Exhibit 99

IPAA OGIS NY Energy Conference April 12, 2011 Exhibit 99

Safe Harbor For Forward Looking Statements This presentation may contain "forward-looking statements" as defined by the Private Securities Litigation Reform Act of 1995, including statements regarding future prospects, plans, performance and capital structure, anticipated capital expenditures and completion of construction projects, 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. Forward-looking statements involve risks and uncertainties, which could cause actual results or outcomes to differ materially from those expressed in the forward-looking statements. The Company's expectations, beliefs and projections contained herein are expressed in good faith and are believed to have a reasonable basis, but there can be no assurance that such expectations, beliefs or projections will result or be achieved or accomplished. In addition to other factors, the following are important factors that could cause actual results to differ materially from results referred to in the forward-looking statements: 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; 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; the creditworthiness or performance of the Company's key suppliers, customers and counterparties; economic disruptions or uninsured losses resulting from terrorist activities, acts of war, major accidents, fires, hurricanes, other severe weather, pest infestation or other natural disasters; 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; 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; uncertainty of oil and gas reserve estimates; significant differences between the Company's projected and actual production levels for natural gas or oil; significant changes in market dynamics or competitive factors affecting the Company's ability to retain existing customers or obtain new customers; changes in demographic patterns and weather conditions; 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; impairments under the SEC's full cost ceiling test for natural gas and oil reserves; changes in the availability and/or cost of derivative financial instruments; changes in the 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; other changes in price differentials between similar quantities of oil or natural gas having different quality, heating value, geographic location or delivery date; changes in the projected profitability of pending or potential projects, investments or transactions; significant differences between the Company's projected and actual capital expenditures and operating expenses; delays or changes in costs or plans with respect to the Company's 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; 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; unanticipated impacts of restructuring initiatives in the natural gas and electric industries; ability to successfully identify and finance acquisitions or other investments and ability to operate and integrate existing and any subsequently acquired business or properties; 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; significant changes in tax rates or policies or in rates of inflation or interest; 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; changes in accounting principles or the application of such principles to the Company; the cost and effects of legal and administrative claims against the Company or activist shareholder campaigns to effect changes at the Company; increasing health care costs and the resulting effect on health insurance premiums and on the obligation to provide other post-retirement benefits; or increasing costs of insurance, changes in coverage and the ability to obtain insurance. Forward-looking statements include estimates of oil and gas quantities. Proved oil and gas reserves are those quantities of oil and gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible under existing economic conditions, operating methods and government regulations. Other estimates of oil and gas quantities, including estimates of probable reserves, possible reserves, and resource potential, are by their nature more speculative than estimates of proved reserves. Accordingly, estimates other than proved reserves are subject to substantially greater risk of being actually realized. Investors are urged to consider closely the disclosure in our Form 10-K available at www.nationalfuelgas.com. You can also obtain this form on the SEC's website at www.sec.gov. For a discussion of the risks set forth above and other factors that could cause actual results to differ materially from results referred to in the forward-looking statements, see "Risk Factors" in the Company's Form 10-K for the fiscal year ended September 30, 2010 and the Company's Form 10-Q for the period ended December 31, 2010. The Company disclaims any obligation to update any forward- looking statements to reflect events or circumstances after the date hereof or to reflect the occurrence of unanticipated events.

National Fuel Gas Company Business Segment Reporting Publicly Traded Holding Company NYSE symbol - NFG Reporting Segments Operating Subsidiaries

4 IPAA OGIS NY - April 12, 2011

Net Income from Continuing Operations Excluding Items Impacting Comparability (1) National Fuel Gas Company A reconciliation to GAAP Net Income is included at the end of this presentation. $213.5 Million Twelve Months Ended December 31, 2010 E&P $110.1 MM 51.6%

National Fuel Gas Company Capital Expenditures(1) from Continuing Operations A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation.

