UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended~~June 30,~~ December 31, 2011

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

For the transition period from to

Commission File Number 1-3880

NATIONAL FUEL GAS COMPANY

(Exact name of registrant as specified in its charter)


New Jersey		13-1086010
(State or other jurisdiction of		~~(I.R.S. Employer~~
incorporation or organization)		(I.R.S. Employer 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. YES x NO ¨

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). YES x NO ¨

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):

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

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

Common stock, $1 par value, outstanding at ~~July~~January 31, ~~2011: 82,726,474~~2012: 83,073,132 shares.

GLOSSARY OF TERMS

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

National Fuel Gas Companies


*~~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


~~Regulatory Agencies~~
EPA		United States Environmental Protection Agency
FASB		Financial Accounting Standards Board
FERC		Federal Energy Regulatory Commission
IASB		International Accounting Standards Board
NYDEC		New York State Department of Environmental Conservation
NYPSC		State of New York Public Service Commission
PaPUC		Pennsylvania Public Utility Commission
PHMSA		Pipeline and Hazardous Materials Safety Administration
SEC		Securities and Exchange Commission

Other


~~Other~~
~~2010~~2011 Form 10-K		The Company’s Annual Report on Form 10-K for the year ended September 30, ~~2010~~2011
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 oil and gas reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas.
Dodd-Frank Act		Dodd-Frank Wall Street Reform and Consumer Protection ~~Act~~Act.

-2-

GLOSSARY OF TERMS (Cont.)


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.

~~-1-~~

~~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~~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 (PUD) 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.

-3-

GLOSSARY OF TERMS (Concl.)


Restructuring		Generally referring to partial “deregulation” of the pipeline and/or utility industry by a 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.

~~-2-~~

~~GLOSSARY OF TERMS (Concl.)~~


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 ~~Ratings~~Rating Service
SAR		Stock appreciation right
Service agreement		The binding agreement by which the pipeline company agrees to provide service and the shipper agrees to pay for the service.
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.

~~-3-~~-4-

INDEX


	~~Page~~
Part I. Financial Information	Page

Item 1.
~~Item 1.~~ Financial Statements (Unaudited)


a. Consolidated Statements of Income and Earnings Reinvested in the Business –- Three ~~and Nine~~ Months Ended ~~June 30,~~December 31, 2011 and 2010		~~5 -~~ 6

	b. Consolidated Balance Sheets – ~~June 30,~~December 31, 2011 and September 30, ~~2010~~2011			7 - 8


c. Consolidated Statements of Cash Flows – ~~Nine~~Three Months Ended ~~June 30,~~December 31, 2011 and 2010		9

	d. Consolidated Statements of Comprehensive Income –- Three ~~and Nine~~ Months Ended ~~June 30,~~December 31, 2011 and 2010			10

	e. Notes to Condensed Consolidated Financial Statements			11 - 30	27

Item 2.	~~Item 2.~~ Management’s Discussion and Analysis of Financial Condition and Results of Operations			3128 - 56	49

Item 3.	~~Item 3.~~ Quantitative and Qualitative Disclosures About Market Risk			56	49

Item 4.	~~Item 4.~~ Controls and Procedures			56	49 - 50

	Part II. Other Information

Item 1.
~~Item 1.~~ Legal Proceedings		57	50

Item 1 A.	Risk Factors			57	50 - 53

Item 2.	~~Item 2.~~ Unregistered Sales of Equity Securities and Use of Proceeds			57	53 - 54

Item 3.	Defaults Upon Senior Securities			.	•

Item 4.	Mine Safety Disclosures		•

Item 5.	Other Information		•
.Item 6.

~~Item 6.~~ Exhibits		58	54 - 55

Signatures		59		56

.	~~The Company has nothing to report under this item.~~

The Company has nothing to report under this item.

Reference to ~~the “Company”~~“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 –~~ 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.

~~-4-~~-5-

Part ~~I. Financial~~I.Financial Information

Item 1.Financial Statements

National Fuel Gas Company

Consolidated Statements of Income and Earnings

Reinvested in the Business

(Unaudited)


	Three Months Ended
	June 30,						Three Months Ended December 31,
(Thousands of Dollars, Except Per Common Share Amounts)	2011			2010			2011			2010
INCOME
Operating Revenues	$	380,979		$	351,992		$	432,423		$	450,948

Operating Expenses
Purchased Gas		112,725			97,195			132,193			163,038
Operation and Maintenance		95,977			96,593			100,059			97,450
Property, Franchise and Other Taxes		20,179			18,594			19,230			19,736
Depreciation, Depletion and Amortization		57,293			50,422			62,547			53,313

		286,174			262,804			314,029			333,537

Operating Income		94,805			89,188
Other Income (Expense):
Income (Loss) from Unconsolidated Subsidiaries		(77	)		624
Operating Income Other Income (Expense):								118,394			117,411
Interest Income		325			568			1,105			884
Other Income		1,890			851			1,336			(107	)
Interest Expense on Long-Term Debt		(17,876	)		(21,115	)		(18,641	)		(20,192	)
Other Interest Expense		(1,159	)		(1,866	)		(770	)		(1,401	)

Income from Continuing Operations Before Income Taxes		77,908			68,250
Income Before Income Taxes								101,424			96,595
Income Tax Expense		31,017			25,608			40,725			38,052

Income from Continuing Operations		46,891			42,642

Loss from Discontinued Operations, Net of Tax		—			(57	)

Net Income Available for Common Stock		46,891			42,585			60,699			58,543

EARNINGS REINVESTED IN THE BUSINESS
Balance at April 1		1,180,531			1,038,869
Balance at October 1								1,206,022			1,063,262

		1,227,422			1,081,454			1,266,721			1,121,805
Dividends on Common Stock (2011 – $0.355 per share; 2010 – $0.345 per share)		(29,358	)		(28,278	)
Dividends on Common Stock (2011—$0.355 per share; 2010—$0.345 per share)								(29,479	)		(28,407	)

Balance at June 30	$	1,198,064		$	1,053,176
Balance at December 31							$	1,237,242		$	1,093,398

Earnings Per Common Share:
Basic:
Income from Continuing Operations	$	0.57		$	0.52
Loss from Discontinued Operations		—			—

Net Income Available for Common Stock	$	0.57		$	0.52		$	0.73		$	0.71

Diluted:
Income from Continuing Operations	$	0.56		$	0.51
Loss from Discontinued Operations		—			—

Net Income Available for Common Stock	$	0.56		$	0.51		$	0.73		$	0.70

Weighted Average Common Shares Outstanding:
Used in Basic Calculation		82,687,467			81,801,377			82,870,931			82,223,428

Used in Diluted Calculation		83,782,493			82,970,921			83,699,981			83,420,351

See Notes to Condensed Consolidated Financial Statements

~~-5-~~

~~Item 1.Financial Statements (Cont.)~~

~~National Fuel Gas Company~~

~~Consolidated Statements of Income and Earnings~~

~~Reinvested in the Business~~

~~(Unaudited)~~

   Nine Months Ended
   June 30,
(Thousands of Dollars, Except Per Common Share Amounts)    2011 2010
INCOME

Operating Revenues
   $ 1,492,808    $ 1,474,107


Operating Expenses

Purchased Gas
   582,358    601,408
Operation and Maintenance
   310,148    306,624
Property, Franchise and Other Taxes
   63,714    57,684
Depreciation, Depletion and Amortization
   170,617    141,935


   1,126,837    1,107,651


Operating Income
   365,971    366,456
Other Income (Expense):

Income (Loss) from Unconsolidated Subsidiaries
   (698 ) 1,696
Gain on Sale of Unconsolidated Subsidiaries
   50,879    —
Interest Income
   1,277    2,048
Other Income
   4,828    2,473
Interest Expense on Long-Term Debt
   (55,994 ) (65,238 )
Other Interest Expense
   (4,014 ) (5,245 )


Income from Continuing Operations Before Income Taxes
   362,249    302,190
Income Tax Expense
   141,204    115,449


Income from Continuing Operations
   221,045    186,741


Income from Discontinued Operations, Net of Tax
   —      771


Net Income Available for Common Stock
   221,045    187,512


EARNINGS REINVESTED IN THE BUSINESS

Balance at October 1
   1,063,262    948,293


   1,284,307    1,135,805
Dividends on Common Stock
(2011 – $1.045 per share; 2010 – $1.015 per share)
   (86,243 ) (82,629 )


Balance at June 30
   $ 1,198,064    $ 1,053,176


Earnings Per Common Share:

Basic:

Income from Continuing Operations
   $ 2.68    $ 2.30
Income from Discontinued Operations
   —      0.01


Income Available for Common Stock
   $ 2.68    $ 2.31


Diluted:

Income from Continuing Operations
   $ 2.64    $ 2.26
Income from Discontinued Operations
   —      0.01


Income Available for Common Stock
   $ 2.64    $ 2.27


Weighted Average Common Shares Outstanding:

Used in Basic Calculation
   82,436,603    81,178,000


Used in Diluted Calculation
   83,649,498    82,556,730

~~See Notes to Condensed Consolidated Financial Statements~~

-6-

Item 1.Financial Statements (Cont.)

National Fuel Gas Company

Consolidated Balance Sheets

(Unaudited)


	June 30,		September 30,
(Thousands of Dollars)	2011		2010		December 31, 2011		September 30, 2011
ASSETS
Property, Plant and Equipment	$	5,392,065	$	5,637,498	$	5,922,308	$	5,646,918
Less – Accumulated Depreciation, Depletion and Amortization		1,607,088		2,187,269
Less—Accumulated Depreciation, Depletion and Amortization						1,694,366		1,646,394

		3,784,977		3,450,229		4,227,942		4,000,524

Current Assets
Cash and Temporary Cash Investments		184,710		397,171		224,262		80,428
Hedging Collateral Deposits		37,984		11,134		25,118		19,701
Receivables – Net of Allowance for Uncollectible Accounts of $39,221 and $30,961, Respectively		165,576		132,136
Receivables—Net of Allowance for Uncollectible Accounts of $35,849 and $31,039, Respectively						152,888		131,885
Unbilled Utility Revenue		13,399		20,920		47,335		17,284
Gas Stored Underground		22,525		48,584		50,808		54,325
Materials and Supplies – at average cost		28,923		24,987
Materials and Supplies—at average cost						27,263		27,932
Unrecovered Purchased Gas Costs						3,002		—
Other Current Assets		44,786		115,969		43,516		38,334
Deferred Income Taxes		22,885		24,476		14,921		15,423

		520,788		775,377		589,113		385,312

Other Assets
Recoverable Future Taxes		151,142		149,712		145,469		144,377
Unamortized Debt Expense		11,058		12,550		14,579		10,571
Other Regulatory Assets		524,355		542,801		570,927		574,644
Deferred Charges		4,989		9,646		4,429		5,552
Other Investments		84,118		77,839		81,055		79,365
Investments in Unconsolidated Subsidiaries		1,367		14,828
Goodwill		5,476		5,476		5,476		5,476
Fair Value of Derivative Financial Instruments		43,347		65,184		106,115		76,085
Other		1,648		1,983		2,650		2,836

		827,500		880,019		930,700		898,906

Total Assets	$	5,133,265	$	5,105,625	$	5,747,755	$	5,284,742

See Notes to Condensed Consolidated Financial Statements

-7-

Item 1.Financial Statements (Cont.)

National Fuel Gas Company

Consolidated Balance Sheets

(Unaudited)


	June 30,			September 30,
(Thousands of Dollars)	2011			2010			December 31, 2011			September 30, 2011
CAPITALIZATION AND LIABILITIES
Capitalization:
Comprehensive Shareholders’ Equity
Common Stock, $1 Par Value Authorized – 200,000,000 Shares; Issued and Outstanding – 82,700,177 Shares and 82,075,470 Shares, Respectively	$	82,700		$	82,075
Common Stock, $1 Par Value
Authorized —200,000,000 Shares;
Issued and Outstanding – 83,038,485 Shares and 82,812,677 Shares, Respectively							$	83,038		$	82,813
Paid in Capital		644,945			645,619			654,000			650,749
Earnings Reinvested in the Business		1,198,064			1,063,262			1,237,242			1,206,022

Total Common Shareholder Equity Before Items of Other Comprehensive Loss		1,925,709			1,790,956
Total Common Shareholders’ Equity Before Items of Other Comprehensive Loss								1,974,280			1,939,584
Accumulated Other Comprehensive Loss		(75,098	)		(44,985	)		(53,132	)		(47,699	)

Total Comprehensive Shareholders’ Equity		1,850,611			1,745,971			1,921,148			1,891,885
Long-Term Debt, Net of Current Portion		899,000			1,049,000			1,399,000			899,000

Total Capitalization		2,749,611			2,794,971			3,320,148			2,790,885

Current and Accrued Liabilities
Notes Payable to Banks and Commercial Paper		—			—			20,000			40,000
Current Portion of Long-Term Debt		150,000			200,000			—			150,000
Accounts Payable		95,182			89,677			105,209			126,709
Amounts Payable to Customers		25,661			38,109			11,997			15,519
Dividends Payable		29,358			28,316			29,479			29,399
Interest Payable on Long-Term Debt		15,953			30,512			16,320			25,512
Customer Advances		1,021			27,638			25,814			19,643
Customer Security Deposits		17,672			18,320			17,685			17,321
Other Accruals and Current Liabilities		133,856			71,592			146,251			94,787
Fair Value of Derivative Financial Instruments		44,607			20,160			48,210			9,728

		513,310			524,324			420,965			528,618

Deferred Credits
Deferred Income Taxes		919,145			800,758			991,805			955,384
Taxes Refundable to Customers		70,343			69,585			65,547			65,543
Unamortized Investment Tax Credit		2,761			3,288			2,441			2,586
Cost of Removal Regulatory Liability		133,759			124,032			144,770			135,940
Other Regulatory Liabilities		92,811			89,334			100,832			94,684
Pension and Other Post-Retirement Liabilities		435,517			446,082			467,396			481,520
Asset Retirement Obligations		65,583			101,618			76,930			75,731
Other Deferred Credits		150,425			151,633			156,921			153,851

		1,870,344			1,786,330			2,006,642			1,965,239

Commitments and Contingencies		—			—			—			—

Total Capitalization and Liabilities	$	5,133,265		$	5,105,625		$	5,747,755		$	5,284,742

See Notes to Condensed Consolidated Financial Statements

-8-

Item 1.Financial Statements (Cont.)

National Fuel Gas Company

Consolidated Statements of Cash Flows

(Unaudited)


	Nine Months Ended
	June 30,						Three Months Ended December 31,
(Thousands of Dollars)	2011			2010			2011			2010
OPERATING ACTIVITIES
Net Income Available for Common Stock	$	221,045		$	187,512		$	60,699		$	58,543
Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities:
Gain on Sale of Unconsolidated Subsidiaries		(50,879	)		—
Depreciation, Depletion and Amortization		170,617			142,433			62,547			53,313
Deferred Income Taxes		140,326			63,813			39,398			36,600
(Income) Loss from Unconsolidated Subsidiaries, Net of Cash Distributions		4,976			904
Excess Tax Costs (Benefits) Associated with Stock-Based Compensation Awards		1,224			(13,207	)
Other		2,375			7,884			2,375			3,543
Change in:
Hedging Collateral Deposits		(26,850	)		(7,374	)		(5,417	)		(20,312	)
Receivables and Unbilled Utility Revenue		(25,919	)		6,676			(51,054	)		(53,984	)
Gas Stored Underground and Materials and Supplies		22,387			20,384			(2,226	)		(5,828	)
Unrecovered Purchased Gas Costs								(3,002	)		—
Prepayments and Other Current Assets		69,960			39,043			(5,182	)		8,768
Accounts Payable		5,506			127			(21,500	)		29,246
Amounts Payable to Customers		(12,448	)		(54,764	)		(3,522	)		(14,195	)
Customer Advances		(26,617	)		(23,526	)		6,171			(5	)
Customer Security Deposits		(648	)		1,188			364			188
Other Accruals and Current Liabilities		36,743			30,961			(4,008	)		1,387
Other Assets		20,255			29,197			(28,139	)		(10,463	)
Other Liabilities		(15,771	)		(11,358	)		31,724			670

Net Cash Provided by Operating Activities		536,282			419,893			79,228			87,471

INVESTING ACTIVITIES
Capital Expenditures		(583,739	)		(327,513	)		(232,670	)		(193,802	)
Net Proceeds from Sale of Unconsolidated Subsidiaries		59,365			—
Net Proceeds from Sale of Oil and Gas Producing Properties		69,435			—
Other		(2,908	)		(273	)		(966	)		(298	)

Net Cash Used in Investing Activities		(457,847	)		(327,786	)		(233,636	)		(194,100	)

FINANCING ACTIVITIES
Excess Tax (Costs) Benefits Associated with Stock-Based Compensation Awards		(1,224	)		13,207
Changes in Notes Payable to Banks and Commercial Paper								(20,000	)		20,500
Net Proceeds from Issuance of Long-Term Debt								496,085			—
Reduction of Long-Term Debt		(200,000	)		—			(150,000	)		(200,000	)
Dividends Paid on Common Stock		(85,201	)		(81,318	)		(29,398	)		(28,316	)
Net Proceeds from Issuance (Repurchase) of Common Stock		(4,471	)		26,798			1,555			(3,104	)

Net Cash Used in Financing Activities		(290,896	)		(41,313	)
Net Cash Provided by (Used in) Financing Activities								298,242			(210,920	)

Net Increase (Decrease) in Cash and Temporary Cash Investments		(212,461	)		50,794			143,834			(317,549	)

Cash and Temporary Cash Investments at October 1		397,171			408,053			80,428			397,171

Cash and Temporary Cash Investments at June 30	$	184,710		$	458,847
Cash and Temporary Cash Investments at December 31							$	224,262		$	79,622

See Notes to Condensed Consolidated Financial Statements

-9-

Item 1.Financial Statements (Cont.)

National Fuel Gas Company

Consolidated Statements of Comprehensive Income

(Unaudited)

   Three Months Ended
   June 30,
(Thousands of Dollars)    2011 2010
Net Income Available for Common Stock
   $ 46,891    $ 42,585
Other Comprehensive Income, Before Tax:

Foreign Currency Translation Adjustment
   —      77
Unrealized Gain (Loss) on Securities Available for Sale Arising During the Period
   23    (3,361 )
Unrealized Gain on Derivative Financial Instruments Arising During the Period
   26,378    16,528
Reclassification Adjustment for Realized (Gains) Losses on Derivative Financial Instruments in Net Income
   3,185    (11,830 )


Other Comprehensive Income, Before Tax
   29,586    1,414


Income Tax Expense (Benefit) Related to Unrealized Gain (Loss) on Securities Available for Sale Arising During the Period
   8    (1,271 )
Income Tax Expense Related to Unrealized Gain on Derivative Financial Instruments Arising During the Period
   10,810    6,794
Reclassification Adjustment for Income Tax Benefit (Expense) on Realized Losses (Gains) on Derivative Financial Instruments in Net Income
   1,345    (4,858 )


Income Taxes – Net
   12,163    665


Other Comprehensive Income
   17,423    749


Comprehensive Income
   $ 64,314    $ 43,334


   Nine Months Ended
   June 30,
(Thousands of Dollars)    2011 2010
Net Income Available for Common Stock
   $ 221,045    $ 187,512


Other Comprehensive Income (Loss), Before Tax:

Foreign Currency Translation Adjustment
   17    140
Reclassification Adjustment for Realized Foreign Currency Transaction Loss in Net Income
   34    —
Unrealized Gain (Loss) on Securities Available for Sale Arising During the Period
   3,461    (2,916 )
Unrealized Gain (Loss) on Derivative Financial Instruments Arising During the Period
   (41,602 ) 39,308
Reclassification Adjustment for Realized Gains on Derivative Financial Instruments in Net Income
   (13,080 ) (29,472 )


Other Comprehensive Income (Loss), Before Tax
   (51,170 ) 7,060


Income Tax Expense (Benefit) Related to Unrealized Gain (Loss) on Securities Available for Sale Arising During the Period
   1,306    (1,104 )
Income Tax Expense (Benefit) Related to Unrealized Gain (Loss) on Derivative Financial Instruments Arising During the Period
   (17,136 ) 16,041
Reclassification Adjustment for Income Tax Expense on Realized Gains on Derivative Financial Instruments in Net Income
   (5,227 ) (12,120 )


Income Taxes – Net
   (21,057 ) 2,817


Other Comprehensive Income (Loss)
   (30,113 ) 4,243


Comprehensive Income
   $ 190,932    $ 191,755


	Three Months Ended December 31,
(Thousands of Dollars)	2011			2010
Net Income Available for Common Stock	$	60,699		$	58,543

Other Comprehensive Income (Loss), Before Tax:
Foreign Currency Translation Adjustment		—			17
Reclassification Adjustment for Realized Foreign Currency Translation Loss in Net Income		—			34
Unrealized Gain on Securities Available for Sale Arising During the Period		712			2,540
Unrealized Gain (Loss) on Derivative Financial Instruments Arising During the Period		2,155			(27,136	)
Reclassification Adjustment for Realized Gains on Derivative Financial Instruments in Net Income		(11,864	)		(9,053	)

Other Comprehensive Loss, Before Tax		(8,997	)		(33,598	)

Income Tax Expense Related to Unrealized Gain on Securities Available for Sale Arising During the Period		263			960
Income Tax Expense (Benefit) Related to Unrealized Gain (Loss) on Derivative Financial Instruments Arising During the Period		817			(11,168	)
Reclassification Adjustment for Income Tax Expense on Realized Gains from Derivative Financial Instruments In Net Income		(4,644	)		(3,725	)

Income Taxes – Net		(3,564	)		(13,933	)

Other Comprehensive Loss		(5,433	)		(19,665	)

Comprehensive Income	$	55,266		$	38,878

See Notes to Condensed Consolidated Financial Statements

-10-

Item 1.Financial Statements (Cont.)

