UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

þ		QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended December 31, 2006

o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from ___ to ___

NATIONAL FUEL GAS COMPANY

(Exact name of registrant as specified in its charter)

New Jersey		13-1086010
(State or other jurisdiction of		(I.R.S. Employer
incorporation or organization)		Identification No.)
6363 Main Street
Williamsville, New York		14221
(Address of principal executive offices)		(Zip 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  þ     NO  o

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  þ     Accelerated Filer  o     Non-Accelerated Filer  o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).  YES  o     NO  þ

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, 2007: 82,769,461 shares.

 

 

GLOSSARY OF TERMS

Frequently used abbreviations, acronyms, or terms used in this report:

National Fuel Gas Companies

Company		The Registrant, the Registrant and its subsidiaries or the Registrant’s subsidiaries as appropriate in the context of the disclosure
Data-Track		Data-Track Account Services, Inc.
Distribution Corporation		National Fuel Gas Distribution Corporation
Empire		Empire State Pipeline
ESNE		Energy Systems North East, LLC
Highland		Highland Forest Resources, Inc.
Horizon		Horizon Energy Development, Inc.
Horizon LFG		Horizon LFG, Inc.
Horizon Power		Horizon Power, Inc.
Leidy Hub		Leidy Hub, Inc.
Model City		Model City Energy, LLC
National Fuel		National Fuel Gas Company
NFR		National Fuel Resources, Inc.
Registrant		National Fuel Gas Company
SECI		Seneca Energy Canada Inc.
Seneca		Seneca Resources Corporation
Seneca Energy		Seneca Energy II, LLC
Supply Corporation		National Fuel Gas Supply Corporation
U.E.		United Energy, a.s.
Regulatory Agencies
FASB		Financial Accounting Standards Board
FERC		Federal Energy Regulatory Commission
NTSB		National Transportation Safety Board
NYPSC		State of New York Public Service Commission
PaPUC		Pennsylvania Public Utility Commission
SEC		Securities and Exchange Commission
Other
2006 Form 10-K		The Company’s Annual Report on Form 10-K for the year ended September 30, 2006
Bbl		Barrel (of oil)
Bcf		Billion cubic feet (of natural gas)
Board foot		A measure of lumber and/or timber equal to 12 inches in length by 12 inches in width by one inch in thickness.
Btu		British thermal unit; the amount of heat needed to raise the temperature of one pound of water one degree Fahrenheit.
Capital expenditure		Represents additions to property, plant, and equipment, or the amount of money a company spends to buy capital assets or upgrade its existing capital assets.
Cashout revenues		A cash resolution of a gas imbalance whereby a customer pays Supply Corporation for gas the customer receives in excess of amounts delivered into Supply Corporation’s system by the customer’s shipper.
Degree day		A measure of the coldness of the weather experienced, based on the extent to which the daily average temperature falls below a reference temperature, usually 65 degrees Fahrenheit.
Derivative		A financial instrument or other contract, the terms of which include an underlying variable (a price, interest rate, index rate, exchange rate, or other variable) and a notional amount (number of units, barrels, cubic feet, etc.). The terms also permit for the instrument or contract to be settled net and no initial net investment is required to enter into the financial instrument or contract. Examples include futures contracts, options, no cost collars and swaps.
Dth		Decatherm; 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.

GLOSSARY OF TERMS (Cont.)
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		FASB Interpretation Number
FIN 48		FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes - an interpretation of SFAS 109
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 decatherms (of natural gas)
MMcf		Million cubic feet (of natural gas)
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.
Reserves		The unproduced but recoverable oil and/or gas in place in a formation which has been proven by production.
Restructuring		Generally referring to partial “deregulation” of the utility industry by statutory or regulatory process. Restructuring of federally regulated natural gas pipelines resulted in the separation (or “unbundling”) of gas commodity service from transportation service for wholesale and large- volume retail markets. State restructuring programs attempt to extend the same process to retail mass markets.
SFAS		Statement of Financial Accounting Standards
SFAS 87		Statement of Financial Accounting Standards No. 87, Employers’ Accounting for Pensions
SFAS 88		Statement of Financial Accounting Standards No. 88, Employers’ Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits
SFAS 106		Statement of Financial Accounting Standards No. 106, Employers’ Accounting for Postretirement Benefits Other Than Pensions
SFAS 109		Statement of Financial Accounting Standards No. 109, Accounting for Income Taxes
SFAS 132R		Statement of Financial Accounting Standards No. 132R, Employers’ Disclosures about Pensions and Other Postretirement Benefits
SFAS 157		Statement of Financial Accounting Standards No. 157, Fair Value Measurements

GLOSSARY OF TERMS (Concl.)
SFAS 158		Statement of Financial Accounting Standards No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of SFAS 87, 88, 106, and 132R
Stock acquisitions		Investments in corporations.
Unbundled service		A service that has been separated from other services, with rates charged that reflect only the cost of the separated service.
WNC		Weather normalization clause; a clause in utility rates which adjusts customer rates to allow a utility to recover its normal operating costs calculated at normal temperatures. If temperatures during the measured period are warmer than normal, customer rates are adjusted upward in order to recover projected operating costs. If temperatures during the measured period are colder than normal, customer rates are adjusted downward so that only the projected operating costs will be recovered.

INDEX

		Page
Part I. Financial Information
Item 1. Financial Statements (Unaudited)
a. Consolidated Statements of Income and Earnings Reinvested in the Business — Three Months Ended December 31, 2006 and 2005			6
b. Consolidated Balance Sheets – December 31, 2006 and September 30, 2006			7 - 8
c. Consolidated Statements of Cash Flows – Three Months Ended December 31, 2006 and 2005			9
d. Consolidated Statements of Comprehensive Income — Three Months Ended December 31, 2006 and 2005			10
e. Notes to Consolidated Financial Statements			11 - 17
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			18 - 35
Item 3. Quantitative and Qualitative Disclosures About Market Risk			35
Item 4. Controls and Procedures			35
Part II. Other Information
Item 1. Legal Proceedings			36
Item 1 A. Risk Factors			36 - 37
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			37
Item 3. Defaults Upon Senior Securities			•
Item 4. Submission of Matters to a Vote of Security Holders			•
Item 5. Other Information			•
Item 6. Exhibits			37 - 38
Signatures			39
EX-10.1
EX-10.2
EX-10.3
EX-10.4
EX-10.5
EX-10.6
EX-10.7
EX-10.8
EX-12
EX-31.1
EX-31.2
EX-32
EX-99

     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.

Part I. Financial Information

Item 1. Financial Statements

National Fuel Gas Company

		Three Months Ended
		December 31,
(Thousands of Dollars, Except Per Common Share Amounts)		2006				2005
INCOME
Operating Revenues		$	504,240			$	710,756
Operating Expenses
Purchased Gas			242,939				436,778
Operation and Maintenance			99,374				103,628
Property, Franchise and Other Taxes			17,112				17,181
Depreciation, Depletion and Amortization			42,825				43,046
			402,250				600,633
Operating Income			101,990				110,123
Other Income (Expense):
Income from Unconsolidated Subsidiaries			1,231				1,264
Interest Income			1,363				1,134
Other Income			715				741
Interest Expense on Long-Term Debt			(16,043	)			(18,218	)
Other Interest Expense			(1,849	)			(1,775	)
Income Before Income Taxes			87,407				93,269
Income Tax Expense			32,887				35,850
Net Income Available for Common Stock			54,520				57,419
EARNINGS REINVESTED IN THE BUSINESS
Balance at October 1			786,013				813,020
			840,533				870,439
Share Repurchases			34,018				—
Dividends on Common Stock (2006 - $0.30; 2005 - $0.29)			24,787				24,488
Balance at December 31		$	781,728			$	845,951
Earnings Per Common Share:
Basic:
Net Income Available for Common Stock		$	0.66			$	0.68
Diluted:
Net Income Available for Common Stock		$	0.64			$	0.67
Weighted Average Common Shares Outstanding:
Used in Basic Calculation			82,679,343				84,422,717
Used in Diluted Calculation			84,730,910				86,256,862

See Notes to Condensed Consolidated Financial Statements

Item 1. Financial Statements (Cont.)

National Fuel Gas Company

		December 31,				September 30,
(Thousands of Dollars)		2006				2006
ASSETS
Property, Plant and Equipment		$	4,742,029			$	4,703,040
Less — Accumulated Depreciation, Depletion and Amortization			1,846,665				1,825,314
			2,895,364				2,877,726
Current Assets
Cash and Temporary Cash Investments			47,598				69,611
Hedging Collateral Deposits			9,760				19,676
Receivables — Net of Allowance for Uncollectible Accounts of $35,677 and $31,427, Respectively			192,608				144,254
Unbilled Utility Revenue			67,866				25,538
Gas Stored Underground			57,865				59,461
Materials and Supplies — at average cost			32,925				36,693
Unrecovered Purchased Gas Costs			23,991				12,970
Prepaid Pension and Post-Retirement Benefit Costs			60,954				64,125
Other Current Assets			60,205				63,723
Deferred Income Taxes			16,533				23,402
			570,305				519,453
Other Assets
Recoverable Future Taxes			79,344				79,511
Unamortized Debt Expense			14,985				15,492
Other Regulatory Assets			76,890				76,917
Deferred Charges			2,068				3,558
Other Investments			90,282				88,414
Investments in Unconsolidated Subsidiaries			13,258				11,590
Goodwill			5,476				5,476
Intangible Assets			30,833				31,498
Fair Value of Derivative Financial Instruments			10,295				11,305
Deferred Income Taxes			6,885				9,003
Other			3,368				4,388
			333,684				337,152
Total Assets		$	3,799,353			$	3,734,331

See Notes to Condensed Consolidated Financial Statements

Item 1. Financial Statements (Cont.)