National Fuel Gas Company Capital Structure $2.824 Billion(1) at December 31, 2010 Forecasted Capital Structure(2) at September 30, 2011 At December 31, 2010, Comprehensive Shareholders' Equity, Long-Term Debt and the Current Portion of Long-Term Debt totaled $2.824 Billion as presented on the Company's Balance Sheet, of which $0.899 Billion was Long-Term Debt, $0.150 Billion was the Current Portion of Long-Term Debt, $0.021 Billion was Short-Term Debt and $1.755 Billion was Comprehensive Shareholders' Equity At September 30, 2011, forecasted Total Capitalization is $3.018 Billion, of which $0.899 Billion is Long-Term Debt, $0.150 Billion is the Current Portion of Long-Term Debt, $0.060 Billion is Short-Term Debt and $1.909 Billion is Comprehensive Shareholders' Equity

Exploration & Production Seneca Resources Corporation

Exploration & Production Fiscal Year End Proved Reserves(1) West - California Reserves: 333 Bcfe (47%) (55.5 MMBoe) Gulf of Mexico Reserves: 34 Bcfe (5%) East - Appalachia Reserves: 333 Bcfe (48%) At September 30, 2010 Total Proved Reserves: 700 Bcfe

Exploration & Production Fiscal 2010 Oil/Gas Mix 700 Bcfe(1) At September 30, 2010 49.7 Bcfe $425.6 Million

Exploration & Production Capital Expenditures by Region Does not include the $34.9MM acquisition of Ivanhoe's US-based assets in California, as this was accounted for as an investment in subsidiaries on the Statement of Cash Flows, and was not included in Capital Expenditures. (1)

Exploration & Production Annual Production by Region 36% 36% Marcellus production in Fiscal 2012 could equal the entire company production in Fiscal 2011

Exploration & Production California

Seneca's California Properties South Lost Hills 1,830 BOEPD Monterey Shale Primary 216 Active Wells Sespe 990 BOEPD Sespe Formation Primary 193 Active Wells North Lost Hills 1,235 BOEPD Tulare & Etchegoin Formation Primary & Steamflood 181 Active Wells North Midway Sunset 4,050 BOEPD Potter & Tulare Formation Steamflood 703 Active Wells South Midway Sunset 680 BOEPD Antelope Formation Steamflood 81 Active Wells

California Average Daily Production Modest capital spending to maintain production Pursue additional bolt-on acquisitions 2011 Plans: CapEx - $40 MM 50 Development wells Two 5-acre in-fill wells at Sespe

California Fiscal Year 2011 Sespe Field Development Plans First drilling for Seneca at Sespe since 1991 Will drill six wells during this fiscal year Wells to be drilled at 10-acre spacing: 4 wells Test wells to be drilled at 5-acre spacing: 2 wells If successful, 5-acre down-spacing could add substantial new reserves and resource potential

Gulf of Mexico Exploration & Production

Gulf of Mexico Planned Divestiture of Offshore Assets On March 9, 2011, Seneca entered into an agreement to sell its offshore Gulf of Mexico oil and natural gas producing properties Sale price: $70 million Effective Date: January 1, 2011 Gulf offshore proven reserves at January 1, 2011: ~30 Bcfe Expected to close by the end of April 2011 No gain or loss is expected as proceeds will be applied against Seneca's full cost pool so as to reduce its capitalized costs Proceeds will be redeployed to long-term growth opportunities in the Marcellus Shale

East Division Exploration & Production

East Division Average Daily Production Rapid growth in the East Division as Marcellus is ramping up

Marcellus Shale Seneca's Pennsylvania Acreage Seneca Resource Acreage Position 745,000 Net Acres in the heart of the PA Marcellus fairway Risked Resource Potential: 8-15 TCFE 80% Fee - Seneca owns the minerals No lease expiration 94% Average NRI SRC Fee Acreage

Marcellus Shale Seneca's Development Areas SRC Fee Acreage Eastern Development Area (Mostly Leased) Western Development Area (Mostly Fee and HBP)