National Fuel Gas Company

Notes to Condensed Consolidated Financial Statements

(Unaudited)

Note ~~1 –~~ 1—Summary of Significant Accounting Policies

Principles of Consolidation. The Company consolidates all entities in which it has a controlling financial interest. The equity method is used to account for entities in which the Company has a non-controlling financial interest. 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, 2011, 2010 ~~2009~~ and ~~2008~~2009 that are included in the Company’s ~~2010~~2011 Form 10-K. The consolidated financial statements for the year ended September 30, ~~2011~~2012 will be audited by the Company’s independent registered public accounting firm after the end of the fiscal year.

The earnings for the ~~nine~~three months ended ~~June 30,~~December 31, 2011 should not be taken as a prediction of earnings for the entire fiscal year ending September 30, ~~2011.~~2012. 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 87 – 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~~investments purchased with a maturity of generally three months or less to be cash equivalents.

At ~~June~~December 31, 2011, the Company accrued $88.1 million of capital expenditures in the Exploration and Production segment, the majority of which was in the Appalachian region. The Company also accrued $15.8 million of capital expenditures in the Pipeline and Storage segment and $14.5 million of capital expenditures in the All Other category at December 31, 2011. These amounts were excluded from the Consolidated Statement of Cash Flows at December 31, 2011 since they represent non-cash investing activities at that date. Accrued capital expenditures at December 31, 2011 are included in Other Accruals and Current Liabilities on the Consolidated Balance Sheet.

At September 30, 2011, the Company accrued $63.5 million of capital expenditures in the Exploration and Production segment, the majority of which was in the Appalachian region. The Company also accrued $7.3 million of capital expenditures in the Pipeline and Storage segment. In addition, the Company accrued $1.4 million of capital expenditures in the All Other category. These amounts were excluded from the Consolidated Statement of Cash Flows at September 30, 2011 since they represented non-cash investing activities at that date. These capital expenditures were paid during the quarter ended December 31, 2011 and have been included in the Consolidated Statement of Cash Flows for the quarter ended December 31, 2011. Accrued capital expenditures at September 30, 2011 are included in Other Accruals and Current Liabilities on the Consolidated Balance Sheet.

-11-

Item 1.Financial Statements (Cont.)

At December 31, 2010, the Company accrued $60.7 million of capital expenditures in the Exploration and Production segment, the majority of which was in the Appalachian region. The Company also accrued ~~$5.9~~$2.0 million of capital expenditures in the Pipeline and Storage segment at ~~June 30, 2011.~~December 31, 2010. These amounts were excluded from the Consolidated Statement of Cash Flows at ~~June 30, 2011~~December 31, 2010 since they ~~represent~~represented non-cash investing activities at that date. ~~Accrued capital expenditures at June 30, 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 ~~nine months ended June 30, 2011. Accrued capital expenditures at September 30, 2010 are included in Other Accruals and Current Liabilities on the Consolidated Balance Sheet.~~

~~-11-~~

~~Item 1.Financial Statements (Cont.)~~

At June 30, 2010, the Company accrued $24.3 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 June 30, 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 nine months ended June 30,~~ 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 ~~June 30,~~December 31, 2011, the Company had hedging collateral deposits of ~~$5.6~~$4.5 million related to its exchange-traded futures contracts and ~~$32.4~~$20.6 million related to its over-the-counter crude oil swap agreements. At September 30, ~~2010,~~2011, the Company had hedging collateral deposits of ~~$10.1~~$5.5 million related to its exchange-traded futures contracts and ~~$1.0~~$14.2 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 ~~instrument~~instruments liability or asset balances.

Gas Stored ~~Underground –~~ 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 ~~$45.0~~$7.1 million at ~~June 30,~~December 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 ~~$193.9~~$226.5 million and ~~$151.2~~$226.3 million at ~~June 30,~~December 31, 2011 and September 30, ~~2010,~~2011, 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.

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. The Company also eliminated the asset retirement obligation associated with its off-shore oil and gas properties. This obligation amounted to $37.5 million and was accounted for as a reduction of capitalized costs under the full cost method of accounting for oil and natural gas properties as well as a reduction of the asset retirement obligation.

~~-12-~~

~~Item 1.Financial Statements (Cont.)~~

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~~The natural gas and oil prices used to

-12-

Item 1.Financial Statements (Cont.)

calculate the full cost ceiling ~~(as of June 30, 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 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 ~~June 30,~~December 31, 2011, the ~~Company’s capitalized costs were below~~ceiling exceeded the ~~full cost ceiling for~~book value of the ~~Company’s~~ oil and gas ~~properties. As a result, an impairment charge was not required at June 30, 2011.~~properties by approximately $360.3 million.

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


	At June 30, 2011			At September 30, 2010			At December 31, 2011			At September 30, 2011
Funded Status of the Pension and Other Post-Retirement Benefit Plans	$	(79,465	)	$	(79,465	)	$	(89,587	)	$	(89,587	)
Cumulative Foreign Currency Translation Adjustment		—			(51	)
Net Unrealized Gain on Derivative Financial Instruments		557			32,876			35,097			40,979
Net Unrealized Gain on Securities Available for Sale		3,810			1,655			1,358			909

Accumulated Other Comprehensive Loss	$	(75,098	)	$	(44,985	)	$	(53,132	)	$	(47,699	)

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


	At June 30, 2011		At September 30, 2010		At December 31, 2011		At September 30, 2011
Prepayments	$	12,645	$	13,884	$	5,857	$	9,489
Prepaid Property and Other Taxes		10,653		12,413		15,146		13,240
Federal Income Taxes Receivable		9,514		56,334		378		385
State Income Taxes Receivable		7,902		18,007		5,089		6,124
Fair Values of Firm Commitments		4,072		15,331		17,046		9,096

	$	44,786	$	115,969	$	43,516	$	38,334

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 ~~6,512~~191,285 and 23,478 securities excluded as being antidilutive ~~securities~~ for the ~~quarter~~quarters ended ~~June 30, 2011. There were no antidilutive securities for the nine months ended June 30, 2011. There were 544,500~~December 31, 2011 and ~~237,538 antidilutive securities for the quarter and nine months ended June 30,~~ 2010, respectively.

~~-13-~~

~~Item 1.Financial Statements (Cont.)~~

Stock-Based Compensation.During the ~~nine months~~quarter ended ~~June 30,~~December 31, 2011, the Company granted ~~180,000~~166,000 non-performance based SARs having a weighted average exercise price of ~~$63.87~~$55.09 per share. The weighted average grant date fair value of these SARs was ~~$15.33~~$11.20 per share. These SARs ~~may~~will 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 June 30, 2011.~~ The non-performance based SARs granted during the ~~nine months~~quarter ended ~~June 30,~~December 31, 2011 vest annually in one-third increments and become exercisable ~~annually in one-third increments.~~on the third anniversary of the date of grant. The weighted average grant date fair value of these non-performance based SARs granted during the ~~nine months~~quarter ended ~~June 30,~~December 31, 2011 was estimated on the date of grant using the same accounting treatment that is applied for stock options.

-13-

Item 1.Financial Statements (Cont.)

There were no stock options granted during the quarter ~~or nine months~~ ended ~~June 30,~~December 31, 2011. The Company did not recognize a tax benefit related to the exercise of stock options and/or performance based SARs for the calendar ~~year~~years ended December 31, 2011 and December 31, 2010 due to tax loss carryforwards. The Company expects to recognize a tax ~~benefit~~benefits of $14.2 million and $18.1 million in Paid in Capital related to calendar 2011 and calendar 2010 stock option and/or performance based SAR exercises, respectively, in future years as the tax loss carryforward is utilized.

The Company granted ~~47,250~~41,525 restricted share awards (non-vested stock as defined by the current accounting literature) during the ~~nine months~~quarter ended ~~June 30,~~December 31, 2011. The weighted average fair value of such restricted shares was ~~$63.98~~$55.09 per share. ~~There were no restricted share awards granted during the quarter ended June 30, 2011.~~ In addition, the Company granted ~~8,100 and 37,000~~56,000 restricted stock units during the quarter ~~and nine months~~ ended ~~June 30, 2011, respectively.~~December 31, 2011. The weighted average fair value of such restricted stock units was ~~$65.50~~$48.77 per ~~share and $59.82 per share for the quarter and nine months ended June 30, 2011, respectively.~~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.

New Authoritative Accounting and Financial Reporting Guidance.In May 2011, the FASB issued authoritative guidance regarding fair value measurement as a joint project with the IASB. The objective of the guidance was to bring together as closely as possible the fair value measurement and disclosure guidance issued by the two boards. The guidance includes a few updates to measurement guidance and some enhanced disclosure requirements. For all Level 3 fair value measurements, the guidance requires quantitative information about significant unobservable inputs used and a description of the valuation processes in place. The guidance also requires a qualitative discussion about the sensitivity of recurring Level 3 fair value measurements and information about any transfers between Level 1 and Level 2 of the fair value hierarchy. The new guidance also contains a requirement that all fair value measurements, whether they are recorded on the balance sheet or disclosed in the footnotes, be classified as Level 1, Level 2 or Level 3 within the fair value hierarchy. This authoritative guidance will be effective as of the Company’s second quarter of fiscal 2012. The Company is currently evaluating the impact that adoption of this authoritative guidance will have on its consolidated financial statement disclosures.

In June 2011, the FASB issued authoritative guidance regarding the presentation of comprehensive income. The new guidance allows companies only two choices for presenting net income and other comprehensive income: in a single continuous statement, or in two separate, but consecutive, statements. The guidance eliminates the current option to report other comprehensive income and its components in the statement of changes in equity. This authoritative guidance will be effective as of the Company’s first quarter of fiscal 2013 and is not expected to have a significant impact on the Company’s financial statements.

In September 2011, the FASB issued revised authoritative guidance that simplifies the testing of goodwill for impairment. The revised guidance allows companies the option to perform a “qualitative” assessment to determine whether further impairment testing is necessary. The revised authoritative guidance is required to be effective for the Company’s annual impairment test performed in fiscal 2013. While early adoption is permitted, the Company has not adopted the new provisions to date.

In December 2011, the FASB issued authoritative guidance requiring enhanced disclosures regarding offsetting assets and liabilities. Companies are required to disclose both gross information and net information about both instruments and transactions eligible for offset in the statement of financial position and instruments and transactions subject to an agreement similar to a master netting arrangement. This authoritative guidance will be effective as of the Company’s first quarter of fiscal 2014 and is not expected to have a significant impact on the Company’s financial statements.

-14-

Item 1.Financial Statements (Cont.)

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 ~~June 30,~~December 31, 2011 and September 30, ~~2010.~~2011. Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement.


Recurring Fair Value Measures	At fair value as of June 30, 2011											At fair value as of December 31, 2011
(Thousands of Dollars)	Level 1		Level 2			Level 3			Total			Level 1		Level 2			Level 3			Total
Assets:
Cash Equivalents – Money Market Mutual Funds	$	118,652	$	—		$	—		$	118,652		$	180,312	$	—		$	—		$	180,312
Derivative Financial Instruments:
Commodity Futures Contracts – Gas		56		—			—			56
Over the Counter Swaps – Oil		—		(176	)		—			(176	)
Over the Counter Swaps – Gas		—		43,367			—			43,367			—		106,115			—			106,115
Other Investments:
Balanced Equity Mutual Fund		22,030		—			—			22,030			21,696		—			—			21,696
Common Stock – Financial Services Industry		6,979		—			—			6,979			4,197		—			—			4,197
Other Common Stock		237		—			—			237			272		—			—			272
Hedging Collateral Deposits		37,984		—			—			37,984			25,118		—			—			25,118

Total	$	185,938	$	43,191		$	—		$	229,129		$	231,595	$	106,115		$	—		$	337,710

Liabilities:
Derivative Financial Instruments:
Commodity Futures Contracts – Gas	$	2,960	$	—		$	—		$	2,960
Commodity Futures Contracts—Gas												$	3,516	$	—		$	—		$	3,516
Over the Counter Swaps – Oil		—		—			50,453			50,453			—		—			54,773			54,773
Over the Counter Swaps – Gas		—		(8,806	)		—			(8,806	)		—		(10,079	)		—			(10,079	)

Total	$	2,960	$	(8,806	)	$	50,453		$	44,607		$	3,516	$	(10,079	)	$	54,773		$	48,210

Total Net Assets/(Liabilities)	$	182,978	$	51,997		$	(50,453	)	$	184,522		$	228,079	$	116,194		$	(54,773	)	$	289,500

-15-

Item 1.Financial Statements (Cont.)


Recurring Fair Value Measures	At fair value as of September 30, 2010										At fair value as of September 30, 2011
(Thousands of Dollars)	Level 1		Level 2		Level 3			Total			Level 1		Level 2		Level 3			Total
Assets:
Cash Equivalents – Money Market Mutual Funds	$	277,423	$	—	$	—		$	277,423		$	32,444	$	—	$	—		$	32,444
Derivative Financial Instruments:
Over the Counter Swaps – Gas		—		67,387		—			67,387			—		75,113		—			75,113
Over the Counter Swaps – Oil		—		—		(2,203	)		(2,203	)		—		—		972			972
Other Investments:
Balanced Equity Mutual Fund		17,256		—		—			17,256			19,882		—		—			19,882
Common Stock – Financial Services Industry		4,991		—		—			4,991			4,478		—		—			4,478
Other Common Stock		241		—		—			241			226		—		—			226
Hedging Collateral Deposits		11,134		—		—			11,134			19,701		—		—			19,701

Total	$	311,045	$	67,387	$	(2,203	)	$	376,229		$	76,731	$	75,113	$	972		$	152,816

Liabilities:
Derivative Financial Instruments:
Commodity Futures Contracts – Gas	$	5,840	$	—	$	—		$	5,840		$	3,292	$	—	$	—		$	3,292
Over the Counter Swaps – Oil		—		—		14,280			14,280			—		—		6,382			6,382
Over the Counter Swaps – Gas		—		40		—			40

Total	$	5,840	$	40	$	14,280		$	20,160		$	3,292	$	—	$	6,382		$	9,674

Total Net Assets/(Liabilities)	$	305,205	$	67,347	$	(16,483	)	$	356,069		$	73,439	$	75,113	$	(5,410	)	$	143,142

Derivative Financial Instruments

At ~~June 30,~~December 31, 2011 and September 30, ~~2010,~~2011, 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.~~segment. Hedging collateral deposits of ~~$5.6~~$4.5 million (at ~~June 30,~~December 31, 2011) and ~~$10.1~~$5.5 million (at September 30, ~~2010)~~2011), which are associated with these futures contracts have been reported in Level 1 as well. The derivative financial instruments reported in Level 2 at ~~June~~December 31, 2011 and September 30, 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 the Level 2 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~~all of the Company’s Exploration and Production segment’s crude oil price swap agreements at ~~June 30,~~December 31, 2011 and ~~all of its crude oil price swap agreements at~~ September 30, ~~2010.~~2011. Hedging collateral deposits of ~~$32.4~~$20.6 million and ~~$1.0~~$14.2 million associated with these crude oil price swap agreements have been reported in Level 1 at ~~June 30,~~December 31, 2011 and September 30, ~~2010,~~2011, respectively. The fair value of the Level 3 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~~has been reduced by ~~$0.4 million and $1.0~~$2.2 million at ~~June 30,~~December 31, 2011 and the fair market value of the price swap agreements reported as Level 2 and Level 3 assets has been reduced by $2.0 million at September 30, ~~2010, respectively.~~2011. 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~~at December 31, 2011 has been reduced by $0.1 million and ~~$0.3 million~~the fair market value of the price swap agreements reported as Level 3 liabilities has not been reduced at ~~June 30, 2011 and~~ September 30, ~~2010, respectively.~~2011. 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.

-16-

Item 1.Financial Statements (Cont.)

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 nine months~~ ended ~~June 30,~~December 31, 2011 and 2010, respectively. For the quarters ~~and nine months~~ ended ~~June 30,~~December 31, 2011 and ~~June 30,~~December 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)

Fair Value Measurements Using Unobservable Inputs (Level 3)
(Thousands of Dollars)
   Total Gains/Losses
      April 1,
2011 Gains/Losses
Realized and
Included in
Earnings Gains/Losses
Unrealized and
Included in
Other
Comprehensive
Income (Loss)    Transfer
In/Out of
Level 3    June 30,
2011
Derivative Financial Instruments⁽²⁾
   $ (71,913 ) $ 15,377 ⁽¹⁾ $ 6,083       $ —         $ (50,453 )


				Total Gains/Losses
(Dollars in thousands)	October 1, 2011			Gains/Losses Realized and Included in Earnings			Gains/Losses Unrealized and Included in Other Comprehensive Income			Transfer In/Out of Level 3		December 31, 2011
Derivative Financial Instruments⁽²⁾	$	(5,410	)	$	12,612	⁽¹⁾	$	(61,975	)	$	—	$	(54,773	)

⁽¹⁾	Amounts are reported in Operating Revenues in the Consolidated Statement of Income for the three months ended ~~June 30,~~December 31, 2011.

⁽²⁾	Derivative Financial Instruments are shown on a net basis.

Fair Value Measurements Using Unobservable Inputs (Level 3)

Fair Value Measurements Using Unobservable Inputs (Level 3)
(Thousands of Dollars)
   Total Gains/Losses
      October 1,
2010 Gains/Losses
Realized and
Included in
Earnings Gains/Losses
Unrealized and
Included in
Other
Comprehensive
Income (Loss) Transfer
In/Out of
Level 3    June 30,
2011
Derivative Financial Instruments⁽²⁾
   $ (16,483 ) $ 28,545 ⁽¹⁾ $ (62,515 ) $ —         $ (50,453 )

⁽¹⁾	~~Amounts are reported in Operating Revenues in the Consolidated Statement of Income for the nine months ended June 30, 2011.~~

⁽²⁾	~~Derivative Financial Instruments are shown on a net basis.~~

Fair Value Measurements Using Unobservable Inputs (Level 3)
(Thousands of Dollars)
   Total Gains/Losses
      April 1,
2010 Gains/Losses
Realized and
Included in
Earnings Gains/Losses
Unrealized and
Included in
Other
Comprehensive
Income (Loss)    Transfer
In/Out of
Level 3    June 30,
2010
Derivative Financial Instruments⁽²⁾
   $ (14,100 ) $ (2,172 )⁽¹⁾ $ 16,126       $ —         $ (146 )


				Total Gains/Losses
(Dollars in thousands)	October 1, 2010			Gains/Losses Realized and Included in Earnings			Gains/Losses Unrealized and Included in Other Comprehensive Income			Transfer In/ Out of Level 3		December 31, 2010
Derivative Financial Instruments⁽²⁾	$	(16,483	)	$	3,602	⁽¹⁾	$	(24,526	)	$	—	$	(37,407	)

⁽¹⁾	Amounts are reported in Operating Revenues in the Consolidated Statement of Income for the three months ended ~~June 30,~~December 31, 2010.

⁽²⁾	Derivative Financial Instruments are shown on a net basis.

~~-17-~~

~~Item 1.Financial Statements (Cont.)~~

Fair Value Measurements Using Unobservable Inputs (Level 3)
(Thousands of Dollars)
      Total Gains/Losses
      October 1,
2010    Gains/Losses
Realized and
Included in
Earnings Gains/Losses
Unrealized and
Included in
Other
Comprehensive
Income (Loss) Transfer
In/Out of
Level 3    June 30,
2010
Derivative Financial Instruments⁽²⁾
   $ 26,969       $ (6,969 )⁽¹⁾ $ (20,146 ) $ —         $ (146 )

⁽¹⁾	~~Amounts are reported in Operating Revenues in the Consolidated Statement of Income for the nine months ended June 30, 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):

   June 30, 2011    September 30, 2010
   Carrying
Amount    Fair Value    Carrying
Amount    Fair Value
Long-Term Debt
   $ 1,049,000       $ 1,209,054       $ 1,249,000       $ 1,423,349


	December 31, 2011				September 30, 2011
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-Term Debt	$	1,399,000	$	1,536,798	$	1,049,000	$	1,198,585

-17-

Item 1.Financial Statements (Cont.)

The fair value amounts are not intended to reflect principal amounts that the Company will ultimately be required to pay. Carrying amounts for other financial instruments recorded on the Company’s Consolidated Balance Sheets approximate fair value.

Temporary cash investments, notes payable to banks and commercial paper are stated at cost, which approximates their fair value due to short-term maturities of those financial instruments.

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 $54.9 million and $54.8 million at ~~June~~December 31, 2011 and September 30, 2011, ~~and $55.4 million at September 30, 2010.~~respectively. The fair value of the equity mutual fund was ~~$22.0~~$21.7 million at ~~June 30,~~December 31, 2011 and ~~$17.3~~$19.9 million at September 30, ~~2010.~~2011. The gross unrealized gain on this equity mutual fund was ~~$1.5~~$0.3 million at ~~June 30,~~December 31, 2011. The gross unrealized ~~gain~~loss on the equity mutual fund was $0.7 million at September 30, ~~2010 was negligible as the fair value was approximately equal to the cost basis.~~2011. The fair value of the stock of an insurance company was ~~$7.0~~$4.2 million at ~~June 30,~~December 31, 2011 and ~~$5.0~~$4.5 million at September 30, ~~2010.~~2011. The gross unrealized gain on this stock was ~~$4.6~~$1.8 million at ~~June 30,~~December 31, 2011 and ~~$2.6~~$2.1 million at September 30, ~~2010.~~2011. The insurance contracts and marketable equity securities are primarily informal funding mechanisms for various benefit obligations the Company has to certain employees.