National Fuel Gas Company
Consolidated Balance Sheets
(Unaudited)

		December 31,				September 30,
(Thousands of Dollars)		2006				2006
CAPITALIZATION AND LIABILITIES
Capitalization:
Comprehensive Shareholders’ Equity
Common Stock, $1 Par Value
Authorized - 200,000,000 Shares; Issued And Outstanding – 82,624,576 Shares And 83,402,670 Shares, Respectively		$	82,625			$	83,403
Paid in Capital			557,504				543,730
Earnings Reinvested in the Business			781,728				786,013
Total Common Shareholder Equity Before Items of Other Comprehensive Income			1,421,857				1,413,146
Accumulated Other Comprehensive Income			32,991				30,416
Total Comprehensive Shareholders’ Equity			1,454,848				1,443,562
Long-Term Debt, Net of Current Portion			1,095,466				1,095,675
Total Capitalization			2,550,314				2,539,237
Current and Accrued Liabilities
Notes Payable to Banks and Commercial Paper			71,600				—
Current Portion of Long-Term Debt			129				22,925
Accounts Payable			144,164				133,034
Amounts Payable to Customers			27,101				23,935
Dividends Payable			24,770				25,008
Interest Payable on Long-Term Debt			13,803				18,420
Other Accruals and Current Liabilities			31,071				27,040
Fair Value of Derivative Financial Instruments			26,939				39,983
			339,577				290,345
Deferred Credits
Deferred Income Taxes			551,589				544,502
Taxes Refundable to Customers			10,430				10,426
Unamortized Investment Tax Credit			5,919				6,094
Cost of Removal Regulatory Liability			86,907				85,076
Other Regulatory Liabilities			70,995				75,456
Post-Retirement Liabilities			31,512				32,918
Asset Retirement Obligations			78,464				77,392
Other Deferred Credits			73,646				72,885
			909,462				904,749
Commitments and Contingencies			—				—
Total Capitalization and Liabilities		$	3,799,353			$	3,734,331

See Notes to Condensed Consolidated Financial Statements

Item 1. Financial Statements (Cont.)

National Fuel Gas Company

		Three Months Ended
		December 31,
(Thousands of Dollars)		2006				2005
OPERATING ACTIVITIES
Net Income Available for Common Stock		$	54,520			$	57,419
Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities:
Depreciation, Depletion and Amortization			42,825				43,046
Deferred Income Taxes			11,198				16,653
(Income) Loss from Unconsolidated Subsidiaries, Net of Cash Distributions			(18	)			1,887
Excess Tax Benefits Associated with Stock-Based Compensation Awards			(13,717	)			(6,439	)
Other			5,728				3,159
Change in:
Hedging Collateral Deposits			9,916				39,093
Receivables and Unbilled Utility Revenue			(91,341	)			(211,491	)
Gas Stored Underground and Materials and Supplies			5,324				5,692
Unrecovered Purchased Gas Costs			(11,021	)			(13,735	)
Prepayments and Other Current Assets			20,398				17,075
Accounts Payable			11,736				56,580
Amounts Payable to Customers			3,166				(127	)
Other Accruals and Current Liabilities			(756	)			(554	)
Other Assets			1,883				(3,083	)
Other Liabilities			(6,810	)			15,394
Net Cash Provided by Operating Activities			43,031				20,569
INVESTING ACTIVITIES
Capital Expenditures			(65,302	)			(70,368	)
Investment in Partnership			(1,650	)			—
Net Proceeds from Sale of Oil and Gas Producing Properties			2,141				—
Other			(316	)			(745	)
Net Cash Used in Investing Activities			(65,127	)			(71,113	)
FINANCING ACTIVITIES
Change in Notes Payable to Banks and Commercial Paper			71,600				74,800
Excess Tax Benefits Associated with Stock-Based Compensation Awards			13,717				6,439
Shares Repurchased under Repurchase Plan			(42,921	)			—
Reduction of Long-Term Debt			(23,005	)			(2,110	)
Dividends Paid on Common Stock			(25,026	)			(24,445	)
Net Proceeds from Issuance of Common Stock			6,743				2,570
Net Cash Provided by Financing Activities			1,108				57,254
Effect of Exchange Rates on Cash			(1,025	)			147
Net Increase (Decrease) in Cash and Temporary Cash Investments			(22,013	)			6,857
Cash and Temporary Cash Investments at October 1			69,611				57,607
Cash and Temporary Cash Investments at December 31		$	47,598			$	64,464

See Notes to Condensed Consolidated Financial Statements

Item 1. Financial Statements (Cont.)

National Fuel Gas Company

		Three Months Ended
		December 31,
(Thousands of Dollars)		2006				2005
Net Income Available for Common Stock		$	54,520			$	57,419
Other Comprehensive Income (Loss), Before Tax:
Foreign Currency Translation Adjustment			(4,868	)			255
Unrealized Gain on Securities Available for Sale Arising During the Period			790				1,142
Unrealized Gain on Derivative Financial Instruments Arising During the Period			9,501				40,997
Reclassification Adjustment for Realized Losses on Derivative Financial Instruments in Net Income			3,177				37,931
Other Comprehensive Income, Before Tax			8,600				80,325
Income Tax Expense Related to Unrealized Gain on Securities Available for Sale Arising During the Period			275				400
Income Tax Expense Related to Unrealized Gain on Derivative Financial Instruments Arising During the Period			3,730				15,776
Reclassification Adjustment for Income Tax Benefit on Realized Losses from Derivative Financial Instruments In Net Income			2,020				14,585
Income Taxes – Net			6,025				30,761
Other Comprehensive Income			2,575				49,564
Comprehensive Income		$	57,095			$	106,983

See Notes to Condensed Consolidated Financial Statements

Item 1. Financial Statements (Cont.)

National Fuel Gas Company

Note 1 — Summary of Significant Accounting Policies

Principles of Consolidation. The Company consolidates its majority owned entities. The equity method is used to account for minority owned entities. All significant intercompany balances and transactions are eliminated.

     The preparation of the consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Earnings for Interim Periods. The Company, in its opinion, has included all adjustments that are necessary for a fair statement of the results of operations for the reported periods. The consolidated financial statements and notes thereto, included herein, should be read in conjunction with the financial statements and notes for the years ended September 30, 2006, 2005 and 2004 that are included in the Company’s 2006 Form 10-K. The consolidated financial statements for the year ended September 30, 2007 will be audited by the Company’s independent registered public accounting firm after the end of the fiscal year.

     The earnings for the three months ended December 31, 2006 should not be taken as a prediction of earnings for the entire fiscal year ending September 30, 2007. Most of the business of the Utility and Energy Marketing segments is seasonal in nature and is influenced by weather conditions. Due to the seasonal nature of the heating business in the Utility and Energy Marketing segments, earnings during the winter months normally represent a substantial part of the earnings that those segments are expected to achieve for the entire fiscal year.

Consolidated Statement of Cash Flows. For purposes of the Consolidated Statement of Cash Flows, the Company considers all highly liquid debt instruments purchased with a maturity of generally three months or less to be cash equivalents.

Hedging Collateral Deposits. Cash held in margin accounts serve as collateral for open positions on exchange-traded futures contracts, exchange-traded options and over-the-counter swaps and collars.

Gas Stored Underground — Current. In the Utility segment, gas stored underground – current is carried at lower of cost or market, on a LIFO method. Gas stored underground – current normally declines during the first and second quarters of the year and is replenished during the third and fourth quarters. In the Utility segment, the current cost of replacing gas withdrawn from storage is recorded in the Consolidated Statements of Income and a reserve for gas replacement is recorded in the Consolidated Balance Sheets under the caption “Other Accruals and Current Liabilities.” Such reserve, which amounted to $8.5 million at December 31, 2006, is reduced to zero by September 30 of each year as the inventory is replenished.

Accumulated Other Comprehensive Income. The components of Accumulated Other Comprehensive Income, net of related tax effect, are as follows (in thousands):

Item 1. Financial Statements (Cont.)

		At December 31, 2006				At September 30, 2006
Cumulative Foreign Currency Translation Adjustment		$	29,833			$	34,701
Net Unrealized Loss on Derivative Financial Instruments			(4,582	)			(11,510	)
Net Unrealized Gain on Securities Available for Sale			7,740				7,225
Accumulated Other Comprehensive Income		$	32,991			$	30,416

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 quarter ended December 31, 2006, there were 122,253 stock options excluded as being antidilutive. For the quarter ended December 31, 2005, there were no stock options excluded as being antidilutive.

Share Repurchases. The Company considers all shares repurchased as cancelled shares restored to the status of authorized but unissued shares, in accordance with New Jersey law. The repurchases are accounted for on the date the share repurchase is settled as an adjustment to common stock (at par value) with the excess repurchase price allocated between paid in capital and retained earnings. Refer to Note 3 – Capitalization for further discussion of the share repurchase program.

Stock-Based Compensation. During the quarter ended December 31, 2006, the Company granted 448,000 stock options having a weighted average exercise price of $39.48. The weighted average grant date fair value of such options was $7.27 per share. The Company also granted 15,000 restricted share awards (non-vested stock as defined in SFAS 123R) during the quarter ended December 31, 2006. The weighted average fair value of such restricted shares was $39.50 per share.