Marcellus Shale Eastern Development Area Covington Area - Full Development 37 Wells Drilled; 27 Producing Gross Prod: (As of 3/22/11): 110 MMCFD 2011: 16 Wells Planned DCNR Block 100 1st Well IP: 15.8 MMCFD 2011: 6 Wells Planned First Production: Fall 2011 Initial Test Wells Drilling / Fracing SRC Fee Acreage DCNR Block 595 - Full Development 4 Wells Drilled; 4 Producing Gross Prod: (As of 3/22/11): 15 MMCFD 2011: 10-15 Wells Planned Tioga/Lycoming/Potter 55,000 Acres Potential: 2 Tcf

Marcellus Shale Longer Lateral EDA Wells Outpacing 6 Bcf Typecurve Chart data represents horizontal well production from wells with lateral lengths greater than 3,500 feet (1)

Marcellus Shale Western Development Area - Activity EOG Contributed JV Acreage SRC Contributed JV Acreage Seneca Operated EOG Operated Punxy Area - Full Development EOG Operated 35 Wells Drilled; 21 Producing Gross Production (As of 3/22/11): 45 MMCFD 2011: 30+ Wells Planned Owl's Nest Area Seneca Operated 2 New Wells Completed IP Rates: 4.0 - 4.5 MMCFD Approx. Outline of JV Acreage 200,000 Gross Acres Seneca 50% W.I. (Avg. 58% NRI) Beechwood Area Seneca Operated 3 Wells Drilled

87 Marcellus Shale Target Zone Example Gamma Ray Pay/Res Resistivity Density/Neutron Phi/Sw/TOC Mineralogy Brittleness Ko Optimal Target Zone Marcellus Interval Important to Find Ideal Target Must account for the variable rock quality and geomechanical profile Major factor in quality of Fracture Stimulation

87 Marcellus Shale Owl's Nest: Pad B 3H - Target Landing Depth 11 of 20 Stages in Target Interval 15' Target Interval Wellbore in zone Frac Stages

Marcellus Shale Marcellus Net Production Seneca Operated EOG JV In early March 2011, Marcellus net production reached: 120 MMcfe per day

Marcellus Shale Centralized Water System Recovering water discharged from an abandoned coal mine which was adversely impacting a local trout stream Authorized by SRBC to withdraw approximately 500,000 gallons per day of mine discharge Water pipeline system supplies frac water for Seneca in Tioga County (90 wells) Can supply water for 3 fracs per month System Cost: ~$3.7 Million Cost Savings: ~$120,000 per well Pay Out: 31 Wells Other Benefits: Improved stream quality Substantial reduction of water truck activity No need to withdraw water elsewhere

Utica Shale Source rock maturation status based on combined CAI to Ro regression equation. (Trenton-Black River Research Consortium, 2006) Seneca Acreage

Seneca Resources Evaluation of JV Opportunities Seneca's Marcellus joint venture goals: Ramp up development faster than current growth plans Bring forward the earnings stream, where a minority-interest partner pays a significant portion of the early drilling costs, enhancing shareholder value Continue operating across most of its acreage position Seneca continues to have active and ongoing discussions with multiple and diverse potential partners Several companies have expressed significant interest Anticipate narrowing field of potential partners in April Seneca will only consider joint venture opportunities that management believes will enhance shareholder value

National Fuel Gas Company Key Takeaways High-Quality Marcellus Acreage Position 745,000 net acres with a resource potential of 8-15 Tcfe Fee ownership results in superior economics Rapid Growth: 0 - 120 MMCFD in 18 months Balanced Business Model Regulated segments support dividend and are not sensitive to commodity prices Sizable oil production provides earnings stability Strong Financial Position Simple balance sheet Well capitalized Significant internally generated cash flows

Corporate & Financial Highlights National Fuel Gas Company

National Fuel Gas Company Dividend Growth $1.38 $0.19 Compound Annual Growth Rate 5.1% National Fuel has had 108 uninterrupted years of dividend payments and has increased its dividend for 40 consecutive years

