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 December 31, 2005
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 January 31, 2006: 84,509,054shares.
1
Frequently used abbreviations or acronyms used in this report:National Fuel Gas CompaniesData-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 Seneca Seneca Resources Corporation Seneca Energy Seneca Energy II, LLC Supply Corporation National Fuel Gas Supply Corporation The Company The Registrant, the Registrant and its subsidiaries or the Registrant's subsidiaries as appropriate in the context of the disclosure 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. 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 (a price, interest rate, index rate, exchange rate, or other variable) and 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
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, as amended 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 An order issued by FERC 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, as amended 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 pipelines separate (or "unbundled") 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
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 the cost of only 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 December 31, (Thousands of Dollars, Except Per Common Share Amounts) 2005 2004 ----------------- ----------------- INCOMEOperating Revenues $710,756 $500,283 - -------------------------------------------------------------------------------- ----------------- -----------------Operating ExpensesPurchased Gas 436,778 256,156 Operation and Maintenance 103,628 92,623 Property, Franchise and Other Taxes 17,181 17,056 Depreciation, Depletion and Amortization 43,046 42,709 - -------------------------------------------------------------------------------- ----------------- ----------------- 600,633 408,544 - -------------------------------------------------------------------------------- ----------------- -----------------Operating Income 110,123 91,739Other Income (Expense):Income from Unconsolidated Subsidiaries 1,264 785 Interest Income 1,134 272 Other Income 741 552 Interest Expense on Long-Term Debt (18,218) (18,376) Other Interest Expense (1,775) (2,417) - -------------------------------------------------------------------------------- ----------------- -----------------Income from Continuing Operations Before Income Taxes 93,269 72,555 Income Tax Expense 35,850 27,725 - -------------------------------------------------------------------------------- ----------------- -----------------Income from Continuing Operations 57,419 44,830 - -------------------------------------------------------------------------------- ----------------- -----------------Income from Discontinued Operations, Net of Tax - 5,608 - -------------------------------------------------------------------------------- ----------------- -----------------Net Income Available for Common Stock 57,419 50,438 - -------------------------------------------------------------------------------- ----------------- ----------------- EARNINGS REINVESTED IN THE BUSINESS Balance at October 1 813,020 718,926 - -------------------------------------------------------------------------------- ----------------- ----------------- 870,439 769,364 Dividends on Common Stock (2005 - $0.29; 2004 - $0.28) 24,488 23,274 - -------------------------------------------------------------------------------- ----------------- -----------------Balance at December 31 $845,951 $746,090 ================================================================================ ================= =================Earnings Per Common Share:Basic: Income from Continuing Operations $0.68 $0.54 Income from Discontinued Operations - 0.07 - -------------------------------------------------------------------------------- ----------------- -----------------Net Income Available for Common Stock $0.68 $0.61 ================================================================================ ================= ================= Diluted: Income from Continuing Operations $0.67 $0.53 Income from Discontinued Operations - 0.07 - -------------------------------------------------------------------------------- ----------------- -----------------Net Income Available for Common Stock $0.67 $0.60 ================================================================================ ================= =================Weighted Average Common Shares Outstanding:Used in Basic Calculation 84,422,717 83,150,086 ================================================================================ ================= ================= Used in Diluted Calculation 86,256,862 84,638,106 ================================================================================ ================= =================
See Notes to Condensed Consolidated Financial Statements
6
National Fuel Gas CompanyConsolidated Balance Sheets(Unaudited)December 31, September 30, 2005 2005 -------------------- ------------------- (Thousands of Dollars) ASSETSProperty, Plant and Equipment $4,471,581 $4,423,255 Less - Accumulated Depreciation, Depletion and Amortization 1,602,254 1,583,955 - ---------------------------------------------------------------------------- -------------------- ------------------- 2,869,327 2,839,300 - ---------------------------------------------------------------------------- -------------------- -------------------Current AssetsCash and Temporary Cash Investments 64,464 57,607 Hedging Collateral Deposits 38,691 77,784 Receivables - Net of Allowance for Uncollectible Accounts of $33,279 and $26,940, Respectively 289,229 155,064 Unbilled Utility Revenue 97,932 20,465 Gas Stored Underground 60,040 64,529 Materials and Supplies - at average cost 32,063 33,267 Unrecovered Purchased Gas Costs 28,552 14,817 Prepayments and Other Current Assets 53,697 65,469 Deferred Income Taxes 47,635 83,774 Fair Value of Derivative Financial Instruments 797 - - ---------------------------------------------------------------------------- -------------------- ------------------- 713,100 572,776 - ---------------------------------------------------------------------------- -------------------- -------------------Other AssetsRecoverable Future Taxes 85,000 85,000 Unamortized Debt Expense 17,025 17,567 Other Regulatory Assets 50,790 47,028 Deferred Charges 3,864 4,474 Other Investments 82,336 80,394 Investments in Unconsolidated Subsidiaries 10,771 12,658 Goodwill 5,476 5,476 Intangible Assets 41,637 42,302 Other 10,609 15,677 - ---------------------------------------------------------------------------- -------------------- ------------------- 307,508 310,576 - ---------------------------------------------------------------------------- -------------------- -------------------Total Asset $3,889,935 $3,722,652 ============================================================================ ==================== ===================
7
National Fuel Gas CompanyConsolidated Balance Sheets(Unaudited)December 31, September 30, 2005 2005 -------------------- ------------------- (Thousands of Dollars) CAPITALIZATION AND LIABILITIESCapitalization:Comprehensive Shareholders' EquityCommon Stock, $1 Par Value Authorized - 200,000,000 Shares; Issued And Outstanding - 84,498,511 Shares And 84,356,748 Shares, Respectively $ 84,499 $ 84,357 Paid in Capital 538,907 529,834 Earnings Reinvested in the Business 845,951 813,020 - ---------------------------------------------------------------------------- -------------------- ------------------- Total Common Shareholder Equity Before Items of Other Comprehensive Loss 1,469,357 1,427,211 Accumulated Other Comprehensive Loss (148,064) (197,628) - ---------------------------------------------------------------------------- -------------------- -------------------Total Comprehensive Shareholders' Equity 1,321,293 1,229,583Long-Term Debt, Net of Current Portion 1,116,779 1,119,012 - ---------------------------------------------------------------------------- -------------------- -------------------Total Capitalization 2,438,072 2,348,595 - ---------------------------------------------------------------------------- -------------------- -------------------Current and Accrued LiabilitiesNotes Payable to Banks and Commercial Paper 74,800 - Current Portion of Long-Term Debt 9,516 9,393 Accounts Payable 212,067 155,485 Amounts Payable to Customers 1,031 1,158 Dividends Payable 24,488 24,445 Other Accruals and Current Liabilities 58,788 60,404 Fair Value of Derivative Financial Instruments 127,428 209,072 - ---------------------------------------------------------------------------- -------------------- ------------------- 508,118 459,957 - ---------------------------------------------------------------------------- -------------------- -------------------Deferred CreditsDeferred Income Taxes 500,982 489,720 Taxes Refundable to Customers 11,066 11,009 Unamortized Investment Tax Credit 6,621 6,796 Cost of Removal Regulatory Liability 91,724 90,396 Other Regulatory Liabilities 64,360 66,339 Pension and Other Post-Retirement Benefit Liabilities 153,242 143,687 Asset Retirement Obligation 41,647 41,411 Other Deferred Credits 74,103 64,742 - ---------------------------------------------------------------------------- -------------------- ------------------- 943,745 914,100 - ---------------------------------------------------------------------------- -------------------- -------------------Commitments and Contingencies - - - ---------------------------------------------------------------------------- -------------------- -------------------Total Capitalization and Liabilities $3,889,935 $3,722,652 ============================================================================ ==================== ===================
