United States Securities and Exchange CommissionWashington, D.C. 20549
Form 10-Q[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 2006
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from ___ to ____
Commission File Number 1-3880
National Fuel Gas Company(Exact name of registrant as specified in its charter)
(Address of principal executive offices)
(716) 857-7000(Registrant's telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months and (2) has been subject to such filing requirements for the past 90 days. YES X NO
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one): Large Accelerated Filer X Accelerated Filer Non-Accelerated Filer
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). YES NO X
Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date:
Common stock, $1 par value, outstanding at April 30, 2006: 83,976,340 shares.
1
GLOSSARY OF TERMSFrequently used abbreviations or acronyms:National Fuel Gas CompaniesCompany The Registrant, the Registrant and its subsidiaries or the Registrant's subsidiaries as appropriate in the context of the disclosure Data-Track Data-Track Account Services, Inc. Distribution Corporation National Fuel Gas Distribution Corporation Empire Empire State Pipeline ESNE Energy Systems North East, LLC Highland Highland Forest Resources, Inc. Horizon Horizon Energy Development, Inc. Horizon LFG Horizon LFG, Inc. Horizon Power Horizon Power, Inc. Leidy Hub Leidy Hub, Inc. Model City Model City Energy, LLC National Fuel National Fuel Gas Company NFR National Fuel Resources, Inc. Registrant National Fuel Gas Company SECI Seneca Energy Canada Inc. Seneca Seneca Resources Corporation Seneca Energy Seneca Energy II, LLC Supply Corporation National Fuel Gas Supply Corporation U.E. United Energy, a.s.Regulatory AgenciesFASB Financial Accounting Standards Board FERC Federal Energy Regulatory Commission NYPSC State of New York Public Service Commission PaPUC Pennsylvania Public Utility Commission SEC Securities and Exchange CommissionOther2005 Form 10-K The Company's Annual Report on Form 10-K for the year ended September 30, 2005 APB 20 Accounting Principles Board Opinion No. 20, Accounting Changes APB 25 Accounting Principles Board Opinion No. 25, Accounting for Stock Issued to Employees Bbl Barrel (of oil) Bcf Billion cubic feet (of natural gas) Board foot A measure of lumber and/or timber equal to 12 inches in length by 12 inches in width by one inch in thickness. Btu British thermal unit; the amount of heat needed to raise the temperature of one pound of water one degree Fahrenheit. Capital expenditure Represents additions to property, plant, and equipment, or the amount of money a company spends to buy capital assets or upgrade its existing capital assets. Cashout revenues A cash resolution of a gas imbalance whereby a customer pays Supply Corporation for gas the customer receives in excess of amounts delivered into Supply Corporation's system by the customer's shipper. Degree day A measure of the coldness of the weather experienced, based on the extent to which the daily average temperature falls below a reference temperature, usually 65 degrees Fahrenheit. Derivative A financial instrument or other contract, the terms of which include an underlying variable (a price, interest rate, index rate, exchange rate, or other variable) and a notional amount (number of units, barrels, cubic feet, etc.). The terms also permit for the instrument or contract to be settled net, and no initial net investment is required to enter into the financial instrument or contract. Examples include futures contracts, options, no cost collars and swaps.
2
GLOSSARY OF TERMS (Cont.)Dth Dekatherm; one Dth of natural gas has a heating value of 1,000,000 British thermal units, approximately equal to the heating value of 1 Mcf of natural gas. Energy Policy Act Energy Policy Act of 2005 Exchange Act Securities Exchange Act of 1934 Expenditures for long-lived assets Includes capital expenditures, stock acquisitions and/or investments in partnerships. FIN 47 FASB Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations - an interpretation of SFAS 143 Firm transportation and/or storage The transportation and/or storage service that a supplier of such service is obligated by contract to provide and for which the customer is obligated to pay whether or not the service is utilized. GAAP Accounting principles generally accepted in the United States of America Goodwill An intangible asset representing the difference between the fair value of a company and the price at which a company is purchased. Hedging A method of minimizing the impact of price, interest rate, and/or foreign currency exchange rate changes, often times through the use of derivative financial instruments. Hub Location where pipelines intersect enabling the trading, transportation, storage, exchange, lending and borrowing of natural gas. Interruptible transportation and/or storage The transportation and/or storage service that, in accordance with contractual arrangements, can be interrupted by the supplier of such service, and for which the customer does not pay unless utilized. LIFO Last-in, first-out Mbbl Thousand barrels (of oil) Mcf Thousand cubic feet (of natural gas) MD&A Management's Discussion and Analysis of Financial Condition and Results of Operations MDth Thousand dekatherms (of natural gas) MMcf Million cubic feet (of natural gas) Order 667-A An order issued by FERC to clarify Order 667 entitled "Repeal of the Public Utility Holding Company Act of 1935 and Enactment of the Public Utility Holding Company Act of 2005" Order 2004 An order issued by FERC entitled "Standards of Conduct for Transmission Providers" Precedent Agreement An agreement between a pipeline company and a potential customer to sign a service agreement after specified events (called "conditions precedent") happen, usually within a specified time. Proved developed reserves Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves Reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required to make these reserves productive. PUHCA 1935 Public Utility Holding Company Act of 1935 PUHCA 2005 Public Utility Holding Company Act of 2005 Reserves The unproduced but recoverable oil and/or gas in place in a formation which has been proven by production. Restructuring Generally referring to partial "deregulation" of the utility industry by statutory or regulatory process. Restructuring of federally regulated natural gas pipelines resulted in the separation (or "unbundling") of gas commodity service from transportation service for wholesale and large-volume retail markets. State restructuring programs attempt to extend the same process to retail mass markets. SFAS Statement of Financial Accounting Standards
3
GLOSSARY OF TERMS (Concl.)SFAS 3 Statement of Financial Accounting Standards No. 3, Reporting Accounting Changes in Interim Financial Statements SFAS 123 Statement of Financial Accounting Standards No. 123, Accounting for Stock-Based Compensation SFAS 123R Statement of Financial Accounting Standards No. 123R, Share-Based Payment SFAS 143 Statement of Financial Accounting Standards No. 143, Accounting for Asset Retirement Obligations SFAS 154 Statement of Financial Accounting Standards No. 154, Accounting Changes and Error Corrections Stock acquisitions Investments in corporations. Unbundled service A service that has been separated from other services, with rates charged that reflect only the cost of the separated service. WNC Weather normalization clause; a clause in utility rates which adjusts customer rates to allow a utility to recover its normal operating costs calculated at normal temperatures. If temperatures during the measured period are warmer than normal, customers are assessed a surcharge. If temperatures during the measured period are colder than normal, customers receive a credit.
4
INDEX
• The Company has nothing to report under this item.
Reference to “the Company” in this report means the Registrant or the Registrant and its subsidiaries collectively, as appropriate in the context of the disclosure. All references to a certain year in this report are to the Company’s fiscal year ended September 30 of that year, unless otherwise noted.
This Form 10-Q contains “forward-looking statements” within the meaning of Section 21E of the Securities Exchange Act of 1934. Forward-looking statements should be read with the cautionary statements and important factors included in this Form 10-Q at Item 2 — MD&A, under the heading “Safe Harbor for Forward-Looking Statements.” Forward-looking statements are all statements other than statements of historical fact, including, without limitation, those statements that are designated with an asterisk (“*”) following the statement, as well as those statements that are identified by the use of the words “anticipates,” “estimates,” “expects,” “intends,” “plans,” “predicts,” “projects,” and similar expressions.
5
National Fuel Gas CompanyConsolidated Statements of Income and EarningsReinvested in the Business(Unaudited)Three Months Ended March 31, (Thousands of Dollars, Except Per Common Share Amounts) 2006 2005 ----------------- ----------------- INCOMEOperating Revenues $890,981 $735,842 - -------------------------------------------------------------------------------- ----------------- -----------------Operating ExpensesPurchased Gas 566,540 440,254 Operation and Maintenance 121,076 110,392 Property, Franchise and Other Taxes 20,120 19,897 Depreciation, Depletion and Amortization 44,278 44,632 - -------------------------------------------------------------------------------- ----------------- ----------------- 752,014 615,175 - -------------------------------------------------------------------------------- ----------------- -----------------Operating Income 138,967 120,667Other Income (Expense):Income from Unconsolidated Subsidiaries 720 455 Interest Income 965 1,018 Other Income 248 4,827 Interest Expense on Long-Term Debt (18,149) (18,319) Other Interest Expense (1,465) (1,936) - -------------------------------------------------------------------------------- ----------------- -----------------Income from Continuing Operations Before Income Taxes 121,286 106,712 Income Tax Expense 42,692 42,731 - -------------------------------------------------------------------------------- ----------------- -----------------Income from Continuing Operations 78,594 63,981 - -------------------------------------------------------------------------------- ----------------- -----------------Income from Discontinued Operations, Net of Tax - 6,702 - -------------------------------------------------------------------------------- ----------------- -----------------Net Income Available for Common Stock 78,594 70,683 - -------------------------------------------------------------------------------- ----------------- ----------------- EARNINGS REINVESTED IN THE BUSINESS Balance at December 31 845,951 746,090 - -------------------------------------------------------------------------------- ----------------- ----------------- 924,545 816,773 Share Repurchases 22,619 - Dividends on Common Stock (2006 - $0.29; 2005 - $0.28) 24,327 23,364 - -------------------------------------------------------------------------------- ----------------- -----------------Balance at March 31 $877,599 $793,409 ================================================================================ ================= =================Earnings Per Common Share:Basic: Income from Continuing Operations $0.93 $0.77 Income from Discontinued Operations - 0.08 - -------------------------------------------------------------------------------- ----------------- -----------------Net Income Available for Common Stock $0.93 $0.85 ================================================================================ ================= ================= Diluted: Income from Continuing Operations $0.91 $0.75 Income from Discontinued Operations - 0.08 - -------------------------------------------------------------------------------- ----------------- -----------------Net Income Available for Common Stock $0.91 $0.83 ================================================================================ ================= =================Weighted Average Common Shares Outstanding:Used in Basic Calculation 84,346,733 83,313,191 ================================================================================ ================= ================= Used in Diluted Calculation 86,253,597 84,770,068 ================================================================================ ================= =================
See Notes to Condensed Consolidated Financial Statements
6
National Fuel Gas CompanyConsolidated Statements of Income and EarningsReinvested in the Business(Unaudited)Six Months Ended March 31, (Thousands of Dollars, Except Per Common Share Amounts) 2006 2005 ----------------- ----------------- INCOMEOperating Revenues $1,601,737 $1,236,126 - -------------------------------------------------------------------------------- ----------------- -----------------Operating ExpensesPurchased Gas 1,003,317 696,410 Operation and Maintenance 224,704 203,015 Property, Franchise and Other Taxes 37,302 36,953 Depreciation, Depletion and Amortization 87,324 87,340 - -------------------------------------------------------------------------------- ----------------- ----------------- 1,352,647 1,023,718 - -------------------------------------------------------------------------------- ----------------- -----------------Operating Income 249,090 212,408Other Income (Expense):Income from Unconsolidated Subsidiaries 1,985 1,239 Interest Income 2,098 1,290 Other Income 989 5,378 Interest Expense on Long-Term Debt (36,367) (36,694) Other Interest Expense (3,240) (4,354) - -------------------------------------------------------------------------------- ----------------- -----------------Income from Continuing Operations Before Income Taxes 214,555 179,267 Income Tax Expense 78,542 70,457 - -------------------------------------------------------------------------------- ----------------- -----------------Income from Continuing Operations 136,013 108,810 - -------------------------------------------------------------------------------- ----------------- -----------------Income from Discontinued Operations, Net of Tax - 12,310 - -------------------------------------------------------------------------------- ----------------- -----------------Net Income Available for Common Stock 136,013 121,120 - -------------------------------------------------------------------------------- ----------------- ----------------- EARNINGS REINVESTED IN THE BUSINESS Balance at October 1 813,020 718,926 - -------------------------------------------------------------------------------- ----------------- ----------------- 949,033 840,046 Share Repurchases 22,619 - Dividends on Common Stock (2006 - $0.58; 2005 - $0.56) 48,815 46,637 - -------------------------------------------------------------------------------- ----------------- -----------------Balance at March 31 $877,599 $793,409 ================================================================================ ================= =================Earnings Per Common Share:Basic: Income from Continuing Operations $1.61 $1.31 Income from Discontinued Operations - 0.15 - -------------------------------------------------------------------------------- ----------------- -----------------Net Income Available for Common Stock $1.61 $1.46 ================================================================================ ================= ================= Diluted: Income from Continuing Operations $1.58 $1.28 Income from Discontinued Operations - 0.15 - -------------------------------------------------------------------------------- ----------------- -----------------Net Income Available for Common Stock $1.58 $1.43 ================================================================================ ================= =================Weighted Average Common Shares Outstanding:Used in Basic Calculation 84,385,140 83,231,435 ================================================================================ ================= ================= Used in Diluted Calculation 86,256,515 84,711,134 ================================================================================ ================= =================
7
National Fuel Gas CompanyConsolidated Balance Sheets(Unaudited)March 31, September 30, 2006 2005 -------------------- ------------------- (Thousands of Dollars) ASSETSProperty, Plant and Equipment $4,535,882 $4,423,255 Less - Accumulated Depreciation, Depletion and Amortization 1,639,493 1,583,955 - ---------------------------------------------------------------------------- -------------------- ------------------- 2,896,389 2,839,300 - ---------------------------------------------------------------------------- -------------------- -------------------Current AssetsCash and Temporary Cash Investments 98,099 57,607 Hedging Collateral Deposits 16,890 77,784 Receivables - Net of Allowance for Uncollectible Accounts of $43,409 and $26,940, Respectively 358,026 155,064 Unbilled Utility Revenue 67,074 20,465 Gas Stored Underground 31,883 64,529 Materials and Supplies - at average cost 32,425 33,267 Unrecovered Purchased Gas Costs - 14,817 Prepayments and Other Current Assets 41,096 65,469 Deferred Income Taxes 49,546 83,774 Fair Value of Derivative Financial Instruments 5,895 - - ---------------------------------------------------------------------------- -------------------- ------------------- 700,934 572,776 - ---------------------------------------------------------------------------- -------------------- -------------------Other AssetsRecoverable Future Taxes 84,834 85,000 Unamortized Debt Expense 16,516 17,567 Other Regulatory Assets 56,713 47,028 Deferred Charges 8,086 4,474 Other Investments 85,349 80,394 Investments in Unconsolidated Subsidiaries 11,491 12,658 Goodwill 5,476 5,476 Intangible Assets 40,971 42,302 Other 6,808 15,677 - ---------------------------------------------------------------------------- -------------------- ------------------- 316,244 310,576 - ---------------------------------------------------------------------------- -------------------- -------------------Total Assets $3,913,567 $3,722,652 ============================================================================ ==================== ===================
8
