Fiscal 2010 Y Year End Analyst Day E d A l t D November 9, 2010 - - PowerPoint PPT Presentation

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Fiscal 2010 Y Year End Analyst Day E d A l t D November 9, 2010 - - PowerPoint PPT Presentation

Fiscal 2010 Y Year End Analyst Day E d A l t D November 9, 2010 Safe Harbor For Forward Looking Statements This presentation may contain forward looking statements as defined by the Private Securities Litigation Reform Act of 1995,


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SLIDE 1

Fiscal 2010 Y E d A l t D Year‐End Analyst Day

November 9, 2010

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SLIDE 2

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

  • r accomplished.

I dditi t th f t th f ll i i t t f t th t ld t l lt t diff t i ll f lt f d t i th f d l ki t t t fi i l d 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; 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; 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 or the valuation of the Company’s natural gas and oil reserves; impairments under the SEC’s full cost ceiling test for l d il i f il d i f ff i h C ’ bili f ll id if d ill f d d i ll i bl l d natural gas and oil reserves; uncertainty of oil and gas reserve estimates; factors affecting the Company’s ability to successfully identify, drill for and produce economically viable natural gas and

  • il 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, and the need to obtain governmental approvals and permits and comply with environmental laws and regulations; significant differences between the Company’s projected and 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 oil having different quality and/or different geographic locations, or changes in the price differentials between natural gas having different heating values and/or different geographic locations; 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; the nature and projected profitability of pending and potential projects and other investments, and the ability to obtain necessary governmental approvals and permits; significant differences between the Company’s projected and actual capital expenditures and operating expenses, and unanticipated project f f ff / delays or changes in project costs or plans; 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 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. 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, 2009 and the Company’s Forms 10‐Q for the quarters ended December 31, 2009, March 31, 2010 and June 30, 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. The Securities and Exchange Commission (the “SEC”) currently permits the Company, in its filings with the SEC, to disclose only proved reserves that the Company has demonstrated by actual

2

Analyst Day – November 9, 2010

production or conclusive formation tests to be economically and legally producible under existing economic and operating conditions. The Company uses the terms “probable,” “possible,” “resource potential” and other descriptions of volumes of reserves or resources potentially recoverable through additional drilling or recovery techniques that the SEC’s guidelines would prohibit us from including in filings with the SEC. These estimates are by their nature more speculative than estimates of proved reserves and, accordingly, are subject to substantially greater risk of being actually realized. Investors are urged to consider closely the disclosure in our Form 10‐K and Forms 10‐Q available at www.nationalfuelgas.com. You can also obtain these forms on the SEC’s website at www.sec.gov.

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SLIDE 3

National Fuel Gas Company

Business Segment Reporting

Publicly Traded

National Fuel Gas Company

y Holding Company NYSE symbol ‐ NFG i

Exploration & Production Pipeline & Storage Utility Energy Marketing

Reporting Segments

Seneca Resources Corporation National Fuel Gas Supply Corporation National Fuel Gas Distribution Corporation National Fuel Resources, Inc.

Operating Subsidiaries

Empire Pipeline, Inc.

3

Analyst Day – November 9, 2010

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SLIDE 4

National Fuel Gas Company

Our Businesses

  • Utility
  • Pipeline & Storage
  • Exploration & Production

p

Appalachia, California, Gulf of Mexico

  • Energy Marketing

gy g

  • Midstream
  • Timber
  • Timber
  • Landfill Gas
  • Gas Fired Generation

4

Analyst Day – November 9, 2010

  • Gas‐Fired Generation
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SLIDE 5

National Fuel Gas Company

Net Plant by Segment

$5,000 Utility P&S E&P Mktg, Corp & All Other

$3,154 $3,133 $3,450 $3,906

$4,000

)

$1,002 $983 $1,096 $1,042 $1,339 $1,656

$2,878 $2,878 $ , $3,133

$2,000 $3,000

($ Millions)

$1 084 $1 099 $1 126 $1 144 $1,165 $1,179 $674 $682 $827 $839 $858 $952 $1,000 $2,000 $1,084 $1,099 $1,126 $1,144 $ , $0

2006 2007 2008 2009 2010 2011 Forecast

5

Analyst Day – November 9, 2010

Forecast

At Fiscal Year End

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SLIDE 6

National Fuel Gas Company

Net Income from Continuing Operations

Excluding Items Impacting Comparability (1)

$266 3

$300

$192.2 $266.3 $210.5

$200

P&S

$36.7 MM 16.7%

$74.9 $146.6 $98.0

$

$200

$ Millions)

Utility

$62.5 MM 28 5%

E&P

$112.5 MM 51.4%

$50 9 $61.5 $58 7 $49.7 $54.1 $47.4 $100

($ 28.5%

$50.9 $61.5 $58.7 $0

2007 2008 2009

Fiscal Year Ended

$219.1 Million

Fiscal Year Ended

6

Analyst Day – November 9, 2010

(1) A reconciliation to GAAP Net Income is included at the end of this presentation.

Utility P&S E&P Mktg, Corp & All Other

Fiscal Year Ended September 30, 2010

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SLIDE 7

National Fuel Gas Company

A Balanced Business Model

Net Income from Continuing Operations(1) – Excluding Items Impacting Comparability

$300

43%

$192 2 $266.3 $210.5

$

52% 43% 50%

$192.2

$200

Millions)

Unregulated

55%

Regulated

45%

48% 57% 50%

$100

($ M

55%

$0

2007 2008 2009

Fiscal Year Ended

$219.1 Million

Fiscal Year Ended

7

Analyst Day – November 9, 2010

(1) A reconciliation to GAAP Net Income is included at the end of this presentation.

Fiscal Year Ended

Unregulated Regulated

Fiscal Year Ended September 30, 2010

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SLIDE 8

National Fuel Gas Company

Oil G

Seneca Resources Corporation – Oil and Gas Revenues

$453 $374 $426

$400 $500

Millions)

Oil Gas

46% 45% 41% 43% $311 $374

$300 $400

evenues ($ M 54% 55% 59% 57% 46%

$100 $200

il and Gas Re 54%

$0 $100

2007 2008 2009 2010 Total Oi

8

Analyst Day – November 9, 2010

Fiscal Year Ended

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SLIDE 9

National Fuel Gas Company

Peer Group Comparisons

1‐Year Total Return 3‐Year Total Return 5‐Year Total Return

Peer Group Total Return Utility Peers 22%

National Fuel 19%

1 Year Total Return

Peer Group Total Return

National Fuel 20%

Utility Peers 19%

3 Year Total Return

Peer Group Total Return

National Fuel 74%

Utility Peers 34%

5 Year Total Return

National Fuel 19%

Diversified Peers 9% E&P Peers 8% Utility Peers 19% E&P Peers ‐10% Diversified Peers ‐27% Utility Peers 34% E&P Peers 4% Diversified Peers ‐3%