8
National Fuel Gas CompanyConsolidated Statements of Cash FlowsUnaudited)Three Months Ended December 31, ----------------------------------------- (Thousands of Dollars) 2005 2004 ------------------- ---------------------OPERATING ACTIVITIESNet Income Available for Common Stock $57,419 $50,438 Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities: Depreciation, Depletion and Amortization 43,046 46,940 Deferred Income Taxes 16,653 (1,864) Income from Unconsolidated Subsidiaries, Net of Cash Distributions 1,887 715 Minority Interest in Foreign Subsidiaries - 937 Excess Tax Benefits Associated with Stock-Based Compensation Awards (6,439) - Other 3,159 2,684 Change in: Hedging Collateral Deposits 39,093 973 Receivables and Unbilled Utility Revenue (211,491) (132,963) Gas Stored Underground and Materials and Supplies 5,692 12,824 Unrecovered Purchased Gas Costs (13,735) 636 Prepayments and Other Current Assets 17,075 6,946 Accounts Payable 56,580 43,950 Amounts Payable to Customers (127) 7,640 Other Accruals and Current Liabilities (554) 14,605 Other Assets (3,083) (13,894) Other Liabilities 15,394 18,560 - ---------------------------------------------------------------------------- ------------------- ---------------------Net Cash Provided by Operating Activities 20,569 59,127 - ---------------------------------------------------------------------------- ------------------- ---------------------INVESTING ACTIVITIESCapital Expenditures (70,368) (40,022) Other (745) (1,046) - ---------------------------------------------------------------------------- ------------------- ---------------------Net Cash Used in Investing Activities (71,113) (41,068) - ---------------------------------------------------------------------------- ------------------- ---------------------FINANCING ACTIVITIESChange in Notes Payable to Banks and Commercial Paper 74,800 13,300 Excess Tax Benefits Associated with Stock-Based Compensation Awards 6,439 - Reduction of Long-Term Debt (2,110) (3,509) Dividends Paid on Common Stock (24,445) (23,210) Net Proceeds from Issuance of Common Stock 2,570 3,452 - ---------------------------------------------------------------------------- ------------------- ---------------------Net Cash Provided by (Used in) Financing Activities 57,254 (9,967) - ---------------------------------------------------------------------------- ------------------- ---------------------Effect of Exchange Rates on Cash 147 5,339 - ---------------------------------------------------------------------------- ------------------- ---------------------Net Increase in Cash and Temporary Cash Investments 6,857 13,431Cash and Temporary Cash Investments at October 1 57,607 57,541 - ---------------------------------------------------------------------------- ------------------- ---------------------Cash and Temporary Cash Investments at December 31 $64,464 $70,972 ============================================================================ =================== =====================
9
National Fuel Gas CompanyConsolidated Statements of Comprehensive Income(Unaudited)Three Months Ended December 31, ----------------------------------------- (Thousands of Dollars) 2005 2004 ------------------- --------------------- Net Income Available for Common Stock $57,419 $50,438 - ---------------------------------------------------------------------------- ------------------- --------------------- Other Comprehensive Income, Before Tax: Foreign Currency Translation Adjustment 255 30,984 Unrealized Gain on Securities Available for Sale Arising During the Period 1,142 1,129 Unrealized Gain on Derivative Financial Instruments Arising During the Period 40,997 20,102 Reclassification Adjustment for Realized Losses on Derivative Financial Instruments in Net Income 37,931 18,196 - ---------------------------------------------------------------------------- ------------------- --------------------- Other Comprehensive Income, Before Tax 80,325 70,411 - ---------------------------------------------------------------------------- ------------------- --------------------- Income Tax Expense Related to Unrealized Gain on Securities Available for Sale Arising During the Period 400 395 Income Tax Expense Related to Unrealized Gain on Derivative Financial Instruments Arising During the Period 15,776 7,727 Reclassification Adjustment for Income Tax Benefit on Realized Losses from Derivative Financial Instruments In Net Income 14,585 6,911 - ---------------------------------------------------------------------------- ------------------- --------------------- Income Taxes - Net 30,761 15,033 - ---------------------------------------------------------------------------- ------------------- --------------------- Other Comprehensive Income 49,564 55,378 - ---------------------------------------------------------------------------- ------------------- --------------------- Comprehensive Income $106,983 $105,816 ============================================================================ =================== =====================
10
National Fuel Gas Company
Notes to Condensed Consolidated Financial Statements
(Unaudited)
The preparation of the consolidated financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Reclassification. Certain prior years amounts have been reclassified to conform with current year presentation.
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 2006 consolidated financial statements will be examined by the Company’s independent accountants after the end of the fiscal year.
The earnings for the three months ended December 31, 2005 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 in those segments 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 $18.4 million at December 31, 2005, is reduced to zero by September 30 of each year 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):
11
At December 31, 2005 At September 30, 2005 -------------------- --------------------- Minimum Pension Liability Adjustment $(107,844) $(107,844) Cumulative Foreign Currency Translation Adjustment 28,264 28,009 Net Unrealized Loss on Derivative Financial Instruments (74,772) (123,339) Net Unrealized Gain on Securities Available for Sale 6,288 5,546 ---------- ---------- Accumulated Other Comprehensive Loss $(148,064) $(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 reflect 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 diluted earnings per common share, the only potentially dilutive securities the Company has outstanding are stock options. The diluted weighted average shares outstanding shown on the Consolidated Statement of Income reflects the potential dilution as a result of these stock options as determined using the Treasury Stock Method. Stock options that are antidilutive are excluded from the calculation of diluted earnings per common share. For the quarters ended December 31, 2005 and December 31, 2004, there were no stock options excluded as being antidilutive.
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. 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 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 during the quarters ended December 31, 2005 and December 31, 2004. Stock-based compensation expense for the quarters ended December 31, 2005 and December 31, 2004
12
Item 1. Financial Statements (Cont.)
totaled approximately $149,000 and $164,000, respectively, and 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 December 31, 2005 and December 31, 2004 was approximately $59,000 and $65,000, respectively. There were no capitalized stock based compensation costs during the quarters ended December 31, 2005 and December 31, 2004.
