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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 8-K
CURRENT REPORT
Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
Date of Report (Date of earliest event reported): November 9, 2007
NATIONAL FUEL GAS COMPANY
(Exact name of registrant as specified in its charter)
 	 	 	 	 	
New Jersey	 	1-3880	 	13-1086010	
(State or other jurisdiction	 	(Commission File Number)	 	(IRS Employer	
of incorporation)	 	 	 	Identification No.)	
 	 	 	 	 	
6363 Main Street, Williamsville, New York	 	14221	
(Address of principal executive offices)	 	(Zip Code)	
Registrant’s telephone number, including area code: (716) 857-7000
Former name or former address, if changed since last report: Not Applicable
     Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions ( see General Instruction A.2. below):

o	 	Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)	
 		
þ	 	Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)	
 		
o	 	Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))	
 		
o	 	Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))	

   

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Item 8.01 Other Events	
Item 9.01 Financial Statements and Exhibits	
SIGNATURES	
EXHIBIT INDEX	
EX-99	

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Item 8.01 Other Events.
National Fuel Gas Company (the “Company”) plans to hold meetings with certain shareholders, industry analysts, money managers and other members of the financial community beginning November 12, 2007. A copy of presentation materials to be provided to participants in the meetings is hereby incorporated by reference into this Item 8.01 and filed as part of this Current Report as Exhibit 99.
Neither the filing of the presentation as an exhibit to this Current Report nor the inclusion in such presentation of any reference to the Company’s internet address shall, under any circumstances, be deemed to incorporate the information available at such internet address into this Current Report. The information available at the Company’s internet address is not part of this Current Report or any other report filed or furnished by the Company with the Securities and Exchange Commission.
In addition to financial measures calculated in accordance with generally accepted accounting principles (“GAAP”), the presentation filed as part of this Current Report as Exhibit 99 contains certain non-GAAP financial measures. The Company believes that such 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.
Certain statements contained herein or incorporated by reference from the presentation, including statements regarding future earnings, developments and operational results, and statements identified by the use of the words “anticipates,” “estimates,” “expects,” “intends,” “plans,” “predicts,” “projects,” and similar expressions, are “forward-looking statements” as defined by the Private Securities Litigation Reform Act of 1995. There is no assurance that the Company’s projections will in fact be achieved nor do these projections reflect any acquisitions or divestitures that may occur in the future. While the Company’s expectations, beliefs and projections are expressed in good faith and are believed to have a reasonable basis, actual results may differ materially from those expressed in the forward-looking statements. Furthermore, each forward-looking statement speaks only as of the date on which it is made. In addition to other factors, the following are important factors that could cause actual results to differ materially from those discussed in the forward-looking statements: changes in laws and regulations to which the Company is subject, including changes in tax, environmental, safety and employment laws and regulations; changes in economic conditions, including economic disruptions caused by terrorist activities, acts of war or major accidents; 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; impairments under the Securities and Exchange Commission’s full cost ceiling test for natural gas and oil reserves; changes in the availability and/or price of

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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; governmental/regulatory actions, initiatives and proceedings, including those involving acquisitions, financings, rate cases (which address, among other things, allowed rates of return, rate design and retained gas), affiliate relationships, industry structure, franchise renewal, and environmental/safety requirements; 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; occurrences affecting the Company’s ability to obtain funds from operations or from issuances of short-term notes or debt or equity securities to finance needed capital expenditures and other investments, including any downgrades in the Company’s credit ratings; uncertainty of oil and gas reserve estimates; ability to successfully identify and finance acquisitions or other investments and ability to operate and integrate existing and any subsequently acquired business or properties; ability to successfully identify, drill for and produce economically viable natural gas and oil reserves; significant changes from expectations in the Company’s actual production levels for natural gas or oil; 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; changes in actuarial assumptions and the return on assets with respect to the Company’s retirement plan and post-retirement benefit plans; 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. 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.
Item 9.01 Financial Statements and Exhibits

 	(c)	 	Exhibits	

 	Exhibit 99 Presentation materials for meetings to be held beginning November 12, 2007	

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SIGNATURES
     Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.
 	 	 	 	 	
 	NATIONAL FUEL GAS COMPANY
 	 	
 	By:  	/s/ James R. Peterson 	 	
 	 	James R. Peterson 	 	
 	 	Assistant Secretary 	 	
 	
Dated: November 9, 2007

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EXHIBIT INDEX
 	 	 	
Exhibit Number	 	Description	
 	 	 	
99	 	Presentation materials for meetings to be held beginning November 12, 2007	

 

Exhibit 99

National Fuel Gas Company Presentation Book November 2007	

 

Important Information Regarding 2008 Proxy Statement National Fuel Gas Company (the "Company") and its directors and executive officers may be deemed to be participants in the solicitation of proxies from stockholders in connection with the Company's 2008 Annual Meeting of Stockholders (the "Annual Meeting"). The Company plans to file a proxy statement with the Securities and Exchange Commission (the "SEC") in connection with this solicitation of proxies for the Annual Meeting (the "2008 Proxy Statement"). Information regarding the names of the Company's directors and executive officers and their respective interests in the Company by security holdings or otherwise is set forth in the Company's proxy statement relating to the 2007 annual meeting of stockholders, which may be obtained free of charge at the SEC's website at http://www.sec.gov and the Company's website at http://www.nationalfuelgas.com. Additional information regarding the interests of such potential participants will be included in the 2008 Proxy Statement and other relevant documents to be filed with the SEC in connection with the Annual Meeting. Promptly after filing its definitive 2008 Proxy Statement for the Annual Meeting with the SEC, the Company will mail the definitive 2008 Proxy Statement and a proxy card to each stockholder entitled to vote at the Annual Meeting. WE URGE INVESTORS TO READ THE 2008 PROXY STATEMENT (INCLUDING ANY AMENDMENTS THERETO) AND ANY OTHER RELEVANT DOCUMENTS THAT THE COMPANY WILL FILE WITH THE SEC WHEN THEY BECOME AVAILABLE BECAUSE THEY WILL CONTAIN IMPORTANT INFORMATION. Stockholders will be able to obtain, free of charge, copies of the 2008 Proxy Statement and any other documents filed by the Company with the SEC in connection with the Annual Meeting at the SEC's website (http://www.sec.gov), at the Company's website (http://www.nationalfuelgas.com) or by contacting Secretary, National Fuel Gas Company, 6363 Main Street, Williamsville, New York 14221, (716) 857-7000.	

 

Grow shareholder value through timely investment in the energy industry. National Fuel Gas Company Corporate Objective	

 

Shareholder Returns National Fuel versus the S&P 500 1Q FY03 2Q FY03 3Q FY03 4Q FY03 1Q FY04 2Q FY04 3Q FY04 4Q FY04 1Q FY05 2Q FY05 3Q FY05 4Q FY05 1Q FY06 2Q FY06 3Q FY06 4Q FY06 1Q FY07 2Q FY07 3Q FY07 4Q FY07 National Fuel 5.64 12.77 35.72 20.45 30.26 32.55 36.21 55.88 57.48 60.42 63.85 95.47 79.92 90.42 106.25 115.11 129.85 159.79 161.95 184.99 S&P 500 8.44 5.02 21.17 24.38 39.49 41.85 44.28 41.57 54.61 51.3 53.36 58.88 62.19 69 66.57 75.98 87.75 88.95 100.81 104.85 Total Return calculated by Bloomberg on a quarterly basis over last five fiscal years (9/30/02 - 9/28/07)	

 