National Fuel’s Diversified business model continues to generate long‐term outperformance versus its peer groups by g g p f p g p y limiting downside risk through economically challenging times and capturing upside growth in an expanding market

9

Analyst Day – November 9, 2010

All returns are for the period starting October 1, 20XX and ending September 30, 2010. 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: ATLS, BRY, CHK, CNX, COG, CRZO, EOG, PETD, PVA, RRC, SFY, SM, SWN, UNT, VQ, XCO

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SLIDE 10

National Fuel Gas Company

Capital Expenditures(1) – An Appalachian Focus

$1,000

Appalachian Growth ‐ E&P Appalchian Growth ‐ Infrastructure Other Spending

(2) (3)

$605‐740 $750

Millions)

$90‐105 $129 $130 – 195

$417 $307 $501 $500

ditures ($ M

$ 39 $356 $385 ‐ 440 $225 $208 $351 $161

$252 $248 $307 $250

pital Expen

$139

$0

2006 2007 2008 2009 2010 2011 Forecast Cap

10

Analyst Day – November 9, 2010

Forecast

Fiscal Year

(1) A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation. (2) Defined as spending related to efforts to drill for, gather, or transport Appalachian sources of natural gas. (3) Any other maintenance spending in the Appalachian region, plus spending in areas outside of the Appalachian region.

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SLIDE 11

Seneca Resources

Evaluation of JV Opportunities

  • Seneca has engaged Jefferies & Company to explore joint‐venture
  • pportunities across a broad portion of its acreage with the following goals:
  • pportunities across a broad portion of its acreage, with the following goals:
  • Ramp up development faster than current aggressive growth plans
  • Bring forward the earnings stream, where a minority‐interest partner pays a

significant portion of the early drilling costs enhancing shareholder value significant portion of the early drilling costs, enhancing shareholder value

  • Continue operating across most of its acreage position
  • Seneca’s unique Marcellus position provides a competitive advantage for a

potential joint‐venture partner:

  • 800,000 net acres in PA – 745,000 in heart of the Marcellus Fairway
  • Majority of acreage is held in fee, carrying no royalty and no lease expirations

j y g , y g y y p

  • Large, contiguous acreage blocks allow for operating‐ and cost‐efficiency through

multi‐well pad drilling

  • Seneca will forgo joint‐venture opportunities that do not enhance shareholder

11

Analyst Day – November 9, 2010

g j pp value when compared to its current growth plans

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SLIDE 12

National Fuel Gas Company

Independent Directors – A Wealth of Industry Experience

Former Director, President & CEO of Northwest Natural Gas Co. Vice Chairman of DTE Energy Director of Northern Border Pipeline Co. Former Chairman and CEO of Questar Corporation Former Vice Chairman, COO and Director of Keyspan Corporation Individual Responsible for DTE’s Barnett & Antrim Shale Plays Former Advisor to the COO of Duke Energy Former Vice Chairman of PanEnergy Corporation (now part of Spectra) Founder of Kidder Exploration, an Appalachian E&P Co. Director of Hess Corporation Former Chairman & COO of MCN Energy Former CEO of Michigan Consolidated Gas Co. Former President, CEO & Director of NUI Corporation , p Former Director of the Independent Oil & Gas Assoc. of NY & PA CEO and Chairman of Moog Inc. for 20+ Years (Major Company in NFG’s Service Territory) Former Vice-Chairman and CFO of Verizon Inc., a Regulated Industry Director of CMS Energy Corporation

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Analyst Day – November 9, 2010

Director of CMS Energy Corporation Director of Dynegy, Inc.

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SLIDE 13

Utility Segment

N i l F l G Di ib i C i

13 13

Analyst Day – November 9, 2010

National Fuel Gas Distribution Corporation

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SLIDE 14

Analyst Day – November 9, 2010

14

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SLIDE 15

Utility

Keys to Continued Success

Provide Stable Earnings

Operate Safe System Control Costs Excellent Customer Service Strong Regulatory Strategy

15

Analyst Day – November 9, 2010

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SLIDE 16

Utility

Diluted Earnings per Share

(Before Items Impacting Comparability)

$1.00 $0.73 $0.73 $0.76 $0.80 $0.55(1) $0.60 $0.60 $0.40 $0.00 $0.20

16 16

Analyst Day – November 9, 2010 (1) Excludes out‐of‐period adjustment to symmetrical sharing of $0.03; Including this adjustment, GAAP earnings would be $0.58.

2006 2007 2008 2009 2010

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SLIDE 17

Utility

$75

NY PA

Capital Spending

$ $18 0

$60

Millions)

$54.4 $54.2 $57.5 $56.2 $58.0 $16.0 $18.1 $18.3 $18.4 $18.0

$30 $45

ending ($ M

$38.4 $36.1 $39.2 $37.8 $40.0

$15 $30

Capital Spe

$0 2006 2007 2008 2009 2010

C

17

Analyst Day – November 9, 2010

Fiscal Year

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SLIDE 18

Utility

$250

NY PA

O&M Expense

$63 8 $63 8 $62 1 $204.3 $203.0 $202.7 $191.2 $181.3

$200

lions)

$63.8 $63.8 $62.1 $60.7 $56.3

$150

ense ($ Mil

$140.5 $139.2 $140.6 $130.5 $125.0

$50 $100

O&M Expe

$0 2006 2007 2008 2009 2010

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Analyst Day – November 9, 2010

2006 2007 2008 2009 2010

Fiscal Year

slide-19
SLIDE 19

Utility

Excellent Customer Service

C S i P f NY G l NY A l(1) PA A l(1) Customer Service Performance Goal Actual(1) Actual(1)

Telephone Response (within 30 seconds) 74.0% 89.1% 92.3% Customer Satisfaction: Residential Commercial 85.1% 86.0% 92.4% 90.7% 89.5% PSC Complaints (per 100,000 Customers) 2.1 0.1 N/A Estimated Meter Reading

Not to Exceed

15.9% 13.2% 10.2% Adjusted Bills

Not to Exceed

1 9% 1.1% 1.4% 1.9% New Service Gas Installations Installed within 10 Days 98.0% 99.9% 99.7% Non‐Emergency Field Appointments Kept 98 0% 99 2% 99 4%

19

Analyst Day – November 9, 2010

Non‐Emergency Field Appointments Kept 98.0% 99.2% 99.4%

(1) 12-months ended September 30, 2010

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SLIDE 20

Utility

New York Pennsylvania

Rate Mechanisms

Revenue Decoupling Customer Choice / POR

y

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

20

Analyst Day – November 9, 2010

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SLIDE 21

Utility

20.0 NY PA

Return on Equity (1)

14.0 13.2 14.7 15.0

uity (%)

10.3 9.1 10.9 9.8 10.6 11.8 10.0

urn on Equ

6.3 5.0

Retu

0.0 FY 2006 FY 2007 FY 2008 FY 2009 FY 2010

21

Analyst Day – November 9, 2010 (1) Calculated using Average Total Comprehensive Shareholder Equity.