Derivative Financial ~~Instruments.~~Instruments

The Company ~~is exposed to certain risks relating to its ongoing business operations. The primary risk managed by using~~uses derivative instruments isto manage commodity price risk in the Exploration and Production and 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 majority of the Company’s hedges dodoes not typically exceed 3 years.

~~-18-~~

~~Item 1.Financial Statements (Cont.)~~

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

   Fair Values of Derivative Instruments

(Dollar Amounts in Thousands)

Asset Derivatives

Liability Derivatives
Derivatives
Designated as
Hedging
Instruments

Consolidated
Balance Sheet
Location

Fair Value

Consolidated
Balance Sheet
Location

Fair Value
Commodity
Contracts – at
June 30,
2011

Fair Value of
Derivative
Financial
Instruments
   $43,247    Fair Value of
Derivative
Financial
Instruments    $44,607
Commodity
Contracts – at
September 30,
2010

Fair Value of
Derivative
Financial
Instruments
   $65,184    Fair Value of
Derivative
Financial
Instruments    $20,160

Fair Values of Derivative Instruments

(Dollar Amounts in Thousands)

Asset Derivatives

Liability Derivatives

Derivatives

Designated as

Hedging

Instruments

Consolidated
Balance Sheet
Location

Fair Value

Consolidated
Balance Sheet
Location

Fair Value

Commodity Contracts – at December 31, 2011

Fair Value of
Derivative
Financial
Instruments

106,115

Fair Value of
Derivative
Financial
Instruments

48,210

Commodity Contracts – at September 30, 2011

Fair Value of
Derivative
Financial
Instruments

76,085

Fair Value of
Derivative
Financial
Instruments

9,674

-18-

Item 1.Financial Statements (Cont.)

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 ~~June 30,~~December 31, 2011 and September 30, ~~2010.~~2011.

   Fair Values of Derivative Instruments

(Dollar Amounts in Thousands)
Derivatives
Designated as
Hedging
Instruments

Gross Asset Derivatives

Gross Liability Derivatives


Fair Value

Fair Value
Commodity Contracts – at
June 30, 2011
   $54,971    $56,331
Commodity Contracts – at
September 30, 2010
   $77,837    $32,813


Derivatives Designated as Hedging	Fair Values of Derivative Instruments (Dollar Amounts in Thousands)
Instruments	Gross Asset Derivatives	Gross Liability Derivatives
Commodity Contracts – at December 31, 2011	$ 122,870	$ 64,965
Commodity Contracts – at September 30, 2011	$ 90,253	$ 23,842

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.

~~At June 30,~~As of December 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		~~73.7~~54.7 Bcf (all short positions)
Crude Oil		~~3,165,000~~2,331,000 Bbls (all short positions)

~~-19-~~

~~Item 1.Financial Statements (Cont.)~~

~~In conjunction with the sale~~As of the Company’s off-shore oil and natural gas properties in the Gulf of Mexico, the Company discontinued hedge accounting for the remaining derivative financial instruments that had been designated as hedges of Gulf of Mexico production. At June 30, 2011, natural gas derivative contracts totaling 0.4 Bcf were still outstanding. They were excluded from the table above since there is no forecasted sale associated with the hedged volume. Changes to the fair value of these natural gas derivative contracts, which mature in September 2011, are being reflected in the Consolidated Statement of Income.

~~At June 30,~~December 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		~~6.6~~8.3 Bcf ~~(5.3~~(5.7 Bcf short positions (forecasted storage withdrawals) and ~~1.3~~2.6 Bcf long positions (forecasted storage injections))

At June 30, 2011, the Company’s Pipeline and Storage segment had 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~~		~~1.5 Bcf (all short positions)~~

~~At June 30,~~As of December 31, 2011, the Company’s Exploration and Production segment had ~~$0.1~~$58.1 million ~~(less than $0.1~~($33.6 million after tax) of net hedging gains included in the accumulated other comprehensive income (loss) balance. It is expected that ~~$3.2~~$36.8 million ($~~1.8~~21.2 million after tax) of these gains will be reclassified into the Consolidated Statement of Income ~~(Loss)~~ within the next 12 months as the expected sales of the underlying commodities occur. ~~It is expected that $3.1 million ($1.7 million after tax) of losses will be reclassified into the Consolidated Statement of Income (loss) after 12 months.~~ 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~~for both the Exploration and Production and Energy Marketing ~~and Pipeline and Storage segments).~~segment.

~~At June 30,~~

-19-

Item 1.Financial Statements (Cont.)

As of December 31, 2011, the Company’s Energy Marketing segment had ~~$0.7~~$2.5 million ($~~0.5~~1.5 million after tax) of net hedging gains included in the accumulated other comprehensive income (loss) balance. It is expected that all of the ~~full amount~~gains 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~~for both the Exploration and Production and Energy Marketing ~~and Pipeline and Storage segments).~~segment.

At June 30, 2011, the Company’s Pipeline and Storage segment had less than $0.1 million 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 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).


The Effect of Derivative Financial Instruments on the Statement of Financial Performance for the Three Months Ended December 31, 2011 and 2010 (Thousands of Dollars)
Derivatives in Cash Flow Hedging Relationships	Amount of Derivative Gain or (Loss) Recognized in Other Comprehensive Income (Loss) on the Consolidated Statement of Comprehensive Income (Loss) (Effective Portion) for the Three Months Ended December 31,						Location of Derivative Gain or (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) on the Consolidated Balance Sheet into the Consolidated Statement of Income (Effective Portion)		Amount of Derivative Gain or (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) on the Consolidated Balance Sheet into the Consolidated Statement of Income (Effective Portion) for the Three Months Ended December 31,				Location of Derivative Gain or (Loss) Recognized in the Consolidated Statement of Income (Ineffective Portion and Amount Excluded from Effectiveness Testing)		Derivative Gain or (Loss) Recognized in the Consolidated Statement of Income (Ineffective Portion and Amount Excluded from Effectiveness Testing) for the Three Months Ended December 31,
	2011			2010					2011		2010				2011		2010
Commodity Contracts – Exploration & Production segment	$	(3,923	)	$	(26,781	)		Operating Revenue	$	5,420	$	9,007		Operating Revenue	$	—	$	—
Commodity Contracts – Energy Marketing segment	$	6,078		$	(269	)		Purchased Gas	$	6,444	$	46		Operating Revenue	$	—	$	—
Commodity Contracts – Pipeline & Storage segment	$	—		$	(86	)		Operating Revenue	$	—	$	—		Operating Revenue	$	—	$	—

Total	$	2,155		$	(27,136	)			$	11,864	$	9,053			$	—	$	—

-20-

~~Item 1.Financial Statements (Cont.)~~

The Effect of Derivative Financial Instruments on the Statement of Financial Performance for the
Three Months Ended June 30, 2011 and 2010 (Thousands of Dollars)

Derivatives in
Cash Flow
Hedging
Relationships
   Amount of
Derivative Gain or
(Loss) Recognized
in Other
Comprehensive
Income (Loss) on
the Consolidated
Statement of
Comprehensive
Income (Loss)
(Effective Portion)
for the Three
Months Ended
June 30, Location of
Derivative Gain
or (Loss)
Reclassified
from
Accumulated
Other
Comprehensive
Income (Loss)
on the
Consolidated
Balance Sheet
into the
Consolidated
Statement of
Income
(Effective
Portion)    Amount of Derivative
Gain or (Loss)
Reclassified from
Accumulated Other
Comprehensive
Income (Loss) on the
Consolidated Balance
Sheet into the
Consolidated
Statement of Income
(Effective Portion)
for the Three
Months Ended
June 30,    Location of
Derivative Gain
or (Loss)
Recognized in
the
Consolidated
Statement of
Income
(Ineffective
Portion and
Amount
Excluded from
Effectiveness
Testing)    Derivative Gain or
(Loss) Recognized
in the Consolidated
Statement of
Income (Ineffective
Portion and Amount
Excluded from
Effectiveness
Testing) for the
Three Months
Ended
June 30,
   2011    2010    2011 2010       2011    2010
Commodity
Contracts –
Exploration &
Production
segment
   $ 25,399       $ 16,445    Operating
Revenue
   $ (5,548 ) $ 11,592       Operating
Revenue
   $ 570       $ —
Commodity
Contracts –
Energy
Marketing
segment
   $ 737       $ 519    Purchased
Gas    $ 1,793    $ 238       Purchased Gas    $ —         $ —
Commodity
Contracts –
Pipeline &
Storage
segment
   $ 242       $ (436 ) Operating
Revenue
   $ —      $ —         Operating
Revenue
   $ —         $ —
Total    $ 26,378       $ 16,528       $ (3,755 ) $ 11,830          $ 570       $ —

~~-21-~~

~~Item 1.Financial Statements (Cont.)~~

The Effect of Derivative Financial Instruments on the Statement of Financial Performance for the
Nine Months Ended June 30, 2011 and 2010 (Thousands of Dollars)

Derivatives in
Cash Flow
Hedging
Relationships
   Amount of
Derivative Gain or
(Loss) Recognized
in Other
Comprehensive
Income (Loss) on
the Consolidated
Statement of
Comprehensive
Income (Loss)
(Effective Portion)
for the Nine
Months Ended
June 30,    Location of
Derivative Gain
or (Loss)
Reclassified
from
Accumulated
Other
Comprehensive
Income (Loss)
on the
Consolidated
Balance Sheet
into the
Consolidated
Statement of
Income
(Effective
Portion)    Amount of Derivative
Gain or (Loss)
Reclassified from
Accumulated Other
Comprehensive
Income (Loss) on the
Consolidated Balance
Sheet into the
Consolidated
Statement of Income
(Effective Portion)
for the Nine
Months Ended
June 30, Location of
Derivative Gain
or (Loss)
Recognized in
the
Consolidated
Statement of
Income
(Ineffective
Portion and
Amount
Excluded from
Effectiveness
Testing)    Derivative Gain or
(Loss) Recognized
in the Consolidated
Statement of
Income (Ineffective
Portion and Amount
Excluded from
Effectiveness
Testing) for the Nine
Months Ended
June 30,
   2011 2010       2011    2010    2011    2010
Commodity
Contracts –
Exploration &
Production
segment
   $ (42,969 ) $ 32,910       Operating
Revenue    $ 5,415       $ 29,170    Operating
Revenue    $ 570       $ —
Commodity
Contracts –
Energy
Marketing
segment
   $ 1,340    $ 5,821       Purchased Gas    $ 7,095       $ (209 ) Purchased Gas    $ —         $ —
Commodity
Contracts –
Pipeline &
Storage
segment
   $ 27    $ 577       Operating
Revenue    $ —         $ 511    Operating
Revenue    $ —         $ —
Total    $ (41,602 ) $ 39,308          $ 12,510       $ 29,472       $ 570       $ —

~~-22-~~

Item 1.Financial Statements (Cont.)

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 ~~June 30,~~December 31, 2011, the Company’s Energy Marketing segment had fair value hedges covering approximately ~~10.5~~10.6 Bcf ~~(7.4~~(8.8 Bcf of fixed price sales commitments (all long positions) and ~~3.1~~1.8 Bcf of fixed price purchase commitments (all short positions)). For derivative instruments that are designated and qualify 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
   $ 9,531,151    $ (9,531,151 )
Purchased Gas
   $ (941,391 ) $ 941,391

Derivatives in
Fair Value Hedging
Relationships
   Location of Derivative Gain or (Loss)
Recognized in the Consolidated
Statement of Income    Amount of Derivative Gain or (Loss)
Recognized in the Consolidated
Statement of Income for the Nine
Months Ended June 30, 2011
(In Thousands)
Commodity Contracts – Energy
Marketing segment⁽¹⁾
   Operating Revenues    $ 9,531
Commodity Contracts – Energy
Marketing segment⁽²⁾
   Purchased Gas    $ (638 )
Commodity Contracts – Energy
Marketing segment⁽³⁾
   Purchased Gas    $ (303 )


      $ 8,590


Consolidated Statement of Income	Gain/(Loss) on Derivative	Gain/(Loss) on Commitment
Operating Revenues	$(625,482)	$625,482
Purchased Gas	$1,076,443	$(1,076,443)

⁽¹⁾Derivatives in

Fair Value Hedging Relationships – Energy
Marketing segment

~~Represents hedging~~Location of Derivative

Gain or (Loss)

Recognized in the

Consolidated Statement

of Income

Amount of Derivative Gain or (Loss)

Recognized in the Consolidated

Statement of Income

for the Three Months Ended

December 31, 2011

(In thousands)

Commodity Contracts — Hedge of fixed price sales commitments of natural ~~gas.~~gas

Operating Revenues

$ (625)

⁽²⁾	~~Represents hedging~~Commodity Contracts — Hedge of fixed price purchase commitments of natural ~~gas.~~gas		Purchased Gas		$ 1,076

				⁽³⁾$ 451
				~~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 eleven counterparties of which ~~nine~~ten are in a net gain position. ~~The Company had derivative financial instruments that were in loss positions with the other two counterparties.~~ On average, the Company had ~~$4.7~~$10.5 million of credit exposure per counterparty in a gain position at ~~June 30,~~December 31, 2011. The maximum credit exposure per counterparty in a gain position at ~~June 30,~~December 31, 2011 was ~~$8.0~~$19.2 million. The Company had not received any collateral from these counterparties at ~~June 30,~~December 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, nor had the counterparties’ credit ratings declined to levels at which the counterparties were required to post collateral.

~~-23-~~

~~Item 1.Financial Statements (Cont.)~~

As of ~~June 30,~~December 31, 2011, eight of the eleven 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

-21-

Item 1.Financial Statements (Cont.)

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~~may be required. At ~~June 30,~~December 31, 2011, the fair market value of the derivative financial instrument assets with a credit-risk related contingency feature was ~~$24.6~~$70.9 million according to the Company’s internal model (discussed in Note 2 –— Fair Value Measurements). At ~~June 30,~~December 31, 2011, the fair market value of the derivative financial instrument liabilities with a credit-risk related contingency feature was ~~$41.6~~$44.7 million according to the Company’s internal model (discussed in Note 2 –— Fair Value Measurements). ~~The liability with one counterparty was $40.3 million.~~ For its over-the-counter crude oil swap agreements, which are in a liability position, the Company was required to post ~~$32.4~~$20.6 million in hedging collateral deposits at ~~June 30,~~December 31, 2011. This is discussed in Note 1 under Hedging Collateral Deposits.

For its exchange traded futures contracts ~~the majority of~~ which are in a liability position, the Company had posted ~~$5.6~~$4.5 million in hedging collateral as of ~~June 30,~~December 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 –~~ 4—Income Taxes

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


	Nine Months Ended						Three Months Ended
	June 30,						December 31,
	2011			2010			2011			2010
Current Income Taxes
Federal	$	(1,825	)	$	42,323		$	(7	)	$	—
State		2,703			9,914			1,334			1,452

Deferred Income Taxes
Federal		112,385			50,079			31,338			29,936
State		27,941			13,734			8,060			6,664

		141,204			116,050			40,725			38,052
Deferred Investment Tax Credit		(523	)		(523	)		(145	)		(174	)

Total Income Taxes	$	140,681		$	115,527		$	40,580		$	37,878

Presented as Follows:
Other Income	$	(523	)	$	(523	)	$	(145	)	$	(174	)
Income Tax Expense – Continuing Operations		141,204			115,449
Income from Discontinued Operations		—			601
Income Tax Expense								40,725			38,052

Total Income Taxes	$	140,681		$	115,527		$	40,580		$	37,878

~~-24-~~-22-

Item 1.Financial Statements (Cont.)

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


	Nine Months Ended						Three Months Ended
	June 30,						December 31,
	2011			2010			2011			2010
U.S. Income Before Income Taxes	$	361,726		$	303,039		$	101,279		$	96,421

Income Tax Expense, Computed at Federal Statutory Rate of 35%	$	126,604		$	106,064
Income Tax Expense, Computed at U.S. Federal Statutory Rate of 35%							$	35,448		$	33,747

Increase (Reduction) in Taxes Resulting from:
State Income Taxes		19,919			15,371			6,106			5,275
Miscellaneous		(5,842	)		(5,908	)		(974	)		(1,144	)

Total Income Taxes	$	140,681		$	115,527		$	40,580		$	37,878

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


	At June 30, 2011			At September 30, 2010			At December 31, 2011			At September 30, 2011
Deferred Tax Liabilities:
Property, Plant and Equipment	$	1,035,695		$	849,869		$	1,116,690		$	1,062,255
Pension and Other Post-Retirement Benefit Costs		183,651			177,853			213,170			217,302
Other		38,958			63,671			67,876			70,389

Total Deferred Tax Liabilities		1,258,304			1,091,393			1,397,736			1,349,946

Deferred Tax Assets:
Pension and Other Post-Retirement Benefit Costs		(227,458	)		(223,588	)		(262,571	)		(263,606	)
Tax Loss Carryforwards		(54,472	)		(9,772	)		(83,199	)		(71,516	)
Other		(80,114	)		(81,751	)		(75,082	)		(74,863	)

Total Deferred Tax Assets		(362,044	)		(315,111	)		(420,852	)		(409,985	)

Total Net Deferred Income Taxes	$	896,260		$	776,282		$	976,884		$	939,961

Presented as Follows:
Net Deferred Tax Liability/(Asset) – Current	$	(22,885	)	$	(24,476	)	$	(14,921	)	$	(15,423	)
Net Deferred Tax Liability – Non-Current		919,145			800,758			991,805			955,384

Total Net Deferred Income Taxes	$	896,260		$	776,282		$	976,884		$	939,961

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 June 30, 2011~~ that arose directly from excess tax deductions related to stock-based compensation. ~~A tax benefit~~Tax benefits of $14.2 million and $18.1 million for the periods ending December 31, 2011 and September 30, 2011, respectively, relating to the excess stock-based compensation deductions will be recorded in Paid in Capital in future years when such tax ~~benefit is~~benefits are realized.

-23-

Item 1.Financial Statements (Cont.)

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 ~~$70.3 million and $69.6~~$65.5 million at ~~June 30,~~December 31, 2011 and September 30, ~~2010, respectively.~~2011. 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 ~~$151.1~~$145.5 million and ~~$149.7~~$144.4 million at ~~June 30,~~December 31, 2011 and September 30, ~~2010,~~2011, respectively.

~~-25-~~

~~Item 1.Financial Statements (Cont.)~~

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 2008 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~~Local IRS examiners proposed to disallow most of the tax accounting method change recorded by the Company in fiscal ~~2009.~~2009 and fiscal 2010. The Company has filed ~~a protest~~protests 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~~principal subsidiaries operate 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.

Note ~~5 –~~ 5—Capitalization

Common Stock.During the ~~nine~~three months ended ~~June 30,~~December 31, 2011, the Company issued ~~1,044,970~~272,292 original issue shares of common stock as a result of stock option ~~and SARs~~ exercises and ~~47,250~~41,525 original issue shares for restricted stock awards (non-vested stock as defined by the current accounting literature for stock-based compensation). In addition, the Company issued ~~24,499~~31,474 original issue shares of common stock for the Direct Stock Purchase and Dividend Reinvestment Plan. The Company also issued ~~11,250~~4,050 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 ~~nine~~three months ended ~~June 30,~~December 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 ~~nine~~three months ended ~~June 30,~~December 31, 2011, ~~503,262~~123,533 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. There was no Current Portion of Long-Term Debt at ~~June 30, 2011 consists of $150 million of 6.70% medium-term notes that mature in November~~December 31, 2011. Current Portion of Long-Term Debt at September 30, ~~2010~~2011 consisted of ~~$200~~$150 million of ~~7.50%~~6.70% notes that matured in November ~~2010.~~2011.

Long-Term Debt.On December 1, 2011, the Company issued $500.0 million of 4.90% notes due December 1, 2021. After deducting underwriting discounts and commissions, the net proceeds to the Company amounted to $496.1 million. The holders of the notes may require the Company to repurchase their notes at a price equal to 101% of the principal amount in the event of a change in control and a ratings downgrade to a rating below investment grade. The proceeds of this debt issuance were used for general corporate purposes, including refinancing short-term debt that was used to pay the $150 million due at the maturity of the Company’s 6.70% notes in November 2011.

-24-

Item 1.Financial Statements (Cont.)

Note ~~6 –~~ 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~~In February 2009, the Company ~~has~~ received approval from the NYDEC of a Remedial Design work plan (RDWP) for this ~~site and has recorded an~~site. In October 2010, the Company submitted a RDWP addendum to conduct additional Preliminary Design Investigation field activities necessary to design a successful remediation. An estimated minimum liability for remediation of this site of ~~$14.5 million.~~$14.3 million has been recorded.

At ~~June 30,~~December 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 ~~$17.2~~$16.0 million to ~~$21.4~~$20.2 million. The minimum estimated liability of ~~$17.2~~$16.0 million, which includes the ~~$14.5~~$14.3 million discussed above, has been recorded on the Consolidated Balance Sheet at ~~June 30,~~December 31, 2011. The Company expects to recover its environmental clean-up costs through rate recovery.

~~-26-~~

~~Item 1.Financial Statements (Cont.)~~

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.

~~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:~~

(Thousands)    Three Months Ended
June 30,
2010 Nine Months Ended
June 30,
2010
Operating Revenues
   $ 2,135    $ 8,411
Operating Expenses
   2,177    7,021


Operating Income (Loss)
   (42 ) 1,390
Interest Income
   1    1
Other Interest Expense
   (8 ) (19 )


Income (Loss) before Income Taxes
   (49 ) 1,372
Income Tax Expense
   8    601


Income (Loss) from Discontinued Operations
   $ (57 ) $ 771

Note 87 – 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~~2011 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~~2011 Form 10-K. As for segment assets, the only significant changes from the segment assets disclosed in the ~~2010~~2011 Form 10-K involve the Exploration and Production segment as well as Corporate and Intersegment Eliminations. Total Exploration and Production segment assets have increased by ~~$184.6~~$216.6 million while Corporate and Intersegment Eliminations assets have ~~decreased~~increased by ~~$163.3~~$204.6 million.

