Exhibit 99

Fiscal Year 2008 Review November 2008

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 their effect on the Company's ability to obtain financing on acceptable terms for working capital, capital expenditures and other investments; occurrences affecting the Company's ability to obtain financing under credit lines or other credit facilities or through the issuance of commercial paper, other short-term notes or debt or equity securities, 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; economic disruptions caused by terrorist activities, acts of war or major accidents; changes in actuarial assumptions, the interest rate environment and the return on assets for the Company's retirement plan and post-retirement benefit plans, which can affect future funding obligations and costs and plan liabilities; changes in demographic patterns and weather conditions, including the occurrence of severe weather such as hurricanes; 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 or the valuation of the Company's natural gas and oil reserves; uncertainty of oil and natural gas reserve estimates; ability to successfully identify, drill for and produce economically viable natural gas and oil reserves, including shortages, delays or unavailability of equipment and services required in drilling operations; significant changes from expectations in the Company's actual production levels for natural gas or oil; changes in the availability and/or price of derivative financial instruments; changes in the price differentials between various types of oil; inability to obtain new customers or retain existing ones; significant changes in competitive factors affecting the Company; changes in laws and regulations to which the Company is subject, including tax, environmental, safety and employment laws and regulations; governmental/regulatory actions, initiatives and proceedings, including those involving acquisitions, financings, rate cases (which address, among other things, allowed rates of return, rate design and retained natural gas), affiliate relationships, industry structure, franchise renewal, and environmental/safety requirements; unanticipated impacts of restructuring initiatives in the natural gas and electric industries; significant changes from expectations in actual capital expenditures and operating expenses and unanticipated project delays or changes in project costs or plans; the nature and projected profitability of pending and potential projects and other investments, and the ability to obtain necessary governmental approvals and permits; ability to successfully identify and finance acquisitions or other investments and ability to operate and integrate existing and any subsequently acquired business or properties; impairments under the SEC's full cost ceiling test for natural gas and oil reserves; changes in the market price of timber and the impact such changes might have on the types and quantity of timber harvested by the Company; 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 post-retirement benefits; or increasing costs of insurance, changes in coverage and the ability to obtain insurance. For a discussion of these risks 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, 2007 and Forms 10-Q for the quarters ended March 31, 2008 and June 30, 2008. 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

National Fuel Gas Company Net Plant by Segment $3,154 Million At September 30, 2008 $2,878 Million At September 30, 2007 All Other $105 MM 3.3% All Other $114 MM 4.0%

National Fuel Gas Company Expenditures for Long-Lived Assets(1) (1) Capital Expenditures exclude all Discontinued Operations (2) Amount for quarter and year ended September 30, 2008 includes $16.8 MM of accrued capital expenditures related to the Empire Connector project. This amount has been excluded from the Consolidated Statement of Cash Flows at September 30, 2008 since it represents a non-cash investing activity at that date

National Fuel Gas Company Capital Expenditures(1) by Segment Utility Pipeline & Storage Exploration & Production (1) Capital Expenditures exclude all Discontinued Operations

National Fuel Gas Company Net Cash Provided by Operating Activities per Diluted Share Calculated using Operating Cash Flow from Statement of Cash Flows, divided by Weighted Average Shares Outstanding at September 30

National Fuel Gas Company Net Income from Continuing Operations(1) Timber $0.1 MM Energy Mkt. $5.9 MM 2.2% $268.7 Million 12 Months Ended 9/30/08 Excludes income from discontinued operations and any gain/loss on disposal of discontinued operations Corp. & All Other $0.5 MM

National Fuel Gas Company Dividend Growth Compound Annual Growth Rate 5.2% $1.30 $0.19

National Fuel Gas Company Share Price Appreciation Price as of 9/30/08 $42.18 1988-2008 Since 10/1/08 Price as of 11/7/08 $32.69

National Fuel Gas Company Total Shareholder Returns(1) (1) Total Return calculated by Bloomberg on a quarterly basis from 4Q FY 2003 to 4Q FY2008

National Fuel Gas Company Share Price vs. Commodity Price (1) SPDR S&P Oil & Gas Exploration & Production ETF (Ticker: XOP) (1)

National Fuel Gas Company Public Utilities Fortnightly Ranked the 3rd best energy company in 2008 Based on the 3-year averages of: Profit Margin Dividend Yield FCF, ROE, ROA Sustainable Growth Consistently in the Top 10 best energy companies (2006-2008) "National Fuel Gas ... strongly positioned in gas markets from the well to the burner tip."

