National Fuel Gas (NFG) 10-Q 2011 Q2 Quarterly report

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period endedMarch 31, 2011

OR

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

For the transition period from                    to                    

Commission File Number 1-3880

NATIONAL FUEL GAS COMPANY

(Exact name of registrant as specified in its charter)

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)

(716) 857-7000

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months and (2) has been subject to such filing requirements for the past 90 days. YESþ NOo

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). YESþ NOo

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer, or a smaller reporting company. See definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filerþ	Accelerated filero	Non-accelerated filero	Smaller reporting companyo
		(Do not check if a smaller reporting company)

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). YESo NOþ

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date:

     Common stock, $1 par value, outstanding at April 30, 2011: 82,690,940 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
Distribution Corporation	National Fuel Gas Distribution Corporation
Empire	Empire Pipeline, Inc.
ESNE	Energy Systems North East, LLC
Highland	Highland Forest Resources, Inc.
Horizon	Horizon Energy Development, Inc.
Horizon B.V.	Horizon Energy Development B.V.
Horizon LFG	Horizon LFG, Inc.
Horizon Power	Horizon Power, Inc.
Midstream Corporation	National Fuel Gas Midstream Corporation
Model City	Model City Energy, LLC
National Fuel	National Fuel Gas Company
NFR	National Fuel Resources, Inc.
Registrant	National Fuel Gas Company
Seneca	Seneca Resources Corporation
Seneca Energy	Seneca Energy II, LLC
Supply Corporation	National Fuel Gas Supply Corporation
Regulatory Agencies
EPA	United States Environmental Protection Agency
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
NYDEC	New York State Department of Environmental Conservation
NYPSC	State of New York Public Service Commission
PaPUC	Pennsylvania Public Utility Commission
SEC	Securities and Exchange Commission
Other
2010 Form 10-K	The Company’s Annual Report on Form 10-K for the year ended September 30, 2010
Bbl	Barrel (of oil)
Bcf	Billion cubic feet (of natural gas)
Bcfe (or Mcfe) — represents Bcf (or Mcf) Equivalent	The total heat value (Btu) of natural gas and oil expressed as a volume of natural gas. The Company uses a conversion formula of 1 barrel of oil = 6 Mcf of natural gas.
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.
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.
Development costs	Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas.
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.

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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.
Exploration costs	Costs incurred in identifying areas that may warrant examination, as well as costs incurred in examining specific areas, including drilling exploratory wells.
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.
LIBOR	London Interbank Offered Rate
LIFO	Last-in, first-out
Marcellus Shale	A Middle Devonian-age geological shale formation that is present nearly a mile or more below the surface in the Appalachian region of the United States, including much of Pennsylvania and southern New York.
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)
MMBtu	Million British thermal units
MMcf	Million cubic feet (of natural gas)
NGA	The Natural Gas Act of 1938, as amended; the federal law regulating interstate natural gas pipeline and storage companies, among other things, codified beginning at 15 U.S.C. Section 717.
NYMEX	New York Mercantile Exchange. An exchange which maintains a futures market for crude oil and natural gas.
Open Season	A bidding procedure used by pipelines to allocate firm transportation or storage capacity among prospective shippers, in which all bids submitted during a defined time period are evaluated as if they had been submitted simultaneously.
PCB	Polychlorinated Biphenyl
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.

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GLOSSARY OF TERMS (Concl.)
Restructuring	Generally referring to partial “deregulation” of the pipeline and/or 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.
Revenue decoupling mechanism	A rate mechanism which adjusts customer rates to render a utility financially indifferent to throughput decreases resulting from conservation.
S&P	Standard & Poor’s Rating Service
SAR	Stock appreciation right
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.
VEBA	Voluntary Employees’ Beneficiary Association
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.

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INDEX

	Page
Part I. Financial Information
Item 1. Financial Statements (Unaudited)
a. Consolidated Statements of Income and Earnings Reinvested in the Business — Three and Six Months Ended March 31, 2011 and 2010		6 - 7
b. Consolidated Balance Sheets — March 31, 2011 and September 30, 2010		8 - 9
c. Consolidated Statements of Cash Flows — Six Months Ended March 31, 2011 and 2010		10
d. Consolidated Statements of Comprehensive Income — Three and Six Months Ended March 31, 2011 and 2010		11
e. Notes to Condensed Consolidated Financial Statements		12 - 30
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		31 - 54
Item 3. Quantitative and Qualitative Disclosures About Market Risk		54
Item 4. Controls and Procedures		54 - 55
Part II. Other Information
Item 1. Legal Proceedings		55
Item 1 A. Risk Factors		55 - 56
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		56 - 57
Item 3. Defaults Upon Senior Securities		•
Item 5. Other Information		•
Item 6. Exhibits		57 - 58
Signatures		59
EX-12
EX-31.1
EX-31.2
EX-32
EX-99
EX-101 INSTANCE DOCUMENT
EX-101 SCHEMA DOCUMENT
EX-101 CALCULATION LINKBASE DOCUMENT
EX-101 LABELS LINKBASE DOCUMENT
EX-101 PRESENTATION LINKBASE DOCUMENT

• The Company has nothing to report under this item.

     Reference to “the Company” in this report means the Registrant or the Registrant and its subsidiaries collectively, as appropriate in the context of the disclosure. All references to a certain year in this report are to the Company’s fiscal year ended September 30 of that year, unless otherwise noted.

     This Form 10-Q contains “forward-looking statements” within the meaning of Section 21E of the Securities Exchange Act of 1934. Forward-looking statements should be read with the cautionary statements and important factors included in this Form 10-Q at Item 2 — MD&A, under the heading “Safe Harbor for Forward-Looking Statements.” Forward-looking statements are all statements other than statements of historical fact, including, without limitation, statements regarding future prospects, plans, objectives, goals, projections, estimates of oil and gas quantities, strategies, future events or performance and underlying assumptions, capital structure, anticipated capital expenditures, completion of construction and other projects, projections for pension and other post-retirement benefit obligations, impacts of the adoption of new accounting rules, and possible outcomes of litigation or regulatory proceedings, as well as statements that are identified by the use of the words “anticipates,” “estimates,” “expects,” “forecasts,” “intends,” “plans,” “predicts,” “projects,” “believes,” “seeks,” “will,” “may,” and similar expressions.

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Part I. Financial Information

Item 1. Financial Statements

National Fuel Gas Company

Consolidated Statements of Income and Earnings
Reinvested in the Business

(Unaudited)

	Three Months Ended
	March 31,
(Thousands of Dollars, Except Per Common Share Amounts)	2011			2010
INCOME
Operating Revenues	$	660,881		$	667,980
Operating Expenses
Purchased Gas		306,595			332,923
Operation and Maintenance		116,721			116,261
Property, Franchise and Other Taxes		23,798			20,440
Depreciation, Depletion and Amortization		60,011			46,725
		507,125			516,349
Operating Income		153,756			151,631
Other Income (Expense):
Income from Unconsolidated Subsidiaries		479			672
Gain on Sale of Unconsolidated Subsidiaries		50,879			—
Interest Income		68			326
Other Income		1,945			1,266
Interest Expense on Long-Term Debt		(17,926	)		(22,061	)
Other Interest Expense		(1,454	)		(2,002	)
Income from Continuing Operations Before Income Taxes		187,747			129,832
Income Tax Expense		72,136			49,958
Income from Continuing Operations		115,611			79,874
Income from Discontinued Operations, Net of Tax		—			554
Net Income Available for Common Stock		115,611			80,428
EARNINGS REINVESTED IN THE BUSINESS
Balance at January 1		1,093,398			985,663
		1,209,009			1,066,091
Dividends on Common Stock (2011 - $0.345 per share; 2010 - $0.335 per share)		(28,478	)		(27,222	)
Balance at March 31	$	1,180,531		$	1,038,869
Earnings Per Common Share:
Basic:
Income from Continuing Operations	$	1.40		$	0.98
Income from Discontinued Operations		—			0.01
Net Income Available for Common Stock	$	1.40		$	0.99
Diluted:
Income from Continuing Operations	$	1.38		$	0.96
Income from Discontinued Operations		—			0.01
Net Income Available for Common Stock	$	1.38		$	0.97
Weighted Average Common Shares Outstanding:
Used in Basic Calculation		82,400,851			81,175,261
Used in Diluted Calculation		83,673,977			82,569,323

See Notes to Condensed Consolidated Financial Statements

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Item 1. Financial Statements (Cont.)

National Fuel Gas Company
Consolidated Statements of Income and Earnings
Reinvested in the Business
(Unaudited)

	Six Months Ended
	March 31,
(Thousands of Dollars, Except Per Common Share Amounts)	2011			2010
INCOME
Operating Revenues	$	1,111,829		$	1,122,115
Operating Expenses
Purchased Gas		469,633			504,213
Operation and Maintenance		214,171			210,031
Property, Franchise and Other Taxes		43,534			39,090
Depreciation, Depletion and Amortization		113,324			91,513
		840,662			844,847
Operating Income		271,167			277,268
Other Income (Expense):
Income (Loss) from Unconsolidated Subsidiaries		(621	)		1,073
Gain on Sale of Unconsolidated Subsidiaries		50,879			—
Interest Income		951			1,480
Other Income		2,938			1,622
Interest Expense on Long-Term Debt		(38,118	)		(44,124	)
Other Interest Expense		(2,855	)		(3,379	)
Income from Continuing Operations Before Income Taxes		284,341			233,940
Income Tax Expense		110,187			89,841
Income from Continuing Operations		174,154			144,099
Income from Discontinued Operations, Net of Tax		—			828
Net Income Available for Common Stock		174,154			144,927
EARNINGS REINVESTED IN THE BUSINESS
Balance at October 1		1,063,262			948,293
		1,237,416			1,093,220
Dividends on Common Stock (2011 - $0.69 per share; 2010 - $0.67 per share)		(56,885	)		(54,351	)
Balance at March 31	$	1,180,531		$	1,038,869
Earnings Per Common Share:
Basic:
Income from Continuing Operations	$	2.12		$	1.78
Income from Discontinued Operations		—			0.01
Net Income Available for Common Stock	$	2.12		$	1.79
Diluted:
Income from Continuing Operations	$	2.08		$	1.75
Income from Discontinued Operations		—			0.01
Net Income Available for Common Stock	$	2.08		$	1.76
Weighted Average Common Shares Outstanding:
Used in Basic Calculation		82,311,162			80,866,311
Used in Diluted Calculation		83,561,775			82,347,254

See Notes to Condensed Consolidated Financial Statements

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Item 1. Financial Statements (Cont.)

National Fuel Gas Company

Consolidated Balance Sheets

(Unaudited)

	March 31,		September 30,
(Thousands of Dollars)	2011		2010
ASSETS
Property, Plant and Equipment	$	6,019,453	$	5,637,498
Less — Accumulated Depreciation, Depletion and Amortization		2,285,313		2,187,269
		3,734,140		3,450,229
Current Assets
Cash and Temporary Cash Investments		144,767		397,171
Hedging Collateral Deposits		61,826		11,134
Receivables — Net of Allowance for Uncollectible Accounts of $44,132 and $30,961, Respectively		227,898		132,136
Unbilled Utility Revenue		48,551		20,920
Gas Stored Underground		11,927		48,584
Materials and Supplies — at average cost		31,707		24,987
Other Current Assets		58,522		115,969
Deferred Income Taxes		34,917		24,476
		620,115		775,377
Other Assets
Recoverable Future Taxes		152,017		149,712
Unamortized Debt Expense		11,547		12,550
Other Regulatory Assets		529,420		542,801
Deferred Charges		5,960		9,646
Other Investments		83,744		77,839
Investments in Unconsolidated Subsidiaries		1,443		14,828
Goodwill		5,476		5,476
Fair Value of Derivative Financial Instruments		37,708		65,184
Other		1,747		1,983
		829,062		880,019
Total Assets	$	5,183,317	$	5,105,625

See Notes to Condensed Consolidated Financial Statements

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Item 1. Financial Statements (Cont.)

National Fuel Gas Company
Consolidated Balance Sheets
(Unaudited)

	March 31,			September 30,
(Thousands of Dollars)	2011			2010
CAPITALIZATION AND LIABILITIES
Capitalization:
Comprehensive Shareholders’ Equity
Common Stock, $1 Par Value Authorized - 200,000,000 Shares; Issued And Outstanding — 82,544,193 Shares and 82,075,470 Shares, Respectively	$	82,544		$	82,075
Paid in Capital		645,961			645,619
Earnings Reinvested in the Business		1,180,531			1,063,262
Total Common Shareholder Equity Before Items of Other Comprehensive Loss		1,909,036			1,790,956
Accumulated Other Comprehensive Loss		(92,521	)		(44,985	)
Total Comprehensive Shareholders’ Equity		1,816,515			1,745,971
Long-Term Debt, Net of Current Portion		899,000			1,049,000
Total Capitalization		2,715,515			2,794,971
Current and Accrued Liabilities
Notes Payable to Banks and Commercial Paper		—			—
Current Portion of Long-Term Debt		150,000			200,000
Accounts Payable		122,911			89,677
Amounts Payable to Customers		25,475			38,109
Dividends Payable		28,478			28,316
Interest Payable on Long-Term Debt		25,512			30,512
Customer Advances		2,700			27,638
Customer Security Deposits		18,064			18,320
Other Accruals and Current Liabilities		160,363			71,592
Fair Value of Derivative Financial Instruments		70,115			20,160
		603,618			524,324
Deferred Credits
Deferred Income Taxes		886,824			800,758
Taxes Refundable to Customers		69,592			69,585
Unamortized Investment Tax Credit		2,937			3,288
Cost of Removal Regulatory Liability		131,958			124,032
Other Regulatory Liabilities		88,825			89,334
Pension and Other Post-Retirement Liabilities		434,488			446,082
Asset Retirement Obligations		102,094			101,618
Other Deferred Credits		147,466			151,633
		1,864,184			1,786,330
Commitments and Contingencies		—			—
Total Capitalization and Liabilities	$	5,183,317		$	5,105,625

See Notes to Condensed Consolidated Financial Statements

-9-

Item 1. Financial Statements (Cont.)

National Fuel Gas Company

Consolidated Statements of Cash Flows

(Unaudited)

	Six Months Ended
	March 31,
(Thousands of Dollars)	2011			2010
OPERATING ACTIVITIES
Net Income Available for Common Stock	$	174,154		$	144,927
Adjustments to Reconcile Net Income to Net Cash
Provided by Operating Activities:
Gain on Sale of Unconsolidated Subsidiaries		(50,879	)		—
Depreciation, Depletion and Amortization		113,324			91,846
Deferred Income Taxes		106,510			41,795
(Income) Loss from Unconsolidated Subsidiaries, Net of Cash Distributions		4,899			1,228
Excess Tax Benefits Associated with Stock-Based Compensation Awards		—			(13,437	)
Other		804			6,271
Change in:
Hedging Collateral Deposits		(50,692	)		(12,809	)
Receivables and Unbilled Utility Revenue		(123,393	)		(101,881	)
Gas Stored Underground and Materials and Supplies		30,144			37,932
Prepayments and Other Current Assets		57,447			31,318
Accounts Payable		33,234			12,178
Amounts Payable to Customers		(12,634	)		(41,442	)
Customer Advances		(24,938	)		(21,840	)
Customer Security Deposits		(256	)		1,996
Other Accruals and Current Liabilities		93,473			90,499
Other Assets		15,710			11,285
Other Liabilities		(23,685	)		(535	)
Net Cash Provided by Operating Activities		343,222			279,331
INVESTING ACTIVITIES
Capital Expenditures		(392,338	)		(230,530	)
Net Proceeds from Sale of Unconsolidated Subsidiaries		59,365			—
Other		(3,097	)		(115	)
Net Cash Used in Investing Activities		(336,070	)		(230,645	)
FINANCING ACTIVITIES
Excess Tax Benefits Associated with Stock-Based Compensation Awards		—			13,437
Reduction of Long-Term Debt		(200,000	)		—
Dividends Paid on Common Stock		(56,723	)		(54,096	)
Net Proceeds from Issuance (Repurchase) of Common Stock		(2,833	)		10,724
Net Cash Used in Financing Activities		(259,556	)		(29,935	)
Net Increase (Decrease) in Cash and Temporary Cash Investments		(252,404	)		18,751
Cash and Temporary Cash Investments at October 1		397,171			410,053
Cash and Temporary Cash Investments at March 31	$	144,767		$	428,804

See Notes to Condensed Consolidated Financial Statements

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Item 1. Financial Statements (Cont.)

National Fuel Gas Company

Consolidated Statements of Comprehensive Income

(Unaudited)

	Three Months Ended
	March 31,
(Thousands of Dollars)	2011			2010
Net Income Available for Common Stock	$	115,611		$	80,428
Other Comprehensive Income (Loss), Before Tax:
Foreign Currency Translation Adjustment		—			47
Unrealized Gain on Securities Available for Sale Arising During the Period		897			1,158
Unrealized Gain (Loss) on Derivative Financial Instruments Arising During the Period		(40,844	)		27,633
Reclassification Adjustment for Realized Gains on Derivative Financial Instruments in Net Income		(7,212	)		(5,590	)
Other Comprehensive Income (Loss), Before Tax		(47,159	)		23,248
Income Tax Expense Related to Unrealized Gain on Securities Available for Sale Arising During the Period		337			438
Income Tax Expense (Benefit) Related to Unrealized Gain (Loss) on Derivative Financial Instruments Arising During the Period		(16,778	)		11,310
Reclassification Adjustment for Income Tax Expense on Realized Gains from Derivative Financial Instruments In Net Income		(2,847	)		(2,300	)
Income Taxes — Net		(19,288	)		9,448
Other Comprehensive Income (Loss)		(27,871	)		13,800
Comprehensive Income	$	87,740		$	94,228

	Six Months Ended
	March 31,
(Thousands of Dollars)	2011			2010
Net Income Available for Common Stock	$	174,154		$	144,927
Other Comprehensive Income (Loss), Before Tax:
Foreign Currency Translation Adjustment		17			64
Reclassification Adjustment for Realized Foreign Currency Transaction Loss in Net Income		34			—
Unrealized Gain on Securities Available for Sale Arising During the Period		3,438			445
Unrealized Gain (Loss) on Derivative Financial Instruments Arising During the Period		(67,980	)		22,780
Reclassification Adjustment for Realized Gains on Derivative Financial Instruments in Net Income		(16,265	)		(17,643	)
Other Comprehensive Income (Loss), Before Tax		(80,756	)		5,646
Income Tax Expense Related to Unrealized Gain on Securities Available for Sale Arising During the Period		1,298			167
Income Tax Expense (Benefit) Related to Unrealized Gain (Loss) on Derivative Financial Instruments Arising During the Period		(27,946	)		9,247
Reclassification Adjustment for Income Tax Expense on Realized Gains from Derivative Financial Instruments In Net Income		(6,572	)		(7,262	)
Income Taxes — Net		(33,220	)		2,152
Other Comprehensive Income (Loss)		(47,536	)		3,494
Comprehensive Income	$	126,618		$	148,421

See Notes to Condensed Consolidated Financial Statements

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Item 1. Financial Statements (Cont.)