National Fuel Gas CompanyConsolidated Balance Sheets(Unaudited)March 31, September 30, 2006 2005 -------------------- ------------------- (Thousands of Dollars) CAPITALIZATION AND LIABILITIESCapitalization:Comprehensive Shareholders' EquityCommon Stock, $1 Par Value Authorized - 200,000,000 Shares; Issued And Outstanding - 83,919,742 Shares and 84,356,748 Shares, Respectively $83,920 $ 84,357 Paid in Capital 540,388 529,834 Earnings Reinvested in the Business 877,599 813,020 - ---------------------------------------------------------------------------- -------------------- -------------------Total Common Shareholder Equity BeforeItems of Other Comprehensive Loss 1,501,907 1,427,211Accumulated Other Comprehensive Loss (119,248) (197,628) - ---------------------------------------------------------------------------- -------------------- ------------------- Total Comprehensive Shareholders' Equity 1,382,659 1,229,583 Long-Term Debt, Net of Current Portion 1,114,371 1,119,012 - ---------------------------------------------------------------------------- -------------------- ------------------- Total Capitalization 2,497,030 2,348,595 - ---------------------------------------------------------------------------- -------------------- -------------------Current and Accrued LiabilitiesNotes Payable to Banks and Commercial Paper - - Current Portion of Long-Term Debt 9,505 9,393 Accounts Payable 145,438 155,485 Amounts Payable to Customers 12,650 1,158 Dividends Payable 24,327 24,445 Other Accruals and Current Liabilities 193,249 60,404 Fair Value of Derivative Financial Instruments 87,962 209,072 - ---------------------------------------------------------------------------- -------------------- ------------------- 473,131 459,957 - ---------------------------------------------------------------------------- -------------------- -------------------Deferred CreditsDeferred Income Taxes 503,147 489,720 Taxes Refundable to Customers 11,070 11,009 Unamortized Investment Tax Credit 6,445 6,796 Cost of Removal Regulatory Liability 93,092 90,396 Other Regulatory Liabilities 58,886 66,339 Pension and Other Post-Retirement Benefit Liabilities 155,582 143,687 Asset Retirement Obligation 42,216 41,411 Other Deferred Credits 72,968 64,742 - ---------------------------------------------------------------------------- -------------------- ------------------- 943,406 914,100 - ---------------------------------------------------------------------------- -------------------- -------------------Commitments and Contingencies - - - ---------------------------------------------------------------------------- -------------------- -------------------Total Capitalization and Liabilities $3,913,567 $3,722,652 ============================================================================ ==================== ===================
9
National Fuel Gas CompanyConsolidated Statements of Cash FlowsUnaudited)Six Months Ended March 31, (Thousands of Dollars) 2006 2005 ------------------- ---------------------OPERATING ACTIVITIESNet Income Available for Common Stock $136,013 $121,120 Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities: Depreciation, Depletion and Amortization 87,324 96,285 Deferred Income Taxes (1,435) (3,982) Income from Unconsolidated Subsidiaries, Net of Cash Distributions 1,166 282 Minority Interest in Foreign Subsidiaries - 3,342 Excess Tax Benefits Associated with Stock-Based Compensation Awards (6,515) - Other (5,297) (7,124) Change in: Hedging Collateral Deposits 60,894 (10,962) Receivables and Unbilled Utility Revenue (249,466) (228,969) Gas Stored Underground and Materials and Supplies 33,486 43,628 Unrecovered Purchased Gas Costs 14,817 7,532 Prepayments and Other Current Assets 24,372 (745) Accounts Payable (9,951) 47,541 Amounts Payable to Customers 11,492 25,342 Other Accruals and Current Liabilities 139,020 153,928 Other Assets (11,837) (13,191) Other Liabilities 19,107 11,989 - ---------------------------------------------------------------------------- ------------------- ---------------------Net Cash Provided by Operating Activities 243,190 246,016 - ---------------------------------------------------------------------------- ------------------- ---------------------INVESTING ACTIVITIESCapital Expenditures (134,961) (114,624) Net Proceeds from Sale of Oil and Gas Producing Properties 4 85 Other (1,396) 2,450 - ---------------------------------------------------------------------------- ------------------- ---------------------Net Cash Used in Investing Activities (136,353) (112,089) - ---------------------------------------------------------------------------- ------------------- ---------------------FINANCING ACTIVITIESChange in Notes Payable to Banks and Commercial Paper - (43,600) Excess Tax Benefits Associated with Stock-Based Compensation Awards 6,515 - Shares Repurchased under Repurchase Plan (26,577) - Reduction of Long-Term Debt (4,529) (7,314) Dividends Paid on Common Stock (48,933) (46,483) Net Proceeds from Issuance of Common Stock 7,164 6,301 - ---------------------------------------------------------------------------- ------------------- ---------------------Net Cash Used in Financing Activities (66,360) (91,096) - ---------------------------------------------------------------------------- ------------------- ---------------------Effect of Exchange Rates on Cash 15 3,135 - ---------------------------------------------------------------------------- ------------------- ---------------------Net Increase in Cash and Temporary Cash Investments 40,492 45,966Cash and Temporary Cash Investments at October 1 57,607 57,541 - ---------------------------------------------------------------------------- ------------------- ---------------------Cash and Temporary Cash Investments at March 31 $98,099 $103,507 ============================================================================ =================== =====================
10
National Fuel Gas CompanyConsolidated Statements of Comprehensive Income(Unaudited)Three Months Ended March 31, (Thousands of Dollars) 2006 2005 ------------------- --------------------- Net Income Available for Common Stock $78,594 $70,683 - ---------------------------------------------------------------------------- ------------------- --------------------- Other Comprehensive Income (Loss), Before Tax: Foreign Currency Translation Adjustment (991) (8,084) Unrealized Gain on Securities Available for Sale Arising During the Period 1,121 222 Unrealized Gain (Loss) on Derivative Financial Instruments Arising During the Period 21,618 (100,334) Reclassification Adjustment for Realized Gains on Securities Available for Sale in Net Income - (652) Reclassification Adjustment for Realized Losses on Derivative Financial Instruments in Net Income 25,794 17,645 - ---------------------------------------------------------------------------- ------------------- --------------------- Other Comprehensive Income (Loss), Before Tax 47,542 (91,203) - ---------------------------------------------------------------------------- ------------------- --------------------- Income Tax Expense Related to Cumulative Translation Adjustment - 363 Income Tax Expense Related to Unrealized Gain on Securities Available for Sale Arising During the Period 392 159 Income Tax Benefit Related to Unrealized Gain (Loss) on Derivative Financial Instruments Arising During the Period 8,334 (38,380) Reclassification Adjustment for Income Tax Expense on Realized Gains from Securities Available for Sale in Net Income - (228) Reclassification Adjustment for Income Tax Benefit on Realized Losses from Derivative Financial Instruments In Net Income 10,000 6,671 - ---------------------------------------------------------------------------- ------------------- --------------------- Income Taxes - Net 18,726 (31,415) - ---------------------------------------------------------------------------- ------------------- --------------------- Other Comprehensive Income (Loss) 28,816 (59,788) - ---------------------------------------------------------------------------- ------------------- --------------------- Comprehensive Income $107,410 $10,895 ============================================================================ =================== =====================
11
National Fuel Gas CompanyConsolidated Statements of Comprehensive Income(Unaudited)Six Months Ended March 31, (Thousands of Dollars) 2006 2005 ------------------- --------------------- Net Income Available for Common Stock $136,013 $121,120 - ---------------------------------------------------------------------------- ------------------- --------------------- Other Comprehensive Income (Loss), Before Tax: Foreign Currency Translation Adjustment (736) 22,900 Unrealized Gain on Securities Available for Sale Arising During the Period 2,263 1,351 Unrealized Gain (Loss) on Derivative Financial Instruments Arising During the Period 62,615 (80,232) Reclassification Adjustment for Realized Gains on Securities Available for Sale in Net Income - (652) Reclassification Adjustment for Realized Losses on Derivative Financial Instruments in Net Income 63,725 35,841 - ---------------------------------------------------------------------------- ------------------- --------------------- Other Comprehensive Income (Loss), Before Tax 127,867 (20,792) - ---------------------------------------------------------------------------- ------------------- --------------------- Income Tax Expense Related to Cumulative Translation Adjustment - 363 Income Tax Expense Related to Unrealized Gain on Securities Available for Sale Arising During the Period 791 554 Income Tax Benefit Related to Unrealized Gain (Loss) on Derivative Financial Instruments Arising During the Period 24,110 (30,653) Reclassification Adjustment for Income Tax Expense on Realized Gains from Securities Available for Sale in Net Income - (228) Reclassification Adjustment for Income Tax Benefit on Realized Losses from Derivative Financial Instruments In Net Income 24,586 13,582 - ---------------------------------------------------------------------------- ------------------- --------------------- Income Taxes - Net 49,487 (16,382) - ---------------------------------------------------------------------------- ------------------- --------------------- Other Comprehensive Income (Loss) 78,380 (4,410) - ---------------------------------------------------------------------------- ------------------- --------------------- Comprehensive Income $214,393 $116,710 ============================================================================ =================== =====================
12
National Fuel Gas Company
Notes to Consolidated Financial Statements
(Unaudited)
The preparation of the consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Earnings for Interim Periods.The Company, in its opinion, has included all adjustments that are necessary for a fair statement of the results of operations for the reported periods. The consolidated financial statements and notes thereto, included herein, should be read in conjunction with the financial statements and notes for the years ended September 30, 2005, 2004 and 2003 that are included in the Company’s 2005 Form 10-K. The consolidated financial statements for the year ended September 30, 2006 will be audited by the Company’s independent registered public accounting firm after the end of the fiscal year.
The earnings for the six months ended March 31, 2006 should not be taken as a prediction of earnings for the entire fiscal year ending September 30, 2006. Most of the business of the Utility and Energy Marketing segments is seasonal in nature and is influenced by weather conditions. Due to the seasonal nature of the heating business in the Utility and Energy Marketing segments, earnings during the winter months normally represent a substantial part of the earnings that those segments are expected to achieve for the entire fiscal year.
Consolidated Statement of Cash Flows. For purposes of the Consolidated Statement of Cash Flows, the Company considers all highly liquid debt instruments purchased with a maturity of generally three months or less to be cash equivalents.
Hedging Collateral Deposits.Cash held in margin accounts serve as collateral for open positions on exchange-traded futures contracts, exchange-traded options and over-the-counter swaps and collars.
Gas Stored Underground — Current. In the Utility segment, gas stored underground – current is carried at lower of cost or market, on a LIFO method. Gas stored underground – current normally declines during the first and second quarters of the year and is replenished during the third and fourth quarters. In the Utility segment, the current cost of replacing gas withdrawn from storage is recorded in the Consolidated Statements of Income and a reserve for gas replacement is recorded in the Consolidated Balance Sheets under the caption “Other Accruals and Current Liabilities.” Such reserve, which amounted to $121.8 million at March 31, 2006, is reduced to zero by September 30 as the inventory is replenished.
Accumulated Other Comprehensive Income (Loss). The components of Accumulated Other Comprehensive Income (Loss), net of related tax effect, are as follows (in thousands):
13
At March 31, 2006 At September 30, 2005 ----------------- --------------------- Minimum Pension Liability Adjustment $(107,844) $(107,844) Cumulative Foreign Currency Translation Adjustment 27,273 28,009 Net Unrealized Loss on Derivative Financial Instruments (45,695) (123,339) Net Unrealized Gain on Securities Available for Sale 7,018 5,546 ---------- ---------- Accumulated Other Comprehensive Loss $(119,248) $(197,628) ========== ===========
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. For purposes of determining 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 Statements of Income reflects the potential dilution as a result of these stock options as determined using the Treasury Stock Method. Stock options that are antidilutive are excluded from the calculation of diluted earnings per common share. For the quarter and six months ended March 31, 2006, there were no stock options excluded as being antidilutive. For the quarter and six months ended March 31, 2005, 21,434 and 10,599 stock options, respectively, were excluded as being antidilutive.
Share Repurchases.The Company considers all shares repurchased as cancelled shares restored to the status of authorized but unissued shares, in accordance with New Jersey law. The repurchases are accounted for on the date the share repurchase is settled as an adjustment to common stock (at par value) with the excess repurchase price allocated between paid in capital and retained earnings. Refer to Note 3 - Capitalization for further discussion of the share repurchase program.
Stock-Based Compensation.The Company has various stock option and stock award plans which provide or provided for the issuance of one or more of the following to key employees: incentive stock options, nonqualified stock options, restricted stock, performance units or performance shares. Stock options under all plans have exercise prices equal to the average market price of Company common stock on the date of grant, and generally no option is exercisable less than one year or more than ten years after the date of each grant. Restricted stock is subject to restrictions on vesting and transferability. Restricted stock awards entitle the participants to full dividend and voting rights. Certificates for shares of restricted stock awarded under the Company's stock option and stock award plans are held by the Company during the periods in which the restrictions on vesting are effective. Restrictions on restricted stock awards generally lapse ratably over a period of not more than ten years after the date of each grant.
Prior to October 1, 2005, the Company accounted for its stock-based compensation under the recognition and measurement principles of APB 25 and related interpretations. Under that method, no compensation expense was recognized for options granted under the Company's stock option and stock award plans. The Company did record, in accordance with APB 25, compensation expense for the market value of restricted stock on the date of the award over the periods during which the vesting restrictions existed.
Effective October 1, 2005, the Company adopted SFAS 123R, which requires the measurement and recognition of compensation cost at fair value for all share-based payments, including stock options. The Company has chosen to use the modified version of prospective application, as allowed by SFAS 123R. Using the modified prospective application, the Company is recording compensation cost for the portion of awards granted prior to October 1, 2005 for which the requisite service had not been rendered and is recognizing such compensation cost as the requisite service is rendered on or after October 1, 2005. Such compensation expense is based on the grant-date fair value of the awards as calculated for
14
the Company's disclosure using a Binomial option-pricing model under SFAS 123. Any new awards, modifications to awards, repurchases of awards, or cancellations of awards subsequent to September 30, 2005 will follow the provisions of SFAS 123R, with compensation expense being calculated using the Black-Scholes-Merton closed form model. The Company has chosen the Black-Scholes-Merton closed form model since it is easier to administer than the Binomial option-pricing model. Furthermore, since the Company does not have complex stock-based compensation awards, it does not believe that compensation expense would be materially different under either model. There were no stock-based compensation awards granted during the quarter or six months ended March 31, 2006. There were 643,000 stock options granted during the quarter ended March 31, 2005. Stock-based compensation expense for the quarters ended March 31, 2006 and March 31, 2005 totaled approximately $134,000 and $152,000, respectively. Stock-based compensation expense for the six months ended March 31, 2006 and March 31, 2005 was approximately $283,000 and $315,000, respectively. Stock-based compensation expense is included in operation and maintenance expenses in the consolidated statement of income. The total income tax benefit related to stock-based compensation expense during the quarters ended March 31, 2006 and March 31, 2005 was approximately $53,000 and $60,000, respectively. The total income tax benefit related to stock-based compensation expense during the six months ended March 31, 2006 and March 31, 2005 was approximately $112,000 and $125,000, respectively. There were no capitalized stock-based compensation costs during the quarters ended March 31, 2006 and March 31, 2005.