Pipeline & Storage National Fuel Gas Supply Corporation Empire State Pipeline

Pipeline & Storage (1) Excludes SFAS 88 settlement loss of -$0.02 (2) Excludes base gas sale of $0.03 and gain associated with insurance proceeds of $0.05 (3) Excludes reversal of reserve for preliminary project costs of $0.06, and discontinuance of Hedge Accounting of $0.02 Diluted Earnings per Share (Before Items Impacting Comparability)

Pipeline & Storage Empire Connector

Pipeline & Storage Empire Connector Upstream Receipts on Empire Pipeline with Deliveries to Millennium @ Corning, New York

35 Empire Connector In-Service prior to Millenium Pipeline completion West to East Proposed pipeline project Storage Expansion Increase Storage Capacity by 8.5 Bcf

Utility Segment National Fuel Gas Distribution Corporation

Utility (1) Excludes SFAS 88 settlement loss of -$0.03 (2) Excludes out-of-period adjustment to symmetrical sharing of $0.03 Diluted Earnings per Share (Before Items Impacting Comparability)

41

Utility Average Use per Residential Customer

Utility Accounts Receivable - Customer $1,262 Average Annual Residential Bill

Utility Keys to Continued Success Conservation Incentive Program

Exploration & Production Seneca Resources Corporation

Exploration & Production Seneca Resources

Exploration & Production Balanced Reserve Portfolio Proved Reserves @9/30 491 Bcfe 503 Bcfe West - California Reserves: 339 Bcfe (57 Mmboe) 67% Gulf of Mexico Reserves: 33 Bcfe 7% East - Appalachia Reserves: 131 Bcfe 26%

Exploration & Production Balanced Portfolio 57 MMBOE (339 Bcfe) - Proved Reserves 51.5 Mmcfe/d - Daily Production Balance d Portfoli o 131 Bcfe - Proved Reserves 234 Bcfe - 3P Reserves (Prvd + Prob + Poss) 670 Bcfe - Upper Devonian prospective resources 725,000 Acres - Prospective Marcellus Shale 21.6 Mmcfe/d - Daily Production Growt h Cash Flow Opportunisti c 33 Bcfe - Proved Reserves 38.5 Mmcfe/d - Daily Production 5 - Recent Discoveries

Exploration & Production Capital Expenditures(1) Major shift in capital allocation from higher-risk exploration to lower-risk development will lead to improved Finding & Development costs $20 8 $17 5 $172 $285 East 2006 2007 2008 2009E 13% 22% 36% 69% West 2006 2007 2008 2009E 17% 23% 26% 19% Gulf of Mexico 2006 2007 2008 2009E 50% 38% 38% 12% Increased Focus Stable Spending Reduced Focus (1) Excluding acquisitions

1. Replaced 130% of Production Exploration & Production Fiscal Year 2008 Results 2. Replaced 361% of Appalachian Production 3. Reduced F&D Costs to $3.82/Mcf 4. Grew Production by 4% 5. Net Income = $1.74/Share

Exploration & Production Annual Production by Division

Exploration & Production Appalachian Basin

Appalachian Basin Continued Upper Devonian Success 2008 Shallow Drilling Program

Appalachian Basin Reserves and Potential Proved Reserves 2P Reserves 3P Reserves Upper Devonian Reserve Base Replaced 361% of production Proved Reserves up 19% 670 Bcfe - Additional Resource Base

Appalachian Basin Upper Devonian - Development Drilling

Appalachian Basin 71 Upper Devonian Drilling Program Detailed Geologic work has improved per well reserves and success rates Accelerating Reserve additions each year (excludes PUDs): 2005 - 5.8 Bcfe 2006 - 11.8 Bcfe 2007 - 20.8 Bcfe 2008 - 24.2 Bcfe

