weighted Average $2.22 $2.33 (4.7) $2.06 $2.57 (19.8) Weighted Average After Hedging $2.24 $2.32 (3.4) $2.22 $2.25 (1.3) Average Oil Price/bbl Gulf Coast $16.54 $12.70 30.2 $13.41 $15.54 (13.7) West Coast $12.60 $ 8.75 44.0 $10.19 $10.10 0.9 Appalachia $14.95 $14.85 0.7 $13.19 $17.00 (22.4) Weighted Average $13.97 $10.13 37.9 $11.30 $13.06 (13.5) Weighted Average After Hedging $14.02 $11.22 25.0 $11.92 $13.78 (13.5) Seneca has entered into certain price swap agreements and options to manage a portion of the market risk associated with fluctuations in the price of natural gas and crude oil, in an effort to provide more stability to its operating results (refer to the "Market Risk Sensitive Instruments" section of this Item and to Note 4 - Derivative Financial Instruments for further discussion). The following summarizes Seneca's settlements under its price swap agreements and options. Three Months Ended Nine Months Ended June 30, June 30, ------------------ ----------------- 1999 1998 1999 1998 ---- ---- ---- ---- Natural Gas Price Swap Agreements: Notional Quantities - Equivalent Bcf 6.6 6.0 17.9 19.1 Gain (Loss) (thousands of dollars) $227,000 $(82,000) $4,357,000 $(8,167,000) Crude Oil Price Swap Agreements: Notional Quantities - Equivalent bbls 232,000 219,000 547,000 672,000 Gain (thousands of dollars) $52,000 $982,000 $1,871,000 $ 1,221,000 Written Put Option on Crude Oil: Notional Quantities - Equivalent bbls - - 118,000 - Gain (Loss) (thousands of dollars) - - $(28) -
Item 2. Management's Discussion and Analysis of Financial Condition and --------------------------------------------------------------- Results of Operations (Cont.) ----------------------------- International. Operating income before income taxes for the International segment decreased $2.7 million for the quarter ended June 30, 1999, compared with the same period a year ago. This decrease resulted from warmer weather and lower margins on heat and electric sales combined with higher O&M expense. Operating income before income taxes for the nine months ended June 30, 1999, increased $11.0 million for this segment. This increase, as well as the revenue increase shown in the "Operating Revenues" table above and the "Heat and Electric Revenues" table below, resulted primarily from the operations of Prvni severozapadni teplarenska, a.s. (PSZT), a district heating and power generation plant located in the northern part of the Czech Republic. Horizon first acquired 75.3% of the outstanding shares of PSZT in February 1998 and currently owns 86.2%. The nine months ended June 30, 1998 reflected only five months of operating revenues and income for PSZT. The following table summarizes the heating and electricity sales of the International segment for the quarter and nine months ended June 30, 1999 and 1998, respectively: Heating and Electric Volumes Three Months Ended Nine Months Ended June 30, June 30, ------------------ ----------------- 1999 1998 1999 1998 ---- ---- ---- ---- Heating (Gigajoules) 1,266,928 1,385,875 9,502,414 6,246,905 Electricity (Megawatt hours) 279,987 277,280 897,829 520,635 Heating and Electric Revenues Three Months Ended Nine Months Ended June 30, June 30, ------------------ ----------------- (in thousands) 1999 1998 1999 1998 ---- ---- ---- ---- Heating $ 8,225 $ 9,516 $68,522 $43,222 Electricity $ 7,853 $ 9,827 $27,531 $15,907 Other Nonregulated. Operating income before income taxes associated with this segment increased $2.3 million and $7.4 million, respectively, for the quarter and nine months ended June 30, 1999, compared with the same periods a year ago. The increases can be attributed primarily to improved performance in the Company's timber operations and principal energy marketing subsidiary. The increased performance in the timber operations resulted from the 1998 purchase of timber property and two lumber mills during 1998. The increased performance of NFR, the Company's principal energy marketing subsidiary, was the result of increased volumes and margins, offset in part by higher operating and maintenance expense.