The following table illustrates the effect on net income and earnings per share of the Company had the Company applied the fair value recognition provisions of SFAS 123 relating to stock-based employee compensation for the three and six months ended March 31, 2005:
Three Months Ended Six Months Ended (Thousands of Dollars, Except Per March 31, March 31, Common Share Amounts) 2005 2005 ------------------ --------------- Net Income, Available for Common Stock, as Reported $70,683 $121,120 Add: Stock-Based Employee Compensation Expense Included in Reported Net Income, Net of Tax (1) 98 205 Deduct: Total Stock-Based Employee Compensation Expense Determined Under Fair Value Based Method for all Awards, Net of Related Tax Effects (317) (680) ------- --------- Pro Forma Net Income Available For Common Stock $70,464 $120,645 ======= ========= Earnings Per Common Share: Basic - As Reported $0.85 $1.46 Basic - Pro Forma $0.85 $1.45 Diluted - As Reported $0.83 $1.43 Diluted - Pro Forma $0.83 $1.42
15
Transactions during the quarter ended March 31, 2006 were as follows (in thousands, except option prices and years):
Weighted Weighted Average Average Remaining Aggregate Number Exercise Contractual Intrinsic of Options Price Life (Years) Value ---------- -------- ------------ --------- Options Outstanding at September 30, 2005 10,997 $ 23.78 Granted - - Exercised (178) 21.24 Forfeited - - ------- ------ Options Outstanding at December 31, 2005 10,819 23.82 Granted - - Exercised (330) 22.34 Forfeited (3) 25.89 -------- ------- Options Outstanding at March 31, 2006 10,486 $ 23.87 4.19 $ 92,807 ========= ======= ========= ======== Options Exercisable at March 31, 2006 10,339 $ 23.87 4.15 $ 91,494 ========= ======== ========= ========
The total intrinsic value of stock options exercised during the quarters ended March 31, 2006 and March 31, 2005 totaled approximately $3.3 million and $5.6 million, respectively. The amount of cash received by the Company from the exercise of such stock options was approximately $5.4 million during the quarter ended March 31, 2006 and approximately $4.5 million during the quarter ended March 31, 2005. The total intrinsic value of stock options exercised during the six months ended March 31, 2006 and March 31, 2005 totaled approximately $5.2 million and $8.5 million, respectively. For the six months ended March 31, 2006 and March 31, 2005, the amount of cash received by the Company from the exercise of stock options was approximately $8.1 million and $8.2 million, respectively. The Company realizes tax benfits from the exercise of stock options on a calendar year basis as opposed to a fiscal year basis. As such, for stock options exercised during the quarters ended December 31, 2005 and December 31, 2004, the Company realized a tax benefit of $0.9 million and $1.1 million, respectively. For stock options exercised during the quarter ended March 31, 2006, the Company will realize a tax benefit of approximately $1.4 million in the quarter ended December 31, 2006. For stock options exercised during the quarter ended March 31, 2005, the Company realized a tax benefit of approximately $2.0 million in the quarter ended December 31, 2005. No stock options were granted or became fully vested during the quarter ended March 31, 2006. The weighted average grant date fair value of options granted during the quarter ended March 31, 2005 is $4.62 per share. No stock options became fully vested during the quarter ended March 31, 2005. As of March 31, 2006, unrecognized compensation expense related to stock options totaled approximately $124,000, which will be recognized over a weighted average period of 1.3 years.
For options granted prior to October 1, 2005, the fair value of options at date of grant was estimated using a Binomial option-pricing model with the following weighted average assumptions:
March 31, ------------------ 2006 2005 ---- ---- Risk Free Interest Rate 4.04% 4.74% Expected Life (years) 6.6 5.9 Expected Volatility 21.2% 21.0% Expected Dividend Yield (Quarterly) 1.10% 1.04%
The risk-free interest rate is based on the yield of a Treasury Note with a remaining term commensurate with the expected term of the option. The expected life and expected volatility are based on historical experience.
16
The Company used a forfeiture rate of 13.6% for calculating stock-based compensation expense related to stock options and this rate is based on the Company’s historical experience of forfeitures on unvested stock option grants.
Transactions during the quarter ended March 31, 2006 were as follows (in thousands, except fair values):
Number of Weighted Average Restricted Fair Value per Share Awards Award ------------ ---------------- Restricted Share Awards Outstanding at September 30, 2005 65 $ 24.46 Granted - - Vested (8) 23.75 Forfeited - - -------- ------- Restricted Share Awards Outstanding at December 31, 2005 57 24.56 Granted - - Vested (25) 24.50 Forfeited - - ------- ------- Restricted Share Awards Outstanding at March 31, 2006 32 $ 24.60 ======= =======
As of March 31, 2006, unrecognized compensation expense related to restricted share awards totaled approximately $147,000, which will be recognized over a weighted average period of 1.1 years.
New Accounting Pronouncements.In March 2005, the FASB issued FIN 47, an interpretation of SFAS 143. FIN 47 provides clarification of the term “conditional asset retirement obligation” as used in SFAS 143, defined as a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the Company. Under this standard, a company must record a liability for a conditional asset retirement obligation if the fair value of the obligation can be reasonably estimated. FIN 47 also serves to clarify when a company would have sufficient information to reasonably estimate the fair value of a conditional asset retirement obligation. FIN 47 becomes effective no later than the end of fiscal 2006. The Company is currently evaluating the impact of FIN 47 on its consolidated financial statements.
In May 2005, the FASB issued SFAS 154. SFAS 154 replaces APB 20 and SFAS 3 and changes the requirements for the accounting for and reporting of a change in accounting principle. The Company is required to adopt SFAS 154 for accounting changes and corrections of errors that occur in fiscal 2007. Early adoption is permitted. The Company’s financial condition and results of operations will only be impacted by SFAS 154 if there are any accounting changes or corrections of errors in the future.
The components of federal, state and foreign income taxes included in the Consolidated Statements of Income are as follows (in thousands):
17
Six Months Ended March 31, 2006 2005 ------------------- -------------------- Operating Expenses: Current Income Taxes Federal $62,466 $59,024 State 15,181 16,882 Foreign 2,328 127 Deferred Income Taxes Federal (1,433) (5,938) State (223) (2,228) Foreign 223 2,590 ------------------- -------------------- 78,542 70,457 Other Income: Deferred Investment Tax Credit (348) (348) Discontinued Operations - 9,837 ------------------- -------------------- Total Income Taxes $78,194 $79,946 =================== ====================
The U.S. and foreign components of income before income taxes are as follows (in thousands):
Six Months Ended March 31, 2006 2005 ------------------- -------------------- U.S. $195,503 $170,680 Foreign 18,704 30,386 ------------------- -------------------- $214,207 $201,066 =================== ====================
Total income taxes as reported differ from the amounts that were computed by applying the federal income tax rate to income before income taxes. The following is a reconciliation of this difference (in thousands):
Six Months Ended March 31, 2006 2005 ------------------- -------------------- Income Tax Expense, Computed at Statutory Rate of 35% $74,972 $70,373 Increase (Reduction) in Taxes Resulting From: State Income Taxes 9,723 9,525 Dividend from Foreign Subsidiary - 3,837 Foreign Tax Differential (4,704) (1) (1,952) Miscellaneous (1,797) (1,837) ------------------- -------------------- Total Income Taxes $78,194 $79,946 =================== ====================
18
Significant components of the Company's deferred tax liabilities (assets) were as follows (in thousands): At March 31, 2006 At September 30, 2005 --------------------------------- ---------------------------- Deferred Tax Liabilities: Property, Plant and Equipment $578,038 $567,850 Other 39,692 52,436 --------------------------------- ---------------------------- Total Deferred Tax Liabilities 617,730 620,286 --------------------------------- ---------------------------- Deferred Tax Assets: Minimum Pension Liability Adjustment (58,070) (58,069) Capital Loss Carryover (7,196) (9,145) Unrealized Hedging Losses (26,170) (75,657) Other (75,570) (74,346) --------------------------------- ---------------------------- (167,006) (217,217) Valuation Allowance 2,877 2,877 --------------------------------- ---------------------------- Total Deferred Tax Assets (164,129) (214,340) --------------------------------- ---------------------------- Total Net Deferred Income Taxes $453,601 $405,946 --------------------------------- ---------------------------- Presented as Follows: Net Deferred Tax Asset - Current (49,546) (83,774) Net Deferred Tax Liability - Non-Current 503,147 489,720 --------------------------------- ---------------------------- Total Net Deferred Income Taxes $453,601 $405,946 ================================= ============================
Regulatory liabilities representing the reduction of previously recorded deferred income taxes with rate-regulated activities that are expected to be refundable to customers amounted to $11.1 million and $11.0 million at March 31, 2006 and September 30, 2005, respectively. Also, regulatory assets representing future amounts collectible from customers, corresponding to additional deferred income taxes not previously recorded because of prior ratemaking practices, amounted to $84.8 million and $85.0 million at March 31, 2006 and September 30, 2005, respectively.
The American Jobs Creation Act of 2004 was signed into law on October 22, 2004. This legislation included a provision which provided a substantially reduced tax rate of 5.25% on certain dividends received from foreign affiliates. In the quarter ended June 30, 2005, the Company received a dividend of $72.8 million from a foreign affiliate and recorded a tax of $3.8 million on such dividend.
A capital loss carryover of $20.6 million existed at March 31, 2006, which expires if not utilized by September 30, 2008. Although realization is not assured, management estimates that a portion of the deferred tax asset associated with this carryover will be realized during the carryover period, and a valuation allowance is recorded for the remaining portion. Adjustments to the valuation allowance may be necessary in the future if estimates of capital gain income are revised.
Common Stock. During the six months ended March 31, 2006, the Company issued 507,855 shares of common stock as a result of stock option exercises. The Company also issued 4,200 shares of common stock to the non-employee directors of the Company as partial consideration for the directors’ services during the six months ended March 31, 2006. Holders of stock options or restricted stock will often tender shares of common stock to the Company for payment of option exercise prices and/or applicable withholding taxes. During the six months ended March 31, 2006, 123,811 shares of common stock were tendered to the Company for such purposes. The Company considers all shares tendered as cancelled shares restored to the status of authorized but unissued shares, in accordance with New Jersey law.
19
On December 8, 2005, the Company’s board of directors authorized the Company to implement a share repurchase program, whereby the Company may repurchase outstanding shares of common stock, up to an aggregate amount of 8 million shares in the open market or through privately negotiated transactions. During the quarter ended March 31, 2006, the Company repurchased 825,250 shares under this program, funded with cash provided by operating activities. At March 31, 2006, the Company had made commitments to repurchase an additional 16,600 shares of common stock. These commitments were settled and recorded as a reduction of the Company’s outstanding shares of common stock in April 2006.
Environmental Matters. The Company is subject to various federal, state and local laws and regulations relating to the protection of the environment. The Company has established procedures for the ongoing evaluation of its operations to identify potential environmental exposures and comply with regulatory policies and procedures. It is the Company’s policy to accrue estimated environmental clean-up costs (investigation and remediation) when such amounts can reasonably be estimated and it is probable that the Company will be required to incur such costs. At March 31, 2006, the Company has estimated its remaining clean-up costs related to former manufactured gas plant sites and third party waste disposal sites will be $3.9 million. This liability has been recorded on the Consolidated Balance Sheet at March 31, 2006. The Company expects to recover its environmental clean-up costs from a combination of insurance proceeds and rate recovery. Other than as discussed in Note G of the Company’s 2005 Form 10-K (referred to below), the Company is currently not aware of any material additional exposure to environmental liabilities. However, adverse changes in environmental regulations or other factors could impact the Company.
Other. In addition to the legal proceedings disclosed in Part II, Item 1 of this report, the Company is involved in other litigation and regulatory matters arising in the normal course of business. These other matters may include, for example, negligence claims and tax, regulatory or other governmental audits, inspections, investigations or other proceedings. These matters may involve state and federal taxes, safety, compliance with regulations, rate base, cost of service, and purchased gas cost issues, among other things. While these normal-course matters could have a material effect on earnings and cash flows in the quarterly and annual period in which they are resolved, they are not expected to change materially the Company’s present liquidity position, nor to have a material adverse effect on the financial condition of the Company.
On July 18, 2005, the Company completed the sale of its entire 85.16% interest in U.E., a district heating and electric generation business in the Bohemia region of the Czech Republic, to Czech Energy Holdings, a.s. for sales proceeds of approximately $116.3 million. The sale resulted in the recognition of a gain of approximately $25.8 million, net of tax, at September 30, 2005. Market conditions during 2005, including the increasing value of the Czech currency as compared to the U.S. dollar, caused the value of the assets of U.E. to increase, providing an opportunity to sell the U.E. operations at a profit for the Company. As a result of the decision to sell its majority interest in U.E., the Company began presenting the Czech Republic operations, which are primarily comprised of U.E., as discontinued operations in June 2005. U.E. was the major component of the Company’s International segment. With this change in presentation, the Company discontinued all reporting for an International segment.
The following is selected financial information of the discontinued operations for U.E.:
20
Three Months Six Months Ended Ended March 31, March 31, (Thousands) 2005 2005 ---------------------- ---------------------- Operating Revenues $55,487 $99,462 Operating Expenses 37,872 73,651 ---------------------- ---------------------- Operating Income 17,615 25,811 Other Income 314 1,141 Interest Expense (152) (321) ---------------------- ---------------------- Income before Income Taxes and Minority Interest 17,777 26,631 Income Tax Expense 8,670 10,979 Minority Interest, Net of Taxes 2,405 3,342 ---------------------- ---------------------- Income from Discontinued Operations $6,702 $12,310 ====================== ======================
The Company has five reportable segments: Utility, Pipeline and Storage, Exploration and Production, Energy Marketing, and Timber. The division of the Company’s operations into the reportable segments is based upon a combination of factors including differences in products and services, regulatory environment and geographic factors.
The data presented in the tables below reflect the reportable segments and reconciliations to consolidated amounts. As stated in the 2005 Form 10-K, the Company evaluates segment performance based on income before discontinued operations, extraordinary items and cumulative effects of changes in accounting (where applicable). When these items are not applicable, the Company evaluates performance based on net income. There have been no changes in the basis of segmentation nor in the basis of measuring segment profit or loss from those used in the Company’s 2005 Form 10-K. There have been no material changes in the amount of assets for any operating segment from the amounts disclosed in the 2005 Form 10-K.