Shareholder Returns National Fuel versus the Alerian Index 1Q FY03 2Q FY03 3Q FY03 4Q FY03 1Q FY04 2Q FY04 3Q FY04 4Q FY04 1Q FY05 2Q FY05 3Q FY05 4Q FY05 1Q FY06 2Q FY06 3Q FY06 4Q FY06 1Q FY07 2Q FY07 3Q FY07 4Q FY07 National Fuel 5.64 12.77 35.72 20.45 30.26 32.55 36.21 55.88 57.48 60.42 63.85 95.47 79.92 90.42 106.25 115.11 129.85 159.79 161.95 184.99 Alerian Index 3.83 11.14 28.44 33.74 49.59 53.48 43.32 61.65 74.04 77.46 91.99 99.56 85.09 95.85 98.16 108.81 132.62 162.33 180.55 153.77 Total Return calculated by Bloomberg on a quarterly basis over last five fiscal years (9/30/02 - 9/28/07)	

 

1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008E $3.1 B At Fiscal Year End Net Plant by Segment (in Billions)	

 

National Fuel Gas Company Net Plant by Segment $2.9 Billion At September 30, 2007 P&S Utility All Other E&P Net plant 0.682 1.1 0.114 0.983	

 

$192.7 Million 12 Months Ended September 30, 2007 P&S Utility Timber Energy Mkt. * Corp. & Other E&P NI 49.7 50.9 3.7 5.3 8.1 74.9 National Fuel Gas Company Net Income	

 

70 0.19 71 0.2 72 0.205 73 0.215 74 0.225 75 0.235 76 0.245 77 0.255 78 0.27 79 0.2875 80 0.3075 81 0.33 82 0.36 83 0.39 84 0.47 85 0.52 86 0.57 87 0.6 88 0.63 89 0.67 90 0.71 91 0.73 92 0.75 93 0.77 94 0.79 95 0.81 96 0.84 97 0.87 98 0.9 99 0.93 '00 0.96 '01 1.01 '02 1.04 '03 1.08 '04 1.12 '05 1.16 '06 1.2 '07 1.24 National Fuel Gas Company Dividend Growth $0.19 '07 $1.24 Annual Rate At Fiscal Year End	

 

Earnings * Dividends Paid 85 0.95 0.48 86 0.88 0.53 87 0.88 0.58 88 0.83 0.61 89 0.97 0.64 90 0.92 0.68 91 0.82 0.72 92 0.97 0.74 93 1.08 0.76 94 1.16 0.78 95 1.02 0.8 96 1.39 0.82 97 1.49 0.85 98 1.44 0.88 99 1.47 0.91 '00 1.61 0.94 '01 2.11 0.97 '02 1.58 1.02 '03 1.89 1.05 '04 1.98 1.09 '05 2.15 1.13 '06 2.25 1.17 '07 2.26 1.21 * Excludes special items Dividends Paid Fiscal Year National Fuel Gas Company Earnings vs. Dividends Paid Earnings per Diluted Share	

 

National Fuel Gas Company Energy Mktg. Timber E&P P&S Utility National Fuel Gas Distribution Corporation National Fuel Gas Supply Corporation and Empire State Pipeline Seneca Resources Corporation Highland Forest Resources, Inc. and NE Div. Of Seneca Resources Corporation National Fuel Resources, Inc. National Fuel Gas Company Major Business Segments	

 

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2,495 Miles of System Pipeline 15 Compressor Stations Totaling 39,929 Horsepower Transportation Volume for Fiscal 2007: 356.1 Bcf $122.9 MM in Revenues for Fiscal 2007 Pipeline & Storage Pipeline Operating Statistics	

 

32 Underground Natural Gas Storage Fields (4 Co-owned with Nonaffiliated Companies) 15 Compressor Stations Totaling 35,475 Horsepower 78.3 Bcf of Working Storage Capacity $67.1 MM in Revenues for Fiscal 2007 Pipeline & Storage Storage Operating Statistics	

 

Fiscal Year 2002 2003 2004 2005 2006 2007 Earnings 0.49 0.56 0.599 0.63 0.65 0.583 a Excludes SFAS 88 settlement loss of -$0.02 b Excludes base gas sale of $0.03 and gain associated with insurance proceeds of $0.05 c Excludes reversal of reserve for preliminary project costs of $0.06, and Discontinuance of Hedge Accounting of $0.02. a Fiscal Year Pipeline & Storage Diluted Earnings per Share b c	

 

20	

 

Construction Started September 2007 20 miles of 24" by mid December Initial Capacity 250,000 Dth/day - KeySpan 150,750 Dth/day Target In-Service Date November 1, 2008 78 Miles of 24" Pipe - 1,440 psig 20,620 HP of Compression Receipts from TransCanada Pipeline @ Chippawa, Ontario; Deliveries to Millennium @ Corning, New York Capital Cost Approximately $177 Million Pipeline & Storage Empire Connector	

 

DAWN Hub: Canadian, Gulf & Mid-Continent FUTURE: Alaska Rockies Express Pipeline - REX East Gulf & Appalachian Production FUTURE: Cove Point Expansion & Gulf LNG I 21	

 

Phase I Pipeline Capacity 130,000 Dth/day Estimated In-Service Date Late Calendar 2009/Early Calendar 2010 23 Miles of 24" Pipe 800 HP of Compression Receipts from NFGSC and Other Storages and Upstream Pipelines Deliveries to Millennium and Empire Capital Cost Approximately $39 Million Development Activities Contingent on Market Pipeline & Storage Tuscarora Extension	

 

Fiscal Year 2002 2003 2004 2005 2006 2007 Earnings 0.12 0.12 0.07 0.06 0.07 0.044 a Excludes gain from timber sale of +$1.26 b Excludes adj. of gain on timber sale of -$0.01 a b Fiscal Year Timber Diluted Earnings per Share	

 

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Fiscal Year 2002 2003 2004 2005 2006 2007 Earnings 0.62 0.7 0.59 0.46 0.55 0.597 a Excludes SFAS 88 settlement loss of -$0.03 b Excludes out-of-period adjustment to symmetrical sharing of $0.03 a Fiscal Year Utility Diluted Earnings per Share b	

 

At 09/30/04 At 9/30/05 At 09/30/06 At 9/30/07 30-59 days 8.3 9 9.2 8.7 60-89 days 5.9 6.5 7.1 6.2 90-119 days 5.4 6.3 6.8 6 120 days & over 48.4 54.5 66.7 60.7 Reserve for Bad Debt 12.9 25.1 29.7 27.2 Utility Accounts Receivable - Customer	

 

New York Merchant Function Charge Varies with Cost of Gas Rates from 2005 Settlement Include Allowance Attributable to Uncollectible Expense Residential Non-Residential 2.742% .304% Multiplied by Gas Supply Cost Rate Utility Bad Debt Tracking	

 

Fiscal Year TME Utility Average Use Per Residential Customer Normalized Mcf Per Account '73 '74 '75 '76 '77 '78 '79 '80 '81 '82 '83 '84 '85 '86 '87 '88 '89 '90 '91 '92 '93 '94 '95 '96 '97 '98 '99 '00 '01 '02 '03 '04 '05 '06 '07 180.205 173.305 173.431 170.237 164.955 156.044 156.898 152.605 153.207 145.597 132.388 134.153 131.672 132.194 131.12 135.531 132.77 130.829 133.551 128.393 127.036 128.857 123.223 124.975 124.137 119.631 116.131 118.369 116.198 114.23 115.603 113.854 107.928 105.861 108.195 108.195 Mcf (New York)	

 