FY 2006 FY 2007 FY 2008 FY 2009 FY 2010

slide-22
SLIDE 22

Utility Challenges

22

Analyst Day – November 9, 2010

slide-23
SLIDE 23

Utility

Average Use per Residential Customer

250 200

count

100 150

ed Mcf/Ac 98.824

50

Normaliz

23

Analyst Day – November 9, 2010

12 Months Ended September (Fiscal Year)

slide-24
SLIDE 24

Utility

Accounts Receivable – Customer (1)

$125 30‐59 Days 60‐89 Days 90‐119 Days 120 Days & Over $91.4 $86 6 $102.4 $99.7 $100 $125

Millions)

$ $75.2 $78 9 $86.6 $72.5 $75

eivable ($ M

$67.9 $64.4 $78.9 $58.3 $ $50

ccounts Rece

$9.3 $9.1 $11.1 $8.3 $6.4

$7.2 $6.6 $7.9 $6.3 $4.2 $7.0 $6.5 $8.2 $6.2 $3.6

$0 $25

Ac

24

Analyst Day – November 9, 2010

At 09/30/06 At 09/30/07 At 09/30/08 At 09/30/09 At 09/30/10

(1) All values include Purchase of Receivables (“POR”) Program

slide-25
SLIDE 25

Utility

HEAP/LIHEAP

$75 NY Basic & Emergency PA Regular & Crisis $58.0 $57.1 $

ions)

g y g $41.9 $35.8 $39.2 $50

nding ($ Mill

$7.7 $6.8 $6 8 $14.6 $14.0 $25

Fun

$7.7 $6.8 $6.8 $0 2006 2007 2008 2009 2010

25

Analyst Day – November 9, 2010

(1) Program year runs from November to May

Program Year (1)

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SLIDE 26

Utility

2011

Provide Stable Earnings

Operate Safe System Control Costs Excellent Customer Service Strong Regulatory Strategy

26

Analyst Day – November 9, 2010

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SLIDE 27

Exploration & Production

S R C i

27 27

Analyst Day – November 9, 2010

Seneca Resources Corporation

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SLIDE 28

Seneca Resources

Fiscal 2010 Highlights

Production

  • Increased annual production by 17% to 49 7 BCFE
  • Increased annual production by 17% to 49.7 BCFE

Reserve Replacement

  • Replaced 445% of production

Finding & Development Cost

  • F&D Cost decreased to approximately $1.80 per Mcfe

M ll E it R t Marcellus Exit Rate

  • Marcellus net production at fiscal year end 2010 was 53 MMcfe per day

Seneca‐Operated IP Rates

  • 6.6 MMcfe per day IP rates across all Seneca‐operated wells
  • 8.5 MMcfe per day IP rates in Tioga and Lycoming county Seneca‐operated wells

EOG Joint‐Venture Results

28

Analyst Day – November 9, 2010

  • Large Frac IPs in Clearfield County have averaged 8.2 MMcfe per day
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SLIDE 29

Exploration & Production

Fiscal 2010 Year End Proved Reserves

East ‐ Appalachia Reserves: 333 Bcfe (48%)

Proved Reserves @ 9/30 503 Bcfe 528 Bcfe 700 Bcfe

FY ’10 Production: 16.5 Bcfe (33%)

55% 53% 61%

503 Bcfe 528 Bcfe 700 Bcfe

53% 39% 45% 47%

2008 2009 2010 West – California Reserves: 333 Bcfe (47%) (55.5 MMBoe)

FY ’10 Production: 19.8 Bcfe (40%)

Gulf of Mexico Reserves: 34 Bcfe (5%)

29

Analyst Day – November 9, 2010

Oil Gas ( )

FY ’10 Production: 13.4 Bcfe (27%)

slide-30
SLIDE 30

Exploration & Production

Proved Reserves at 9/30/10 Probable and Possible Reserves, plus Resource Potential

Marcellus Shale

Accelerate development; Convert resource potential to reserves

202 Bcfe

Appalachian Region ‐ Upper Devonian

Drill 25‐50 wells per year

700 Bcfe 8 ‐ 15 Tcfe 131 Bcfe f

California

l d

700 Bcfe 131 Bcfe

Continue to operate as a low‐cost producer

Gulf of Mexico

333 Bcfe 280 Bcfe

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Analyst Day – November 9, 2010

No exploration; Develop and produce existing reserves

34 Bcfe 15 Bcfe

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SLIDE 31

Exploration & Production

Capital Expenditures by Region

$425‐500

$500 West Upper Devonian Gulf of Mexico Marcellus

$398 $

$400

Millions)

$332 $380‐425

$192 $188

$300

nditures ($ M

$61 $66 $64 $71

$147 $192 $188

$100 $200

Capital Expen

$41 $63 $31(1) $28 $35‐45 $39 $61 $68

$23 $15

$0

Fiscal 2007 Fiscal 2008 Fiscal 2009 Fiscal 2010 Fiscal 2011 C

31

Analyst Day – November 9, 2010

Fiscal 2007 Fiscal 2008 Fiscal 2009 Fiscal 2010 Fiscal 2011 Forecast

(1) 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.

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SLIDE 32

Exploration & Production

Annual Production by Region

75 West Upper Devonian Gulf of Mexico Marcellus 25 30

49.7 60‐70

60

fe)

30% 17%

14 7 14.1 13.7 13.4 9 11 7.2 25‐30

39.3 40.8 42.5

45

duction (Bcf

6.3 7.9 8.7 9.3 7‐9 14.7 9‐11 15 30

Prod

18.3 18.8 20.1 19.8 19‐20

Fiscal 2007 Fiscal 2008 Fiscal 2009 Fiscal 2010 Fiscal 2011

32

Analyst Day – November 9, 2010

Fiscal 2007 Fiscal 2008 Fiscal 2009 Fiscal 2010 Fiscal 2011 Forecast

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SLIDE 33

Exploration & Production

$8.00 NFG All E&P Companies

Finding & Development Cost (1)

$5.98 $4 95

$6.00 All E&P Companies Mid‐Sized Independents

(2)

$4.95 $4.27 $3.10

$4.00

$/Mcfe $1.80

$2.00

(3)

$0.00 2006 2007 2008 2009 2010

33

Analyst Day – November 9, 2010

Fiscal Year

(1) 2006 – 2009 Finding and Development cost information was obtained from IHS Herold, Inc. (2) National Fuel’s 2007 finding and development cost is adjusted for revisions due to a change in reserve auditors. (3) National Fuel’s 2010 finding and development cost was calculated internally.