21
Quarter Ended March 31, 2006 (Thousands) - ------------------------------------------------------------------------------------------------------------------------------------- Pipeline Exploration Total Corporate and and and Energy Reportable Intersegment Total Utility Storage Production Marketing Timber Segments All Other Eliminations Consolidated - ------------------------------------------------------------------------------------------------------------------------------------- Revenue from External Customers $536,235 $39,346 $88,719 $206,061 $19,157 $889,518 $ 1,075 $ 388 $890,981 Intersegment Revenues $ 5,681 $19,711 $ - $ - $ (23) $ 25,369 $ 2,057 $(27,426) $ - Segment Profit: Net Income $ 28,654 $16,892 $25,845 $ 3,877 $2,242 $77,510 $ 46 $ 1,038 $78,594 Six Months Ended March 31, 2006 (Thousands) - ------------------------------------------------------------------------------------------------------------------------------------- Pipeline Exploration Total Corporate and and and Energy Reportable Intersegment Total Utility Storage Production Marketing Timber Segments All Other Eliminations Consolidated - ------------------------------------------------------------------------------------------------------------------------------------- Revenue from External Customers $967,714 $74,085 $170,806 $351,620 $36,066 $1,600,291 $1,058 $ 388 $1,601,737 Intersegment Revenues $ 9,803 $41,006 $ - $ - $ - $ 50,809 $6,584 $(57,393) $ - Segment Profit: Net Income $50,407 $32,742 $ 43,280 $ 4,864 $ 3,706 $ 134,999 $ 616 $ 398 $ 136,013 Quarter Ended March 31, 2005 (Thousands) - ------------------------------------------------------------------------------------------------------------------------------------- Pipeline Exploration Total Corporate and and and Energy Reportable Intersegment Total Utility Storage Production Marketing Timber Segments All Other Eliminations Consolidated - ------------------------------------------------------------------------------------------------------------------------------------- Revenue from External Customers $485,647 $36,029 $70,319 $124,565 $18,971 $735,531 $ 311 $ - $735,842 Intersegment Revenues $ 5,693 $21,517 $ - $ - $ 1 $ 27,211 $3,263 $(30,474) $ - Segment Profit (Loss): Income (Loss) from Continuing Operations $ 28,882 $18,457 $11,230 $ 2,612 $ 2,893 $ 64,074 $ 652 $ (745) $63,981 Six Months Ended March 31, 2005 (Thousands) - ------------------------------------------------------------------------------------------------------------------------------------- Pipeline Exploration Total Corporate and and and Energy Reportable Intersegment Total Utility Storage Production Marketing Timber Segments All Other Eliminations Consolidated - ------------------------------------------------------------------------------------------------------------------------------------- Revenue from External Customers $802,476 $68,474 $142,157 $188,059 $31,966 $1,233,132 $2,994 $ - $1,236,126 Intersegment Revenues $ 9,998 $42,116 $ - $ - $ 1 $ 52,115 $4,342 $(56,457) $ - Segment Profit (Loss): Income (Loss) from Continuing Operations $ 46,954 $ 30,734 $ 25,153 $ 3,361 $ 3,646 $ 109,848 $1,252 $ (2,290) $ 108,810
22
The components of the Company’s intangible assets were as follows (in thousands):
At September 30, At March 31, 2006 2005 ----------------------------------------- --------------------- Gross Net Net Carrying Accumulated Carrying Carrying Amount Amortization Amount Amount ----------- ----------------- ----------- --------------------- Intangible Assets Subject to Amortization: Long-Term Transportation Contracts $8,580 $(3,385) $5,195 $5,729 Long-Term Gas Purchase Contracts 31,864 (4,230) 27,634 28,431 Intangible Assets Not Subject to Amortization: Retirement Plan Intangible Asset 8,142 - 8,142 8,142 ----------- ----------- ---------- ------------ $48,586 $ (7,615) $40,971 $42,302 ----------- ----------- ---------- ------------ Aggregate Amortization Expense: (Thousands) Three Months Ended March 31, 2006 $665 Three Months Ended March 31, 2005 $665 Six Months Ended March 31, 2006 $1,331 Six Months Ended March 31, 2005 $1,331
Amortization expense for the long-term transportation contracts is estimated to be $0.5 million for the remainder of 2006 and $1.1 million annually for 2007 and 2008. Amortization expense is estimated to be $0.5 million and $0.4 million for 2009 and 2010, respectively.
Amortization expense for the long-term gas purchase contracts is estimated to be $0.8 million for the remainder of 2006 and $1.6 million annually for 2007, 2008, 2009 and 2010.
Components of Net Periodic Benefit Cost (in thousands):
Three months ended March 31,
Retirement Plan Other Post-Retirement Benefits --------------- ------------------------------ 2006 2005 2006 2005 ---- ---- ---- ---- Service Cost $4,104 $3,429 $2,007 $1,538 Interest Cost 10,049 10,520 6,701 6,446 Expected Return on Plan Assets (12,486) (12,386) (5,576) (4,715) Amortization of Prior Service Cost 239 257 1 1 Amortization of Transition Amount - - 1,782 1,782 Amortization of Losses 5,777 2,618 5,850 3,116 Net Amortization and Deferral For Regulatory Purposes (Including Volumetric Adjustments) (1) 1,907 2,723 2,634 5,948 ----------- ------------ ------------- -------------- Net Periodic Benefit Cost $9,590 $7,161 $13,399 $14,116 =========== ============ ============= ==============
23
Six months ended March 31,
Retirement Plan Other Post-Retirement Benefits --------------- ------------------------------ 2006 2005 2006 2005 ---- ---- ---- ---- Service Cost $8,208 $6,858 $ 4,015 $ 3,076 Interest Cost 20,098 21,040 13,402 12,892 Expected Return on Plan Assets (24,972) (24,772) (11,151) (9,430) Amortization of Prior Service Cost 478 514 2 2 Amortization of Transition Amount - - 3,564 3,564 Amortization of Losses 11,554 5,236 11,701 6,232 Net Amortization and Deferral For Regulatory Purposes (Including Volumetric Adjustments) (1) 379 3,605 (51) 5,235 ----------- ----------- ------------ ------------ Net Periodic Benefit Cost $15,745 $12,481 $21,482 $21,571 =========== =========== ============ ============
Employer Contributions. During the six months ended March 31, 2006, the Company contributed $10.5 million to its retirement plan and $26.6 million to its other post-retirement benefit plan. In April 2006, the Company funded $8.6 million to its retirement plan and $2.2 million to its other post-retirement benefit plan. The Company does not expect to make any contributions to the retirement plan during the remainder of the fiscal year. In the remainder of 2006, the Company expects to contribute in the range of $10.0 million to $12.0 million to its other post-retirement benefit plan.
24
For a complete discussion of critical accounting policies, refer to “Critical Accounting Policies” in Item 7 of the Company’s 2005 Form 10-K. There have been no material changes to that disclosure other than as set forth below. The information presented below updates and should be read in conjunction with the critical accounting policies in that Form 10-K.
At March 31, 2006, the Canadian oil and gas properties passed the quarterly ceiling tests but capitalized costs less accumulated depletion and related deferred income taxes were nearly equal to the ceiling. A downward revision to reserves or prices could result in an impairment of the Canadian oil and gas properties in the future.
The Company’s earnings were $78.6 million for the quarter ended March 31, 2006 compared to earnings of $70.7 million for the quarter ended March 31, 2005. As previously discussed, the Company began presenting its Czech Republic operations as discontinued operations in June 2005. Prior year amounts have been reclassified to reflect this change in presentation. The Company’s earnings from continuing operations were $78.6 million for the quarter ended March 31, 2006 compared to earnings from continuing operations of $64.0 million for the quarter ended March 31, 2005. The increase in earnings from continuing operations of $14.6 million is primarily the result of higher earnings in the Exploration and Production segment, as shown in the table below. The Pipeline and Storage segment’s earnings for the quarter ended March 31, 2005 include a $2.6 million gain on the FERC approved sale of base gas by Supply Corporation’s jointly-owned Ellisburg Storage Pool. The Exploration and Production segment’s earnings for the quarter ended March 31, 2006 include a $5.1 million benefit to earnings resulting from an adjustment to a deferred income tax balance.
The Company’s earnings were $136.0 million for the six months ended March 31, 2006 compared to earnings of $121.1 million for the six months ended March 31, 2005. The Company’s earnings from continuing operations were $136.0 million for the six months ended March 31, 2006 compared to earnings from continuing operations of $108.8 million for the six months ended March 31, 2005. The increase in earnings from continuing operations of $27.2 million is primarily the result of higher earnings in the Utility, Pipeline and Storage, Exploration and Production, and Energy Marketing segments, as well as in Corporate operations, as shown in the table below. As mentioned above, earnings for the six months ended March 31, 2005 include a $2.6 million gain on the sale of base gas in the Pipeline and Storage segment and earnings for the six months ended March 31, 2006 include a $5.1 million deferred income tax benefit in the Exploration and Production segment.
Additional discussion of earnings in each of the business segments can be found in the business segment information that follows. Note that all amounts used in the earnings discussions are after tax amounts.
25
Earnings (Loss) by Segment- ------------------------------------ ------------------------------------------- ------------------------------------------- Three Months Ended Six Months Ended March 31, March 31, - ------------------------------------ ------------------------------------------- ------------------------------------------- Increase/ Increase/(Thousands) 2006 2005 (Decrease) 2006 2005 (Decrease) - ------------------------------------ ------------- ------------- --------------- ------------- ------------- --------------- Utility $28,654 $28,882 $(228) $50,407 $46,954 $3,453 Pipeline and Storage 16,892 18,457 (1,565) 32,742 30,734 2,008 Exploration and Production 25,845 11,230 14,615 43,280 25,153 18,127 Energy Marketing 3,877 2,612 1,265 4,864 3,361 1,503 Timber 2,242 2,893 (651) 3,706 3,646 60 - ------------------------------------ ------------- ------------- --------------- ------------- ------------- --------------- Total Reportable Segments 77,510 64,074 13,436 134,999 109,848 25,151 All Other 46 652 (606) 616 1,252 (636) Corporate (1) 1,038 (745) 1,783 398 (2,290) 2,688 - ------------------------------------ ------------- ------------- --------------- ------------- ------------- --------------- Total Earnings from Continuing Operations 78,594 63,981 14,613 136,013 108,810 27,203 - ------------------------------------ ------------- ------------- --------------- ------------- ------------- --------------- Earnings from Discontinued Operations - 6,702 (6,702) - 12,310 (12,310) - ------------------------------------ ------------- ------------- --------------- ------------- ------------- --------------- Total Consolidated $78,594 $70,683 $7,911 $136,013 $121,120 $14,893 - ------------------------------------ ------------- ------------- --------------- ------------- ------------- --------------- (1) Includes earnings from the former International segment's activity other than the activity from the Czech Republic operations included in Earnings from Discontinued Operations.UtilityUtility Operating Revenues- ------------------------------- ------------------------------------------- ------------------------------------------ Three Months Ended Six Months Ended March 31, March 31, - ------------------------------- ------------------------------------------- ------------------------------------------(Thousands) 2006 2005 Increase 2006 2005 Increase - ------------------------------- ------------- -------------- -------------- ------------ -------------- -------------- Retail Sales Revenues: Residential $422,495 $386,623 $35,872 $767,368 $641,689 $125,679 Commercial 75,758 69,367 6,391 132,648 111,150 21,498 Industrial 6,272 4,566 1,706 10,724 6,710 4,014 - ------------------------------- ------------- -------------- -------------- ------------ -------------- -------------- 504,525 460,556 43,969 910,740 759,549 151,191 - ------------------------------- ------------- -------------- -------------- ------------ -------------- -------------- Transportation 32,360 30,600 1,760 59,276 51,559 7,717 Other 5,031 184 4,847 7,501 1,366 6,135 - ------------------------------- ------------- -------------- -------------- ------------ -------------- -------------- $541,916 $491,340 $50,576 $977,517 $812,474 $165,043 - ------------------------------- ------------- -------------- -------------- ------------ -------------- --------------Utility ThroughputM- ------------------------------- ------------------------------------------- ------------------------------------------ Three Months Ended Six Months Ended March 31, March 31, - ------------------------------- ------------------------------------------- ------------------------------------------ Increase/ Increase/(MMcf) 2006 2005 (Decrease) 2006 2005 (Decrease) - ------------------------------- ------------- -------------- -------------- ------------ -------------- -------------- Retail Sales: Residential 26,807 32,559 (5,752) 46,331 52,428 (6,097) Commercial 5,038 6,072 (1,034) 8,481 9,526 (1,045) Industrial 459 425 34 786 601 185 - ------------------------------- ------------- -------------- -------------- ------------ -------------- -------------- 32,304 39,056 (6,752) 55,598 62,555 (6,957) - ------------------------------- ------------- -------------- -------------- ------------ -------------- -------------- Transportation 22,119 22,465 (346) 36,461 36,568 (107) - ------------------------------- ------------- -------------- -------------- ------------ -------------- -------------- 54,423 61,521 (7,098) 92,059 99,123 (7,064) - ------------------------------- ------------- -------------- -------------- ------------ -------------- --------------
26
Degree Days- ---------------------------------- -------------- -------------- -------------------- -------------------------------- Percent Three Months Ended Colder (Warmer) Than -------------------------------- March 31 Normal 2006 2005 Normal Prior Year - ---------------------------------- -------------- -------------- -------------------- ----------------- -------------- Buffalo 3,327 2,875 3,468 (13.6) (17.1) Erie 3,142 2,705 3,266 (13.9) (17.2) - ---------------------------------- -------------- -------------- -------------------- ----------------- -------------- Six Months Ended March 31 - ---------------------------------- -------------- -------------- -------------------- ----------------- -------------- Buffalo 5,587 5,085 5,640 (9.0) (9.8) Erie 5,223 4,753 5,263 (9.0) (9.7) - ---------------------------------- -------------- -------------- -------------------- ----------------- --------------
Operating revenues for the Utility segment increased $50.6 million for the quarter ended March 31, 2006 as compared with the quarter ended March 31, 2005. The increase is attributable primarily to higher retail gas sales revenues. Retail gas sales revenues increased $44.0 million largely due to the recovery of higher gas costs (gas costs are recovered dollar for dollar in revenues), which more than offset the decrease in retail gas sales revenues resulting from lower volumes. The decrease in volumes reflects warmer weather for the period as well as lower average usage per customer stemming from customer conservation efforts. The impact of the New York rate case settlement, which became effective August 2005, was to increase operating revenues by $7.8 million. This increase consisted of a base rate increase, the implementation of a merchant function charge, the elimination of certain bill credits, and the elimination of the gross receipts tax surcharge. In the Pennsylvania jurisdiction, the impact of a base rate increase, which became effective in April 2005, was to increase operating revenues by $4.3 million.