New Accounting Pronouncements. In July 2006, the FASB issued FIN 48, “Accounting for Uncertainty in Income Taxes.” FIN 48 clarifies the accounting for income taxes by prescribing a minimum probability threshold that a tax position must meet before a financial statement benefit is recognized. The minimum threshold is defined in FIN 48 as a tax position that is more likely than not to be sustained upon examination by the applicable taxing authority, including resolution of any related appeals or litigation processes, based on the technical merits of the position. The cumulative effect of applying FIN 48 at adoption, if any, is to be reported as an adjustment to opening retained earnings for the year of adoption. FIN 48 is effective for the first quarter of the Company’s 2008 fiscal year. The Company is currently assessing the potential effect of FIN 48 on its consolidated financial statements.

     In September 2006, the FASB issued SFAS 157, “Fair Value Measurements”. SFAS 157 provides guidance for using fair value to measure assets and liabilities. The pronouncement serves to clarify the extent to which companies measure assets and liabilities at fair value, the information used to measure fair value, and the effect that fair-value measurements have on earnings. SFAS 157 is to be applied whenever another standard requires or allows assets or liabilities to be measured at fair value. The pronouncement is effective as of the Company’s first quarter of fiscal 2009. The Company is currently evaluating the impact that the adoption of SFAS 157 will have on its consolidated financial statements.

Item 1. Financial Statements (Cont.)

     In September 2006, the FASB also issued SFAS 158, “Employer’s Accounting for Defined Benefit Pension and Other Postretirement Plans” (an amendment of SFAS 87, SFAS 88, SFAS 106, and SFAS 132R). SFAS 158 requires that companies recognize a net liability or asset to report the underfunded or overfunded status of their defined benefit pension and other post-retirement benefit plans on their balance sheets, as well as recognize changes in the funded status of a defined benefit post-retirement plan in the year in which the changes occur through comprehensive income. The pronouncement also specifies that a plan’s assets and obligations that determine its funded status be measured as of the end of the Company’s fiscal year, with limited exceptions. The Company is required to recognize the funded status of its benefit plans and the disclosure requirements of SFAS 158 by the fourth quarter of fiscal 2007. The requirement to measure the plan assets and benefit obligations as of the Company’s fiscal year-end date will be adopted by the Company by the end of fiscal 2009. If the Company recognized the funded status of its pension and post-retirement benefit plans at September 30, 2006, the Company’s consolidated balance sheet would reflect a liability of $220.8 million instead of the prepaid pension and post-retirement costs of $64.1 million and post-retirement liabilities of $32.9 million that were presented on the balance sheet at September 30, 2006. The Company expects that it will record a regulatory asset for the majority of this liability with the remainder reflected in accumulated other comprehensive income. The Company will recalculate the funded status of its pension and post-retirement benefit plans during the fourth quarter of fiscal 2007.

Note 2 — Income Taxes

     The components of federal, state and foreign income taxes included in the Consolidated Statement of Income are as follows (in thousands):

		Three Months Ended
		December 31,
		2006				2005
Operating Expenses:
Current Income Taxes
Federal		$	16,653			$	14,311
State			5,036				4,814
Foreign			—				72
Deferred Income Taxes
Federal			8,210				10,870
State			1,209				1,695
Foreign			1,779				4,088
			32,887				35,850
Other Income:
Deferred Investment Tax Credit			(174	)			(174	)
Total Income Taxes		$	32,713			$	35,676

     The U.S. and foreign components of income before income taxes are as follows (in thousands):

		Three Months Ended
		December 31,
		2006				2005
U.S.		$	81,575			$	79,630
Foreign			5,658				13,465
		$	87,233			$	93,095

Item 1. Financial Statements (Cont.)

     Total income taxes as reported differ from the amounts that were computed by applying the federal income tax rate to income before income taxes. The following is a reconciliation of this difference (in thousands):

		Three Months Ended
		December 31,
		2006				2005
Income Tax Expense, Computed at Statutory Rate of 35%		$	30,532			$	32,583
Increase (Reduction) in Taxes Resulting From:
State Income Taxes			4,059				4,231
Foreign Tax Differential			(185	)			(557	)
Miscellaneous			(1,693	)			(581	)
Total Income Taxes		$	32,713			$	35,676

     Significant components of the Company’s deferred tax liabilities and assets were as follows (in thousands):

		At December 31, 2006				At September 30, 2006
Deferred Tax Liabilities:
Property, Plant and Equipment		$	581,438			$	569,677
Other			37,784				37,865
Total Deferred Tax Liabilities			619,222				607,542
Deferred Tax Assets:
Capital Loss Carryover			(8,048	)			(8,786	)
Other			(83,003	)			(86,659	)
Total Deferred Tax Assets			(91,051	)			(95,445	)
Total Net Deferred Income Taxes		$	528,171			$	512,097
Presented as Follows:
Net Deferred Tax Asset — Current		$	(16,533	)		$	(23,402	)
Net Deferred Tax Asset — Non-Current			(6,885	)			(9,003	)
Net Deferred Tax Liability — Non-Current			551,589				544,502
Total Net Deferred Income Taxes		$	528,171			$	512,097

     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 $10.4 million at both December 31, 2006 and September 30, 2006. 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 $79.3 million and $79.5 million at December 31, 2006 and September 30, 2006, respectively.

     A capital loss carryover of $23.0 million existed at December 31, 2006, which expires if not utilized by September 30, 2008. Although realization is not assured, management determined that it is more likely than not that the entire deferred tax asset associated with this carryover will be realized during the carryover period, and as such, no valuation allowance has been provided at December 31, 2006.

     A deferred tax asset of $6.9 million and $9.0 million relating to Canadian operations existed at December 31, 2006 and September 30, 2006, respectively. Although realization is not assured, management determined that it is more likely than not that future taxable income will be generated in Canada to fully utilize this asset, and as such, no valuation allowance has been provided.

Item 1. Financial Statements (Cont.)

Note 3 — Capitalization

Common Stock. During the three months ended December 31, 2006, the Company issued 545,596 original issue shares of common stock as a result of stock option exercises and 15,000 original issue shares for restricted stock awards (non-vested stock as defined in SFAS 123R). The Company also issued 2,100 original issue shares of common stock to the non-employee directors of the Company as partial consideration for the directors’ services during the three months ended December 31, 2006. Holders of stock options or restricted stock will often tender shares of common stock to the Company for payment of option exercise prices and/or applicable withholding taxes. During the three months ended December 31, 2006, 156,862 shares of common stock were tendered to the Company for such purposes. The Company considers all shares tendered as cancelled shares restored to the status of authorized but unissued shares, in accordance with New Jersey law.

     On December 8, 2005, the Company’s Board of Directors authorized the Company to implement a share repurchase program, whereby the Company may repurchase outstanding shares of common stock, up to an aggregate amount of 8 million shares in the open market or through privately negotiated transactions. During the three months ended December 31, 2006, the Company repurchased 1,183,928 shares for $42.9 million under this program, funded with cash provided by operating activities and/or through the use of the Company’s bi-lateral lines of credit. Since the share repurchase program was implemented, the Company has repurchased 3,710,478 shares for $128.1 million.

Long-Term Debt. On December 8, 2006, the Company repaid $22.8 million of Empire’s secured debt. Such amount was classified as Current Portion of Long-Term Debt on the Company’s Consolidated Balance Sheet at September 30, 2006.

Note 4 — Commitments and Contingencies

Environmental Matters. The Company is subject to various federal, state and local laws and regulations relating to the protection of the environment. The Company has established procedures for the ongoing evaluation of its operations 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, 2006, the Company has estimated its remaining clean-up costs related to former manufactured gas plant sites and third party waste disposal sites will be $3.6 million. This liability has been recorded on the Consolidated Balance Sheet at December 31, 2006. The Company expects to recover its environmental clean-up costs from a combination of rate recovery and insurance proceeds. The Company is currently not aware of any material exposure to environmental liabilities. However, adverse changes in environmental regulations or other factors could impact the Company.

Other. The Company is involved in other litigation and regulatory matters arising in the normal course of business. These other matters may include, for example, negligence claims and tax, regulatory or other governmental audits, inspections, investigations and other proceedings. These matters may involve state and federal taxes, safety, compliance with regulations, rate base, cost of service and purchased gas cost issues, among other things. While these normal-course matters could have a material effect on earnings and cash flows in the quarterly and annual period in which they are resolved, they are not expected to change materially the Company’s present liquidity position, nor to have a material adverse effect on the financial condition of the Company.

Note 5 — Business Segment Information

     The Company has five reportable segments: Utility, Pipeline and Storage, Exploration and Production, Energy Marketing, and Timber. The division of the Company’s operations into the reportable segments is based upon a combination of factors including differences in products and services, regulatory environment and geographic factors.

Item 1. Financial Statements (Cont.)

          The data presented in the tables below reflect the reportable segments and reconciliations to consolidated amounts. As stated in the 2006 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 Company’s 2006 Form 10-K. There have been no material changes in the amount of assets for any operating segment from the amounts disclosed in the 2006 Form 10-K.

Quarter Ended December 31, 2006 (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		$	288,782			$	29,809			$	88,709			$	83,318			$	11,763			$	502,381			$	1,676				$183			$	504,240
Intersegment Revenues			$4,029			$	20,368			$	—			$	—			$	—				$24,397			$	2,198			$	(26,595	)		$	—
Segment Profit:
Net Income			$17,174			$	13,688			$	20,723				$492				$217				$52,294				$985				$1,241				$54,520

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

     Note 6 — Intangible Assets

          The components of the Company’s intangible assets were as follows (in thousands):

Item 1. Financial Statements (Cont.)