~~-27-~~

~~Item 1.Financial Statements (Cont.)~~

Quarter Ended June 30, 2011 (Thousands)
   Utility    Pipeline
and
Storage    Exploration
and
Production    Energy
Marketing    Total
Reportable
Segments    All Other    Corporate and
Intersegment
Eliminations Total
Consolidated
Revenue from External Customers
   $ 146,215       $ 29,933       $ 130,974       $ 71,746       $ 378,868       $ 1,873       $ 238    $ 380,979
Intersegment Revenues
   $ 3,475       $ 20,324       $ —         $ 156       $ 23,955       $ 2,810       $ (26,765 ) $ —
Segment Profit:

Net Income (Loss)
   $ 6,328       $ 4,503       $ 32,784       $ 1,891       $ 45,506       $ 2,713       $ (1,328 ) $ 46,891
Nine Months Ended June 30, 2011 (Thousands)
   Utility    Pipeline
and
Storage    Exploration
and
Production    Energy
Marketing    Total
Reportable
Segments    All Other    Corporate and
Intersegment
Eliminations Total
Consolidated
Revenue from External Customers
   $ 750,802       $ 103,115       $ 388,571       $ 246,719       $ 1,489,207       $ 2,895       $ 706    $ 1,492,808
Intersegment Revenues
   $ 14,680       $ 60,838       $ —         $ 156       $ 75,674       $ 7,026       $ (82,700 ) $ —
Segment Profit:

Net Income (Loss)
   $ 62,399       $ 24,036       $ 93,455       $ 9,122       $ 189,012       $ 34,320       $ (2,287 ) $ 221,045
Quarter Ended June 30, 2010 (Thousands)
   Utility    Pipeline
and
Storage    Exploration
and
Production    Energy
Marketing    Total
Reportable
Segments    All Other    Corporate and
Intersegment
Eliminations Total
Consolidated
Revenue from External Customers
   $ 126,326       $ 32,086       $ 112,802       $ 72,830       $ 344,044       $ 7,724       $ 224    $ 351,992
Intersegment Revenues
   $ 2,653       $ 19,466       $ —         $ —         $ 22,119       $ 1,418       $ (23,537 ) $ —
Segment Profit:

Income (Loss) from Continuing Operations
   $ 5,969       $ 7,234       $ 27,883       $ 1,411       $ 42,497       $ 243       $ (98 ) $ 42,642
Nine Months Ended June 30, 2010 (Thousands)
   Utility    Pipeline
and
Storage    Exploration
and
Production    Energy
Marketing    Total
Reportable
Segments    All Other    Corporate and
Intersegment
Eliminations Total
Consolidated
Revenue from External Customers
   $ 707,323       $ 107,560       $ 328,312       $ 303,103       $ 1,446,298       $ 27,157       $ 652    $ 1,474,107
Intersegment Revenues
   $ 13,315       $ 60,289       $ —         $ —         $ 73,604       $ 1,418       $ (75,022 ) $ —
Segment Profit:

Income (Loss) from Continuing Operations
   $ 62,254       $ 30,036       $ 85,046       $ 8,472       $ 185,808       $ 2,154       $ (1,221 ) $ 186,741

~~-28-~~-25-

Item 1.Financial Statements (Cont.)

~~Note 9 – Investments in Unconsolidated Subsidiaries~~

At June 30, 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~~Quarter Ended December 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.

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

   At June 30, 2011    At September 30, 2010
Seneca Energy
   $ —         $ 11,007
Model City
   —         2,017
ESNE
   1,367       1,804




   $ 1,367       $ 14,828


	Utility		Pipeline and Storage		Exploration and Production		Energy Marketing		Total Reportable Segments		All Other		Corporate and Intersegment Eliminations			Total Consolidated
Revenue from External Customers	$	208,810	$	35,225	$	135,974	$	51,222	$	431,231	$	937	$	255		$	432,423
Intersegment Revenues	$	4,389	$	21,064	$	—	$	287	$	25,740	$	3,362	$	(29,102	)	$	—
Segment Profit:

Net Income (Loss)	$	19,353	$	9,959	$	30,315	$	429	$	60,056	$	1,404	$	(761	)	$	60,699

Quarter Ended December 31, 2010 (Thousands)


	Utility		Pipeline and Storage		Exploration and Production		Energy Marketing		Total Reportable Segments		All Other			Corporate and Intersegment Eliminations			Total Consolidated
Revenue from External Customers	$	242,842	$	33,513	$	120,168	$	53,652	$	450,175	$	549		$	224		$	450,948
Intersegment Revenues	$	4,570	$	19,882	$	—	$	—	$	24,452	$	1,678		$	(26,130	)	$	—
Segment Profit:

Net Income (Loss)	$	22,990	$	8,578	$	27,373	$	932	$	59,873	$	(574	)	$	(756	)	$	58,543

Note 108 – Retirement Plan and Other Post-Retirement Benefits

Components of Net Periodic Benefit Cost (in thousands):


Three months ended June 30,
	Retirement Plan						Other Post-Retirement Benefits
	2011			2010			2011			2010			Retirement Plan						Other Post-Retirement Benefits
Three months ended December 31,													2011			2010			2011			2010
Service Cost	$	3,693		$	3,249		$	1,069		$	1,075		$	3,551		$	3,693		$	1,004		$	1,069
Interest Cost		10,669			11,077			5,471			6,254			10,381			10,669			5,329			5,471
Expected Return on Plan Assets		(14,776	)		(14,585	)		(7,291	)		(6,583	)		(14,925	)		(14,776	)		(7,243	)		(7,291	)
Amortization of Prior Service Cost		147			164			(427	)		(427	)		67			147			(534	)		(427	)
Amortization of Transition Amount		—			—			135			135			—			—			3			135
Amortization of Losses		8,718			5,410			5,948			6,470			9,904			8,718			6,014			5,948
Net Amortization and Deferral for Regulatory Purposes (Including Volumetric Adjustments)⁽¹⁾		(2,346	)		(920	)		1,602			(569	)
Net Amortization and Deferral
For Regulatory Purposes (Including Volumetric Adjustments)⁽¹⁾														(1,802	)		(1,793	)		2,132			1,921

Net Periodic Benefit Cost	$	6,105		$	4,395		$	6,507		$	6,355		$	7,176		$	6,658		$	6,705		$	6,826

~~-29-~~

~~Item 1.Financial Statements (Cont.)~~

Nine months ended June 30,

   Retirement Plan Other Post-Retirement Benefits
   2011 2010 2011 2010
Service Cost
   $ 11,079    $ 9,747    $ 3,207    $ 3,224
Interest Cost
   32,007    33,231    16,413    18,763
Expected Return on Plan Assets
   (44,328 ) (43,756 ) (21,873 ) (19,751 )
Amortization of Prior Service Cost
   441    492    (1,282 ) (1,282 )
Amortization of Transition Amount
   —      —      405    405
Amortization of Losses
   26,155    16,230    17,845    19,411
Net Amortization and Deferral for Regulatory Purposes (Including Volumetric Adjustments)⁽¹⁾
   (584 ) 2,896    9,564    2,919


Net Periodic Benefit Cost
   $ 24,770    $ 18,840    $ 24,279    $ 23,689

⁽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.

-26-

Item 1.Financial Statements (Concl.)

Employer Contributions.During the ~~nine~~three months ended ~~June 30,~~December 31, 2011, the Company contributed ~~$40.0~~$22.5 million to its tax-qualified, noncontributory defined-benefit retirement plan (Retirement Plan) and ~~$18.9~~$5.2 million to its VEBA trusts and 401(h) accounts for its other post-retirement benefits. In the remainder of ~~2011~~2012, the Company expects to contribute between ~~$8.0~~$16.0 and ~~$9.0~~$27.0 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~~2012 in order to be in compliance with the Pension Protection Act of 2006. In the remainder of ~~2011~~2012, the Company expects to contribute between ~~$1.0~~$14.0 and ~~$6.5~~$15.0 million to its VEBA trusts and 401(h) accounts.

~~-30-~~-27-

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 ~~June 30,~~December 31, 2011 compared to the quarter ended ~~June 30,~~December 31, 2010, the Company experienced an increase in earnings of ~~$4.3 million. The earnings increase for the quarter is~~$2.2 million, primarily due to higher earnings in the Exploration and Production segment and the ~~All Other category partially offset by lower earnings in the~~ Pipeline &and Storage segment, and the Corporate category. For the nine months ended June 30, 2011 compared to the nine months ended June 30, 2010, the Company experienced an increase in earnings of $33.5 million. The earnings increase for the nine-month period 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 quarter ended March 31, 2011as well as in the All Other category. ~~In February 2011,~~Lower earnings in the ~~Company sold its 50% equity method investments in Seneca~~Utility and 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~~Marketing segments partly offset these increases. For further discussion of the Company’s ~~strategy~~earnings, refer to ~~pursue~~ the ~~sale~~Results 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.~~Operations section below.

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 the natural gas interests associated with approximately 745,000 net acres within the Marcellus Shale area, ~~of Pennsylvania,~~ with a majority of the ~~acreage~~interests 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.~~2010 to 607 Bcf at September 30, 2011. 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 ~~nine months~~quarter ended ~~June 30,~~December 31, 2011, the Company spent ~~$433.5~~$172.0 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. The Company also eliminated the asset retirement obligation associated with its off-shore oil and gas properties. This obligation amounted to $37.5 million and was accounted for as a reduction of capitalized costs under the full cost method of accounting for oil and natural gas properties as well as a reduction of the asset retirement obligation. 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.

~~-31-~~

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

In September, 2010, the Company engaged Jefferies & Company (“Jefferies”) to explore joint-venture opportunities across its Marcellus Shale acreage in its Exploration and Production segment. At that time, the Company believed that a joint-venture could allow the Company to enhance shareholder value by shifting a significant portion of the early drilling costs for shale wells to a noncontrolling-interest partner while still allowing the Company to continue operating across most of its acreage. The Company and Jefferies established a data room to highlight the value of the Company’s position in the Marcellus Shale, and invited qualified parties to review the information in contemplation of entering into a joint venture. The Company has had discussions with many of the parties that have visited the data room and has received some offers. However, the Company has decided not to pursue these offers. Throughout this process, the Company has continued its drilling operations in the Marcellus Shale and has achieved favorable results. Since a majority of the Company’s acreage is held in fee, carrying no royalty and no lease expirations, and large, contiguous acreage blocks allow for operating- and cost-efficiency through multi-well pad drilling, the Company is not forced to take extraordinary steps to maintain its mineral acreage. The Company will forgo any joint-venture opportunities that do not enhance shareholder value when compared to the growth that it could expect to achieve without a joint venture partner. While discussions with certain potential partners continue, at this time it is likely that the Company will develop its Marcellus Shale acreage on its own.

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,~~One such project, Empire’s Tioga County Extension Project, was placed in service in November 2011. Supply Corporation’s planned Northern Access expansion project is also considered significant. Just like the Tioga County Extension Project, ~~and the Northern Access expansion project, are considered significant for Empire and Supply Corporation. Both projects are~~it is 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,~~two years, 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~~Empire’s Tioga County Extension Project is currently providing one such alternative transportation route and ~~the~~Supply Corporation’s Northern Access expansion project ~~are~~is designed to provide ananother alternative ~~gas supply source for the customers of Empire and Supply Corporation.~~transportation route. These projects, which are discussed more completely in the Investing Cash Flow section that follows, have or will involve significant capital expenditures.

From a capital resources perspective, the Company has largely 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 $184.7 million in Cash and Temporary Cash Investments at June 30, 2011, as shown on~~operations. In addition, the Company’s ~~Consolidated Balance Sheet. For the remainder~~December 2011 issuance of ~~fiscal 2011,~~$500.0 million of 4.90% notes due in December 2021 has enhanced its liquidity position to meet these needs. On January 6, 2012, the Company ~~expects~~entered into an Amended and Restated Credit Agreement that ~~it will be able~~replaces the Company’s $300.0 million committed credit facility with a similar committed credit facility totaling $750.0 million that extends to ~~use cash on hand, cash from operations,~~January 6, 2017.

-28-

Item 2.Management’s Discussion and ~~cash from asset sales as its first means~~Analysis of ~~financing capital expenditures, with short-term borrowings~~Financial Condition and ~~long-term borrowings being its next sources~~Results 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.~~Operations (Cont.)

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 had a moratorium in place that prevented hydraulic fracturing of new horizontal wells in the Marcellus Shale. The moratorium ended in July 2011 and the DEC has issued its recommendations for shale development and production. However, the recommendations have not gone into effect ~~since they are subject~~ to ~~a 60-day public comment period that is anticipated to begin sometime in August 2011.~~date. Due to the small amount of Marcellus Shale acreage owned by the Company in New York State, the final outcome of the

~~-32-~~

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

DEC’s recommendations are 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~~2011 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 and March 31,~~ 2011 Form ~~10-Qs.~~10-K. There have been no material changes to ~~those disclosures~~that disclosure 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.~~that Form 10-K.

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 ~~June 30,~~December 31, 2011, the ceiling exceeded the book value of the oil and gas properties by approximately ~~$289~~$360.3 million. The 12-month average of the first day of the month price for crude oil for each month during the twelve months ended ~~June 30,~~December 31, 2011, based on posted ~~Midway-Sunset~~Midway Sunset prices was ~~$87.63~~$103.62 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 ~~June 30,~~December 31, 2011, based on the quoted Henry Hub spot price for natural gas, was ~~$4.21~~$4.12 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~~Midway Sunset and Henry Hub prices, which are only indicative of 12-month average prices for the twelve months ended ~~June 30,~~December 31, 2011.) If natural gas average prices used in the ceiling test calculation at ~~June 30,~~December 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 ~~$157~~$187.9 million. If crude oil average prices used in the ceiling test calculation at ~~June 30,~~December 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 ~~$247~~$315.3 million. If both natural gas and crude oil average prices used in the ceiling test calculation at ~~June 30,~~December 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 ~~$116~~$142.9 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~~2011 Form 10-K.

~~Accounting for Derivative Financial Instruments~~. The Company, in its Exploration and Production segment, Energy Marketing segment, and Pipeline and Storage segment, uses a variety of derivative financial instruments to manage a portion of the market risk associated with fluctuations in the price of natural gas and crude oil. These instruments are categorized as price swap agreements and futures contracts. In accordance with the authoritative guidance for derivative instruments and hedging activities, the Company accounted for these instruments as effective cash flow hedges or fair value hedges. Gains or losses associated with the derivative financial instruments are matched with gains or losses resulting from the underlying physical transaction that is being hedged. To the extent that the derivative financial instruments would ever be deemed to be ineffective based on the effectiveness testing, mark-to-market gains or losses from the derivative financial instruments would be recognized in the income statement without regard to an underlying physical transaction. In April 2011, the Company completed the sale of its off-shore oil and natural gas properties in the Gulf of Mexico and discontinued hedge accounting for the remaining derivative financial instruments that had been designated as hedges of the Gulf of Mexico production. Accordingly, $0.6 million of unrealized gains associated with such derivative financial instruments was reclassified from accumulated other comprehensive income to the income statement in April 2011.

~~-33-~~-29-

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

The Company uses both exchange-traded and non exchange-traded derivative financial instruments. The Company adopted the authoritative guidance for fair value measurements during the quarter ended December 31, 2008. As such, the fair value of such derivative financial instruments is determined under the provisions of this guidance. The fair value of exchange traded derivative financial instruments is determined from Level 1 inputs, which are quoted prices in active markets. The Company determines the fair value of non exchange-traded derivative financial instruments based on an internal model, which uses both observable and unobservable inputs other than quoted prices. These inputs are considered Level 2 or Level 3 inputs. All derivative financial instrument assets and liabilities are evaluated for the probability of default by either the counterparty or the Company. Credit reserves are applied against the fair values of such assets or liabilities. Refer to the “Market Risk Sensitive Instruments” section below for further discussion of the Company’s derivative financial instruments.

RESULTS OF OPERATIONS

Earnings

The Company’s earnings were ~~$46.9~~$60.7 million for the quarter ended ~~June 30,~~December 31, 2011 compared towith earnings of ~~$42.6~~$58.5 million for the quarter ended ~~June 30,~~December 31, 2010. The increase in earnings of ~~$4.3~~$2.2 million is primarily a result of higher earnings in the Exploration and Production segment, the Pipeline and Storage segment and the All Other category. Lower earnings in the ~~Pipeline~~Utility and ~~Storage segment and the Corporate category slightly~~Energy Marketing segments partially offset these increases. 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. Discontinued operations did not have a material impact on quarterly earnings, as shown in the table below.

The Company’s earnings were $221.0 million for the nine months ended June 30, 2011 compared to earnings of $187.5 million for the nine months ended June 30, 2010. The Company’s earnings from continuing operations were $221.0 million for the nine months ended June 30, 2011 compared with $186.7 million for the nine months ended June 30, 2010. The increase in earnings from continuing operations of $34.3 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 and the Corporate category slightly offset these increases. The Company’s earnings for the nine months ended June 30, 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.

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									Nine Months Ended
	June 30,									June 30,
(Thousands)	2011			2010			Increase (Decrease)			2011			2010			Increase (Decrease)
Three Months Ended December 31 (Thousands)																			2011			2010			Increase (Decrease)
Utility	$	6,328		$	5,969		$	359		$	62,399		$	62,254		$	145		$	19,353		$	22,990		$	(3,637	)
Pipeline and Storage		4,503			7,234			(2,731	)		24,036			30,036			(6,000	)		9,959			8,578			1,381
Exploration and Production		32,784			27,883			4,901			93,455			85,046			8,409			30,315			27,373			2,942
Energy Marketing		1,891			1,411			480			9,122			8,472			650			429			932			(503	)

Total Reportable Segments		45,506			42,497			3,009			189,012			185,808			3,204			60,056			59,873			183
All Other		2,713			243			2,470			34,320			2,154			32,166			1,404			(574	)		1,978
Corporate		(1,328	)		(98	)		(1,230	)		(2,287	)		(1,221	)		(1,066	)		(761	)		(756	)		(5	)

Total Earnings from Continuing Operations		46,891			42,642			4,249			221,045			186,741			34,304

Earnings (Loss) from Discontinued Operations		—			(57	)		57			—			771			(771	)

Total Consolidated	$	46,891		$	42,585		$	4,306		$	221,045		$	187,512		$	33,533		$	60,699		$	58,543		$	2,156

Utility

Utility Operating Revenues


Three Months Ended December 31(Thousands)	2011		2010		Increase (Decrease)
Retail Sales Revenues:
Residential	$	148,263	$	177,189	$	(28,926	)
Commercial		17,645		22,545		(4,900	)
Industrial		1,022		1,244		(222	)

		166,930		200,978		(34,048	)

Transportation		34,965		35,412		(447	)
Off-System Sales		9,145		8,889		256
Other		2,159		2,133		26

	$	213,199	$	247,412	$	(34,213	)

Utility Throughput


Three Months Ended December 31(MMcf)	2011		2010		Increase (Decrease)
Retail Sales:
Residential		14,549		17,160		(2,611	)
Commercial		1,994		2,469		(475	)
Industrial		101		146		(45	)

		16,644		19,775		(3,131	)

Transportation		16,928		18,110		(1,182	)
Off-System Sales		2,745		1,863		882

		36,317		39,748		(3,431	)

~~-34-~~-30-

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

~~Utility~~

~~Utility Operating Revenues~~

   Three Months Ended
June 30, Nine Months Ended
June 30,
(Thousands)
   2011    2010    Increase
(Decrease) 2011    2010    Increase
(Decrease)
Retail Sales Revenues:

Residential
   $ 105,001       $ 88,158       $ 16,843    $ 545,786       $ 521,202       $ 24,584
Commercial
   12,474       10,721       1,753    73,833       73,438       395
Industrial
   807       696       111    4,951       4,579       372










   118,282       99,575       18,707    624,570       599,219       25,351










Transportation
   25,016       20,909       4,107    105,380       92,112       13,268
Off-System Sales
   3,976       5,486       (1,510 ) 29,564       20,491       9,073
Other
   2,416       3,009       (593 ) 5,968       8,816       (2,848 )










   $ 149,690       $ 128,979       $ 20,711    $ 765,482       $ 720,638       $ 44,844










Utility Throughput
   Three Months Ended
June 30, Nine Months Ended
June 30,
(MMcf)
   2011    2010    Increase
(Decrease) 2011    2010    Increase
Retail Sales:

Residential
   8,867       7,055       1,812    54,075       50,292       3,783
Commercial
   1,203       920       283    8,044       7,666       378
Industrial
   79       66       13    618       512       106










   10,149       8,041       2,108    62,737       58,470       4,267










Transportation
   12,335       10,530       1,805    57,916       51,957       5,959
Off-System Sales
   867       1,124       (257 ) 6,188       4,034       2,154










   23,351       19,695       3,656    126,841       114,461       12,380

Degree Days


							Percent Colder
							(Warmer) Than
	Normal		2011		2010		Normal ⁽¹⁾			Prior Year ⁽¹⁾
Three Months Ended June 30
Three Months Ended December 31																		Percent Colder (Warmer) Than
Three Months Ended December 31												Normal		2011		2010		Normal⁽¹⁾			Prior Year⁽¹⁾
Buffalo		927		848		665		(8.5	)		27.5		2,260		1,848		2,332		(18.2	)		(20.8	)
Erie		885		812		631		(8.2	)		28.7		2,081		1,721		2,160		(17.3	)		(20.3	)
Nine Months Ended June 30
Buffalo		6,514		6,674		6,152		2.5			8.5
Erie		6,108		6,284		5,842		2.9			7.6

⁽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 $20.7~~decreased $34.2 million for the quarter ended ~~June 30,~~December 31, 2011 as compared with the quarter ended ~~June 30,~~December 31, 2010. This ~~increase~~decrease largely resulted from ~~an $18.7~~a $34.0 million ~~increase~~decrease in retail gas sales revenues. The decrease in retail gas sales revenues and a $4.1 million increase in transportation revenues. These increases were partially offset by a $1.5 million decrease in off-system sales revenues and a $0.6 million decrease in other operating revenues. The increase in retail gas sales revenues of $18.7 million was ~~largely a function of higher volumes (2.1 Bcf)~~primarily due to ~~colder~~warmer 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 incombined with the recovery of ~~a larger amount of~~lower gas costs ~~despite a decline in the Utility segment’s average cost of purchased gas. The~~

~~-35-~~

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

Utility segment’s average cost of purchased gas, including the cost of transportation and storage, was $6.43 per Mcf for the three months ended June 30, 2011, a decrease of 4.0% from the average cost of $6.70 per Mcf for the three months ended June 30, 2010. Subject(subject to certain timing variations, gas costs are recovered dollar for dollar in ~~revenues.~~revenues). The ~~increase in transportation revenues~~recovery of $4.1 million was primarily due to a 1.8 Bcf increase in transportation throughput, largely the result of colder weather and the migration of customers from retail sales to transportation service. The decrease in off-system sales revenues was largely due to a decrease 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 $0.6 million decrease in other operating revenues was largely attributable to a lower ~~undercollection of pension and other post-retirement benefit~~gas costs ~~quarter over quarter.~~

~~Operating revenues for the Utility segment increased $44.8 million for the nine months ended June 30, 2011 as compared with the nine months ended June 30, 2010. This increase largely~~ resulted from lower volumes sold combined with a $25.4 million increase in retail gas sales revenues, a $13.3 million increase in transportation revenues and a $9.1 million increase in off-system sales revenues. These increases were partially offset by a $2.8 million decrease in other operating revenues. The increase in retail gas sales revenues of $25.4 million was largely a function of higher volumes (4.3 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 averagelower cost of purchased gas. The Utility segment’s average cost of purchased gas, including the cost of transportation and storage, was ~~$6.26~~$5.78 per Mcf for the ~~nine~~three months ended ~~June 30,~~December 31, 2011, a decrease of ~~12.6%~~5% from the average cost of ~~$7.16~~$6.06 per Mcf for the ~~nine~~three months ended ~~June 30,~~December 31, 2010. Subject to certain timing variations, gas costs are recovered dollar for dollar in revenues. The increase in transportation revenues of $9.1 million was primarily due to a 6.0 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 ~~$2.8 million~~ decrease in ~~other operating~~transportation revenues of $0.4 million was primarily due to a 1.2 Bcf decrease in transportation throughput, largely the result of warmer weather. The decrease in transportation revenues was ~~largely attributable~~partially offset by the migration of customers from retail sales to ~~a regulatory adjustment to reduce a previous undercollection of pension and other post-retirement benefit costs.~~transportation service.