National Fuel Gas Company

Notes to Condensed Consolidated Financial Statements

(Unaudited)

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.

Reclassification.Certain prior year amounts have been reclassified to conform with current year presentation. This includes the reclassification of accrued capital expenditures of $55.5 million from Accounts Payable to Other Accruals and Current Liabilities on the Consolidated Balance Sheet at September 30, 2010. This reclassification did not impact the Consolidated Statement of Income or the Consolidated Statement of Cash Flows for any of the periods presented.

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, 2010, 2009 and 2008 that are included in the Company’s 2010 Form 10-K. The consolidated financial statements for the year ended September 30, 2011 will be audited by the Company’s independent registered public accounting firm after the end of the fiscal year.

     The earnings for the six months ended March 31, 2011 should not be taken as a prediction of earnings for the entire fiscal year ending September 30, 2011. 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. The Company’s business segments are discussed more fully in Note 8 — Business Segment Information.

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.

     At March 31, 2011, the Company accrued $43.9 million of capital expenditures in the Exploration and Production segment, the majority of which was in the Appalachian region. The Company also accrued $2.0 million of capital expenditures in the Pipeline and Storage segment at March 31, 2011. These amounts were excluded from the Consolidated Statement of Cash Flows at March 31, 2011 since they represent non-cash investing activities at that date. Accrued capital expenditures at March 31, 2011 are included in Other Accruals and Current Liabilities on the Consolidated Balance Sheet.

     At September 30, 2010, the Company accrued $55.5 million of capital expenditures in the Exploration and Production segment, the majority of which was in the Appalachian region. This amount was excluded from the Consolidated Statement of Cash Flows at September 30, 2010 since it represented a non-cash investing activity at that date. These capital expenditures were paid during the quarter ended December 31, 2010 and have been included in the Consolidated Statement of Cash Flows for the six months ended March 31, 2011. Accrued capital expenditures at September 30, 2010 are included in Other Accruals and Current Liabilities on the Consolidated Balance Sheet.

-12-

Item 1. Financial Statements (Cont.)

     At March 31, 2010, the Company accrued $15.3 million of capital expenditures in the Exploration and Production segment, the majority of which was in the Appalachian region. This amount was excluded from the Consolidated Statement of Cash Flows at March 31, 2010 since it represented a non-cash investing activity at that date.

     At September 30, 2009, the Company accrued $9.1 million of capital expenditures in the Exploration and Production segment, the majority of which was in the Appalachian region. The Company also accrued $0.7 million of capital expenditures in the All Other category related to the construction of the Midstream Covington Gathering System. These amounts were excluded from the Consolidated Statement of Cash Flows at September 30, 2009 since they represented non-cash investing activities at that date. These capital expenditures were paid during the quarter ended December 31, 2009 and have been included in the Consolidated Statement of Cash Flows for the six months ended March 31, 2010.

Hedging Collateral Deposits.This is an account title for cash held in margin accounts funded by the Company to serve as collateral for hedging positions. At March 31, 2011, the Company had hedging collateral deposits of $6.9 million related to its exchange-traded futures contracts and $54.9 million related to its over-the-counter crude oil swap agreements. At September 30, 2010, the Company had hedging collateral deposits of $10.1 million related to its exchange-traded futures contracts and $1.0 million related to its over-the-counter crude oil swap agreements. In accordance with its accounting policy, the Company does not offset hedging collateral deposits paid or received against related derivative financial instruments liability or asset balances.

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 $88.6 million at March 31, 2011, is reduced to zero by September 30 of each year as the inventory is replenished.

Property, Plant and Equipment.In the Company’s Exploration and Production segment, oil and gas property acquisition, exploration and development costs are capitalized under the full cost method of accounting. Under this methodology, all costs associated with property acquisition, exploration and development activities are capitalized, including internal costs directly identified with acquisition, exploration and development activities. The internal costs that are capitalized do not include any costs related to production, general corporate overhead, or similar activities. The Company does not recognize any gain or loss on the sale or other disposition of oil and gas properties unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves of oil and gas attributable to a cost center.

     Capitalized costs include costs related to unproved properties, which are excluded from amortization until proved reserves are found or it is determined that the unproved properties are impaired. Such costs amounted to $180.8 million and $151.2 million at March 31, 2011 and September 30, 2010, respectively. All costs related to unproved properties are reviewed quarterly to determine if impairment has occurred. The amount of any impairment is transferred to the pool of capitalized costs being amortized.

     Capitalized costs are subject to the SEC full cost ceiling test. The ceiling test, which is performed each quarter, determines a limit, or ceiling, on the amount of property acquisition, exploration and development costs that can be capitalized. The ceiling under this test represents (a) the present value of estimated future net cash flows, excluding future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheet, using a discount factor of 10%, which is computed by applying prices of oil and gas (as adjusted for hedging) to estimated future production of proved oil and gas reserves as of the date of the latest balance sheet, less estimated future expenditures, plus (b) the cost of unevaluated properties not being depleted, less (c) income tax effects related to the differences between the book and tax basis of the properties. In accordance with the SEC final rule on Modernization of Oil and Gas Reporting, the natural gas and oil prices used to calculate the full cost ceiling (as of March 31, 2011) are based on an unweighted arithmetic average of the first day of the month oil and gas prices for each month within the twelve-month period prior to the end of the reporting period. If

-13-

Item 1. Financial Statements (Cont.)

capitalized costs, net of accumulated depreciation, depletion and amortization and related deferred income taxes, exceed the ceiling at the end of any quarter, a permanent impairment is required to be charged to earnings in that quarter. At March 31, 2011, the Company’s capitalized costs were below the full cost ceiling for the Company’s oil and gas properties. As a result, an impairment charge was not required at March 31, 2011.

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

	At March 31, 2011			At September 30, 2010
Funded Status of the Pension and Other Post-Retirement Benefit Plans	$	(79,465	)	$	(79,465	)
Cumulative Foreign Currency Translation Adjustment		—			(51	)
Net Unrealized Gain (Loss) on Derivative Financial Instruments		(16,851	)		32,876
Net Unrealized Gain on Securities Available for Sale		3,795			1,655
Accumulated Other Comprehensive Loss	$	(92,521	)	$	(44,985	)

Other Current Assets. The components of the Company’s Other Current Assets are as follows (in thousands):

	At March 31, 2011		At September 30, 2010
Prepayments	$	6,779	$	13,884
Prepaid Property and Other Taxes		20,507		12,413
Federal Income Taxes Receivable		16,399		56,334
State Income Taxes Receivable		9,290		18,007
Fair Values of Firm Commitments		5,547		15,331
	$	58,522	$	115,969

Earnings Per Common Share.Basic earnings per common share is computed by dividing net income available for common stock by the weighted average number of common shares outstanding for the period. Diluted earnings per common share reflects the potential dilution that could occur if securities or other contracts to issue common stock were exercised or converted into common stock. For purposes of determining earnings per common share, the only potentially dilutive securities the Company has outstanding are stock options, SARs and restricted stock units. The diluted weighted average shares outstanding shown on the Consolidated Statements of Income reflects the potential dilution as a result of these securities as determined using the Treasury Stock Method. Stock options, SARs and restricted stock units that are antidilutive are excluded from the calculation of diluted earnings per common share. There were 10,959 and 140 SARs excluded as being antidilutive for the quarter and six months ended March 31, 2011, respectively. For both the quarters and six months ended March 31, 2011 and March 31, 2010, there were no stock options or restricted stock units excluded as being antidilutive. There were 145,450 and 84,058 SARs excluded as being antidilutive for the quarter and six months ended March 31, 2010, respectively.

Stock-Based Compensation.During the six months ended March 31, 2011, the Company granted 180,000 non-performance based SARs having a weighted average exercise price of $63.87 per share. The weighted average grant date fair value of these SARs was $15.33 per share. These SARs may be settled in cash, in shares of common stock of the Company, or in a combination of cash and shares of common stock of the Company, as determined by the Company. These SARs are considered equity awards under the current authoritative guidance for stock-based compensation. The accounting for those SARs is the same as the accounting for stock options. There were no SARs granted during the quarter ended March 31, 2011. The non-performance based SARs granted during the six months ended March 31, 2011 vest and become

-14-

Item 1. Financial Statements (Cont.)

exercisable annually in one-third increments. The weighted average grant date fair value of these non-performance based SARs granted during the six months ended March 31, 2011 was estimated on the date of grant using the same accounting treatment that is applied for stock options.

     There were no stock options granted during the quarter or six months ended March 31, 2011. The Company did not recognize a tax benefit related to the exercise of stock options for the calendar year ended December 31, 2010 due to tax loss carryforwards. The Company expects to recognize a tax benefit of $18.1 million in Paid in Capital related to calendar 2010 stock option exercises in future years as the tax loss carryforward is utilized.

     The Company granted 47,250 restricted share awards (non-vested stock as defined by the current accounting literature) during the six months ended March 31, 2011. The weighted average fair value of such restricted shares was $63.98 per share. In addition, the Company granted 28,900 restricted stock units during the six months ended March 31, 2011. The weighted average fair value of such restricted stock units was $58.23 per share. Restricted stock units represent the right to receive shares of common stock of the Company (or the equivalent value in cash or a combination of cash and shares of common stock of the Company, as determined by the Company) at the end of a specified time period. These restricted stock units do not entitle the participant to receive dividends during the vesting period. The accounting for these restricted stock units is the same as the accounting for restricted share awards, except that the fair value at the date of grant of the restricted stock units must be reduced by the present value of forgone dividends over the vesting term of the award. There were no restricted share awards or restricted stock units granted during the quarter ended March 31, 2011.

Note 2 — Fair Value Measurements

     The FASB authoritative guidance regarding fair value measurements establishes a fair-value hierarchy and prioritizes the inputs used in valuation techniques that measure fair value. Those inputs are prioritized into three levels. Level 1 inputs are unadjusted quoted prices in active markets for assets or liabilities that the Company has the ability to access at the measurement date. Level 2 inputs are inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly at the measurement date. Level 3 inputs are unobservable inputs for the asset or liability at the measurement date. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.

     The following table sets forth, by level within the fair value hierarchy, the Company’s financial assets and liabilities (as applicable) that were accounted for at fair value on a recurring basis as of March 31, 2011 and September 30, 2010. Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement.

-15-

Item 1. Financial Statements (Cont.)

Recurring Fair Value Measures	At fair value as of March 31, 2011
(Thousands of Dollars)	Level 1		Level 2			Level 3			Total
Assets:
Cash Equivalents — Money Market Mutual Funds	$	115,924	$	—		$	—		$	115,924
Derivative Financial Instruments:
Over the Counter Swaps — Oil		—		(777	)		—			(777	)
Over the Counter Swaps — Gas		—		38,485			—			38,485
Other Investments:
Balanced Equity Mutual Fund		21,786		—			—			21,786
Common Stock — Financial Services Industry		6,991		—			—			6,991
Other Common Stock		247		—			—			247
Hedging Collateral Deposits		61,826		—			—			61,826
Total	$	206,774	$	37,708		$	—		$	244,482
Liabilities:
Derivative Financial Instruments:
Commodity Futures Contracts — Gas	$	2,846	$	—		$	—		$	2,846
Over the Counter Swaps — Oil		—		—			71,913			71,913
Over the Counter Swaps — Gas		—		(4,644	)		—			(4,644	)
Total	$	2,846	$	(4,644	)	$	71,913		$	70,115
Total Net Assets/(Liabilities)	$	203,928	$	42,352		$	(71,913	)	$	174,367

Recurring Fair Value Measures	At fair value as of September 30, 2010
(Thousands of Dollars)	Level 1		Level 2		Level 3			Total
Assets:
Cash Equivalents — Money Market Mutual Funds	$	277,423	$	—	$	—		$	277,423
Derivative Financial Instruments:
Over the Counter Swaps — Gas		—		67,387		—			67,387
Over the Counter Swaps — Oil		—		—		(2,203	)		(2,203	)
Other Investments:
Balanced Equity Mutual Fund		17,256		—		—			17,256
Common Stock — Financial Services Industry		4,991		—		—			4,991
Other Common Stock		241		—		—			241
Hedging Collateral Deposits		11,134		—		—			11,134
Total	$	311,045	$	67,387	$	(2,203	)	$	376,229
Liabilities:
Derivative Financial Instruments:
Commodity Futures Contracts — Gas	$	5,840	$	—	$	—		$	5,840
Over the Counter Swaps — Oil		—		—		14,280			14,280
Over the Counter Swaps — Gas		—		40		—			40
Total	$	5,840	$	40	$	14,280		$	20,160
Total Net Assets/(Liabilities)	$	305,205	$	67,347	$	(16,483	)	$	356,069

Derivative Financial Instruments

     At March 31, 2011 and September 30, 2010, the derivative financial instruments reported in Level 1 consist of natural gas NYMEX futures contracts used in the Company’s Energy Marketing and Pipeline and Storage segments. Hedging collateral deposits of $6.9 million (at March 31, 2011) and $10.1 million (at September 30, 2010), which are associated with these futures contracts have been reported in Level 1 as

-16-

Item 1. Financial Statements (Cont.)

well. The derivative financial instruments reported in Level 2 at March 31, 2011 consist of crude oil and natural gas price swap agreements used in the Company’s Exploration and Production and Energy Marketing segments. At September 30, 2010, the derivative financial instruments reported in Level 2 consist of natural gas price swap agreements used in the Company’s Exploration and Production and Energy Marketing segments. The fair value of these price swap agreements is based on an internal, discounted cash flow model that uses observable inputs (i.e. LIBOR based discount rates and basis differential information, if applicable, at active natural gas and crude oil trading markets). The derivative financial instruments reported in Level 3 consist of the majority of the Company’s Exploration and Production segment’s crude oil price swap agreements at March 31, 2011 and all of its crude oil price swap agreements at September 30, 2010. Hedging collateral deposits of $54.9 million and $1.0 million associated with these crude oil price swap agreements have been reported in Level 1 at March 31, 2011 and September 30, 2010, respectively. The fair value of the crude oil price swap agreements is based on an internal, discounted cash flow model that uses both observable (i.e. LIBOR based discount rates) and unobservable inputs (i.e. basis differential information of crude oil trading markets with low trading volume). Based on an assessment of the counterparties’ credit risk, the fair market value of the price swap agreements reported as Level 2 assets have been reduced by $0.2 million and $1.0 million at March 31, 2011 and September 30, 2010, respectively. Based on an assessment of the Company’s credit risk, the fair market value of the price swap agreements reported as Level 2 and Level 3 liabilities have been reduced by less than $0.1 million and $0.3 million at March 31, 2011 and September 30, 2010, respectively. These credit reserves were determined by applying default probabilities to the anticipated cash flows that the Company is either expecting from its counterparties or expecting to pay to its counterparties.

     The tables listed below provide reconciliations of the beginning and ending net balances for assets and liabilities measured at fair value and classified as Level 3 for the quarters and six months ended March 31, 2011 and 2010, respectively. For the quarters and six months ended March 31, 2011 and March 31, 2010, no transfers in or out of Level 1 or Level 2 occurred. There were no purchases or sales of derivative financial instruments during the periods presented in the tables below. All settlements of the derivative financial instruments are reflected in the Gains/Losses Realized and Included in Earnings column of the tables below.

Fair Value Measurements Using Unobservable Inputs (Level 3)

				Total Gains/Losses
							Gains/Losses
							Unrealized and
				Gains/Losses			Included in
				Realized and			Other			Transfer
	January 1,			Included in			Comprehensive			In/Out of		March 31,
(Thousands of Dollars)	2011			Earnings			Income (Loss)			Level 3		2011
Derivative Financial Instruments(2)	$	(37,407	)	$	(13,189	)(1)	$	(21,317	)	$	—	$	(71,913	)

(1)	Amounts are reported in Operating Revenues in the Consolidated Statement of Income for the three months ended March 31, 2011.
(2)	Derivative Financial Instruments are shown on a net basis.

Fair Value Measurements Using Unobservable Inputs (Level 3)

				Total Gains/Losses
							Gains/Losses
							Unrealized and
				Gains/Losses			Included in
				Realized and			Other			Transfer
	October 1,			Included in			Comprehensive			In/Out of		March 31,
(Thousands of Dollars)	2010			Earnings			Income (Loss)			Level 3		2011
Derivative Financial Instruments(2)	$	(16,483	)	$	(15,992	)(1)	$	(39,438	)	$	—	$	(71,913	)

(1)	Amounts are reported in Operating Revenues in the Consolidated Statement of Income for the six months ended March 31, 2011.
(2)	Derivative Financial Instruments are shown on a net basis.

-17-

Item 1. Financial Statements (Cont.)

Fair Value Measurements Using Unobservable Inputs (Level 3)

				Total Gains/Losses
							Gains/Losses
							Unrealized and
				Gains/Losses			Included in
				Realized and			Other			Transfer
	January 1,			Included in			Comprehensive			In/Out of		March 31,
(Thousands of Dollars)	2010			Earnings			Income (Loss)			Level 3		2010
Derivative Financial Instruments(2)	$	(149	)	$	(1,662	)(1)	$	(12,289	)	$	—	$	(14,100	)

(1)	Amounts are reported in Operating Revenues in the Consolidated Statement of Income for the three months ended March 31, 2010.
(2)	Derivative Financial Instruments are shown on a net basis.

Fair Value Measurements Using Unobservable Inputs (Level 3)

			Total Gains/Losses
						Gains/Losses
						Unrealized and
			Gains/Losses			Included in
			Realized and			Other			Transfer
	October 1,		Included in			Comprehensive			In/Out of		March 31,
(Thousands of Dollars)	2009		Earnings			Income (Loss)			Level 3		2010
Derivative Financial Instruments(2)	$	26,969	$	(4,797	)(1)	$	(36,272	)	$	—	$	(14,100	)

(1)	Amounts are reported in Operating Revenues in the Consolidated Statement of Income for the six months ended March 31, 2010.
(2)	Derivative Financial Instruments are shown on a net basis.

Note 3 — Financial Instruments

Long-Term Debt.The fair market value of the Company’s debt, as presented in the table below, was determined using a discounted cash flow model, which incorporates the Company’s credit ratings and current market conditions in determining the yield, and subsequently, the fair market value of the debt. Based on these criteria, the fair market value of long-term debt, including current portion, was as follows (in thousands):

	March 31, 2011				September 30, 2010
	Carrying				Carrying
	Amount		Fair Value		Amount		Fair Value
Long-Term Debt	$	1,049,000	$	1,190,130	$	1,249,000	$	1,423,349

Other Investments.Investments in life insurance are stated at their cash surrender values or net present value as discussed below. Investments in an equity mutual fund and the stock of an insurance company (marketable equity securities), as discussed below, are stated at fair value based on quoted market prices.

     Other investments include cash surrender values of insurance contracts (net present value in the case of split-dollar collateral assignment arrangements) and marketable equity securities. The values of the insurance contracts amounted to $54.7 million at March 31, 2011 and $55.4 million at September 30, 2010. The fair value of the equity mutual fund was $21.8 million at March 31, 2011 and $17.3 million at September 30, 2010. The gross unrealized gain on this equity mutual fund was $1.4 million at March 31, 2011. The unrealized gain on the equity mutual fund at September 30, 2010 was negligible as the fair value was approximately equal to the cost basis. The fair value of the stock of an insurance company was $7.0 million at March 31, 2011 and $5.0 million at September 30, 2010. The gross unrealized gain on this stock was $4.6 million at March 31, 2011 and $2.6 million at September 30, 2010. The insurance contracts and marketable equity securities are primarily informal funding mechanisms for various benefit obligations the Company has to certain employees.