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 quarter ended December 31, 2004:
Three Months Ended December 31, 2004 ------------------- (In thousands, except per common share amounts) Net Income, Available for Common Stock, As Reported $ 50,438 Add: Stock-Based Employee Compensation Expense Included in Reported Net Income, Net of Tax 106 Deduct: Total Stock-Based Employee Compensation Expense Determined Under Fair Value Based Method for all Awards, Net of Related Tax Effects (362) ---------- $ 50,182 Pro Forma Net Income Available for Common Stock ========== Earnings Per Common Share: Basic-As Reported $ 0.61 ========== Basic-Pro Forma $ 0.60 ========== Diluted-As Reported $ 0.60 ========== Diluted-Pro Forma $ 0.59 ==========
Transactions during the quarter ended December 31, 2005 were as follows (in thousands, except option prices and years):
13
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 4.38 $ 79,699 ======= ======== ======= ========= Options Exercisable at December 31, 2005 10,669 $ 23.82 4.38 $ 78,595 ======= ======== ======== =========
The total intrinsic value of stock options exercised during the quarters ended December 31, 2005 and December 31, 2004 totaled approximately $1.9 million and $2.9 million, respectively. The amount of cash received by the Company from the exercise of such stock options was approximately $2.7 million during the quarter ended December 31, 2005 and approximately $3.7 million during the quarter ended December 31, 2004. The tax benefit realized by the Company from the exercise of such stock options during the quarters ended December 31, 2005 and December 31, 2004 was $0.9 million and $1.1 million, respectively. No stock options were granted or became fully vested during the quarters ended December 31, 2005 and December 31, 2004. As of December 31, 2005, unrecognized compensation expense related to stock options totaled approximately $0.2 million, 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:
Three Months Ended December 31, ------------------ 2005 2004 ---- ---- Risk Free Interest Rate 4.04% 4.81% Expected Life (years) 6.6 5.7 Expected Volatility 21.2% 21.9% Expected Dividend Yield (Quarterly) 1.10% 1.06%
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.
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 historical experience of the Company’s currently unvested stock option grants.
14
Transactions during the quarter ended December 31, 2005 were as follows (in thousands, except fair values):
Number of Restricted Weighted Average Share Fair Value per 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 ====== ==========
As of December 31, 2005, unrecognized compensation expense related to restricted share awards totaled approximately $0.2 million, 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, if any, 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 Statement of Income are as follows (in thousands):
15
Three Months Ended December 31, ---------------------------------------- 2005 2004 ------------------- -------------------- Operating Expenses: Current Income Taxes Federal $14,311 $23,742 State 4,814 6,525 Foreign 72 68 Deferred Income Taxes Federal 10,870 (2,182) State 1,695 (960) Foreign 4,088 532 ------------------- -------------------- 35,850 27,725 Other Income: Deferred Investment Tax Credit (174) (174) Discontinued Operations - 1,968 ------------------- -------------------- Total Income Taxes $35,676 $29,519 =================== ==================== The U.S. and foreign components of income before income taxes are as follows (in thousands): Three Months Ended December 31, ------------------- -------------------- 2005 2004 ------------------- -------------------- U.S. $79,630 $68,582 Foreign 13,465 11,375 ------------------- -------------------- $93,095 $79,957 =================== ==================== 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): Three Months Ended December 31, ---------------------------------------- 2005 2004 ------------------- -------------------- Income Tax Expense, Computed at Statutory Rate of 35% $32,583 $27,985 Increase (Reduction) in Taxes Resulting From: State Income Taxes 4,231 3,617 Foreign Tax Differential (557) (1,399) (581) (684) Miscellaneous ------------------- -------------------- Total Income Taxes $35,676 $29,519 =================== ==================== Significant components of the Company's deferred tax liabilities (assets) were as follows (in thousands):
16
At December 31, 2005 At September 30, 2005 --------------------------------- ---------------------------- Deferred Tax Liabilities: Property, Plant and Equipment $577,306 $567,850 Other 54,509 52,436 --------------------------------- ---------------------------- Total Deferred Tax Liabilities 631,815 620,286 --------------------------------- ---------------------------- Deferred Tax Assets: Minimum Pension Liability Adjustment (58,070) (58,069) Capital Loss Carryover (8,459) (9,145) Unrealized Hedging Losses (44,897) (75,657) Other (69,919) (74,346) --------------------------------- ---------------------------- (181,345) (217,217) Valuation Allowance 2,877 2,877 --------------------------------- ---------------------------- Total Deferred Tax Assets (178,468) (214,340) --------------------------------- ---------------------------- Total Net Deferred Income Taxes $453,347 $405,946 --------------------------------- ---------------------------- Presented as Follows: Net Deferred Tax Asset - Current (47,635) (83,774) Net Deferred Tax Liability - Non-Current 500,982 489,720 --------------------------------- ---------------------------- Total Net Deferred Income Taxes $453,347 $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 December 31, 2005 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 $85.0 million at December 31, 2005 and September 30, 2005.
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 $24.2 million existed at December 31, 2005, 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 three months ended December 31, 2005, the Company issued 141,763 shares of common stock under the Company’s stock option and director compensation plans.
Environmental Matters. The Company is subject to various federal, state and local laws and regulations relating to the protection of the environment. The Company has established procedures for the ongoing evaluation of its operations to identify potential environmental exposures and comply with regulatory policies and procedures. It is the Company’s policy to accrue estimated environmental clean-up costs (investigation and remediation) when such amounts can reasonably be estimated and it is probable that the Company will be required to incur such costs. At December 31, 2005, the Company has estimated its remaining clean-up costs related to former manufactured gas plant sites and third party waste disposal sites will be $3.7 million. This liability has been recorded on the Consolidated Balance Sheet at December 31, 2005. The Company expects to recover its environmental clean-up costs from a
17
combination of insurance proceeds and rate recovery. Other than as discussed in Note G of the Company’s 2005 Form 10-K, 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. The Company is involved in litigation arising in the normal course of business. Also in the normal course of business, the Company is involved in tax, regulatory and other governmental audits, inspections, investigations and other proceedings that involve state and federal taxes, safety, compliance with regulations, rate base, cost of service and purchased gas cost issues, among other things. While the resolution of such litigation or regulatory matters could have a material effect on earnings and cash flows in the quarterly and annual period of resolution, none of this litigation, and none of these regulatory matters, are expected to change materially the Company’s present liquidity position, nor have a material adverse effect on the financial condition of the Company.
On 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.:
Three Months Ended December 31,(Thousands) 2004 ------------------------- Operating Revenues $43,975 Operating Expenses 35,777 ------------------------- Operating Income 8,198 Other Income 826 Interest Expense (169) ------------------------- Income before Income Taxes and Minority Interest 8,855 Income Tax Expense 2,310 Minority Interest, Net of Taxes 937 ------------------------- Income from Discontinued Operations $5,608 =========================
The Company has five reportable segments: Utility, Pipeline and Storage, Exploration and Production, Energy Marketing, and Timber. The breakdown of the Company’s reportable segments is based upon a combination of factors including differences in products and services, regulatory environment and geographic factors.