Item 2. Management's Discussion and Analysis of Financial Condition and --------------------------------------------------------------- Results of Operations (Cont.) ----------------------------- Income Taxes. Income taxes decreased $4.1 million for the quarter ended June 30, 1999, primarily as a result of a decrease in pretax income. For the nine months ended June 30, 1999, income taxes increased $35.2 million, primarily as a result of an increase in pretax income (pretax income before cumulative effect, for the nine months ended June 30, 1998). For further discussion of income taxes, refer to "Note 2 - Income Taxes" in Part I, Item 1 of this report. Other Income. Other income decreased $4.1 million and $24.5 million, respectively, for the quarter and nine months ended June 30, 1999. For the quarter, this decrease is primarily the result of a buyout of a firm transportation agreement by a Pipeline and Storage segment customer in the prior year's quarter in the amount of $2.5 million combined with a gain of $1.2 million that was also recorded in the prior year for U.S. dollar denominated debt carried on the balance sheet of PSZT (until December 1998, at which time it was converted to a Czech koruna denominated loan). The decrease 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) combined with $18.5 million of interest income, which resulted from the settlement of IRS audits in March 1998. As an offset to these decreases, $3.1 million of interest income was recorded in December 1998 related to a final settlement of these audits. Interest Charges. Interest on long-term debt increased $1.5 million and $12.1 million for the quarter and nine months ending June 30, 1999, respectively, mainly because of a higher average amount of long-term debt outstanding compared to the same periods a year ago. Long-term balances have grown significantly as a result of last year's acquisitions of PSZT, HarCor, Whittier and BER, as well as last year's additional investment in Severoceske teplarny, a.s. (SCT). Other interest decreased $0.2 million and $9.5 million for the quarter and nine-month period ended June 30, 1999. The decrease in the quarter was the result of lower interest rates, partly offset by higher short-term debt balances. The decrease in the nine-month period as compared to the prior year was mainly the result of interest expense related to the previously mentioned settlement of IRS audits. The nine months ended June 30, 1998 included $11.7 million of interest expense related to these IRS audits. The nine months ended June 30, 1999 includes a reduction of interest expense of $1.3 million related to the final settlement of these audits. Partly offsetting these decreases in the nine months was higher interest on short-term borrowings as the result of higher short-term debt balances, offset in part by lower interest rates. Short-term debt balances are at a higher level due to the aforementioned acquisitions in 1998, combined with the retirement of long-term debt in 1998.
Item 2. Management's Discussion and Analysis of Financial Condition and --------------------------------------------------------------- Results of Operations (Cont.) ----------------------------- CAPITAL RESOURCES AND LIQUIDITY The Company's primary sources of cash during the nine month period ended June 30, 1999, consisted of cash provided by operating activities, long-term debt and short-term bank loans and commercial paper. These sources were supplemented by issuances of common stock under the Company's stock and benefit plans. 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 depreciation, depletion and amortization, deferred income taxes, minority interest in foreign subsidiaries and allowance for funds used during construction. For the nine months ended June 30, 1998, non-cash items also included the cumulative effect of a change in accounting for depletion and the impairment of oil and gas producing properties. 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, pipeline company refunds, over- or under-recovered purchased gas costs and weather also significantly impact cash flow. The Company considers pipeline company 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 weather normalization clause and in the Pipeline and Storage segment by Supply Corporation's SFV rate design. Historically, because of the seasonal nature of the Company's heating business, revenues have been relatively high during the nine months ended June 30 and receivables have increased between September and June because of winter weather. The storage gas inventory normally declines during the first and second quarters of the year and is replenished during the third and fourth quarters. For storage gas inventory accounted for under the last-in, first-out (LIFO) method, the current cost of replacing gas withdrawn from storage is recorded in the Consolidated 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 $252.1 million for the nine months ended June 30, 1999, an increase of $9.5 million compared with the $242.6 million provided by operating activities for the nine months ended June 30, 1998. This slight increase is attributed primarily to the Utility segment's contribution offset partly by a decrease to cash provided by operations in the Exploration and Production segment. The increase in the Utility segment can be attributed to lower cash disbursements for gas purchases, taxes and interest, all of which more than offset lower cash receipts from gas sales and transportation service. The decrease to cash provided by operations in the Exploration and Production segment is primarily because of an increase in interest payments stemming from the acquisitions made in 1998. An increase in cash received from hedging transactions offset the decrease in cash receipts from the Exploration and Production segment's sale of natural gas and crude oil production.