The Utility segment’s earnings for the quarter ended ~~June 30,~~December 31, 2011 were ~~$6.3~~$19.4 million, ~~an increase~~a decrease of ~~$0.3~~$3.6 million when compared with earnings of ~~$6.0~~$23.0 million for the quarter ended ~~June 30,~~December 31, 2010.

~~In the New York jurisdiction, earnings decreased $1.5 million.~~ The decrease in earnings was largely due to various regulatory true-up adjustments ($0.6 million), an increase in other taxes ($0.4 million) and higher income tax expense ($0.4 million). The regulatory true-up adjustments related primarily to a lower undercollection of pension and other post-retirement benefit costs quarter over quarter.

~~In the Pennsylvania jurisdiction, earnings increased $1.8 million. The earnings increase was~~is largely attributable to ~~higher usage per account~~warmer weather ($~~0.6~~2.3 million) and ~~colder weather~~various routine regulatory adjustments ($~~1.4~~0.9 million). In addition, earnings were negatively impacted by higher operating expenses of $0.3 million (largely the result of higher personnel costs and outside services). These ~~increases~~decreases were partially offset by the ~~negative~~positive earnings impact ~~associated with a higher effective tax rate~~of lower interest expense ($~~0.5~~0.4 million)., which was largely due to lower interest on deferred gas costs.

The impact of weather ~~variations~~ on ~~earnings in~~ the Utility segment’s New York rate jurisdiction is ~~mitigated~~tempered by ~~that jurisdiction’s~~a 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 ~~June 30,~~December 31, 2011, the WNC preserved earnings of approximately $1.4 million, as the weather was warmer than normal. For the quarter ended December 31, 2010, the WNC reduced earnings by ~~$0.2~~$0.1 million, as it was colder than normal. ~~For the quarter ended June 30, 2010, the WNC preserved earnings of approximately $1.0 million, as weather was warmer than normal for the period.~~

The Utility segment’s earnings for the nine months ended June 30, 2011 were $62.4 million, an increase of $0.1 million when compared with earnings of $62.3 million for the nine months ended June 30, 2010.Pipeline and Storage

Pipeline and Storage Operating Revenues


Three Months Ended December 31(Thousands)	2011		2010		Increase (Decrease)
Firm Transportation	$	39,132	$	34,950	$	4,182
Interruptible Transportation		402		314		88

		39,534		35,264		4,270

Firm Storage Service		16,498		16,603		(105	)
Interruptible Storage Service		—		17		(17	)
Other		257		1,511		(1,254	)

	$	56,289	$	53,395	$	2,894

~~-36-~~

-31-

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

In the New York jurisdiction, earnings decreased $4.0 million. The decrease in earnings was mainly due to various regulatory true-up adjustments ($2.1 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 ($0.9 million), higher depreciation expense ($0.5 million), higher interest expense on deferred gas costs ($0.4 million) and higher income tax expense ($0.7 million) further reduced earnings.

In the Pennsylvania jurisdiction, earnings increased $4.1 million. The earnings increase was largely attributable to higher usage per account ($2.1 million) and colder weather ($2.4 million). In addition, the positive earnings impact associated with lower interest expense on deferred gas costs ($0.9 million) further increased earnings. These increases were partially offset by the negative earnings impact associated with higher income tax expense of $0.9 million.

For the nine months ended June 30, 2011, the WNC in the New York jurisdiction reduced earnings by $1.0 million, as it was colder than normal. For the nine months ended June 30, 2010, the WNC in the New York jurisdiction preserved earnings of approximately $1.3 million, as weather was warmer than normal.

~~Pipeline and Storage~~

Pipeline and Storage ~~Operating Revenues~~Throughput

   Three Months Ended Nine Months Ended
   June 30, June 30,
(Thousands)
   2011    2010    Increase
(Decrease) 2011    2010    Increase
(Decrease)
Firm Transportation
   $ 31,208       $ 32,205       $ (997 ) $ 103,448       $ 106,926       $ (3,478 )
Interruptible Transportation
   305       618       (313 ) 1,035       1,458       (423 )










   31,513       32,823       (1,310 ) 104,483       108,384       (3,901 )










Firm Storage Service
   16,629       16,646       (17 ) 50,090       50,032       58
Interruptible Storage Service
   —         19       (19 ) 19       78       (59 )
Other
   2,115       2,064       51    9,361       9,355       6










   $ 50,257       $ 51,552       $ (1,295 ) $ 163,953       $ 167,849       $ (3,896 )










Pipeline and Storage Throughput
   Three Months Ended Nine Months Ended
   June 30, June 30,
(MMcf)
   2011    2010    Increase
(Decrease) 2011    2010    Increase
(Decrease)
Firm Transportation
   53,326       52,448       878    266,545       245,233       21,312
Interruptible Transportation
   489       1,016       (527 ) 1,709       3,575       (1,866 )










   53,815       53,464       351    268,254       248,808       19,446


Three Months Ended December 31(MMcf)	2011		2010		Increase (Decrease)
Firm Transportation		83,608		89,249		(5,641	)
Interruptible Transportation		808		125		683

		84,416		89,374		(4,958	)

2011 Compared with 2010

Operating revenues for the Pipeline and Storage segment ~~decreased $1.3~~increased $2.9 million in the quarter ended ~~June 30,~~December 31, 2011 as compared with the quarter ended ~~June 30,~~December 31, 2010. The ~~decrease~~increase was primarily due to ~~a decrease~~an increase in transportation revenues of ~~$1.3 million. The decrease in~~$4.3 million, largely due to new contracts for transportation revenues was primarily the result of a reduction in the level of contracts entered into by shippers quarter over quarter as shippers utilized lower priced pipeline transportation routes and a decrease in the gathering rate underservice on Supply Corporation’s ~~tariff. Shippers continue to seek alternative lower priced gas supply (and~~Line N Expansion Project, which was placed 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.service in October 2011, and Empire’s ~~proposed~~ Tioga County Extension Project, which was placed in service in November 2011. Both projects provide pipeline capacity for Marcellus Shale production 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~~follows. The increase in transportation revenues was partially offset by ~~receiving natural gas produced from the Marcellus Shale and transporting it to Canada and the Northeast United States where demand has been growing.~~

~~-37-~~

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

Operating revenues for the Pipeline and Storage segment for the nine months ended June 30, 2011 decreased $3.9 million as compared with the nine months ended June 30, 2010. The decrease was primarily due to a decrease in ~~transportation~~efficiency gas revenues of ~~$3.9~~$1.2 million ~~which was primarily the result~~(reported as a part of ~~a reduction~~other revenue in the ~~level~~table above) resulting from lower natural gas prices and an adjustment to reduce the carrying value of ~~contracts entered into by~~Supply Corporation’s efficiency gas inventory to market value during the quarter ended December 31, 2011. Under Supply Corporation’s tariff with shippers, ~~period over period~~Supply Corporation is allowed to retain a set percentage of shipper-supplied gas as ~~shippers utilized lower priced pipeline transportation routes,~~compressor fuel and for other operational purposes. To the extent that Supply Corporation does not need all of the gas to cover such operational needs, it is allowed to keep the excess gas as ~~discussed above.~~inventory. That inventory is later sold to buyers on the open market. The excess gas that is retained as inventory, as well as any gains resulting from the sale of such inventory, represent efficiency gas revenue to Supply Corporation.

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 June 30, 2011 increased by 0.4 Bcf from the prior year’s quarter. For the nine months ended June 30, 2011, transportation volumes increased by 19.4 Bcf from the prior year’s nine-month period.Empire. While transportation volume ~~increased~~decreased by 5.0 Bcf largely due to ~~colder~~warmer weather, there was little impact on revenues due to ~~the~~Supply Corporation and Empire’s straight fixed-variable rate design.

The Pipeline and Storage segment’s earnings for the quarter ended ~~June 30,~~December 31, 2011 were ~~$4.5~~$10.0 million, ~~a decrease~~an increase of ~~$2.7~~$1.4 million when compared with earnings of ~~$7.2~~$8.6 million for the quarter ended ~~June 30,~~December 31, 2010. The increase in earnings ~~decrease was~~is primarily due to the earnings impact of higher operating expenses ($2.1 million). The increase in operating expenses can be attributed primarily to reserve activity associated with preliminary project costs ($0.8 million), higher pension costs ($0.4 million), higher compressor maintenance costs ($0.4 million) and the write-off of expired and unused storage rights ($0.6 million). Lower transportation revenues of ~~$0.9~~$2.8 million, ~~also contributed to the earnings decrease,~~ as discussed above. Higher depreciation expense ($0.4 million) contributed to the decrease in earnings as well. The increase in depreciation expense is primarily the result of a revision during the quarter ended June 30, 2011 to correct accumulated depreciation as well as additional projects that were placed in service in the last year. These earnings decreases were slightly offset byabove, combined with an increase in the allowance for funds used during construction (equity component) of ~~$0.5~~$0.8 million primarily due to construction ~~commencing~~ during the ~~previous~~current quarter on Supply Corporation’s Line N Expansion Project and ~~Lamont Phase II~~Line N 2012 Expansion Project ~~as discussed in the Investing Cash Flow section that follows. Earnings also benefited from lower income tax expense of $0.3 million due to a lower effective tax rate.~~

~~The Pipeline~~ and ~~Storage segment’s~~Empire’s Tioga County Extension Project. These earnings ~~for the nine months ended June 30, 2011~~increases were ~~$24.0 million, a decrease of $6.0 million when compared with earnings of $30.0 million for the nine months ended June 30, 2010. The decrease in earnings is primarily due to~~partially offset by the earnings impact ~~of higher operating expenses~~associated with lower efficiency gas revenues ($~~3.9~~0.8 million), ~~lower transportation revenues of $2.5 million,~~ as discussed above, higher depreciation expense ($~~0.8~~0.7 million) and higher ~~property taxes~~operating expenses ($~~0.4~~0.6 million). The increase in depreciation expense is primarily the result of additional projects that were placed in service in the last year. The increase in operating expenses can be attributed primarily to higher pension expense ~~($1.1 million), reserve activity~~and additional costs associated with ~~preliminary project costs ($0.6 million), higher compressor maintenance costs ($0.6 million)~~compliance with federal/state mandates and the write-off of expired and unused storage rights ($0.6 million). 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 a revision during the quarter ended June 30, 2011 to correct accumulated depreciation 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 $1.0 million primarily due to construction commencing during the current year on Supply Corporation’s ~~Line N Expansion Project and Lamont Phase II Project, as discussed above, and lower income tax expense ($0.7 million) due to a lower effective tax rate.~~current rate case.

~~-38-~~-32-

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

Exploration and Production

Exploration and Production Operating Revenues


	Three Months Ended									Nine Months Ended
	June 30,									June 30,
(Thousands)	2011			2010			Increase (Decrease)			2011			2010			Increase (Decrease)
Three Months Ended December 31(Thousands)																			2011			2010			Increase (Decrease)
Gas (after Hedging)	$	70,849		$	48,381		$	22,468		$	202,114		$	135,761		$	66,353		$	66,512		$	58,009		$	8,503
Oil (after Hedging)		56,058			60,891			(4,833	)		176,088			183,800			(7,712	)		65,671			58,692			6,979
Gas Processing Plant		7,379			7,207			172			20,721			22,078			(1,357	)		6,961			6,683			278
Other		337			218			119			265			380			(115	)		(31	)		(114	)		83
Intrasegment Elimination⁽¹⁾		(3,649	)		(3,895	)		246			(10,617	)		(13,707	)		3,090			(3,139	)		(3,102	)		(37	)

	$	130,974		$	112,802		$	18,172		$	388,571		$	328,312		$	60,259		$	135,974		$	120,168		$	15,806

⁽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 Nine Months Ended
   June 30, June 30,
   2011 2010    Increase
(Decrease) 2011    2010    Increase
(Decrease)
Gas Production(MMcf)

Gulf Coast
   22    2,745       (2,723 ) 4,092       8,079       (3,987 )
West Coast
   826    940       (114 ) 2,616       2,866       (250 )
Appalachia
   12,090    4,741       7,349    31,020       11,084       19,936








Total Production
   12,938    8,426       4,512    37,728       22,029       15,699








Oil Production(Mbbl)

Gulf Coast⁽¹⁾
   (9 ) 135       (144 ) 187       389       (202 )
West Coast
   661    661       —      1,958       2,007       (49 )
Appalachia
   13    13       —      35       34       1








Total Production
   665    809       (144 ) 2,180       2,430       (250 )

⁽¹⁾	~~The sale of Gulf Coast properties in April 2011 and various adjustments to prior months’ production resulted in negative oil production.~~


Three Months Ended December 31	2011		2010		Increase (Decrease)
Gas Production(MMcf)
Appalachia		13,111		8,082		5,029
West Coast		817		935		(118	)
Gulf Coast		—		2,013		(2,013	)

Total Production		13,928		11,030		2,898

Oil Production(Mbbl)
Appalachia		10		10		—
West Coast		709		654		55
Gulf Coast		—		106		(106	)

Total Production		719		770		(51	)

Average Prices


	Three Months Ended								Nine Months Ended
	June 30,								June 30,
	2011			2010		Increase (Decrease)			2011		2010		Increase (Decrease)
Three Months Ended December 31																2011		2010		Increase (Decrease)
Average Gas Price/Mcf
Appalachia																$	3.39	$	4.03	$	(0.64	)
West Coast																$	4.95	$	3.92	$	1.03
Gulf Coast		N/M		$	4.95		N/M		$	5.02	$	5.26	$	(0.24	)		N/M	$	4.55		N/M
West Coast	$	4.87	��	$	4.38	$	0.49		$	4.40	$	4.92	$	(0.52	)
Appalachia	$	4.55		$	4.45	$	0.10		$	4.36	$	5.10	$	(0.74	)
Weighted Average	$	4.67		$	4.61	$	0.06		$	4.44	$	5.13	$	(0.69	)	$	3.48	$	4.11	$	(0.63	)
Weighted Average After Hedging	$	5.48		$	5.74	$	(0.26	)	$	5.36	$	6.16	$	(0.80	)	$	4.78	$	5.26	$	(0.48	)

Average Oil Price/Bbl
Appalachia																$	88.16	$	81.40	$	6.76
West Coast																$	109.23	$	80.45	$	28.78
Gulf Coast		N/M		$	76.42		N/M		$	88.57	$	78.64	$	9.93			N/M	$	83.97		N/M
West Coast	$	108.30		$	71.92	$	36.38		$	94.74	$	71.79	$	22.95
Appalachia	$	92.89		$	74.90	$	17.99		$	87.36	$	77.77	$	9.59
Weighted Average	$	107.97		$	72.72	$	35.25		$	94.10	$	72.97	$	21.13		$	108.93	$	80.95	$	27.98
Weighted Average After Hedging	$	84.37		$	75.23	$	9.14		$	80.78	$	75.65	$	5.13		$	91.38	$	76.24	$	15.14

~~N/M Not Meaningful~~2011 Compared with 2010

Operating revenues for the Exploration and Production segment increased $15.8 million for the quarter ended December 31, 2011 as compared with the quarter ended December 31, 2010. Gas production revenue after hedging increased $8.5 million primarily due to production increases in the Appalachian division, partially offset by decreases in Gulf Coast production. The increase in Appalachian

~~-39-~~-33-

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

~~2011 Compared with 2010~~

~~Operating revenues for~~production was primarily due to increased development within the Exploration and Production segment increased $18.2 million for the quarter ended June 30, 2011 as compared with the quarter ended June 30, 2010. Gas production revenue after hedging increased $22.5 million. IncreasesMarcellus Shale formation, primarily in ~~Appalachian natural gas production were partially offset by decreases~~Tioga County, Pennsylvania. The decrease in Gulf Coast gas production ~~(as a result of~~resulted from the sale of the Exploration and Production segment’s ~~off-shore~~offshore oil and natural gas properties in April ~~2011) and~~2011. Increases in natural gas production were partially offset by a ~~$0.26~~$0.48 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 nine months of fiscal 2011. Oil production revenue after hedging ~~decreased $4.8~~increased $7.0 million ~~as a result of the decrease in production~~ due to ~~the aforementioned sale of Gulf Coast off-shore properties, which more than offset the impact associated with the~~an increase in the weighted average price of oil after hedging ($~~9.14~~15.14 per Bbl).

Operating revenues for the Exploration and Production segment increased $60.3 million for the nine months ended June 30, 2011 as compared with the nine months ended June 30, 2010. Gas production revenue after hedging increased $66.4 million. Increases in Appalachian natural gas production were This increase was partially offset by ~~decreases~~a decrease in ~~Gulf Coast~~ production ~~(as~~as a result of the sale of the Exploration and Production segment’s off-shore oil and natural gas properties in April 2011) and an $0.80 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 nine months of fiscal 2011. Oil production revenue after hedging decreased $7.7 million due largely to the decrease in production due to the aforementioned sale of off-shore properties, which more than offset the impact associated with the increase in the weighted average price of oil after hedging ($5.13 per Bbl). In addition, there was a $1.7 million increase in processing plant revenues (net of eliminations) primarily because of higher prices for gas processing plant liquids combined with a lower cost of WestGulf Coast ~~gas production for the nine months ended June 30, 2011 as compared to the nine months ended June 30, 2010.~~offshore properties.