-18-

Item 1. Financial Statements (Cont.)

Derivative Financial Instruments.The Company is exposed to certain risks relating to its ongoing business operations. The primary risk managed by using derivative instruments is commodity price risk in the Exploration and Production, Energy Marketing and Pipeline and Storage segments. The Company enters into futures contracts and over-the-counter swap agreements for natural gas and crude oil to manage the price risk associated with forecasted sales of gas and oil. The Company also enters into futures contracts and swaps to manage the risk associated with forecasted gas purchases, storage of gas, withdrawal of gas from storage to meet customer demand and the potential decline in the value of gas held in storage. The duration of the Company’s hedges do not typically exceed 3 years.

     The Company has presented its net derivative assets and liabilities on its Consolidated Balance Sheets at March 31, 2011 and September 30, 2010 as shown in the table below.

	Fair Values of Derivative Instruments
	(Dollar Amounts in Thousands)
Derivatives	Asset Derivatives			Liability Derivatives
Designated as	Consolidated			Consolidated
Hedging	Balance Sheet			Balance Sheet
Instruments	Location	Fair Value		Location	Fair Value
Commodity	Fair Value of			Fair Value of
Contracts — at	Derivative			Derivative
March 31,	Financial			Financial
2011	Instruments	$	37,708	Instruments	$	70,115
	Fair Value of			Fair Value of
Commodity	Derivative			Derivative
Contracts — at	Financial			Financial
September 30, 2010	Instruments	$	65,184	Instruments	$	20,160

     The following table discloses the fair value of derivative contracts on a gross-contract basis as opposed to the net-contract basis presentation on the Consolidated Balance Sheets at March 31, 2011 and September 30, 2010.

Derivatives	Fair Values of Derivative Instruments
Designated as	(Dollar Amounts in Thousands)
Hedging	Gross Asset Derivatives		Gross Liability Derivatives
Instruments	Fair Value		Fair Value
Commodity Contracts — at March 31, 2011	$	47,243	$	79,650
Commodity Contracts — at September 30, 2010	$	77,837	$	32,813

Cash flow hedges

     For derivative instruments that are designated and qualify as a cash flow hedge, the effective portion of the gain or loss on the derivative is reported as a component of other comprehensive income (loss) and reclassified into earnings in the period or periods during which the hedged transaction affects earnings. Gains and losses on the derivative representing either hedge ineffectiveness or hedge components excluded from the assessment of effectiveness are recognized in current earnings.

-19-

Item 1. Financial Statements (Cont.)

     As of March 31, 2011, the Company’s Exploration and Production segment had the following commodity derivative contracts (swaps) outstanding to hedge forecasted sales (where the Company uses short positions (i.e. positions that pay-off in the event of commodity price decline) to mitigate the risk of decreasing revenues and earnings):

Commodity	Units
Natural Gas	55.6 Bcf (all short positions)
Crude Oil	3,138,000 Bbls (all short positions)

     As of March 31, 2011, the Company’s Energy Marketing segment had the following commodity derivative contracts (futures contracts and swaps) outstanding to hedge forecasted sales (where the Company uses short positions to mitigate the risk associated with natural gas price decreases and its impact on decreasing revenues and earnings) and purchases (where the Company uses long positions (i.e. positions that pay-off in the event of commodity price increases) to mitigate the risk of increasing natural gas prices, which would lead to increased purchased gas expense and decreased earnings):

Commodity	Units
Natural Gas	6.2 Bcf (3.5 Bcf short positions (forecasted storage withdrawals) and 2.7 Bcf long positions (forecasted storage injections))

     As of March 31, 2011, the Company’s Pipeline and Storage segment has the following commodity derivative contracts (futures contracts) outstanding to hedge forecasted sales (where the Company uses short positions to mitigate the risk associated with natural gas price decreases and its impact on decreasing revenues and earnings):

Commodity	Units
Natural Gas	1.2 Bcf (all short positions)

     As of March 31, 2011, the Company’s Exploration and Production segment had $30.2 million ($17.8 million after tax) of net hedging losses included in the accumulated other comprehensive income (loss) balance. It is expected that $14.4 million ($8.5 million after tax) of these losses will be reclassified into the Consolidated Statement of Income (Loss) within the next 12 months as the expected sales of the underlying commodities occur. See Note 1, under Accumulated Other Comprehensive Income (Loss), for the after-tax gain (loss) pertaining to derivative financial instruments (Net Unrealized Gain (Loss) on Derivative Financial Instruments in Note 1 includes the Exploration and Production, Energy Marketing and Pipeline and Storage segments).

     As of March 31, 2011, the Company’s Energy Marketing segment had $1.8 million ($1.1 million after tax) of net hedging gains included in the accumulated other comprehensive income (loss) balance. It is expected that the full amount will be reclassified into the Consolidated Statement of Income (Loss) within the next 12 months as the sales and purchases of the underlying commodities occur. See Note 1, under Accumulated Other Comprehensive Income (Loss), for the after-tax gain (loss) pertaining to derivative financial instruments (Net Unrealized Gain (Loss) on Derivative Financial Instruments in Note 1 includes the Exploration and Production, Energy Marketing and Pipeline and Storage segments).

     As of March 31, 2011, the Company’s Pipeline and Storage segment had $0.2 million ($0.1 million after tax) of net hedging losses included in the accumulated other comprehensive income (loss) balance. It is expected that the full amount will be reclassified into the Consolidated Statement of Income (Loss) within the next 12 months as the expected sales of the underlying commodities occur. See Note 1, under Accumulated Other Comprehensive Income (Loss), for the after-tax gain (loss) pertaining to derivative financial instruments (Net Unrealized Gain (Loss) on Derivative Financial Instruments in Note 1 includes the Exploration and Production, Energy Marketing and Pipeline and Storage segments).

-20-

Item 1. Financial Statements (Cont.)

The Effect of Derivative Financial Instruments on the Statement of Financial Performance for the
Three Months Ended March 31, 2011 and 2010 (Thousands of Dollars)

						Location of
						Derivative Gain
						or (Loss)
						Reclassified
	Amount of					from	Amount of Derivative
	Derivative Gain or					Accumulated	Gain or (Loss)					Location of
	(Loss) Recognized					Other	Reclassified from					Derivative Gain
	in Other					Comprehensive	Accumulated Other					or (Loss)	Derivative Gain or
	Comprehensive					Income (Loss)	Comprehensive					Recognized in the	(Loss) Recognized
	Income (Loss) on					on the	Income (Loss) on the					Consolidated	in the Consolidated
	the Consolidated					Consolidated	Consolidated Balance					Statement of	Statement of
	Statement of					Balance Sheet	Sheet into the					Income	Income (Ineffective
	Comprehensive					into the	Consolidated					(Ineffective	Portion and Amount
	Income (Loss)					Consolidated	Statement of Income					Portion and	Excluded from
Derivatives in	(Effective Portion)					Statement of	(Effective Portion) for					Amount	Effectiveness
Cash Flow	for the Three					Income	the Three Months					Excluded from	Testing) for the
Hedging	Months Ended					(Effective	Ended					Effectiveness	Three Months Ended
Relationships	March 31,					Portion)	March 31,					Testing)	March 31,
	2011			2010			2011		2010				2011		2010
Commodity Contracts — Exploration & Production segment	$	(41,586	)	$	24,375	Operating Revenue	$	1,956	$	5,538		Operating Revenue	$	—	$	—
Commodity Contracts — Energy Marketing segment	$	872		$	2,278	Purchased Gas	$	5,256	$	(470	)	Purchased Gas	$	—	$	—
Commodity Contracts — Pipeline & Storage segment	$	(130	)	$	980	Operating Revenue	$	—	$	522		Operating Revenue	$	—	$	—
Total	$	(40,844	)	$	27,633		$	7,212	$	5,590			$	—	$	—

-21-

Item 1. Financial Statements (Cont.)

The Effect of Derivative Financial Instruments on the Statement of Financial Performance for the
Six Months Ended March 31, 2011 and 2010 (Thousands of Dollars)

						Location of
						Derivative Gain
						or (Loss)
						Reclassified
						from						Location of
	Amount of					Accumulated	Amount of Derivative					Derivative Gain
	Derivative Gain or					Other	Gain or (Loss)					or (Loss)
	(Loss) Recognized					Comprehensive	Reclassified from					Recognized in	Derivative Gain or
	in Other					Income (Loss)	Accumulated Other					the	(Loss) Recognized
	Comprehensive					on the	Comprehensive					Consolidated	in the Consolidated
	Income (Loss) on					Consolidated	Income (Loss) on the					Statement of	Statement of
	the Consolidated					Balance Sheet	Consolidated Balance					Income	Income (Ineffective
	Statement of					into the	Sheet into the					(Ineffective	Portion and Amount
	Comprehensive					Consolidated	Consolidated					Portion and	Excluded from
Derivatives in	Income (Loss)					Statement of	Statement of Income					Amount	Effectiveness
Cash Flow	(Effective Portion)					Income	(Effective Portion) for					Excluded from	Testing) for the Six
Hedging	for the Six Months Ended					(Effective	the Six Months Ended					Effectiveness	Months Ended
Relationships	March 31,					Portion)	March 31,					Testing)	March 31,
	2011			2010			2011		2010				2011		2010
Commodity Contracts — Exploration & Production segment	$	(68,368	)	$	16,465	Operating Revenue	$	10,963	$	17,578		Operating Revenue	$	—	$	—
Commodity Contracts — Energy Marketing segment	$	603		$	5,303	Purchased Gas	$	5,302	$	(447	)	Purchased Gas	$	—	$	—
Commodity Contracts — Pipeline & Storage segment	$	(215	)	$	1,012	Operating Revenue	$	—	$	512		Operating Revenue	$	—	$	—
Total	$	(67,980	)	$	22,780		$	16,265	$	17,643			$	—	$	—

     Fair value hedges

     The Company’s Energy Marketing segment utilizes fair value hedges to mitigate risk associated with fixed price sales commitments, fixed price purchase commitments, and the decline in the value of natural gas held in storage. With respect to fixed price sales commitments, the Company enters into long positions to mitigate the risk of price increases for natural gas supplies that could occur after the Company enters into fixed price sales agreements with its customers. With respect to fixed price purchase commitments, the Company enters into short positions to mitigate the risk of price decreases that could occur after the Company locks into fixed price purchase deals with its suppliers. With respect to storage hedges, the Company enters into short positions to mitigate the risk of price decreases that could result in a lower of cost or market writedown of the value of natural gas in storage that is recorded in the Company’s financial statements. As of March 31, 2011, the Company’s Energy Marketing segment had fair value hedges covering approximately 10.6 Bcf (7.9 Bcf of fixed price sales commitments (all long positions) and 2.7 Bcf of fixed price purchase commitments (all short positions)). For derivative instruments that are designated and qualify

-22-

Item 1. Financial Statements (Cont.)

as a fair value hedge, the gain or loss on the derivative as well as the offsetting gain or loss on the hedged item attributable to the hedged risk completely offset each other in current earnings, as shown below.

Consolidated
Statement of Income	Gain/(Loss) on Derivative			Gain/(Loss) on Commitment
Operating Revenues	$	10,625,997		$	(10,625,997	)
Purchased Gas	$	(1,470,609	)	$	1,470,609

		Amount of Derivative Gain or (Loss)
		Recognized in the Consolidated
Derivatives in	Location of Derivative Gain or (Loss)	Statement of Income for the Six
Fair Value Hedging	Recognized in the Consolidated	Months Ended March 31, 2011
Relationships	Statement of Income	(In Thousands)
Commodity Contracts — Energy Marketing segment(1)	Operating Revenues	$	10,626
Commodity Contracts — Energy Marketing segment(2)	Purchased Gas	$	(1,167	)
Commodity Contracts — Energy Marketing segment(3)	Purchased Gas	$	(304	)
		$	9,155

(1)	Represents hedging of fixed price sales commitments of natural gas.
(2)	Represents hedging of fixed price purchase commitments of natural gas.
(3)	Represents hedging of natural gas held in storage.

     The Company may be exposed to credit risk on any of the derivative financial instruments that are in a gain position. Credit risk relates to the risk of loss that the Company would incur as a result of nonperformance by counterparties pursuant to the terms of their contractual obligations. To mitigate such credit risk, management performs a credit check, and then on a quarterly basis monitors counterparty credit exposure. The majority of the Company’s counterparties are financial institutions and energy traders. The Company has over-the-counter swap positions with twelve counterparties of which nine are in a net gain position. The Company had derivative financial instruments that were in loss positions with the other three counterparties. On average, the Company had $4.1 million of credit exposure per counterparty in a gain position at March 31, 2011. The maximum credit exposure per counterparty in a gain position at March 31, 2011 was $7.9 million. The Company had not received any collateral from these counterparties at March 31, 2011 since the Company’s gain position on such derivative financial instruments had not exceeded the established thresholds at which the counterparties would be required to post collateral.

     As of March 31, 2011, nine of the twelve counterparties to the Company’s outstanding derivative instrument contracts (specifically the over-the-counter swaps) had a common credit-risk related contingency feature. In the event the Company’s credit rating increases or falls below a certain threshold (applicable debt ratings), the available credit extended to the Company would either increase or decrease. A decline in the Company’s credit rating, in and of itself, would not cause the Company to be required to increase the level of its hedging collateral deposits (in the form of cash deposits, letters of credit or treasury debt instruments). If the Company’s outstanding derivative instrument contracts were in a liability position (or if the current liability were larger) and/or the Company’s credit rating declined, then additional hedging collateral deposits would be required. At March 31, 2011, the fair market value of the derivative financial instrument assets with a credit-risk related contingency feature was $21.9 million according to the Company’s internal model (discussed in Note 2 — Fair Value Measurements). At March 31, 2011, the fair market value of the derivative financial instrument liabilities with a credit-risk related contingency feature was $67.2 million according to the Company’s internal model (discussed in Note 2 — Fair Value Measurements). The liability with one counterparty was $54.8 million. For its over-the-counter crude oil swap agreements, which are in a liability position, the Company was required to post $54.9 million in hedging collateral deposits at March 31, 2011. This is discussed in Note 1 under Hedging Collateral Deposits.

-23-

Item 1. Financial Statements (Cont.)

     For its exchange traded futures contracts, which are in a liability position, the Company had posted $6.9 million in hedging collateral as of March 31, 2011. As these are exchange traded futures contracts, there are no specific credit-risk related contingency features. The Company posts hedging collateral based on open positions and margin requirements it has with its counterparties.

     The Company’s requirement to post hedging collateral deposits is based on the fair value determined by the Company’s counterparties, which may differ from the Company’s assessment of fair value. Hedging collateral deposits may also include closed derivative positions in which the broker has not cleared the cash from the account to offset the derivative liability. The Company records liabilities related to closed derivative positions in Other Accruals and Current Liabilities on the Consolidated Balance Sheet. These liabilities are relieved when the broker clears the cash from the hedging collateral deposit account. This is discussed in Note 1 under Hedging Collateral Deposits.

Note 4 — Income Taxes

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

	Six Months Ended
	March 31,
	2011			2010
Current Income Taxes
Federal	$	—		$	39,245
State		3,677			9,394
Deferred Income Taxes
Federal		87,598			33,447
State		18,912			8,348
		110,187			90,434
Deferred Investment Tax Credit		(348	)		(348	)
Total Income Taxes	$	109,839		$	90,086
Presented as Follows:
Other Income	$	(348	)	$	(348	)
Income Tax Expense — Continuing Operations		110,187			89,841
Income from Discontinued Operations		—			593
Total Income Taxes	$	109,839		$	90,086

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

	Six Months Ended
	March 31,
	2011			2010
U.S. Income Before Income Taxes	$	283,993		$	235,013
Income Tax Expense, Computed at Federal Statutory Rate of 35%	$	99,398		$	82,255
Increase (Reduction) in Taxes Resulting from:
State Income Taxes		14,683			11,532
Miscellaneous		(4,242	)		(3,701	)
Total Income Taxes	$	109,839		$	90,086

-24-

Item 1. Financial Statements (Cont.)

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

	At March 31, 2011			At September 30, 2010
Deferred Tax Liabilities:
Property, Plant and Equipment	$	966,524		$	849,869
Pension and Other Post-Retirement Benefit Costs		179,360			177,853
Other		37,109			63,671
Total Deferred Tax Liabilities		1,182,993			1,091,393
Deferred Tax Assets:
Pension and Other Post-Retirement Benefit Costs		(225,461	)		(223,588	)
Tax Loss Carryforwards		(16,237	)		(9,772	)
Other		(89,388	)		(81,751	)
Total Deferred Tax Assets		(331,086	)		(315,111	)
Total Net Deferred Income Taxes	$	851,907		$	776,282
Presented as Follows:
Net Deferred Tax Liability/(Asset) — Current	$	(34,917	)	$	(24,476	)
Net Deferred Tax Liability — Non-Current		886,824			800,758
Total Net Deferred Income Taxes	$	851,907		$	776,282

     As a result of certain realization requirements of the authoritative guidance on stock-based compensation, the table of deferred tax liabilities and assets shown above does not include certain deferred tax assets at March 31, 2011 that arose directly from excess tax deductions related to stock-based compensation. A tax benefit of $18.1 million relating to the excess stock-based compensation deductions will be recorded in Paid in Capital in future years when such tax benefit is realized.

     Regulatory liabilities representing the reduction of previously recorded deferred income taxes associated with rate-regulated activities that are expected to be refundable to customers amounted to $69.6 million at both March 31, 2011 and September 30, 2010. 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 $152.0 million and $149.7 million at March 31, 2011 and September 30, 2010, respectively.

     The Company files U.S. federal and various state income tax returns. The Internal Revenue Service (IRS) is currently conducting an examination of the Company for fiscal 2010 and 2011 in accordance with the Compliance Assurance Process (“CAP”). The CAP audit employs a real time review of the Company’s books and tax records by the IRS that is intended to permit issue resolution prior to the filing of the tax return. While the federal statute of limitations remains open for fiscal 2007 and later years, IRS examinations for fiscal 2008 and prior years have been completed and the Company believes such years are effectively settled. During fiscal 2009, consent was received from the IRS National Office approving the Company’s application to change its tax method of accounting for certain capitalized costs relating to its utility property. During fiscal 2010, local IRS examiners proposed to disallow most of the accounting method change recorded by the Company in fiscal 2009. The Company has filed a protest with the IRS Appeals Office disputing the local IRS findings.

     The Company is also subject to various routine state income tax examinations. The Company’s operating subsidiaries mainly operate in four states which have statutes of limitations that generally expire between three to four years from the date of filing of the income tax return.

-25-

Item 1. Financial Statements (Cont.)