Appalachian Basin Marcellus Shale Acreage SRC Minerals EOG Minerals Seneca - High Bidder DCNR Leases 24,000 Acres Marcellus Shale Fairway Seneca Resources - Marcellus Position ~725,000 Prospective Acres 450,000 High-Graded Acres

Appalachian Basin Marcellus - EOG JV Drilling Update Horizontal Well Summary Drilling Summary 2009: 10+ Anticipated Horizontal Wells

Appalachian Basin EOG JV Modifications Terms Modifications Prospect Selections Timeframe EOG prospect box selection to occur March 2009 (Originally - December 2011) Prospect Selection More flexibility Total Acreage Unchanged - Remains at 200,000 Acres (EOG can earn 50%) Drilling Requirements Unchanged New terms allow Seneca Resources to control remaining 100% acreage beginning in March 2009

Appalachian Basin Marcellus Shale Evaluation Depth TVD: 5,000' - 8,000' Thickness 50' - 200' Total Organic Content (TOC) 2% - (>) 10% Thermal Maturity 1% - 3% Effective Porosity 3% - 12% Pressure (psi/foot) 0.43 - 0.65 Water Saturation 12% - 35% Gas-in-Place (Bcfe/Section) 30 - 150 Anticipated EUR/Horizontal Well (Bcfe) 1.0 - 3.0

Appalachian Basin PA State Forest Lease Sale - 9/3/08 Seneca was the high bidder on 4 of 6 bids Total of the 4 high bids - $74 million 10-year lease terms Lycoming & Tioga Counties Marcellus Shale impact 150-200 potential horizontal well locations Acreage is relatively contiguous in the core area of the play where the shale is thick

Appalachian Basin Seneca Marcellus Operations New DCNR Leases Adjusted EOG JV Terms Seneca as a major Marcellu s Operato r 500,000 net acres to evaluate as operator Plan to drill 8-10 vertical "test" wells, beginning January '09 Begin horizontal program in June '09 (2-4 horizontal wells in FY '09) Marcellus acreage prioritized by: Geology Lease Terms Permitting Issues Pipeline infrastructure May partner in some areas, remain 100% in others

Exploration & Production Gulf of Mexico

Gulf of Mexico Discoveries since April 1st, 2007 Recent Discovery HI 24L North Disc. (Q3 '07) Producing: 35 Mmcf/d WI: 35% HI 23L Prospect (Q2 '08) 60' Pay WI: 55% ; Paid 35% Producing: 14 Mmcf/d ; 1,800 BCPD WC 96 Disc. (Q4 '07) Producing: 9 Mmcf/d WI: 11% Cyclops (Q2 '08) 1st Well: 106' Pay 2nd Well: 200'+ Pay First Production: Q2 '09 WI: 29% EI383 (Q3 '08) 70' Pay ; WI: 30% First Production: Q3 '09

Gulf of Mexico Fiscal 2008 Exploration Program 3 Discoveries, 1 Dry Hole 5 discoveries in 18 months since implementing new strategy Fiscal '08 Net 2P Reserves Added: 23.7 Bcfe (13.9 Proved) 2P Program F&D Cost: $2.61/Mcfe ($4.44 Proved) Estimated Program IRR: 44%(1) (1) Assumes $7/Mcf and $70/Bbl

Exploration & Production California

California Lifting Cost - Peer Comparison Seneca is a low-cost operator in California, with Lifting Costs consistently outperforming its peers Source: HIS Herold, Inc. and Seneca Financial Reports

California 2008 Highlights Monterey Shale Drilling at Lost Hills Drilled 4 wells Added 300 Boepd Marvic Sand Development at MWSS Drilled 11 wells in 2008 3.3 Bcfe @ $1.58 F&D Cost Additional wells planned in 2009 Increased Production 500 Boepd