The Exploration and Production segment’s earnings for the quarter ended ~~June 30,~~December 31, 2011 were ~~$32.8~~$30.3 million, an increase of ~~$4.9~~$2.9 million when compared ~~with~~to earnings of ~~$27.9~~$27.4 million for the quarter ended ~~June 30,~~December 31, 2010. Higher natural gas production in the Appalachian region, higher crude oil prices in the West Coast region, and higher ~~natural gas~~crude oil production in the West Coast region increased earnings by ~~$4.0~~$17.1 million, $7.6 million, and ~~$16.8~~$2.6 million, respectively. ~~In addition, higher processing plant revenues ($0.3 million), lower property and other taxes ($0.5 million), and lower~~Lower interest expense ($~~2.2~~0.6 million) ~~also~~due to lower average interest rates further contributed to ~~an increase in earnings. The decrease in interest expense is primarily due to a lower average amount of debt outstanding. The decrease in property~~the earnings increase. Lower natural gas and ~~other taxes is largely~~crude oil revenues from the Gulf Coast region ($12.1 million) due to the ~~April 2011~~ sale of the ~~Gulf Coast’s off-shore~~offshore oil and natural gas properties ~~and its impact on production and property taxes for the quarter. These earnings increases were~~ partially offset bythe earnings increase. In addition, lower natural gas prices ~~after hedging~~in the Appalachian and ~~lower crude oil production, which~~West Coast regions ($5.2 million) further decreased ~~earnings by $2.2 million and $7.1 million, respectively. In addition, earnings~~earnings. Earnings were further reduced by higher depletion expense ($~~5.2 million), higher lease operating expenses ($0.9~~5.1 million), higher general, administrative and other operating expenses ($~~1.2~~1.4 million), ~~and~~ higher income tax expense ($~~2.2~~0.9 million), and higher lease operating expenses ($0.8 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 and higher transportation costs in ~~Appalachia.~~the Appalachian region combined with higher steam fuel costs in the West Coast region. This was partially offset by the elimination of lease operating expenses in the Gulf Coast region. The increase in income taxes is attributable to higher state income taxes. Higher personnel costs are largely responsible for the increase in general, administrative and other operating expenses. ~~The increase in income tax expense is attributable to higher state income taxes coupled~~

Energy Marketing

Energy Marketing Operating Revenues


Three Months Ended December 31(Thousands)	2011		2010		Decrease
Natural Gas (after Hedging)	$	51,498	$	53,639	$	(2,141	)
Other		11		13		(2	)

	$	51,509	$	53,652	$	(2,143	)

Energy Marketing Volume


Three Months Ended December 31	2011		2010		Decrease
Natural Gas – (MMcf)		10,312		10,746		(434	)

2011 Compared with 2010

Operating revenues for the ~~loss of a domestic production activities deduction that occurred during~~Energy Marketing segment decreased $2.1 million for the quarter ended ~~September 30, 2010 and its impact on~~December 31, 2011 as compared with the ~~effective tax rate during fiscal 2011.~~

quarter ended December 31, 2010. The ~~Exploration and Production segment’s earnings~~decrease primarily reflects a decline in gas sales revenue due largely to a decrease in volume sold. Warmer weather is primarily responsible for the nine months ended June 30, 2011 were $93.5 million, an increase of $8.5 million when compared with earnings of $85.0 million for the nine months ended June 30, 2010. Higher crude oil prices and higher natural gas production increased earnings by $7.3 million and $62.9 million, respectively. In addition, higher processing plant revenues ($1.1 million) and lower interest expense ($5.8 million) also contributed to an increasedecrease in ~~earnings.~~volume. The decrease in ~~interest expense is primarily due~~volume also reflects a decrease in volume sold to ~~a lower average amount~~low-margin wholesale customers. Such transactions had the effect of ~~debt outstanding during the nine months ended June 30, 2011. These earnings increases were partially offset by lower natural gas prices after hedging~~decreasing revenue and ~~lower crude oil production, which decreased earnings by $19.8 million and $12.3 million, respectively. In addition, earnings~~volume sold with minimal impact to earnings.

~~-40-~~-34-

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

were further reduced by higher depletion expense ($20.7 million), higher lease operating expenses ($6.4 million), higher general, administrative and other operating expenses ($5.3 million), higher property and other taxes ($1.1 million), and higher income tax expense ($2.9 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 and other taxes are attributable to a revision of the California property tax liability, which was partially offset by the decrease in property and other taxes as a result of the sale of the Gulf Coast’s off-shore properties in April 2011. The increase in income tax expense is attributable to higher state income taxes coupled with 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.

~~Energy Marketing~~

~~Energy Marketing Operating Revenues~~

   Three Months Ended Nine Months Ended
   June 30, June 30,
(Thousands)
   2011    2010    Increase
(Decrease) 2011    2010    Increase
(Decrease)
Natural Gas (after Hedging)
   $ 71,892       $ 72,759       $ (867 ) $ 246,825       $ 302,931       $ (56,106 )
Other
   10       71       (61 ) 50       172       (122 )










   $ 71,902       $ 72,830       $ (928 ) $ 246,875       $ 303,103       $ (56,228 )










Energy Marketing Volume
   Three Months Ended Nine Months Ended
   June 30, June 30,
   2011    2010    Increase
(Decrease) 2011    2010    Increase
(Decrease)
Natural Gas – (MMcf)
   13,508       13,047       461    45,863       51,144       (5,281 )

~~2011 Compared with 2010~~

Operating revenues for the Energy Marketing segment decreased $0.9 million and $56.2 million for the quarter and nine months ended June 30, 2011, as compared with the quarter and nine months ended June 30, 2010. The decrease for the quarter ended June 30, 2011 reflects a decline in gas sales revenue due to a lower average price of natural gas that was recovered through revenues, partially offset by an increase in volume sold to retail customers. The decrease for the nine months ended June 30, 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 for the nine-month period is largely attributable to 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. The decrease in volume also reflects a decrease in volume sold to low-margin wholesale customers. Such transactions had the effect of increasing revenue and volume sold with minimal impact to earnings. The decrease in volume sold to wholesale customers during the nine-month period was partially offset by an increase in volume sold to retail customers.

The Energy Marketing segment’s earnings for the quarter ended ~~June 30,~~December 31, 2011 were ~~$1.9~~$0.4 million, ~~an increase~~a decrease of $0.5 million when compared with earnings of ~~$1.4~~$0.9 million for the quarter ended ~~June 30,~~December 31, 2010. ~~The increase for the quarter~~This decrease was largely attributable to ~~lower operating expenses of $0.3 million. This consisted primarily of~~ a ~~decrease~~decline in expense for anticipated U.S. Customs merchandise processing fees. The Energy Marketing segment also experienced a decrease in bad debt expense quarter over quarter. The Energy Marketing segment’s earnings for the nine months ended June 30, 2011 were $9.1 million, an

~~-41-~~

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

~~increase of $0.6 million when compared with earnings of $8.5 million for the nine months ended June 30, 2010. This increase was largely attributable to higher~~ margin of ~~$0.3~~$0.4 million and ~~lower~~higher operating costs of $0.1 million. The ~~increase~~decrease in margin was primarily ~~driven by improved~~due to lower average margins per Mcf offset partially by a lower benefit from its contracts for storage capacity. The decrease in operating costs reflects the decrease in expense for U.S. Customs merchandise processing fees, discussed above, as well as lower ~~bad debt expense. These decreases were partially offset by higher pension expense.~~volume sold to retail customers.

Corporate and All Other

2011 Compared with 2010

Corporate and All Other operations recorded ~~earnings from continuing operations~~net income of ~~$1.4~~$0.6 million for the quarter ended ~~June 30,~~December 31, 2011 ~~an increase of $1.3 million when~~ compared with ~~earnings from continuing operations~~a loss of ~~$0.1~~$1.3 million for the quarter ended ~~June 30,~~December 31, 2010. The increase in earnings ~~from continuing operations is~~was largely due to 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), lower depreciation and depletion expense of $1.3 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 gathering and processing revenues of ~~$1.2~~$1.0 million, ~~(due to an increase~~a reduction in ~~Midstream Corporation’s gathering~~losses from unconsolidated subsidiaries of $0.7 million, lower interest expense of $0.7 million and ~~processing activities). Lower income tax expense ($0.6 million) further contributed to the earnings increase as did a gain~~higher revenues from sales of ~~$0.2~~standing timber of $0.4 million, ~~resulting from the auction of some remaining timber mill equipment during the quarter ended June 30, 2011. The factors contributing to the overall increase in earnings were~~ partially offset by lower interest income of ~~$2.4~~$0.5 million. The higher gathering and processing revenues are due to Midstream Corporation’s increase in gathering operations for Marcellus Shale gas in Tioga County, Pennsylvania. The loss from unconsolidated subsidiaries of $0.7 million ~~(due~~that occurred during the quarter ended December 31, 2010 was largely due to lower renewable energy credit revenue recorded by Seneca Energy and Model City. This did not recur during the quarter ended December 31, 2011 as Seneca Energy and Model City were sold in February 2011. The decrease in interest expense was due to lower interest rates on borrowings. In November 2011, $150 million of 6.70% notes matured. In December 2011, the Company issued $500 million of notes at 4.90%. The decrease in interest income was due to lower interest collected from the Company’s Exploration and Production segment as a result of ~~the aforementioned November 2010 debt repayment), higher property, franchise and other taxes of $0.9~~lower interest rates on borrowings discussed above.

Other Income

Other income increased $1.4 million ~~(due to an increase in capital stock tax expense recorded during~~for the quarter ended ~~June 30,~~December 31, 2011 ~~related to fiscal year 2010) and lower margins of $0.7 million (due~~as compared with the quarter ended December 31, 2010. The increase is primarily attributed to a ~~decrease~~reduction in ~~timber harvested as a result of the sale of the Company’s timber harvesting and milling operations in September 2010). Additionally, the Company recorded a loss~~losses from unconsolidated subsidiaries of ~~$0.1~~$1.0 million. It also reflects a $0.8 million ~~during the quarter ended June 30, 2011 compared to income of $0.4 million during the quarter ended June 30, 2010.~~

For the nine months ended June 30, 2011, Corporate and All Other had earnings from continuing operations of $32.0 million, an increase of $31.1 million when compared with earnings from continuing operations of $0.9 million for the nine months ended June 30, 2010. The increase in ~~earnings from continuing operations is due to~~allowance for funds used during construction in the Pipeline and Storage segment. These factors were partially offset by a $0.4 million gain on the sale of Horizon Power’s investments in Seneca Energy and Model City of $31.4 million, lower interest expense of $6.0 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 $3.8 million (due to an increase in Midstream Corporation’s gathering and processing activities) and lower depreciation and depletion expense of $3.4 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 income tax expense ($0.6 million) further contributed to the earnings increase. Additionally, a $0.5 million gain on corporate-owned life insurance policies recorded during the quarter ended March 31, 2011 also factored into the increase. The gain of $0.2 million resulting from the auction of some remaining timber mill equipment, discussed above, and a $0.2 million gain resulting from the sale of Horizon Energy Development infor the quarter ended December 31, 2010, also factored into the earnings increase. The factors contributing to the overall increase in earnings were partially offset by lower margins of $5.7 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 $5.7 million (due to lower interest collected from the Company’s Exploration and Production segment as a result of the aforementioned November 2010 debt repayment), higher property, franchise and other taxes of $1.2 million (due to an increase in capital stock tax expense recorded during the nine months ended June 30, 2011 related to fiscal year 2010) and higher operating expenses of $1.0 million (mostly due to the increase in Midstream Corporation’s operating activities). Additionally, the Company recorded a loss from unconsolidated subsidiaries of $0.5 millionwhich did not recur during the quarter ended ~~June 30, 2011 compared to income of $1.1~~December 31, 2011.

Interest Expense on Long-Term Debt

Interest on long-term debt decreased $1.6 million ~~during~~for the quarter ended ~~June 30,~~December 31, 2011 as compared with the quarter ended December 31, 2010. This decrease is primarily the result of lower average interest rates coupled with a slightly lower average amount of long-term debt outstanding. The Company repaid $150 million of 6.70% notes that matured in November 2011. In December 2011, the Company issued $500.0 million of 4.90% notes due in December 2021.

Other Interest Expense

Other interest expense decreased $0.6 million for the quarter ended December 31, 2011 as compared with the quarter ended December 31, 2010. The decrease is mainly due to lower interest expense on regulatory deferrals (primarily interest on deferred gas costs) in the Utility segment.

~~-42-~~-35-

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

~~Other Income~~

Other income increased $1.0 million for the quarter ended June 30, 2011 as compared with the quarter ended June 30, 2010. This increase is mainly attributable to a $0.5 million increase in allowance for funds used during construction in the Pipeline and Storage segment. In addition, there was a $0.3 million gain on disposal of some sawmill assets. For the nine months ended June 30, 2011, other income increased $2.3 million as compared with the nine months ended June 30, 2010. This increase is attributable to a $0.5 million gain on corporate-owned life insurance policies 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 $0.9 million increase in allowance for funds used during construction in the Pipeline and Storage segment as well as a $0.3 million gain on the disposal of sawmill assets mentioned above.

~~Interest Expense on Long-Term Debt~~

Interest on long-term debt decreased $3.2 million for the quarter ended June 30, 2011 as compared with the quarter ended June 30, 2010. For the nine months ended June 30, 2011, interest on long-term debt decreased $9.2 million as compared with the nine months ended June 30, 2010. This decrease is primarily the result of a lower average amount of long-term debt outstanding and slightly lower average interest rates. The Company repaid $200 million of 7.5% notes that matured in November 2010.

~~Other Interest Expense~~

Other Interest expense decreased $0.7 million for the quarter ended June 30, 2011 as compared with the quarter ended June 30, 2010. The decrease is mainly due to lower interest expense on regulatory deferrals (primarily deferred gas costs) in the Utility segment. For the nine months ended June 30, 2011, other interest expense decreased $1.2 million as compared with the nine months ended June 30, 2010. The decrease in interest expense is mainly attributed to a decrease in interest expense on regulatory deferrals (primarily deferred gas costs) in the Utility segment. An increase in the allowance for borrowed funds used during construction also contributed to the decrease in interest expense.

CAPITAL RESOURCES AND LIQUIDITY

The Company’s primary ~~source~~sources of cash during the ~~nine-month~~three-month period ended ~~June 30,~~December 31, 2011 consisted of proceeds from the issuance of long-term debt and cash provided by operating ~~activities, net proceeds from the sale of unconsolidated subsidiaries and net proceeds from the sale of oil and gas producing properties.~~activities. The Company’s primary source of cash during the ~~nine-month~~three-month period ended ~~June 30,~~December 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~~short-term borrowings for the ~~nine months~~quarter ended ~~June 30,~~December 31, 2010. During the ~~nine~~three months ended ~~June 30,~~December 31, 2011 and December 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 and deferred income ~~taxes, gain on the sale of unconsolidated subsidiaries, and income or loss from unconsolidated subsidiaries net of cash distributions.~~taxes.

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.

~~-43-~~

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

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 as well as changes in production. 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 ~~$536.3~~$79.2 million for the ~~nine~~three months ended ~~June 30,~~December 31, 2011, ~~an increase~~a decrease of ~~$116.4~~$8.3 million when compared with ~~$419.9~~the $87.5 million provided by operating activities for the ~~nine~~three months ended ~~June 30,~~December 31, 2010. InThe decrease in cash provided by operating activities is primarily due to an increase in cash used in operations in the Energy Marketing segment and lower cash provided by operations in the Utility segment, both of which were partially offset by an increase in cash provided by operations in the Exploration and Production segment. The variation in the Energy Marketing segment ~~cash provided by operations increased~~can be attributed to lower customer advances due to ~~higher cash receipts from the sale of natural~~low gas ~~production. An increase in~~prices combined with hedging collateral ~~deposits~~account fluctuations. The decrease in the Utility segment can be attributed to the timing of gas cost recovery. The increase in the Exploration and Production segment ~~at June 30, 2011 partly~~reflects higher cash receipts from oil and natural gas production in the West Coast and Appalachian regions combined with hedging collateral account fluctuations, which both offset the ~~increase~~loss of cash flow from the Company’s former oil and natural gas properties in ~~cash provided by operating activities. Hedging collateral deposits serve as collateral for open positions on exchange-traded futures contracts~~the Gulf of Mexico.

-36-

Item 2.Management’s Discussion and ~~over-the-counter swaps.~~Analysis of Financial Condition and Results of Operations (Cont.)

Investing Cash Flow

Expenditures for Long-Lived Assets

The Company’s expenditures ~~from continuing operations~~ for long-lived assets totaled ~~$549.7 million during the nine months ended June 30, 2011 and $341.9~~$279.0 million for the ~~nine~~three months ended ~~June 30,~~December 31, 2011 and $200.9 million for the three months ended December 31, 2010. The table below presents these expenditures:

Total Expenditures for Long-Lived Assets

Total Expenditures for Long-Lived Assets
Nine Months Ended June 30,
(Millions)
   2011 2010 Increase
(Decrease)
Utility:

Capital Expenditures
   $ 39.4    $ 39.5    $ (0.1 )
Pipeline and Storage:

Capital Expenditures
   75.0 ⁽¹⁾ 22.2    52.8
Exploration and Production:

Capital Expenditures
   473.5 ⁽¹⁾⁽²⁾ 273.8 ⁽³⁾⁽⁴⁾ 199.7
All Other:

Capital Expenditures
   6.8    6.4 ⁽⁴⁾ 0.4


Total Expenditures from Continuing Operations
   $ 594.7    $ 341.9    $ 252.8



Three Months Ended December 31, (Millions)	2011			2010			Increase
Utility:
Capital Expenditures	$	11.3		$	10.9		$	0.4
Pipeline and Storage:
Capital Expenditures		44.2	⁽¹⁾⁽²⁾		9.2	⁽³⁾		35.0
Exploration and Production:
Capital Expenditures		191.9	⁽¹⁾⁽²⁾		179.8	⁽³⁾⁽⁴⁾		12.1
All Other:
Capital Expenditures		31.6	⁽¹⁾⁽²⁾		1.0			30.6

	$	279.0		$	200.9		$	78.1

⁽¹⁾

Capital expenditures for the Exploration and Production segment include $88.1 million of accrued capital expenditures at December 31, 2011, the majority of which was in the Appalachian region. Capital expenditures for the Pipeline and Storage segment include $15.8 million of accrued capital expenditures at December 31, 2011. In addition, capital expenditures for the All Other category include $14.5 million of accrued capital expenditures at December 31, 2011. These amounts have been excluded from the Consolidated Statement of Cash Flows at December 31, 2011 since they represent non-cash investing activities at that date.

⁽²⁾

Capital expenditures for the Exploration and Production segment for the three months ended December 31, 2011 exclude $63.5 million of capital expenditures, the majority of which was in the Appalachian region. Capital expenditures for the Pipeline and Storage segment for the three months ended December 31, 2011 exclude $7.3 million of capital expenditures. Capital expenditures for the All Other category for the three months ended December 31, 2011 exclude $1.4 million of capital expenditures. These amounts were accrued at September 30, 2011 and paid during the three months ended December 31, 2011. These amounts were excluded from the Consolidated Statement of Cash Flows at September 30, 2011 since they represented non-cash investing activities at that date. These amounts have been included in the Consolidated Statement of Cash Flows at December 31, 2011.

⁽³⁾

Capital expenditures include $60.7 million of accrued capital expenditures for the Exploration and Production segment at ~~June 30, 2011,~~December 31, 2010, the majority of which was in the Appalachian region. In addition, capital expenditures for the Pipeline and Storage segment include ~~$5.9~~$2.0 million of accrued capital expenditures at ~~June 30, 2011.~~December 31, 2010. These amounts were excluded from the Consolidated Statement of Cash Flows at ~~June 30, 2011~~December 31, 2010 since they represented non-cash investing activities at that date.

⁽²⁾⁽⁴⁾

Capital expenditures for the Exploration and Production segment for the ~~nine~~three months ended ~~June 30, 2011 exclude~~December 31, 2010 excludes $55.5 million of ~~accrued~~ capital expenditures, the majority of which was in the Appalachian region. This amount was accrued at September 30, 2010 and paid during the ~~nine~~three months ended ~~June 30, 2011.~~December 31, 2010. This amount was excluded from the Consolidated Statement of Cash Flows at September 30, 2010 since it represented a non-cash investing ~~activities~~activity at that date. ~~This~~The amount ~~has been~~was included in the Consolidated Statement of Cash Flows at ~~June 30, 2011.~~December 31, 2010.

Utility

~~-44-~~The majority of the Utility capital expenditures for the three months ended December 31, 2011 and December 31, 2010 were made for replacement of mains and main extensions, as well as for the replacement of service lines.

-37-

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

⁽³⁾	Amount includes $24.3 million of accrued capital expenditures at June 30, 2010, the majority of which was in the Appalachian region. This amount has been excluded from the Consolidated Statement of Cash Flows at June 30, 2010 since it represents a non-cash investing activity at that date.

⁽⁴⁾

Capital expenditures for the Exploration and Production segment for the nine months ended June 30, 2010 exclude $9.1 million of accrued capital expenditures, the majority of which was in the Appalachian region. Capital expenditures for All Other for the nine months ended June 30, 2010 exclude $0.7 million of accrued 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 nine months ended June 30, 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 June 30, 2010.

~~Utility~~

The majority of the Utility capital expenditures for the nine months ended June 30, 2011 and June 30, 2010 were made for replacement of mains and main extensions, as well as for the replacement of service lines.

Pipeline and Storage

The majority of the Pipeline and Storage capital expenditures for the ~~nine~~three months ended ~~June 30,~~December 31, 2011 were related to the construction of Empire’s Tioga County Extension Project, and Supply Corporation’s Line N 2012 Expansion Project and Northern Access expansion project, as discussed below. The Pipeline and Storage segment capital expenditures for the three months ended December 31, 2011 include $17.4 million spent on the Tioga County Extension Project, $6.6 million spent on the Line N 2012 Expansion Project, and $2.5 million spent on the Northern Access expansion project. The Pipeline and Storage capital expenditures for the three months ended December 31, 2011 also include additions, improvements, and replacements to this segment’s transmission and gas storage systems. The majority of the Pipeline and Storage capital expenditures for the three months ended December 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 nine months ended June 30, 2011 include $11.8 million spent on the Line N Expansion Project, $7.0 million spent on the Lamont Phase II Project and $11.2 million spent on the Tioga County Extension Project, as discussed below. The Pipeline and Storage capital expenditure amounts for the nine months ended June 30, 2010 also include $5.8 million spent on the Lamont Phase I 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 ~~June 30,~~December 31, 2011, the total amount reserved for the Pipeline and Storage segment’s preliminary survey and investigation costs was $7.2 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 with Statoil Natural Gas LLC (“Statoil”) to provide 320,000 Dth/day of firm transportation capacity for a 20-year term in conjunction with its “Northern Access” expansion ~~project. Upon satisfaction of~~project, and has executed the ~~conditions in the precedent agreement, Statoil Natural Gas LLC (“Statoil”) will enter into a 20-year firm~~ transportation ~~agreement for 320,000 Dth/day.~~service agreement. This capacity will provide Statoil 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, and received its Certificate on October 20, 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

~~-45-~~

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

compressor station in East Aurora, New York, along with other system enhancements including enhancements to the jointly owned Niagara Spur Loop Line. Service is expected to begin in November 2012. The ~~preliminary~~ cost estimate for the Northern Access expansion is $62 million. As of ~~June 30,~~December 31, 2011, approximately ~~$0.7~~$4.9 million has been spent on the Northern Access expansion project. The Company has determined that it is highly probable that this project will be built. Accordingly, previous reserves have been reversed and the $0.7 million has been capitalized as Construction Work in Progress.