Note 5 — Capitalization

Common Stock.During the six months ended March 31, 2011, the Company issued 786,929 original issue shares of common stock as a result of stock option and SARs exercises and 47,250 original issue shares for restricted stock awards (non-vested stock as defined by the current accounting literature for stock-based compensation). The Company also issued 7,200 original issue shares of common stock to the non-employee directors of the Company who receive compensation under the Company’s 2009 Non-Employee Director Equity Compensation Plan, as partial consideration for the directors’ services during the six months ended March 31, 2011. Holders of stock options, SARs or restricted stock will often tender shares of common stock to the Company for payment of option exercise prices and/or applicable withholding taxes. During the six months ended March 31, 2011, 372,656 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.

Current Portion of Long-Term Debt.Current Portion of Long-Term Debt at March 31, 2011 consists of $150 million of 6.70% medium-term notes that mature in November 2011. Current Portion of Long-Term Debt at September 30, 2010 consisted of $200 million of 7.50% notes that matured in November 2010.

Note 6 — 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 to 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 agreed with the NYDEC to remediate a former manufactured gas plant site located in New York. The Company has received approval from the NYDEC of a Remedial Design work plan for this site and has recorded an estimated minimum liability for remediation of this site of $14.6 million.

     At March 31, 2011, the Company has estimated its remaining clean-up costs related to former manufactured gas plant sites and third party waste disposal sites (including the former manufactured gas plant site discussed above) will be in the range of $17.1 million to $21.3 million. The minimum estimated liability of $17.1 million, which includes the $14.6 million discussed above, has been recorded on the Consolidated Balance Sheet at March 31, 2011. The Company expects to recover its environmental clean-up costs through rate recovery.

     The Company is currently not aware of any material additional exposure to environmental liabilities. However, changes in environmental regulations, new information or other factors could adversely 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 are they expected to have a material adverse effect on the financial condition of the Company.

-26-

Item 1. Financial Statements (Cont.)

Note 7 — Discontinued Operations

     On September 1, 2010, the Company sold its landfill gas operations in the states of Ohio, Michigan, Kentucky, Missouri, Maryland and Indiana. Those operations consisted of short distance landfill gas pipeline companies engaged in the purchase, sale and transportation of landfill gas. The Company’s landfill gas operations were maintained under the Company’s wholly-owned subsidiary, Horizon LFG. The decision to sell was based on progressing the Company’s strategy of divesting its smaller, non-core assets in order to focus on its core businesses, including the development of the Marcellus Shale and the construction of key pipeline infrastructure projects throughout the Appalachian region. As a result of the decision to sell the landfill gas operations, the Company began presenting these operations as discontinued operations during the fourth quarter of 2010.

     The following is selected financial information of the discontinued operations for the sale of the Company’s landfill gas operations:

	Three Months Ended			Six Months Ended
	March 31,			March 31,
(Thousands)	2010			2010
Operating Revenues	$	3,400		$	6,277
Operating Expenses		2,445			4,845
Operating Income		955			1,432
Other Interest Expense		(4	)		(11	)
Income before Income Taxes		951			1,421
Income Tax Expense		397			593
Income from Discontinued Operations	$	554		$	828

Note 8 — Business Segment Information

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

     The data presented in the tables below reflect financial information for the segments and reconciliations to consolidated amounts. As stated in the 2010 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 2010 Form 10-K. There have been no material changes in the amount of assets for any operating segment from the amounts disclosed in the 2010 Form 10-K.

Quarter Ended March 31, 2011 (Thousands)

					Exploration				Total				Corporate and
			Pipeline and		and				Reportable				Intersegment			Total
	Utility		Storage		Production		Energy Marketing		Segments		All Other		Eliminations			Consolidated
Revenue from External Customers	$	361,745	$	39,669	$	137,430	$	121,321	$	660,165	$	472	$	244		$	660,881
Intersegment Revenues	$	6,635	$	20,632	$	—	$	—	$	27,267	$	2,538	$	(29,805	)	$	—
Segment Profit:
Net Income (Loss)	$	33,081	$	10,955	$	33,299	$	6,299	$	83,634	$	32,181	$	(204	)	$	115,611

-27-

Item 1.Financial Statements (Cont.)

Six Months Ended March 31, 2011 (Thousands)

					Exploration				Total				Corporate and
			Pipeline and		and		Energy		Reportable				Intersegment			Total
	Utility		Storage		Production		Marketing		Segments		All Other		Eliminations			Consolidated
Revenue from External Customers	$	604,587	$	73,182	$	257,598	$	174,973	$	1,110,340	$	1,021	$	468		$	1,111,829
Intersegment Revenues	$	11,205	$	40,514	$	—	$	—	$	51,719	$	4,216	$	(55,935	)	$	—
Segment Profit:
Net Income (Loss)	$	56,071	$	19,533	$	60,672	$	7,231	$	143,507	$	31,606	$	(959	)	$	174,154

Quarter Ended March 31, 2010 (Thousands)

					Exploration				Total				Corporate and
			Pipeline and		and		Energy		Reportable				Intersegment			Total
	Utility		Storage		Production		Marketing		Segments		All Other		Eliminations			Consolidated
Revenue from External Customers	$	348,593	$	40,971	$	109,158	$	158,537	$	657,259	$	10,503	$	218		$	667,980
Intersegment Revenues	$	6,149	$	20,565	$	—	$	—	$	26,714	$	—	$	(26,714	)	$	—
Segment Profit:
Income (Loss) from Continuing Operations	$	33,273	$	12,448	$	27,383	$	5,969	$	79,073	$	1,020	$	(219	)	$	79,874

Six Months Ended March 31, 2010 (Thousands)

					Exploration				Total				Corporate and
			Pipeline and		and		Energy		Reportable				Intersegment			Total
	Utility		Storage		Production		Marketing		Segments		All Other		Eliminations			Consolidated
Revenue from External Customers	$	580,997	$	75,475	$	215,511	$	230,273	$	1,102,256	$	19,430	$	429		$	1,122,115
Intersegment Revenues	$	10,662	$	40,822	$	—	$	—	$	51,484	$	—	$	(51,484	)	$	—
Segment Profit:
Income (Loss) from Continuing Operations	$	56,286	$	22,802	$	57,163	$	7,061	$	143,312	$	1,910	$	(1,123	)	$	144,099

Note 9 — Investments in Unconsolidated Subsidiaries

     At March 31, 2011, the Company owns a 50% interest in ESNE. ESNE is an 80-megawatt, combined cycle, natural gas-fired turbine power plant in North East, Pennsylvania that is in the process of being dismantled. The Company expects to recover its investment in ESNE through the sale of ESNE’s major assets, such as the power turbines.

     During the quarter ended March 31, 2011, the Company sold its 50% equity method investments in Seneca Energy and Model City for $59.4 million, resulting in a gain of $50.9 million. Seneca Energy and Model City generate and sell electricity using methane gas obtained from landfills owned by outside parties.

-28-

Item 1.Financial Statements (Cont.)

     A summary of the Company’s investments in unconsolidated subsidiaries at March 31, 2011 and September 30, 2010 is as follows (in thousands):

	At March 31, 2011		At September 30, 2010
Seneca Energy	$	—	$	11,007
Model City		—		2,017
ESNE		1,443		1,804
	$	1,443	$	14,828

Note 10 — Retirement Plan and Other Post-Retirement Benefits

     Components of Net Periodic Benefit Cost (in thousands):

Three months ended March 31,

	Retirement Plan						Other Post-Retirement Benefits
	2011			2010			2011			2010
Service Cost	$	3,693		$	3,249		$	1,069		$	1,075
Interest Cost		10,669			11,077			5,471			6,254
Expected Return on Plan Assets		(14,776	)		(14,585	)		(7,291	)		(6,584	)
Amortization of Prior Service Cost		147			164			(427	)		(427	)
Amortization of Transition Amount		—			—			135			135
Amortization of Losses		8,718			5,410			5,948			6,470
Net Amortization and Deferral for
Regulatory Purposes (Including
Volumetric Adjustments)(1)		3,556			3,858			6,042			3,588
Net Periodic Benefit Cost	$	12,007		$	9,173		$	10,947		$	10,511

Six months ended March 31,

	Retirement Plan						Other Post-Retirement Benefits
	2011			2010			2011			2010
Service Cost	$	7,386		$	6,498		$	2,138		$	2,149
Interest Cost		21,338			22,154			10,942			12,508
Expected Return on Plan Assets		(29,552	)		(29,170	)		(14,582	)		(13,167	)
Amortization of Prior Service Cost		294			328			(854	)		(854	)
Amortization of Transition Amount		—			—			270			270
Amortization of Losses		17,437			10,820			11,896			12,941
Net Amortization and Deferral for
Regulatory Purposes (Including
Volumetric Adjustments)(1)		1,762			3,816			7,963			3,487
Net Periodic Benefit Cost	$	18,665		$	14,446		$	17,773		$	17,334

⁽¹⁾ The Company’s policy is to record retirement plan and other post-retirement benefit costs in the Utility segment on a volumetric basis to reflect the fact that the Utility segment experiences higher throughput of natural gas in the winter months and lower throughput of natural gas in the summer months.

-29-

Item 1.Financial Statements (Concl.)

Employer Contributions.During the six months ended March 31, 2011, the Company contributed $32.4 million to its tax-qualified, noncontributory defined-benefit retirement plan (Retirement Plan) and $16.0 million to its VEBA trusts and 401(h) accounts for its other post-retirement benefits. In the remainder of 2011, the Company expects to contribute at a minimum in the range of $7.0 million to $15.0 million to the Retirement Plan. Changes in the discount rate, other actuarial assumptions, and asset performance could ultimately cause the Company to fund larger amounts to the Retirement Plan in fiscal 2011 in order to be in compliance with the Pension Protection Act of 2006. In the remainder of 2011, the Company expects to contribute in the range of $9.0 million to $14.0 million to its VEBA trusts and 401(h) accounts.

Note 11 — Subsequent Event

     In March 2011, the Company entered into a purchase and sale agreement to sell its off-shore oil and natural gas properties in the Gulf of Mexico effective as of January 1, 2011 for approximately $70 million and received a deposit of $7.0 million from the purchaser. The Company completed the sale in April 2011, receiving an additional $54.8 million. The difference between the total proceeds received of $61.8 million and the sale price of $70.0 million represents a purchase price adjustment for the operating cash flow that the Company recorded from January 1, 2011 to the closing date of the sale. Under the full cost method of accounting for oil and natural gas properties, the sale proceeds were accounted for as a reduction of capitalized costs in April 2011. Since the disposition did not significantly alter the relationship between capitalized costs and proved reserves of oil and gas attributable to the cost center, the Company did not record any gain or loss from this sale.

-30-

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

OVERVIEW

[Please note that this overview is a high-level summary
of items that are discussed in greater detail in subsequent sections of this report.]

     The Company is a diversified energy holding company that owns a number of subsidiary operating companies, and reports financial results in four reportable business segments. For the quarter ended March 31, 2011 compared to the quarter ended March 31, 2010, the Company experienced an increase in earnings of $35.2 million. For the six months ended March 31, 2011 compared to the six months ended March 31, 2010, the Company experienced an increase in earnings of $29.2 million. The earnings increase for both the quarter and six-month periods is primarily due to the recognition of a gain on the sale of unconsolidated subsidiaries of $50.9 million ($31.4 million after tax) during the current quarter in the All Other category. In February 2011, the Company sold its 50% equity method investments in Seneca Energy and Model City for $59.4 million. Seneca Energy and Model City generate and sell electricity using methane gas obtained from landfills owned by outside parties. The sale is the result of the Company’s strategy to pursue the sale of smaller, non-core assets in order to focus on its core businesses, including the development of the Marcellus Shale and the expansion of its pipeline business throughout the Appalachian region.

     The Marcellus Shale is a Middle Devonian-age geological shale formation that is present nearly a mile or more below the surface in the Appalachian region of the United States, including much of Pennsylvania and southern New York. Due to the depth at which this formation is found, drilling and completion costs, including the drilling and completion of horizontal wells with hydraulic fracturing, are very expensive. However, independent geological studies have indicated that this formation could yield natural gas reserves measured in the trillions of cubic feet. The Company controls approximately 745,000 net acres within the Marcellus Shale area of Pennsylvania, with a majority of the acreage held in fee, carrying no royalty and no lease expirations. The Company’s reserve base has grown substantially from development in the Marcellus Shale. Natural gas proved developed and undeveloped reserves in the Appalachian region increased from 150 Bcf at September 30, 2009 to 331 Bcf at September 30, 2010. With this in mind, and with a natural desire to realize the value of these assets in a responsible and orderly fashion, the Company has spent significant amounts of capital in this region. For the six months ended March 31, 2011, the Company spent $295.7 million towards the development of the Marcellus Shale. This includes paying $24.1 million in November 2010 for the acquisition of additional oil and gas properties in the Covington Township area of Tioga County, Pennsylvania from EOG Resources, Inc. These properties are producing natural gas from the Marcellus Shale and are also prospective for additional Marcellus reserves. As a result of the transaction, it is anticipated that the Appalachian region of the Exploration and Production segment will add approximately 42 Bcf of proved natural gas reserves, thereby having an immediate positive impact on the Company’s production and proved reserves.

     As the Company has been accelerating its Marcellus Shale development, it has been decreasing its emphasis in the Gulf Coast region. In March 2011, the Company entered into a purchase and sale agreement to sell its off-shore oil and natural gas properties effective as of January 1, 2011 in the Gulf of Mexico for approximately $70 million and received a deposit of $7.0 million from the purchaser. The Company completed the sale in April 2011, receiving an additional $54.8 million. The difference between the total proceeds received of $61.8 million and the sale price of $70.0 million represents a purchase price adjustment for the operating cash flow that the Company recorded from January 1, 2011 to the closing date of the sale. Under the full cost method of accounting for oil and natural gas properties, the sale proceeds were accounted for as a reduction of capitalized costs in April 2011. Since the disposition did not significantly alter the relationship between capitalized costs and proved reserves of oil and gas attributable to the cost center, the Company did not record any gain or loss from this sale.

     The Company has engaged Jefferies & Company to explore joint-venture opportunities across its Marcellus Shale acreage in its Exploration and Production segment. It is the Company’s goal to accelerate Marcellus Shale development faster than its current plans. By entering into a joint-venture agreement, the Company expects to enhance shareholder value by shifting a significant portion of the early drilling costs to a noncontrolling-interest partner while still allowing the Company to continue operating across most of its acreage. The Company’s position in the Marcellus Shale provides a competitive advantage for a potential joint-venture partner as a majority of the acreage is held in fee, carrying no royalty and no lease expirations,

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

and large, contiguous acreage blocks allow for operating- and cost-efficiency through multi-well pad drilling. The Company will forgo any joint-venture opportunities that do not enhance shareholder value when compared to its current growth plans.

     Coincident with the development of its Marcellus Shale acreage, the Company’s Pipeline and Storage segment is building pipeline gathering and transmission facilities to connect Marcellus Shale production with existing pipelines in the region and is pursuing the development of additional pipeline and storage capacity in order to meet anticipated demand for the large amount of Marcellus Shale production expected to come on-line in the months and years to come. Two of the projects, the Tioga County Extension Project and the Northern Access expansion project, are considered significant for Empire and Supply Corporation. Both projects are designed to receive natural gas produced from the Marcellus Shale and transport it to Canada and the Northeast United States to meet growing demand in those areas. During the past year, Empire and Supply Corporation have experienced a decline in the volumes of natural gas received at the Canada/United States border at the Niagara River to be shipped across their systems. The historical price advantage for gas sold at the Niagara import points has declined as production in the Canadian producing regions has declined or been diverted to other demand areas, and as production from new shale plays has increased in the United States. This factor has been causing shippers to seek alternative gas supplies and consequently alternative transportation routes. The Tioga County Extension Project and the Northern Access expansion project are designed to provide an alternative gas supply source for the customers of Empire and Supply Corporation. These projects, which are discussed more completely in the Investing Cash Flow section that follows, will involve significant capital expenditures.

     From a capital resources perspective, the Company has been able to meet its capital expenditure needs for all of the above projects by using cash from operations and short-term borrowings. The Company had $144.8 million in Cash and Temporary Cash Investments at March 31, 2011, as shown on the Company’s Consolidated Balance Sheet. For the remainder of fiscal 2011, the Company expects that it will be able to use cash on hand, cash from operations, and cash from asset sales as its first means of financing capital expenditures, with short-term borrowings and long-term borrowings being its next sources of funding. It is not expected that long-term financing will be required to meet capital expenditure needs until the later part of fiscal 2011 or in fiscal 2012.

     The possibility of environmental risks associated with a well completion technology referred to as hydraulic fracturing continues to be debated. In Pennsylvania, where the Company is focusing its Marcellus Shale development efforts, the permitting and regulatory processes seem to strike a balance between the environmental concerns associated with hydraulic fracturing and the benefits of increased natural gas production. Hydraulic fracturing is a well stimulation technique that has been used for many years, and in the Company’s experience, one that the Company believes has little negative impact to the environment. Nonetheless, the potential for increased state or federal regulation of hydraulic fracturing could impact future costs of drilling in the Marcellus Shale and lead to operational delays or restrictions. There is also the risk that drilling could be prohibited on certain acreage that is prospective for the Marcellus Shale. For example, New York State currently has a moratorium in place that prevents hydraulic fracturing of new horizontal wells in the Marcellus Shale. However, due to the small amount of Marcellus Shale acreage owned by the Company in New York State, the moratorium is not expected to have a significant impact on the Company’s plans for Marcellus Shale development. Please refer to the Risk Factors section of the Form 10-K for the year ended September 30, 2010 as well as updates to that section in the Form 10-Q for the quarter ended December 31, 2010 for further discussion.

CRITICAL ACCOUNTING ESTIMATES

     For a complete discussion of critical accounting estimates, refer to “Critical Accounting Estimates” in Item 7 of the Company’s 2010 Form 10-K and Item 2 of the Company’s December 31, 2010 Form 10-Q. There have been no material changes to those disclosures other than as set forth below. The information presented below updates and should be read in conjunction with the critical accounting estimates in those documents.

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

Oil and Gas Exploration and Development Costs.The Company, in its Exploration and Production segment, follows the full cost method of accounting for determining the book value of its oil and natural gas properties. In accordance with this methodology, the Company is required to perform a quarterly ceiling test. Under the ceiling test, the present value of future revenues from the Company’s oil and gas reserves based on an unweighted arithmetic average of the first day of the month oil and gas prices for each month within the twelve-month period prior to the end of the reporting period (the “ceiling”) is compared with the book value of the Company’s oil and gas properties at the balance sheet date. If the book value of the oil and gas properties exceeds the ceiling, a non-cash impairment charge must be recorded to reduce the book value of the oil and gas properties to the calculated ceiling. At March 31, 2011, the ceiling exceeded the book value of the oil and gas properties by approximately $230 million. The 12-month average of the first day of the month price for crude oil for each month during the twelve months ended March 31, 2011, based on posted Midway-Sunset prices was $77.73 per Bbl. The 12-month average of the first day of the month price for natural gas for each month during the twelve months ended March 31, 2011, based on the quoted Henry Hub spot price for natural gas, was $4.10 per MMBtu. (Note — Because actual pricing of the Company’s various producing properties varies depending on their location and hedging, the actual various prices received for such production is utilized to calculate the ceiling, rather than the Midway-Sunset and Henry Hub prices, which are only indicative of 12-month average prices for the twelve months ended March 31, 2011.) If natural gas average prices used in the ceiling test calculation at March 31, 2011 had been $1 per MMBtu lower, the ceiling would have exceeded the book value of the Company’s oil and gas properties by approximately $77 million. If crude oil average prices used in the ceiling test calculation at March 31, 2011 had been $5 per Bbl lower, the ceiling would have exceeded the book value of the Company’s oil and gas properties by approximately $184 million. If both natural gas and crude oil average prices used in the ceiling test calculation at March 31, 2011 were lower by $1 per MMBtu and $5 per Bbl, respectively, the ceiling would have exceeded the book value of the Company’s oil and gas properties by approximately $31 million. These calculated amounts are based solely on price changes and do not take into account any other changes to the ceiling test calculation. For a more complete discussion of the full cost method of accounting, refer to “Oil and Gas Exploration and Development Costs” under “Critical Accounting Estimates” in Item 7 of the Company’s 2010 Form 10-K.