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SLIDE 34

Exploration & Production

C lif i

34 34

Analyst Day – November 9, 2010

California

slide-35
SLIDE 35

Seneca’s California Properties

South Lost Hills

1,900 BOEPD

North Lost Hills

1,200 BOEPD Tulare & Etchegoin Formation Monterey Shale Primary 216 Active Wells Tulare & Etchegoin Formation Primary & Steamflood 221 Active Wells

North Midway Sunset North Midway Sunset

4,100 BOEPD Potter & Tulare Formation Steamflood 709 Active Wells

Sespe

1,000 BOEPD Sespe Formation Primary

South Midway Sunset

650 BOEPD Primary 182 Active Wells Antelope Formation Steamflood 74 Active Wells

35

Analyst Day – November 9, 2010

slide-36
SLIDE 36

California

Average Daily Production

10,000

  • Modest capital spending

to maintain production

9,500 0,000

  • Pursue additional bolt‐on

acquisitions

  • 2011 Plans:

8,500 9,000

OE/Day

  • CapEx ‐ $40 MM
  • 50 Development wells
  • Two 5‐acre in‐fill wells at

7,500 8,000

B

Sespe

7,000

36

Analyst Day – November 9, 2010

slide-37
SLIDE 37

Exploration & Production

G lf f M i

37 37

Analyst Day – November 9, 2010

Gulf of Mexico

slide-38
SLIDE 38

Gulf of Mexico

Average Daily Production

60

Mi i l i l di

40 50

Minimal capital spending Expect production decline

30 40

MMcfe/Day

in 2011

10 20

M

38

Analyst Day – November 9, 2010

slide-39
SLIDE 39

Exploration & Production

E Di i i

39 39

Analyst Day – November 9, 2010

East Division

slide-40
SLIDE 40

East Division

Average Daily Production

70 50 60 Mcfe/Day)

Upper Devonian Marcellus

Rapid growth in the East Division as Marcellus is

30 40 roduction (MM

ramping up Expect significant production

10 20 erage Daily Pr

Expect significant production increase in Q1

Ave

40

Analyst Day – November 9, 2010

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SLIDE 41

Marcellus Shale

Seneca’s Pennsylvania Acreage

Seneca Resource Acreage Position 745,000 Net Acres in the heart of the PA Marcellus fairway 160,000 Net Acres included in EOG JV 80% Fee – Seneca owns the minerals No lease expiration 94% Average NRI

SRC L A SRC Fee Acreage

41

Analyst Day – November 9, 2010

94% Average NRI

SRC Lease Acreage

slide-42
SLIDE 42

Marcellus Shale

Recent Well Results Validate Seneca’s Position

McKean County

SM E

Lycoming County Tioga County

Seneca Resources SM Energy IP: 7+ MMCFD

y g y

Seneca Resources IP: 15.8 MMCFD

Elk County

  • Avg. IP: 7.9 MMCFD

Clearfield County

Seneca Resources IP: 3.9 MMCFD

Clearfield County

Seneca/EOG IP: 8.9 MMCFD

Armstrong County

EQT IP: 15 MMCFD

SRC L A SRC Fee Acreage

42

Analyst Day – November 9, 2010

SRC Lease Acreage

slide-43
SLIDE 43

Marcellus Shale

Recent Activity

  • Approx. Outline of JV Acreage

200,000 Gross Acres Seneca 50% W.I. (Avg. 58% NRI) Seneca Operated – Tioga 3 Rigs Drilling 12 Wells Producing Average IP: 7.9 MMcf per Day Seneca Operated – Lycoming IP 15 8 MM f D EOG Acreage Contributed IP: 15.8 MMcf per Day EOG Acreage Contributed ~120,000 Gross Acres Seneca 50% W.I. (40% NRI) EOG Operated – Last 4 Completions Bigger Fracs – 5 ½” Casing SRC Lease Acreage SRC Fee Acreage SRC Contributed JV Acreage

43

Analyst Day – November 9, 2010

Average IP: 8.2 MMcf per Day EOG Contributed JV Acreage

slide-44
SLIDE 44

Marcellus Shale

Eastern Development Area

Covington Area – Full Development Seneca Operated Initial Test Wells

  • Tioga/Lycoming/Potter

55,000 Acres

Seneca Operated 24 Wells Drilled; 12 Producing Current Production: 62 MMcf/d 2011: 16 Wells Planned

Drilling / Fracing

Resource Potential: 2 Tcf

DCNR Block 595 – Full Development S O t d Seneca Operated 3 Wells Drilled; 1 Producing Current Production: 5.0 MMCFD 2011: 10‐15 Wells Planned DCNR Block 100 – Full Development Seneca Operated 1 well drilled 2011: 6 Wells Planned First Production: Fall 2011 SRC L A SRC Fee Acreage

44

Analyst Day – November 9, 2010

First Production: Fall 2011 SRC Lease Acreage

slide-45
SLIDE 45

Marcellus Shale

Western Development Area

Seneca Operated

  • Mt. Jewett Area

Seneca Operated EOG Operated 2011: 3 Wells Planned Beechwood Area Seneca Operated 2011: 3 Wells Planned Owl’s Nest Area Seneca Operated Drilling 2011: 3+ Wells Planned Boone Mtn. Area Seneca Operated 3 e s a ed Optimized Landing Target SRC Lease Acreage SRC Fee Acreage SRC Contributed JV Acreage Punxy Area – Full Development EOG Operated p 2011: 3 Wells Planned

45

Analyst Day – November 9, 2010

EOG Contributed JV Acreage 30 Wells Drilled; 8 Producing Current Gross Production: 16 MMcf/d 2011: 30+ Wells Planned

slide-46
SLIDE 46

Tioga County Decline Curves

Longer Lateral Wells Outpacing Original Decline Curve

Avg Tioga Production per Well(1)

  • Avg. Tioga Production per Well(1)

6.3 Bcf Typecurve

46

Analyst Day – November 9, 2010

(1) Chart data represents horizontal well production from wells with lateral lengths greater than 3,000 feet

slide-47
SLIDE 47

Marcellus Shale

Pennsylvania Average Daily Gas Production per Horizontal Well

(Companies with at least 5 horizontal wells producing)

5.0 4.0 n per Well d) 2.0 3.0 Gas Production (Avg. MMcfd 0 0 1.0 Daily G 0.0

47

Analyst Day – November 9, 2010

Source: All data represents Marcellus Shale gas production from July 1, 2009 through June 30, 2010 for companies with at least five producing horizontal wells within the State of Pennsylvania and was provided by the Pennsylvania Department of Environmental Protection. The data was retrieved on November 4, 2010.

slide-48
SLIDE 48

Marcellus Shale

60

Marcellus Net Production

Marcellus net production at

40 50 MMcfe)