Exploration & Production Fiscal 2008 Highlights

Exploration & Production Long-Term Outlook

National Fuel Gas Company Corporate Overview

National Fuel Gas Company 2009 EPS Guidance & Sensitivity Fiscal 2009 Earnings per Share (Diluted) Guidance(1) Consolidated Earnings $2.60 - $2.80 Earnings per Share Sensitivity to Changes from $7.00/ MMBtu for natural gas and $70/Bbl for crude oil(1) $1 change per $5 change per MMBtu Gas Bbl Oil Increase Decrease Increase Decrease +$0.08 -$0.08 +$0.07 -$0.07 Range NFG & Subsidiaries (1) The earnings guidance and sensitivity table are current as of November 6, 2008. The sensitivity table only considers revenue from the Exploration and Production segment's crude oil and natural gas sales. The sensitivities will become obsolete with the passage of time, changes in Seneca's production forecast, changes in basis differentials, as additional hedging contracts are entered into, and with the settling of NYMEX hedge contracts at their maturity. For its fiscal 2009 earnings guidance, the Company is utilizing flat commodity pricing, exclusive of basis differential, of $7.00 per MMBtu for natural gas and $70 per Bbl for crude oil Seneca Resources Production Guidance: 38 to 44 Bcfe

National Fuel Gas Company Net Plant by Segment $3.4 B

National Fuel Gas Company Capitalization Long-Term Debt 41% Short-Term Debt N/A $2.70 Billion At September 30, 2008 Long-Term Debt 38% Short-Term Debt N/A $2.63 Billion At September 30, 2007

National Fuel Gas Company 2008 Cash Flows $237.0 $124.8

National Fuel Gas Company Capital Resources $300.0 MM Commercial Paper Program And Uncommitted Credit Facilities - Aggregate Of $720.0 MM $0 borrowed at September 30, 2008 $300.0 MM Committed Credit Facility Through September 2010 - backs commercial paper program $0 borrowed at September 30, 2008 The Company may issue debt or equity securities in a public offering or a private placement from time to time, depending on market conditions, indenture requirements, regulatory authorizations and the Company's capital requirements.

National Fuel Gas Company Share Buyback Completed Authorized: December 8, 2005 Authorized Amount: Up to 8 Million Shares Shares Repurchased (As of 9/30/08): All 8 Million Shares Remaining Authorized Authorized: September 24, 2008 Authorized Amount: Up to 8 Million Shares Shares Repurchased (As of 9/30/08): 1,028,981 Shares

Pipeline & Storage Pipeline Overview

Pipeline & Storage Storage Overview (1) Includes 4 storage fields co-owned with non-affiliated companies

Pipeline & Storage Upcoming Projects West to East & Appalachian Lateral Project Pipeline Length: 324 Miles Starting Location: Rockies Express (REX) - Clarington, OH Ending Location: Millennium Pipeline - Corning, NY Receipts From: REX (~555,000 to 750,000 Dth/d) Local Production Cove Point Gas at Leidy and Corning Deliveries To: Millennium & Empire at Corning Project Status: Open Seasons Conducted May 2007/October 2008 Strong Initial Interest Storage Expansion Incremental Storage Capacity: Approximately 8.5 Bcf No additional base gas required Storage Fields: East Branch - Pennsylvania Galbraith - Pennsylvania Tuscarora - Central New York Project Status: Open Season Conducted October 2008

Utility Segment Overview

Utility Rate Case Activity 11/30/06: The Pennsylvania PUC approved the Settlement Agreement reached in the Delivery Service Charge Rate Case Effective Date: 1/1/07 Revenue Increase: $14.3 MM Revenue Decoupling: Initially proposed by the Utility in this case. Will instead be pursued via active participation in the statewide generic proceeding announced by the Pennsylvania PUC on September 28th, 2006 Pennsylvania Effective Date: 12/28/07 Awarded $1.8 MM base rate increase and $10.8 MM rate component (for expenses associated with Conservation Incentive Program) Granted 9.1% ROE Approved Revenue Decoupling: Recovery of operating costs & margin is decoupled from customer usage Early decision on Conservation Incentive Program Became effective 11/1/07 NY Revenue Stabilization Features: WNC, RDM, MFC, Symmetrical Sharing New York Case Concluded Case Concluded