Item 2. Management's Discussion and Analysis of Financial Condition and --------------------------------------------------------------- Results of Operations (Cont.) ----------------------------- Investing Cash Flow. Capital Expenditures and Other Investing Activities - --------------------------------------------------- Capital expenditures represent the Company's additions to property, plant and equipment and are exclusive of investments in corporations (stock acquisitions) and/or partnerships. Such investments are treated separately in the Statements of Cash Flows and further discussed in the segment discussion below. The Company's capital expenditures and other investments totaled $213.5 million during the nine months ended June 30, 1999. The following table summarizes the Company's capital expenditures and other investments by business segment: (in millions) Other Total Capital Investments Capital Expenditures through Expenditures and through 6/30/99 6/30/99 Other Investments --------------- ----------- ----------------- Utility $ 30.6 $ - $ 30.6 Pipeline and Storage 19.4 3.6 23.0 Exploration and Production 80.5 - 80.5 International 23.6 - 23.6 Other Nonregulated 55.8 - 55.8 ------ ----- ------ $209.9 $ 3.6 $213.5 ====== ===== ====== Utility - ------- The Utility capital expenditures were made primarily for replacement of mains and main extensions, as well as for the replacement of service lines. Pipeline and Storage - -------------------- The Pipeline and Storage capital expenditures were made primarily for additions, improvements, and replacements to this segment's transmission and storage systems. During the nine month period, SIP made a $3.6 million investment in Independence Pipeline Company, a Delaware general partnership, bringing its total investment through June 30, 1999 to $9.1 million. This investment represents a one-third partnership interest. The investment has been financed with short-term borrowings. Independence Pipeline Company intends to build a 370 mile natural gas pipeline (Independence Pipeline Project) 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 $9.0 to $13.0 million. Exploration and Production - -------------------------- The Exploration and Production segment's capital expenditures for the nine months ended June 30, 1999 contained approximately $46.7 million for Seneca's offshore program in the Gulf of Mexico, including offshore drilling expenditures, offshore construction, lease acquisition costs and geological and geophysical expenditures. Offshore drilling was concentrated on Vermilion
Item 2. Management's Discussion and Analysis of Financial Condition and --------------------------------------------------------------- Results of Operations (Cont.) ----------------------------- 309, Galveston 239, Vermilion 253, Brazos 414S, Brazos 375, Brazos 376 and Eugene Island Block 29. Offshore construction occurred primarily at Eugene Island 47 and Galveston 239. Lease acquisition costs resulted from successful bidding on six state of Texas tracts and five federal lease blocks in the Gulf of Mexico. Offshore geological and geophysical expenditures were made for purchases of 3-D seismic data. The remaining $33.8 million of capital expenditures reflects, among other things, onshore drilling, construction and recompletion costs for wells located in Louisiana, Texas, Alabama and California as well as onshore geological and geophysical costs, including the purchase of certain 3-D seismic data and fixed asset purchases. The onshore capital expenditures were concentrated on the California properties acquired through the Whittier and BER asset purchases, as well as the HarCor stock purchase, all of which occurred in 1998. Another area of emphasis included the Thomas Ranch #1-H Well in Grimes County, Texas. During the quarter ended June 30, 1999, Seneca sold its 50% working interest in the Jurassic Park prospect in Escambia and Monroe Counties, Alabama, which included two producing wells and approximately 3,300 gross acres. Proceeds from this sale, as well as other sales of assets within the Company, are included in other investing activities in the Statement of Cash Flows. International - ------------- The International segment capital expenditures were made primarily by PSZT for the construction of new fluidized-bed boilers at its district heating and power generation plant in order to comply with stricter clean air standards. Short-term borrowings and cash from operations were used to finance these capital expenditures. Other Nonregulated - ------------------ Other Nonregulated capital expenditures consisted primarily of 36,300 acres of land and timber purchased from PennzEnergy Company by Seneca and Highland. The purchase price was approximately $47 million and was funded by short-term borrowings. The remaining capital expenditures consisted of smaller land and timber purchases for Seneca's timber operations, as well as the installation of new equipment for Highland's sawmill and kiln operations. 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
Item 2. Management's Discussion and Analysis of Financial Condition and --------------------------------------------------------------- Results of Operations (Cont.) ----------------------------- Financing Cash Flow. Consolidated short-term debt increased by $24.7 million during the first nine months of 1999. 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 pipeline company 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. In February 1999, the Company issued $100.0 million of 6.0% medium-term notes due to mature in March 2009. After deducting underwriting discounts and commissions, the net proceeds to the Company amounted to $98.7 million. The proceeds of this debt issuance were used to redeem $100.0 million of 5.58% medium-term notes which matured in March 1999. In July 1999, the Company issued $100.0 million of 6.82% medium-term notes due to mature in August 2004. After deducting underwriting discounts and commissions, the net proceeds to the Company amounted to $99.5 million. The proceeds of this debt issuance were used to redeem $50 million of 7.25% medium-term notes which matured in July 1999 and to complete the redemption of HarCor's 14.875% Senior Secured Notes, which is discussed below. In March 1999, the Company redeemed $10.3 million of HarCor's 14.875% Senior Secured Notes through an open market purchase. The total cost of this redemption was $11.9 million, which included a redemption price of 110% and accrued interest. The Company used short-term debt to finance this redemption. In July 1999, the Company redeemed the remaining $43.5 million of HarCor's 14.875% Senior Secured Notes. The total cost of this redemption was $51.0 million, which included a redemption price of 110% and accrued interest. As noted above, this redemption was financed primarily by proceeds from the Company's July 1999 issuance of 6.82% medium-term notes. The redemption premiums were accrued on the opening balance sheet when HarCor was acquired in 1998. 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 July 1999, the Company filed a registration statement pursuant to the Securities Act of 1933 to register up to $625 million of either debt or equity securities. The Company's present liquidity position is believed to be adequate to satisfy known demands.1 Under the Company's covenants contained in its indenture covering long-term debt, at June 30, 1999, the Company would have been permitted to issue up to a maximum of $499.0 million in additional long-term unsecured indebtedness at projected market interest rates. In addition, at June 30, 1999, the Company had regulatory authorizations and unused short-term credit lines that would have permitted it to borrow an additional $399.0 million of short-term debt. The amounts and timing of the issuance and sale of debt and/or equity securities will depend on market conditions, regulatory authorizations, and the requirements of the Company.