Operating revenues for the Utility segment increased $165.0 million for the six months ended March 31, 2006 as compared with the six months ended March 31, 2005. The increase is primarily attributable to higher retail gas sales revenues. The increase in retail gas sales revenues was largely a function of the recovery of higher gas costs, which more than offset lower retail sales volumes, as shown above. The increase in transportation revenues was primarily due to an out-of-period adjustment of $3.9 million to correct the New York jurisdiction’s calculation of the symmetrical sharing component of the Gas Adjustment rate. The adjustment resulted when it was determined that certain credits that had been included in the calculation should have been removed during the implementation of a previous rate case settlement. The symmetrical sharing component is a mechanism included in Distribution’s New York rate settlement that shares with customers 90% of the difference between actual revenues received from large volume customers and the level of revenues that were projected to be received during the rate year. The impact of the New York rate case settlement, discussed above, was to increase operating revenues by $13.3 million. In the Pennsylvania jurisdiction, the impact of a base rate increase, which became effective in April 2005, was to increase operating revenues by $7.1 million.
The Utility segment’s earnings for the quarter ended March 31, 2006 were $28.7 million, a decrease of $0.2 million when compared with the quarter ended March 31, 2005. In the New York jurisdiction, earnings increased by $1.3 million principally due to the rate case settlement in this jurisdiction that became effective in August 2005 ($5.1 million). This increase was partially offset by an increase in pension and post retirement expense ($1.5 million), higher bad debt expense ($1.2 million), higher interest expense ($0.9 million) and a decline in margin associated with lower average usage per customer ($0.5 million). In the Pennsylvania Division, earnings decreased by $1.5 million primarily due to the impact of warmer weather ($2.4 million), lower average usage per customer ($0.6 million), an increase in bad debt expense ($0.8 million) and a higher effective tax rate in this jurisdiction ($0.9 million). Partially offsetting these decreases, the rate case settlement in this jurisdiction, which became effective in April 2005, increased quarterly earnings by approximately $2.8 million. Lower pension and post retirement expense ($0.4 million) also increased earnings in the Pennsylvania jurisdiction.
The impact of weather variations on earnings in the New York jurisdiction is mitigated by that jurisdiction’s WNC. The WNC in New York, which covers the eight-month period from October through May, has had a stabilizing effect on earnings for the New York rate jurisdiction. For the quarter ended March 31, 2006, the WNC preserved earnings of approximately $4.2 million, as weather was warmer than
27
normal for the period. For the quarter ended March 31, 2005, the WNC reduced earnings by approximately $1.5 million, since weather for the period was colder than normal.
The Utility segment’s earnings for the six months ended March 31, 2006 were $50.4 million, an increase of $3.4 million when compared with the earnings of $47.0 million for the six months ended March 31, 2005. In the New York jurisdiction, earnings increased by $3.0 million due primarily to the positive impact of the rate case settlement in this jurisdiction ($8.6 million), discussed above, and the impact of the symmetrical sharing adjustment ($2.6 million). This increase was partially offset by an increase in bad debt expense ($3.3 million), higher pension and post retirement expense ($2.1 million), higher interest expense ($1.5 million) and a decline in margin associated with lower average usage per customer ($0.8 million). For the Pennsylvania jurisdiction, earnings increased by $0.4 million. The rate case settlement in this jurisdiction, discussed above, increased earnings by approximately $4.6 million. In addition, earnings were increased slightly by lower pension and post retirement expense ($0.5 million). These increases were offset by the impacts to margin of warmer weather ($2.1 million) and lower average usage per customer ($1.0 million), as well as an increase in bad debt expense ($1.4 million).
For the six months ended March 31, 2006, the WNC preserved earnings of approximately $4.7 million, as the weather was warmer than normal. For the six months ended March 31, 2005, the WNC did not have a significant impact on earnings as the weather was close to normal.
Pipeline and StoragePipeline and Storage Operating Revenues- ------------------------------------ ---------------------------------------- ------------------------------------------- Three Months Ended Six Months Ended March 31, March 31, - ------------------------------------ ---------------------------------------- ------------------------------------------- Increase/ Increase/(Thousands) 2006 2005 (Decrease) 2006 2005 (Decrease) - ------------------------------------ ------------ ------------ -------------- --------------- ------------ -------------- Firm Transportation $31,738 $32,086 $(348) $62,824 $61,616 $1,208 Interruptible Transportation 1,115 922 193 2,438 1,848 590 - ------------------------------------ ------------ ------------ -------------- --------------- ------------ -------------- 32,853 33,008 (155) 65,262 63,464 1,798 - ------------------------------------ ------------ ------------ -------------- --------------- ------------ -------------- Firm Storage Service 16,408 16,376 32 32,655 32,471 184 Other 9,796 8,162 1,634 17,174 14,655 2,519 - ------------------------------------ ------------ ------------ -------------- --------------- ------------ -------------- $59,057 $57,546 $1,511 $115,091 $110,590 $4,501 - ------------------------------------ ------------ ------------ -------------- --------------- ------------ --------------Pipeline and Storage Throughput- ------------------------------------ ---------------------------------------- ------------------------------------------- Three Months Ended Six Months Ended March 31, March 31, - ------------------------------------ ---------------------------------------- ------------------------------------------- Increase/ Increase/(MMcf) 2006 2005 (Decrease) 2006 2005 (Decrease) - ------------------------------------ ------------ ------------ -------------- --------------- ------------ -------------- Firm Transportation 114,828 129,851 (15,023) 217,650 213,593 4,057 Interruptible Transportation 1,831 1,180 651 5,554 2,842 2,712 - ------------------------------------ ------------ ------------ -------------- --------------- ------------ -------------- 116,659 131,031 (14,372) 223,204 216,435 6,769 - ------------------------------------ ------------ ------------ -------------- --------------- ------------ --------------
Operating revenues for the Pipeline and Storage segment increased $1.5 million for the quarter ended March 31, 2006 as compared with the quarter ended March 31, 2005. The increase was primarily due to higher revenues from unbundled pipeline sales reported as part of other revenues in the table above, due to higher natural gas prices. For the six months ended March 31, 2006, operating revenues for the Pipeline and Storage segment increased $4.5 million as compared with the six months ended March 31, 2005. The increase was primarily due to higher revenues from unbundled pipeline sales ($4.4 million), due to higher natural gas prices. The $1.8 million increase in transportation revenues was primarily due to additional contracts with customers and the renewal of contracts at higher rates, both of which reflect the increased demand for transportation services due to market conditions resulting from the effects of last fall’s hurricane damage to production and pipeline infrastructure in the Gulf of Mexico. Also
28
contributing to the increase in transportation revenues was the addition of new contracts with customers due to the Interconnect Pressure Agreement with TransCanada Pipelines, Ltd. The Interconnect Pressure Agreement is an excess pressure agreement that allows for greater capacity on the Empire State Pipeline.
The Pipeline and Storage segment’s earnings for the quarter ended March 31, 2006 were $16.9 million, a decrease of $1.6 million when compared with earnings of $18.5 million for the quarter ended March 31, 2005. The decrease can be attributed to the $2.6 million gain on the FERC approved sale of base gas during the quarter ended March 31, 2005 that did not recur in 2006, and higher operation and maintenance expense ($1.6 million), due primarily to higher pension expense ($1.0 million). Higher unbundled pipeline sales ($1.9 million) and lower depreciation expense ($0.7 million) partially offset these increases.
The Pipeline and Storage segment’s earnings for the six months ended March 31, 2006 were $32.7 million, an increase of $2.0 million when compared with earnings of $30.7 million for the six months ended March 31, 2005. The major factors that contributed to the increase were higher revenues from unbundled pipeline sales ($2.8 million), higher transportation revenues ($1.2 million), a lower reserve for preliminary project costs associated with the Empire State Pipeline Connector project ($0.8 million), lower depreciation expense ($0.6 million), and lower interest expense ($0.4 million). These increases in earnings were offset by the $2.6 million gain on the FERC approved sale of base gas during the six months ended March 31, 2005 that did not recur in 2006, and higher pension expense ($0.8 million).
Exploration and ProductionExploration and Production Operating Revenues- ------------------------------------- --------------------------------------- ----------------------------------------- Three Months Ended Six Months Ended March 31, March 31, - ------------------------------------- --------------------------------------- ----------------------------------------- Increase/ Increase/(Thousands) 2006 2005 (Decrease) 2006 2005 (Decrease) - ------------------------------------- ------------ ------------ ------------- ------------- ------------ -------------- Gas (after Hedging) $49,432 $42,520 $6,912 $98,774 $85,264 $13,510 Oil (after Hedging) 36,262 25,624 10,638 65,656 52,520 13,136 Gas Processing Plant 10,662 8,344 2,318 24,082 17,048 7,034 Other 312 434 (122) 1,835 1,187 648 Intrasegment Elimination (1) (7,949) (6,603) (1,346) (19,541) (13,862) (5,679) - ------------------------------------- ------------ ------------ ------------- ------------- ------------ -------------- $88,719 $70,319 $18,400 $170,806 $142,157 28,649 - ------------------------------------- ------------ ------------ ------------- ------------- ------------ -------------- (1) Represents the elimination of certain West Coast gas production included in "Gas (after Hedging)" in the table above that was sold to the gas processing plant shown in the table above. An elimination for the same dollar amount was made to reduce the gas processing plant's Purchased Gas expense. - --------------------------------------- ---------------------------------------- --------------------------------------Production Volumes Three Months Ended Six Months Ended March 31, March 31, - --------------------------------------- ---------------------------------------- -------------------------------------- Increase/ Increase/ 2006 2005 (Decrease) 2006 2005 (Decrease) - --------------------------------------- ------------ ----------- --------------- ----------- ----------- --------------Gas Production (MMcf)Gulf Coast 2,752 2,844 (92) 4,419 6,069 1,650) West Coast 933 986 (53) 1,951 2,025 (74) Appalachia 1,246 1,137 109 2,499 2,343 156 Canada 1,761 2,160 (399) 3,672 3,825 (153) - --------------------------------------- ------------ ----------- --------------- ----------- ----------- -------------- 6,692 7,127 (435) 12,541 14,262 (1,721) - --------------------------------------- ------------ ----------- --------------- ----------- ----------- --------------Oil Production (Mbbl)Gulf Coast 181 261 (80) 288 550 (262) West Coast 639 634 5 1,324 1,287 37 Appalachia 12 9 3 22 12 10 Canada 68 78 (10) 155 154 1 - --------------------------------------- ------------ ----------- --------------- ----------- ----------- -------------- 900 982 (82) 1,789 2,003 (214) - --------------------------------------- ------------ ----------- --------------- ----------- ----------- --------------
29
Average Prices- ----------------------------------------- --------------------------------------- ---------------------------------------- Three Months Ended Six Months Ended March 31, March 31, - ----------------------------------------- --------------------------------------- ---------------------------------------- Increase/ Increase/ 2006 2005 (Decrease) 2006 2005 (Decrease) - ----------------------------------------- ----------- ----------- --------------- ------------ ------------ --------------Average Gas Price/McfGulf Coast $8.47 $6.75 $1.72 $9.33 $6.61 $2.72 West Coast $8.02 $6.20 $1.82 $9.62 $6.38 $3.24 Appalachia $10.03 $6.76 $3.27 $11.83 $7.26 $4.57 Canada $7.21 $5.52 $1.69 $9.06 $5.49 $3.57 Weighted Average $8.37 $6.30 $2.07 $9.79 $6.38 $3.41 Weighted Average After Hedging $7.39 $5.97 $1.42 $7.88 $5.98 $1.90Average Oil Price/bblGulf Coast $58.69 $46.42 $12.27 $58.39 $46.77 $11.62 West Coast $53.65 $37.67 $15.98 $52.46 $37.40 $15.06 Appalachia $60.28 $42.28 $18.00 $60.84 $42.85 $17.99 Canada $48.63 $41.08 $7.55 $45.57 $39.78 $5.79 Weighted Average $54.37 $40.31 $14.06 $52.92 $40.19 $12.73 Weighted Average After Hedging $40.30 $26.10 $14.20 $36.70 $26.22 $10.48 - ----------------------------------------- ----------- ----------- --------------- ------------ ------------ --------------
Operating revenues for the Exploration and Production segment increased $18.4 million for the quarter ended March 31, 2006 as compared with the quarter ended March 31, 2005. Oil production revenue after hedging increased $10.6 million due to a $14.20 per barrel increase in weighted average prices after hedging. Gas production revenue after hedging increased $6.9 million due to an increase in the weighted average price of gas after hedging ($1.42 per Mcf). This was offset slightly by an overall decrease in gas production of 435 MMcf, mostly due to a decline in Canadian production as a result of delays in drilling and gas processing plant constraints.
Operating revenues for the Exploration and Production segment increased $28.6 million for the six months ended March 31, 2006 as compared with the six months ended March 31, 2005. Oil production revenue after hedging increased $13.1 million due to a $10.48 per barrel increase in weighted average prices after hedging. This increase in prices was offset slightly by a decrease in production (214,000 barrels). Gas production revenue after hedging increased $13.5 million. An increase in the weighted average price of gas after hedging ($1.90 per Mcf) more than offset a decrease in gas production of 1,721 MMcf. The decrease in gas production occurred primarily in the Gulf Coast region (a 1,650 MMcf decline), which is partially attributable to last fall’s hurricane damage and partially to the expected decline rates for the Company’s production in this region.
The Exploration and Production segment’s earnings for the quarter ended March 31, 2006 were $25.8 million, an increase of $14.6 million when compared with earnings of $11.2 million for the quarter ended March 31, 2005. The increase is primarily attributable to the increase in operating revenues, due to higher commodity prices of oil and natural gas, as discussed above ($12.0 million). In addition, a $5.1 million benefit to earnings resulting from an adjustment to a deferred income tax balance was recognized during the quarter ended March 31, 2006. Under GAAP, a company may recognize the benefit of certain expected future income tax deductions as a deferred tax asset only if it anticipates sufficient future taxable income to utilize those deductions. As a result of the rise in commodity prices, the Company increased its forecast of future taxable income in the Exploration and Production segment’s Canadian division and, as a result, recorded a deferred tax asset for certain drilling costs that it now expects to deduct on future income tax returns. These increases were partially offset by higher lease operating costs ($1.4 million), higher general and administrative costs ($0.6 million) and higher depletion expense ($0.5 million). The increase in lease operating costs was primarily in the West Coast region due to higher steaming costs associated with heavy crude oil production in the California Midway-Sunset and North Lost Hills fields. The higher steaming costs were due to an increase in the price for natural gas purchased in the field and used in the steaming operations which averaged $7.72/Btu this quarter versus $5.62/Btu in the prior year’s
30
quarter and an increase in the volume burned at the North Lost Hills field. Beginning in April, a scrubber facility in the Midway-Sunset field was in full operation and is burning waste gas rather than purchased gas to generate the steam for its thermal recovery project.* Depletion expense increased in spite of the drop in production due to a rise in the per unit depletion rate, which was caused by an increase in finding and development costs.