The data presented in the tables below reflect the reportable segments and reconciliations to consolidated amounts. 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 (when 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 2005 Form 10-K. There have been no
18
material changes in the amount of assets for any operating segment from the amounts disclosed in the 2005 Form 10-K.
Quarter Ended December 31, 2005 (Thousands) - ----------------------------------------------------------------------------------------------------------------------------------- Exploration Total Corporate and Pipeline and Energy Reportable Intersegment Total Utility and Storage Production Marketing Timber Segments All Other Eliminations Consolidated - ----------------------------------------------------------------------------------------------------------------------------------- Revenue from External Customers $431,479 $34,738 $82,087 $145,560 $16,908 $710,772 $(16) $ - $710,756 Intersegment Revenues $4,121 $21,296 $ - $ - $23 $25,440 $4,527 $(29,967) $ - Segment Profit (Loss): Net Income (Loss) $21,753 $15,850 $17,435 $987 $1,464 $57,489 $570 $(640) $57,419 Quarter Ended December 31, 2004 (Thousands) - ----------------------------------------------------------------------------------------------------------------------------------- Exploration Total Corporate and Pipeline and Energy Reportable Intersegment Total Utility and Storage Production Marketing Timber Segments All Other Eliminations Consolidated - ----------------------------------------------------------------------------------------------------------------------------------- Revenue from External Customers $316,829 $32,445 $71,838 $63,494 $12,995 $497,601 $2,682 $ - $500,283 Intersegment Revenues $4,305 $20,599 $ - $ - $ - $24,904 $1,080 $(25,984) $ - Segment Profit (Loss): Income (Loss) from Continuing Operations $18,072 $12,277 $13,923 $750 $753 $45,775 $600 $(1,545) $44,830
19
The components of the Company’s intangible assets were as follows (in thousands):
At September 30, At December 31, 2005 2005 ----------- ----------------- ----------- --------------------- Gross Net Net Carrying Accumulated Carrying Carrying Amount Amortization Amount Amount ----------- ----------------- ----------- --------------------- Intangible Assets Subject to Amortization Long-Term Transportation Contracts $8,580 $(3,118) $5,462 $5,729 Long-Term Gas Purchase Contracts 31,864 (3,831) 28,033 28,431 Intangible Assets Not Subject to Amortization Retirement Plan Intangible Asset 8,142 - 8,142 8,142 ----------- ----------------- ----------- --------------------- $48,586 $(6,949) $41,637 $42,302 ----------- ----------------- ----------- --------------------- Aggregate Amortization Expense (Thousands) Three Months Ended December 31, 2005 $666 Three Months Ended December 31, 2004 $666
Amortization expense for the transportation contracts is estimated to be $0.8 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 $1.2 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 December 31,
Retirement Plan Other Post-Retirement Benefits --------------- ------------------------------ 2005 2004 2005 2004 ---- ---- ---- ---- 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) (1,528) 883 (2,684) (713) -------- -------- -------- -------- Net Periodic Benefit Cost $6,155 $5,321 $8,081 $7,455 ======== ======== ======== ========
(1) The Company’s policy is to record retirement plan and other post-retirement benefit costs in the Utility segment on a volumetric basis to reflect the fact that the Utility segment experiences higher throughput of natural gas in the winter months and lower throughput of natural gas in the summer months.
20
Employer Contributions. During the three months ended December 31, 2005, the Company contributed $1.8 million to its retirement plan and $7.8 million to its post-retirement benefit plan. In the remainder of 2006, the Company expects to contribute in the range of $13.0 million to $18.0 million to its retirement plan and to contribute in the range of $25.0 million to $32.0 million to its post-retirement benefit plan.
21
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 subsequent changes to that disclosure.
The Company’s earnings were $57.4 million for the quarter ended December 31, 2005 compared to earnings of $50.4 million for the quarter ended December 31, 2004. 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 $57.4 million for the quarter ended December 31, 2005 compared to earnings from continuing operations of $44.8 million for the quarter ended December 31, 2004. The increase in earnings from continuing operations of $12.6 million is primarily the result of higher earnings in the Utility, Pipeline and Storage, and Exploration and Production segments. 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.
Earnings (Loss) by Segment- ---------------------------------------------------------------------- ---------------- ----------------- ---------------- Increase Three Months Ended December 31 (Thousands) 2005 2004 (Decrease) - ---------------------------------------------------------------------- ---------------- ----------------- ---------------- Utility $21,753 $18,072 $3,681 Pipeline and Storage 15,850 12,277 3,573 Exploration and Production 17,435 13,923 3,512 Energy Marketing 987 750 237 Timber 1,464 753 711 - ---------------------------------------------------------------------- ---------------- ----------------- ---------------- Total Reportable Segments 57,489 45,775 11,714 All Other 570 600 (30) Corporate (1) (640) (1,545) 905 - ---------------------------------------------------------------------- ---------------- ----------------- ---------------- Total Earnings from Continuing Operations 57,419 44,830 12,589 - ---------------------------------------------------------------------- ---------------- ----------------- ---------------- Earnings from Discontinued Operations - 5,608 (5,608) - ---------------------------------------------------------------------- ---------------- ----------------- ---------------- Total Consolidated $57,419 $50,438 $6,981 - ---------------------------------------------------------------------- ---------------- ----------------- ----------------
(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- ---------------------------------------------------------------------- ---------------- ----------------- ---------------- Increase Three Months Ended December 31 (Thousands) 2005 2004 (Decrease) - ---------------------------------------------------------------------- ---------------- ----------------- ---------------- Retail Sales Revenues: Residential $344,873 $255,066 $89,807 Commercial 56,890 41,783 15,107 Industrial 4,452 2,143 2,309 - ---------------------------------------------------------------------- ---------------- ----------------- ---------------- 406,215 298,992 107,223 - ---------------------------------------------------------------------- ---------------- ----------------- ---------------- Transportation 26,916 20,960 5,956 Other 2,469 1,182 1,287 - ---------------------------------------------------------------------- ---------------- ----------------- ---------------- $435,600 $321,134 $ 114,466 - ---------------------------------------------------------------------- ---------------- ----------------- ----------------
22
Utility Throughput- ---------------------------------------------------------------------- ---------------- ----------------- ---------------- Increase Three Months Ended December 31 (MMcf) 2005 2004 (Decrease) - ---------------------------------------------------------------------- ---------------- ----------------- ---------------- Retail Sales: Residential 19,524 19,869 (345) Commercial 3,443 3,454 (11) Industrial 327 176 151 - ---------------------------------------------------------------------- ---------------- ----------------- ---------------- 23,294 23,499 (205) - ---------------------------------------------------------------------- ---------------- ----------------- ---------------- Transportation 14,342 14,103 239 - ---------------------------------------------------------------------- ---------------- ----------------- ---------------- 37,636 37,602 34 - ---------------------------------------------------------------------- ---------------- ----------------- ----------------Degree Days- ---------------------------------- -------------- -------------- -------------------- -------------------------------- Percent Three Months Ended Colder (Warmer) Than -------------------------------- December 31 Normal 2005 2004 Normal Prior Year - ---------------------------------- -------------- -------------- -------------------- ----------------- -------------- Buffalo 2,260 2,210 2,172 (2.2) 1.7 Erie 2,081 2,048 1,997 (1.6) 2.6 - ---------------------------------- -------------- -------------- -------------------- ----------------- --------------
Operating revenues for the Utility segment increased $114.5 million for the quarter ended December 31, 2005 as compared with the quarter ended December 31, 2004. The $107.2 million increase in retail gas sales was primarily the result of the recovery of higher gas costs (gas costs are recovered dollar for dollar in revenues). 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 adjustment related to fiscal years 2002 through 2005. The impact of the New York rate case settlement, which became effective in August 2005, was to increase operating revenues by $7.4 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 $2.7 million.