Utility Rate Case Settlements * Represents the approximate range of rate base filed for in this case. ** Black-box settlement in both states. Previous Settlements Previous Settlements Current Case New York Pennsylvania New York Approximate Rate Base $640-$650 MM $280-$290 MM* $711 MM Approximate Base Rate Revenue Increase $21 MM $14.3 MM $52 MM Effective Date 8/1/2005 1/1/2007 Late '07/Early '08 Approximate Utility Capital Structure**: Approximate Utility Capital Structure**: Long-term Debt Cost Component Short-term Debt Cost Component Equity Component Return on Equity 45.0% 6.65% 5.0% 5.0 - 6.0% 50.0% 10.0 - 11.0% 39.4% 6.57% 9.5% 5.3% 51.1% 11.65%	

 

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 28, 2006 Pennsylvania 01/29/07: Utility Submitted a Request to Re-Design and Raise its Delivery Service Charges in 2008 Proposed Revenue Increase: $52 MM, or 6.4% Revenue Decoupling: The Conservation Incentive Program Became Effective 11/1/07; Allocates $12 MM to the Promotion of Energy Conservation. The Companion Revenue Decoupling Proposal Remains Pending The delivery rate would be adjusted, based upon throughput, to enable the Utility to recover its operating margin New York Case Concluded Case Initiated	

 

Energy Marketing Customers & Marketing Area Customers @ FYE 2004 2005 2006 2007 Residential 15,983 14,902 14,963 15,357 Commercial/Industrial 4,345 4,265 4,605 5,219	

 

Energy Marketing Diluted Earnings per Share Fiscal Year 2002 2003 2004 2005 2006 2007 Earnings 0.11 0.07 0.07 0.06 0.07 0.062 Fiscal Year * * Excludes resolution of a purchased gas contingency of +$.03.	

 

Fiscal Year 2002 2003 2004 2005 2006 2007 Earnings 0.33 0.46 0.61 0.6 0.71 0.88 a b a Excludes oil & gas impairment, loss on sale and cum. effect of change in acctg of - $0.85 b Excludes SFAS 88 settlement loss of -$0.01 and Adjustment of loss on sale of oil and gas assets of +$0.06 c Excludes loss from discontinued operations of -$0.54 and income tax adjustments of +$0.07 d Excludes gain on disposal of discontinued operations of +$1.41 and Earnings from discontinued operations of +$0.18. Fiscal Year c d Seneca Resources Diluted Earnings per Share	

 

Fiscal 2007 Results: Increased U.S. Production to 39 BCFE Sold Canada operations for $232 million ($4.75/MCFE) Replaced over 500% of Appalachian production Fiscal 2008 Expectations: Continue U.S. Production Growth Appalachia up 15-20% Gulf up 5-10% California flat Accelerate drilling in Appalachia - 280 Well target Drill up to 10 horizontal wells in the Marcellus Shale Further Gulf exploration on trend to HI24L discovery Seneca Resources Positioned for Growth in 2008	

 

NY PA Gulf Coast - 7% 34 BCFE West - 71% 58 MMBOE (347 BCFE) Total: 491 BCFE Oil: 58% Gas: 42% East - 22% 110 BCFE At 09/30/2007 Seneca Resources Reserves by Region	

 

NY PA Gulf Coast - 38% 44 MMCFED West - 44% 8,300 BOED (50 MMCFED) Total: 114 MMCFED 2008 Forecast East - 18% 20 MMCFED Seneca Resources Average Daily Production	

 

2006 2007 2008 Fcst East 5.5 6.3 7 West 19.4 18.3 18 Gulf 13.2 14.7 16.5 Canada 9.3 7.7 BCFE Fiscal Year 47.0 47.4 Approx. 38 - 44 Seneca Resources Annual Production by Division	

 

2006 2007 2008 East 27 39.1 58.6 West 36 41.4 45.7 Canada 42 29.1 0 Gulf 103 66.2 50.1 $176 Fiscal Year $US Millions Approx. $151-$159 $208 13% 22% 38% 50% 38% 32% 30% 24% 17% 20% 16% Seneca Resources Capital Expenditures by Division	

 

940,000 Total Net Acres Seneca Resources Appalachian Position	

 

Upper Devonian/Silurian Drilled 233 Wells (53% increase over '06), while also improving EUR per well Replaced 530% of 2007 Appalachian production Increased Proved Developed reserves by ~20% Increased total Proved reserves by ~32% 2007 drilling program had an estimated IRR of over 30%* Increased daily production from 16.6 MMCFED (Sep '06) to 20 MMCFED (Sep '07), a 20% increase * Economics based on NYMEX pricing of $7/MCF and $70/BBL Seneca Resources Fiscal '07 Drilling Results	

 

Fiscal Year 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 Development 31 38 49 48 78 144 215 250 Exploration 5 2 6 10 2 2 3 4 8 18 30 Shallow Gas Program Wells Drilled per Year 5 2 6 10 2 2 3 4 8 18 30 Increasing number of exploration wells will allow for a more rapid evaluation of prospective resource Seneca Resources Development & Exploration Drilling Target	

 

2004 2005 2006 2007 BCFE 3.7 5.6 11.2 20.8 Wells 42 83 146 220 Fiscal Year Reserves Added by Drilling Wells Drilled per Year (Reserves Added by Drilling - excludes PUDS) Seneca Resources Appalachian Reserve Statistics	

 

SRC minerals in yellow (860,000 Acres contributed to AMI) EOG minerals in blue (145,000 Acres contributed to AMI) Seneca Resources Marcellus Shale Activity	

 

Cratonic Basin Stratigraphic Cross-section Ohio Pennsylvania Transgressive Black Shales Regressive Shales Clastic Sediments (Sands & Silts) Marcellus Geneseo Middlesex Rhinestreet Dunkirk Huron Ohio Shale Sunbury Foreland Basin West East * Modified Cross Section from "The Atlas of Major Appalachian Gas Plays", West Virginia Geological & Economic Survey, Mont Chateau Research Center, Morgantown, WV 26507-0879. Seneca Resources Appalachian Basin Black Shales	

 

Marcellus Shale: Basin edge Marcellus Shale: > 100' thick Range Resources Marcellus Activity Seneca/EOG Marcellus Activity * Marcellus Isopach from "The Atlas of Major Appalachian Gas Plays", West Virginia Geological & Economic Survey, Mont Chateau Research Center, Morgantown, WV 26507-0879. Seneca Resources Marcellus Shale Activity	

 

1,000 BOEPD 230 BOEPD 640 BOEPD 4,700 BOEPD 2,200 BOEPD Seneca Resources California Properties	

 

FY 2008 Forecast Operating Cash Flow: $132 MM FY 2008 Forecast CAPEX: $44-47 MM Net Cash Flow: $86 MM FY 2008 average hedge price at MWSS $58.78/BOE Seneca is a low-cost producer ~ $8/boe Long-lived reserves (R/P > 19 years) Efficient, profitable, and well-run operation Seneca Resources California	

 

Why the Gulf of Mexico? Historic IRR for GOM program: 19% Cumulative $1.3 billion cash flow on $960 million investment Very large 3D seismic data base HI24L discovery in 2006/2007 Subsequently built a core acreage position along trend with similar opportunities New program is focused and selective Seneca Resources Gulf of Mexico	

 

North Lease - Drilled March '07 Discovery Well - Tested November '06 14,000 14,100 13,900 14,300 14,500 Building on Success HI 24-L Well Net Pay Test SRC W.I. HI24L-1S 200' 47 mmcfd 35% HI24L-1N 100' 50 mmcfd 35% Seneca Resources Gulf of Mexico - High Island 24L	

 

Total GOM Exploration & Development program projected to deliver: > 30% IRR < $4.00 F&D GOM FY08 capital forecast: $50-$52MM (FY07: $66MM; FY06: $103MM) Drill 4 to 5 Exploration wells; 5 to 6 Recompletions Grow production Evaluate Results at fiscal year-end Seneca Resources Fiscal 2008 Gulf of Mexico Plan	

 

Achieved our goals in 2007: Increased U.S. Production Sold Canada for $232 million Focused Gulf of Mexico program Continued to accelerate Appalachian drilling program Expect Growth in 2008: Forecast 5% production increase Further accelerate Appalachia drilling Drill up to 10 horizontal wells in the Marcellus Shale Seneca Resources Summary	

 

Well-positioned for continued success: Major competitive advantage in Appalachia First rate E&P Team Proprietary database and knowledge Outstanding acreage position Long-lived production and positive cash flow from California Focused and successful program in the Gulf Seneca Resources Summary (cont'd.)	