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. The project will allow Marcellus production located in the vicinity of Line N to flow south and access markets off Texas Eastern’s system, with a projected in-service date of September 2011. Two service agreements totaling 160,000 Dth/day of firm transportation have been executed. 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. The preliminary cost estimate for the Line N Expansion Project is $20 million. As of June 30, 2011, approximately $11.8 million has been spent on the Line N expansion project, all of which has been capitalized as Construction Work in Progress.

Supply Corporation has begun service under two service agreements, which total 160,000 Dth/day of firm transportation capacity in its “Line N Expansion Project.” This project allows Marcellus production located in the vicinity of Line N to flow south and access markets at Texas Eastern’s Holbrook Station (“TETCO Holbrook”) in southwestern Pennsylvania. The FERC issued the NGA Section 7(c) certificate on December 16, 2010, and the project was placed into service on October 19, 2011.

-38-

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

Completed cost for the Line N Expansion Project is expected to be approximately $21 million. As of December 31, 2011, approximately $18.9 million has been spent on the Line N Expansion Project, all of which is included in Property, Plant and Equipment on the balance sheet at December 31, 2011.

Supply Corporation has also executed two precedent agreements for a ~~precedent agreement for 150,000~~total of 158,000 Dth/day of additional capacity on Line N to TETCO Holbrook ~~and has designed a project for this shipper to be ready~~ for service beginning November 2012 (“Line N 2012 Expansion Project”). On July 8, 2011, Supply Corporation filed for FERC authorization to construct the Line N 2012 Expansion Project which consists of an additional 20,620 horsepower of compression at its Buffalo Compressor Station, and the replacement of 4.85 miles of 20” pipe with 24” pipe, to enhance ~~its~~the integrity and reliability of its system and to create the additional capacity. The preliminary cost estimate for the Line N 2012 Expansion Project is approximately $30.0 ~~million.~~million for the incremental capacity plus approximately $5.8 million allocated to system replacement. As of ~~June 30,~~December 31, 2011, approximately ~~$0.2~~$9.0 million has been spent on the Line N 2012 Expansion Project, ~~which has been included in preliminary survey and investigation charges and has been fully reserved for at June 30, 2011.~~

Following up on Supply Corporation’s Lamont Project which went into service on June 15, 2010, a second Lamont expansion (“Lamont Phase II Project”) has been fully subscribed and is nearing completion. Supply Corporation has two executed service agreements for the full capacity of this project. Following construction of an additional 3,400 horsepower of compression, which began in March 2011, 10,000 Dth/day of incremental firm capacity was placed in service on July 1, 2011, and an additional 40,000 Dth/day will commence on October 1, 2011. The preliminary cost estimate for the Lamont Phase II Project is approximately $7.6 million. As of June 30, 2011, approximately $7.0 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 Marcellus 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~~initial 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 late 2013 or late 2014.~~

~~-46-~~

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

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 $290 million. The project may be built in phases depending on the development of Marcellus production along the corridor, with the first facilities available for service in late 2013 or late 2014. As of ~~June 30,~~December 31, 2011, approximately ~~$5.1~~$5.5 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 ~~June 30,~~December 31, 2011.

On August 4, 2011, Supply Corporation concluded an Open Season to increase its capability to move gas north on its Line N system and deliver gas to Tennessee Gas Pipeline at Mercer, Pennsylvania, a pooling point recently established at their Station 219 (“Mercer Expansion Project”). Supply Corporation is in discussions with an anchor shipper that would take all 150,000 Dth/day of the capacity on the project. Service is expected to begin in 2014 and the estimated cost is $25 million to $30 million. As of December 31, 2011, less than $0.1 million has been spent to study the Mercer Expansion Project, all of which has been included in preliminary survey and investigation charges and has been fully reserved for at December 31, 2011.

Empire has ~~executed~~begun service under two service agreements ~~for all~~which total 350,000 Dth/day of incremental firm transportation capacity in its “Tioga County Extension Project.” This project ~~will transport~~transports Marcellus production from new interconnections at the southern terminus of a 15-mile extension of its Empire Connector line, in Tioga County, Pennsylvania. ~~Empire’s preliminary~~Completed cost ~~estimate~~ for the Tioga County Extension Project is expected to be approximately ~~$49 million.~~$54 million, of which approximately $49.2 million has been spent through December 31, 2011. This project ~~will enable~~enables 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~~the new interconnection with TGP’s 200 Line (Zone 5) in Ontario County, New York. On August 26, 2010, Empire filed an NGA Section 7(c) application to the FERC for approval of the project and the FERC issued the certificate on May 19, 2011. Empire ~~has~~ accepted the certificate, received a FERC Notice to Proceed and on July 7, 2011 commenced construction. ~~Empire anticipates that these~~These facilities ~~will be~~were placed fully in service on ~~or before~~ November 1,22, 2011. AsAll costs associated with the project are included in Property, Plant and Equipment on the balance sheet at December 31, 2011.

-39-

Item 2.Management’s Discussion and Analysis of ~~June 30, 2011, approximately $11.2 million has been spent related to the Tioga County Extension Project, all~~Financial Condition and Results of ~~which has been capitalized as Construction Work in Progress.~~Operations (Cont.)

On December 17, 2010, Empire concluded an Open Season for up to 260,000 ~~Dth per~~ Dth/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~~in discussions with an anchor shipper for a significant portion of the ~~substantial market interest resulting from this Open Season, which was for more than 260,000 Dth per day of~~proposed capacity, with service commencing in late 2013 or mid-2014, 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 ~~June 30,~~December 31, 2011, approximately ~~$0.1~~$0.2 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 ~~June 30,~~December 31, 2011.

The Company anticipates financing the Line N Expansion Projects, the Lamont Phase II Project, the Northern Access expansion project, the W2E Overbeck to Leidy 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 $184.7 million in Cash and Temporary Cash Investments at June 30, 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.

~~-47-~~

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

Exploration and Production

The Exploration and Production segment capital expenditures for the ~~nine~~three months ended ~~June 30,~~December 31, 2011 were primarily well drilling and completion expenditures and included approximately ~~$441.2~~$181.2 million for the Appalachian region (including ~~$433.5~~$172.0 million in the Marcellus Shale area) and $10.7 million for the West Coast region. These amounts included approximately $55.7 million spent to develop proved undeveloped reserves.

The Exploration and Production segment capital expenditures for the three months ended December 31, 2010 were primarily well drilling and completion expenditures and included approximately $174.3 million for the Appalachian region (including $173.0 million in the Marcellus Shale area), ~~$28.1~~$2.7 million for the West Coast region and ~~$4.2~~$1.1 million for the Gulf Coast ~~region.~~region (former offshore oil and natural gas properties in the Gulf of Mexico). These amounts included approximately ~~$165.5~~$57.0 million spent to develop proved undeveloped reserves. The capital expenditures in the Appalachian region ~~include~~included 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.

AsFor all of fiscal 2012, 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~~expects to spend $760.0 million on Exploration 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 adjustmentProduction segment capital expenditures. Previously reported 2012 estimated capital expenditures for the ~~operating cash flow that~~Exploration and Production segment were $858.5 million. In the ~~Company recorded~~Appalachian region, estimated capital expenditures will decrease from ~~January 1, 2011~~$808.5 million 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.

~~In May 2011, the Company sold the Sprayberry property~~$710.0 million. Estimated capital expenditures in the West Coast region ~~for $7.7~~will remain at the previously reported $50.0 million. 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 May 2011. Since the disposition did not significantly alter the relationship between capitalized costs and proved reserves of oil and gas attributableThe Company had previously reported that it anticipates drilling 100 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 nine months ended June 30, 2010 were primarily well drilling and completion expenditures and included approximately $240.6 million for the Appalachian region (including $217.6 million125 net horizontal wells in the Marcellus Shale ~~area), $21.2 million for the West Coast region and $12.0 million for the Gulf Coast region, the majority of which was for the off-shore program~~during 2012. The Company now anticipates drilling 60 to 90 net horizontal wells in the ~~shallow waters~~Marcellus Shale during 2012. The decrease in estimated capital expenditures noted above is a result of the Gulf of Mexico. These amounts included approximately $23.4 million spent to develop proved undeveloped reserves. The capital expenditures in the Appalachian region include the Company’s acquisition of two tracts of leasehold acreagecurrent low price environment for approximately $71.8 million. The Company 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.natural gas.

All Other

The majority of the All Other category’s capital expenditures for the ~~nine~~three months ended ~~June 30,~~December 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 ~~nine~~three months ended ~~June 30,~~December 31, 2010 were primarily for the expansion of Midstream Corporation’s Covington gathering system in Tioga County, Pennsylvania as well as for the construction of Midstream Corporation’s ~~Covington~~Trout Run 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 ~~late 2011.~~March 2012. The system will consist of approximately ~~16.5~~26 miles of backbone and in-field gathering system at a cost of ~~$51~~approximately $70 million. As of ~~June 30,~~December 31, 2011, the Company has spent approximately ~~$3.3~~$42.0 million in costs related to this ~~project.~~project, all of which has been capitalized as Construction Work in Progress.

~~-48-~~-40-

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

Midstream Corporation is planning to construct a gathering system in McKean County, Pennsylvania. The project, called the Mt. Jewett Gathering System, is anticipated to be placed in service in the fall of 2012. The gathering system will cost approximately $22 million. As of December 31, 2011, the Company has spent approximately $1.1 million in costs related to this project, all of which has been capitalized as Construction Work in Progress.

Project Funding

The Company ~~anticipates funding~~has been financing the ~~Trout Run Gathering System project~~Pipeline and Storage segment projects and the Midstream Corporation projects mentioned above, as well as the Exploration and Production segment capital expenditures with cash from ~~operations and/or short-term borrowings. Given the Company’s cash position at June 30, 2011,~~operations. Going forward, while the Company expects to use cash from operations as the first means of financing these ~~projects.~~projects, it is expected that the Company will increase its use of short-term borrowings during fiscal 2012. 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 also issued additional long-term debt in December 2011 to enhance its liquidity position.

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 necessitated by the continued need for replacement and upgrading of mains and service lines, the magnitude of future capital expenditures or other investments in the Company’s other business segments depends, to a large degree, upon market conditions.

Financing Cash Flow

Consolidated short-term debt decreased $20.0 million during the three months ended December 31, 2011. The maximum amount of short-term debt outstanding during the three months ended December 31, 2011 was $327.8 million. The Company ~~did not have any outstanding~~used its $500.0 million long-term debt issuance in December 2011 to substantially reduce its short-term ~~notes payable to banks or commercial paper at June 30, 2011. During the nine months ended June 30, 2011, consolidated short-term debt did not exceed $31.5 million outstanding.~~debt. 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.~~needs and repayment of long-term debt. Fluctuations in these items can have a significant impact on the amount and timing of short-term debt. At December 31, 2011, the Company had outstanding commercial paper of $20.0 million and no outstanding short-term notes payable to banks.

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~~totaled $385.0 million at December 31, 2011, are revocable at the option of the financial institutions and are reviewed on an annual basis. Subsequent to December 31, 2011, and following an increase in the amount of the Company’s syndicated committed credit facility, as described below, the amount of the Company’s uncommitted lines of credit decreased to $335.0 million. The Company anticipates that ~~these~~its uncommitted lines of credit generally will ~~continue to~~ be renewed at amounts near current levels, or substantially replaced by similar lines.

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

The total amount available to be issued under the Company’s commercial paper program is $300.0 million. ~~The~~At December 31, 2011, the commercial paper program iswas backed by a syndicated committed credit facility totaling $300.0 million, which commitment ~~extends~~extended through September 30, 2013. Under the ~~Company’s~~ committed credit facility, the Company ~~has~~ agreed that its debt to capitalization ratio ~~will~~would not exceed .65 at the last day of any fiscal quarter through September 30, 2013. At ~~June 30,~~December 31, 2011, the Company’s debt to capitalization ratio (as calculated under the facility) was ~~.36.~~.42. The constraints specified in the committed credit facility would ~~permit~~have permitted an additional ~~$2.39~~$2.14 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~~exceeded .65. On January 6, 2012, the Company entered into an Amended and Restated Credit Agreement with a syndicate of 14 banks. The agreement replaces the Company’s $300.0 million committed credit facility with a similar committed credit facility totaling $750.0 million. The new facility extends to January 6, 2017.

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 ~~June 30,~~December 31, 2011, the Company would have been permitted to issue up to a maximum of ~~$1.71~~$1.46 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%~~7.1%) of the Company’s long-term debt (as of ~~June 30,~~December 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

~~-49-~~

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

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~~$750.0 million committed credit facility, like the $300.0 million facility it replaced, also contains a cross-default provision whereby the failure by the Company or its significant subsidiaries to make payments under other borrowing arrangements, or the occurrence of certain events affecting those other borrowing arrangements, could trigger an obligation to repay any amounts outstanding under the committed credit facility. In particular, a repayment obligation could be triggered if (i) the Company or any of its significant subsidiaries fails to make a payment when due of any principal or interest on any other indebtedness aggregating $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 ~~June 30,~~December 31, 2011, the Company did not have any debt outstanding under the committed credit facility.

The Company’s embedded cost of long-term debt was 6.17% at December 31, 2011 and 6.85% at ~~June 30, 2011 and 6.95% at June 30,~~December 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%.~~

There was no Current Portion of Long-Term Debt at ~~June 30, 2011 consists of~~December 31, 2011. The Company repaid $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~~21, 2011, which had been classified as Current Portion of Long-Term Debt at September 30, ~~2010.~~2011.

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

On December 1, 2011, the Company issued $500.0 million of 4.90% notes due December 1, 2021. After deducting underwriting discounts and commissions, the net proceeds to the Company amounted to $496.1 million. The holders of the notes may require the Company to repurchase their notes at a price equal to 101% of the principal amount in the event of a change in control and a ratings downgrade to a rating below investment grade. The proceeds of this debt issuance were used for general corporate purposes, including refinancing short-term debt that was used to pay the $150 million due at the maturity of the Company’s 6.70% notes in November 2011.

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 ~~$23.8~~$33.5 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 ~~nine~~three months ended ~~June 30,~~December 31, 2011, the Company contributed ~~$40.0~~$22.5 million to its Retirement Plan and ~~$18.9~~$5.2 million to its VEBA trusts and 401(h) accounts for its other post-retirement benefits. In the remainder of ~~2011,~~2012, the Company expects to contribute between ~~$8.0~~$16.0 and ~~$9.0~~$27.0 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~~2012 in order to be in compliance with the Pension Protection Act of 2006. In the remainder of ~~2011,~~2012, the Company expects to contribute between ~~$1.0~~$14.0 and ~~$6.5~~$15.0 million to its VEBA trusts and 401(h) accounts.

~~-50-~~

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

Market Risk Sensitive Instruments

On July 21, 2010, the Dodd-Frank Act was signed into law. The Dodd-Frank Act includes provisions related to the swaps and over-the-counter derivatives markets. Certain provisions of the Dodd-Frank Act related to derivatives became effective July 16, 2011, but other provisions related to derivatives will not become effective until federal agencies (including the Commodity Futures Trading Commission (CFTC), various banking regulators and the SEC) adopt rules to implement the law. For purposes of the Dodd-Frank Act, the Company ~~should~~believes it will be categorized as a non-financial end user of derivatives, that is, as a non-financial entity that uses derivatives to hedge commercial risk. Nevertheless, the rules that are being developed could have a significant impact on the Company. For example, banking regulators have proposed a rule that would require swap dealers and major swap participants subject to their jurisdiction to collect initial and variation margin from counterparties that are non-financial end users, though such swap dealers and major swap participants would have the discretion to set thresholds for posting margin (unsecured credit limits). Regardless of the levels of margin that might be required,

-43-

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

concern remains that swap dealers and major swap participants will pass along their increased capital and margin costs through higher prices and reductions in thresholds for posting margin. In addition, while the Company expects to be exempt from the Dodd-Frank Act’s requirement that swaps be cleared and traded on exchanges or swap execution facilities, the cost of entering into a non-cleared swap that is available as a cleared swap may be greater. The Company continues to monitor these developments but cannot predict the impact the Dodd-Frank Act may ultimately have on its operations.

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 crude 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 ~~$50.5~~$54.8 million at ~~June 30,~~December 31, 2011 and represent ~~27.3%~~18.9% of the Total Net Assets shown in Part I, Item 1 at Note 2 – Fair Value Measurements at ~~June 30,~~December 31, 2011.

The increase in the net fair value liability of the Level 3 positions from October 1, ~~2010~~2011 to ~~June 30,~~December 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 ~~June 30,~~December 31, 2011.

The fair value of all of the Company’s Net Derivative ~~Asset~~Assets was reduced by ~~$0.3~~$2.2 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~~2011 Form 10-K. There have been no subsequent material changes to the Company’s exposure to market risk sensitive instruments.

~~-51-~~

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

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 only 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.

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

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 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, among other things, that the NYPSC improperly disallowed recovery of certain environmental clean-up costs. Following further appeals, on March 29, 2011, the Court of Appeals, the state’s highest court, issued a judgment and opinion in favor of Distribution Corporation. The matter was remanded to the NYPSC to be implemented consistent with the decision of the court.

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~~filed a general 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~~October 31, 2011, proposing rate ~~filing~~increases to be effective December 1, 2011. The proposed rates reflect a cost of service of $199.3 million, a rate base of $441.7 million, and a proposed cost of equity of 13.5% per year. The FERC has accepted the filed rates, and has suspended the effective date of the proposed rate increases until May 1, 2012, when the increased rates will be made effective, subject to refund. If the rates finally approved at the end of the proceeding exceed the rates that were in effect at October 31, 2011 but are less than the rates put into effect subject to refund on May 1, 2012, Supply Corporation will be required to refund the difference between the rates collected subject to refund and the final approved rates, with interest at the FERC-approved rate. If the rates approved at the end of the proceeding are lower than the rates in effect at October 31, 2011, the refund obligation will be limited to the difference between the rates in effect at October 31, 2011 and ~~bars Supply Corporation~~the rates put into effect subject to refund on May 1, 2012, with interest at the FERC-approved rate. To the extent the final FERC-approved rates are below those in effect at October 31, 2011, there is no refund for that rate differential. The final FERC-approved rates would be charged to customers only prospectively, from ~~making a general rate filing before then, with some exceptions specified in~~ the ~~settlement.~~date they go into effect.

Empire’s ~~new~~ facilities ~~(the~~known as the Empire Connector ~~project)~~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 as an interstate pipeline, in conjunction with which Empire will either justify Empire’s existing recourse rates or propose alternative rates. Empire will file this cost and revenue study before the end of March 2012.

~~-52-~~-45-

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

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.

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. The EPA is also considering other regulatory options to regulate greenhouse gas emissions from the energy industry. In April 2011, 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~~International, federal, state or regional 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. Climate change and greenhouse gas initiatives, and incentives to conserve energy or use alternative energy sources, could also reduce demand for oil and natural gas. 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.

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

New Authoritative Accounting and Financial Reporting Guidance

In May 2011, the FASB issued authoritative guidance regarding fair value measurement as a joint project with the IASB. The objective of the guidance was to bring together as closely as possible the fair value measurement and disclosure guidance issued by the two boards. The guidance includes a few updates to measurement guidance and some enhanced disclosure requirements. For all Level 3 fair value measurements, the guidance requires quantitative information about significant unobservable inputs used and a description of the valuation processes in place. The guidance also requires a qualitative discussion about the sensitivity of recurring Level 3 fair value measurements and information about any transfers between Level 1 and Level 2 of the fair value hierarchy. The new guidance also contains a requirement that all fair value measurements, whether they are recorded on the balance sheet or disclosed in the footnotes, be classified as Level 1, Level 2 or Level 3 within the fair value hierarchy. This authoritative guidance will be effective as of the Company’s second quarter of fiscal 2012. The Company is currently evaluating the impact that adoption of this authoritative guidance will have on its consolidated financial statement disclosures.

~~-53-~~

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

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

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

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:

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, title disputes, 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;

2.	Changes in laws, regulations or judicial interpretations to which the Company is subject, including those involving derivatives, taxes, safety, employment, climate change, other environmental matters, real property, and exploration and production activities such as hydraulic fracturing;

3.	Changes in the price of natural gas or oil;

4.	Uncertainty of oil and gas reserve estimates;

5.	Significant differences between the Company’s projected and actual production levels for natural gas or oil;

6.	Impairments under the SEC’s full cost ceiling test for natural gas and oil reserves;

7.	Changes in the availability, price or accounting treatment of derivative financial instruments;

Governmental/regulatory actions, initiatives and proceedings, including those involving rate cases (which address, among other things, allowed rates of return, rate design and retained natural gas), environmental/safety requirements, affiliate relationships, industry structure, and franchise renewal;

9.	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;

10.

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;

2.11.

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;

3.12.

The creditworthiness or performance of the Company’s key suppliers, customers and counterparties;

4.13.

Economic disruptions or uninsured losses resulting from major accidents, fires, severe weather, natural disasters, terrorist activities, acts of war, ~~major accidents, fires, severe weather,~~cyber attacks or pest ~~infestation or natural disasters;~~

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;

~~-54-~~

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

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;~~infestation;

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;~~

-48-

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

~~17.~~16.

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;

~~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.~~17.

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.~~18.