The Utility segment’s earnings for the quarter ended December 31, 2005 were $21.7 million, an increase of $3.7 million when compared with the quarter ended December 31, 2004. In the New York jurisdiction, earnings increased $1.8 million. The increased earnings in the New York jurisdiction largely related to the symmetrical sharing adjustment discussed above ($2.6 million). The positive impact to revenues of the New York rate case settlement ($4.8 million) was mostly offset by lower usage per customer account ($1.9 million), higher bad debt expense ($2.1 million), higher pension expense ($0.6 million), and higher interest expense ($0.6 million). In the Pennsylvania jurisdiction, earnings increased $1.9 million. Increased earnings in the Pennsylvania jurisdiction resulted primarily from a base rate increase first implemented in April 2005 ($1.8 million). This increase more than offset slightly higher bad debt expense ($0.6 million).
The impact of weather variations on earnings in the New York jurisdiction is mitigated by that jurisdiction’s weather normalization clause (WNC). The WNC in New York, which covers the eight-month period from October through May, has had a stabilizing effect on earnings for the New York rate jurisdiction. For the quarters ended December 31, 2005 and December 31, 2004, the WNC preserved $0.5 million and $1.3 million of earnings, respectively, since it was warmer than normal. In periods of colder than normal weather, the WNC benefits Distribution Corporation’s New York customers.
23
Pipeline and StoragePipeline and Storage Operating Revenues- ---------------------------------------------------------------------- ---------------- ----------------- ---------------- Increase Three Months Ended December 31 Thousands) 2005 2004 (Decrease) - ---------------------------------------------------------------------- ---------------- ----------------- ---------------- Firm Transportation $31,086 $29,531 $1,555 Interruptible Transportation 1,323 926 397 - ---------------------------------------------------------------------- ---------------- ----------------- ---------------- 32,409 30,457 1,952 - ---------------------------------------------------------------------- ---------------- ----------------- ---------------- Firm Storage Service 16,248 16,094 154 Other 7,377 6,493 884 - ---------------------------------------------------------------------- ---------------- ----------------- ---------------- $56,034 $53,044 $ 2,990 - ---------------------------------------------------------------------- ---------------- ----------------- ----------------Pipeline and Storage Throughput- ---------------------------------------------------------------------- ---------------- ----------------- ---------------- Increase Three Months Ended December 31 (MMcf) 2005 2004 (Decrease) - ---------------------------------------------------------------------- ---------------- ----------------- ---------------- Firm Transportation 102,822 83,742 19,080 Interruptible Transportation 3,723 1,662 2,061 - ---------------------------------------------------------------------- ---------------- ----------------- ---------------- 106,545 85,404 21,141 - ---------------------------------------------------------------------- ---------------- ----------------- ----------------
Operating revenues for the Pipeline and Storage segment increased $3.0 million for the quarter ended December 31, 2005 as compared with the quarter ended December 31, 2004. The $2.0 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. The $0.9 million increase in other operating revenues was primarily due to higher revenues from unbundled pipeline sales due to higher natural gas prices ($1.4 million), offset by a decrease in cashout revenues ($0.7 million). Cashout revenues are completely offset by purchased gas expense and consequently have no impact on earnings.
Earnings in the Pipeline and Storage segment increased $3.6 million from $12.3 million for the quarter ended December 31, 2004 to $15.9 million for the quarter ended December 31, 2005. The major factors contributing to the increase were higher transportation revenues ($1.3 million) and higher revenues from unbundled pipeline sales ($0.9 million), both noted above, as well as lower operating expenses ($1.1 million). Operating expenses decreased primarily due to a lower reserve for preliminary project costs associated with the Empire State Pipeline Expansion project ($0.7 million) and the impact of lower pension expense ($0.2 million).
Exploration and ProductionExploration and Production Operating Revenues- --------------------------------------------------------------------- ---------------- ----------------- ---------------- Increase Three Months Ended December 31 (Thousands) 2005 2004 (Decrease) - --------------------------------------------------------------------- ---------------- ----------------- ---------------- Gas (after Hedging) $49,341 $42,744 $6,597 Oil (after Hedging) 29,395 26,896 2,499 Gas Processing Plant 13,419 8,704 4,715 Other 1,524 753 771 Intrasegment Elimination (1) (11,592) (7,259) (4,333) - --------------------------------------------------------------------- ---------------- ----------------- ---------------- $82,087 $71,838 $ 10,249 - --------------------------------------------------------------------- ---------------- ----------------- ----------------
(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.