 

National Fuel Gas Company Earnings Guidance FY 2008 Earnings Guidance $2.50-$2.70 per share, includes: Exploration & Production Production between 38 and 44 Bcfe Pricing based on 7/24/07 NYMEX futures pricing strip No new 2008 production from announced venture with EOG Resources Utility New York rate determination in effect as of January 1, 2008	

 

National Fuel Gas Company Share Buyback Date Authorized: December 8, 2005 Authorized Amount: Up to 8 Million Shares As of 9/30/07: 3,834,878 Shares Repurchased	

 

National Fuel Gas Company As a Value Company Financially Strong Diversified Asset Base Prime Location: Proximity to Canada Undeveloped Storage Pipeline Corridor to East Coast Appalachian Acreage Potential Strong Dividend Record	

 

APPENDIX	

 

National Fuel Gas Company New York Stock Exchange NFG Shares Outstanding (Approx.) (As of 09/30/07) 83.5 Million Average Daily Trading Volume (12 Months Ended 09/30/07) 589,666 Market Capitalization (Approx.) (As of 11/7/07) $3.9 Billion $1.24 Annual Dividend Rate September Fiscal Year End	

 

1/1/1992 2/1/1992 3/1/1992 4/1/1992 5/1/1992 6/1/1992 7/1/1992 8/1/1992 9/1/1992 10/1/1992 11/1/1992 12/1/1992 1/1/1993 2/1/1993 3/1/1993 4/1/1993 5/1/1993 6/1/1993 7/1/1993 8/1/1993 9/1/1993 10/1/1993 11/1/1993 12/1/1993 1/1/1994 2/1/1994 3/1/1994 4/1/1994 5/1/1994 6/1/1994 7/1/1994 8/1/1994 9/1/1994 10/1/1994 11/1/1994 12/1/1994 1/1/1995 2/1/1995 3/1/1995 4/1/1995 5/1/1995 6/1/1995 7/1/1995 8/1/1995 9/1/1995 10/1/1995 11/1/1995 12/1/1995 1/1/1996 2/1/1996 3/1/1996 4/1/1996 5/1/1996 6/1/1996 7/1/1996 8/1/1996 9/1/1996 10/1/1996 11/1/1996 12/1/1996 1/1/1997 2/1/1997 3/1/1997 4/1/1997 5/1/1997 6/1/1997 7/1/1997 8/1/1997 9/1/1997 10/1/1997 11/1/1997 12/1/1997 1/1/1998 2/1/1998 3/1/1998 4/1/1998 5/1/1998 6/1/1998 7/1/1998 8/1/1998 9/1/1998 10/1/1998 11/1/1998 12/1/1998 1/1/1999 2/1/1999 3/1/1999 4/1/1999 5/1/1999 6/1/1999 7/1/1999 8/1/1999 9/1/1999 10/1/1999 11/1/1999 12/1/1999 1/1/2000 2/1/2000 3/1/2000 12.1875 12.75 12.1875 12.5 12.6875 12.75 13.1875 14.125 13.0625 13.125 14.0625 14.75 14.8125 15.75 16 15.875 14.9375 16.6875 17.375 17.9375 18.1875 17.75 16.6875 17 17.4375 15.375 15 15 15.1875 14.6875 15 15.5625 14.9375 14.875 13 12.75 13.25 13.625 14 14.4375 14.4375 14.3125 14 14.0625 14.375 14.875 16.0625 16.8125 16.75 16.0625 17.3125 17.5625 17.1875 18 16.875 18.5 18.375 18.625 21.3125 20.625 21.125 21.5 21.375 20.8125 20.6875 20.96875 21.25 22.21875 22 22.0625 23.34375 24.34375 23 23.3125 23.5 23 21.1875 21.78125 20.65625 20.5625 23.5 23.625 22.96875 22.59375 21.15625 20.21875 19.625 21.875 23.75 24.25 23.46875 23.53125 23.59375 24.4375 25.03125 23.25 22.28125 20.46875 22.28125 National Fuel Gas Company Stock Price 11/7/2007 $47.30 NFG LISTED NYSE	

 

Standard & Poor's Moody's Fitch, Inc. Long-Term Debt BBB+ Baa1 A- Outlook Stable Stable Stable Commercial Paper A-2 P-2 F2 NFG Debt Ratings at September 30, 2007	

 

National Fuel Gas Company Capital Resources Commercial Paper Program And Bilateral Credit Facilities - Aggregate Of $755 MM $0 borrowed at September 30, 2007 $300.0 MM Committed Credit Facility Through September 2010 $0 borrowed at September 30, 2007 Universal Shelf Registration on File - Additional $550 MM Can Be Issued As Debt Or Equity Securities Any offer and sale of such securities would be made only by means of a prospectus meeting requirements of securities laws	

 

* Long-term Debt includes Current Portion of Long-term Debt. ** Includes Discontinued Operations. National Fuel Gas Company Capitalization $2.56 Billion at September 30, 2006 ** Long-Term Debt Short-Term Debt Shareholder Equity Capitalization 1119 0 1444 Short-Term Debt 0% Shareholder Equity 56% Long-Term* Debt 44% $2.63 Billion at September 30, 2007 Long-Term Debt Short-Term Debt Shareholder Equity Capitalization 999 0 1630 Short-Term Debt 0% Shareholder Equity 62% Long-Term* Debt 38%	

 

2002 2003 2004 2005 2006 2007 CFPS 1.18 2.52 1.82 2.29 0.36 2.49 Fiscal Year National Fuel Gas Company Free Cash Flow per Diluted Share	

 

2001 2002 2003 2004 2005 2006 2007 2008E Utility 42.4 51.5 49.9 55.5 50.1 54.4 54.2 59 P & S 26 30.3 199.4 23.2 21.1 26 43.2 146 E & P 296.4 114.6 75.8 77.7 121.2 208.3 146.7 154 Energy Mkt. 0.116 0.1 0.2 0.0102 0 $- 0.08 0 Timber 3.7 25.6 3.5 2.8 18.9 2.3 3.657 0 Corp & Others 0.937 6.6 50.1 5.7 1.1 3.2 -0.232 1 International 15.6 4.2 2.5 7.5 5.9 0 0 0 E&P Discontinued Operations 0 0 0 0 0 0 29.1 $ Millions $381.4 $172.3 $218.3 Fiscal Year National Fuel Gas Company Expenditures for Long-Lived Assets $294.2 Approx. $357 - $365 $276.7	

 

2002 2003 2004 2005 2006 2007 Utility 169 179 191 211 204 203 * Excludes SFAS 88 settlement loss of -$3.4 million Fiscal Year $ Millions * Utility O & M Expense	

 

2002 2003 2004 2005 2006 2007 61.3 60.7 65.1 65.4 66.3 61.2 * Excludes SFAS 88 settlement loss of -$3.0 million * Pipeline & Storage O & M Expense $ Millions Fiscal Year	