~~Significant changes~~Changes in ~~tax rates or policies or in rates of inflation or interest;~~demographic patterns and weather conditions;

~~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;~~

~~-55-~~

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

~~26.~~19.

The cost and effects of legal and administrative claims against the Company or activist shareholder campaigns to effect changes at the Company;

~~27.~~20.

Increasing health care costs and the resulting effect on health insurance premiums and on the obligation to provide other post-retirement benefits; or

~~28.~~21.

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 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 ~~June 30,~~December 31, 2011.

-49-

Item 4.Controls and Procedures (Concl.)

Changes in Internal ~~Controls~~Control Over Financial Reporting

There were no changes in the Company’s internal control over financial reporting that occurred during the quarter ended ~~June 30,~~December 31, 2011 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

~~-56-~~

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 –~~ 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~~2011 Form 10-K have not materially changed other than as ~~amended by Item 1A~~set forth below. The risk factors presented below supersede the risk factors having the same captions in the 2011 Form 10-K and should otherwise be read in conjunction with all of ~~Part II~~the risk factors disclosed in the 2011 Form 10-K.

The Company’s need to comply with comprehensive, complex, and sometimes unpredictable government regulations may increase its costs and limit its revenue growth, which may result in reduced earnings.

While the Company generally refers to its Utility segment and its Pipeline and Storage segment as its “regulated segments,” there are many governmental regulations that have an impact on almost every aspect of the Company’s ~~Forms 10-Q~~businesses. Existing statutes and regulations may be revised or reinterpreted and new laws and regulations may be adopted or become applicable to the Company, which may increase the Company’s costs or affect its business in ways that the Company cannot predict.

In the Company’s Utility segment, the operations of Distribution Corporation are subject to the jurisdiction of the NYPSC, the PaPUC and, with respect to certain transactions, the FERC. The NYPSC and the PaPUC, among other things, approve the rates that Distribution Corporation may charge to its utility customers. Those approved rates also impact the returns that Distribution Corporation may earn on the assets that are dedicated to those operations. If Distribution Corporation is required in a rate proceeding to reduce the rates it charges its utility customers, or to the extent Distribution Corporation is unable to obtain approval for rate increases from these regulators, particularly when necessary to cover increased costs (including costs that may be incurred in connection with governmental investigations or proceedings or mandated infrastructure inspection, maintenance or replacement programs), earnings may decrease.

-50-

Item 1A.Risk Factors (Cont.)

In addition to their historical methods of utility regulation, both the PaPUC and NYPSC have established competitive markets in which customers may purchase gas commodity from unregulated marketers, in addition to utility companies. Retail competition for gas commodity service does not pose an acute competitive threat for Distribution Corporation because in both jurisdictions it recovers its cost of service through delivery rates and charges, and not through any mark-up on the gas commodity purchased by its customers. Over the longer run, however, rate design changes resulting from further customer migration to marketer service (“unbundling”) can expose utilities such as Distribution Corporation to stranded costs and revenue erosion in the absence of compensating rate relief.

Both the NYPSC and the PaPUC have instituted proceedings for the ~~quarters ended~~purpose of promoting conservation of energy commodities, including natural gas. In New York, Distribution Corporation implemented a Conservation Incentive Program that promotes conservation and efficient use of natural gas by offering customer rebates for high-efficiency appliances, among other things. The intent of conservation and efficiency programs is to reduce customer usage of natural gas. Under traditional volumetric rates, reduced usage by customers results in decreased revenues to the Utility. To prevent revenue erosion caused by conservation, the NYPSC approved a “revenue decoupling mechanism” that renders Distribution Corporation’s New York division financially indifferent to the effects of conservation. In Pennsylvania, although a generic statewide proceeding is pending, the PaPUC has not yet directed Distribution Corporation to implement conservation measures. If the NYPSC were to revoke the revenue decoupling mechanism in a future proceeding or the PaPUC were to adopt a conservation program without a revenue decoupling mechanism or other changes in rate design, reduced customer usage could decrease revenues, forcing Distribution Corporation to file for rate relief.

In New York, aggressive generic statewide programs created under the label of efficiency or conservation continue to generate a sizable utility funding requirement for state agencies that administer those programs. Although utilities are authorized to recover the cost of efficiency and conservation program funding through special rates and surcharges, the resulting upward pressure on customer rates, coupled with increased assessments and taxes, could affect future tolerance for traditional utility rate increases, especially if natural gas commodity costs were to increase.

The Company is subject to the jurisdiction of the FERC with respect to Supply Corporation, Empire and some transactions performed by other Company subsidiaries, including Seneca Resources, Distribution Corporation and NFR. The FERC, among other things, approves the rates that Supply Corporation and Empire may charge to their natural gas transportation and/or storage customers. Those approved rates also impact the returns that Supply Corporation and Empire may earn on the assets that are dedicated to those operations. State commissions can also petition the FERC to investigate whether Supply Corporation’s and Empire’s rates are still just and reasonable, and if not, to reduce those rates prospectively. If Supply Corporation or Empire is required in a rate proceeding to reduce the rates it charges its natural gas transportation and/or storage customers, or if either Supply Corporation or Empire is unable to obtain approval for rate increases, particularly when necessary to cover increased costs, Supply Corporation’s or Empire’s earnings may decrease. The FERC also possesses significant penalty authority with respect to violations of the laws and regulations it administers. Supply Corporation, Empire and, to the extent subject to FERC jurisdiction, the Company’s other subsidiaries are subject to the FERC’s penalty authority. In addition, the FERC exercises jurisdiction over the construction and operation of facilities used in interstate gas transmission. Also, decisions of Canadian regulators such as the National Energy Board and the Ontario Energy Board could affect the viability and profitability of Supply Corporation and Empire projects designed to transport gas from New York into Ontario.

In January 2012, President Obama signed into law the Pipeline Safety, Regulatory Certainty, and Job Creation Act. The legislation increases civil penalties for pipeline safety violations and addresses matters such as pipeline damage prevention, automatic and remote-controlled shut-off valves, excess flow valves, pipeline integrity management, documentation and testing of maximum allowable operating pressure, and reporting of pipeline accidents. The legislation requires the Pipeline and Hazardous Materials Safety Administration (PHMSA) to issue or revise certain regulations and to conduct various reviews, studies and evaluations. In addition, PHMSA in August 2011 issued an Advance Notice of Proposed Rulemaking regarding pipeline safety. As described in the notice, PHMSA is considering

-51-

Item 1A.Risk Factors (Cont.)

regulations regarding, among other things, the designation of additional high consequence areas along pipelines, minimum requirements for leak detection systems, installation of emergency flow restricting devices, and revision of valve spacing requirements. Unrelated to these safety initiatives, the EPA in April 2010 issued an Advance Notice of Proposed Rulemaking reassessing its regulations governing the use and distribution in commerce of PCBs. The EPA projects that it may issue a Notice of Proposed Rulemaking by December ~~31, 2010~~2012. If as a result of new laws or regulations the Company incurs material costs that it is unable to recover fully through rates or otherwise offset, the Company’s financial condition, results of operations, and ~~March 31,~~cash flows would be adversely affected.

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 into which hedged natural gas production 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. In addition, the Company enters into certain commodity price hedges that are cleared through the NYMEX by futures commission merchants. Under NYMEX rules, the Company is required to post collateral in connection with such hedges, with such collateral being held by its futures commission merchants. The Company is exposed to the risk of loss of such collateral from occurrences such as financial failure of its futures commission merchants, or misappropriation or mishandling of clients’ funds or other similar actions by its futures commission merchants. In addition, the Company is exposed to potential hedging ineffectiveness in the event of a failure by one of its futures commission merchants or contract counterparties.

-52-

Item 1A.Risk Factors (Concl.)

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.

The Dodd-Frank Act includes provisions related to the swaps and over-the-counter derivatives markets. Certain provisions of the Dodd-Frank Act related to derivatives became effective July 16, 2011, but other provisions related to derivatives will not become effective until federal agencies (including the Commodity Futures Trading Commission (CFTC), various banking regulators and the SEC) adopt rules to implement the law. For purposes of the Dodd-Frank Act, we believe that the Company will be categorized as a non-financial end user of derivatives, that is, as a non-financial entity that uses derivatives to hedge commercial risk. Nevertheless, the rules that are being developed could have ~~not materially changed.~~a significant impact on the Company. For example, banking regulators have proposed a rule that would require swap dealers and major swap participants subject to their jurisdiction to collect initial and variation margin from counterparties that are non-financial end users, though such swap dealers and major swap participants would have the discretion to set thresholds for posting margin (unsecured credit limits). Regardless of the levels of margin that might be required, concern remains that swap dealers and major swap participants will pass along their increased capital and margin costs through higher prices and reductions in thresholds for posting margin. In addition, while the Company expects to be exempt from the Dodd-Frank Act’s requirement that swaps be cleared and traded on exchanges or swap execution facilities, the cost of entering into a non-cleared swap that is available as a cleared swap may be greater.

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

On ~~April 1,~~October 3, 2011, the Company issued a total of 4,050 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, 450 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 ~~June 30,~~December 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.

Issuer Purchases of Equity Securities

Period
   Total Number of
Shares
Purchased^(a)    Average Price
Paid per Share    Total Number of
Shares Purchased
as Part of Publicly
Announced Share
Repurchase Plans
or Programs    Maximum Number
of Shares that May
Yet Be Purchased
Under Share
Repurchase Plans
or Programs^(b)
Apr. 1 - 30, 2011
   131,782       $ 74.38       —         6,971,019
May 1 - 31, 2011
   6,269       $ 68.66       —         6,971,019
June 1 - 30, 2011
   10,980       $ 69.49       —         6,971,019
Total
   149,031       $ 73.78       —         6,971,019


Period	Total Number of Shares Purchased^(a)		Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Share Repurchase Plans or Programs		Maximum Number of Shares that May Yet Be Purchased Under Share Repurchase Plans or Programs^(b)
Oct. 1-31, 2011		6,522	$	55.52		—		6,971,019
Nov. 1-30, 2011		33,960	$	59.20		—		6,971,019
Dec. 1-31, 2011		101,778	$	57.11		—		6,971,019
Total		142,260	$	57.53		—		6,971,019

-53-

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

^(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 ~~June 30,~~December 31, 2011, the Company did not purchase any shares of its common stock pursuant to its publicly announced share repurchase program. Of the ~~149,031~~142,260 shares purchased other than through a publicly announced share repurchase program, ~~18,425~~18,727 were purchased for the Company’s 401(k) plans and ~~130,606~~123,533 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. 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.

~~-57-~~

Item 6.Exhibits

(a)

Exhibits


Exhibit Number		Description of Exhibit

—		Officer’s Certificate establishing 4.90% Notes due 2021, dated December 1, 2011 (incorporated by reference to Exhibit 4.4, Form 8-K dated December 1, 2011)

10.1		Description of performance goals under the Amended and Restated National Fuel Gas Company 2007 Annual At Risk Compensation Incentive Program and the National Fuel Gas Company Executive Annual Cash Incentive Program.

10.2		Form of Stock Appreciation Right Award Notice under the National Fuel Gas Company 1997 Award and Option Plan.

10.3		Administrative Rules of the Compensation Committee of the Board of Directors of National Fuel Gas Company, as amended and restated effective December 7, 2011.

12		Statements regarding Computation of Ratios: Ratio of Earnings to Fixed Charges for the Twelve Months Ended ~~June 30,~~December 31, 2011 and the Fiscal Years Ended September 30, ~~2007~~2008 through ~~2010.~~2011.

31.1		Written statements of Chief Executive Officer pursuant to Rule 13a-14(a) ~~or Rule~~ /15d-14(a) ~~under~~of the ~~Securities~~ Exchange ~~Act of 1934.~~Act.

31.2		Written statements of Principal Financial Officer pursuant to Rule 13a-14(a) ~~or Rule~~ /15d-14(a) ~~under~~of the ~~Securities~~ Exchange ~~Act of 1934.~~Act.

32		Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

99		National Fuel Gas Company Consolidated Statements of Income for the Twelve Months Ended ~~June 30,~~December 31, 2011 and 2010.

-54-

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 nine~~ months ended ~~June 30,~~December 31, 2011 and 2010, (ii) the Consolidated Balance Sheets at ~~June 30,~~December 31, 2011 and September 30, ~~2010,~~2011, (iii) the Consolidated Statements of Cash Flows for the ~~nine~~three months ended ~~June 30,~~December 31, 2011 and 2010, (iv) the Consolidated Statements of Comprehensive Income for the three ~~and nine~~ months ended ~~June 30,~~December 31, 2011 and 2010 and (v) the Notes to Condensed Consolidated Financial Statements.

—	Incorporated herein by reference as indicated.

~~-58-~~-55-

~~SIGNATURES~~SIGNATURE

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

NATIONAL FUEL GAS COMPANY

(Registrant)

/s/ D. P. Bauer

D. P. Bauer

Treasurer and Principal Financial Officer




/s/ K. M. Camiolo
K. M. Camiolo Controller and Principal Accounting Officer

Date:~~August 9, 2011~~February 3, 2012

~~-59-~~-56-


	June 30, 2011				September 30, 2010
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-Term Debt	$	1,049,000	$	1,209,054	$	1,249,000	$	1,423,349


	Fair Values of Derivative Instruments
	(Dollar Amounts in Thousands)
Derivatives Designated as Hedging Instruments	Gross Asset Derivatives	Gross Liability Derivatives
Derivatives Designated as Hedging Instruments	Gross Asset Derivatives	Gross Liability Derivatives
	Fair Value	Fair Value
Commodity Contracts – at June 30, 2011	$54,971	$56,331
Commodity Contracts – at September 30, 2010	$77,837	$32,813


The Effect of Derivative Financial Instruments on the Statement of Financial Performance for the Three Months Ended June 30, 2011 and 2010 (Thousands of Dollars)
Derivatives in Cash Flow Hedging Relationships	Amount of Derivative Gain or (Loss) Recognized in Other Comprehensive Income (Loss) on the Consolidated Statement of Comprehensive Income (Loss) (Effective Portion) for the Three Months Ended June 30,					Location of Derivative Gain or (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) on the Consolidated Balance Sheet into the Consolidated Statement of Income (Effective Portion)	Amount of Derivative Gain or (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) on the Consolidated Balance Sheet into the Consolidated Statement of Income (Effective Portion) for the Three Months Ended June 30,					Location of Derivative Gain or (Loss) Recognized in the Consolidated Statement of Income (Ineffective Portion and Amount Excluded from Effectiveness Testing)	Derivative Gain or (Loss) Recognized in the Consolidated Statement of Income (Ineffective Portion and Amount Excluded from Effectiveness Testing) for the Three Months Ended June 30,
	2011		2010				2011			2010			2011		2010
Commodity Contracts – Exploration & Production segment	$	25,399	$	16,445		Operating Revenue	$	(5,548	)	$	11,592	Operating Revenue	$	570	$	—
Commodity Contracts – Energy Marketing segment	$	737	$	519		Purchased Gas	$	1,793		$	238	Purchased Gas	$	—	$	—
Commodity Contracts – Pipeline & Storage segment	$	242	$	(436	)	Operating Revenue	$	—		$	—	Operating Revenue	$	—	$	—
Total	$	26,378	$	16,528			$	(3,755	)	$	11,830		$	570	$	—


Derivatives in Fair Value Hedging Relationships	Location of Derivative Gain or (Loss) Recognized in the Consolidated Statement of Income	Amount of Derivative Gain or (Loss) Recognized in the Consolidated Statement of Income for the Nine Months Ended June 30, 2011 (In Thousands)
Commodity Contracts – Energy Marketing segment⁽¹⁾	Operating Revenues	$	9,531
Commodity Contracts – Energy Marketing segment⁽²⁾	Purchased Gas	$	(638	)
Commodity Contracts – Energy Marketing segment⁽³⁾	Purchased Gas	$	(303	)

		$	8,590


(Thousands)	Three Months Ended June 30, 2010			Nine Months Ended June 30, 2010
Operating Revenues	$	2,135		$	8,411
Operating Expenses		2,177			7,021

Operating Income (Loss)		(42	)		1,390
Interest Income		1			1
Other Interest Expense		(8	)		(19	)

Income (Loss) before Income Taxes		(49	)		1,372
Income Tax Expense		8			601

Income (Loss) from Discontinued Operations	$	(57	)	$	771


Quarter Ended June 30, 2011 (Thousands)
	Utility		Pipeline and Storage		Exploration and Production		Energy Marketing		Total Reportable Segments		All Other		Corporate and Intersegment Eliminations			Total Consolidated
Revenue from External Customers	$	146,215	$	29,933	$	130,974	$	71,746	$	378,868	$	1,873	$	238		$	380,979
Intersegment Revenues	$	3,475	$	20,324	$	—	$	156	$	23,955	$	2,810	$	(26,765	)	$	—
Segment Profit:
Net Income (Loss)	$	6,328	$	4,503	$	32,784	$	1,891	$	45,506	$	2,713	$	(1,328	)	$	46,891

Nine Months Ended June 30, 2011 (Thousands)
	Utility		Pipeline and Storage		Exploration and Production		Energy Marketing		Total Reportable Segments		All Other		Corporate and Intersegment Eliminations			Total Consolidated
Revenue from External Customers	$	750,802	$	103,115	$	388,571	$	246,719	$	1,489,207	$	2,895	$	706		$	1,492,808
Intersegment Revenues	$	14,680	$	60,838	$	—	$	156	$	75,674	$	7,026	$	(82,700	)	$	—
Segment Profit:
Net Income (Loss)	$	62,399	$	24,036	$	93,455	$	9,122	$	189,012	$	34,320	$	(2,287	)	$	221,045

Quarter Ended June 30, 2010 (Thousands)
	Utility		Pipeline and Storage		Exploration and Production		Energy Marketing		Total Reportable Segments		All Other		Corporate and Intersegment Eliminations			Total Consolidated
Revenue from External Customers	$	126,326	$	32,086	$	112,802	$	72,830	$	344,044	$	7,724	$	224		$	351,992
Intersegment Revenues	$	2,653	$	19,466	$	—	$	—	$	22,119	$	1,418	$	(23,537	)	$	—
Segment Profit:
Income (Loss) from Continuing Operations	$	5,969	$	7,234	$	27,883	$	1,411	$	42,497	$	243	$	(98	)	$	42,642

Nine Months Ended June 30, 2010 (Thousands)
	Utility		Pipeline and Storage		Exploration and Production		Energy Marketing		Total Reportable Segments		All Other		Corporate and Intersegment Eliminations			Total Consolidated
Revenue from External Customers	$	707,323	$	107,560	$	328,312	$	303,103	$	1,446,298	$	27,157	$	652		$	1,474,107
Intersegment Revenues	$	13,315	$	60,289	$	—	$	—	$	73,604	$	1,418	$	(75,022	)	$	—
Segment Profit:
Income (Loss) from Continuing Operations	$	62,254	$	30,036	$	85,046	$	8,472	$	185,808	$	2,154	$	(1,221	)	$	186,741


Nine months ended June 30,
	Retirement Plan						Other Post-Retirement Benefits
	2011			2010			2011			2010
Service Cost	$	11,079		$	9,747		$	3,207		$	3,224
Interest Cost		32,007			33,231			16,413			18,763
Expected Return on Plan Assets		(44,328	)		(43,756	)		(21,873	)		(19,751	)
Amortization of Prior Service Cost		441			492			(1,282	)		(1,282	)
Amortization of Transition Amount		—			—			405			405
Amortization of Losses		26,155			16,230			17,845			19,411
Net Amortization and Deferral for Regulatory Purposes (Including Volumetric Adjustments)⁽¹⁾		(584	)		2,896			9,564			2,919

Net Periodic Benefit Cost	$	24,770		$	18,840		$	24,279		$	23,689


	Three Months Ended June 30,							Nine Months Ended June 30,
(Thousands)	2011		2010		Increase (Decrease)			2011		2010		Increase (Decrease)
Retail Sales Revenues:
Residential	$	105,001	$	88,158	$	16,843		$	545,786	$	521,202	$	24,584
Commercial		12,474		10,721		1,753			73,833		73,438		395
Industrial		807		696		111			4,951		4,579		372

		118,282		99,575		18,707			624,570		599,219		25,351

Transportation		25,016		20,909		4,107			105,380		92,112		13,268
Off-System Sales		3,976		5,486		(1,510	)		29,564		20,491		9,073
Other		2,416		3,009		(593	)		5,968		8,816		(2,848	)

	$	149,690	$	128,979	$	20,711		$	765,482	$	720,638	$	44,844


Utility Throughput
	Three Months Ended June 30,							Nine Months Ended June 30,
(MMcf)	2011		2010		Increase (Decrease)			2011		2010		Increase
Retail Sales:
Residential		8,867		7,055		1,812			54,075		50,292		3,783
Commercial		1,203		920		283			8,044		7,666		378
Industrial		79		66		13			618		512		106

		10,149		8,041		2,108			62,737		58,470		4,267

Transportation		12,335		10,530		1,805			57,916		51,957		5,959
Off-System Sales		867		1,124		(257	)		6,188		4,034		2,154

		23,351		19,695		3,656			126,841		114,461		12,380


Total Expenditures for Long-Lived Assets
Nine Months Ended June 30, (Millions)	2011			2010			Increase (Decrease)
Utility:
Capital Expenditures	$	39.4		$	39.5		$	(0.1	)
Pipeline and Storage:
Capital Expenditures		75.0	⁽¹⁾		22.2			52.8
Exploration and Production:
Capital Expenditures		473.5	⁽¹⁾⁽²⁾		273.8	⁽³⁾⁽⁴⁾		199.7
All Other:
Capital Expenditures		6.8			6.4	⁽⁴⁾		0.4

Total Expenditures from Continuing Operations	$	594.7		$	341.9		$	252.8

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Smaller Reporting Company