RESULTS OF OPERATIONS

Earnings

     The Company’s earnings were $115.6 million for the quarter ended March 31, 2011 compared to earnings of $80.4 million for the quarter ended March 31, 2010. As previously discussed, the Company sold its landfill gas operations in the states of Ohio, Michigan, Kentucky, Missouri, Maryland and Indiana in September 2010. Accordingly, all financial results for these operations, which are part of the All Other category, have been presented as discontinued operations. The Company’s earnings from continuing operations were $115.6 million for the quarter ended March 31, 2011 compared with $79.9 million for the quarter ended March 31, 2010. The increase in earnings from continuing operations of $35.7 million is primarily a result of higher earnings in the All Other category and the Exploration and Production segment. Lower earnings in the Pipeline and Storage segment slightly offset these increases. The Company’s earnings for the quarter ended March 31, 2011 include a $50.9 million ($31.4 million after tax) gain on the sale of unconsolidated subsidiaries as a result of the Company’s sale of its 50% equity method investments in Seneca Energy and Model City, as discussed above.

     The Company’s earnings were $174.2 million for the six months ended March 31, 2011 compared to earnings of $144.9 million for the six months ended March 31, 2010. The Company’s earnings from continuing operations were $174.2 million for the six months ended March 31, 2011 compared with $144.1 million for the six months ended March 31, 2010. The increase in earnings from continuing operations of $30.1 million is primarily the result of higher earnings in the All Other category and the Exploration and Production segment. Lower earnings in the Pipeline and Storage segment slightly offset these increases. The Company’s earnings for the six months ended March 31, 2011 include a $50.9 million ($31.4 million after tax) gain on the sale of unconsolidated subsidiaries, as discussed above.

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

     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, unless otherwise noted.

Earnings (Loss) by Segment

	Three Months Ended									Six Months Ended
	March 31,									March 31,
							Increase									Increase
(Thousands)	2011			2010			(Decrease)			2011			2010			(Decrease)
Utility	$	33,081		$	33,273		$	(192	)	$	56,071		$	56,286		$	(215	)
Pipeline and Storage		10,955			12,448			(1,493	)		19,533			22,802			(3,269	)
Exploration and Production		33,299			27,383			5,916			60,672			57,163			3,509
Energy Marketing		6,299			5,969			330			7,231			7,061			170
Total Reportable Segments		83,634			79,073			4,561			143,507			143,312			195
All Other		32,181			1,020			31,161			31,606			1,910			29,696
Corporate		(204	)		(219	)		15			(959	)		(1,123	)		164
Total Earnings from Continuing Operations		115,611			79,874			35,737			174,154			144,099			30,055
Earnings from Discontinued Operations		—			554			(554	)		—			828			(828	)
Total Consolidated	$	115,611		$	80,428		$	35,183		$	174,154		$	144,927		$	29,227

Utility

Utility Operating Revenues

	Three Months Ended							Six Months Ended
	March 31,							March 31,
					Increase							Increase
(Thousands)	2011		2010		(Decrease)			2011		2010		(Decrease)
Retail Sales Revenues:
Residential	$	263,596	$	256,447	$	7,149		$	440,785	$	433,043	$	7,742
Commercial		38,813		38,311		502			61,359		62,717		(1,358	)
Industrial		2,900		2,594		306			4,144		3,883		261
		305,309		297,352		7,957			506,288		499,643		6,645
Transportation		44,951		40,509		4,442			80,363		71,203		9,160
Off-System Sales		16,699		13,314		3,385			25,589		15,005		10,584
Other		1,421		3,567		(2,146	)		3,552		5,808		(2,256	)
	$	368,380	$	354,742	$	13,638		$	615,792	$	591,659	$	24,133

Utility Throughput

	Three Months Ended						Six Months Ended
	March 31,						March 31,
(MMcf)	2011		2010		Increase		2011		2010		Increase
Retail Sales:
Residential		28,048		26,413		1,635		45,207		43,237		1,970
Commercial		4,372		4,256		116		6,842		6,746		96
Industrial		393		288		105		539		446		93
		32,813		30,957		1,856		52,588		50,429		2,159
Transportation		27,472		24,366		3,106		45,581		41,427		4,154
Off-System Sales		3,458		2,554		904		5,321		2,910		2,411
		63,743		57,877		5,866		103,490		94,766		8,724

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

Degree Days

							Percent
Three Months Ended							Colder (Warmer) Than
March 31	Normal		2011		2010		Norm al(1)		Prior Year(1)
Buffalo		3,327		3,494		3,241		5.0		7.8
Erie		3,142		3,312		3,163		5.4		4.7

Six Months Ended March 31
Buffalo	5,587	5,826	5,487	4.3	6.2
Erie	5,223	5,472	5,211	4.8	5.0

⁽¹⁾ Percents compare actual 2011 degree days to normal degree days and actual 2011 degree days to actual 2010 degree days.

2011 Compared with 2010

     Operating revenues for the Utility segment increased $13.6 million for the quarter ended March 31, 2011 as compared with the quarter ended March 31, 2010. This increase largely resulted from an $8.0 million increase in retail gas sales revenues, a $4.4 million increase in transportation revenues and a $3.4 million increase in off-system sales revenues. These increases were partially offset by a $2.1 million decrease in other operating revenues. The increase in retail gas sales revenues of $8.0 million was largely a function of higher volumes (1.9 Bcf) due to colder weather and higher customer usage per account. The phrase “usage per account” refers to the average gas consumption per customer account after factoring out any impact that weather may have had on consumption. The increase in volumes resulted in the recovery of a larger amount of gas costs, despite a decline in the Utility segment’s average cost of purchased gas. The Utility segment’s average cost of purchased gas, including the cost of transportation and storage, was $6.31 per Mcf for the three months ended March 31, 2011, a decrease of 17.1% from the average cost of $7.61 per Mcf for the three months ended March 31, 2010. Subject to certain timing variations, gas costs are recovered dollar for dollar in revenues. The increase in transportation revenues of $4.4 million was primarily due to a 3.1 Bcf increase in transportation throughput, largely the result of colder weather and the migration of customers from retail sales to transportation service. The increase in off-system sales revenues was largely due to an increase in off-system sales volume. Due to profit sharing with retail customers, the margins resulting from off-system sales are minimal and there was not a material impact to margins. The $2.1 million decrease in other operating revenues was largely attributable to a regulatory adjustment to reduce a previous undercollection of pension and other post-retirement benefit costs.

     Operating revenues for the Utility segment increased $24.1 million for the six months ended March 31, 2011 as compared with the six months ended March 31, 2010. This increase largely resulted from a $6.6 million increase in retail gas sales revenues, a $9.2 million increase in transportation revenues and a $10.6 million increase in off-system sales revenues. These increases were partially offset by a $2.3 million decrease in other operating revenues. The increase in retail gas sales revenues of $6.6 million was largely a function of higher volumes (2.2 Bcf) due to colder weather and higher customer usage per account. The increase in volumes resulted in the recovery of a larger amount of gas costs, despite a decline in the Utility segment’s average cost of purchased gas. The Utility segment’s average cost of purchased gas, including the cost of transportation and storage, was $6.19 per Mcf for the six months ended March 31, 2011, a decrease of 15.9% from the average cost of $7.36 per Mcf for the six months ended March 31, 2010. Subject to certain timing variations, gas costs are recovered dollar for dollar in revenues. The increase in transportation revenues of $9.2 million was primarily due to a 4.2 Bcf increase in transportation throughput, largely the result of colder weather and the migration of customers from retail sales to transportation service. The increase in off-system sales revenues was largely due to an increase in off-system sales volume. Due to profit sharing with retail customers, the margins resulting from off-system sales are minimal and there was not a material impact to margins. The $2.3 million decrease in other operating revenues was largely attributable to a regulatory adjustment to reduce a previous undercollection of pension and other post-retirement benefit costs.

     The Utility segment’s earnings for the quarter ended March 31, 2011 were $33.1 million, a decrease of $0.2 million when compared with earnings of $33.3 million for the quarter ended March 31, 2010.

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

     In the New York jurisdiction, earnings decreased $1.3 million. The decrease in earnings was mainly due to the decrease in other operating revenues ($1.4 million), which was largely attributable to a regulatory adjustment to reduce a previous undercollection of pension and other post-retirement benefit costs.

     In the Pennsylvania jurisdiction, earnings increased $1.1 million. The earnings increase was largely attributable to higher usage per account ($1.0 million) and colder weather ($0.5 million).

     The impact of weather variations on earnings in the New York jurisdiction is mitigated by that jurisdiction’s weather normalization clause (WNC). The WNC in New York, which covers the eight-month period from October through May, has had a stabilizing effect on earnings for the New York rate jurisdiction. In addition, in periods of colder than normal weather, the WNC benefits the Utility segment’s New York customers. For the quarter ended March 31, 2011, the WNC reduced earnings by $0.7 million, as it was colder than normal. The WNC did not have a significant earnings impact during the quarter ended March 31, 2010.

     The Utility segment’s earnings for the six months ended March 31, 2011 were $56.1 million, a decrease of $0.2 million when compared with earnings of $56.3 million for the six months ended March 31, 2010.

     In the New York jurisdiction, earnings decreased $2.5 million. The decrease in earnings was mainly due to the decrease in other operating revenues ($1.4 million), which was largely attributable to a regulatory adjustment to reduce a previous undercollection of pension and other post-retirement benefit costs. In addition, the negative earnings impact associated with an increase in other taxes ($0.5 million), higher depreciation expense ($0.3 million), higher interest expense ($0.3 million) and higher income tax expense ($0.2 million) further reduced earnings.

     In the Pennsylvania jurisdiction, earnings increased $2.3 million. The earnings increase was largely attributable to higher usage per account ($1.5 million) and colder weather ($1.0 million). In addition, the positive earnings impact associated with lower interest expense on deferred gas costs ($0.6 million) further increased earnings. These increases were partially offset by the negative earnings impact associated with higher income tax expense of $0.4 million and higher operating expenses of $0.4 million. Operating expenses increased primarily because of higher pension costs.

     For the six months ended March 31, 2011, the WNC reduced earnings by $0.8 million, as it was colder than normal. The WNC did not have a significant earnings impact during the quarter ended March 31, 2010.

Pipeline and Storage

Pipeline and Storage Operating Revenues

	Three Months Ended							Six Months Ended
	March 31,							March 31,
					Increase							Increase
(Thousands)	2011		2010		(Decrease)			2011		2010		(Decrease)
Firm Transportation	$	37,290	$	38,294	$	(1,004	)	$	72,240	$	74,722	$	(2,482	)
Interruptible Transportation		415		535		(120	)		730		840		(110	)
		37,705		38,829		(1,124	)		72,970		75,562		(2,592	)
Firm Storage Service		16,859		16,763		96			33,461		33,386		75
Interruptible Storage Service		2		2		—			19		59		(40	)
Other		5,735		5,942		(207	)		7,246		7,290		(44	)
	$	60,301	$	61,536	$	(1,235	)	$	113,696	$	116,297	$	(2,601	)

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

Pipeline and Storage Throughput

	Three Months Ended							Six Months Ended
	March 31,							March 31,
					Increase							Increase
(MMcf)	2011		2010		(Decrease)			2011		2010		(Decrease)
Firm Transportation		123,969		112,146		11,823			213,218		192,785		20,433
Interruptible Transportation		1,095		1,804		(709	)		1,220		2,559		(1,339	)
		125,064		113,950		11,114			214,438		195,344		19,094

2011 Compared with 2010

     Operating revenues for the Pipeline and Storage segment decreased $1.2 million in the quarter ended March 31, 2011 as compared with the quarter ended March 31, 2010. The decrease was primarily due to a decrease in transportation revenues of $1.1 million. This decrease was primarily the result of a reduction in the level of short-term contracts entered into by shippers quarter over quarter as shippers utilized lower priced pipeline transportation routes and a decrease in the gathering rate under Supply Corporation’s tariff. Shippers are seeking alternative lower priced gas supply (and in some cases, not renewing short-term transportation contracts) because of the relatively higher price of natural gas supplies available at the United States/Canadian border at the Niagara River near Buffalo, New York compared to the lower pricing for supplies available at Leidy, Pennsylvania. Empire’s proposed Tioga County Extension Project and Supply Corporation’s Northern Access expansion project, both of which are discussed in the Investing Cash Flow section that follows, are designed to utilize that available pipeline capacity by receiving natural gas produced from the Marcellus Shale and transporting it to Canada and the Northeast United States where demand has been growing.

     Operating revenues for the Pipeline and Storage segment for the six months ended March 31, 2011 decreased $2.6 million as compared with the six months ended March 31, 2010. The decrease was primarily due to a decrease in transportation revenues of $2.6 million, which was primarily the result of a reduction in the level of short-term contracts entered into by shippers period over period as shippers utilized lower priced pipeline transportation routes, as discussed above.

     Volume fluctuations generally do not have a significant impact on revenues as a result of the straight fixed-variable rate design utilized by Supply Corporation and Empire, but this rate design does not protect Supply Corporation or Empire in situations where shippers do not contract for that capacity at the same quantity and rate. In that situation, Supply Corporation or Empire can propose revised rates and services in a rate case at the FERC. Transportation volume for the quarter ended March 31, 2011 increased by 11.1 Bcf from the prior year’s quarter. For the six months ended March 31, 2011, transportation volumes increased by 19.1 Bcf from the prior year’s six-month period. While transportation volume increased largely due to colder weather, there was little impact on revenues due to the straight fixed-variable rate design.

     The Pipeline and Storage segment’s earnings for the quarter ended March 31, 2011 were $11.0 million, a decrease of $1.4 million when compared with earnings of $12.4 million for the quarter ended March 31, 2010. The earnings decrease was primarily due to the earnings impact of lower transportation revenues of $0.7 million, as discussed above, combined with higher operating expenses ($0.9 million). The increase in operating expenses can primarily be attributed to higher pension expense and higher personnel costs. Higher property taxes ($0.3 million) and higher depreciation expense ($0.2 million) also contributed to the decrease in earnings. The increase in property taxes is primarily a result of additional property and higher Pennsylvania public utility realty taxes. The increase in depreciation expense is primarily the result of Supply Corporation’s Lamont Project being placed in service on June 15, 2010 as well as additional projects that were placed in service in the last year. These earnings decreases were slightly offset by an increase in the allowance for funds used during construction (equity component) of $0.3 million primarily due to construction commencing during the current quarter on Supply Corporation’s Line N Expansion Project and Lamont Phase II Project, projects designed to move anticipated Marcellus production gas to other interstate pipelines and to markets beyond the Supply Corporation system, as discussed in the Investing Cash Flow section that follows.

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

     The Pipeline and Storage segment’s earnings for the six months ended March 31, 2011 were $19.5 million, a decrease of $3.3 million when compared with earnings of $22.8 million for the six months ended March 31, 2010. The decrease in earnings is primarily due to the earnings impact of lower transportation revenues of $1.7 million, as discussed above, combined with higher operating expenses ($1.8 million), higher property taxes ($0.3 million), and higher depreciation expense ($0.3 million). The increase in operating expenses can primarily be attributed to higher pension expense and higher personnel costs. The increase in property taxes is primarily a result of additional property and higher Pennsylvania public utility realty taxes. The increase in depreciation expense is primarily the result of Supply Corporation’s Lamont Project being placed in service on June 15, 2010 as well as additional projects that were placed in service in the last year. These earnings decreases were partially offset by an increase in the allowance for funds used during construction (equity component) of $0.5 million primarily due to construction commencing during the current quarter on Supply Corporation’s Line N Expansion Project and Lamont Phase II Project, as discussed above, and lower income tax expense ($0.4 million) due to a lower effective tax rate.

Exploration and Production

Exploration and Production Operating Revenues

	Three Months Ended									Six Months Ended
	March 31,									March 31,
							Increase									Increase
(Thousands)	2011			2010			(Decrease)			2011			2010			(Decrease)
Gas (after Hedging)	$	73,256		$	46,512		$	26,744		$	131,265		$	87,380		$	43,885
Oil (after Hedging)		61,337			60,215			1,122			120,030			122,910			(2,880	)
Gas Processing Plant		6,659			7,663			(1,004	)		13,342			14,871			(1,529	)
Other		44			116			(72	)		(71	)		162			(233	)
Intrasegment Elimination(1)		(3,866	)		(5,348	)		1,482			(6,968	)		(9,812	)		2,844
	$	137,430		$	109,158		$	28,272		$	257,598		$	215,511		$	42,087

⁽¹⁾ Represents the elimination of certain West Coast gas production revenue included in “Gas (after Hedging)” in the table above that was sold to the gas processing plant shown in the table above. An elimination for the same dollar amount was made to reduce the gas processing plant’s Purchased Gas expense.