 

Production: 39.3 BCFE Operating Revenue $324.0 MM Net Income $ 74.9 MM Expenses/Mcfe 4th Quarter Fiscal Year DD&A $2.19 $1.99 LOE $1.28 $1.23 G&A $0.63 $0.51 * Excludes discontinued operations of Canada. Seneca Resources 2007 Year End Results *	

 

Appalachia Stratigraphic Column national fuel 68 Exploration & Production Devonian Shales (EOG JointVenture) Depth: 4,500' - 8,000' (PA) Bass Island, Lockport, Medina, Whirlpool Depth: 2,000' - 6,000' (NY Target zones) Upper Devonian Sandstones (Primary Drilling Target) Depth: 800' - 4,500' (PA) Onondaga Lime (Recent Seneca Discovery) Depth: 2,500' - 6,000' (Southern NY / PA) Trenton, Black River Depth: 1,800' - 2,500' (Central NY) 8,000' - 15,000' (Southern NY / PA) Theresa Depth: 5,000' - 7,000' (Southern NY) AGA FINANCIAL FORUM Apr 30, 2007	

 

Production: 38 - 44 BCFE Number of Wells to be Drilled: 309 - 368 Expenses/Mcfe Estimated Range DD&A $2.20 - $2.30 LOE $1.10 - $1.25 Other Taxes (% of Revenue) $0.20 - $0.25 Other Operating Expenses $ 6 MM - $ 7 MM General and Administrative $20 MM - $22 MM Exploration & Production Seneca Resources Forecast Data for Fiscal 2008	

 

$17.81 / MCF Fiscal 2008 $ 7.42 / MCF 1.4 BCF Gas Highest Ceiling Price Lowest Floor Price Volume No-cost Collars $ 8.47 / MCF 10.8 BCF Gas $58.78 / BBL 1.4 MMBBL Oil Average Hedge Price Volume Swaps Fiscal 2009 $62.00 / BBL 0.4 MMBBL Oil Average Hedge Price Volume Swaps $ 8.83 / MCF 4.0 BCF Gas Seneca Resources Hedging Summary	

 

Certain statements contained herein, including those regarding future earnings, developments and operational results, and those which use words such as "anticipates," "estimates," "expects," "intends," "plans," "predicts," "projects," and similar expressions, are "forward-looking statements" as defined by the Private Securities Litigation Reform Act of 1995. 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 those discussed in the forward-looking statements: changes in laws and regulations to which the Company is subject, including changes in tax, environmental, safety and employment laws and regulations; changes in economic conditions, including economic disruptions caused by terrorist activities, acts of war or major accidents; 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; impairments under the Securities and Exchange Commission's full cost ceiling test for natural gas and oil reserves; 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; governmental/regulatory actions, initiatives and proceedings, including those involving acquisitions, financings, rate cases (which address, among other things, allowed rates of return, rate design and retained gas), affiliate relationships, industry structure, franchise renewal, and environmental/safety requirements; 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, including changes in the plans of the sponsors of the proposed Millennium Pipeline with respect to that project; the nature and projected profitability of pending and potential projects and other investments, and the ability to obtain necessary governmental approvals and permits; occurrences affecting the Company's ability to obtain funds from operations or from issuances of short-term notes or debt or equity securities to finance needed capital expenditures and other investments, including any downgrades in the Company's credit ratings; uncertainty of oil and gas reserve estimates; ability to successfully identify and finance acquisitions or other investments and ability to operate and integrate existing and any subsequently acquired business or properties; ability to successfully identify, drill for and produce economically viable natural gas and oil reserves; significant changes from expectations in the Company's actual production levels for natural gas or oil; regarding foreign operations, changes in trade and monetary policies, inflation and exchange rates, taxes, operating conditions, laws and regulations related to foreign operations, and political and governmental changes; 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; changes in actuarial assumptions and the return on assets with respect to the Company's retirement plan and post-retirement benefit plans; 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. 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. Safe Harbor For Forward Looking Statements	

 

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. Comparable GAAP Financial Measure Slides and Reconciliations	

 

2001 2002 2003 2004 2005 2006 2007 387.9 205.8 104.8 163.2 103.3 297.4 101.8 Fiscal Year National Fuel Gas Company Consolidated Net Cash Used in Investing Activities $ Millions	

 

P&S Utility Timber Energy Mkt. Corp. & Other E&P NI 56.4 50.9 3.7 7.7 8.1 210.7 National Fuel Gas Company Net Income $337.5 Million 12 Months Ended September 30, 2007	

 

Earnings Dividends Paid 85 0.95 0.48 86 0.88 0.53 87 0.88 0.58 88 0.83 0.61 89 0.97 0.64 90 0.92 0.68 91 0.82 0.72 92 0.97 0.74 93 1.08 0.76 94 1.16 0.78 95 1.02 0.8 96 1.39 0.82 97 1.49 0.85 98 0.3 0.88 99 1.47 0.91 '00 1.61 0.94 '01 0.82 0.97 '02 1.46 1.02 '03 2.2 1.04 '04 2.01 1.09 '05 2.23 1.13 '06 1.61 1.17 '07 3.96 1.21 National Fuel Gas Company Earnings vs. Dividends Paid Fiscal Year Dividends Paid Earnings per Diluted Share $3.96	

 

2002 2003 2004 2005 2006 2007 Pipeline & Storage 0.37 0.56 0.58 0.71 0.65 0.66 All Other Segments 1.09 1.64 1.43 1.52 0.96 3.3 $2.20 $2.01 $2.23 Fiscal Year Pipeline & Storage vs. Consolidated NFG Diluted Earnings per Share $1.61 $3.96	

 

2002 2003 2004 2005 2006 2007 Timber 0.12 1.38 0.06 0.06 0.07 0.04 All Other Segments 1.34 0.82 1.95 2.17 1.54 3.92 $2.20 $2.01 $2.23 Fiscal Year Timber vs. Consolidated NFG Diluted Earnings per Share $1.61 $3.96	

 

2002 2003 2004 2005 2006 2007 Energy Marketing 0.11 0.07 0.07 0.06 0.07 0.09 All Other Segments 1.35 2.13 1.94 2.17 1.54 3.87 Fiscal Year Energy Marketing vs. Consolidated NFG Diluted Earnings per Share $2.20 $2.01 $2.23 $1.61 $3.96	

 

2002 2003 2004 2005 2006 2007 4.29 4 5.27 3.73 5.48 4.62 Fiscal Year National Fuel Gas Company Net Cash Provided by Operating Activities per Diluted Share	

 

2002 2003 2004 2005 2006 2007 Utility 0.62 0.7 0.56 0.46 0.55 0.6 All Other Segments 0.84 1.5 1.45 1.77 1.06 3.36 $2.20 $2.01 $2.23 Fiscal Year Utility vs. Consolidated NFG Diluted Earnings per Share $1.61 $3.96	

 

2002 2003 2004 2005 2006 2007 Utility 169 179 194 211 204 203 All Other Segments 225 207 220 193 210 193 Fiscal Year $ Millions Utility vs. Consolidated NFG O & M Expense $386 $414 $404 $414 $396	

 

2002 2003 2004 2005 2006 2007 Pipeline & Storage 61 61 68 65 66 61 All Other Segments 333 325 346 339 348 335 Fiscal Year $ Millions Pipeline & Storage vs. Consolidated NFG O & M Expense $386 $414 $404 $414 $396	

 