Utility Rate Cases Pennsylvania New York Rate Case Result Rate Case Result Settled Adjudicated Approximate Rate Base Approximate Rate Base $280 - 290 MM(1) $699 MM Approximate Base Rate Revenue Increase Approximate Base Rate Revenue Increase $14.3 MM $1.8 MM Conservation Incentive Program Conservation Incentive Program N/A $10.8 MM Effective Date Effective Date 1/1/2007 12/28/2007 Approximate Utility Capital Structure(2): Approximate Utility Capital Structure(2): Long-Term Debt 45.0% 45.54% Cost Component 6.65% 6.57% Short-Term Debt 5.0% 9.32% Cost Component 5.0 - 6.0% 5.98% Equity Component 50.0% 44.35% Return on Equity 10.0 - 11.0% 9.10% (1) Represents the approximate range of rate base filed for in this case (2) Black-box settlement in Pennsylvania

California Property Trade Upper Ojai Assets + $14.1 mm Sespe Acreage 6.6 Bcfe 210 Boepd $2.14/Mcfe (Reserve Repl. Cost) SRC - Trades Sespe offers significant upside Potential Property Trade SRC - Receives

Energy Marketing (1) Excludes resolution of a purchased gas contingency of +$0.03 Diluted Earnings per Share (Before Items Impacting Comparability)

Timber (1) Excludes gain from timber sale of +$1.26 (2) Excludes adjustment of gain on timber sale of -$0.01 Diluted Earnings per Share (Before Items Impacting Comparability)

National Fuel Gas Company Debt Ratings - At September 30, 2008

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 Exploration & Production Segment Capital Expenditures from Continuing Operations to
Consolidated Capital Expenditures
($ millions)

	2004		2005		2006		2007			2008			2009 Forecast		2010 Forecast
Exploration & Production Capital Expenditures from Continuing Operations	$	46.3	$	83.9	$	166.5	$	146.7		$	192.2		$	285.0	$	233.0
Pipeline & Storage Capital Expenditures		23.2		21.1		26.0		43.2			165.5			73.0		76.0
Utility Capital Expenditures		55.4		50.1		54.4		54.2			57.5			58.0		60.0
Timber Capital Expenditures		2.8		18.9		2.3		3.7			1.4			1.0		1.0
Corporate & All Other Capital Expenditures		5.7		1.1		3.2		(0.2	)		(2.1	)
Total Corporation — Continuing Operations	$	133.4	$	175.1	$	252.4	$	247.6		$	414.5		$	417.0	$	370.0
Capital Expenditures from Discontinued Operations		38.9		38.5		41.8		29.1			—			—		—
Total Capital Expenditures	$	172.3	$	213.6	$	294.2	$	276.7		$	414.5		$	417.0	$	370.0

Reconciliation of Segment Net Income from Continuing Operations to
Consolidated Net Income
(’000)

	2005		2006			2007		2008
Income from Continuing Operations	$	138,437	$	184,614		$	201,675	$	268,728
Discontinued Operations:
Income (Loss) From Operations, Net of Tax		25,277		(46,523	)		15,479		—
Gain on Disposal, Net of Tax		25,774		—			120,301		—
Income (Loss) From Discontinued Operations, Net of Tax	$	51,051	$	(46,523	)	$	135,780	$	—
GAAP Net Income	$	189,488	$	138,091		$	337,455	$	268,728

Reconciliation of Net Property, Plant & Equipment by Segment to
Consolidated Net Plant
($ millions)

	2007		2008
Exploration & Production	$	982.7	$	1,096.0
Pipeline & Storage		681.9		826.5
Utility		1099.3		1125.9
Timber		89.9		86.4
Marketing		0.1		0.1
Corporate & All Other		24.5		19.2
Total Net Plant	$	2,878.4	$	3,154.1

Reconciliation of Segment Revenue to Consolidated Revenue
($ millions)