Item 2. Management's Discussion and Analysis of Financial Condition and --------------------------------------------------------------- Results of Operations (Cont.) ----------------------------- The Company is involved in litigation arising in the normal course of business. 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 Market Risk Sensitive Instruments. For a complete discussion of market risk sensitive instruments, refer to "Market Risk Sensitive Instruments" in Item 7 of the Company's 1998 Form 10-K and Item 2 of the Company's December 31, 1998 Form 10-Q (see also "Note 4 - Derivative Financial Instruments in this Form 10-Q). There have been no subsequent material changes to the Company's exposure to market risk sensitive instruments. RATE MATTERS Utility Operation. New York Jurisdiction On October 21, 1998, the PSC approved a rate plan for Distribution Corporation for the period beginning October 1, 1998 and ending September 30, 2000. The plan is the result of a settlement agreement entered into by Distribution Corporation, Staff for the PSC (Staff), Multiple Intervenors (an advocate for large industrial customers) and the State Consumer Protection Board. Under the plan, Distribution Corporation's rates are reduced by $7.2 million, or 1.1%. In addition, customers will receive up to $6.0 million in bill credits, disbursed volumetrically over the two year term, reflecting a predetermined share of excess earnings under a 1996 settlement. An allowed return on equity of 12%, above which 50% of additional earnings are shared with the customers, is maintained from the 1996 settlement. Finally, the rate plan also provides that $7.2 million of 1999 revenues will be set aside in a special reserve to be applied against Distribution Corporation's incremental costs resulting from the PSC's gas restructuring effort further described below. On November 3, 1998, the PSC issued its Policy Statement Concerning ----------------------------- the Future of the Natural Gas Industry in New York State and Order Terminating - -------------------------------------------------------------------------------- Capacity Assignment (Policy Statement). The Policy Statement sets forth the - -------------------- PSC's "vision" on "how best to ensure a competitive market for natural gas in New York." That vision includes the following goals: (1) Effective competition in the gas supply market for retail customers; (2) Downward pressure on customer gas prices; (3) Increased customer choice of gas suppliers and service options; (4) A provider of last resort (not necessarily the utility); (5) Continuation of reliable service and maintenance of operations procedures that treat all participants fairly; (6) Sufficient and accurate information for customers to use in making informed decisions;
Item 2. Management's Discussion and Analysis of Financial Condition and --------------------------------------------------------------- Results of Operations (Cont.) ----------------------------- (7) The availability of information that permits adequate oversight of the market to ensure fair competition; and (8) Coordination of Federal and State policies affecting gas supply and distribution in New York State. The Policy Statement provides that the most effective way to establish a competitive market in gas supply is "for local distribution companies to cease selling gas." The PSC hopes to accomplish that objective over a three-to-seven year transition period, taking into account "statutory requirements" and the individual needs of each local distribution company (LDC).1 The Policy Statement directs Staff to schedule "discussions" with each LDC on an "individualized plan that would effectuate our vision." In preparation for negotiations, LDCs will be required to address issues such as a strategy to hold new capacity contracts to a minimum, a long-term rate plan with a goal of reducing or freezing rates, and a plan for further unbundling. In addition, Staff was instructed to hold collaborative sessions with multiple parties to discuss generic issues including reliability and market power regulation. As of February 1, 1999, Staff had convened a multitude of collaboratives, proceedings and discussions on various issues relating to restructuring, including reliability of service, billing and allocation of stranded costs. Distribution Corporation is participating in all facets of Staff's effort. The PSC's Order Terminating Capacity Assignment, included with the --------------------------------------- Policy Statement, directed the state's LDCs to file proposed tariffs, by no later than February 1, 1999, revising the current requirement that marketers take assignment of an allocation of upstream capacity for each customer that elects to purchase gas from a marketer other than the LDC. Although the order states that the so-called "mandatory assignment" feature of aggregation service was terminated effective April 1, 1999, LDCs are permitted to show that their individual circumstances may warrant continuation of the requirement. The order also recognizes that LDCs with intermediate pipelines, like Distribution Corporation, could present "unique cost and reliability issues which require further consideration." The order provides that to the extent all or part of an LDC's mandatory assignment authority is indeed terminated, there will be a reasonable opportunity to recover stranded costs. On February 1, 1999, Distribution Corporation filed revised tariff sheets in compliance with the Order Terminating Capacity Assignment. ------------------------------------------- Distribution Corporation's compliance filing is designed to comply with the PSC's directives and operate in the same manner as the company's "System Wide Energy Select" program approved for