2002 2003 2004 2005 2006 2007 Exploration & Production 0.33 -0.39 0.66 0.6 0.24 2.47 All Other Segments 1.13 2.59 1.35 1.63 1.37 1.49 $2.20 $2.01 $2.23 Fiscal Year Exploration & Production vs. Consolidated NFG Diluted Earnings per Share $1.61 $3.96	

 
Reconciliation of Segment Net Income to
      Consolidated Net Income
(‘000)
 	 	 	 	 	 	 	 	 	
 	 	12 Mos Ended 9/30/07	 	
Utility	 	 	 	 	 	$	50,886	 	
 	 	 	 	 	 	 	 	 	
Pipeline & Storage	 	$	49,711	 	 	 	 	 	
Plus: Reversal of reserve for preliminary project costs	 	 	4,787	 	 	 	 	 	
Discontinuance of hedge accounting	 	 	1,888	 	 	 	56,386	 	

Exploration & Production	 	$	74,889	 	 	 	 	 	
Plus: Gain on disposal of discontinued operations.	 	 	120,301	 	 	 	 	 	
Earnings from discontinued operations	 	 	15,479	 	 	 	210,669	 	

Energy Marketing	 	$	5,319	 	 	 	 	 	
Plus: Resolution of purchased gas contingency	 	 	2,344	 	 	 	7,663	 	

Timber	 	 	 	 	 	 	3,728	 	
 	 	 	 	 	 	 	 	 	
Corporate & Other	 	 	 	 	 	 	8,123	 	

Consolidated Net Income	 	 	 	 	 	$	337,455	 	

 
NATIONAL FUEL GAS COMPANY
AND SUBSIDIARIES
RECONCILIATION TO REPORTED EARNINGS
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Fiscal Year	 	 	Fiscal Year	 	 	Fiscal Year	 	 	Fiscal Year	 	 	Fiscal Year	 	
 	 	Ended	 	 	Ended	 	 	Ended	 	 	Ended	 	 	Ended	 	
(Diluted Earnings Per Share)	 	September 30, 2003	 	 	September 30, 2004	 	 	September 30, 2005	 	 	September 30, 2006	 	 	September 30, 2007	 	
 	 	 	
Utility	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Reported earnings	 	$	0.70	 	 	$	0.56	 	 	$	0.46	 	 	$	0.58	 	 	$	0.60	 	
Out-of-period adjustment to symmetical sharing	 	 	—	 	 	 	—	 	 	 	—	 	 	 	(0.03	)	 	 	—	 	
Pension settlement loss	 	 	—	 	 	 	0.03	 	 	 	—	 	 	 	—	 	 	 	—	 	
 	 	         	
Earnings before non-recurring items	 	 	0.70	 	 	 	0.59	 	 	 	0.46	 	 	 	0.55	 	 	 	0.60	 	

Pipeline and Storage	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Reported earnings	 	 	0.56	 	 	 	0.58	 	 	 	0.71	 	 	 	0.65	 	 	 	0.66	 	
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 non-recurring items	 	 	0.56	 	 	 	0.60	 	 	 	0.63	 	 	 	0.65	 	 	 	0.58	 	

Exploration and Production	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Reported earnings	 	 	(0.39	)	 	 	0.66	 	 	 	0.60	 	 	 	0.24	 	 	 	2.47	 	
Gain on disposal of discontinued operations	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	(1.41	)	
Earnings from discontinued operations	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	(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	 	 	 	—	 	 	 	—	 	 	 	0.54	 	 	 	—	 	
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 non-recurring items	 	 	0.46	 	 	 	0.61	 	 	 	0.60	 	 	 	0.71	 	 	 	0.88	 	

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 non-recurring items	 	 	(0.02	)	 	 	0.01	 	 	 	 	 	 	 	 	 	 	 	 	 	
  Energy Marketing	 	   	 	 	 	 	 	 	 	 	 	 	 	 	
Reported earnings	 	 	0.07	 	 	 	0.07	 	 	 	0.06	 	 	 	0.07	 	 	 	0.09	 	
Resolution of a purchased gas contingency	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	(0.03	)	
Pension settlement loss	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	
 	 	 	
Earnings before non-recurring items	 	 	0.07	 	 	 	0.07	 	 	 	0.06	 	 	 	0.07	 	 	 	0.06	 	
  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 non-recurring items	 	 	0.12	 	 	 	0.07	 	 	 	0.06	 	 	 	0.07	 	 	 	0.04	 	

Corporate and All Other	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Reported earnings	 	 	—	 	 	 	0.01	 	 	 	(0.08	)	 	 	—	 	 	 	0.10	 	
Pension settlement loss	 	 	—	 	 	 	0.02	 	 	 	—	 	 	 	—	 	 	 	—	 	
 	 	     	
Earnings before non-recurring items	 	 	—	 	 	 	0.03	 	 	 	(0.08	)	 	 	—	 	 	 	0.10	 	

Consolidated	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Reported earnings	 	 	2.20	 	 	 	2.01	 	 	 	 	 	 	 	 	 	 	 	 	 	
Total non-recurring items from above	 	 	(0.31	)	 	 	(0.03	)	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Earnings before non-recurring items	 	$	1.89	 	 	$	1.98	 	 	 	 	 	 	 	 	 	 	 	 	 	

Consolidated Earnings from Continuing Operations	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Reported earnings from continuing operations	 	 	 	 	 	 	 	 	 	 	1.81	 	 	 	1.61	 	 	 	3.96	 	
Total non-recurring items from above	 	 	 	 	 	 	 	 	 	 	(0.08	)	 	 	0.44	 	 	 	(1.70	)	
 	 	 	 	 	 	 	 	 	 	 	
Earnings from continuing operations before non-recurring items	 	 	 	 	 	 	 	 	 	$	1.73	 	 	$	2.05	 	 	$	2.26	 	

Discontinued Operations	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Reported earnings from discontinued operations	 	 	 	 	 	 	 	 	 	 	0.42	 	 	 	 	 	 	 	 	 	

Consolidated	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Reported earnings	 	 	 	 	 	 	 	 	 	$	2.23	 	 	$	1.61	 	 	$	3.96	 	

 

Reconciliation of Pipeline & Storage Operating Revenues to
      Consolidated Operating Revenues Fiscal 2007
($Millions)
 	 	 	 	 	
Pipeline Revenues	 	$	122.9	 	
Storage Revenues	 	$	67.1	 	
Other Revenues	 	$	21.9	 	
 	 	 	 	
Total Pipeline & Storage Revenues	 	$	211.9	 	
All Other Segments	 	$	1,827.7	 	
 	 	 	 	
Total Corporation	 	$	2,039.6	 	
 	 	 	 	
Reconciliation of Pipeline & Storage O&M Expense to
      Consolidated O&M Expense (From Continuing Operations)
($000s)
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	2003	 	2004	 	2005	 	2006	 	2007	
 	 	         	
Pipeline & Storage	 	$	61,286	 	 	$	65,071	 	 	$	65,397	 	 	$	66,340	 	 	$	61,230	 	
SFAS 88 Pension Settlement	 	 	—	 	 	 	3,026	 	 	 	—	 	 	 	—	 	 	 	—	 	
All Other Segments	 	 	324,984	 	 	$	345,496	 	 	 	339,120	 	 	 	328,949	 	 	 	335,178	 	
 	 	     	
Total Corporation	 	$	386,270	 	 	$	413,593	 	 	$	404,517	 	 	$	395,289	 	 	$	396,408	 	

 

Reconciliation of Utility Segment O&M Expense to
      Consolidated O&M Expense (From Continuing Operations)
($000s)
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	2003	 	2004	 	2005	 	2006	 	2007	
 	 	         	