The Exploration and Production segment’s earnings for the six months ended March 31, 2006 were $43.3 million, an increase of $18.1 million when compared with earnings of $25.2 million for the quarter ended March 31, 2005. As noted above, the increase is primarily attributable to the increase in operating revenues, due to higher commodity prices of oil and natural gas ($18.6 million) and the tax benefit of $5.1 million discussed above. Partially offsetting these increases were higher lease operating costs ($3.4 million), higher general and administrative costs ($1.4 million) and higher depreciation and depletion expense ($0.3 million). As discussed above, the increase in lease operating costs was primarily in the West Coast region due to higher steaming costs.
Energy MarketingEnergy Marketing Operating Revenues- ----------------------------------- -------------------------------------------- ----------------------------------------- Three Months Ended Six Months Ended March 31, March 31, - ----------------------------------- -------------------------------------------- ----------------------------------------- Increase/ Increase/(Thousands) 2006 2005 (Decrease) 2006 2005 (Decrease) - ----------------------------------- ------------- -------------- -------------- ------------ ------------- -------------- Natural Gas (after Hedging) $206,057 $124,560 $81,497 $351,580 $188,050 $163,530 Other 4 5 (1) 40 9 31 - ----------------------------------- ------------- -------------- --------------- ------------ ------------- -------------- $206,061 $124,565 $81,496 $351,620 $188,059 $163,561 - ----------------------------------- ------------- -------------- --------------- ------------ ------------- --------------Energy Marketing Volumes- ----------------------------------- -------------------------------------------- ----------------------------------------- Three Months Ended Six Months Ended March 31, March 31, - ----------------------------------- -------------------------------------------- ----------------------------------------- 2006 2005 Increase 2006 2005 Increase - ----------------------------------- ------------- -------------- --------------- ------------ ------------- -------------- Natural Gas - (MMcf) 17,332 15,184 2,148 27,306 23,191 4,115 - ----------------------------------- ------------- -------------- --------------- ------------ ------------- --------------
Operating revenues for the Energy Marketing segment increased $81.5 million and $163.6 million, respectively, for the quarter and six months ended March 31, 2006, as compared with the quarter and six months ended March 31, 2005. The increase for both the quarter and six months ended March 31, 2006 primarily reflects higher gas sales revenue due to an increase in the price of natural gas and, to a lesser extent, an increase in throughput. The increase in throughput was due to the addition of certain large commercial and industrial customers, which more than offset any decrease in throughput due to warmer weather and greater conservation by customers due to higher natural gas prices.
Earnings in the Energy Marketing segment increased $1.3 million and $1.5 million, respectively, for the quarter and six months ended March 31, 2006 as compared with the quarter and six months ended March 31, 2005. Despite warmer weather and greater conservation by customers, margins increased due to a number of factors, including higher volumes and the market flexibility associated with stored gas. The Energy Marketing segment’s contracts for significant storage and transportation volumes provided operational flexibility resulting in increased sales throughput and earnings.
31
TimberTimber Operating Revenues- ------------------------------- ------------------------------------------- --------------------------------------------- Three Months Ended Six Months Ended March 31, March 31, - ------------------------------- ------------------------------------------- --------------------------------------------- Increase/ Increase/(Thousands) 2006 2005 (Decrease) 2006 2005 (Decrease) - ------------------------------- -------------- ------------- -------------- --------------- ------------- --------------- Log Sales $8,267 $8,768 $(501) $14,523 $13,644 $879 Green Lumber Sales 1,968 1,863 105 3,430 3,309 121 Kiln Dry Lumber Sales 8,384 7,822 562 16,885 14,096 2,789 Other 515 519 (4) 1,228 918 310 - ------------------------------- -------------- ------------- -------------- --------------- ------------- --------------- Operating Revenues $19,134 $18,972 $162 $36,066 $31,967 $4,099 - ------------------------------- -------------- ------------- -------------- --------------- ------------- ---------------Timber Board Feet- ------------------------------- ------------------------------------------- --------------------------------------------- Three Months Ended Six Months Ended March 31, March 31, - ------------------------------- ------------------------------------------- --------------------------------------------- Increase/ Increase/(Thousands) 2006 2005 (Decrease) 2006 2005 (Decrease) - ------------------------------- -------------- ------------- -------------- --------------- ------------- --------------- Log Sales 3,282 2,570 712 5,774 4,315 1,459 Green Lumber Sales 2,982 2,538 444 4,956 4,702 254 Kiln Dry Lumber Sales 4,512 3,897 615 8,998 7,263 1,735 - ------------------------------- -------------- ------------- -------------- --------------- ------------- --------------- 10,776 9,005 1,771 19,728 16,280 3,448 - ------------------------------- -------------- ------------- -------------- --------------- ------------- ---------------
Operating revenues for the Timber segment increased $0.2 million and $4.1 million, respectively, for the quarter and six months ended March 31, 2006, as compared with the quarter and six months ended March 31, 2005. For the quarter ended March 31, 2006, the increase can be attributed primarily to an increase in kiln dry lumber sales ($0.6 million and 615,000 board feet) due to a 22 percent increase in processing capacity for kiln dry lumber from the addition of two new kilns in February 2005. This increase was largely offset by a decline in cherry veneer log sales as a result of lower volumes of cherry veneer logs harvested because of unfavorable weather conditions. Although there was an overall increase in log sales volumes in the table above, most of the increase came from lower priced logs. Cherry veneer logs command the highest prices and have the largest impact on overall log sales revenue. For the six months ended March 31, 2006, higher revenues from kiln dry lumber sales of $2.8 million are primarily responsible for the increase. The increase in kiln dry lumber sales is attributable to the increased kiln processing capacity noted above. Additionally, log sales increased $0.9 million primarily due to an increase in cherry export log sales as a result of greater market demand.
Earnings in the Timber segment decreased $0.7 million for the quarter ended March 31, 2006 as compared with the quarter ended March 31, 2005. This decline primarily resulted from the impact of lower margins from cherry veneer log sales combined with an increase in cost of goods sold on lumber sales.
The Timber segment’s earnings increased $0.1 million for the six months ended March 31, 2006 as compared to the six months ended March 31, 2005. Higher revenues from kiln dry lumber sales and cherry export log sales were largely offset by an increase in cost of goods sold on lumber sales, resulting in a net increase to earnings of $0.5 million. This increase was offset by higher depletion expense ($0.3 million).
32
Corporate and All Other recorded earnings of $1.1 million for the quarter ended March 31, 2006 compared with a loss of $0.1 million for the quarter ended March 31, 2005. For the six months ended March 31, 2006, Corporate and All Other had earnings of $1.0 million compared with a loss of $1.0 million for the six months ended March 31, 2005. These improvements were principally due to an increase in interest income resulting from the investment of proceeds received from the sale of U.E. in July 2005.
The Company’s primary source of cash during the six-month period ended March 31, 2006 consisted of cash provided by operating activities. This source of cash was supplemented by issuances of new shares of common stock as a result of stock option exercises. During the six months ended March 31, 2006, the common stock used to fulfill the requirements of the Company’s 401(k) plans and Direct Stock Purchase and Dividend Reinvestment Plan was obtained via open market purchases. During the three months ended March 31, 2006, the Company began repurchasing outstanding shares of its common stock under a share repurchase program, which is discussed below under Financing 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, income or loss from unconsolidated subsidiaries net of cash distributions, and minority interest in foreign subsidiaries.
Cash provided by operating activities in the Utility and the Pipeline and Storage segments may vary from period to period because of the impact of rate cases. In the Utility segment, supplier refunds, over- or under-recovered purchased gas costs and weather may also significantly impact cash flow. The impact of weather on cash flow is tempered in the Utility segment’s New York rate jurisdiction by its WNC and in the Pipeline and Storage segment by Supply Corporation’s straight fixed-variable rate design.
Because of the seasonal nature of the heating business in the Utility and Energy Marketing segments, revenues in these segments are relatively high during the heating season, primarily the first and second quarters of the fiscal year, and receivable balances historically increase during these periods from the balances receivable at September 30.
The storage gas inventory normally declines during the first and second quarters of the year and is replenished during the third and fourth quarters. For storage gas inventory accounted for under the LIFO method, the current cost of replacing gas withdrawn from storage is recorded in the Consolidated Statements of Income and a reserve for gas replacement is recorded in the Consolidated Balance Sheets under the caption “Other Accruals and Current Liabilities.” Such reserve is reduced as the inventory is replenished.
Cash provided by operating activities in the Exploration and Production segment may vary from period to period as a result of changes in the commodity prices of natural gas and crude oil. The Company uses various derivative financial instruments, including price swap agreements and no cost collars in an attempt to manage this energy commodity price risk.
Net cash provided by operating activities totaled $243.2 million for the six months ended March 31, 2006, a decrease of $2.8 million compared with $246.0 million provided by operating activities for the six months ended March 31, 2005. The timing of gas cost recovery in the Utility segment along with the loss of positive cash flow from the Company’s former Czech Republic operations, which were sold in July 2005, were the main reasons for this decrease. These decreases were mainly offset by higher oil and gas revenues in the Exploration and Production segment and a decrease in hedging collateral deposits at March 31, 2006 in the Exploration and Production and Energy Marketing segments. Hedging collateral deposits serve as collateral for open positions on exchange-traded futures contracts, exchange-traded options and over-the-counter swaps and collars.
33
Expenditures for Long-Lived Assets
The Company’s expenditures for long-lived assets totaled $135.0 million during the six months ended March 31, 2006. The table below presents these expenditures:
----------------------------------------------------------------- ------------------------ ------------------ Six Months Ended March 31, 2006 (in millions of dollars) Total Expenditures for Long-Lived Assets -------------------------------------- -------------------------- ------------------------ ------------------ Utility $25.4 Pipeline and Storage 10.3 Exploration and Production 96.3 Timber 0.8 Corporate and All Other 2.2 -------------------------------------- -------------------------- ------------------------ ------------------ $135.0 -------------------------------------- -------------------------- ------------------------ ------------------
Utility
The majority of the Utility capital expenditures for the six months ended March 31, 2006 were made for replacement of mains and main extensions, as well as for the replacement of service lines.
Pipeline and Storag
The majority of the Pipeline and Storage capital expenditures for the six months ended March 31, 2006 were made for additions, improvements, and replacements to this segment’s transmission and gas storage systems.
The Company continues to explore various opportunities to expand its capabilities to transport gas to the East Coast, either through the Supply Corporation or Empire systems or in partnership with others. In October 2005, Empire filed an application with the FERC for the authority to build and operate the Empire Connector project to expand its natural gas pipeline operations to serve new markets in New York and elsewhere in the Northeast by extending the Empire Pipeline. Assuming the proposed Millennium Pipeline is constructed, the Empire Connector will provide an upstream supply link for Phase I of the Millennium Pipeline and will transport Canadian and other natural gas supplies to downstream customers, including KeySpan Gas East Corporation, which has entered into precedent agreements to subscribe for at least 150 MDth per day of natural gas transportation service through the Empire State Pipeline and the Millennium Pipeline systems.* The Empire Connector will be designed to move up to approximately 250 MDth of natural gas per day.* Empire anticipates that FERC will provide a determination on this application by November 2006.* The targeted in-service date is November 2007.* The Company anticipates financing this project with cash on hand and/or through the use of the Company’s bi-lateral lines of credit.* As of March 31, 2006, the Company had incurred approximately $5.2 million in costs (all of which have been reserved) related to this project. Of this amount, $0.5 million and $1.2 million, respectively, were incurred during the quarter and six months ended March 31, 2006.
The Company also has plans to extend Supply Corporation’s pipeline system from the Tuscarora storage field to the intersection of the proposed Millennium and Empire Connector pipelines (the Tuscarora Extension).* The Tuscarora Extension will be designed initially to move up to approximately 130 MDth of natural gas per day.* The project depends on market developments and its in-service date will be contingent upon the Millennium/Empire project timeline. The Company has not yet filed an application with the FERC for the authority to build and operate the Tuscarora Extension. The Company anticipates financing this project with cash on hand and/or through the use of the Company’s bi-lateral lines of credit.* There have been no costs incurred by the Company related to this project as of March 31, 2006.
34
Exploration and Production
The Exploration and Production segment capital expenditures for the six months ended March 31, 2006 included approximately $20.8 million for Canada, $45.7 million for the Gulf Coast region ($45.5 million for the off-shore program in the Gulf of Mexico), $19.5 million for the West Coast region and $10.3 million for the Appalachian region. The significant amount spent in the Gulf Coast region is related to high commodity prices, which has improved the economics of investment in the area, plus royalty relief. These amounts included approximately $21.5 million spent to develop proved undeveloped reserves.
Timber
The majority of the Timber segment capital expenditures for the six months ended March 31, 2006 were made for purchases of equipment for Highland’s sawmill and kiln operations.
Corporate and All Other
The majority of the Corporate and All Other capital expenditures for the six months ended March 31, 2006 were for the construction of a distributed generation facility at the Company’s corporate headquarters.