September 30, 2010 was:

53 MMcfe per day

30 Production (M

Seneca Operated

20 Daily Net P ‐ 10

EOG JV

48

Analyst Day – November 9, 2010

slide-49
SLIDE 49

Marcellus Shale

Centralized Water System

Recovering water discharged from an b d d l i hi h d l 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 Can supply water for 3 fracs per month System Cost: ~$3.7 Million Cost Savings: ~$120,000 per well

Pay Out: 31 Wells Pay Out: 31 Wells

Other Benefits:

Improved stream quality Substantial reduction of water truck activity

49

Analyst Day – November 9, 2010

activity No need to withdraw water elsewhere

slide-50
SLIDE 50

Marcellus Shale

100‐130 125

EOG JV Wells Seneca Vertical Wells Seneca Horizontal Wells

Wells Drilled per Year

100

60‐80

65 75

ells Drilled

7 5 29

24 25 50

We

11 29 35‐45 10

4 6

Fiscal 2007 Fiscal 2008 Fiscal 2009 Fiscal 2010 Fiscal 2011

50

Analyst Day – November 9, 2010

Fiscal 2007 Fiscal 2008 Fiscal 2009 Fiscal 2010 Fiscal 2011 Forecast

slide-51
SLIDE 51

Marcellus Shale

Pre‐Tax IRR Comparison

D i ti EUR Well Cost ($ MM) Net Working I t t Net Revenue I t t Pre‐Tax IRR (NYMEX ‐ $/MMBtu)

$4 00 $5 00 $6 00

Description EUR ($ MM) Interest Interest

$4.00 $5.00 $6.00

Seneca Tioga County Wells at 18% Royalty 6 Bcf $4.6 100% 82% 63% 100+% 100+% Seneca Mineral Fee Seneca Mineral Fee Wells in EOG JV 4 Bcf $4.0 50% 60% 68% 100+% 100+% Seneca Mineral Fee Wells – No Royalty 4 Bcf $4.0 100% 100% 46% 75% 100+% Competitor Well with 15% Royalty Rate 4 Bcf $4.0 100% 85% 30% 51% 78%

51

Analyst Day – November 9, 2010

slide-52
SLIDE 52

Marcellus Shale

$6.00

Breakeven Pricing at PV10

$4 00 $5.00

$/Mcfe)

On November 1, 2011, NYMEX Strip(1) for Fiscal Year 2011 was $4.03 $ $2.21 $2.32

$3.00 $4.00

even Price (

EUR: 4 Bcf EUR: 6 Bcf EUR: 4 Bcf

$1.93 $2.21

$1.00 $2.00

PV10 Break

NWI: 50% NRI: 60% NWI: 100% NRI: 82% NWI: 100% NRI: 100% $0.00

Seneca Mineral Fee Wells in EOG JV Seneca Tioga/Lycoming Wells at 18% Royalty Seneca Mineral Fee Wells With No Royalty

52

Analyst Day – November 9, 2010

Wells in EOG JV Wells at 18% Royalty Wells With No Royalty

(1) The NYMEX strip prices for fiscal year 2011 include the settlement prices for the October 2010 and November 2010 contracts.

slide-53
SLIDE 53

Seneca Resources

Marcellus Shale Summary

  • Continuing to achieve high IP rates and showing slow decline
  • Continuing to achieve high IP rates and showing slow decline
  • Fourth horizontal rig is on location
  • Will have 3 rigs in East and 1 in West for 1st half of FY2011
  • EOG Program is picking up and showing improvement
  • First “big fracs” came on at high rate
  • Infrastructure constrained in Clearfield County
  • Marcellus production will continue to grow rapidly
  • Fiscal Year 2010 exit rate was 53 MMCFD
  • Fiscal Year 2010 exit rate was 53 MMCFD
  • Expect net 100+ MMCFD by fiscal year end 2011 (9/30/2011)
  • Explore joint‐venture opportunities

53

Analyst Day – November 9, 2010

slide-54
SLIDE 54

Pipeline & Storage / Midstream

National Fuel Gas Supply Corporation Empire Pipeline, Inc.

54 54

Analyst Day – November 9, 2010

National Fuel Gas Midstream Corporation

slide-55
SLIDE 55

Analyst Day – November 9, 2010

55

Analyst Day – November 9, 2010

55

slide-56
SLIDE 56

Analyst Day – November 9, 2010

56

Analyst Day – November 9, 2010

56

slide-57
SLIDE 57

Analyst Day – November 9, 2010

57

Analyst Day – November 9, 2010

57

slide-58
SLIDE 58

Analyst Day – November 9, 2010

58

Analyst Day – November 9, 2010

58

slide-59
SLIDE 59

PIPELINE & STORAGE / MIDSTREAM EXPANSION INITIATIVES

NORTHERN ACCESS LAMONT COMPRESSOR TIOGA COUNTY EXTENSION ACCESS COMPRESSOR STATION PHASE I & II COVINGTON GATHERING SYSTEM LINE “N” EXPANSION PHASE I & II TROUT RUN GATHERING SYSTEM WEST TO EAST OVERBECK TO LEIDY PHASE I & II

Seneca Drilling Activity EOG JV Drilling Activity Expansion Projects

Analyst Day – November 9, 2010

59

Analyst Day – November 9, 2010

APPALACHIAN LATERAL

Appalachian Lateral/W2E W2E Overbeck to Leidy Northern Access Expansion

59

slide-60
SLIDE 60

Pipeline & Storage/Midstream

Expansion Initiatives

Project Name Capacity Est. In‐Service Status Project Name (Dth/D) CapEx Date Status

Covington Gathering System 145,000 $16 MM 11/17/09 Completed – Flowing into TGP 300 Line Lamont Compressor Station 40,000 $6 MM 6/15/10 Completed – Flowing into TGP 300 Line p p g Lamont Phase II Project 50,000 $7 MM ~ 07/2011 Executed precedent agreements Line “N” Expansion 160,000 $23 MM ~ 09/2011 Filed FERC 7(c) application on 6/11/10. Negotiating final precedent agreement for 10 000 Dth/day 10,000 Dth/day Tioga County Extension 350,000 $46 MM ~ 09/2011 Filed FERC 7(c) filing on August 23, 2010 Trout Run Gathering System 250,000 $27 MM Fall 2011 Preliminary work has begun Northern Access Expansion 320,000 $60 MM Late 2012 Executed precedent agreement Line “N” Phase II Expansion ~195,000 $40 MM ~ 11/2012 Executed precedent agreement for 150,000 Dth/day W2E Overbeck to Leidy 425,000 $260 MM 2013 Pursuing post‐Open season requests for remaining 300 000 Dth/day