Utility Segment	 	$	179,052	 	 	$	190,669	 	 	$	211,019	 	 	$	204,330	 	 	$	202,965	 	
SFAS 88 Pension Settlement	 	$	—	 	 	$	3,374	 	 	$	—	 	 	$	—	 	 	 	—	 	
All Other Segments	 	 	207,218	 	 	$	219,550	 	 	$	193,498	 	 	$	190,959	 	 	 	193,443	 	
 	 	         	
Total Corporation	 	$	386,270	 	 	$	413,593	 	 	$	404,517	 	 	$	395,289	 	 	$	396,408	 	
 	 	         	
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	
 	 	       	
Utility Aged Accounts Receivable	 	$	68.1	 	 	$	76.3	 	 	$	89.7	 	 	$	120.5	 	
Utility Current/Other Accounts Receivable	 	$	18.2	 	 	$	16.4	 	 	$	11.8	 	 	$	8.8	 	
 	 	       	
Utility Gross Accounts Receivable	 	$	86.3	 	 	$	92.7	 	 	$	101.5	 	 	$	129.3	 	
Utility Reserve for Bad Debt	 	$	(12.9	)	 	$	(25.1	)	 	$	(29.7	)	 	$	(27.2	)	
 	 	       	
Utility Net Accounts Receivable	 	$	73.4	 	 	$	67.6	 	 	$	71.8	 	 	$	102.1	 	
 	 	       	
All Other Segments Gross Accounts Receivable	 	$	61.0	 	 	$	89.3	 	 	$	103.5	 	 	$	71.7	 	
All Other Segments Reserve for Bad Debts	 	$	(4.6	)	 	$	(1.8	)	 	$	(1.7	)	 	$	(1.4	)	
 	 	       	
All Other Segments Net Accounts Receivable	 	$	56.4	 	 	$	87.5	 	 	$	101.8	 	 	$	70.3	 	
 	 	       	
Total Corporation Accounts Receivable — Net	 	$	129.8	 	 	$	155.1	 	 	$	173.7	 	 	$	172.4	 	

 
Reconciliation of National Fuel Gas Expenditures for Long-lived Assets to
      Consolidated Net Cash Used in Investing Activities
(‘000)
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	2003	 	2004	 	2005	 	2006	 	2007	
 	 	         	
Capital Expenditures	 	$	(152,251	)	 	$	(172,341	)	 	$	(219,530	)	 	$	(294,159	)	 	$	(276,728	)	
Investment in Subsidiaries, Net of Cash	 	 	(228,814	)	 	$	—	 	 	$	—	 	 	$	—	 	 	$	—	 	
Investment in Partnerships	 	$	(375	)	 	$	—	 	 	$	—	 	 	$	—	 	 	$	(3,300	)	
 	 	         	
Expenditures for Long Lived Assets	 	$	(381,440	)	 	$	(172,341	)	 	$	(219,530	)	 	$	(294,159	)	 	$	(280,028	)	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Expenditures for Long Lived Assets	 	$	(381,440	)	 	$	(172,341	)	 	$	(219,530	)	 	$	(294,159	)	 	$	(280,028	)	
Net Proceeds from Sale of Foreign Subsidiary	 	$	—	 	 	$	—	 	 	$	111,619	 	 	$	—	 	 	$	232,092	 	
Cash Held in Escrow	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	$	(58,248	)	
Net Proceeds from Sale of Timber Properties	 	$	186,014	 	 	$	—	 	 	$	—	 	 	$	—	 	 	$	—	 	
Net Proceeds from Sale of Oil and Gas Producing Properties	 	$	78,531	 	 	$	7,162	 	 	$	1,349	 	 	$	13	 	 	$	5,137	 	
Other	 	$	12,065	 	 	$	1,974	 	 	$	3,238	 	 	$	(3,230	)	 	$	(725	)	
 	 	     	
Net Cash Used in Investing Activities	 	$	(104,830	)	 	$	(163,205	)	 	$	(103,324	)	 	$	(297,376	)	 	$	(101,772	)	

 

Reconciliation of Exploration & Production Segment Capital Expenditures to
      Consolidated Capital Expenditures
($000s)
 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	2006	 	2007	 	2008E	
 	 	     	
Exploration & Production Capital Expenditures	 	$	208,303	 	 	$	146,687	 	 	$	151,000 - $159,000	 	
Expenditures from Discontinued Operations	 	 	 	 	 	 	29,129	 	 	 	 	 	
 	 	 	
Total Exploration & Production Capital Expenditures	 	$	208,303	 	 	$	175,816	 	 	$	151,000 - $159,000	 	
All Other	 	 	85,856	 	 	$	100,912	 	 	$	206,000	 	
 	 	     	
Total Corporation	 	$	294,159	 	 	$	276,728	 	 	$	357,000 - $365,000	 	
 	 	     	
Reconciliation of Exploration & Production Operating Revenue to
      Consolidated Operating Revenue
($000s)
 	 	 	 	 	
 	 	2007	 	
Exploration & Production	 	$	324,037	 	
All Other Segments	 	 	1,715,529	 	
 	 	 	 	
Consolidated Operating Revenue	 	$	2,039,566	 	
 	 	 	 	
Reconciliation of Exploration & Production Net Income to
      Consolidated Net Income
($000s)
 	 	 	 	 	
 	 	2007	 	
Exploration & Production (Income from Continuing Operations)	 	$	74,889	 	
Income from Discontinued Operations, Net of Tax	 	 	15,479	 	
Gain on Disposal of Discontinued Operations, Net of Tax	 	 	120,301	 	
 	 	 	 	
Total Exploration & Production	 	$	210,669	 	
All Other Segments	 	 	126,786	 	
 	 	 	 	
Consolidated Net Income	 	$	337,455	 	

 

Reconciliation of Exploration & Production Lease Operating Expense (LOE) to
      Consolidated O&M
($000s)
 	 	 	 	 	
 	 	2007	 	
Exploration & Production LOE	 	$	43,916	 	
Exploration & Production Property, Franchise and Other Taxes	 	 	4,493	 	
 	 	 	 	
Exploration & Production Total LOE *	 	$	48,409	 	

Exploration & Production LOE	 	$	43,916	 	
Exploration & Production Other O&M	 	 	28,324	 	
 	 	 	 	
Exploration & Production Total O&M	 	$	72,240	 	
All Other Segments O&M	 	 	324,168	 	
 	 	 	 	
Total Consolidated O&M	 	$	396,408	 	

Exploration & Production Property, Franchise and Other Taxes	 	$	4,493	 	
All Other Segments Property, Franchise and Other Taxes	 	 	66,167	 	
 	 	 	 	
Total Consolidated Property Franchise and Other Taxes	 	$	70,660	 	
 	 	 	 	
Reconciliation of Exploration & Production Depreciation, Depletion and Amortization to
      Consolidated Depreciation, Depletion and Amortization (DD&A)
($000s)
 	 	 	 	 	
 	 	2007	 	
Exploration & Production DD&A *	 	$	78,174	 	
All Other Segments DD&A	 	 	79,745	 	
 	 	 	 	
Consolidated DD&A	 	$	157,919	 	

			
*	 	DD&A and Total LOE cost per Mcf equivalent equals Exploration & Production DD&A and Total LOE costs, respectively, for the referenced fiscal period, divided by the Total Gas & Oil Production (Mmcfe) in that same fiscal period.	