														At September 30,
		At December 31, 2006												2006
		Gross								Net				Net
		Carrying				Accumulated				Carrying				Carrying
		Amount				Amortization				Amount				Amount
Intangible Assets Subject to Amortization:
Long-Term Transportation Contracts		$	8,580			$	(4,187	)		$	4,393			$	4,660
Long-Term Gas Purchase Contracts			31,864				(5,424	)			26,440				26,838
		$	40,444			$	(9,611	)		$	30,833			$	31,498
Aggregate Amortization Expense (Thousands)
Three Months Ended December 31, 2006		$	665
Three Months Ended December 31, 2005		$	666

     The gross carrying amount of intangible assets subject to amortization at December 31, 2006 remained unchanged from September 30, 2006. The only activity with regard to intangible assets subject to amortization was amortization expense as shown in the table above. Amortization expense for the transportation contracts is estimated to be $0.8 million for the remainder of 2007 and $1.1 million and $0.5 million for 2008 and 2009, respectively. Amortization expense for transportation contracts is estimated to be $0.4 million for 2010 and 2011. Amortization expense for the long-term gas purchase contracts is estimated to be $1.2 million for the remainder of 2007 and $1.6 million annually for 2008, 2009, 2010 and 2011.

Note 7 — Retirement Plan and Other Post-Retirement Benefits

     Components of Net Periodic Benefit Cost (in thousands):

Three months ended December 31,

		Retirement Plan								Other Post-Retirement Benefits
		2006				2005				2006				2005
Service Cost		$	3,225			$	4,104			$	1,403			$	2,007
Interest Cost			11,088				10,049				6,800				6,701
Expected Return on Plan Assets			(12,809	)			(12,486	)			(6,740	)			(5,576	)
Amortization of Prior Service Cost			220				239				1				1
Amortization of Transition Amount			—				—				1,782				1,782
Amortization of Losses			3,382				5,777				2,053				5,850
Net Amortization and Deferral
For Regulatory Purposes (Including Volumetric Adjustments) (1)			155				(1,528	)			2,339				(2,684	)
Net Periodic Benefit Cost		$	5,261			$	6,155			$	7,638			$	8,081

Employer Contributions. During the three months ended December 31, 2006, the Company contributed $11.9 million to its other post-retirement benefit plan. In the remainder of 2007, the Company expects to contribute in the range of $15.0 million to $25.0 million to its retirement plan and to contribute in the range of $25.0 million to $35.0 million to its other post-retirement benefit plan.

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

OVERVIEW

     The Company is a diversified energy company consisting of five reportable business segments. For the quarter ended December 31, 2006 compared to the quarter ended December 31, 2005, the Company has experienced an overall decrease in earnings of $2.9 million primarily due to lower earnings in the Utility, Pipeline and Storage, Energy Marketing, and Timber segments. Higher earnings in the Exploration and Production segment and Corporate and All Other category partially offset these decreases. The Company’s earnings are discussed further in the Results of Operations section that follows.

     From a capital resources and liquidity perspective, the Company spent $65.3 million on capital expenditures during the quarter ended December 31, 2006, with approximately 71% being spent in the Exploration and Production segment. This is in line with the Company’s expectations.

     The Company is still pursuing its Empire Connector project to expand its natural gas pipeline operations. On December 21, 2006, FERC issued an order granting a Certificate of Public Convenience and Necessity authorizing the construction and operation of the Empire Connector and various other related pipeline projects by other unaffiliated companies. Empire has accepted that Certificate and has also filed a request for clarification of limited aspects of the December 21, 2006 order. The targeted in-service date of the Empire Connector project is November 2008.* There are no other significant changes in the status of the project. The total cost of the Empire Connector project is estimated at $152 million. However, because of an escalation in labor and other construction-related costs caused by an increase in industry-wide demand for such services, the ultimate cost of constructing the project could be as much as 10% to 20% higher. The Company is seeking to mitigate the impact of any potential cost increases. The project is discussed further in the Capital Resources and Liquidity section that follows.

     The Company also began repurchasing outstanding shares of common stock during fiscal 2006 under a share repurchase program authorized by the Company’s Board of Directors. The program authorizes the Company to repurchase up to an aggregate amount of 8 million shares. Through December 31, 2006, the Company had repurchased 3,710,478 shares for $128.1 million under this program, including 1,183,928 shares for $42.9 million in the quarter ended December 31, 2006. These matters are discussed further in the Capital Resources and Liquidity section that follows.

     On January 29, 2007, the Company commenced a rate case in the New York rate jurisdiction of the Utility segment by filing proposed tariff amendments and supporting testimony requesting approval to increase its annual revenues by $52.0 million annually. The Company explains in the filing that its request for rate relief is necessitated by decreased revenues resulting from customer conservation efforts and increased customer uncollectibles, among other things. The rate filing also includes a proposal for an aggressive efficiency and conservation initiative with a revenue decoupling mechanism designed to render the Company indifferent to throughput reductions resulting from conservation. This matter is discussed more fully in the Rate and Regulatory Matters section.

CRITICAL ACCOUNTING ESTIMATES

     For a complete discussion of critical accounting estimates, refer to “Critical Accounting Estimates” in Item 7 of the Company’s 2006 Form 10-K. There have been no subsequent changes to that disclosure.

RESULTS OF OPERATIONS

Earnings

     The Company’s earnings were $54.5 million for the quarter ended December 31, 2006 compared to earnings of $57.4 million for the quarter ended December 31, 2005. The decrease in earnings of $2.9 million is primarily the result of lower earnings in the Utility, Pipeline and Storage, Energy Marketing, and Timber segments, somewhat offset by higher earnings in the Exploration and Production segment and

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations (Cont.)

the Corporate and All Other categories. Additional discussion of earnings in each of the business segments can be found in the business segment information that follows. Note that all amounts used in the earnings discussions are after-tax amounts.

Earnings (Loss) by Segment

										Increase
Three Months Ended December 31 (Thousands)		2006				2005				(Decrease)
Utility		$	17,174			$	21,753			$	(4,579	)
Pipeline and Storage			13,688				15,850				(2,162	)
Exploration and Production			20,723				17,435				3,288
Energy Marketing			492				987				(495	)
Timber			217				1,464				(1,247	)
Total Reportable Segments			52,294				57,489				(5,195	)
All Other			985				570				415
Corporate (1)			1,241				(640	)			1,881
Total Consolidated		$	54,520			$	57,419			$	(2,899	)

Utility

Utility Operating Revenues

										Increase
Three Months Ended December 31 (Thousands)		2006				2005				(Decrease)
Retail Sales Revenues:
Residential		$	225,432			$	344,873			$	(119,441	)
Commercial			35,635				56,890				(21,255	)
Industrial			1,901				4,452				(2,551	)
			262,968				406,215				(143,247	)
Transportation			26,876				26,916				(40	)
Other			2,967				2,469				498
		$	292,811			$	435,600			$	(142,789	)

Utility Throughput

										Increase
Three Months Ended December 31 (MMcf)		2006				2005				(Decrease)
Retail Sales:
Residential			16,678				19,524				(2,846	)
Commercial			2,868				3,443				(575	)
Industrial			192				327				(135	)
			19,738				23,294				(3,556	)
Transportation			15,853				14,342				1,511
			35,591				37,636				(2,045	)

Degree Days

														Percent
Three Months Ended														Colder (Warmer) Than
December 31		Normal				2006				2005				Normal				Prior Year
Buffalo			2,260				1,947				2,210				(13.8	)			(11.9	)
Erie			2,081				1,878				2,048				(9.8	)			(8.3	)

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations (Cont.)

2006 Compared with 2005

     Operating revenues for the Utility segment decreased $142.8 million for the quarter ended December 31, 2006 as compared with the quarter ended December 31, 2005. The $143.2 million decrease in retail gas sales was the result of the recovery of lower gas costs (gas costs are recovered dollar for dollar in revenues) and, to a lesser extent, lower throughput volumes due to warmer weather. The positive impact of the 1.5 Bcf increase in transportation throughput volumes was offset by an out-of-period adjustment of $3.9 million recorded during the quarter ended December 31, 2005. The adjustment was required 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 Corporation’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 Utility segment’s earnings for the quarter ended December 31, 2006 were $17.2 million, a decrease of $4.6 million when compared with earnings of $21.8 million for the quarter ended December 31, 2005. In the New York jurisdiction, earnings decreased $4.3 million. The major factors that contributed to the decrease were the symmetrical sharing adjustment discussed above ($2.6 million) and a decline in margin associated with lower usage per customer ($1.1 million). In the Pennsylvania jurisdiction, earnings were flat compared with the quarter ended December 31, 2005.

     The impact of weather variations on earnings in the New York jurisdiction is mitigated by that jurisdiction’s WNC. The WNC in New York, which covers the eight-month period from October through May, has had a stabilizing effect on earnings for the New York rate jurisdiction. For the quarters ended December 31, 2006 and December 31, 2005, the WNC preserved $1.5 million and $0.5 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.