60

Analyst Day – November 9, 2010

remaining 300,000 Dth/day

slide-61
SLIDE 61

Midstream Corporation

Covington Gathering System – Tioga County

Tennessee Gas Pipeline

TGP 300

C i 146 000 D h/d Capacity: 146,000 Dth/d Interconnects with Tennessee Gas Pipeline in Tioga County Gas Pipeline in Tioga County Seneca Resources is the sole shipper

Tract 595

pp Seneca is currently shipping gross production of

Interstate Pipeline

approximately 60 MMcf per day

61

Analyst Day – November 9, 2010

p Gathering System

slide-62
SLIDE 62

Midstream Corporation

Trout Run Gathering System – Lycoming County

Capacity: 250,000 Dth/d Will Interconnect with Transco Will Interconnect with Transco Pipeline in Lycoming County Seneca Resources will be the primary shipper Estimated In‐Service: Fall 2011

Interstate Pipeline

Transco

62

Analyst Day – November 9, 2010

Gathering System

slide-63
SLIDE 63

Pipeline & Storage

Challenges & Opportunities

Challenges Opportunities

NFGSC Contract Turnbacks

Supply has received capacity turnbacks on expiring contracts

Expansion Projects

Both Supply and Empire have significant pipeline expansion turnbacks on expiring contracts, decreasing future revenue by:

FY11: ~$4.5 Million FY12: ~$6.0 Million

significant pipeline expansion projects planned to transport gas

  • ut of the Marcellus. Yearly

revenue from these expansion

Empire Unsold Capacity

~100 000 Dth/d of capacity projects is forecasted to total:

FY11: ~$0.2 Million FY12: ~$32.0 Million

100,000 Dth/d of capacity remains unsold after the construction of the Empire Connector in 2008

63

Analyst Day – November 9, 2010

slide-64
SLIDE 64

Energy Marketing

National Fuel Resources

64 64

Analyst Day – November 9, 2010

slide-65
SLIDE 65

National Fuel Resources National Fuel Resources

Fiscal 2010 Highlights

  • Recently launched a residential marketing campaign on RG&E and

y g p g NYSEG

  • Further diversify customer pool in areas where commercial, industrial and

holesale c stomers alread e ist wholesale customers already exist

  • Falling natural gas futures prices have led to increased customer price

l k i lock‐ins over most customer groups

  • NFR continued to be a significant customer of both NFGSC and Empire
  • Increased competition in Pennsylvania, potentially due to PAPUC

initiatives to expand customer choice programs

65

Analyst Day – November 9, 2010

p p g

slide-66
SLIDE 66

National Fuel Resources National Fuel Resources

Fiscal 2011 Expectations

  • Strong focus on growth of new residential and small commercial

g g customer pools on RG&E and NYSEG using POR programs

  • Expand residential customer program in NFGDC’s Pennsylvania territory

with the recently adopted POR program

  • Monitor development of Marcellus production and position NFR to

p p p ensure diverse and reliable supplies at minimal cost structure

  • Continue to evaluate strategic acquisition of pipeline capacity in NFR
  • Continue to evaluate strategic acquisition of pipeline capacity in NFR

territories

66

Analyst Day – November 9, 2010

slide-67
SLIDE 67

National Fuel Gas Company

Corporate & Financial Highlights

67 67

Analyst Day – November 9, 2010

Corporate & Financial Highlights

slide-68
SLIDE 68

National Fuel Gas Company

2011 EPS Guidance & Sensitivity

NFG & Subsidiaries NFG & Subsidiaries

On November 4, 2010, the Company updated its fiscal 2011 earnings guidance utilizing flat di i i f $

Fiscal 2011

Preliminary Earnings per Share (Diluted) Guidance(1) commodity pricing of $4.00 per MMBtu for natural gas and $80.00 per Bbl for crude oil, and adjusting for basis differential y g p ( )

Range

Consolidated Earnings $2.40 ‐ $2.70(1) j g

Seneca Resources Preliminary

Earnings per Share Sensitivity to Changes from $4.00/MMBtu for natural gas and $80.00/Bbl for crude oil(1)

Production Guidance: 60 to 70 Bcfe

$1 change per MMBtu gas $5 change per Bbl oil

Increase Decrease Increase Decrease

+$0.19 ‐$0.19 +$0.05 ‐$0.05

68

Analyst Day – November 9, 2010

(1) The preliminary earnings guidance and sensitivity table are current as of November 4, 2010. 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 hedge contracts at their maturity. For its fiscal 2011 updated earnings forecast, the Company is using flat commodity pricing of $4.00 per MMBtu for natural gas and $80.00 per Bbl for crude oil, and adjusting for basis differential.

slide-69
SLIDE 69

National Fuel Gas Company

Fiscal Year 2011 Earnings Guidance – Key Drivers

Exploration & Production

P d i ↑ 30%

FY 2011 EPS

  • Production ‐ ↑ 30%
  • DD&A: $2.05 to $2.15 per Mcfe
  • LOE: $1.10 to $1.35 per Mcfe
  • G&A: $38 ‐ $41 Million

FY2010 FY 2011 EPS

$2.40 to $2 70

Pipeline & Storage / Midstream

  • Operating Expense: ↑ 3% to 5%
  • Transportation Revenue: ↓ $4.5 Million
  • Project Development Costs (O&M): $7 Million

FY2010 Operating Results

$2 65(1) +

=

$2.70

Utility

  • Project Development Costs (O&M): $7 Million
  • Midstream Earnings per Share: $0.05 to $0.10

$2.65(1)

  • Operating Expense: ↑ 3% to 5%
  • PA Normal Weather

NYMEX Pricing ⏐

69

Analyst Day – November 9, 2010

Gas: $4.00/MMBtu ⏐ Oil: $80.00/Bbl

(1) 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.

slide-70
SLIDE 70

National Fuel Gas Company

Looking Beyond Fiscal 2011…

Exploration & Production p

  • Marcellus = Substantial growth engine
  • West = Stable production and cash flows
  • Gulf = Produce out assets
  • Gulf = Produce out assets

Pipeline & Storage / Midstream

  • Major expansion projects on line starting in late 2011
  • Rate case in Supply Corporation in early fiscal 2012

Utility

  • Limited opportunities for growth
  • i

i f &

70

Analyst Day – November 9, 2010

  • Maintain focus on O&M costs
slide-71
SLIDE 71

National Fuel Gas Company

Capital Expenditures(1) from Continuing Operations

$1,000

Exploration & Production Pipeline & Storage Utility All Other

$605‐740 $750

Millions)

$38

$100‐ 150

$57 $58 $55‐60

$501 $500

ditures ($ M

$417

$192 $188 $398 $425 ‐ 500

$43 $166 $53 $54 $54 $57 $56

$252 $248 $307 $250

pital Expen

$167 $147 $192 $188

$0

2006 2007 2008 2009 2010 2011 Forecast Cap

71

Analyst Day – November 9, 2010

Forecast

Fiscal Year

(1) A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation.