 

Reconciliation of Exploration & Production General & Administrative Costs to
      Consolidated O&M
($000s)
 	 	 	 	 	
 	 	2007	 	
Exploration & Production General & Administrative *	 	$	19,946	 	
Exploration & Production All Other O&M	 	 	52,294	 	
 	 	 	 	
Exporation & Production Total O&M	 	$	72,240	 	
All Other Segments O&M	 	 	324,168	 	
 	 	 	 	
Total Consolidated O&M	 	$	396,408	 	

			
*	 	General and Administrative cost per Mcf equivalent equals Exploration & Production General and Administrative cost, for the referenced fiscal period, divided by the Total Gas & Oil Production (Mmcfe) in that same fiscal period.	

 

Free Cash Flow Per Diluted Share Calculation
and Reconciliation to Net Cash Provided by Operating Activities
($000s)
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
 	 	Fiscal Year Ended	 	Fiscal Year Ended	 	Fiscal Year Ended	 	Fiscal Year Ended	 	Fiscal Year Ended	
 	 	September 30, 2003	 	September 30, 2004	 	September 30, 2005	 	September 30, 2006	 	September 30, 2007	
 	 	         	
Net Income	 	$	178,944	 	 	$	166,586	 	 	$	189,488	 	 	$	138,091	 	 	$	337,455	 	
DD&A	 	 	195,226	 	 	 	189,538	 	 	 	193,144	 	 	 	179,615	 	 	 	170,803	 	
Impairment of Oil and Gas Producing Properties	 	 	42,774	 	 	 	—	 	 	 	—	 	 	 	104,739	 	 	 	—	 	
Impairment of Investment in Partnership	 	 	—	 	 	 	—	 	 	 	4,158	 	 	 	—	 	 	 	—	 	
(Income) Loss from Unconsolidated Subsidiaries, Net of Cash Distributions	 	 	703	 	 	 	(19	)	 	 	(1,372	)	 	 	1,067	 	 	 	(3,366	)	
Gain on Sale of Discontinued Operations	 	 	—	 	 	 	—	 	 	 	(27,386	)	 	 	—	 	 	 	(159,873	)	
Loss (Gain) on Sale of Oil and Gas Properties	 	 	58,472	 	 	 	(4,645	)	 	 	—	 	 	 	—	 	 	 	—	 	
(Gain) Loss on Sale of Timber Properties	 	 	(168,787	)	 	 	1,252	 	 	 	—	 	 	 	—	 	 	 	—	 	
Deferred Income Taxes	 	 	78,369	 	 	 	40,329	 	 	 	40,388	 	 	 	(5,230	)	 	 	52,847	 	
Minority Interest in Foreign Subsidiaries	 	 	785	 	 	 	1,933	 	 	 	2,645	 	 	 	—	 	 	 	—	 	
Cumulative Effect of Changes in Accounting	 	 	8,892	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	
Other	 	 	11,289	 	 	 	9,839	 	 	 	7,390	 	 	 	4,829	 	 	 	16,399	 	
 	 	         	
 	 	 	406,667	 	 	 	404,813	 	 	 	408,455	 	 	 	423,111	 	 	 	414,265	 	
Less: Dividends Paid on Common Stock (Including Dividends to Minority Interests)	 	 	(84,530	)	 	 	(89,092	)	 	 	(106,835	)	 	 	(98,266	)	 	 	(100,632	)	
Plus: Net Proceeds from Sale of Oil and Gas Producing Properties	 	 	78,531	 	 	 	7,162	 	 	 	1,349	 	 	 	13	 	 	 	5,137	 	
Plus: Net Proceeds from Sale of Timber Properties	 	 	186,014	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	
Plus: Net Proceeds from Sale of Foreign Subsidiary	 	 	—	 	 	 	—	 	 	 	111,619	 	 	 	—	 	 	 	232,092	 	
Plus: Investment in Partnership	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	(3,300	)	
Plus: Cash Held in Escrow	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	(58,248	)	
Less: Expenditures for Long-Lived Assets	 	 	(381,440	)	 	 	(172,341	)	 	 	(219,530	)	 	 	(294,159	)	 	 	(276,728	)	
 	 	     	
Free Cash Flow	 	$	205,242	 	 	$	150,542	 	 	$	195,058	 	 	$	30,699	 	 	$	212,586	 	

Weighted Average Diluted Shares	 	 	81,358	 	 	 	82,900	 	 	 	85,029	 	 	 	86,028	 	 	 	85,301	 	
 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Free Cash Flow Per Share	 	$	2.52	 	 	$	1.82	 	 	$	2.29	 	 	$	0.36	 	 	$	2.49	 	

Reconciliation to Net Cash Provided by Operating Activities:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Free Cash Flow	 	$	205,242	 	 	$	150,542	 	 	$	195,058	 	 	$	30,699	 	 	$	212,586	 	
Add Back:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Expenditures for Long-Lived Assets	 	 	381,440	 	 	 	172,341	 	 	 	219,530	 	 	 	294,159	 	 	 	276,728	 	
Dividends Paid on Common Stock (Inc. Dividends to Minority Interests)	 	 	84,530	 	 	 	89,092	 	 	 	106,835	 	 	 	98,266	 	 	 	100,632	 	
Investment in Partnership	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	3,300	 	
Cash Held in Escrow	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	 	 	58,248	 	
Other	 	 	—	 	 	 	—	 	 	 	—	 	 	 	3,230	 	 	 	725	 	
Deduct:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Net Proceeds from Sale of Oil and Gas Producing Properties	 	 	(78,531	)	 	 	(7,162	)	 	 	(1,349	)	 	 	(13	)	 	 	(5,137	)	
Net Proceeds from Sale of Timber Properties	 	 	(186,014	)	 	 	—	 	 	 	—	 	 	 	—	 	 	 	—	 	
Net Proceeds from Sale of Foreign Subsidiary	 	 	—	 	 	 	—	 	 	 	(111,619	)	 	 	—	 	 	 	(232,092	)	
Change in:	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	
Hedging Collateral Deposits	 	 	(1,109	)	 	 	(7,151	)	 	 	(69,172	)	 	 	58,108	 	 	 	15,610	 	
Receivables and Unbilled Utility Revenue	 	 	(28,382	)	 	 	4,840	 	 	 	(31,246	)	 	 	(12,343	)	 	 	5,669	 	
Gas Stored Underground & Materials and Supplies	 	 	(13,826	)	 	 	13,662	 	 	 	1,934	 	 	 	1,679	 	 	 	(5,714	)	
Unrecovered Purchased Gas Costs	 	 	(16,261	)	 	 	21,160	 	 	 	(7,285	)	 	 	1,847	 	 	 	(1,799	)	
Prepayments and Other Current Assets	 	 	(12,628	)	 	 	37,390	 	 	 	(30,390	)	 	 	(39,572	)	 	 	18,800	 	
Accounts Payable	 	 	13,699	 	 	 	(5,134	)	 	 	48,089	 	 	 	(23,144	)	 	 	(26,002	)	
Amounts Payable to Customers	 	 	692	 	 	 	2,462	 	 	 	(1,996	)	 	 	22,777	 	 	 	(13,526	)	
Customer Advances	 	 	—	 	 	 	—	 	 	 	—	 	 	 	4,946	 	 	 	(6,554	)	
Other Accruals and Current Liabilities	 	 	9,343	 	 	 	2,082	 	 	 	16,085	 	 	 	(17,754	)	 	 	8,950	 	
Other Assets	 	 	(9,343	)	 	 	(2,525	)	 	 	(13,461	)	 	 	(22,700	)	 	 	4,109	 	
Other Liabilities	 	 	(23,124	)	 	 	(34,450	)	 	 	(3,667	)	 	 	80,960	 	 	 	(5,922	)	
 	 	         	
Net Cash Provided by Operating Activities	 	$	325,728	 	 	$	437,149	 	 	$	317,346	 	 	$	481,145	 	 	$	408,611