24
Production Volumes- ------------------------------------------------------------------ ---------------- ---------------- ---------------- Increase Three Months Ended December 31 2005 2004 (Decrease) - ------------------------------------------------------------------ ---------------- ---------------- ----------------Gas Production (MMcf)Gulf Coast 1,667 3,225 (1,558) West Coast 1,018 1,039 (21) Appalachia 1,253 1,206 47 Canada 1,911 1,665 246 ------------------------------------------------------------------ ---------------- ---------------- ---------------- 5,849 7,135 (1,286) - ------------------------------------------------------------------ ---------------- ---------------- ----------------Oil Production (Mbbl)Gulf Coast 107 289 (182) West Coast 685 653 32 Appalachia 10 3 7 Canada 87 76 11 - ------------------------------------------------------------------ ---------------- ---------------- ---------------- 889 1,021 (132) - ------------------------------------------------------------------ ---------------- ---------------- ----------------Average Prices- ------------------------------------------------------------------ --------------- ----------------- ---------------- Increase Three Months Ended December 31 2005 2004 (Decrease) - ------------------------------------------------------------------ --------------- ----------------- ----------------Average Gas Price/McfGulf Coast $10.74 $6.50 $4.24 West Coast $11.08 $6.55 $4.53 Appalachia $13.62 $7.73 $5.89 Canada $10.76 $5.45 $5.31 Weighted Average $11.42 $6.47 $4.95 Weighted Average After Hedging $8.44 $5.99 $2.45 - ------------------------------------------------------------------ --------------- ----------------- ----------------Average Oil Price/BblGulf Coast $57.90 $47.08 $10.82 West Coast $51.34 $37.14 $14.20 Appalachia $61.53 $44.33 $17.20 Canada $43.18 $38.43 $4.75 Weighted Average $51.45 $40.08 $11.37 Weighted Average After Hedging $33.07 $26.35 $6.72 - ------------------------------------------------------------------ --------------- ----------------- ----------------
Operating revenues for the Exploration and Production segment increased $10.2 million for the quarter ended December 31, 2005 as compared with the quarter ended December 31, 2004. Gas production revenue after hedging increased $6.6 million. An increase in the weighted average price of gas after hedging ($2.45 per Mcf) more than offset an overall decrease in gas production. Oil production revenue after hedging increased $2.5 million. An increase in the weighted average price of oil after hedging ($6.72 per bbl) more than offset an overall decrease in oil production of 132,000 barrels. Most of the decrease in gas and oil production occurred in the Gulf Coast (a 1,558 MMcf decline in gas production and a 182,000 bbl decline in oil production), which is consistent with this region’s expected delays in production volumes due largely to the impact of last fall’s hurricane damage to pipeline infrastructure in the Gulf of Mexico. Currently, Seneca has approximately 87% of its pre hurricane Gulf of Mexico production back on line. The remaining 13% continues to wait on pipeline and facilities repair. These repairs may be completed within the next six months.*
The Exploration and Production segment’s earnings for the quarter ended December 31, 2005 were $17.4 million compared with earnings of $13.9 million for the quarter ended December 31, 2004. The increase is attributable to the positive impact of higher natural gas and crude oil revenues, as discussed above ($5.9 million positive contribution to earnings). Partially offsetting this increase, the Exploration and Production segment experienced higher lease operating costs ($2.0 million), primarily in
25
the West Coast region due to higher steaming costs associated with heavy crude oil production in the California Midway-Sunset field.
Energy MarketingEnergy Marketing Operating Revenues- ---------------------------------------------------------------------- ------------------- ---------------- ----------------- Increase Three Months Ended December 31 (Thousands) 2005 2004 (Decrease) - ---------------------------------------------------------------------- ------------------- ---------------- ----------------- Natural Gas (after Hedging) $145,523 $63,489 $82,034 Other 37 5 32 - ---------------------------------------------------------------------- ------------------- ---------------- ----------------- $145,560 $63,494 $ 82,066 - ---------------------------------------------------------------------- ------------------- ---------------- -----------------nergy Marketing Volumes- ---------------------------------------------------------------------- ------------------- ---------------- ----------------- Increase Three Months Ended December 31 2005 2004 (Decrease) - ---------------------------------------------------------------------- ------------------- ---------------- ----------------- Natural Gas - (MMcf) 9,975 8,007 1,968 - ---------------------------------------------------------------------- ------------------- ---------------- -----------------
Operating revenues for the Energy Marketing segment increased $82.1 million for the quarter ended December 31, 2005 as compared with the quarter ended December 31, 2004. This increase 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 Energy Marketing segment’s earnings increased $0.2 million from $0.8 million for the quarter ended December 31, 2004 to $1.0 million for the quarter ended December 31, 2005. The major factors contributing to the increase were higher gross margin ($0.5 million) resulting from higher throughput offset by an increase in operating expenses ($0.3 million).
TimberTimber Operating Revenues- ---------------------------------------------------------------------- ------------------- ---------------- ----------------- Increase Three Months Ended December 31 (Thousands) 2005 2004 (Decrease) - ---------------------------------------------------------------------- ------------------- ---------------- ----------------- Log Sales $6,256 $4,876 $1,380 Green Lumber Sales 1,462 1,446 16 Kiln Dry Lumber Sales 8,500 6,274 2,226 Other 713 399 314 - ---------------------------------------------------------------------- ------------------- ---------------- ----------------- Operating Revenues $16,931 $12,995 $3,936 - ---------------------------------------------------------------------- ------------------- ---------------- -----------------Timber Board Feet- ---------------------------------------------------------------------- ------------------- ---------------- ----------------- Increase Three Months Ended December 31 (Thousands) 2005 2004 (Decrease) - ---------------------------------------------------------------------- ------------------- ---------------- ----------------- Log Sales 2,491 1,745 746 Green Lumber Sales 1,974 2,164 (190) Kiln Dry Lumber Sales 4,486 3,366 1,120 - ---------------------------------------------------------------------- ------------------- ---------------- ----------------- 8,951 7,275 1,676 - ---------------------------------------------------------------------- ------------------- ---------------- -----------------
26
Operating revenues for the Timber segment increased $3.9 million for the quarter ended December 31, 2005 as compared with the quarter ended December 31, 2004. Higher revenues from kiln dry lumber sales ($2.2 million and 1.1 million board feet) are partially responsible for the increase due to an increase in processing capacity for kiln dry lumber. The increase in capacity resulted from the addition of two new kilns in February 2005. Higher log sales of $1.4 million also contributed to the increase in revenues. Favorable weather conditions allowed for the harvesting of greater volumes of timber and the accompanying cherry veneer logs, which have the highest price in the harvested timber mix.
The Timber segment’s earnings for the quarter ended December 31, 2005 were $1.5 million, an increase of $0.7 million when compared with earnings of $0.8 million for the quarter ended December 31, 2004. The increase was principally due to higher margins from lumber and log sales ($1.2 million). This was partially offset by higher depletion expense ($0.3 million).
Corporate and All Other recorded a loss of $0.1 million for the quarter ended December 31, 2005 compared with a loss of $0.9 million for the quarter ended December 31, 2004. This improvement was 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 three-month period ended December 31, 2005 consisted of short-term borrowings and cash provided by operating activities. This source of cash was supplemented by issuances of common stock under the Company’s stock plans. During the three months ended December 31, 2005, 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.
Internally generated cash from operating activities consists of net income available for common stock, adjusted for noncash expenses, noncash income and changes in operating assets and liabilities. Noncash 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
27
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 $20.6 million for the three months ended December 31, 2005, a decrease of $38.5 million compared with the $59.1 million provided by operating activities for the three months ended December 31, 2004. This decrease can be attributed to the timing of gas cost recovery in the Utility segment. It also can be attributed to the timing of federal tax payments and reflects the fact that the Company no longer has positive cash flow from its former Czech Republic operations, which were sold in July 2005. These decreases were partially offset by higher oil and gas revenues in the Exploration and Production segment and a decrease in hedging collateral deposits for the quarter ended December 31, 2005 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.