the Pennsylvania Division (described below). In an order issued on March 24, 1999, the PSC rejected portions of the February 1, 1999 compliance filing without prejudice, and directed Distribution Corporation to submit revised tariff sheets, effective April 1, 1999, to adopt a new capacity option for retail marketers. The new capacity option eliminates long line capacity upstream of Supply Corporation from the "mandatory capacity" requirement described above. This change, effective April 1, 1999, allows marketers to choose alternate capacity paths, if available, from the production area to Supply Corporation's city gate. Marketers will continue to be obligated to take release of Distribution Corporation's storage and transmission capacity on Supply Corporation. To the extent any stranded pipeline costs are generated by the above proposal, they would be recoverable from firm service customers through a "transition surcharge" mechanism.1
Item 2. Management's Discussion and Analysis of Financial Condition and --------------------------------------------------------------- Results of Operations (Cont.) ----------------------------- The effective date for the compliance filing was April 1, 1999. On March 17, 1999, the PSC issued an order in Case 98-G-0122 directing the state's LDCs to file a uniform, basic gas-for-electric-generation-service tariff to replace tariffs filed pursuant to the PSC's 1991 Bypass Policy Statement. Distribution Corporation serves a number of generation customers under tariffs designed pursuant to the 1991 Bypass Policy Statement. Although existing contracts for service would not be disturbed by the March 17, 1999 order, future contracts would be negotiated under the terms of the new, uniform tariff. In its filing to comply with the March 17 order, Distribution Corporation proposed to implement the PSC's uniform tariff while retaining flexibility for individual customer negotiations. The PSC has not ruled on Distribution Corporation's filing and the outcome cannot be ascertained at this time. To preserve its legal rights, however, Distribution Corporation filed for rehearing of the March 17, 1999 order challenging several features of the uniform tariff. That action remains pending. On June 7, 1999, the PSC issued a notice requesting comments on a proposal for a "single retailer" billing environment. The proposal recommends that electric and gas utilities exit the billing function at an undetermined future date. The retail billing function would then be performed solely by unregulated marketers. Included in the billing proposal is a recommendation that utilities design a "back-out" credit equal to the long run costs avoided by each utility when billing is provided by another party. Distribution Corporation filed comments opposing much of the proposal, but supporting a suggested interim regime where multiple billing arrangements, including utility billing, would be permitted. This proceeding remains pending. 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 lasted until April 1, 1999, allowed approximately 19,000 small commercial and residential customers of Distribution Corporation in the greater Sharon, Pennsylvania area to purchase gas supplies from qualified, participating non-utility suppliers (or marketers) of gas. Distribution Corporation was not a supplier of gas in this pilot. Under Energy Select, Distribution Corporation delivered the gas to the customer's home or business and remained responsible for reading customer meters, the safety and maintenance of its pipeline system and responding to gas emergencies. NFR was a participating supplier in Energy Select. Effective February 11, 1999, Distribution Corporation's System Wide Energy Select tariff was approved by the PaPUC. This program is intended to expand the Energy Select pilot program described above to apply across Distribution Corporation's entire Pennsylvania service territory. The plan borrows many features of the Energy Select pilot, but several important changes were adopted. Most significantly, the new program includes Distribution Corporation as a choice for retail consumers, in furtherance of Distribution Corporation's objective to remain a merchant. Also departing
Item 2. Management's Discussion and Analysis of Financial Condition and --------------------------------------------------------------- Results of Operations (Cont.) ----------------------------- from the pilot scheme, Distribution Corporation resumes its role as provider of last resort, and maintains customer contact by providing a billing service on its own behalf and, as an option, for participating marketers. Finally, the System Wide Energy Select program addresses upstream capacity requirements in a manner substantially similar to the method proposed for Distribution Corporation's New York compliance filing, described above. In Pennsylvania, a natural gas restructuring bill was signed into law on June 22, 1999. Entitled the Natural Gas Choice and Competition Act ("Act"), the new law requires all Pennsylvania LDCs to file tariffs designed to provide retail customers with direct access to competitive gas markets. Distribution Corporation has been scheduled by the PaPUC to submit its compliance filing on October 1, 1999, for an effective date on or about April 1, 2000. Distribution Corporation is currently reviewing the filing requirements and preparing its case. It is anticipated that the October 1 filing will largely mirror the Energy Select program currently in effect, which substantially complies with the Act's requirements. Base rate adjustments in both the New York and Pennsylvania jurisdictions do not reflect the recovery of purchased gas costs. Such costs are recovered through operation of the purchased gas adjustment clauses of the appropriate