National Fuel Gas Company Peer Group Comparisons National Fuel's diversified business model continues to generate long-term outperformance versus its peer groups by limiting downside risk through economically challenging times and capturing upside growth in an expanding market 1-Year Total Return Peer Group Total Return National Fuel 74% Utility Peers 44% Diversified Peers 3% E&P Peers -2% 3-Year Total Return Peer Group Total Return National Fuel 166% Diversified Peers 57% Utility Peers 56% E&P Peers 55% 5-Year Total Return Peer Group Total Return National Fuel 53% E&P Peers 46% Diversified Peers 36% Utility Peers 23% All returns are for the period starting at the close on March 31, 20XX and ending April 1, 2011. Calculated utilizing Bloomberg L.P. software and peer group averages calculated using an arithmetic mean Diversified Peers: EGN, EP, EQT, MDU, WMB; Utility Peers: AGL, ATO, CPK, NI, NJR, NWN, SWX, WGL; E&P Peers: BRY, CHK, CNX, COG, CRZO, EOG, PETD, PVA, RRC, SFY, SM, SWN, UNT

National Fuel Gas Company Fiscal Year 2011 Earnings Guidance - Key Drivers(1) FY 2011 EPS $2.70 to $2.95 Utility Operating Expense: ? 3% to 5% PA Normal Weather Pipeline & Storage Operating Expense: ? 3% to 5% Transportation Revenue: ? $7.5 Million Project Development Costs (O&M): $7 Million Exploration & Production Production - ? 36% DD&A: $2.05 to $2.15 per Mcfe LOE: $1.10 to $1.35 per Mcfe G&A: $41 - $44 Million FY2010 Operating Results $2.65(2) ? ? NYMEX Pricing: Gas: $4.00/MMBtu ? Oil: $80.00/Bbl The Earnings Guidance is current as of March 9, 2011 Excludes gain on disposal of discontinued operations of $0.07 and earnings from discontinued operations of $0.01; including these items GAAP earnings were $2.73. Corporate & All Other Sale of Horizon Power, Inc. Investments: $0.37/Sh Midstream Earnings per Share: $0.05 to $0.10

National Fuel Gas Company Seneca Oil and Gas Hedge Positions For fiscal year 2011, Seneca has hedged 56% of its remaining forecasted production NYMEX Strip Prices (at 03/08/11) Natural Gas Oil Fiscal 2011(1) $3.98 $95.53 Fiscal 2012 $4.59 $105.74 Fiscal 2013 $5.04 $102.93 The NYMEX strip prices for fiscal year 2011 include the settlement prices for the October 2010 through March 2011 contracts. Natural Gas Swaps Volume (Bcf) Average Hedge Price Fiscal 2011 21.4 $6.07 / Mcf Fiscal 2012 21.1 $6.32 / Mcf Fiscal 2013 9.6 $5.90 / Mcf Oil Swaps Volume (MMBbl) Average Hedge Price Fiscal 2011 1.3 $70.93 / Bbl Fiscal 2012 1.5 $75.80 / Bbl Fiscal 2013 0.6 $80.47 / Bbl

Utility Segment National Fuel Gas Distribution Corporation

(1) Calculated using Average Total Comprehensive Shareholder Equity. Utility Return on Equity (1)

New York Revenue Decoupling Customer Choice / POR Merchant Function Charge 90/10 Sharing (large volume users) Weather Normalization Low Income Rates Pennsylvania Low Income Rates Customer Choice / POR Merchant Function Charge Under Consideration: Revenue Decoupling Rate Mechanisms Utility

National Fuel Gas Supply Corporation Empire Pipeline, Inc. National Fuel Gas Midstream Corporation Pipeline & Storage / Midstream