	2008
Exploration & Production	$	466.8
Pipeline & Storage		216.6
Utility		1,210.3
All Other Segments		506.8
Total Revenue	$	2,400.4

NATIONAL FUEL GAS COMPANY
AND SUBSIDIARIES
RECONCILIATION TO REPORTED EARNINGS

	Fiscal Year			Fiscal Year			Fiscal Year			Fiscal Year			Fiscal Year			Fiscal Year
	Ended			Ended			Ended			Ended			Ended			Ended
(Diluted Earnings Per Share)	September 30, 2003			September 30, 2004			September 30, 2005			September 30, 2006			September 30, 2007			September 30, 2008
Utility
Reported earnings	$	0.70		$	0.56		$	0.46		$	0.58		$	0.60		$	0.73
Out-of-period adjustment to symmetrical sharing		—			—			—			(0.03	)		—			—
Pension settlement loss		—			0.03			—			—			—			—
Earnings before items impacting comparability		0.70			0.59			0.46			0.55			0.60			0.73
Pipeline and Storage
Reported earnings		0.56			0.58			0.71			0.65			0.66			0.64
Reversal of reserve for preliminary project costs		—			—			—			—			(0.06	)
Discontinuance of hedge accounting		—			—			—			—			(0.02	)
Pension settlement loss		—			0.02			—			—			—			—
Gain associated with insurance proceeds		—			—			(0.05	)		—			—			—
Base gas sale								(0.03	)		—			—			—
Earnings before items impacting comparability		0.56			0.60			0.63			0.65			0.58			0.64
Exploration and Production
Reported earnings		(0.39	)		0.66			0.60			0.24			2.47			1.73
Gain on disposal of discontinued operations		—			—			—			—			(1.41	)		—
(Earnings)/Loss from discontinued operations		—			—			—			0.54			(0.18	)		—
Income tax adjustments		—			—			—			(0.07	)		—			—
Loss on sale of oil and gas assets		0.48			—			—			—			—			—
Impairment of oil and gas producing properties		0.36			—			—			—			—			—
Cumulative Effect of Change in Accounting		0.01			—			—			—			—			—
Adjustment of loss on sale of oil and gas assets		—			(0.06	)		—			—			—			—
Pension settlement loss		—			0.01			—			—			—			—
Earnings before items impacting comparability		0.46			0.61			0.60			0.71			0.88			1.73
International
Reported earnings		(0.12	)		0.07
Cumulative Effect of Change in Accounting		0.10			—		see
Pension settlement loss		—			—		“Discontinued
Tax rate change		—			(0.06	)	Operations”
Repatriation tax							below
Earnings before items impacting comparability		(0.02	)		0.01
Energy Marketing
Reported earnings		0.07			0.07			0.06			0.07			0.09			0.07
Resolution of a purchased gas contingency		—			—			—			—			(0.03	)		—
Pension settlement loss		—			—			—			—			—			—
Earnings before items impacting comparability		0.07			0.07			0.06			0.07			0.06			0.07
Timber
Reported earnings		1.38			0.06			0.06			0.07			0.04			—
Gain on sale of timber assets		(1.26	)		—			—			—			—			—
Pension settlement loss		—			—			—			—			—			—
Adjustment of gain on sale of timber properties		—			0.01			—			—			—			—
Earnings before items impacting comparability		0.12			0.07			0.06			0.07			0.04			—
	-
Corporate and All Other
Reported earnings		—			0.01			(0.08	)		—			0.10			0.01
Pension settlement loss		—			0.02			—			—			—			—
Gain on sale of turbine		—			—			—			—			—			(0.01	)
Earnings before items impacting comparability		—			0.03			(0.08	)		—			0.10			—
Consolidated
Reported earnings		2.20			2.01
Total items impacting comparability from above		(0.31	)		(0.03	)
Earnings before items impacting comparability	$	1.89		$	1.98
Consolidated Earnings from Continuing Operations
Reported earnings from continuing operations								1.81			1.61			3.96			3.18
Total items impacting comparability from above								(0.08	)		(0.10	)		(1.70	)		(0.01	)
Earnings from continuing operations before items impacting comparability							$	1.73		$	1.51		$	2.26		$	3.17
Discontinued Operations
Reported earnings from discontinued operations								0.42
Consolidated
Reported earnings							$	2.23		$	1.61		$	3.96		$	3.18