regulatory authorities. Pipeline and Storage. Supply Corporation currently does not have a rate case on file with the Federal Energy Regulatory Commission (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. Supply Corporation has been successful in marketing and obtaining executed contracts for such terminated storage service (at discounted rates) and expects to continue 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 the ongoing evaluation of its operations to identify potential environmental exposures and assure compliance with regulatory policies and procedures.1 It is the Company's policy to accrue estimated environmental clean-up costs (investigation and remediation) when such amounts can reasonably be estimated and it is probable that the Company will be required to incur such costs. Distribution Corporation has estimated its clean-up costs related to former manufactured gas plant sites and third party waste disposal sites will be in the range of $9.1 million to $10.1 million.1 At June 30, 1999, Distribution Corporation has recorded the minimum liability of $9.1 million. The Company is currently not aware of any material additional exposure to environmental liabilities. However, adverse changes in environmental regulations or other factors could impact the Company.
Item 2. Management's Discussion and Analysis of Financial Condition and --------------------------------------------------------------- Results of Operations (Cont.) ----------------------------- In New York and Pennsylvania, Distribution Corporation is recovering site investigation and remediation costs in rates. Accordingly, the Consolidated Balance Sheet at June 30, 1999 includes related regulatory assets in the amount of approximately $11.7 million. The Company, in its international operations in the Czech Republic, is in the process of constructing new fluidized-bed boilers at the district heating and power generation plant of PSZT in order to comply with certain clean air standards mandated by the Czech Republic government. Capital expenditures related to this construction incurred by PSZT for the nine months ended June 30, 1999 were approximately $20.4 million. An additional $12.6 million is budgeted for this construction for the rest of 1999. For further discussion, refer to Note H - Commitments and Contingencies under the heading "Environmental Matters" in Item 8 of the Company's 1998 Form 10-K. Year 2000 Readiness Disclosure. Numerous media reports have heightened concern that information technology computer systems, software programs and semiconductors may not be capable of recognizing dates after the Year 2000 because such systems use only two digits to refer to a particular year. Such systems may read dates in the Year 2000 and thereafter as if those dates represent the year 1900 or thereafter and, in certain instances, such systems may fail to function properly. State of Readiness. The Company believes that all necessary work has been completed in order to make its internal computer system Year 2000 ready.1 Following the completion of an early-impact analysis study, a formal project manager at the Company was designated to spearhead the Year 2000 remediation effort. The methodology adopted by the Company to address the Year 2000 issue is a combination of methods recommended by respected industry consultants and efforts tailored to meet the Company's specific needs. The Company's Year 2000 plan addresses five primary areas. A. Mainframe Corporate Business Applications Developed and Maintained by the Company: A detailed plan and impact analysis was conducted in 1996-1997 to determine the extent of Year 2000 implications on the Company's mainframe-based computer systems. The remediation and testing in this area have been completed.1 B. Personal Computer Business Applications Software Developed and Supported by the Company: The Company has retained a consulting firm to perform a detailed impact analysis of the personal computer business application systems supported by the Company's Information Services Department. The firm has corrected Year 2000 problems identified by its analysis. Certain applications identified by the consulting firm as potentially problematic have been retired and replaced with Year 2000 compliant applications. The required changes and testing for these applications are complete.1
Item 2. Management's Discussion and Analysis of Financial Condition and --------------------------------------------------------------- Results of Operations (Cont.) ----------------------------- C. Vendor-Supplied Software, Hardware, and Services for Corporate Business Applications Supported by the Company: This category includes all mainframe infrastructure products as well as all PC client / server software and hardware. The Company has sent letters to its vendors asking if their products and services will continue to perform as expected after January 1, 2000. These vendors are responsible for approximately 200 products and services associated with corporate computer applications. The Company has received responses from all vendors which the Company believes supply critical hardware, software, date-sensitive embedded chips and related computer services. The Company has completed testing and implementation of the vendor-supplied Year 2000 compliant products and services.1 D. Vendor-Supplied Products and Services Used on a Corporate Wide Basis: This category includes the critical products and services that are used by multiple departments within the Company including all products containing embedded chips which might be date sensitive. The Company has sent letters to the primary vendors who provide these products and services to the Company, requesting Year 2000 compliance plans. The Company is monitoring their