Expenditures for Long-Lived Assets
The Company’s expenditures for long-lived assets totaled $70.4 million during the three months ended December 31, 2005. The table below presents these expenditures:
------------------------------------------------------------- ----------------------- ----------------------- Three Months Ended December 31, 2005(in millions of dollars)-------------------------------------- ---------------------- ----------------------- ----------------------- Total Expenditures for Long-Lived Assets -------------------------------------- ---------------------- ----------------------- ----------------------- Utility $12.4 Pipeline and Storage 6.2 Exploration and Production 50.9 Timber 0.5 Corporate and All Other 0.4 -------------------------------------- ---------------------- ----------------------- ----------------------- $70.4 -------------------------------------- ---------------------- ----------------------- -----------------------
Utility
The majority of the Utility capital expenditures for the three months ended December 31, 2005 were made for replacement of mains and main extensions, as well as for the replacement of service lines.
Pipeline and Storage
The majority of the Pipeline and Storage capital expenditures for the three months ended December 31, 2005 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
28
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 December 31, 2005, the Company had incurred approximately $4.7 million in costs (all of which have been reserved) related to this project. Of this amount, $0.7 million and $1.7 million were incurred during the quarters ended December 31, 2005 and December 31, 2004, respectively.
The Company also 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 targeted in-service date is late in calendar 2007 or early in calendar 2008.* The Company anticipates financing this project with cash on hand and/or through the use of the Company’s bi-lateral lines of credit.* The Tuscarora Extension is contingent on market developments, and the Company has not yet filed an application with the FERC for the authority to build and operate it. There have been no costs incurred by the Company related to this project as of December 31, 2005.
Exploration and Production
The Exploration and Production segment capital expenditures for the three months ended December 31, 2005 included approximately $12.1 million for Canada, $24.0 million for the Gulf Coast region ($24.0 million for the off-shore program in the Gulf of Mexico), $9.4 million for the West Coast region and $5.4 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. These amounts included approximately $8.0 million spent to develop proved undeveloped reserves.
Timber
The majority of the Timber segment capital expenditures for the three months ended December 31, 2005 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 three months ended December 31, 2005 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 natural gas transmission line capacities. While the majority of capital expenditures in the Utility segment are necessitated by the continued need for replacement and upgrading of mains and service lines, the magnitude of future capital expenditures or other investments in the Company’s other business segments depends, to a large degree, upon market conditions.*
Consolidated short-term debt increased $74.8 million during the three months ended December 31, 2005. The Company continues to consider short-term debt (consisting of short-term notes payable to
29
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. At December 31, 2005, the Company had outstanding short-term notes payable to banks of $74.8 million. There was no outstanding commercial paper at December 31, 2005. The Company had SEC authorization under PUHCA 1935 to borrow and have outstanding as much as $750.0 million of short-term debt at any time through February 8, 2006. PUHCA 1935 was repealed effective February 8, 2006, and as of that date the Company no longer needs authorization from the SEC under that act to issue 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 $420.0 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 December 31, 2005, the Company’s debt to capitalization ratio (as calculated under the facility) was .48. The constraints specified in the committed credit facility would permit an additional $1.25 billion in short-term and/or long-term debt to be outstanding (further limited by the indenture covenants discussed below) 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.*
Under the Company’s existing indenture covenants, at December 31, 2005, the Company would have been permitted to issue up to a maximum of $837.0 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 35%) of the Company’s long-term debt (as of December 31, 2005) 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 any of its significant subsidiaries fails 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 December 31, 2005, the Company had no debt outstanding under the committed credit facility.
30
The Company also had authorization from the SEC, under PUHCA 1935 to issue long-term debt securities and equity securities in an aggregate amount of up to $1.5 billion during the period from November 2002 through February 8, 2006. As a result of the repeal of PUHCA 1935 (effective February 8, 2006), the Company no longer needs authorization under that act to issue long-term debt securities and equity securities. 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. It is expected that this share repurchase program will be funded with cash provided by operating activities and/or through the use of the Company’s bi-lateral lines of credit.* Currently, no shares have been repurchased under this program, but it is expected that open market repurchases will begin in February 2006 and 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 $49.8 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 $8.4 million. The Company has guaranteed 50% or $4.2 million of these capital lease commitments.
The Company is involved in litigation arising in the normal course of business. Also in the normal course of business, the Company is involved in tax, regulatory and other governmental audits, inspections, investigations and other proceedings that involve state and federal taxes, safety, compliance with regulations, rate base, cost of service and purchased gas cost issues, among other things. While the resolution of such litigation or regulatory matters could have a material effect on earnings and cash flows in the quarterly and annual period of resolution, none of this litigation, and none of these regulatory matters, are expected to change materially the Company’s present liquidity position, nor have a material adverse effect on the financial condition of the Company.*
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.
31
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, pursuant to PUHCA 2005, the FERC issued Order 667. As required by Order 667, the Company will file a “Notification of Holding Company Status” with the FERC by March 10, 2006. Certain subsidiaries of the Company may be eligible for exemption from the requirements of PUHCA 2005 and Order 667. The Company is in the process of evaluating that matter and may file appropriate exemption notifications with the FERC. The Company is unable to predict at this time what the ultimate outcome of these or future legislative or regulatory changes will be. The Company is still in the process of analyzing the effect of the Energy Policy Act on the Company, including the effects of any related proceeding at the state level and new regulations at the federal level.
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 filed proposed tariff amendments and supporting testimony designed to increase its annual revenues by $41.3 million beginning October 1, 2004. Parties, including the NYPSC Staff, the New York State Consumer Protection Board, Multiple Intervenors (an advocate for large commercial and industrial customers), natural gas marketers and others, filed responsive testimony recommending a base rate decrease, among other things. Thereafter, the Parties and other interests commenced settlement negotiations. 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%.
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 was submitted to the Administrative Law Judge, who, on March 2, 2005 issued a decision recommending adoption of the settlement. 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.
32
Supply Corporation currently does not have a rate case on file with the FERC. Management will continue to monitor Supply Corporation’s financial position to determine the necessity of filing a rate case in the future.
On November 25, 2003, the FERC issued Order 2004. 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, 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 site will be $3.7 million.* This liability has been recorded on the Consolidated Balance Sheet at December 31, 2005. 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 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.*
33
For further discussion refer to Note G — Commitments and Contingencies under the heading “Environmental Matters” in Item 8 of the 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,” “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:
34
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations (Cont.)
35
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.
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 December 31, 2005 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, Chautauqua County on January 31, 2000 against Seneca, NFR and “National Fuel Gas Corporation,” Donald J. and Margaret Ortel and Brian and Judith Rapp, “individually and on behalf of all those similarly situated,” allege, in an amended complaint which adds National Fuel Gas Company as a party defendant that (a) Seneca underpaid royalties due under leases operated by it, and (b) Seneca’s co-defendants (i) fraudulently participated in and concealed such alleged underpayment, and (ii) induced Seneca’s alleged breach of such leases. Plaintiffs seek an accounting, declaratory and related injunctive relief, and compensatory and exemplary damages. Defendants have denied each of plaintiffs’ material substantive allegations and set up twenty-five affirmative defenses in separate verified answers.