LAMONT COMPRESSOR STATION PHASE I & II COVINGTON GATHERING SYSTEM TROUT RUN GATHERING SYSTEM WEST TO EAST OVERBECK TO LEIDY LAMONT COMPRESSOR STATION PHASE I & II TIOGA COUNTY EXTENSION LINE "N" EXPANSION PIPELINE & STORAGE / MIDSTREAM EXPANSION INITIATIVES NORTHERN ACCESS EXPANSION Seneca Drilling Activity EOG JV Drilling Activity W2E Overbeck to Leidy Northern Access Expansion Expansion Projects 43 CENTRAL TIOGA COUNTY EXTENSION LINE "N" 2012 EXPANSION IPAA OGIS NY - April 12, 2011

Pipeline & Storage/Midstream Expansion Initiatives Project Name Capacity (Dth/D) Est. CapEx In-Service Date Market Status Covington Gathering System 145,000 $16 MM 11/17/09 Fully Subscribed Completed - Flowing into TGP 300 Line Lamont Compressor Station 40,000 $6 MM 6/15/10 Fully Subscribed Completed - Flowing into TGP 300 Line Lamont Phase II Project 50,000 $8 MM ~ 06/2011 Fully Subscribed Construction began March 2011 Line "N" Expansion 160,000 $20 MM ~ 09/2011 Fully Subscribed Construction began February 2011 Tioga County Extension 350,000 $50 MM ~ 09/2011 Fully Subscribed Certificate expected during March/April Trout Run Gathering System 300,000 $33 MM Fall 2011 85% Subscribed Preliminary work has begun. Northern Access Expansion 320,000 $62 MM ~11/2012 Fully Subscribed Certificate filed in March 2011 Line "N" 2012 Expansion ~195,000 $39 MM ~ 11/2012 76% Subscribed Negotiating for additional capacity. Planned FERC 7(c) filing - Summer 2011. West to East ~425,000 $260 MM Late 2013 29% Subscribed Pursuing post-Open Season requests for remaining 300,000 Dth/day Central Tioga County Extension 365,000 Up to $135 MM 2013/ 2014 Open Season Closed Developing facility design and cost estimate

Pipeline & Storage Challenges & Opportunities NFGSC Contract Turnbacks Supply has received capacity turnbacks on expiring contracts, decreasing future revenue by: FY11: ~$7.5 Million FY12: ~$4-6 Million Empire Unsold Capacity ~100,000 Dth/d of capacity remains unsold after the construction of the Empire Connector in 2008 Expansion Projects Both Supply and Empire have significant pipeline expansion projects planned to transport gas out of the Marcellus. Yearly revenue from these expansion projects is forecasted to total: FY11: ~$0.2 Million FY12: ~$32.0 Million Challenges Opportunities

Midstream Corporation Trout Run Gathering System - Lycoming County Capacity: 300,000 Dth/d Will Interconnect with Transco Pipelines in Lycoming County Seneca Resources will be the anchor shipper Estimated In-Service: Fall 2011 Interstate Pipeline Gathering System Transco

Exploration & Production Seneca Resources Corporation

Exploration & Production Fiscal 2010 Annual Production West - California Production: 19.8 Bcfe (40%) (3.3 MMBoe) Gulf of Mexico Production: 13.4 Bcfe (27%) East - Appalachia Production: 16.5 Bcfe (33%) Total Production: 49.7 Bcfe

Marcellus Shale Pennsylvania Acreage Holdings EOG Contributed JV Acreage SRC Contributed JV Acreage

Marcellus Shale Gross Horizontal Wells Drilled per Year Marcellus Horizontal Rig Count Current Rig Count: Seneca : 4 Rigs EOG : 2 Rigs Additional Seneca Rigs Scheduled: 5th Rig: Spring/Summer 2011 6th Rig: Fall 2011