responses and incorporating them into the Company's overall Year 2000 project and contingency plans. The Company has completed testing and implementation of the products and services of these vendors (reference is made to the "Risks" section below).1 E. User-Department Maintained Business Applications: The Company uses certain business software applications that were either built in-house or vendor-supplied and subsequently maintained by individual departments of the Company. The scope of such applications includes, but is not limited to, spreadsheets, databases, vendor provided products and services and embedded process controls. A corporate wide Year 2000 task force is in place and has established a process to identify and resolve Year 2000 problems in this area. This task force meets on a monthly basis to coordinate ongoing activities and report on the project status. Providers of critical products and services have been identified and the Company has sent letters requesting their Year 2000 compliance plans. Responses are being monitored and incorporated into the Year 2000 planning of the various departments. Based on responses received to date along with internal testing, the Company anticipates that all applications and services under this category will be Year 2000 ready.1 Cost. The cost of upgrading both vendor supplied and internally developed systems and services is expensed as incurred and has amounted to approximately $2.1 million in total. Minimal additional expenses related to Year 2000 administration are expected to be incurred.1 Risks. The Company's main concern is to ensure the safe and reliable production and delivery of natural gas and Company-provided services to its customers. Based on the efforts discussed above, the Company expects to be able to operate its own facilities without interruption and continue normal operation in Year 2000 and beyond.1 However, the Company has no control over the systems and services used by third parties with whom it interfaces. While the Company has placed its major third parties on notice that the Company expects their products and services to perform as expected after January 1, 2000, the Company cannot predict with accuracy the actual adverse consequences to the Company that could result if such third parties are not Year 2000 compliant.1 The widespread failure of electric, telecommunication, and
Item 2. Management's Discussion and Analysis of Financial Condition and --------------------------------------------------------------- Results of Operations (Cont.) ----------------------------- upstream gas supply could potentially affect gas service to utility customers, and the Company is pursuing contingency plans to avoid such disruptions. The majority of the devices which control the Company's physical delivery system are not susceptible to Year 2000 problems because they do not contain micro-processors. The Company has conducted an extensive review of its existing micro-processors (embedded technology) and has replaced non-Year 2000 compliant hardware. Distribution Corporation is subject to regulatory review by both the PSC and the PaPUC. Both of these regulatory bodies have issued orders concerning the Year 2000 issue, and both have established dates in 1999 by which jurisdictional utilities must have taken the necessary steps to ensure that its critical systems are Year 2000 ready. In the event Distribution Corporation fails to meet the requirements of those orders, it may be subject to the imposition of fines or formal enforcement actions by the regulatory bodies. Contingency Planning. The Company formed its Corporate Year 2000 task force in mid-1997. The primary function of this group is to: (1) raise awareness of the Year 2000 issue within the Company, (2) facilitate identification and remediation of Year 2000 potential problems within the Company, and (3) facilitate and develop corporate contingency plans. The group is comprised of middle to senior level managers and Company executives. The Company has developed Year 2000 strategic contingency plans which have been prioritized in relation to the overall corporation in the order of human safety, reliability/delivery of Company services and administrative services. The Company will be adding the operational specifics between now and mid-September. The pertinent portions of these plans have been filed with the New York State Public Service Commission whose review is ongoing. The Company is currently working with other utilities in its service areas and regional Emergency Management Services to establish communication channels and procedures in the low probability event of a serious Year 2000 disruption. The Company has existing disaster/contingency plans to deal with operational gas supply or delivery problems, loss of the corporate data center, and loss of the corporate customer telephone centers. These plans are being reviewed to address failures resulting from Year 2000 problems created or occurring outside of the Company (i.e. loss of electricity, telephone service, etc.). The Company expects to have its Year 2000 contingency plans completed by mid- September 1999.1 The Company has selected this date as opposed to one in early 1999 so that the contingency plans are current and operational and that the Company will be able to use them immediately, if required.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 without limitation those which are designated with a "1",