Pipeline and Storage

Pipeline and Storage Operating Revenues

										Increase
Three Months Ended December 31 (Thousands)		2006				2005				(Decrease)
Firm Transportation		$	29,489			$	31,086			$	(1,597	)
Interruptible Transportation			945				1,323				(378	)
			30,434				32,409				(1,975	)
Firm Storage Service			16,402				16,248				154
Other			3,341				7,377				(4,036	)
		$	50,177			$	56,034			$	(5,857	)

Pipeline and Storage Throughput

										Increase
Three Months Ended December 31 (MMcf)		2006				2005				(Decrease)
Firm Transportation			74,427				102,822				(28,395	)
Interruptible Transportation			995				3,723				(2,728	)
			75,422				106,545				(31,123	)

2006 Compared with 2005

     Operating revenues for the Pipeline and Storage segment decreased $5.9 million in the quarter ended December 31, 2006 as compared with the quarter ended December 31, 2005. This decrease consisted primarily of a $4.0 million decrease in other revenues and a $2.0 million decrease in firm and interruptible transportation revenues. The decrease in other revenues is primarily due to a $4.0 million

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations (Cont.)

decrease in revenues from unbundled pipeline sales largely due to lower natural gas prices. Approximately $1.2 million of the decrease in firm and interruptible transportation revenues is due to the absence of hurricanes during the quarter ended December 31, 2006 as compared with the quarter ended December 31, 2005. During the quarter ended December 31, 2005, the Pipeline and Storage segment was able to gain additional contracts with customers and renew existing contracts at higher rates because of the increased demand for transportation services due to market conditions resulting from the effects of hurricane damage to production and pipeline infrastructure in the Gulf of Mexico during the fall of 2005. In addition, there was a $0.8 million decrease in transportation revenue due to a rate reduction in gathering charges and the Utility segment’s cancellation of a portion of its firm transportation capacity based on lower usage in its service territory.

     The Pipeline and Storage segment’s earnings for the quarter ended December 31, 2006 were $13.7 million, a decrease of $2.2 million when compared with earnings of $15.9 million for the quarter ended December 31, 2005. The decrease reflects the earnings impact associated with lower revenues from unbundled pipeline sales ($2.6 million), lower transportation revenues ($1.3 million), and increased interest expense ($0.6 million) associated with higher intercompany borrowings. These earnings decreases were partially offset by a $1.9 million positive earnings impact associated with the discontinuance of hedge accounting for Empire’s interest rate collar. On December 8, 2006, Empire repaid $22.8 million of secured debt. The interest costs of this secured debt were hedged by the interest rate collar. Since the hedged transaction was settled and there will be no future cash flows associated with the secured debt, the unrealized gain in accumulated other comprehensive income associated with the interest rate collar was reclassified to the income statement.

Exploration and Production

Exploration and Production Operating Revenues

										Increase
Three Months Ended December 31 (Thousands)		2006				2005				(Decrease)
Gas (after Hedging)		$	47,014			$	49,341			$	(2,327	)
Oil (after Hedging)			38,325				29,395				8,930
Gas Processing Plant			8,629				13,419				(4,790	)
Other			591				1,524				(933	)
Intrasegment Elimination (1)			(5,850	)			(11,592	)			5,742
		$	88,709			$	82,087			$	6,622

Production Volumes

										Increase
Three Months Ended December 31		2006				2005				(Decrease)
Gas Production (MMcf)
Gulf Coast			2,723				1,667				1,056
West Coast			944				1,018				(74	)
Appalachia			1,394				1,253				141
Canada			1,721				1,911				(190	)
			6,782				5,849				933
Oil Production (Mbbl)
Gulf Coast			202				107				95
West Coast			591				685				(94	)
Appalachia			27				10				17
Canada			56				87				(31	)
			876				889				(13	)

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations (Cont.)

Average Prices

										Increase
Three Months Ended December 31		2006				2005				(Decrease)
Average Gas Price/Mcf
Gulf Coast		$	6.55			$	10.74			$	(4.19	)
West Coast		$	6.09			$	11.08			$	(4.99	)
Appalachia		$	7.22			$	13.62			$	(6.40	)
Canada		$	6.39			$	10.76			$	(4.37	)
Weighted Average		$	6.58			$	11.42			$	(4.84	)
Weighted Average After Hedging		$	6.93			$	8.44			$	(1.51	)
Average Oil Price/Bbl
Gulf Coast		$	56.51			$	57.90			$	(1.39	)
West Coast (1)		$	51.11			$	51.34			$	(0.23	)
Appalachia		$	59.78			$	61.53			$	(1.75	)
Canada		$	42.58			$	43.18			$	(0.60	)
Weighted Average		$	52.08			$	51.45			$	0.63
Weighted Average After Hedging		$	43.74			$	33.07			$	10.67

2006 Compared with 2005

     Operating revenues for the Exploration and Production segment increased $6.6 million for the quarter ended December 31, 2006 as compared with the quarter ended December 31, 2005. Gas production revenue after hedging decreased $2.3 million. A decrease in the weighted average price of gas after hedging ($1.51 per Mcf) more than offset an overall increase in gas production (933 MMcf). Oil production revenue after hedging increased $8.9 million. An increase in the weighted average price of oil after hedging ($10.67 per bbl) was the primary cause, as production remained relatively flat. The increase in the weighted average price after hedging is largely due to the fact that the Exploration and Production segment hedged significantly less production during the quarter ended December 31, 2006 as compared to the quarter ended December 31, 2005. While oil prices did not change significantly quarter over quarter, many of the lower priced hedges during the quarter ended December 31, 2005 had expired, and were not replaced, resulting in an increase to the weighted average oil price (after hedging) received for this segment’s oil production during the quarter ended December 31, 2006. Most of the increase in gas production occurred in the Gulf Coast region (1,056 MMcf). During the quarter ended December 31, 2005, Seneca experienced significant production delays due largely to the impact of hurricane damage to pipeline infrastructure in the Gulf of Mexico. During the quarter ended December 31, 2006, Seneca had substantially all of its pre-hurricane Gulf of Mexico production back on line.

     The Exploration and Production segment’s earnings for the quarter ended December 31, 2006 were $20.7 million compared with earnings of $17.4 million for the quarter ended December 31, 2005. The increase is primarily attributable to the positive impact of higher crude oil revenues as discussed above ($5.8 million), partially offset by the negative impact of lower natural gas revenues, as discussed above ($1.5 million).

Energy Marketing

Energy Marketing Operating Revenues

										Increase
Three Months Ended December 31 (Thousands)		2006				2005				(Decrease)
Natural Gas (after Hedging)		$	83,270			$	145,523			$	(62,253	)
Other			48				37				11
		$	83,318			$	145,560			$	(62,242	)

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations (Cont.)

Energy Marketing Volumes

										Increase
Three Months Ended December 31		2006				2005				(Decrease)
Natural Gas — (MMcf)			11,116				9,975				1,141

2006 Compared with 2005

     Operating revenues for the Energy Marketing segment decreased $62.2 million for the quarter ended December 31, 2006 as compared with the quarter ended December 31, 2005. This decrease primarily reflects lower gas sales revenue due to a decrease in the price of natural gas commodity prices that were recovered through revenues, partially offset by an increase in throughput. The increase in throughput was due to the addition of certain large, low-margin industrial customers, offset in part by a decrease in wholesale natural gas sales to other energy marketing companies.

     The Energy Marketing segment’s earnings decreased $0.5 million from $1.0 million for the quarter ended December 31, 2005 to $0.5 million for the quarter ended December 31, 2006. Per unit gross margins declined, largely due to the higher cost of gas storage and transportation services as well as the impact of the addition of certain large, but low-margin industrial customers.

Timber

Timber Operating Revenues

										Increase
Three Months Ended December 31 (Thousands)		2006				2005				(Decrease)
Log Sales		$	4,065			$	6,256			$	(2,191	)
Green Lumber Sales			918				1,462				(544	)
Kiln Dry Lumber Sales			6,270				8,500				(2,230	)
Other			510				713				(203	)
Operating Revenues		$	11,763			$	16,931			$	(5,168	)

Timber Board Feet

										Increase
Three Months Ended December 31 (Thousands)		2006				2005				(Decrease)
Log Sales			1,709				2,491				(782	)
Green Lumber Sales			1,530				1,974				(444	)
Kiln Dry Lumber Sales			3,157				4,486				(1,329	)
			6,396				8,951				(2,555	)

2006 Compared with 2005

     Operating revenues for the Timber segment decreased $5.2 million for the quarter ended December 31, 2006 as compared with the quarter ended December 31, 2005. The decrease in revenues can be attributed to unfavorable weather conditions during the quarter ended December 31, 2006 that greatly diminished the harvesting of logs. These conditions consisted of warm, wet weather that made it difficult to bring logging trucks into the forests. Weather conditions were significantly more favorable during the quarter ended December 31, 2005. These unfavorable conditions for harvesting resulted in a decline in log sales of $2.2 million or 782,000 board feet. There was also a decline in both green lumber and kiln dry lumber sales of $0.5 million and $2.2 million, respectively, since there were fewer logs available for processing.

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations (Cont.)

     The Timber segment’s earnings for the quarter ended December 31, 2006 were $0.2 million, a decrease of $1.3 million when compared with earnings of $1.5 million for the quarter ended December 31, 2005. The decrease was primarily due to lower margins from lumber and log sales ($1.7 million) as a result of the decline in revenues noted above. This decrease was partially offset by a decline in depletion expense of $0.4 million.

Corporate and All Other

2006 Compared with 2005

     Corporate and All Other operations recorded earnings of $2.2 million for the quarter ended December 31, 2006 compared with a loss of $0.1 million for the quarter ended December 31, 2005. This improvement was largely due to an increase in intercompany interest income. On a consolidated basis, all significant intercompany balances and transactions are eliminated.

Interest Charges

     Interest on long-term debt decreased $2.2 million for the quarter ended December 31, 2006 as compared with the quarter ended December 31, 2005. This decrease can be attributed to a $1.9 million benefit to interest expense as a result of the discontinuance of hedge accounting for Empire’s interest rate collar, as discussed above under Pipeline and Storage. The underlying long-term debt associated with this interest rate collar was repaid during the current quarter and the unrealized gain recorded in accumulated other comprehensive income associated with the interest rate collar was reclassified to interest expense.