slide-72
SLIDE 72

National Fuel Gas Company

$1,400 $1,400 $1,400

Sources and Uses of Cash

2010 Actual 2011 Forecast

$58

$1,050 $1,050 $1,050

Debt Maturities

Uses

$989 $989 $115 $200 $333 $58

$700 $700 $700

Dividend CapEx New Financing

Uses

  • f Cash

$ Millions

$566 $566 $75 $69 $77 $674

$350

$82 $100 $113 $110

$350 $350

Cash on Hand Other Utility

Sources

  • f Cash

$377

$0

Sources of Uses of Sources of Uses of

$257 $456

$0

Sources of Uses of Sources of Uses of

$0

Sources of Uses of Sources of Uses of

P&S E&P

f

72

Analyst Day – November 9, 2010

Sources of Cash Uses of Cash Sources of Cash Uses of Cash Sources of Cash Uses of Cash Sources of Cash Uses of Cash Sources of Cash Uses of Cash Sources of Cash Uses of Cash

(1) For its fiscal 2011 earnings forecast, the Company is using flat commodity pricing of $4.00 per MMBtu for natural gas and $80.00 per Bbl for crude oil, and adjusting for basis differential.

(1)

slide-73
SLIDE 73

National Fuel Gas Company

Seneca Oil and Gas Hedge Positions

Natural Gas Swaps Volume (Bcf) Average Hedge Price

Fiscal 2011 19 9 $6 76 / Mcf

Oil Swaps Volume (MMBbl) Average Hedge Price

Fiscal 2011 1 6 $70 26 / Bbl Fiscal 2011 19.9 $6.76 / Mcf Fiscal 2012 14.6 $7.03 / Mcf Fiscal 2013 3.8 $6.65 / Mcf Fiscal 2011 1.6 $70.26 / Bbl Fiscal 2012 1.1 $70.55 / Bbl Fiscal 2013 0.3 $75.94 / Bbl

For fiscal year 2011, S ’ h h d d

NYMEX Strip Prices

(at 11/01/10)

Natural Gas Oil

Seneca’s has hedged 45% of their forecasted production

(at 11/01/10)

Gas Oil

Fiscal 2011(1) $4.03 $83.83 Fiscal 2012 $4.85 $87.53 Fiscal 2013 $5 24 $88 32

73

Analyst Day – November 9, 2010

Fiscal 2013 $5.24 $88.32

(1) The NYMEX strip prices for fiscal year 2011 include the settlement prices for the October 2010 and November 2010 contracts.

slide-74
SLIDE 74

National Fuel Gas Company

Short‐Term Debt

2%

Capital Structure

Sh h ld ’ Long‐Term Debt

Shareholders’ Long‐Term Debt

Shareholders’ Equity

63%

Debt

35% Shareholders Equity

58%

Debt

42%

$2.995 Billion(1)

at September 30, 2010

Forecasted Capital Structure(2)

t S t b 30 2011

74

Analyst Day – November 9, 2010

at September 30, 2011

(1) At September 30, 2010, Comprehensive Shareholders’ Equity, Long‐Term Debt and the Current Portion of Long‐Term Debt totaled $2.995 Billion as presented on the Company’s Balance Sheet, of which $1.049 Billion was Long‐Term Debt, $0.2 Billion was the Current Portion of Long‐Term Debt and $1.746 Billion was Comprehensive Shareholders’ Equity (2) At September 30, 2011, forecasted Total Capitalization is $3.002 Billion, of which $0.899 Billion is Long‐Term Debt, $0.150 Billion is the Current Portion of Long‐Term Debt, $0.058 Billion is Short‐Term Debt and $1.896 Billion is Comprehensive Shareholders’ Equity

slide-75
SLIDE 75

National Fuel Gas Company

Capital Resources & Credit Ratings

Capital Resources

CURRENT CREDIT RATINGS

$300.0 MM Commercial Paper Program and $405 MM in Uncommitted Credit Facilities – Aggregate of $705.0 MM

RATING AGENCY RATING

FITCH BBB+ ’

CURRENT CREDIT RATINGS

$300.0 MM Committed Credit Facility through September 2013 – backs Commercial Paper Program

MOODY’S Baa1 STANDARD & POOR’S BBB

75

Analyst Day – November 9, 2010

slide-76
SLIDE 76

National Fuel Gas Company

Debt Maturity Schedule

$300

$300

$200 $250 $250

$200

Millions)

$150

$100 $200

aturity ($ M

$49 $50

7 500% 6 700% 5 250% 6 500% 8 750% 7 395% 7 375% $100

Debt Ma

7.500% 6.700% 5.250% 6.500% 8.750% 7.395% 7.375% $0 2011 2012 2013 2018 2019 2023 2025

Fiscal Year

76

Analyst Day – November 9, 2010

Total Long‐Term Debt Outstanding At September 30, 2010: $1.249 B

slide-77
SLIDE 77

National Fuel Gas Company

Dividend Growth

$1.38

National Fuel has had 108 uninterrupted f di id d d h i d years of dividend payments and has increased its dividend for 40 consecutive years Compound Annual Growth Rate

5.1%

$0.19

%

77

Analyst Day – November 9, 2010

Annual Rate at Fiscal Year End

slide-78
SLIDE 78

National Fuel Gas Company

Key Takeaways

High‐Quality Marcellus Acreage Position g Q y g

745,000 net acres with a resource potential of 8‐15 Tcfe Recent well results validate the quality of our acreage Fee ownership results in superior economics

Balanced Business Model

Regulated segments support dividend and are not sensitive to commodity prices Sizable oil production provides earnings stability

S Fi i l P i i Strong Financial Position

Simple balance sheet Well capitalized Si ifi t i t ll t d h fl

78

Analyst Day – November 9, 2010

Significant internally generated cash flows

slide-79
SLIDE 79

79 79

Analyst Day – November 9, 2010

slide-80
SLIDE 80

Marcellus Shale

Recent Activity

SRC Lease Acreage SRC Fee Acreage SRC Contributed JV Acreage

80

Analyst Day – November 9, 2010

EOG Contributed JV Acreage

slide-81
SLIDE 81

National Fuel Gas Company

bl l 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

  • f the Company’s ongoing operations.