Production Volumes

	Three Months Ended							Six Months Ended
	March 31,							March 31,
					Increase							Increase
	2011		2010		(Decrease)			2011		2010		(Decrease)
Gas Production(MMcf)
Gulf Coast		2,056		2,643		(587	)		4,070		5,333		(1,263	)
West Coast		855		930		(75	)		1,790		1,926		(136	)
Appalachia		10,848		3,542		7,306			18,930		6,344		12,586
Total Production		13,759		7,115		6,644			24,790		13,603		11,187
Oil Production(Mbbl)
Gulf Coast		92		109		(17	)		197		255		(58	)
West Coast		643		661		(18	)		1,297		1,345		(48	)
Appalachia		11		9		2			21		20		1
Total Production		746		779		(33	)		1,515		1,620		(105	)

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

Average Prices

	Three Months Ended							Six Months Ended
	March 31,							March 31,
					Increase							Increase
	2011		2010		(Decrease)			2011		2010		(Decrease)
Average Gas Price/Mcf
Gulf Coast	$	4.87	$	6.02	$	(1.15	)	$	4.71	$	5.42	$	(0.71	)
West Coast	$	4.46	$	5.79	$	(1.33	)	$	4.18	$	5.19	$	(1.01	)
Appalachia	$	4.40	$	5.97	$	(1.57	)	$	4.24	$	5.57	$	(1.33	)
Weighted Average	$	4.48	$	5.96	$	(1.48	)	$	4.31	$	5.46	$	(1.15	)
Weighted Average After Hedging	$	5.32	$	6.54	$	(1.22	)	$	5.30	$	6.42	$	(1.12	)
Average Oil Price/bbl
Gulf Coast	$	96.12	$	89.22	$	6.90		$	89.61	$	79.81	$	9.80
West Coast	$	95.35	$	73.16	$	22.19		$	87.84	$	71.72	$	16.12
Appalachia	$	86.53	$	73.80	$	12.73		$	84.07	$	79.67	$	4.40
Weighted Average	$	95.31	$	75.41	$	19.90		$	88.01	$	73.09	$	14.92
Weighted Average After Hedging	$	82.28	$	77.29	$	4.99		$	79.21	$	75.86	$	3.35

2011 Compared with 2010

     Operating revenues for the Exploration and Production segment increased $28.3 million for the quarter ended March 31, 2011 as compared with the quarter ended March 31, 2010. Gas production revenue after hedging increased $26.7 million. Increases in Appalachian natural gas production were partially offset by a $1.22 per Mcf decrease in the weighted average price of gas after hedging. The increase in Appalachian production was primarily due to additional wells within the Marcellus Shale formation, primarily in Tioga County, Pennsylvania, coming on line late in fiscal 2010 and the first six months of fiscal 2011. Oil production revenue after hedging increased $1.1 million. An increase in the weighted average price of oil after hedging ($4.99 per Bbl) was the primary cause, as oil production levels were slightly lower quarter over quarter. The decrease in oil production is a result of the Company switching its emphasis from the Gulf Coast region to the Appalachian region combined with natural declines in the West Coast region. The Company intends to spend modest amounts of capital to maintain West Coast production at current levels in the future. In addition, there was a $0.5 million increase in processing plant revenues (net of eliminations) primarily because of the lower cost of West Coast gas production quarter over quarter.

     Operating revenues for the Exploration and Production segment increased $42.1 million for the six months ended March 31, 2011 as compared with the six months ended March 31, 2010. Gas production revenue after hedging increased $43.9 million. Increases in Appalachian natural gas production were partially offset by a $1.12 per Mcf decrease in the weighted average price of gas after hedging. The increase in Appalachian production was primarily due to additional wells within the Marcellus Shale formation, primarily in Tioga County, Pennsylvania, coming on line late in fiscal 2010 and the first six months of fiscal 2011. Oil production revenue after hedging decreased $2.9 million due to lower crude oil production levels, which were partially offset by an increase in the weighted average price of oil after hedging ($3.35 per Bbl). The decrease in oil production is a result of the Company switching its emphasis from the Gulf Coast region to the Appalachian region combined with natural declines in the West Coast region. The Company intends to spend modest amounts of capital to maintain West Coast production at current levels in the future. In addition, there was a $1.3 million increase in processing plant revenues (net of eliminations) primarily because of the lower cost of West Coast gas production for the six months ended March 31, 2011 as compared to the six months ended March 31, 2010.

     The Exploration and Production segment’s earnings for the quarter ended March 31, 2011 were $33.3 million, an increase of $5.9 million when compared with earnings of $27.4 million for the quarter ended March 31, 2010. Higher crude oil prices and higher natural gas production increased earnings by $2.4 million and $28.2 million, respectively. In addition, higher processing plant revenues ($0.3 million) and lower interest expense ($2.5 million) also contributed to an increase in earnings. The decrease in interest expense is primarily due to a lower average amount of debt outstanding and the capitalization of interest during the quarter ended March 31, 2011. These earnings increases were partially offset by lower natural gas prices after hedging and lower crude oil production, which decreased earnings by $10.8 million and $1.7 million, respectively. In addition, earnings were further reduced by higher depletion expense ($9.2 million), higher lease operating expenses ($2.1 million), higher general, administrative and other operating expenses ($2.4 million), and higher property taxes ($1.3 million). The increase in depletion expense is primarily due to an increase in production and depletable base (largely due to increased capital spending in the Appalachian region, specifically related to the development of Marcellus Shale properties). The increase in lease

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

operating expenses is largely attributable to a higher number of producing properties in Appalachia. Higher personnel costs are largely responsible for the increase in general, administrative and other operating expenses. Higher property taxes are attributable to a revision of the California property tax liability.

     The Exploration and Production segment’s earnings for the six months ended March 31, 2011 were $60.7 million, an increase of $3.5 million when compared with earnings of $57.2 million for the quarter ended March 31, 2010. Higher crude oil prices and higher natural gas production increased earnings by $3.3 million and $46.7 million, respectively. In addition, higher processing plant revenues ($0.9 million) and lower interest expense ($3.6 million) also contributed to an increase in earnings. The decrease in interest expense is primarily due to a lower average amount of debt outstanding and the capitalization of interest during the six months ended March 31, 2011. These earnings increases were partially offset by lower natural gas prices after hedging and lower crude oil production, which decreased earnings by $18.2 million and $5.2 million, respectively. In addition, earnings were further reduced by higher depletion expense ($15.5 million), higher lease operating expenses ($5.5 million), higher general, administrative and other operating expenses ($4.1 million), higher property taxes ($1.6 million), and higher income tax expense ($0.7 million). The increase in depletion expense is primarily due to an increase in production and depletable base (largely due to increased capital spending in the Appalachian region, specifically related to the development of Marcellus Shale properties). The increase in lease operating expenses is largely attributable to a higher number of producing properties in Appalachia. Higher personnel costs are largely responsible for the increase in general, administrative and other operating expenses. Higher property taxes are attributable to a revision of the California property tax liability. The increase in income taxes is attributable to the loss of a domestic production activities deduction that occurred during the quarter ended September 30, 2010 and its impact on the effective tax rate during fiscal 2011 coupled with higher state income taxes.

Energy Marketing

Energy Marketing Operating Revenues

	Three Months Ended							Six Months Ended
	March 31,							March 31,
(Thousands)	2011		2010		Decrease			2011		2010		Decrease
Natural Gas (after Hedging)	$	121,294	$	158,459	$	(37,165	)	$	174,933	$	230,172	$	(55,239	)
Other		27		78		(51	)		40		101		(61	)
	$	121,321	$	158,537	$	(37,216	)	$	174,973	$	230,273	$	(55,300	)

Energy Marketing Volume

	Three Months Ended							Six Months Ended
	March 31,							March 31,
	2011		2010		Decrease			2011		2010		Decrease
Natural Gas — (MMcf)		21,609		23,996		(2,387	)		32,355		38,097		(5,742	)

2011 Compared with 2010

     Operating revenues for the Energy Marketing segment decreased $37.2 million and $55.3 million for the quarter and six months ended March 31, 2011, as compared with the quarter and six months ended March 31, 2010. The decrease for both the quarter and six months ended March 31, 2011 primarily reflects a decline in gas sales revenue due largely to a decrease in volume sold as well as a lower average price of natural gas that was recovered through revenues. The decrease in volume is largely attributable to a decrease in volume sold to low-margin wholesale customers as well as the non-recurrence of sales transactions undertaken at the Niagara pipeline delivery point to offset certain basis risks that the Energy Marketing segment was exposed to under certain fixed basis commodity purchase contracts for Appalachian production. Such transactions had the effect of increasing revenue and volume sold with minimal impact to earnings. The decrease in volume sold to wholesale customers was offset slightly by an increase in volume sold to retail customers.

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

     The Energy Marketing segment’s earnings for the quarter ended March 31, 2011 were $6.3 million, an increase of $0.3 million when compared with earnings of $6.0 million for the quarter ended March 31, 2010. The Energy Marketing segment’s earnings for the six months ended March 31, 2011 were $7.2 million, an increase of $0.1 million when compared with earnings of $7.1 million for the six months ended March 31, 2010. These increases were largely attributable to higher margin of $0.3 million for both the quarter and six-month periods, respectively. The increase in margin was primarily driven by improved average margins per Mcf as well as an increase in volume sold to retail customers. Partially offsetting the increase in earnings for the six months ended March 31, 2011 were higher operating expenses of $0.2 million primarily due to higher pension expense and higher personnel costs, offset slightly by lower bad debt expense.

Corporate and All Other

2011 Compared with 2010

     Corporate and All Other recorded earnings from continuing operations of $32.0 million for the quarter ended March 31, 2011, an increase of $31.2 million when compared with earnings from continuing operations of $0.8 million for the quarter ended March 31, 2010. The increase in earnings is due to the gain on the sale of Horizon Power’s investments in Seneca Energy and Model City of $31.4 million, lower interest expense of $2.4 million (primarily the result of lower borrowings at a lower interest rate due to the repayment of $200 million of 7.5% notes that matured in November 2010), higher gathering and processing revenues of $1.4 million (due to an increase in Midstream Corporation’s gathering and processing activities) and lower depreciation and depletion expense of $1.0 million (due to a decrease in timber harvested as a result of the sale of the Company’s timber harvesting and milling operations in September 2010). The factors contributing to the overall increase in earnings were partially offset by lower interest income of $2.3 million (due to lower interest collected from the Company’s Exploration and Production segment as a result of the aforementioned November 2010 debt repayment), lower margins of $2.2 million (due to a decrease in timber harvested as a result of the sale of the Company’s timber harvesting and milling operations in September 2010) and higher operating expenses of $0.3 million (primarily due to the increase in Midstream Corporation’s operating activities).

     For the six months ended March 31, 2011, Corporate and All Other had earnings from continuing operations of $30.6 million, an increase of $29.8 million when compared with earnings from continuing operations of $0.8 million for the six months ended March 31, 2010. The increase in earnings is due to the gain on the sale of Horizon Power’s investments in Seneca Energy and Model City of $31.4 million, lower interest expense of $3.5 million (primarily the result of lower borrowings at a lower interest rate due to the aforementioned November 2010 debt repayment), higher gathering and processing revenues of $2.6 million (due to an increase in Midstream Corporation’s gathering and processing activities) and lower depreciation and depletion expense of $2.1 million (due to a decrease in timber harvested due to the sale of the Company’s timber harvesting and milling operations in September 2010). The factors contributing to the overall increase in earnings were partially offset by lower margins of $5.1 million (due to a decrease in timber harvested due to the sale of the Company’s timber harvesting and milling operations in September 2010), lower interest income of $3.3 million (due to lower interest collected from the Company’s Exploration and Production segment as a result of the aforementioned November 2010 debt repayment) and higher operating expenses of $0.7 million (primarily due to the increase in Midstream Corporation’s operating activities). Additionally, the Company recorded a loss from unconsolidated subsidiaries of $0.4 million during the six months ended March 31, 2011 compared to income of $0.7 million during the six months ended March 31, 2010.

Other Income

     Other income increased $0.7 million for the quarter ended March 31, 2011 as compared with the quarter ended March 31, 2010. This increase is mainly attributable to a gain on corporate-owned life insurance policies of $0.5 million recognized during the quarter. In addition, there was a $0.3 million increase in allowance for funds used during construction in the Pipeline and Storage segment. For the six months ended March 31, 2011, other income increased $1.3 million as compared with the six months ended March 31, 2010. This increase is attributable to a $0.5 million gain on corporate-owned life insurance policies

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

recognized during the second quarter and a $0.4 million gain on the sale of Horizon Energy Development recognized during the first quarter. In addition, there was a $0.5 million increase in allowance for funds used during construction in the Pipeline and Storage segment.

Interest Expense on Long-Term Debt

     Interest on long-term debt decreased $4.1 million for the quarter ended March 31, 2011 as compared with the quarter ended March 31, 2010. For the six months ended March 31, 2011, interest on long-term debt decreased $6.0 million as compared with the six months ended March 31, 2010. This decrease is primarily the result of a lower average amount of long-term debt outstanding, slightly lower average interest rates and capitalization of interest during the quarter and six months ended March 31, 2011. The Company repaid $200 million of 7.5% notes that matured in November 2010.

CAPITAL RESOURCES AND LIQUIDITY

     The Company’s primary source of cash during the six-month period ended March 31, 2011 consisted of cash provided by operating activities and net proceeds from the sale of unconsolidated subsidiaries. The Company’s primary source of cash during the six-month period ended March 31, 2010 consisted of cash provided by operating activities. This source of cash was supplemented by issues of new shares of common stock as a result of stock option exercises for the six months ended March 31, 2010. During the six months ended March 31, 2011 and March 31, 2010, 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. In April 2011, the Company began issuing original issue shares for the Direct Stock Purchase and Dividend Reinvestment Plan.

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, gain on the sale of unconsolidated subsidiaries, and income or loss from unconsolidated subsidiaries net of cash distributions.

     Cash provided by operating activities in the Utility and Pipeline and Storage segments may vary substantially from period to period because of the impact of rate cases. In the Utility segment, supplier refunds, over- or 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 the straight fixed-variable rate design used by Supply Corporation and Empire.

     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 receivable balances at September 30.

     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 futures contracts in an attempt to manage this energy commodity price risk.

     Net cash provided by operating activities totaled $343.2 million for the six months ended March 31, 2011, an increase of $63.9 million compared with $279.3 million provided by operating activities for the six months ended March 31, 2010. In the Exploration and Production segment, cash provided by operations

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

increased due to higher cash receipts from the sale of natural gas production. An increase in hedging collateral deposits in the Exploration and Production segment at March 31, 2011 partly offset the increase in cash provided by operating activities. Hedging collateral deposits serve as collateral for open positions on exchange-traded futures contracts and over-the-counter swaps.

Investing Cash Flow

Expenditures for Long-Lived Assets

     The Company’s expenditures from continuing operations for long-lived assets totaled $382.7 million during the six months ended March 31, 2011 and $236.0 million for the six months ended March 31, 2010. The table below presents these expenditures:

Total Expenditures for Long-Lived Assets

Six Months Ended March 31,							Increase
(Millions)	2011			2010			(Decrease)
Utility :
Capital Expenditures	$	25.4		$	25.5		$	(0.1	)
Pipeline and Storage:
Capital Expenditures		39.5	(1)		15.5			24.0
Exploration and Production:
Capital Expenditures		315.2	(1)(2)		191.0	(3)(4)		124.2
All Other:
Capital Expenditures		2.6			4.0	(4)		(1.4	)
Total Expenditures from Continuing Operations	$	382.7		$	236.0		$	146.7

(1)	Capital expenditures for the Exploration and Production segment include $43.9 million of accrued capital expenditures at March 31, 2011, the majority of which was in the Appalachian region. In addition, capital expenditures for the Pipeline and Storage segment include $2.0 million of accrued capital expenditures at March 31, 2011. These amounts were excluded from the Consolidated Statement of Cash Flows at March 31, 2011 since they represented non-cash investing activities at that date.
(2)	Amount for the six months ended March 31, 2011 excludes $55.5 million of accrued capital expenditures in the Exploration and Production segment, the majority of which was in the Appalachian region. This amount was accrued at September 30, 2010 and paid during the six months ended March 31, 2010. This amount was excluded from the Consolidated Statement of Cash Flows at September 30, 2010 since it represented a non-cash investing activity at that date. The amount has been included in the Consolidated Statement of Cash Flows at March 31, 2011.
(3)	Amount includes $15.3 million of accrued capital expenditures at March 31, 2010, the majority of which was in the Appalachian region. This amount has been excluded from the Consolidated Statement of Cash Flows at March 31, 2010 since it represents a non-cash investing activity at that date.
(4)	Capital expenditures for the Exploration and Production segment for the six months ended March 31, 2010 exclude $9.1 million of capital expenditures, the majority of which was in the Appalachian region. Capital expenditures for All Other for the six months ended March 31, 2010 exclude $0.7 million of capital expenditures related to the construction of the Midstream Covington Gathering System. Both of these amounts were accrued at September 30, 2009 and paid during the six months ended March 31, 2010. These amounts were excluded from the Consolidated Statement of Cash Flows at September 30, 2009 since they represented non-cash investing activities at that date. These amounts have been included in the Consolidated Statement of Cash Flows at March 31, 2010.

Utility

     The majority of the Utility capital expenditures for the six months ended March 31, 2011 and March 31, 2010 were made for replacement of mains and main extensions, as well as for the replacement of service lines.

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

Pipeline and Storage

     The majority of the Pipeline and Storage capital expenditures for the six months ended March 31, 2011 and March 31, 2010 were related to additions, improvements, and replacements to this segment’s transmission and gas storage systems. In addition, the Pipeline and Storage capital expenditure amounts for the six months ended March 31, 2011 include $7.3 million spent on the Line N Expansion Project, $5.0 million spent on the Lamont Phase II Project and $4.0 million spent on the Tioga County Extension Project, as discussed below. The Pipeline and Storage capital expenditure amounts for the six months ended March 31, 2010, also include $2.5 million spent on the Lamont Project.

     In light of the growing demand for pipeline capacity to move natural gas from new wells being drilled in Appalachia — specifically in the Marcellus Shale producing area — Supply Corporation and Empire are actively pursuing several expansion projects and paying for preliminary survey and investigation costs, which are initially recorded as Deferred Charges on the Consolidated Balance Sheet. An offsetting reserve is established as those preliminary survey and investigation costs are incurred, which reduces the Deferred Charges balance and increases Operation and Maintenance Expense on the Consolidated Statement of Income. The Company reviews all projects on a quarterly basis, and if it is determined that it is highly probable that the project will be built, the reserve is reversed. This reversal reduces Operation and Maintenance Expense and reestablishes the original balance in Deferred Charges. After the reversal of the reserve, the amounts remain in Deferred Charges until such time as capital expenditures for the project have been incurred and activities that are necessary to get the construction project ready for its intended use are in progress. At that point, the balance is transferred from Deferred Charges to Construction Work in Progress, a component of Property, Plant and Equipment on the Consolidated Balance Sheet. As of March 31, 2011, the total amount reserved for the Pipeline and Storage segment’s preliminary survey and investigation costs was $6.6 million.

     Supply Corporation and Empire are moving forward with several projects designed to move anticipated Marcellus production gas to other interstate pipelines and to markets beyond the Supply Corporation and Empire pipeline systems.

     Supply Corporation has signed a precedent agreement to provide 320,000 Dth/day of firm transportation capacity in conjunction with its “Northern Access” expansion project. Upon satisfaction of the conditions in the precedent agreement, Statoil Natural Gas LLC will enter into a 20-year firm transportation agreement for 320,000 Dth/day. This capacity will provide the subscribing shipper with a firm transportation path from the Tennessee Gas Pipeline (“TGP”) 300 Line at Ellisburg to the TransCanada Pipeline at Niagara. This path is attractive because it provides a route for Marcellus shale gas, principally along the TGP 300 Line in northern Pennsylvania, to be transported from the Marcellus supply basin to northern markets. Service is expected to begin in November 2012, and Supply Corporation filed an application for FERC authorization of the project on March 7, 2011. The project facilities involve approximately 9,500 horsepower of additional compression at Supply Corporation’s existing Ellisburg Station and a new approximately 5,000 horsepower compressor station in East Aurora, New York, along with other system enhancements including enhancements to the jointly owned Niagara Spur Loop Line. The preliminary cost estimate for the Northern Access expansion is $62 million. As of March 31, 2011, approximately $0.4 million has been spent to study the Northern Access expansion project, which has been included in preliminary survey and investigation charges and has been fully reserved for at March 31, 2011.