CAPITAL RESOURCES AND LIQUIDITY

     The Company’s primary source of cash during the three-month period ended December 31, 2006 consisted of short-term borrowings and cash provided by operating activities. This source of cash was supplemented by issuances of new shares of common stock as a result of the exercise of stock options. During the three months ended December 31, 2006, the common stock used to fulfill the requirements of the Company’s 401(k) plans and Direct Stock Purchase and Dividend Reinvestment Plan was obtained via open market purchases. During 2006, the Company began repurchasing outstanding shares of its common stock under a share repurchase program, which is discussed below under Financing Cash Flow.

Operating Cash Flow

     Internally generated cash from operating activities consists of net income available for common stock, adjusted for non-cash expenses, non-cash income and changes in operating assets and liabilities. Non-cash items include depreciation, depletion and amortization, deferred income taxes, and income or loss from unconsolidated subsidiaries net of cash distributions.

     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.

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations (Cont.)

     The storage gas inventory normally declines during the first and second quarters of the fiscal year and is replenished during the third and fourth quarters. For storage gas inventory accounted for under the LIFO method, the current cost of replacing gas withdrawn from storage is recorded in the Consolidated Statements of Income and a reserve for gas replacement is recorded in the Consolidated Balance Sheets under the caption “Other Accruals and Current Liabilities.” Such reserve is reduced as the inventory is replenished.

     Cash provided by operating activities in the Exploration and Production segment may vary from period to period as a result of changes in the commodity prices of natural gas and crude oil. The Company uses various derivative financial instruments, including price swap agreements and no cost collars, options and futures contracts in an attempt to manage this energy commodity price risk.

     Net cash provided by operating activities totaled $43.0 million for the three months ended December 31, 2006, an increase of $22.4 million when compared with the $20.6 million provided by operating activities for the three months ended December 31, 2005. The timing of gas cost recovery in the Utility segment for the quarter ended December 31, 2006 as compared to the quarter ended December 31, 2005 is primarily responsible for the increase.

Investing Cash Flow

Expenditures for Long-Lived Assets

     The Company’s expenditures for long-lived assets totaled $67.0 million during the three months ended December 31, 2006. The table below presents these expenditures:

Three Months Ended December 31, 2006
(in millions of dollars)
										Total
		Capital				Investment				Expenditures for
		Expenditures				in Partnership				Long-Lived Assets
Utility		$	12.9			$	—			$	12.9
Pipeline and Storage			4.9				—				4.9
Exploration and Production			46.6				—				46.6
Timber			0.8				—				0.8
Corporate and All Other			0.1				1.7				1.8
		$	65.3			$	1.7			$	67.0

Utility

     The majority of the Utility capital expenditures for the three months ended December 31, 2006 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, 2006 were made for additions, improvements, and replacements to this segment’s transmission and gas storage systems.

     The Company continues to explore various opportunities to expand its capabilities to transport gas to the East Coast, either through the Supply Corporation or Empire systems or in partnership with others. In October 2005, Empire filed an application with the FERC for the authority to build and operate the Empire Connector project to expand its natural gas pipeline operations to serve new markets in New York and elsewhere in the Northeast by extending the Empire Pipeline. The application also asked that

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations (Cont.)

Empire’s existing business and facilities be brought under FERC jurisdiction, and that FERC approve rates for Empire’s existing and proposed services. Assuming the proposed Millennium Pipeline is constructed, the Empire Connector will provide an upstream supply link for 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.* The targeted in-service date is November 2008.* FERC issued on December 21, 2006 an order granting a Certificate of Public Convenience and Necessity authorizing the construction and operation of the Empire Connector and various other related pipeline projects by other unaffiliated companies. Refer to the Rate and Regulatory Matters section that follows for further discussion of this matter. The total cost of the Empire Connector project is estimated at $152 million. However, because of an escalation in labor and other construction-related costs caused by an increase in industry-wide demand for such services, the ultimate cost of constructing the project could be as much as 10% to 20% higher. The Company is seeking to mitigate the impact of any potential cost increases by a combination of competitive bidding and seeking partnering arrangements with its contractors. Further, as discussed in the Rate and Regulatory Matters section that follows, the Company is also seeking sales and property tax abatements as a means of offsetting the impact of rising construction costs. 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, 2006, the Company had incurred approximately $6.3 million in costs (all of which have been reserved) related to this project. Of this amount, $0.4 million and $0.7 million were incurred during the quarters ended December 31, 2006 and December 31, 2005, respectively. The Company will continue to reserve for project related costs until such time as a final service agreement is signed with KeySpan, which is expected to be completed in the spring of 2007.* At such time, the Company anticipates reversing the reserve that has been established since it believes that such costs will be recovered as part of rate base.*

     The Company also has plans to expand Supply Corporation’s existing interconnect with Empire at Pendleton, New York. Compression will be added to allow Supply Corporation transportation and storage volumes to be delivered to Empire, which is operated at higher pressures than Supply Corporation’s system.* The Pendleton Compression project will be a key strategic expansion for Supply Corporation, allowing access to both Empire and Millennium markets to the east, as well as for Empire, providing its shippers with access to storage services and Supply Corporation’s array of interconnects. Supply Corporation is in the process of negotiating customer agreements, and expects to complete design and launch the regulatory approval process in 2007.* There have been no costs incurred by the Company related to this project as of December 31, 2006. The target in-service date for the Pendleton Compression project is contingent upon the Millennium/Empire Connector timeline.* Accordingly, Supply Corporation anticipates that most of the capital spending associated with this expansion will occur in fiscal 2008.*

     Supply Corporation continues to view the Tuscarora Extension project as an important link to Millennium and potential storage development in the Corning, New York area.* The new pipeline, which would expand the Supply Corporation system from its Tuscarora storage field to the intersection of the proposed Millennium and Empire Connector pipelines, will be designed initially to transport up to approximately 130 MDth of natural gas per day. It may also provide Supply Corporation with the opportunity to increase the deliverability of the existing Tuscarora storage field.* The project timeline relies on market development, and should the market mature, the Company anticipates financing the Tuscarora Extension with cash on hand and/or through the use of the Company’s bi-lateral lines of credit.* There have been no costs incurred by the Company related to this project as of December 31, 2006. The Company has not yet filed an application with the FERC for the authority to build and operate the Tuscarora Extension.

Exploration and Production

     The Exploration and Production segment capital expenditures for the three months ended December 31, 2006 included approximately $9.3 million for Canada, $21.1 million for the Gulf Coast region ($19.2 million for the off-shore program in the Gulf of Mexico), $11.8 million for the West Coast

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations (Cont.)

region and $4.4 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, plus projected royalty relief. These amounts included approximately $8.4 million spent to develop proved undeveloped reserves.

Timber

     The majority of the Timber segment capital expenditures for the three months ended December 31, 2006 were made for purchases of equipment for Highland’s sawmill and kiln operations.

Corporate and All Other

     The majority of the Corporate and All Other category expenditures for long-lived assets for the three months ended December 31, 2006 consisted of a $1.65 million capital contribution to Seneca Energy by Horizon Power. Seneca Energy generates and sells electricity using methane gas obtained from landfills owned by outside parties. Seneca Energy is in the process of expanding its generating capacity from 11.2 megawatts to 17.6 megawatts. In January 2007, Horizon Power contributed an additional $1.65 million towards the expansion. Horizon Power has funded its capital contributions with short-term borrowings.

     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.*

Financing Cash Flow

     Consolidated short-term debt increased $71.6 million during the three months ended December 31, 2006. The Company continues to consider short-term debt (consisting of short-term notes payable to banks and commercial paper) an important source of cash for temporarily financing capital expenditures and investments in corporations and/or partnerships, gas-in-storage inventory, unrecovered purchased gas costs, margin calls on derivative financial instruments, exploration and development expenditures, repurchases of stock, 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, 2006, the Company had outstanding short-term notes payable to banks and commercial paper of $41.5 million and $30.1 million, respectively. 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. These credit lines, which aggregate to $455.0 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, or replaced by similar lines.* The total amount available to be issued under the Company’s commercial paper program is $300.0 million. The commercial paper program is backed by a syndicated committed credit facility totaling $300.0 million that extends through September 30, 2010.

     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, 2006, the Company’s debt to capitalization ratio (as calculated under the facility) was .45. The constraints specified in the committed credit facility would permit an additional $1.53 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.*

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations (Cont.)

     Under the Company’s existing indenture covenants, at December 31, 2006, the Company would have been permitted to issue up to a maximum of $1.1 billion in additional long-term unsecured indebtedness at then-current market interest rates in addition to being able to issue new indebtedness to replace maturing debt. The Company’s present liquidity position is believed to be adequate to satisfy known demands.*

     The Company’s 1974 indenture, pursuant to which $399.0 million (or 36%) of the Company’s long-term debt (as of December 31, 2006) was issued, contains a cross-default provision whereby the failure by the Company to perform certain obligations under other borrowing arrangements could trigger an obligation to repay the debt outstanding under the indenture. In particular, a repayment obligation could be triggered if the Company fails (i) to pay any scheduled principal or interest on any debt under any other indenture or agreement or (ii) to perform any other term in any other such indenture or agreement, and the effect of the failure causes, or would permit the holders of the debt to cause, the debt under such indenture or agreement to become due prior to its stated maturity, unless cured or waived.