Marcellus Shale Transportation Capacity Eastern Development Area Covington Gathering System: 150,000 Dth/d into TGP 300 Provides capacity for DCNR Tract 595 and Covington in Tioga county Firm sales of 100,000 Dth/d thru October 31, 2011 Trout Run Gathering System: 200,000 - 250,000 Dth/d into Transco (In-Service: Fall 2011) Provides capacity for DCNR Tract 100 in Lycoming county Tennessee Gas Pipeline: 50,000 Dth/d of firm capacity to Niagara Provides capacity for Covington, DCNR Tract 595 and DCNR Tract 007 Western Development Area National Fuel Gas Supply Corporation: ~100,000 Dth/d through 2013 (As of November 2011 ) Provides capacity to acreage in Elk, Cameron, McKean and Potter counties Supply's West to East project will create additional capacity in 2013 and beyond Seneca continues to pursue long-term firm capacity and sales contracts on many of the interstate pipeline networks running throughout the Marcellus region

Marcellus Shale Decline Curve - 6.0 BCF Estimated Ultimate Recovery (EUR) Category Type Curve Parameters Initial Rate 7,250 MCF/D Average first year decline 72% Final decline 6% Hyperbolic Coefficient 1.4 Abandonment rate 60 MCF/D Average first month rate 6,670 MCF/D Average first year rate 3,560 MCF/D EUR 6.0 BCF

Marcellus Shale Pre-Tax IRR Comparison at NYMEX of $4.00/MMBtu Description EUR Net Working Interest Net Revenue Interest Well Costs ($ Millions) Well Costs ($ Millions) Description EUR Net Working Interest Net Revenue Interest $6.0 $6.4 Seneca - EDA Well 8 Bcf 100% 85% 73% 63% Seneca - EDA Well 6 Bcf 100% 85% 40% 34% Description EUR Net Working Interest Net Revenue Interest Well Costs ($ Millions) Well Costs ($ Millions) Description EUR Net Working Interest Net Revenue Interest $5.0 $6.0 Seneca - EOG JV Well 4 Bcf 50% 60% 44% 29% Seneca - WDA Well 4 Bcf 100% 100% 28% 19% Eastern Development Area Western Development Area Seneca is in active development within the Eastern Development Area. It is currently testing various well and completion designs in its Western Development Area and expects to see results continue to improve over time.

Marcellus Shale Water Handling & Recycling Characterization Centralized Impoundment Stream Coal Mine Drainage Water Well Well 1 Well 2 Well 3 Frac Tanks Flowback Well 4 Well 5 Well 6 Production Tank Etc. Etc. Treatment Landfill Disposal of Solids Freshwater sources are piped to a centralized impoundment and blended in subsequent fracs with flowback and produced fluids. Essentially all water can be recycled in an active operation through this approach. Ultimately, production fluids will need to be disposed of and any resultant solids will be landfilled. Flowback and production waters handled similarly to Wells 1, 2 and 3.

National Fuel Gas Company Comparable GAAP Financial Measure Slides and Reconciliations This presentation contains certain non-GAAP financial measures. For pages that contain non-GAAP financial measures, pages containing the most directly comparable GAAP financial measures and reconciliations are provided in the slides that follow. The Company believes that its non-GAAP financial measures are useful to investors because they provide an alternative method for assessing the Company's operating results in a manner that is focused on the performance of the Company's ongoing operations. The Company's management uses these non-GAAP financial measures for the same purpose, and for planning and forecasting purposes. The presentation of non-GAAP financial measures is not meant to be a substitute for financial measures prepared in accordance with GAAP.

Reconciliation of GAAP Net Income to Income From Continuing Operations
Excluding Items Impacting Comparability
($ Thousands)