     Another expansion project involves new compression along Supply Corporation’s Line N (“Line N Expansion Project”), increasing that line’s capacity by 160,000 Dth/day into Texas Eastern’s Holbrook Station (“TETCO Holbrook”) in southwestern Pennsylvania. Two service agreements totaling 160,000 Dth/day of firm transportation have been executed. The project will allow Marcellus production located in the vicinity of Line N to flow south into Texas Eastern and access markets off Texas Eastern’s system, with a projected in-service date of September 2011. The FERC issued the NGA Section 7(c) certificate on December 16, 2010. Supply Corporation has accepted the certificate, received a FERC Notice to Proceed, and in February 2011 commenced construction. Service agreements for all 160,000 Dth/day of firm transportation have been executed. The preliminary cost estimate for the Line N Expansion Project is $20 million. As of March 31, 2011, approximately $7.3 million has been spent on the Line N expansion project, all of which has been capitalized as Construction Work in Progress.

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

     Supply Corporation has also executed a precedent agreement for 150,000 Dth/day of additional capacity on Line N to TETCO Holbrook and has designed a project for their shippers to be ready for service beginning November 2012 (“Line N 2012 Expansion Project”). The preliminary cost estimate for the Line N 2012 Expansion Project is approximately $30 million. As of March 31, 2011, approximately $0.1 million has been spent to study the Line N 2012 Expansion Project, which has been included in preliminary survey and investigation charges and has been fully reserved for at March 31, 2011.

     Following up on Supply Corporation’s Lamont Project that went into service on June 15, 2010, a second Lamont project is planned (“Lamont Phase II Project”). With the construction of an additional 3,400 horsepower, 50,000 Dth/day of incremental firm capacity is expected to be available starting July 1, 2011 ramping up to full service by approximately October 1, 2011. Supply Corporation has two executed binding service agreements for the full capacity of this project. The preliminary cost estimate for the Lamont Phase II Project is approximately $7.6 million. The Company began construction in March 2011. As of March 31, 2011, approximately $5.0 million has been spent on the Lamont Phase II project, all of which has been capitalized as Construction Work in Progress.

     In addition, Supply Corporation continues to actively pursue its largest planned expansion, the West-to-East (“W2E”) pipeline project, which is designed to transport Rockies and/or locally produced natural gas supplies to the Ellisburg/Leidy/Corning area. Supply Corporation anticipates that the development of the W2E project will occur in phases. As currently envisioned, the first two phases of W2E, referred to as the “W2E Overbeck to Leidy” project, are designed to transport at least 425,000 Dth/day, and involves construction of a new 82-mile pipeline through Elk, Cameron, Clinton, Clearfield and Jefferson Counties to the Leidy Hub, from Marcellus and other producing areas along over 300 miles of Supply Corporation’s existing pipeline system. The W2E Overbeck to Leidy project also includes a total of approximately 25,000 horsepower of compression at two separate stations. The project may be built in phases depending on the development of Marcellus production along the corridor, with the first facilities expected to go in service in 2013.

     Following an Open Season that concluded on October 8, 2009, Supply Corporation executed precedent agreements to provide 125,000 Dth/day of firm transportation on the W2E Overbeck to Leidy project. Supply Corporation is pursuing post-Open Season capacity requests for the remaining capacity. On March 31, 2010, the FERC granted Supply Corporation’s request for a pre-filing environmental review of the W2E Overbeck to Leidy project, and Supply Corporation is in the process of preparing an NGA Section 7(c) application. The capital cost of the W2E Overbeck to Leidy project is estimated to be $260 million. As of March 31, 2011, approximately $4.4 million has been spent to study the W2E Overbeck to Leidy project, which has been included in preliminary survey and investigation charges and has been fully reserved for at March 31, 2011.

     Supply Corporation expects that its previously announced Appalachian Lateral project will complement the W2E Overbeck to Leidy project due to its strategic upstream location. The Appalachian Lateral project, which would be routed through several counties in central Pennsylvania where producers are actively drilling and seeking market access for their newly discovered reserves, will be able to collect and transport locally produced Marcellus shale gas into the W2E Overbeck to Leidy facilities. Supply Corporation expects to continue marketing efforts for the Appalachian Lateral and all other remaining sections of W2E. The timeline and projected costs associated with W2E sections other than W2E Overbeck to Leidy, including the Appalachian Lateral project, will depend on market development, and as of March 31, 2011, no preliminary survey and investigation charges had been spent on those projects.

     Empire has executed precedent agreements for all 350,000 Dth/day of incremental firm transportation capacity in its “Tioga County Extension Project.” This project will transport Marcellus production from new interconnections at the southern terminus of a 15-mile extension of its recently completed Empire Connector line, in Tioga County, Pennsylvania. Empire’s preliminary cost estimate for the Tioga County Extension Project is approximately $49 million. This project will enable shippers to deliver their natural gas at existing Empire interconnections with Millennium Pipeline at Corning, New York, with the TransCanada Pipeline at the Niagara River at Chippawa, and with utility and power generation markets along its path, as well as to a planned new interconnection with TGP’s 200 Line (Zone 5) in Ontario County, New York. On January 28, 2010, the FERC granted Empire’s request for a pre-filing environmental review of the Tioga County Extension Project, and on August 26, 2010, Empire filed an NGA Section 7(c) application to the

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

FERC for approval of the project. Empire anticipates that these facilities will be placed in service on September 1, 2011. As of March 31, 2011, approximately $4.0 million has been spent related to the Tioga County Extension Project, all of which has been capitalized as Construction Work in Progress.

     On December 17, 2010, Empire concluded an Open Season for up to 260,000 Dth per day of additional capacity from Tioga County, Pennsylvania, to TransCanada Pipeline and the TGP 200 Line, as well as additional short-haul capacity to Millennium Pipeline at Corning (“Central Tioga County Extension”). Empire is evaluating the substantial market interest resulting from this Open Season, which was for more than 260,000 Dth per day of capacity, and is studying the facility design that would be necessary to provide the requested service. The Central Tioga County Extension project may involve up to 25,000 horsepower of compression at up to three new stations and a 25 mile 24” pipeline extension, at a preliminary cost estimate of $135 million. As of March 31, 2011, less than $0.1 million has been spent to study the Central Tioga County Extension project, which has been included in preliminary survey and investigation charges and has been fully reserved for at March 31, 2011. No decision has been made to proceed with this project.

     The Company anticipates financing the Line N Expansion Projects, the Lamont Project, the Northern Access expansion project, the W2E Overbeck to Leidy project, the Appalachian Lateral project, and the Tioga County Extension Projects, all of which are discussed above, with a combination of cash from operations, short-term debt, and long-term debt. The Company had $144.8 million in Cash and Temporary Cash Investments at March 31, 2011, as shown on the Company’s Consolidated Balance Sheet. The Company expects to use cash from operations as the first means of financing these projects, with short-term debt providing temporary financing when needed. The Company may issue some long-term debt in conjunction with these projects in the later part of fiscal 2011 or in fiscal 2012.

Exploration and Production

     The Exploration and Production segment capital expenditures for the six months ended March 31, 2011 were primarily well drilling and completion expenditures and included approximately $298.7 million for the Appalachian region (including $295.7 million in the Marcellus Shale area), $14.7 million for the West Coast region and $1.8 million for the Gulf Coast region, the majority of which was for the off-shore program in the shallow waters of the Gulf of Mexico. These amounts included approximately $109.4 million spent to develop proved undeveloped reserves. The capital expenditures in the Appalachian region include the Company’s acquisition of oil and gas properties in the Covington Township area of Tioga County, Pennsylvania from EOG Resources, Inc. for approximately $24.1 million in November 2010. The Company funded this transaction with cash from operations.

     As the Company has been accelerating its Marcellus Shale development, it has been decreasing its emphasis in the Gulf Coast region. In March 2011, the Company entered into a purchase and sale agreement to sell its off-shore oil and natural gas properties in the Gulf of Mexico effective as of January 1, 2011 for approximately $70 million and received a deposit of $7.0 million from the purchaser. The Company completed the sale in April 2011, receiving an additional $54.8 million. The difference between the total proceeds received of $61.8 million and the sale price of $70.0 million represents a purchase price adjustment for the operating cash flow that the Company recorded from January 1, 2011 to the closing date of the sale. Under the full cost method of accounting for oil and natural gas properties, the sale proceeds were accounted for as a reduction of capitalized costs in April 2011. Since the disposition did not significantly alter the relationship between capitalized costs and proved reserves of oil and gas attributable to the cost center, the Company did not record any gain or loss from this sale.

     The Exploration and Production segment capital expenditures for the six months ended March 31, 2010 were primarily well drilling and completion expenditures and included approximately $170.8 million for the Appalachian region (including $152.7 million in the Marcellus Shale area), $14.8 million for the West Coast region and $5.4 million for the Gulf Coast region, the majority of which was for the off-shore program in the shallow waters of the Gulf of Mexico. These amounts included approximately $18.2 million spent to develop proved undeveloped reserves. The capital expenditures in the Appalachian region include the Company’s acquisition of two tracts of leasehold acreage for approximately $71.8 million. The Company

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

acquired these tracts in order to expand its Marcellus Shale acreage holdings. These tracts, consisting of approximately 18,000 net acres in Tioga and Potter Counties in Pennsylvania, are geographically similar to the Company’s existing Marcellus Shale acreage in the area. The transaction closed on March 12, 2010.

     For all of fiscal 2011, the Company expects to spend $629.0 million on Exploration and Production segment capital expenditures. Previously reported 2011 estimated capital expenditures for the Exploration and Production segment were $531.0 million. In the Appalachian region, estimated capital expenditures will increase from $490.0 million to $588.0 million. The Company had previously reported that it anticipates drilling 100 to 130 gross wells in the Marcellus Shale during 2011. The Company now anticipates drilling 85 to 110 gross horizontal wells in the Marcellus Shale during 2011. The increase in estimated capital expenditures in the Appalachian region is primarily due to an increase in estimated well costs due to drilling longer laterals in horizontal wells, hydraulic fracturing at more stages per well, and an increase in service company completion costs.

     For all of fiscal 2012, the Company expects to spend $732.0 million on Exploration and Production segment capital expenditures. Previously reported 2012 estimated capital expenditures for the Exploration and Production segment were $596.0 million. In the Appalachian region, estimated capital expenditures will increase from $533.0 million to $689.0 million. Estimated capital expenditures in the Gulf Coast region will decrease from $20.0 million to zero. Estimated capital expenditures in the West Coast region will remain at the previously reported $43.0 million. The Company had previously reported that it anticipates drilling 130 to 160 gross wells in the Marcellus Shale during fiscal 2012. The Company now anticipates drilling 115 to 140 gross horizontal wells in the Marcellus Shale during fiscal 2012. The increase in estimated capital expenditures in the Appalachian region is primarily due to an increase in estimated well costs, as noted above. The decline in the Gulf Coast region estimated capital expenditures is due to the Company’s sale of its offshore Gulf of Mexico oil and natural gas producing properties, as noted above.

     The Company expects to use cash from operations and cash from asset sales as the first means of financing its future capital expenditures during 2011 and 2012, with short-term debt providing temporary financing when needed. Natural gas and crude oil prices combined with production from existing wells will be a significant factor in determining how much of the capital expenditures are funded with cash from operations. The Company may issue some long-term debt in conjunction with these expenditures in the later part of fiscal 2011 or in fiscal 2012.

All Other

     The majority of the All Other category’s capital expenditures for the six months ended March 31, 2011 were primarily for expansion of Midstream Corporation’s Covington Gathering system in Tioga County, Pennsylvania as well as for the construction of Midstream Corporation’s Trout Run Gathering System, as discussed below. The majority of the All Other category’s capital expenditures for the six months ended March 31, 2010 were for the construction of Midstream Corporation’s Covington Gathering System.

     NFG Midstream Trout Run, LLC, a wholly owned subsidiary of Midstream Corporation, is developing a gathering system in Lycoming County, Pennsylvania. The project, called the Trout Run Gathering System, is anticipated to be placed in service in the fall of 2011. The system will consist of approximately 16.5 miles of gathering system at a cost of $35 million. As of March 31, 2011, the Company has spent approximately $0.9 million in costs related to this project.

     The Company anticipates funding the Trout Run Gathering System project with cash from operations and/or short-term borrowings. Given the Company’s cash position at March 31, 2011, the Company expects to use cash from operations as the first means of financing these projects.

     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, natural gas storage facilities and the expansion of natural gas transmission line capacities. While the majority of capital expenditures in the Utility segment are

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

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

     The Company did not have any outstanding short-term notes payable to banks or commercial paper at March 31, 2011. During the six months ended March 31, 2011, consolidated short-term debt did not exceed $31.5 million outstanding. 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.

     As for bank loans, the Company maintains a number of individual 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 $385.0 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 substantially 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, which commitment extends through September 30, 2013. 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 through September 30, 2013. At March 31, 2011, the Company’s debt to capitalization ratio (as calculated under the facility) was .37. The constraints specified in the committed credit facility would permit an additional $2.32 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 committed credit facility, uncommitted bank lines of credit or rely upon other liquidity sources, including cash provided by operations.

     Under the Company’s existing indenture covenants, at March 31, 2011, the Company would have been permitted to issue up to a maximum of $1.65 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. However, if the Company were to experience a significant loss in the future (for example, as a result of an impairment of oil and gas properties), it is possible, depending on factors including the magnitude of the loss, that these indenture covenants would restrict the Company’s ability to issue additional long-term unsecured indebtedness for a period of up to nine calendar months, beginning with the fourth calendar month following the loss. This would not at any time preclude the Company from issuing new indebtedness to replace maturing debt.

     The Company’s 1974 indenture pursuant to which $99.0 million (or 9.4%) of the Company’s long-term debt (as of March 31, 2011) 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

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

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 $40.0 million or more, or (ii) an event occurs that causes, or would permit the holders of any other indebtedness aggregating $40.0 million or more to cause, such indebtedness to become due prior to its stated maturity. As of March 31, 2011, the Company had no debt outstanding under the committed credit facility.

     The Company’s embedded cost of long-term debt was 6.85% at March 31, 2011 and 6.95% at March 31, 2010. If the Company were to issue 10-year long-term debt today, its borrowing costs might be expected to be in the range of 4.75% to 5.25%.

     Current Portion of Long-Term Debt at March 31, 2011 consists of $150 million of 6.70% medium-term notes that mature in November 2011. Currently, the Company expects to refund these medium-term notes in November 2011 with cash on hand, short-term borrowings and/or long-term debt. In November 2010, the Company repaid $200 million of 7.50% notes that matured on November 22, 2010 that were classified as Current Portion of Long-Term Debt at September 30, 2010.

     The Company may issue debt or equity securities in a public offering or a private placement from time to time. 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.

OFF-BALANCE SHEET ARRANGEMENTS

     The Company has entered into certain off-balance sheet financing arrangements. These financing arrangements are primarily operating 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 $25.0 million. These leases have been entered into for the use of buildings, vehicles, construction tools, meters and other items and are accounted for as operating leases.

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 are they expected to have a material adverse effect on the financial condition of the Company.

     During the six months ended March 31, 2011, the Company contributed $32.4 million to its Retirement Plan and $16.0 million to its VEBA trusts and 401(h) accounts for its other post-retirement benefits. In the remainder of 2011, the Company expects to contribute at a minimum in the range of $7.0 million to $15.0 million to the Retirement Plan. Changes in the discount rate, other actuarial assumptions, and asset performance could ultimately cause the Company to fund larger amounts to the Retirement Plan in fiscal 2011 in order to be in compliance with the Pension Protection Act of 2006. In the remainder of 2011, the Company expects to contribute in the range of $9.0 million to $14.0 million to its VEBA trusts and 401(h) accounts.

Market Risk Sensitive Instruments

     On July 21, 2010, the Dodd-Frank Wall Street Reform and Consumer Protection Act (H.R. 4173) was signed into law. The law includes provisions related to the swaps and over-the-counter derivatives markets. A variety of rules must be adopted by federal agencies (including the Commodity Futures Trading Commission, SEC and the FERC) to implement the law. These rules, which will be implemented over time frames as determined in the law, could have a significant impact on the Company. For example, while the Company

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

expects to be exempt from the law’s mandatory clearing and exchange trading requirements for most or all of its commodity hedges, other requirements with respect to these hedges, including capital, margin and reporting requirements, may apply to the Company. These requirements will be determined as regulators write detailed rules. The Company is currently reviewing the provisions of H.R. 4173 and proposed rules, but it will not be able to determine the impact to its financial condition until the final rules are issued.

     In accordance with the authoritative guidance for fair value measurements, the Company has identified certain inputs used to recognize fair value as Level 3 (unobservable inputs). The Level 3 derivative net liabilities relate to oil swap agreements used to hedge forecasted sales at a specific location (southern California). The Company’s internal model that is used to calculate fair value applies a historical basis differential (between the sales locations and NYMEX) to a forward NYMEX curve because there is not a forward curve specific to this sales location. Given the high level of historical correlation between NYMEX prices and prices at this sales location, the Company does not believe that the fair value recorded by the Company would be significantly different from what it expects to receive upon settlement.

     The Company uses the crude oil swaps classified as Level 3 to hedge against the risk of declining commodity prices and not as speculative investments. Gains or losses related to these Level 3 derivative net liabilities (including any reduction for credit risk) are deferred until the hedged commodity transaction occurs in accordance with the provisions of the existing guidance for derivative instruments and hedging activities. The Level 3 Net Liabilities amount to $71.9 million at March 31, 2011 and represent 41.2% of the Total Net Assets shown in Part I, Item 1 at Note 2 — Fair Value Measurements at March 31, 2011.

     The increase in the net fair value liability of the Level 3 positions from October 1, 2010 to March 31, 2011, as shown in Part I, Item 1 at Note 2, was attributable to an increase in the commodity price of crude oil relative to the swap price during that period. The Company believes that these fair values reasonably represent the amounts that the Company would realize upon settlement based on commodity prices that were present at March 31, 2011.

     The fair value of all of the Company’s Net Derivative Liability was reduced by $0.1 million based upon the Company’s assessment of counterparty credit risk (for the Company’s derivative assets) and the Company’s credit risk (for the Company’s derivative liabilities). The Company applied default probabilities to the anticipated cash flows that it was expecting to receive and pay to its counterparties to calculate the credit reserve.

     For a complete discussion of market risk sensitive instruments, refer to “Market Risk Sensitive Instruments” in Item 7 of the Company’s 2010 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

     Delivery rates for both the New York and Pennsylvania divisions are regulated by the states’ respective public utility commissions and are changed when approved through a procedure known as a “rate case.” Currently neither division has a rate case on file. In both jurisdictions, delivery rates do not reflect the recovery of purchased gas costs. Prudently-incurred gas costs are recovered through operation of automatic adjustment clauses, and are collected largely through a separately-stated “supply charge” on the customer bill.