Item 2. Management's Discussion and Analysis of Financial Condition and --------------------------------------------------------------- Results of Operations (Cont.) ----------------------------- are forward-looking statements and accordingly involve risks and uncertainties which could cause actual results or outcomes to differ materially from those expressed in the forward-looking statements. The forward-looking statements contained herein are based on various assumptions, many of which are based, in turn, upon further assumptions. The Company's expectations, beliefs and projections are expressed in good faith and are believed by the Company to have a reasonable basis, including, without limitation, management's examination of historical operating trends, data contained in the Company's records and other data available from third parties, but there can be no assurance that management's expectations, beliefs or projections will result or be achieved or accomplished. In addition to other factors and matters discussed elsewhere herein, the following are important factors that, in the view of the Company, could cause actual results to differ materially from those discussed in the forward-looking statements: 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 instruments 13. Regarding foreign operations - changes in foreign trade and monetary policies, laws and regulations related to foreign operations, political and governmental changes, inflation and exchange rates, taxes and operating conditions
Item 2. Management's Discussion and Analysis of Financial Condition and --------------------------------------------------------------- Results of Operations (Cont.) ----------------------------- 14. Significant changes in tax rates or policies or in rates of inflation or interest 15. Significant changes in the Company's relationship with its employees and the potential adverse effects if labor disputes or grievances were to occur 16. Changes in accounting principles and/or the application of such principles to the Company 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 ---------------------------------------------------------- Refer to the "Market Rate Sensitive Instruments" section in Item 2 - Management's Discussion and Analysis of Financial Condition and Results of Operations. Part II. Other Information - --------------------------- Item 2. Changes in Securities --------------------- On April 1, 1999, 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, 1999, 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 ----------------- The Company's By-Laws were amended by the Board on June 17, 1999. The amended By-Laws are included in this Form 10-Q as Exhibit 3(ii). Specifically, the By-Laws were amended at Article I ("Meetings of Stockholders") to insert new Sections 7 and 8. These amendments relate to both those matters which may properly come before meetings of stockholders and the conduct of such meetings. Among other things, as permitted by SEC Rule 14a-4(c) [17 CFR Section 240.14a-4(c)] the amendments incorporated into the By-Laws an "advance notice provision" describing when a stockholder's notice of business or nominations to be considered at a meeting of stockholders will be considered timely. Under most circumstances, this provision requires that a stockholder provide such a notice at least 110 days prior to the anniversary of the date on which the Company mailed its proxy materials for the prior year's annual meeting of stockholders. For example, since the Company mailed its proxy materials for the February 1999 annual meeting on December 31, 1998, a stockholder's notice of business or nominations for the February 2000 annual meeting will be due on September 13, 1999.
Item 5. Other Information (Cont.) ------------------------- This requirement is separate and apart from the requirements of SEC Rule 14 a-8 (17 CFR Section 240.14 a-8)that a stockholder must meet in order to have a stockholder proposal included in the Company's proxy statement and form of proxy. Item 6. Exhibits and Reports on Form 8-K -------------------------------- (a) Exhibits Exhibit Number Description of Exhibit ------ ---------------------- (3)(ii) By-Laws, as amended on June 17, 1999 (10) Material Contracts 10.1 Form of Employment Continuation and Noncompetition Agreement, dated as of December 11, 1998, with Philip C. Ackerman, Walter E. DeForest, Joseph P. Pawlowski, Dennis J. Seeley, David F. Smith and Gerald T. Wehrlin. 10.2 Form of Employment Continuation and Noncompetition Agreement, dated as of December 11, 1998, with Bruce H. Hale and Richard Hare. 10.3 Form of Employment Continuation and Noncompetition Agreement, dated as of December 11, 1998, with James A. Beck. (12) Statements regarding Computation of Ratios: Ratio of Earnings to Fixed Charges for the Twelve Months Ended June 30, 1999 and the Years Ended September 30, 1994 through 1998. (27) Financial Data Schedules 27.1 Financial Data Schedule for the Nine Months Ended June 30, 1999. 27.2 Amended 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, 1999 and 1998. (b) Reports on Form 8-K None
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 13, 1999 ---------------
EXHIBIT INDEX (Form 10Q) Exhibit 3(ii) By-Laws, as amended on June 17, 1999. Exhibit 10.1 Form of Employment Continuation and Noncompetition Agreement, dated as of December 11, 1998, with Philip C. Ackerman, Walter E. DeForest, Joseph P. Pawlowski, Dennis J. Seeley David F. Smith and Gerald T. Wehrlin. Exhibit 10.2 Form of Employment Continuation and Noncompetition Agreement, dated as of December 11, 1998, with Bruce H. Hale and Richard Hare. Exhibit 10.3 Form of Employment Continuation and Noncompetition Agreement, dated as of December 11, 1998, with James A. Beck. Exhibit 12 Statements regarding Computation of Ratios: Ratio of Earnings to Fixed Charges for the Twelve Months Ended June 30, 1999 and the Years Ended September 30, 1994 through 1998. Exhibit 27.1 Financial Data Schedule for the Nine Months Ended June 30, 1999. Exhibit 27.2 Amended 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, 1999 and 1998.