A motion was made by plaintiffs on July 15, 2002 to certify a class comprising all persons presently and formerly entitled to receive royalties on the sale of natural gas produced and sold from wells operated in New York by Seneca (and its predecessor Empire Exploration, Inc). On December 23,
36
Item 1. Legal Proceedings (Cont.)
2002, the court granted certification of the proposed class, as modified to exclude those leaseholders whose leases provide for calculation of royalties based upon a flat fee, or flat fee per cubic foot of gas produced. The court’s order states that there are approximately 749 potential class members. Discovery closed on July 31, 2005, and the plaintiffs thereafter filed a formal demand for a jury trial and a “Note of Issue and Statement of Readiness” to proceed to trial. A trial date has not been set.
On October 13, 2005, the Company and the attorneys for the class entered into a Stipulation of Settlement, under which (i) the class would be expanded for purposes of settlement to include similarly situated persons entitled to royalties on natural gas production in Pennsylvania, (ii) the Company would pay $2.25 million to the plaintiffs to settle all damages, interest, legal fees and costs, and (iii) the Company would comply with various procedures set out in the Stipulation regarding the marketing of natural gas produced and the calculation of royalties. A fairness hearing was held on December 19, 2005, at which no interested parties objected to the settlement. On January 27, 2006, the judge issued an order approving the settlement as fair, reasonable and adequate. The Company’s balance sheets at December 31, 2005 and September 30, 2005 include a liability for the $2.25 million settlement. Subsequent periodic filings will not include any further discussion of this matter.
In an action instituted in the New York State Supreme Court, Kings County on February 18, 2003 against Distribution Corporation and Paul J. Hissin, an unaffiliated third party, plaintiff Donna Fordham-Coleman, as administratrix of the estate of Velma Arlene Fordham, alleges that Distribution Corporation’s denial of natural gas service in November 2000 to the plaintiff’s decedent, Velma Arlene Fordham, caused decedent’s death in February 2001. The plaintiff seeks damages for wrongful death and pain and suffering, plus punitive damages. Distribution Corporation has denied plaintiff’s material allegations, set up seven affirmative defenses in separate verified answers and filed a cross-claim against the co-defendant. Distribution Corporation believes, and will vigorously assert, that plaintiff’s allegations lack merit. The Court changed venue of the action to New York State Supreme Court, Erie County. Discovery has closed. Distribution Corporation filed a motion for summary judgment and is awaiting the Court’s decision on that motion. A trial date has been scheduled for February 27, 2006.
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 asserts certain violations of DEP regulations concerning erosion, sedimentation and stream crossings. The order requires Seneca to apply for certain permits, control erosion, submit plans for removal of water encroachments not included in permit applications, notify the DEP of additional current or planned timber harvesting operations, and grant the DEP access to timber acreage. On January 9, 2004, Seneca filed with the Pennsylvania Environmental Hearing Board (Hearing Board) a notice of appeal, objecting to each finding and order contained in the order, and asserting that the DEP’s findings are factually incorrect, an arbitrary exercise of the DEP’s functions and duties, and contrary to law. Also on January 9, 2004, Seneca filed with the Hearing Board a petition requesting a stay of operation of portions of the order. On January 16, 2004, the parties settled Seneca’s request for a stay. Seneca has resumed its timber harvesting operations pursuant to the terms of the settlement. The settlement preserves various issues raised by the DEP’s order for a hearing on the merits of Seneca’s notice of appeal. Seneca is engaged in settlement negotiations regarding this matter.* The most substantial question in the appeal involves 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. The DEP takes the position that Seneca must aggregate the acreage of all of its logging sites across its entire 21,000 acre tract for purposes of determining whether its earth disturbing activities meet the 25 acres threshold. Seneca maintains that no permit is required, because the law does not require aggregation and each of its individual logging sites disturbs less than 25 acres.
The Company believes, based on the information presently known, that the ultimate resolution of these matters, individually or in the aggregate, will not be material to the consolidated financial condition, results of operations, or cash flow of the Company.* No assurances can be given, however, as to the ultimate outcomes of these matters, and it is possible that the outcomes, individually or in the aggregate, could be material to results of operations or cash flow for a particular quarter or annual period.*
37
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 “Environmental Matters.”
The Company is involved in litigation arising in the normal course of business. Also in the normal course of business, the Company is involved in tax, regulatory and other governmental audits, inspections, investigations and other proceedings that involve state and federal taxes, safety, compliance with regulations, rate base, cost of service and purchased gas cost issues, among other things. While the resolution of such litigation or regulatory matters could have a material effect on earnings and cash flows in the period of resolution, none of this litigation, and none of these regulatory matters, are expected to change materially the Company’s present liquidity position, nor have a material adverse effect on the financial condition of the Company.*
For a complete discussion of risk factors, refer to “Risk Factors” in Item 1A of the 2005 Form 10-K. There have been no subsequent material changes to that disclosure.
On October 16, 2005 the Company issued a total of 2,100 unregistered shares of Company common stock to the seven non-employee directors of the Company then 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 December 31, 2005, 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 of Shares Purchased as Shares that May Yet Part of Publicly Be Purchased Under Total Number of Announced Share Share Repurchase Shares Average Price Repurchase Plans or Plans or Programs (b) Period Purchased(a) Paid per Share Programs - ------------------------- ---------------------- ---------------------- ---------------------- ---------------------- Oct. 1-31, 2005 11,675 $32.68 - - - ------------------------- ---------------------- ---------------------- ---------------------- ---------------------- Nov. 1-30, 2005 11,268 $29.83 - - - ------------------------- ---------------------- ---------------------- ---------------------- ---------------------- Dec. 1-31, 2005 47,953 $32.05 - 8,000,000 - ------------------------- ---------------------- ---------------------- ---------------------- ---------------------- Total 70,896 $31.80 - 8,000,000 - ------------------------- ---------------------- ---------------------- ---------------------- ----------------------
(a) Exhibits Exhibit Number Description of Exhibit ------- ---------------------- 10 Material Contracts:
38
10.1 National Fuel Gas Company Tophat Plan, dated December 7, 2005. 10.2 Description of performance goals for Chief Executive Officer under the Company's Annual At Risk Compensation Incentive Program. 12 Statements regarding Computation of Ratios: Ratio of Earnings to Fixed Charges for the Twelve Months Ended December 31, 2005 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 December 31, 2005 and 2004.
39
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: February 9, 2006
40
EXHIBIT INDEX(Form 10-Q)
Exhibit 10.1 National Fuel Gas Company Tophat Plan, dated December 7, 2005. Exhibit 10.2 Description of performance goals for Chief Executive Officer under the Company's Annual At Risk Compensation Incentive Program. Exhibit 12 Statements regarding Computation of Ratios: Ratio of Earnings to Fixed Charges for the Twelve Months Ended December 31, 2005 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 December 31, 2005 and 2004.