     The Company’s $300.0 million committed credit facility also contains a cross-default provision whereby the failure by the Company or its significant subsidiaries to make payments under other borrowing arrangements, or the occurrence of certain events affecting those other borrowing arrangements, could trigger an obligation to repay any amounts outstanding under the committed credit facility. In particular, a repayment obligation could be triggered if (i) the Company or 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, 2006, the Company had no debt outstanding under the committed credit facility.

     The Company has an effective registration statement on file with the SEC under which it has available capacity to issue an additional $550.0 million of debt and equity securities under the Securities Act of 1933. The Company may sell all or a portion of the remaining registered securities if warranted by market conditions and the Company’s capital requirements. Any offer and sale of the above mentioned $550.0 million of debt and equity securities will be made only by means of a prospectus meeting the requirements of the Securities Act of 1933 and the rules and regulations thereunder.

     The amounts and timing of the issuance and sale of debt or equity securities will depend on market conditions, indenture requirements, regulatory authorizations and the capital requirements of the Company.

     On December 8, 2005, the Company’s Board of Directors authorized the Company to implement a share repurchase program, whereby the Company may repurchase outstanding shares of common stock, up to an aggregate amount of 8 million shares in the open market or through privately negotiated transactions. As of December 31, 2006, the Company has repurchased 3,710,478 shares for $128.1 million under this program, including 1,183,928 shares for $42.9 million during the quarter ended December 31, 2006, funded with cash provided by operating activities and/or through the use of the Company’s bi-lateral lines of credit. In the future, it is expected that this share repurchase program will continue to be funded with cash provided by operating activities and/or through the use of the Company’s bi-lateral lines of credit.* It is expected that open market repurchases will continue from time to time depending on market conditions.*

OFF-BALANCE SHEET ARRANGEMENTS

     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 $41.5 million. These leases have been entered into for the use of buildings, vehicles, construction tools, meters, computer equipment and other items and are accounted for as operating leases. The Company’s unconsolidated subsidiaries,

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations (Cont.)

which are accounted for under the equity method, have capital leases of electric generating equipment having a remaining lease commitment of approximately $6.1 million. The Company has guaranteed 50% or $3.0 million of these capital lease commitments.

OTHER MATTERS

     In addition to the legal proceedings disclosed in Part II, Item 1 of this report, the Company is involved in other litigation and regulatory matters arising in the normal course of business. These other matters may include, for example, negligence claims and tax, regulatory or other governmental audits, inspections, investigations or other proceedings. These matters may involve state and federal taxes, safety, compliance with regulations, rate base, cost of service and purchased gas cost issues, among other things. While these normal-course matters could have a material effect on earnings and cash flows in the quarterly and annual period in which they are resolved, they are not expected to change materially the Company’s present liquidity position, nor to have a material adverse effect on the financial condition of the Company.*

Market Risk Sensitive Instruments

     For a complete discussion of market risk sensitive instruments, refer to “Market Risk Sensitive Instruments” in Item 7 of the Company’s 2006 Form 10-K. There have been no subsequent material changes to the Company’s exposure to market risk sensitive instruments.

Rate and Regulatory Matters

Utility Operation

     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.

New York Jurisdiction

     On August 27, 2004, Distribution Corporation commenced a rate case by filing proposed tariff amendments and supporting testimony requesting approval to increase its annual revenues beginning October 1, 2004. Various parties opposed the filing. On April 15, 2005, Distribution Corporation, the parties and others executed an agreement settling all outstanding issues. In an order issued July 22, 2005, the NYPSC approved the April 15, 2005 settlement agreement, substantially as filed, for an effective date of August 1, 2005. The settlement agreement provides for a rate increase of $21 million by means of the elimination of bill credits ($5.8 million) and an increase in base rates ($15.2 million). For the two-year term of the agreement and thereafter, the return on equity level above which earnings must be shared with rate payers is 11.5%.

     On January 29, 2007, Distribution Corporation commenced a rate case by filing proposed tariff amendments and supporting testimony requesting approval to increase its annual revenues by $52.0 million. It is anticipated that following standard procedure, the NYPSC will suspend the proposed tariff amendments through late December 2007 to enable its staff and intervenors to conduct a routine investigation and hold hearings. Distribution Corporation explains in the filing that its request for rate relief is necessitated by decreased revenues resulting from customer conservation efforts and increased customer uncollectibles, among other things. The rate filing also includes a proposal for an aggressive efficiency and conservation initiative with a revenue decoupling mechanism designed to render the company indifferent to throughput reductions resulting from conservation. The NYPSC may accept, reject or modify the Company’s filing. The outcome of the proceeding cannot be ascertained at this time.

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations (Cont.)

Pennsylvania Jurisdiction

     On June 1, 2006, Distribution Corporation filed proposed tariff amendments with PaPUC to increase annual revenues by $25.9 million to cover increases in the cost of service to be effective July 30, 2006. The rate request was filed to address increased costs associated with Distribution Corporation’s ongoing construction program as well as increases in operating costs, particularly uncollectible accounts. Following standard regulatory procedure, the PaPUC issued an order on July 20, 2006 instituting a rate proceeding and suspending the proposed tariff amendments until March 2, 2007.* On October 2, 2006, the parties, including Distribution Corporation, Staff of the PaPUC and intervenors, executed an agreement (Settlement) proposing to settle all issues in the rate proceeding. The Settlement includes an increase in annual revenues of $14.3 million to non-gas revenues, an agreement not to file a rate case until January 28, 2008 at the earliest and an early implementation date. The Settlement was approved by the PaPUC at its meeting on November 30, 2006, and the new rates became effective January 1, 2007.

     On June 8, 2006, the NTSB issued safety recommendations to Distribution Corporation as a result of an investigation of a natural gas explosion that occurred on Distribution Corporation’s system in Dubois, Pennsylvania in August 2004. The explosion destroyed a residence, resulting in the death of two people who lived there, and damaged a number of other houses in the immediate vicinity.

     The NTSB and Distribution Corporation differ in their assessment of the probable cause of the explosion. The NTSB determined that the probable cause was the fracture of a defective “butt-fusion joint” which had joined two sections of plastic pipe, and the failure of Distribution Corporation to have an adequate program to inspect butt-fusion joints and replace those joints not meeting its inspection criteria. Distribution Corporation had submitted to the NTSB a proposed determination of probable cause that was substantially different, namely, that the probable cause was the improper excavation and backfill operations of a third party that had worked in the vicinity of Distribution Corporation’s pipeline. Distribution Corporation also had raised issues concerning the testing standards employed in the NTSB investigation. The NTSB has noted Distribution Corporation’s disagreement with the NTSB’s finding of probable cause and has forwarded to its pipeline staff the information provided by Distribution Corporation. Distribution Corporation is considering alternatives by which to seek review of the NTSB’s findings and conclusions to ensure that the NTSB considered all relevant evidence, including the report of Distribution Corporation’s third-party plastic pipe expert and other relevant evidence, in reaching its determination of probable cause.

     The NTSB’s safety recommendations to Distribution Corporation involved revisions to its butt-fusion procedures for joining plastic pipe, and revisions to its procedures for qualifying personnel who perform plastic fusions. Although not required by law to do so, Distribution Corporation implemented those recommendations. In December 2006, the NTSB classified its recommendations as “closed” after determining that Distribution Corporation took acceptable action with respect to the recommendations.

     The NTSB also issued safety recommendations to the PaPUC and certain other parties. The recommendation to the PaPUC was to require an analysis of the integrity of butt-fusion joints in Distribution Corporation’s system and replacement of those joints that are determined to have unacceptable characteristics. Distribution Corporation is working cooperatively with the Staff of the PaPUC to permit the PaPUC to undertake the analysis recommended by the NTSB. Specifically, Distribution has done the following, in agreement with the PaPUC Staff:

	(i)		Distribution Corporation uncovered a limited number of butt-fusions at two locations designated by the PaPUC Staff;
	(ii)		Commencing July 6, 2006, Distribution Corporation has uncovered additional butt-fusions throughout its Pennsylvania service area as it has uncovered facilities for other purposes; when a butt-fusion has been uncovered, Distribution Corporation has notified the designated PaPUC Staff representative to permit inspection of the quality of the fusion. Distribution Corporation has removed a number of fusions for further evaluation.

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations (Cont.)

     Distribution Corporation met with the PaPUC Staff in August 2006 to review findings to date and to discuss further procedures to facilitate the analysis. Distribution Corporation and the PaPUC Staff agreed to submit several of the butt-fusion specimens removed during the inspection process to an independent testing laboratory to assess the integrity of the fusions (and to provide an evaluation of the sampling procedure employed). Distribution Corporation and the PaPUC Staff have agreed upon procedures to test the butt-fusion specimens. Distribution Corporation anticipates that it will continue to meet with the PaPUC Staff to review findings pertaining to this matter and address any integrity concerns that may be identified.* At this time, Distribution Corporation is unable to predict the outcome of the analysis or of any negotiations or proceedings that may result from it. Distribution Corporation’s response to the actions of the PaPUC will depend on its assessment of the validity of the PaPUC’s analysis and conclusions.

     Without admitting liability, Distribution Corporation has settled all significant third-party claims against it related to the explosion, for amounts that are immaterial in the aggregate to the Company. Distribution Corporation has been committed to providing safe and reliable service throughout its service territory and firmly believes, based on information presently known, that its system continues to be safe and reliable. According to the Plastics Pipe Institute, plastic pipe today accounts for over 90% of the pipe installed for the natural gas distribution industry in the United States and Canada. Distribution Corporation, along with many other natural gas utilities operating in the United States, has relied extensively upon the use of plastic pipe in its natural gas distribution system since the 1970s.