The Company continuously evaluates capital expenditures and investments in corporations, partnerships, and other business entities. The amounts are subject to modification for opportunities such as the acquisition of attractive oil and gas properties, timber or natural gas storage facilities and the expansion of transmission line capacities. While the majority of capital expenditures in the Utility segment are necessitated by the continued need for replacement and upgrading of mains and service lines, the magnitude of future capital expenditures or other investments in the Company’s other business segments depends, to a large degree, upon market conditions.*
The Company did not have any outstanding short-term notes payable to banks or commercial paper at March 31, 2006. However, the Company continues to consider short-term debt (consisting of short-term notes payable to banks and commercial paper) an important source of cash for temporarily financing capital expenditures and investments in corporations and/or partnerships, gas-in-storage inventory, unrecovered purchased gas costs, margin calls on derivative financial instruments, exploration and development expenditures and other working capital needs. Fluctuations in these items can have a significant impact on the amount and timing of short-term debt. As for bank loans, the Company maintains a number of individual (bi-lateral) uncommitted or discretionary lines of credit with certain financial institutions for general corporate purposes. Borrowings under these lines of credit are made at competitive market rates. Each of these credit lines, which aggregate to $445.0 million, are revocable at the option of the financial institutions and are reviewed on an annual basis. The Company anticipates that these lines of credit will continue to be renewed.* The total amount available to be issued under the Company’s commercial paper program is $200.0 million. The commercial paper program is backed by a syndicated committed credit facility which totals $300.0 million and extends through September 30, 2010. The Company plans to increase the size of its commercial paper program from $200.0 million to $300.0 million.*
Under the Company’s committed credit facility, the Company has agreed that its debt to capitalization ratio will not exceed .65 at the last day of any fiscal quarter from September 30, 2005 through September 30, 2010. At March 31, 2006, the Company’s debt to capitalization ratio (as calculated under the facility) was .45. The constraints specified in the committed credit facility would permit an additional $1.44 billion in short-term and/or long-term debt to be outstanding before the Company’s debt to capitalization ratio would exceed .65. If a downgrade in any of the Company’s credit ratings were to occur, access to the commercial paper markets might not be possible.* However, the Company expects that it could borrow under its uncommitted bank lines of credit or rely upon other liquidity sources, including cash provided by operations.*
35
Under the Company’s existing indenture covenants, at March 31, 2006, the Company would have been permitted to issue up to a maximum of $926.0 million in additional long-term unsecured indebtedness at then-current market interest rates in addition to being able to issue new indebtedness to replace maturing debt. The Company’s present liquidity position is believed to be adequate to satisfy known demands.*
The Company’s 1974 indenture pursuant to which $399.0 million (or 36%) of the Company’s long-term debt (as of March 31, 2006) was issued, contains a cross-default provision whereby the failure by the Company to perform certain obligations under other borrowing arrangements could trigger an obligation to repay the debt outstanding under the indenture. In particular, a repayment obligation could be triggered if the Company fails (i) to pay any scheduled principal or interest on any debt under any other indenture or agreement or (ii) to perform any other term in any other such indenture or agreement, and the effect of the failure causes, or would permit the holders of the debt to cause, the debt under such indenture or agreement to become due prior to its stated maturity, unless cured or waived.
The Company’s $300.0 million committed credit facility also contains a cross-default provision whereby the failure by the Company or its significant subsidiaries to make payments under other borrowing arrangements, or the occurrence of certain events affecting those other borrowing arrangements, could trigger an obligation to repay any amounts outstanding under the committed credit facility. In particular, a repayment obligation could be triggered if (i) the Company or its significant subsidiaries fail to make a payment when due of any principal or interest on any other indebtedness aggregating $20.0 million or more or (ii) an event occurs that causes, or would permit the holders of any other indebtedness aggregating $20.0 million or more to cause, such indebtedness to become due prior to its stated maturity. As of March 31, 2006, the Company had no debt outstanding under the committed credit facility.
The Company has an effective registration statement on file with the SEC under which it has available capacity to issue an additional $550.0 million of debt and equity securities under the Securities Act of 1933. The Company may sell all or a portion of the remaining registered securities if warranted by market conditions and the Company’s capital requirements. Any offer and sale of the above mentioned $550.0 million of debt and equity securities will be made only by means of a prospectus meeting the requirements of the Securities Act of 1933 and the rules and regulations thereunder.
The amounts and timing of the issuance and sale of debt or equity securities will depend on market conditions, indenture requirements, regulatory authorizations and the capital requirements of the Company.
On December 8, 2005, the Company’s board of directors authorized the Company to implement a share repurchase program, whereby the Company may repurchase outstanding shares of common stock, up to an aggregate amount of 8 million shares in the open market or through privately negotiated transactions. For the quarter ended March 31, 2006, the Company repurchased 825,250 shares under this program, funded with cash provided by operating activities. In the future, it is expected that this share repurchase program will continue to be funded with cash provided by operating activities and/or through the use of the Company’s bi-lateral lines of credit.* It is expected that open market repurchases will continue from time to time depending on market conditions.*
The Company has entered into certain off-balance sheet financing arrangements. These financing arrangements are primarily operating and capital leases. The Company’s consolidated subsidiaries have operating leases, the majority of which are with the Utility and the Pipeline and Storage segments, having a remaining lease commitment of approximately $46.5 million. These leases have been entered into for the use of buildings, vehicles, construction tools, meters, computer equipment and other items and are accounted for as operating leases. The Company’s unconsolidated subsidiaries, which are accounted for under the equity method, have capital leases of electric generating equipment having a remaining lease commitment of approximately $8.0 million. The Company has guaranteed 50% or $4.0 million of these capital lease commitments.
36
In addition to the legal proceedings disclosed in Part II, Item 1 of this report, the Company is involved in other litigation and regulatory matters arising in the normal course of business. These other matters may include, for example, negligence claims and tax, regulatory or other governmental audits, inspections, investigations or other proceedings. These matters may involve state and federal taxes, safety, compliance with regulations, rate base, cost of service and purchased gas cost issues, among other things. While these normal-course matters could have a material effect on earnings and cash flows in the quarterly and annual period in which they are resolved, they are not expected to change materially the Company’s present liquidity position, nor to have a material adverse effect on the financial condition of the Company.*
For a complete discussion of market risk sensitive instruments, refer to “Market Risk Sensitive Instruments” in Item 7 of the Company’s 2005 Form 10-K. There have been no subsequent material changes to the Company’s exposure to market risk sensitive instruments.
On August 8, 2005, President Bush signed into law the Energy Policy Act, which, among other things, repealed PUHCA 1935 effective February 8, 2006. With repeal of PUHCA 1935, the Company is no longer subject to that act’s broad regulatory provisions, including provisions relating to the issuance of securities, sales and acquisitions of securities and utility assets, intra-company transactions and limitations on diversification. The Energy Policy Act includes PUHCA 2005, which, among other things, grants the FERC and state public utility regulatory commissions access to certain books and records of companies in holding company systems, provides (upon request of a state commission or holding company system) for FERC review of allocations of costs of non-power goods and administrative services in electric utility holding company systems, and modifies the jurisdiction of FERC over certain mergers and acquisitions involving public utilities or holding companies. On December 8, 2005, the FERC issued Order 667 to implement PUHCA 2005. The FERC clarified certain aspects of Order 667 in Order 667-A, issued on April 24, 2006. The Company will file a “notification of holding company status” with the FERC under Order 667-A. The Company also plans to file an “exemption notification” with the FERC, seeking exemption from the requirements of PUHCA 2005 and Order 667-A for certain subsidiaries of the Company. The Company is unable to predict at this time what the ultimate outcome of these or future legislative or regulatory changes will be.
Base rate adjustments in both the New York and Pennsylvania jurisdictions do not reflect the recovery of purchased gas costs. Such costs are recovered through operation of the purchased gas adjustment clauses of the appropriate regulatory authorities.
On August 27, 2004, Distribution Corporation commenced a rate case by filing proposed tariff amendments and supporting testimony requesting approval to increase its annual revenues beginning October 1, 2004. Various parties opposed the filing. On April 15, 2005, Distribution Corporation, the parties and others executed an agreement settling all outstanding issues. In an order issued July 22, 2005, the NYPSC, approved the April 15, 2005 settlement agreement, substantially as filed, for an effective date of August 1, 2005. The settlement agreement provides for a rate increase of $21 million by means of the elimination of bill credits ($5.8 million) and an increase in base rates ($15.2 million). For the two-year term of the agreement and thereafter, the return on equity level above which earnings must be shared with rate payers will be 11.5%.
37
On September 15, 2004, Distribution Corporation filed proposed tariff amendments with PaPUC to increase annual revenues by $22.8 million to cover increases in the cost of service to be effective November 14, 2004. The rate request was filed to address throughput reductions and increased operating costs such as uncollectibles and personnel expenses. Applying standard procedure, the PaPUC suspended Distribution Corporation’s tariff filing to perform an investigation and hold hearings. On February 16, 2005, the parties reached a settlement of all issues. The settlement provides for a base rate increase of $12.0 million and terminates the tracking of pension expenses versus the rate allowance. The settlement was approved by PaPUC on March 23, 2005, and the new rates went into effect on April 15, 2005.
On April 7, 2006, the NYPSC, PaPUC and Pennsylvania Office of Consumer Advocate filed a complaint and a motion for summary disposition against Supply Corporation with the FERC under Sections 5(a) and 13 of the Natural Gas Act. The complainants allege that Supply Corporation’s rates are unjust and unreasonable, and that Supply Corporation is permitted to retain more gas from shippers than is necessary for fuel and loss. As a result, the complainants allege, Supply Corporation has excess annual earnings of approximately $30 million to $35 million. In their complaint, the complainants ask FERC (i) to find that Supply Corporation’s rates are unjust and unreasonable, and (ii) to institute proceedings to determine the just and reasonable rates Supply Corporation will be authorized to charge prospectively. The complainants also ask FERC in their complaint (i) to determine whether Supply Corporation has the authority to make sales of gas retained from shippers, and (ii) if FERC concludes that Supply Corporation does not have such authority, to direct Supply Corporation to show cause why it should not be required to disgorge profits associated with such sales. In their motion for summary disposition, the complainants ask FERC (i) to find summarily that the rate at which Supply Corporation is permitted to retain gas from shippers for fuel and loss is unjust and unreasonable, (ii) to require Supply Corporation to make a compliance filing providing detailed information regarding its fuel and loss retention and use, and (iii) to establish just and reasonable fuel and loss percentages for Supply Corporation. Supply Corporation filed answers on April 27, 2006, opposing the complaint and the motion for summary disposition, asserting that its current rates are just and reasonable, and documenting its authority to sell retained gas. Supply Corporation will vigorously oppose these actions.*
On November 25, 2003, the FERC issued Order 2004. Order 2004 was clarified in Order 2004-A on April 16, 2004 and Order 2004-B on August 2, 2004. Order 2004, which went into effect September 22, 2004, regulates the conduct of transmission providers (such as Supply Corporation) with their “energy affiliates.” The FERC broadened the definition of “energy affiliates” to include any affiliate of a transmission provider if that affiliate engages in or is involved in transmission (gas or electric) transactions, or manages or controls transmission capacity, or buys, sells, trades or administers natural gas or electric energy or engages in financial transactions relating to the sale or transmission of natural gas or electricity. Supply Corporation’s principal energy affiliates are Seneca, NFR and, possibly, Distribution Corporation.* Order 2004 provides that companies may request waivers, which the Company has done with respect to Distribution Corporation and is awaiting rulings. Order 2004 also provides an exemption for local distribution companies that are affiliated with interstate pipelines (such as Distribution Corporation), but the exemption is limited, with very minor exceptions, to local distribution corporations that do not make any off-system sales. Distribution Corporation stopped making such off-system sales effective September 22, 2004, although it continues to make certain sales permitted by a prior FERC order; FERC has required Supply Corporation to provide arguments justifying the continued effectiveness of that order. Supply Corporation and Distribution Corporation would like to continue operating as they do, whether by waiver, amendment or further clarification of the new rules, or by complying with the requirements applicable if Distribution Corporation were an energy affiliate. Treating Distribution Corporation as an energy affiliate, without any waivers, would require changes in the way Supply Corporation and Distribution Corporation operate which would decrease efficiency, but probably would not increase capital or operating expenses to an extent that would be material to the financial condition of the Company.* Until there is further clarification from the FERC on the scope of these exemptions and rulings on the Company’s waiver requests, the Company is unable to predict the impact Order 2004 will have on the Company. As previously mentioned, Distribution Corporation stopped making off-system sales,
38
effective September 22, 2004. The Company does not expect that change to have a material effect on the Company’s results of operations, as margins resulting from off-system sales are minimal as a result of profit sharing with retail customers.*
Empire currently does not have a rate case on file with the NYPSC. Management will continue to monitor its financial position in the New York jurisdiction to determine the necessity of filing a rate case in the future. Among the issues that will be resolved in connection with Empire’s FERC application to build the Empire Connector are the rates and terms of service that would become applicable to all of Empire’s business, effective upon Empire accepting the FERC certificate and placing its new facilities into service (currently targeted for November 2007), when Empire would become an interstate pipeline subject to FERC regulation.*
The Company is subject to various federal, state and local laws and regulations relating to the protection of the environment. The Company has established procedures for the ongoing evaluation of its operations to identify potential environmental exposures and comply with regulatory policies and procedures. It is the Company’s policy to accrue estimated environmental clean-up costs (investigation and remediation) when such amounts can reasonably be estimated and it is probable that the Company will be required to incur such costs. The Company has estimated its remaining clean-up costs related to former manufactured gas plant sites and third party waste disposal sites will be $3.9 million.* This liability has been recorded on the Consolidated Balance Sheet at March 31, 2006. The Company expects to recover its environmental clean-up costs from a combination of rate recovery and insurance proceeds.* Other than as discussed in Note G of the Company’s 2005 Form 10-K (referred to below), the Company is currently not aware of any material additional exposure to environmental liabilities. However, adverse changes in environmental regulations or other factors could impact the Company.*
For further discussion refer to Note G — Commitments and Contingencies under the heading “Environmental Matters” in Item 8 of the Company’s 2005 Form 10-K, and to Part II, Item 1, “Legal Proceedings.”
In March 2005, the FASB issued FIN 47, an interpretation of SFAS 143. FIN 47 provides additional guidance on the term “conditional asset retirement obligation” as used in SFAS 143, and in particular the standard clarifies when a Company must record a liability for a conditional asset retirement obligation. The Company is currently evaluating the impact of FIN 47, if any, on its consolidated financial statements. For further discussion of FIN 47 and its impact on the Company, refer to Item 1 at Note 1 — Summary of Significant Accounting Policies.
In May 2005, the FASB issued SFAS 154. SFAS 154 replaces APB 20 and SFAS 3 and changes the requirements for the accounting for and reporting of a change in accounting principle. The Company’s financial condition and results of operations will only be impacted by SFAS 154 if there are any accounting changes or corrections of errors in the future. For further discussion of SFAS 154 and its impact on the Company, refer to Item 1 at Note 1 – Summary of Significant Accounting Policies.
The Company is including the following cautionary statement in this Form 10-Q to make applicable and take advantage of the safe harbor provisions of the Private Securities Litigation Reform Act of 1995 for any forward-looking statements made by, or on behalf of, the Company. Forward-looking statements include statements concerning plans, objectives, goals, projections, strategies, future events or performance, and underlying assumptions and other statements 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 in this report, including, without limitation, those which are designated with an asterisk (“*”) and those which are identified by the use of the words “anticipates,”
39
“estimates,” “expects,” “intends,” “plans,” “predicts,” “projects,” and similar expressions, are “forward-looking” statements as defined in the Private Securities Litigation Reform Act of 1995 and accordingly involve risks and uncertainties which could cause actual results or outcomes to differ materially from those expressed in the forward-looking statements. The forward-looking statements contained herein are based on various assumptions, many of which are based, in turn, upon further assumptions. The Company’s expectations, beliefs and projections are expressed in good faith and are believed by the Company to have a reasonable basis, including, without limitation, management’s examination of historical operating trends, data contained in the Company’s records and other data available from third parties, but there can be no assurance that management’s expectations, beliefs or projections will result or be achieved or accomplished. In addition to other factors and matters discussed elsewhere herein, the following are important factors that, in the view of the Company, could cause actual results to differ materially from those discussed in the forward-looking statements:
40
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations (Cont.)