New York Jurisdiction

     Customer delivery rates charged by Distribution Corporation’s New York division were established in a rate order issued on December 21, 2007 by the NYPSC. The rate order approved a revenue increase of $1.8 million annually, together with a surcharge that would collect up to $10.8 million to cover expenses for implementation of an efficiency and conservation incentive program. The rate order further provided for a return on equity of 9.1%. In connection with the efficiency and conservation program, the rate order approved a revenue decoupling mechanism. The revenue decoupling mechanism “decouples” revenues from throughput by enabling the Company to collect from small volume customers its allowed margin on average

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

weather normalized usage per customer. The effect of the revenue decoupling mechanism is to render the Company financially indifferent to throughput decreases resulting from conservation. The Company surcharges or credits any difference from the average weather normalized usage per customer account. The surcharge or credit is calculated to recover total margin for the most recent twelve-month period ending December 31, and is applied to customer bills annually, beginning March 1st.

     On April 18, 2008, Distribution Corporation filed an appeal with Supreme Court, Albany County, seeking review of the rate order. The appeal contended that portions of the rate order were invalid because they failed to meet the applicable legal standard for agency decisions. Among the issues challenged by the Company was the reasonableness of the NYPSC’s disallowance of expense items and the methodology used for calculating rate of return, which the appeal contended understated the Company’s cost of equity. Because of the issues appealed, the case was later transferred to the Appellate Division, New York State’s second-highest court. On December 31, 2009, the Appellate Division issued its Opinion and Judgment. The court upheld the NYPSC’s determination relating to the authorized rate of return but also supported the Company’s argument that the NYPSC improperly disallowed recovery of certain environmental clean-up costs. On February 1, 2010, the NYPSC filed a motion with the Court of Appeals, New York State’s highest court, seeking permission to appeal the Appellate Division’s annulment of that part of the rate order relating to disallowance of environmental clean up costs. The NYPSC’s motion was granted and was followed by briefs and oral argument. On March 29, 2011, the Court of Appeals issued a judgment and opinion affirming the Appellate Division’s judgment.

Pennsylvania Jurisdiction

     Distribution Corporation’s current delivery charges in its Pennsylvania jurisdiction were approved by the PaPUC on November 30, 2006 as part of a settlement agreement that became effective January 1, 2007.

Pipeline and Storage

     Supply Corporation currently does not have a rate case on file with the FERC. The rate settlement approved by the FERC on February 9, 2007 requires Supply Corporation to make a general rate filing to be effective December 1, 2011, and bars Supply Corporation from making a general rate filing before then, with some exceptions specified in the settlement.

     Empire’s new facilities (the Empire Connector project) were placed into service on December 10, 2008. As of that date, Empire became an interstate pipeline subject to FERC regulation, performing services under a FERC-approved tariff and at FERC-approved rates. The December 21, 2006 FERC order issuing Empire its Certificate of Public Convenience and Necessity requires Empire to file a cost and revenue study at the FERC following three years of actual operation, in conjunction with which Empire will either justify Empire’s existing recourse rates or propose alternative rates.

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 agreed with the NYDEC to remediate a former manufactured gas plant site located in New York. The Company has received approval from the NYDEC of a Remedial Design work plan for this site and has recorded an estimated minimum liability for remediation of this site of $14.6 million.

     At March 31, 2011, the Company has estimated its remaining clean-up costs related to former manufactured gas plant sites and third party waste disposal sites (including the former manufactured gas plant site discussed above) will be in the range of $17.1 million to $21.3 million. The minimum estimated

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

liability of $17.1 million, which includes the $14.6 million discussed above, has been recorded on the Consolidated Balance Sheet at March 31, 2011. The Company expects to recover its environmental clean-up costs through rate recovery.

     Legislative and regulatory measures to address climate change and greenhouse gas emissions are in various phases of discussion or implementation. Pursuant to an EPA determination, effective January 2011 projects proposing new stationary sources of significant greenhouse gas emissions or major modifications of existing facilities are required under the federal Clean Air Act to obtain permits covering such emissions. In April, the U.S. Senate rejected bills aimed at curbing the authority of the EPA to regulate greenhouse gas emissions. In addition, the U.S. Congress has from time to time considered bills that would establish a cap-and-trade program to reduce emissions of greenhouse gases. Legislation or regulation that restricts carbon emissions could increase the Company’s cost of environmental compliance by requiring the Company to install new equipment to reduce emissions from larger facilities and/or purchase emission allowances. Climate change and greenhouse gas measures could also delay or otherwise negatively affect efforts to obtain permits and other regulatory approvals with regard to existing and new facilities, or impose additional monitoring and reporting requirements. But legislation or regulation that sets a price on or otherwise restricts carbon emissions could also benefit the Company by increasing demand for natural gas, because substantially fewer carbon emissions per Btu of heat generated are associated with the use of natural gas than with certain alternate fuels such as coal and oil. The effect (material or not) on the Company of any new legislative or regulatory measures will depend on the particular provisions that are ultimately adopted.

     The Company is currently not aware of any material additional exposure to environmental liabilities. However, changes in environmental regulations, new information or other factors could adversely impact the Company.

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, statements regarding future prospects, plans, objectives, goals, projections, estimates of oil and gas quantities, strategies, future events or performance and underlying assumptions, capital structure, anticipated capital expenditures, completion of construction projects, projections for pension and other post-retirement benefit obligations, impacts of the adoption of new accounting rules, and possible outcomes of litigation or regulatory proceedings, as well as statements that are identified by the use of the words “anticipates,” “estimates,” “expects,” “forecasts,” “intends,” “plans,” “predicts,” “projects,” “believes,” “seeks,” “will,” “may,” 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:

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

1.	Financial and economic conditions, including the availability of credit, and occurrences affecting the Company’s ability to obtain financing on acceptable terms for working capital, capital expenditures and other investments, including any downgrades in the Company’s credit ratings and changes in interest rates and other capital market conditions;
2.	Changes in economic conditions, including global, national or regional recessions, and their effect on the demand for, and customers’ ability to pay for, the Company’s products and services;
3.	The creditworthiness or performance of the Company’s key suppliers, customers and counterparties;
4.	Economic disruptions or uninsured losses resulting from terrorist activities, acts of war, major accidents, fires, hurricanes, other severe weather, pest infestation or other natural disasters;
5.	Factors affecting the Company’s ability to successfully identify, drill for and produce economically viable natural gas and oil reserves, including among others geology, lease availability, weather conditions, shortages, delays or unavailability of equipment and services required in drilling operations, insufficient gathering, processing and transportation capacity, the need to obtain governmental approvals and permits, and compliance with environmental laws and regulations;
6.	Changes in laws and regulations to which the Company is subject, including those involving derivatives, taxes, safety, employment, climate change, other environmental matters, and exploration and production activities such as hydraulic fracturing;
7.	Uncertainty of oil and gas reserve estimates;
8.	Significant differences between the Company’s projected and actual production levels for natural gas or oil;
9.	Significant changes in market dynamics or competitive factors affecting the Company’s ability to retain existing customers or obtain new customers;
10.	Changes in demographic patterns and weather conditions;
11.	Changes in the availability and/or price of natural gas or oil and the effect of such changes on the accounting treatment of derivative financial instruments;
12.	Impairments under the SEC’s full cost ceiling test for natural gas and oil reserves;
13.	Changes in the availability and/or price of derivative financial instruments;
14.	Changes in price differential between similar quantities of natural gas at different geographic locations, and the effect of such changes on the demand for pipeline transportation capacity to or from such locations;
15.	Other changes in price differentials between similar quantities of oil or natural gas having different quality, heating value, geographic location or delivery date;
16.	Changes in the projected profitability of pending or potential projects, investments or transactions;
17.	Significant differences between the Company’s projected and actual capital expenditures and operating expenses;
18.	Delays or changes in costs or plans with respect to Company projects or related projects of other companies, including difficulties or delays in obtaining necessary governmental approvals, permits or orders or in obtaining the cooperation of interconnecting facility operators;

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

19.	Governmental/regulatory actions, initiatives and proceedings, including those involving derivatives, acquisitions, financings, rate cases (which address, among other things, allowed rates of return, rate design and retained natural gas), affiliate relationships, industry structure, franchise renewal, and environmental/safety requirements;
20.	Unanticipated impacts of restructuring initiatives in the natural gas and electric industries;
21.	Ability to successfully identify and finance acquisitions or other investments and ability to operate and integrate existing and any subsequently acquired business or properties;
22.	Changes in actuarial assumptions, the interest rate environment and the return on plan/trust assets related to the Company’s pension and other post-retirement benefits, which can affect future funding obligations and costs and plan liabilities;
23.	Significant changes in tax rates or policies or in rates of inflation or interest;
24.	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;
25.	Changes in accounting principles or the application of such principles to the Company;
26.	The cost and effects of legal and administrative claims against the Company or activist shareholder campaigns to effect changes at the Company;
27.	Increasing health care costs and the resulting effect on health insurance premiums and on the obligation to provide other post-retirement benefits; or
28.	Increasing costs of insurance, changes in coverage and the ability to obtain insurance.

     The Company disclaims any obligation to update any forward-looking statements to reflect events or circumstances after the date hereof.

Industry and Market Information

     The industry and market data used or referenced in this report are based on independent industry publications, government publications, reports by market research firms or other published independent sources. Some industry and market data may also be based on good faith estimates, which are derived from the Company’s review of internal information, as well as the independent sources listed above. Independent industry publications and surveys generally state that they have obtained information from sources believed to be reliable, but do not guarantee the accuracy and completeness of such information. While the Company believes that each of these studies and publications is reliable, the Company has not independently verified such data and makes no representation as to the accuracy of such information. Forecasts in particular may prove to be inaccurate, especially over long periods of time. Similarly, while the Company believes its internal information is reliable, such information has not been verified by any independent sources, and the Company makes no assurances that any predictions contained herein will prove to be accurate.

Item 3.Quantitative and Qualitative Disclosures About Market Risk

               Refer to the “Market Risk Sensitive Instruments” section in Item 2 — MD&A.

Item 4.Controls and Procedures

Evaluation of Disclosure Controls and Procedures

     The term “disclosure controls and procedures” is defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act. These rules refer to the controls and other procedures of a company that are designed to ensure that information required to be disclosed by a company in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. Disclosure controls and procedures include, without limitation, controls and

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Item 4.Controls and Procedures (Concl.)

procedures designed to ensure that information required to be disclosed is accumulated and communicated to the company’s management, including its principal executive and principal financial officers, as appropriate to allow timely decisions regarding required disclosure. The Company’s management, including the Chief Executive Officer and Principal Financial Officer, evaluated the effectiveness of the Company’s disclosure controls and procedures as of the end of the period covered by this report. Based upon that evaluation, the Company’s Chief Executive Officer and Principal Financial Officer concluded that the Company’s disclosure controls and procedures were effective as of March 31, 2011.

Changes in Internal Control Over Financial Reporting

     There were no changes in the Company’s internal control over financial reporting that occurred during the quarter ended March 31, 2011 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

Part II. Other Information

Item 1.Legal Proceedings

     For a discussion of various environmental and other matters, refer to Part I, Item 1 at Note 6 — Commitments and Contingencies, and Part I, Item 2 — MD&A of this report under the heading “Other Matters — Environmental Matters.”

     In addition to these matters, 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 are they expected to have a material adverse effect on the financial condition of the Company.

Item 1A.Risk Factors

     The risk factors in Item 1A of the Company’s 2010 Form 10-K, as amended by Item 1A of Part II of the Company’s Form 10-Q for the quarter ended December 31, 2010, have not materially changed other than as set forth below. The risk factor presented below supersedes the risk factor having the same caption in the 2010 Form 10-K and should otherwise be read in conjunction with all of the risk factors disclosed in that Form 10-K and in the Company’s December 31, 2010 Form 10-Q.

The Company has significant transactions involving price hedging of its oil and natural gas production as well as its fixed price purchase and sale commitments.

     In order to protect itself to some extent against unusual price volatility and to lock in fixed pricing on oil and natural gas production for certain periods of time, the Company’s Exploration and Production segment regularly enters into commodity price derivatives contracts (hedging arrangements) with respect to a portion of its expected production. These contracts may at any time cover as much as approximately 80% of the Company’s expected energy production during the upcoming 12-month period. These contracts reduce exposure to subsequent price drops but can also limit the Company’s ability to benefit from increases in commodity prices. In addition, the Energy Marketing segment enters into certain hedging arrangements, primarily with respect to its fixed price purchase and sales commitments and its gas stored underground. The Company’s Pipeline and Storage segment enters into hedging arrangements with respect to certain sales of efficiency gas.

     Under applicable accounting rules currently in effect, the Company’s hedging arrangements are subject to quarterly effectiveness tests. Inherent within those effectiveness tests are assumptions concerning the long-term price differential between different types of crude oil, assumptions concerning the difference between published natural gas price indexes established by pipelines in which hedged natural gas production

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Item 1A.Risk Factors (Concl.)

is delivered and the reference price established in the hedging arrangements, assumptions regarding the levels of production that will be achieved and, with regard to fixed price commitments, assumptions regarding the creditworthiness of certain customers and their forecasted consumption of natural gas. Depending on market conditions for natural gas and crude oil and the levels of production actually achieved, it is possible that certain of those assumptions may change in the future, and, depending on the magnitude of any such changes, it is possible that a portion of the Company’s hedges may no longer be considered highly effective. In that case, gains or losses from the ineffective derivative financial instruments would be marked-to-market on the income statement without regard to an underlying physical transaction. For example, in the Exploration and Production segment, where the Company uses short positions (i.e. positions that pay off in the event of commodity price decline) to hedge forecasted sales, gains would occur to the extent that natural gas and crude oil hedge prices exceed market prices for the Company’s natural gas and crude oil production, and losses would occur to the extent that market prices for the Company’s natural gas and crude oil production exceed hedge prices.

     Use of energy commodity price hedges also exposes the Company to the risk of non-performance by a contract counterparty. These parties might not be able to perform their obligations under the hedge arrangements.

     It is the Company’s policy that the use of commodity derivatives contracts comply with various restrictions in effect in respective business segments. For example, in the Exploration and Production segment, commodity derivatives contracts must be confined to the price hedging of existing and forecast production, and in the Energy Marketing segment, commodity derivatives with respect to fixed price purchase and sales commitments must be matched against commitments reasonably certain to be fulfilled. Similar restrictions apply in the Pipeline and Storage segment. The Company maintains a system of internal controls to monitor compliance with its policy. However, unauthorized speculative trades, if they were to occur, could expose the Company to substantial losses to cover positions in its derivatives contracts. In addition, in the event the Company’s actual production of oil and natural gas falls short of hedged forecast production, the Company may incur substantial losses to cover its hedges.

     In July 2010, the Dodd-Frank Wall Street Reform and Consumer Protection Act was signed into law. The law includes provisions aimed at increasing the transparency and stability of the over-the-counter derivatives markets and preventing excessive speculation. A variety of rules must be adopted by federal agencies (including the Commodity Futures Trading Commission, SEC and the FERC) to implement the law. These rules, which have not yet been finalized, could reduce trading positions in the energy futures markets and otherwise negatively impact the Company. For example, while the Company expects to be exempt from the law’s mandatory clearing and exchange trading requirements for most or all of its commodity hedges, other requirements with respect to these hedges, including capital, margin and reporting requirements, may apply to the Company. These requirements could increase the Company’s hedging costs. The new rules could also reduce the Company’s hedging opportunities, which could negatively affect the Company’s revenues and cash flow during periods of declining commodity prices and negatively affect the Company’s expenses during periods of rising commodity prices.

Item 2.Unregistered Sales of Equity Securities and Use of Proceeds

     On January 3, 2011, the Company issued a total of 3,600 unregistered shares of Company common stock to the nine non-employee directors of the Company then serving on the Board of Directors of the Company, 400 shares to each such director. All of these unregistered shares were issued under the Company’s 2009 Non-Employee Director Equity Compensation Plan as partial consideration for such directors’ services during the quarter ended March 31, 2011. These transactions were exempt from registration under Section 4(2) of the Securities Act of 1933, as transactions not involving a public offering.

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Item 2.Unregistered Sales of Equity Securities and Use of Proceeds (Concl.)

Issuer Purchases of Equity Securities

					Total Number of		Maximum Number
					Shares Purchased		of Shares that May
					as Part of Publicly		Yet Be Purchased
	Total Number of				Announced Share		Under Share
	Shares		Average Price Paid		Repurchase Plans		Repurchase Plans
Period	Purchased(a)		per Share		or Programs		or Programs(b)
Jan. 1 - 31, 2011		6,598	$	69.60		—		6,971,019
Feb. 1 - 28, 2011		92,361	$	70.87		—		6,971,019
Mar. 1 - 31, 2011		22,033	$	70.71		—		6,971,019
Total		120,992	$	70.77		—		6,971,019

^(a) Represents (i) shares of common stock of the Company purchased on the open market with Company “matching contributions” for the accounts of participants in the Company’s 401(k) plans, and (ii) shares of common stock of the Company tendered to the Company by holders of stock options, SARs or shares of restricted stock for the payment of option exercise prices or applicable withholding taxes. During the quarter ended March 31, 2011, the Company did not purchase any shares of its common stock pursuant to its publicly announced share repurchase program. Of the 120,992 shares purchased other than through a publicly announced share repurchase program, 18,311 were purchased for the Company’s 401(k) plans and 102,681 were purchased as a result of shares tendered to the Company by holders of stock options, SARs or shares of restricted stock.

^(b) In September 2008, the Company’s Board of Directors authorized the repurchase of eight million shares of the Company’s common stock. The Company, however, stopped repurchasing shares after September 17, 2008 in light of the unsettled nature of the credit markets. Since that time, the Company has increased its emphasis on Marcellus Shale development and pipeline expansion. As such, the Company does not anticipate repurchasing any shares in the near future.

Item 6.Exhibits

Exhibit
Number		Description of Exhibit
	•	By-Laws of National Fuel Gas Company, as amended March 10, 2011 (incorporated herein by reference to Exhibit 3.1, Form 8-K dated March 14, 2011).
	12	Statements regarding Computation of Ratios:
		Ratio of Earnings to Fixed Charges for the Twelve Months Ended March 31, 2011 and the Fiscal Years Ended September 30, 2007 through 2010.
	31.1	Written statements of Chief Executive Officer pursuant to Rule 13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act of 1934.
	31.2	Written statements of Principal Financial Officer pursuant to Rule 13a-14(a) or Rule 15d-14(a) under the Securities Exchange Act of 1934.
	32	Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
	99	National Fuel Gas Company Consolidated Statement of Income for the Twelve Months Ended March 31, 2011 and 2010.

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Item 6.Exhibits (Concl.)

101 Interactive data files pursuant to Regulation S-T: (i) the Consolidated Statements of Income and Earnings Reinvested in the Business for the three and six months ended March 31, 2011 and 2010, (ii) the Consolidated Balance Sheets at March 31, 2011 and September 30, 2010, (iii) the Consolidated Statements of Cash Flows for the six months ended March 31, 2011 and 2010, (iv) the Consolidated Statements of Comprehensive Income for the three and six months ended March 31, 2011 and 2010 and (v) the Notes to Condensed Consolidated Financial Statements.

•     Incorporated herein by reference as indicated.

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SIGNATURES

     Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

NATIONAL FUEL GAS COMPANY
  (Registrant)
 

/s/ D. P. Bauer  

D. P. Bauer 

Treasurer and Principal Financial Officer 

/s/ K. M. Camiolo  

K. M. Camiolo 

Controller and Principal Accounting Officer 

Date: May 6, 2011

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