Pipeline and Storage

     On April 7, 2006, the NYPSC, PaPUC and Pennsylvania Office of Consumer Advocate filed a complaint and a motion for summary disposition against Supply Corporation with the FERC under Sections 5(a) and 13 of the Natural Gas Act (NGA). The complainants alleged that Supply Corporation’s rates were unjust and unreasonable, and that Supply Corporation was permitted to retain more gas from shippers than is necessary for fuel and loss. As a result, the complainants alleged, Supply Corporation has excess annual earnings of approximately $30 million to $35 million. An uncontested settlement of this complaint is awaiting FERC approval to become final.

     In their complaint, the complainants asked FERC (i) to find that Supply Corporation’s rates are unjust and unreasonable, and (ii) to institute proceedings to determine the just and reasonable rates Supply Corporation will be authorized to charge prospectively. The complainants also asked FERC in their complaint (i) to determine whether Supply Corporation has the authority to make sales of gas retained from shippers, and (ii) if FERC concludes that Supply Corporation does not have such authority, to direct Supply Corporation to show cause why it should not be required to disgorge profits associated with such sales.

     After considerable motion practice, discovery and negotiation, Supply Corporation filed on November 17, 2006, a motion asking FERC to approve an uncontested settlement of all the issues raised or which could have been raised in the proceeding. The proposed settlement would be implemented when and if FERC approves the settlement, but if approved would be effective as of December 1, 2006. On December 20, 2006, the presiding Administrative Law Judge certified the settlement to FERC for final approval. The principal elements of the settlement and the procedural history of the case were all detailed in the Company’s 2006 Form 10-K. The Company’s earnings guidance is based on Supply Corporation’s expectation that the settlement will be approved by the FERC and become effective according to its terms.*

     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

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations (Cont.)

business, effective upon Empire accepting the FERC certificate and placing its new facilities into service (currently targeted for November 2008). At that time, Empire would become an interstate pipeline subject to FERC regulation.*

     The FERC issued on December 21, 2006 an order granting a Certificate of Public Convenience and Necessity authorizing the construction and operation of the Empire Connector and various other related pipeline projects by other unaffiliated companies. That order, in part, largely accepts Empire’s September 18, 2006 rate and tariff related compliance filing that was described in the Company’s 2006 Form 10-K, and also contains various environmental and other conditions. Empire has accepted that Certificate and has also filed a request for clarification (or, in the alternative, rehearing) of limited aspects of the December 21, 2006 order. Additional environmental permits from the U.S. Army Corps of Engineers and state environmental agencies will also be required.* Empire is also seeking from six counties in upstate New York sales tax abatements and temporary partial property tax abatements necessary to enable the Empire Connector to generate a fair return, in light of construction costs expected to exceed the costs anticipated in Empire’s 2005 application to build this project for a 2007 in-service date.* The Company expects that all the necessary permits and abatements will be obtained and accepted, that firm service agreements will be signed, that acceptable proposals for materials and construction-related services will be received, and that the Empire Connector project will be built and in service by November 2008.*

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. The Company has estimated its remaining clean-up costs related to former manufactured gas plant sites and third party waste disposal site will be $3.6 million.* This liability has been recorded on the Consolidated Balance Sheet at December 31, 2006. The Company expects to recover its environmental clean-up costs from a combination of rate recovery and insurance proceeds.* The Company is currently not aware of any material exposure to environmental liabilities. However, adverse changes in environmental regulations or other factors could impact the Company.*

New Accounting Pronouncements

     In July 2006, the FASB issued FIN 48. FIN 48 clarifies the accounting for income taxes by prescribing a minimum probability threshold that a tax position must meet before a financial statement benefit is recognized. The minimum threshold is defined in FIN 48 as a tax position that is more likely than not to be sustained upon examination by the applicable taxing authority, including resolution of any related appeals or litigation processes, based on the technical merits of the position. The cumulative effect of applying FIN 48 at adoption, if any, is to be reported as an adjustment to opening retained earnings for the year of adoption. FIN 48 is effective for the first quarter of the Company’s 2008 fiscal year. The Company is currently assessing the potential effect of FIN 48 on its consolidated financial statements.

     In September 2006, the FASB issued SFAS 157. SFAS 157 provides guidance for using fair value to measure assets and liabilities. The pronouncement serves to clarify the extent to which companies measure assets and liabilities at fair value, the information used to measure fair value, and the effect that fair-value measurements have on earnings. The Company is currently evaluating the impact that the adoption of SFAS 157 will have on its consolidated financial statements. SFAS 157 is to be applied whenever another standard requires or allows assets or liabilities to be measured at fair value. The pronouncement is effective as of the Company’s first quarter of fiscal 2009.

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations (Cont.)

     In September 2006, the FASB issued SFAS 158, an amendment of SFAS 87, SFAS 88, SFAS 106, and SFAS 132R. SFAS 158 requires that companies recognize a net liability or asset to report the underfunded or overfunded status of their defined benefit pension and other post-retirement benefit plans on their balance sheets, as well as recognize changes in the funded status of a defined benefit post-retirement plan in the year in which the changes occur through comprehensive income. The pronouncement also specifies that a plan’s assets and obligations that determine its funded status be measured as of the end of Company’s fiscal year, with limited exceptions. The Company is required to recognize the funded status of its benefit plans and the disclosure requirements of SFAS 158 by the fourth quarter of fiscal 2007. The requirement to measure the plan assets and benefit obligations as of the Company’s fiscal year-end date will be adopted by the Company by the end of fiscal 2009. If the Company recognized the funded status of its pension and post-retirement benefit plans at September 30, 2006, the Company’s Consolidated Balance Sheet would reflect a liability of $220.8 million instead of the prepaid pension and post-retirement costs of $64.1 million and pension and post-retirement liabilities of $32.9 million that were presented on the balance sheet at September 30, 2006. The Company expects that it will record a regulatory asset for the majority of this liability with the remainder reflected in accumulated other comprehensive income. The Company will recalculate the funded status of its pension and post-retirement benefit plans during the fourth quarter of fiscal 2007. The difference between what the Company currently records on its Consolidated Balance Sheet for its pension and post-retirement benefit obligations and what it will be required to record under SFAS 158 is due to certain unrecognized actuarial gains and losses and unrecognized prior service costs for both the pension and other post-retirement benefit plans as well as an unrecognized transition obligation for the other post-retirement benefit plan. These amounts are not required to be recorded on the Company’s Consolidated Balance Sheet under the current accounting standards, but were instead amortized over a period of time.

Safe Harbor for Forward-Looking Statements

     The Company is including the following cautionary statement in this Form 10-Q to make applicable and take advantage of the safe harbor provisions of the Private Securities Litigation Reform Act of 1995 for any forward-looking statements made by, or on behalf of, the Company. Forward-looking statements include statements concerning plans, objectives, goals, 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:

	1.		Changes in laws and regulations to which the Company is subject, including changes in tax, environmental, safety and employment laws and regulations;
	2.		Changes in economic conditions, including economic disruptions caused by terrorist activities, acts of war or major accidents;
	3.		Changes in demographic patterns and weather conditions, including the occurrence of severe weather such as hurricanes;

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations (Cont.)

	4.		Changes in the availability and/or price of natural gas or oil and the effect of such changes on the accounting treatment or valuation of derivative financial instruments or the Company’s natural gas and oil reserves;
	5.		Impairments under the SEC’s full cost ceiling test for natural gas and oil reserves;
	6.		Changes in the availability and/or price of derivative financial instruments;
	7.		Changes in the price differentials between various types of oil;
	8.		Inability to obtain new customers or retain existing ones;
	9.		Significant changes in competitive factors affecting the Company;
	10.		Governmental/regulatory actions, initiatives and proceedings, including those involving acquisitions, financings, rate cases (which address, among other things, allowed rates of return, rate design and retained gas), affiliate relationships, industry structure, franchise renewal, and environmental/safety requirements;
	11.		Unanticipated impacts of restructuring initiatives in the natural gas and electric industries;
	12.		Significant changes from expectations in actual capital expenditures and operating expenses and unanticipated project delays or changes in project costs or plans, including changes in the plans of the sponsors of the proposed Millennium Pipeline with respect to that project;
	13.		The nature and projected profitability of pending and potential projects and other investments;
	14.		Occurrences affecting the Company’s ability to obtain funds from operations or from issuances of debt or equity securities to finance needed capital expenditures and other investments, including any downgrades in the Company’s credit ratings;
	15.		Uncertainty of oil and gas reserve estimates;
	16.		Ability to successfully identify and finance acquisitions or other investments and ability to operate and integrate existing and any subsequently acquired business or properties;
	17.		Ability to successfully identify, drill for and produce economically viable natural gas and oil reserves;
	18.		Significant changes from expectations in the Company’s actual production levels for natural gas or oil;
	19.		Regarding foreign operations, changes in trade and monetary policies, inflation and exchange rates, taxes, operating conditions, laws and regulations related to foreign operations, and political and governmental changes;
	20.		Significant changes in tax rates or policies or in rates of inflation or interest;
	21.		Significant changes in the Company’s relationship with its employees or contractors and the potential adverse effects if labor disputes, grievances or shortages were to occur;
	22.		Changes in accounting principles or the application of such principles to the Company;
	23.		The cost and effects of legal and administrative claims against the Company;
	24.		Changes in actuarial assumptions and the return on assets with respect to the Company’s retirement plan and post-retirement benefit plans;