The Company disclaims any obligation to update any forward-looking statements to reflect events or circumstances after the date hereof.
Refer to the “Market Risk Sensitive Instruments” section in Item 2 – MD&A.
The term “disclosure controls and procedures” is defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act. These rules refer to the controls and other procedures of a company that are designed to ensure that information required to be disclosed by a company in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed is accumulated and communicated to the company’s management, including its principal executive and principal financial officers, as appropriate to allow timely decisions regarding required disclosure. The Company’s management, including the Chief Executive Officer and Principal Financial Officer, evaluated the effectiveness of the Company’s disclosure controls and procedures as of the end of the period covered by this report. Based upon that evaluation, the Company’s Chief Executive Officer and Principal Financial Officer concluded that the Company’s disclosure controls and procedures were effective as of the end of the period covered by this report.
41
The management of the Company maintains a system of internal control over financial reporting that is designed to provide reasonable assurance regarding the reliability of financial reporting and preparation of financial statements for external purposes in accordance with GAAP. There were no changes in the Company’s internal control over financial reporting that occurred during the quarter ended March 31, 2006 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.
In an action instituted in the New York State Supreme Court, Kings County on February 18, 2003 against Distribution Corporation and Paul J. Hissin, an unaffiliated third party, plaintiff Donna Fordham-Coleman, as administratrix of the estate of Velma Arlene Fordham, alleges that Distribution Corporation’s denial of natural gas service in November 2000 to the plaintiff’s decedent, Velma Arlene Fordham, caused decedent’s death in February 2001. The plaintiff seeks damages for wrongful death and pain and suffering, plus punitive damages. Distribution Corporation denied plaintiff’s material allegations, asserted seven affirmative defenses and asserted a cross-claim against the co-defendant. Distribution Corporation believes, and has vigorously asserted, that plaintiff’s allegations lack merit. The Court changed venue of the action to New York State Supreme Court, Erie County. Discovery closed in October 2005, and Distribution Corporation filed a motion for summary judgment in November 2005. On February 24, 2006, the Court granted Distribution Corporation’s motion for summary judgment dismissing plaintiff’s claims for wrongful death and punitive damages. The Court denied Distribution Corporation’s motion for summary judgment to dismiss plaintiff’s negligence claim seeking recovery for conscious pain and suffering. On March 15, 2006, the plaintiff appealed the Court’s decision to the New York State Supreme Court, Appellate Division, Fourth Department. On March 29, 2006, Distribution Corporation filed a cross-appeal.
On December 22, 2003, the Pennsylvania Department of Environmental Protection (DEP) issued an order to Seneca to halt its timber harvesting operations on 21,000 acres in Cameron, Elk and McKean counties in Pennsylvania. The order asserted certain violations of DEP regulations concerning erosion, sedimentation and stream crossings. The order required Seneca to apply for certain permits, control erosion, submit plans for removal of water encroachments not included in permit applications, notify the DEP of additional current or planned timber harvesting operations, and grant the DEP access to timber acreage. On January 9, 2004, Seneca filed with the Pennsylvania Environmental Hearing Board (Hearing Board) a notice of appeal, objecting to each finding and order contained in the order, and asserting that the DEP’s findings were factually incorrect, an arbitrary exercise of the DEP’s functions and duties, and contrary to law. Also on January 9, 2004, Seneca filed with the Hearing Board a petition requesting a stay of operation of portions of the order. On January 16, 2004, the parties settled Seneca’s request for a stay. Seneca resumed its timber harvesting operations pursuant to the terms of the settlement. The settlement of Seneca’s request for a stay preserved various issues raised by the DEP’s order for a hearing on the merits of Seneca’s notice of appeal. The most substantial issue was whether Seneca is required to apply for a permit under Section 102.5(b) of Title 25 of the Pennsylvania Code, governing earth disturbance activities of greater than 25 acres. Seneca maintained that no permit is required because each of its individual logging sites disturbs less than 25 acres, and the law does not require aggregation of individual sites.
Seneca and the DEP have agreed to a final settlement of this matter. The final settlement provides in part that Seneca will submit to the DEP an Erosion and Sedimentation Control Plan (“E&S Plan”) for each individual earth disturbance activity for which such a plan is required by Section 102.4 of Title 25 of the Pennsylvania Code. Generally, Seneca may proceed with any earth disturbance activity provided it has submitted a written E&S Plan to the DEP 15 business days prior to commencement of the proposed activity. Seneca is not required to apply for a permit under Section 102.5(b) of Title 25 of the Pennsylvania Code, governing earth disturbance activities of greater than 25 acres. Finally, under the terms of the final settlement, Seneca will pay a total of $9,000 in civil penalties and damages.
On April 7, 2006, the NYPSC, PaPUC and Pennsylvania Office of Consumer Advocate filed a complaint against Supply Corporation with the FERC under Section 5(a) of the Natural Gas Act and a
42
Item 1. Legal Proceedings (Concl.)
motion for summary disposition against Supply Corporation under Section 13 of the Natural Gas Act. For a discussion of these matters, refer to Part I, Item 2 — MD&A of this report under the heading “Other Matters — Rate and Regulatory Matters.”
The Company believes, based on the information presently known, that the ultimate resolution of the Fordham case will not be material to the consolidated financial condition, results of operations, or cash flow of the Company.* No assurances can be given, however, as to the ultimate outcome of this matter, and it is possible that the outcome could be material to results of operations or cash flow for a particular quarter or annual period.* In addition, regarding the complaint filed against Supply Corporation at FERC, the Company believes that chances are remote that the complainants will succeed in challenging the authority of Supply Corporation to sell retained gas.* Nevertheless, the resolution of the complaint and the motion for summary disposition filed at FERC could have a material effect on the Company’s financial condition, results of operations or cash flow.*
For a discussion of various environmental and other matters, refer to Part I, Item 1 at Note 4 and Part I, Item 2 — MD&A of this report under the heading “Other Matters — Environmental Matters.”
In addition to the proceedings disclosed above, the Company is involved in other litigation and regulatory matters arising in the normal course of business. These other matters may include, for example, negligence claims and tax, regulatory or other governmental audits, inspections, investigations or other proceedings. These matters may involve state and federal taxes, safety, compliance with regulations, rate base, cost of service, and purchased gas cost issues, among other things. While these normal-course matters could have a material effect on earnings and cash flows in the quarterly and annual period in which they are resolved, they are not expected to change materially the Company’s present liquidity position, nor to have a material adverse effect on the financial condition of the Company.*
The risk factors in Item 1A of the Company’s 2005 Form 10-K have not materially changed other than as set forth below. The information presented below updates and should be read in conjunction with the risk factors disclosed in that Form 10-K.
The nature of National Fuel’s operations presents inherent risks of loss that could adversely affect its results of operations, financial condition and cash flows.
National Fuel’s operations are subject to inherent hazards and risks such as: fires; natural disasters; explosions; formations with abnormal pressures; blowouts; collapses of wellbore casing or other tubulars; pipeline ruptures; spills; and other hazards and risks that may cause personal injury, death, property damage, environmental damage or business interruption losses. Additionally, National Fuel’s facilities, machinery, and equipment may be subject to sabotage. Any of these events could cause a loss of hydrocarbons, environmental pollution, personal injury or death claims, damage to National Fuel’s properties or damage to the properties of others. As protection against operational hazards, National Fuel maintains insurance coverage against some, but not all, potential losses. In addition, many of the agreements that National Fuel executes with contractors provide for the division of responsibilities between the contractor and National Fuel, and National Fuel seeks to obtain an indemnification from the contractor for certain of these risks. National Fuel is not always able, however, to secure written agreements with its contractors that contain indemnification, and sometimes National Fuel is required to indemnify others.
Insurance or indemnification agreements when obtained may not adequately protect National Fuel against liability from all of the consequences of the hazards described above. The occurrence of an event not fully insured or indemnified against, the failure of a contractor to meet its indemnification obligations, or the failure of an insurance company to pay valid claims could result in substantial losses to National Fuel. In addition, insurance may not be available, or if available may not be adequate, to cover any or all of these risks. It is also possible that insurance premiums or other costs may rise significantly in the future, so as to make such insurance prohibitively expensive.
43
Due to large insurance losses caused by Hurricanes Katrina and Rita, the insurance industry has significantly increased premiums for insurance on Gulf of Mexico properties, and has reduced the limits typically available for windstorm damage. As a result, National Fuel has determined that it is not economical to purchase insurance to fully cover its exposures in the Gulf of Mexico in the event of a named windstorm. National Fuel has procured named windstorm coverage in an amount equal to approximately three times the estimated physical damage loss sustained by National Fuel as a result of named windstorms during the 2005 hurricane season. No assurance can be given, however, that such amount will be sufficient to cover losses that may occur in the future.
Hazards and risks faced by National Fuel, and insurance and indemnification obtained or provided by National Fuel, may subject National Fuel to litigation or administrative proceedings from time to time. Such litigation or proceedings could result in substantial monetary judgments, fines or penalties against National Fuel or be resolved on unfavorable terms, the result of which could have a material adverse effect on National Fuel’s results of operations, financial condition and cash flows.
On January 3, 2006, the Company issued a total of 2,100 unregistered shares of Company common stock to the seven non-employee directors of the Company serving on the Board of Directors, 300 shares to each such director. All of these unregistered shares were issued as partial consideration for the directors’ services during the quarter ended March 31, 2006, pursuant to the Company’s Retainer Policy for Non-Employee Directors. These transactions were exempt from registration by Section 4(2) of the Securities Act of 1933 as transactions not involving a public offering.
Issuer Purchases of Equity Securities- ------------------------- ---------------------- ----------------------- ---------------------- ---------------------- Total Number of Maximum Number Shares Purchased as of Shares that May Part of Publicly Yet Be Purchased Announced Share Under Share Total Number of Average Price Paid Repurchase Plans or Repurchase Plans Period Shares Purchased(a) per Share Programs or Programs(b) - ------------------------- ---------------------- ----------------------- ---------------------- ---------------------- Jan. 1 - 31, 2006 10,169 $32.88 - 8,000,000 - ------------------------- ---------------------- ----------------------- ---------------------- ---------------------- Feb. 1 - 28, 2006 125,353 $32.20 115,800 7,884,200 - ------------------------- ---------------------- ----------------------- ---------------------- ---------------------- Mar. 1 - 31, 2006 806,157 $32.23 709,450 7,174,750 - ------------------------- ---------------------- ----------------------- ---------------------- ---------------------- Total 941,679 $32.23 825,250 7,174,750 - ------------------------- ---------------------- ----------------------- ---------------------- ----------------------
(a) Represents (i) shares of common stock of the Company purchased on the open market with Company “matching contributions” for the accounts of participants in the Company’s 401(k) plans, (ii) shares of common stock of the Company tendered to the Company by holders of stock options or shares of restricted stock for the payment of option exercise prices or applicable withholding taxes, and (iii) shares of common stock of the Company purchased on the open market pursuant to the Company’s share repurchase program. Shares purchased other than through a publicly announced share repurchase program totaled 10,169 in January 2006, 9,553 in February 2006 and 96,707 in March 2006. Of the shares purchased other than through a publicly announced share repurchase program mentioned in the previous sentence, 31,023 shares were purchased for the Company’s 401(k) plans and 85,406 shares were purchased as a result of shares tendered to the Company by holders of stock options or shares of restricted stock.
(b) On December 8, 2005, the Company’s Board of Directors authorized the repurchase of up to eight million shares of the Company’s common stock. Repurchases may be made from time to time in the open market or through private transactions.
44
The Annual Meeting of Shareholders of National Fuel Gas Company was held on February 16, 2006. At that meeting, the shareholders elected directors, appointed an independent registered public accounting firm, and rejected a shareholder proposal to reduce the compensation of the Company’s non-employee directors.
The total votes were as follows: For Withheld --- -------- (i) Election of directors to serve for a three-year term: - R. Don Cash 73,088,520 1,893,863 - George L. Mazanec 73,062,016 1,920,367 Election of directors to serve for a two-year term: - John F. Riordan 73,617,335 1,365,048 Other directors whose term of office continued after the meeting: Term expiring in 2007: Philip C. Ackerman, Craig G. Matthews, and Richard G. Reiten. Term expiring in 2008: Robert T. Brady and Rolland E. Kidder. Broker For Against Abstain Non-Votes --- ------- ------- --------- (ii) Appointment of PricewaterhouseCoopers LLP as independent registered public accounting firm 73,389,799 1,268,463 324,121 - (iii) Adoption of shareholder proposal to reduce the compensation of non- employee directors 5,198,024 48,371,311 1,946,254 19,466,794
Exhibit Number Description of Exhibit ------- ---------------------- 10.1 Description of bonuses awarded to executive officer. 10.2 Description of performance goals for certain executive officers. 10.3 Noncompete and Restrictive Covenant Agreement, dated February 1, 2006, between the Company and Dennis J. Seeley. 10.4 Description of salaries of certain executive officers. 12 Statements regarding Computation of Ratios:
45
Ratio of Earnings to Fixed Charges for the Twelve Months Ended March 31, 2006 and the Fiscal Years Ended September 30, 2001 through 2005. 31.1 Written statements of Chief Executive Officer pursuant to Rule 13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act of 1934. 31.2 Written statements of Principal Financial Officer pursuant to Rule 13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act of 1934. 32 Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. 99 National Fuel Gas Company Consolidated Statement of Income for the Twelve Months Ended March 31, 2006 and 2005.
46
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/R. J. TanskiR. J. Tanski Treasurer and Principal Financial Officer/s/K. M. CamioloK. M. Camiolo Controller and Principal Accounting Officer
Date: May 5, 2006
47
EXHIBIT INDEX(Form 10-Q)
Exhibit 10.1 Description of bonuses awarded to executive officer. Exhibit 10.2 Description of performance goals for certain executive officers. Exhibit 10.3 Noncomplete and Restrictive Covenant Agreement, dated February 1, 2006, between the Company and Dennis J. Seeley Exhibit 10.4 Description of salaries of certain executive officers. Exhibit 12 Statements regarding Computation of Ratios: Ratio of Earnings to Fixed Charges for the Twelve Months Ended March 31, 2006 and the Fiscal Years Ended September 30, 2001 through 2005. Exhibit 31.1 Written statements of Chief Executive Officer pursuant to Rule 13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act of 1934. Exhibit 31.2 Written statements of Principal Financial Officer pursuant to Rule 13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act of 1934. Exhibit 32 Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. Exhibit 99 National Fuel Gas Company Consolidated Statements of Income for the Twelve Months Ended March 31, 2006 and 2005.