Reconciliation of Pipeline & Storage Operating Revenues to
Consolidated Operating Revenues Fiscal 2008
($Millions)

	2008
Pipeline Revenues	$	126.7
Storage Revenues	$	67.0
Other Revenues	$	22.9
Total Pipeline & Storage Revenues	$	216.6
All Other Segments	$	2,183.8
Total Corporation	$	2,400.4

Reconciliation of Utility Segment Aged Accounts Receivable to
Consolidated Accounts Receivable — Net
($Millions)

	at 9/30/04			at 9/30/05			at 9/30/06			at 9/30/07			at 9/30/08
Utility Aged Accounts Receivable		68.10		$	76.30		$	89.70		$	120.50			133.58
Utility Current/Other Accounts Receivable		18.20		$	16.40		$	11.80		$	8.80			12.63
Utility Gross Accounts Receivable		86.30			92.70			101.50			129.30			146.21
Utility Reserve for Bad Debt		(12.90	)	$	(25.10	)	$	(29.70	)	$	(27.20	)		(30.55	)
Utility Net Accounts Receivable		73.40			67.60			71.80			102.10			115.66
All Other Segments Gross Accounts Receivable		77.30			100.10			103.60			71.70			72.31
All Other Segments Reserve for Bad Debts		(4.60	)	$	(1.80	)	$	(1.70	)	$	(1.40	)		(2.57	)
All Other Segments Net Accounts Receivable	$	72.70		$	98.30		$	101.90		$	70.30		$	69.74
Total Corporation Accounts Receivable — Net	$	146.10		$	165.90		$	173.70		$	172.40			185.40

Reconciliation of Net Cash Provided by Operating Activites
($000s)

	2008
Net Income Available for Common Stock	$	268,728
Depreciation, Depletion & Amortization		170,623
Deferred Income Taxes		72,496
Income from Unconsolidated Subsidiaries		1,977
Other non-cash items		4,858
Operating Cash Flows, per slide		518,682
Excess Tax Benefits Associated with Stock-Based Compensation Awards		(16,275	)
Changes in Working Capital		(19,631	)
		(35,906	)
Net Cash Flow provided by Operating Activities		482,776
Net Cash Flow provided by Investting Activities		(328,992	)
Net Cash Flow provided by Financing Activities		(210,351	)
Cash & Temporary Cash Investments at Beginning of Period, September 30, 2007		124,806
Cash & Temporary Cash Investments at End of Period, September 30, 2008	$	68,239

Reconciliation of Exploration & Production Segment Capital Expenditures to
Consolidated Capital Expenditures
($000s)

	2006		2007		2008		2009 Forecast		2010 Forecast
Exploration & Production Capital Expenditures	$	166,535	$	146,687	$	192,187	$	285,000	$	233,000
All Other		127,624		130,041		222,315		132,000		137,000
Total Corporation	$	294,159	$	276,728	$	414,500	$	417,000	$	370,000

Reconciliation of Exploration & Production Operating Revenue to
Consolidated Operating Revenue (from Continuing Operations)
($000s)

	2008
Exploration & Production	$	466,760
All Other Segments		1,933,601
Consolidated Operating Revenue	$	2,400,361

Reconciliation of Exploration & Production Net Income to
Consolidated Net Income
($000s)

	2005		2006			2007		2008
Exploration & Production (Income from Continuing Operations)	$	35,581	$	67,494		$	74,889	$	146,612
Income/(Loss) from Discontinued Operations, Net of Tax		15,078		(46,523	)		15,479		—
Gain on Disposal of Discontinued Operations, Net of Tax		—		—			120,301		—
Total Exploration & Production	$	50,659	$	20,971		$	210,669	$	146,612
All Other Segments		138,829		117,120			126,786		122,116
Consolidated Net Income	$	189,488	$	138,091		$	337,455	$	268,728