The Company’s management uses these non GAAP financial measures for the same purpose and for planning 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

81

Analyst Day – November 9, 2010

with GAAP.

slide-82
SLIDE 82

Analyst Day – November 9, 2010

82

slide-83
SLIDE 83

Reconciliation of GAAP Net Income to Income From Continuing Operations Excluding Items Impacting Comparability ($ Thousands) ($ Thousands) FY 2007 FY 2008 FY 2009 FY 2010 GAAP Net Income E&P Segment GAAP Net Income 210,669 $ 146,612 $ (10,238) $ 112,531 $ P&S Segment GAAP Net Income 56,386 54,148 47,358 36,703 Utility Segment GAAP Net Income 50,886 61,472 58,664 62,473 Marketing Segment GAAP Net Income 7,663 5,889 7,166 8,816 Marketing Segment GAAP Net Income 7,663 5,889 7,166 8,816 Corporate & All Other GAAP Net Income 11,851 607 (2,242) 5,390 Total GAAP Net Income 337,455 $ 268,728 $ 100,708 $ 225,913 $ Discontinued Operations (Income) Loss from Operations, Net of Tax (Corporate & All Other) (427) $ (1,821) $ 2,776 $ (470) $ Gain on Disposal, Net of Tax (Corporate & All Other)

  • (6,310)

(Income) Loss from Operations, Net of Tax (Exploration & Production) (15,479)

  • Gain on Disposal, Net of Tax (Exploration & Production)

(120,301)

  • (Income) Loss from Discontinued Operations, Net of Tax

(136,207) $ (1,821) $ 2,776 $ (6,780) $ Items Impacting Comparability Reversal of reserve for preliminary project costs (P&S) (4,787) $

  • $
  • $
  • $

R l i f h d i (M k i ) (2 344) Resolution of purchased gas contingency (Marketing) (2,344)

  • Discontinuance of hedge accounting (P&S)

(1,888)

  • 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

(9 019) $ (586) $ 106 980 $ $ Total Items Impacting Comparability (9,019) $ (586) $ 106,980 $

  • $

Income from Continuing Operations excluding Items Impacting Comparability E&P Segment Operating Income 74,889 $ 146,612 $ 97,969 $ 112,531 $ P&S Segment Operating Income 49,711 54,148 47,358 36,703 Utility Segment Operating Income 50,886 61,472 58,664 62,473 Marketing Segment Operating Income 5,319 5,889 7,166 8,816

Analyst Day – November 9, 2010

83

Marketing Segment Operating Income 5,319 5,889 7,166 8,816 Corporate & All Other Operating Income 11,424 (1,800) (693) (1,390) Total Income from Continuing Operations excluding Items Impacting Comparability 192,229 $ 266,321 $ 210,464 $ 219,133 $

slide-84
SLIDE 84

Reconciliation of Segment Capital Expenditures to Consolidated Capital Expenditures ($ Thousands) FY 2011 FY 2006 FY 2007 FY 2008 FY 2009 FY 2010 Forecast Capital Expenditures from Continuing Operations Capital Expenditures from Continuing Operations Exploration & Production Capital Expenditures 166,535 $ 146,687 $ 192,187 $ 188,290 $ 398,174 $ $425,000-500,000 Pipeline & Storage Capital Expenditures 26,023 43,226 165,520 52,504 37,894 $100,000-150,000 Utility Capital Expenditures 54,414 54,185 57,457 56,178 57,973 $55,000-60,000 Marketing, Corporate & All Other Capital Expenditures 5,334 3,414 1,614 9,829 7,311 $25,000-30,000 Total Capital Expenditures from Continuing Operations 252,306 $ 247,512 $ 416,778 $ 306,801 $ 501,352 $ $605,000-740,000 Capital Expenditures from Discountinued Operations Exploration & Production Capital Expenditures 41,768 $ 29,129 $

  • $
  • $
  • $
  • $

All Other Capital Expenditures 85 87 131 216 150 Total Capital Expenditures from Discontinued Operations 41,853 $ 29,216 $ 131 $ 216 $ 150 $

  • $

Plus (Minus) Accrued Capital Expenditures ( ) p p 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 294,159 $ 276,728 $ 397,734 $ 313,633 $ 455,764 $ $605,000-740,000

Analyst Day – November 9, 2010

84

slide-85
SLIDE 85

Reconciliation of Appalachian Growth Capital Expenditures to Consolidated Capital Expenditures ($ Millions) FY 2011 FY 2006 FY 2007 FY 2008 FY 2009 FY 2010 Forecast Appalachian Growth Capital Expenditures from Continuing Operations1 Exploration & Production Capital Expenditures - East Division 27.0 $ 39.1 $ 65.8 $ 138.6 $ 355.7 $ $385-440 Pi li & St A l hi E i C it l E dit 10 3 $65 75 Pipeline & Storage Appalachian Expansion Capital Expenditures

  • 10.3

$65-75 Midstream Capital Expenditures

  • 7.4

6.5 $25-30 Total Appalachian Capital Expenditures from Continuing Operations 27.0 $ 39.1 $ 65.8 $ 146.0 $ 372.5 $ $475-545 Other Capital Expenditures from Continuing Operations Exploration & Production Capital Expenditures 139.5 $ 107.6 $ 126.4 $ 49.7 $ 42.5 $ $40-60 Pipeline & Storage Capital Expenditures 26 0 43 2 165 5 52 5 27 6 $35-75 Pipeline & Storage Capital Expenditures 26.0 43.2 165.5 52.5 27.6 $35 75 Utility Capital Expenditures 54.4 54.2 57.5 56.2 58.0 $55-60 Marketing, Corporate & All Other Capital Expenditures 5.3 3.4 1.6 2.3 0.8

  • $

Total Other Capital Expenditures from Continuing Operations 225.2 $ 208.4 $ 351.0 $ 160.7 $ 128.9 $ $130-195 Capital Expenditures from Discountinued Operations Exploration & Production Capital Expenditures 41.8 $ 29.1 $

  • $
  • $
  • $
  • $

All Other Capital Expenditures 0.1 0.1 0.1 0.2 0.1 Total Capital Expenditures from Discontinued Operations 41.9 $ 29.2 $ 0.1 $ 0.2 $ 0.1 $

  • $

Plus (Minus) Accrued Capital Expenditures Exploration & Production FY 2010 Accrued Capital Expenditures

  • $
  • $
  • $
  • $

(55.5) $ Exploration & Production FY 2009 Accrued Capital Expenditures

  • (9.1)

9.1 Pipeline & Storage Accrued Capital Expenditures (16 8) 16 8 Pipeline & Storage Accrued Capital Expenditures

  • (16.8)

16.8

  • All Other Accrued Capital Expenditures
  • (0.7)

0.7

  • Total Accrued Capital Expenditures
  • $
  • $

(16.8) $ 7.0 $ (45.7) $

  • $

Eliminations

  • (2.4)

(0.3)

  • Total Capital Expenditures per Statement of Cash Flows

294.1 $ 276.7 $ 397.7 $ 313.6 $ 455.8 $ $605-740

Analyst Day – November 9, 2010

85

(1) Defined as spending related to efforts to drill for, gather, or transport Appalachian sources of natural gas.