										12 Mos. Ended
	FY 2008			FY 2009			FY 2010			12/31/2010
GAAP Net Income
E&P Segment GAAP Net Income	$	146,612		$	(10,238	)	$	112,531		$	110,124
P&S Segment GAAP Net Income		54,148			47,358			36,703			34,927
Utility Segment GAAP Net Income		61,472			58,664			62,473			62,450
Marketing Segment GAAP Net Income		5,889			7,166			8,816			8,656
Corporate & All Other GAAP Net Income		607			(2,242	)		5,390			3,801
Total GAAP Net Income	$	268,728		$	100,708		$	225,913		$	219,958
Discontinued Operations
(Income) Loss from Operations, Net of Tax (Corporate & All Other)	$	(1,821	)	$	2,776		$	(470	)	$	(196	)
Gain on Disposal, Net of Tax (Corporate & All Other)		—			—			(6,310	)		(6,310	)
(Income) Loss from Operations, Net of Tax (Exploration & Production)		—			—			—			—
Gain on Disposal, Net of Tax (Exploration & Production)		—			—			—			—
(Income) Loss from Discontinued Operations, Net of Tax	$	(1,821	)	$	2,776		$	(6,780	)	$	(6,506	)
Items Impacting Comparability
Reversal of reserve for preliminary project costs (P&S)	$	—		$	—		$	—		$	—
Resolution of purchased gas contingency (Marketing)		—			—			—			—
Discontinuance of hedge accounting (P&S)		—			—			—			—
Gain on sale of turbine (Corporate & All Other)		(586	)		—			—			—
Gain on life insurance policies (Corporate & All Other)		—			(2,312	)		—			—
Impairment of investment partnership (Corporate & All Other)		—			1,085			—			—
Impairment of oil and gas properties (E&P)		—			108,207			—			—
Total Items Impacting Comparability	$	(586	)	$	106,980		$	—		$	—
Income from Continuing Operations excluding Items Impacting Comparability
E&P Segment Operating Income	$	146,612		$	97,969		$	112,531		$	110,124
P&S Segment Operating Income		54,148			47,358			36,703			34,927
Utility Segment Operating Income		61,472			58,664			62,473			62,450
Marketing Segment Operating Income		5,889			7,166			8,816			8,656
Corporate & All Other Operating Income		(1,800	)		(693	)		(1,390	)		(2,705	)
Total Income from Continuing Operations excluding Items Impacting Comparability	$	266,321		$	210,464		$	219,133		$	213,452

Reconciliation of Segment Capital Expenditures to
Consolidated Capital Expenditures
($ Thousands)

												FY 2011		FY 2012
	FY 2007		FY 2008			FY 2009			FY 2010			Forecast		Forecast
Capital Expenditures from Continuing Operations
Exploration & Production Capital Expenditures	$	146,687	$	192,187		$	188,290		$	398,174		$	600,000-655,000	$	685,000-800,000
Pipeline & Storage Capital Expenditures		43,226		165,520			52,504			37,894		$	100,000-150,000	$	100,000-135,000
Utility Capital Expenditures		54,185		57,457			56,178			57,973		$	55,000-60,000	$	55,000-60,000
Marketing, Corporate & All Other Capital Expenditures		3,414		1,614			9,829			7,311		$	25,000-30,000	$	5,000-15,000
Total Capital Expenditures from Continuing Operations	$	247,512	$	416,778		$	306,801		$	501,352		$	780,000-895,000	$	845,000-1,010,000
Capital Expenditures from Discountinued Operations
Exploration & Production Capital Expenditures	$	29,129	$	—		$	—		$	—		$	—	$	—
All Other Capital Expenditures		87		131			216			150
Total Capital Expenditures from Discontinued Operations	$	29,216	$	131		$	216		$	150		$	—	$	—
Plus (Minus) Accrued Capital Expenditures
Exploration & Production FY 2010 Accrued Capital Expenditures	$	—	$	—		$	—		$	(55,546	)	$	—	$	—
Exploration & Production FY 2009 Accrued Capital Expenditures		—		—			(9,093	)		9,093			—		—
Pipeline & Storage FY 2008 Accrued Capital Expenditures		—		(16,768	)		16,768			—			—		—
All Other FY 2009 Accrued Capital Expenditures		—		—			(715	)		715			—		—
Total Accrued Capital Expenditures	$	—	$	(16,768	)	$	6,960		$	(45,738	)	$	—	$	—
Elimintations	$	—	$	(2,407	)	$	(344	)	$	—		$	—	$	—
Total Capital Expenditures per Statement of Cash Flows	$	276,728	$	397,734		$	313,633		$	455,764		$	780,000-895,000	$	845,000-1,010,000