 National Fuel Gas Company Investor Presentation November 2012 Exhibit 99 |
 National Fuel Gas Company 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 or accomplished. In addition to other factors, the following are important factors that could cause actual results to differ materially from results referred to in the forward-looking statements: factors affecting the Company’s ability to successfully identify, drill for and produce economically viable natural gas and oil reserves, including among others geology, lease availability, title disputes, weather conditions, shortages, delays or unavailability of equipment and services required in drilling operations, insufficient gathering, processing and transportation capacity, the need to obtain governmental approvals and permits, and compliance with environmental laws and regulations; changes in laws, regulations or judicial interpretations to which the Company is subject, including those involving derivatives, taxes, safety, employment, climate change, other environmental matters, real property, and exploration and production activities such as hydraulic fracturing; changes in the price of natural gas or oil; impairments under the SEC’s full cost ceiling test for natural gas and oil reserves; uncertainty of oil and gas reserve estimates; significant differences between the Company’s projected and actual production levels for natural gas or oil; changes in demographic patterns and weather conditions; changes in the availability, price or accounting treatment of derivative financial instruments; governmental/regulatory actions, initiatives and proceedings, including those involving rate cases (which address, among other things, allowed rates of return, rate design and retained natural gas), environmental/safety requirements, affiliate relationships, industry structure, and franchise renewal; delays or changes in costs or plans with respect to Company projects or related projects of other companies, including difficulties or delays in obtaining necessary governmental approvals, permits or orders or in obtaining the cooperation of interconnecting facility operators; financial and economic conditions, including the availability of credit, and occurrences affecting the Company’s ability to obtain financing on acceptable terms for working capital, capital expenditures and other investments, including any downgrades in the Company’s credit ratings and changes in interest rates and other capital market conditions; changes in economic conditions, including global, national or regional recessions, and their effect on the demand for, and customers’ ability to pay for, the Company’s products and services; the creditworthiness or performance of the Company’s key suppliers, customers and counterparties; economic disruptions or uninsured losses resulting from major accidents, fires, severe weather, natural disasters, terrorist activities, acts of war, cyber attacks or pest infestation; changes in price differential between similar quantities of natural gas at different geographic locations, and the effect of such changes on the demand for pipeline transportation capacity to or from such locations; other changes in price differentials between similar quantities of oil or natural gas having different quality, heating value, geographic location or delivery date; significant differences between the Company’s projected and actual capital expenditures and operating expenses; changes in laws, 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; the cost and effects of legal and administrative claims against the Company or activist shareholder campaigns to effect changes at the Company; increasing health care costs and the resulting effect on health insurance premiums and on the obligation to provide other post-retirement benefits; or increasing costs of insurance, changes in coverage and the ability to obtain insurance. Forward-looking statements include estimates of oil and gas quantities. Proved oil and gas reserves are those quantities of oil and gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible under existing economic conditions, operating methods and government regulations. Other estimates of oil and gas quantities, including estimates of probable reserves, possible reserves, and resource potential, are by their nature more speculative than estimates of proved reserves. Accordingly, estimates other than proved reserves are subject to substantially greater risk of being actually realized. Investors are urged to consider closely the disclosure in our Form 10-K available at www.nationalfuelgas.com. You can also obtain this form on the SEC’s website at www.sec.gov. For a discussion of the risks set forth above and other factors that could cause actual results to differ materially from results referred to in the forward-looking statements, see “Risk Factors” in the Company’s Form 10-K for the fiscal year ended September 30, 2012. The Company disclaims any obligation to update any forward-looking statements to reflect events or circumstances after the date thereof or to reflect the occurrence of unanticipated events. November 2012 |
 November 2012 National Fuel Gas Company Our Business Mix Leads to Long-Term Value Creation National Fuel Gas Supply Corporation Empire Pipeline, Inc. National Fuel Gas Midstream Corporation National Fuel Gas Distribution Corporation National Fuel Resources, Inc. The strategic, operational and financial benefits and flexibility created by this integrated mix of businesses continues to generate significant long-term value for the Company’s shareholders in nearly all economic and commodity price scenarios Seneca Resources Corporation (West Division) Seneca Resources Corporation (East Division) Upstream Crude Oil Upstream Natural Gas Midstream Downstream 3 |
 National Fuel Gas Company 4 Integrated Business Mix Provides Financial Balance November 2012 Note: A reconciliation of Adjusted EBITDA to Net Income as presented on the Consolidated Statement of Income and Earnings is included at the end of this presentation. |
 National Fuel Gas Company 5 Integrated Businesses with Significant Marcellus Exposure… November 2012 |
 November 2012 National Fuel Gas Company …And Exposure to Growth from the Utica Shale 6 |
 November 2012 National Fuel Gas Company 7 Capital Spending Flexibility to Maintain Financial Strength Note: A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation. (1) Does not include the $34.9 MM Seneca Resources Corporation’s acquisition of Ivanhoe’s U.S.-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 the Exploration & Production segment’s Capital Expenditures Additional infrastructure expansions are being aggressively pursued and as a result, additional capital spending remains flexible and will be deployed based upon return-driven decision making |
 November 2012 Total Debt (1) 44% National Fuel Gas Company 8 Strong Balance Sheet and Liquidity Position $3.530 Billion (2) As of September 30, 2012 (1) Includes Long-Term Debt of $1.149 billion, the Current Portion of Long-Term Debt of $0.250 billion, and Notes Payable to Banks and Commercial Paper of $0.171 billion, as of September 30, 2012. (2) Includes Notes Payable to Banks and Commercial Paper of $171.0 million and Current Portion of Long-Term Debt of $250.0 million as of September 30, 2012. Short-Term Debt Long - Term Debt Shareholders’ Equity 56 % Capital Resources Total Short-Term Capacity: $1,085 Million Committed Credit Facility: $750 Million Syndicated facility extends until January 6, 2017 Uncommitted Lines of Credit: $335 Million $6.0 million of outstanding short-term notes payable to banks as of September 30, 2012 $300.0 Million Commercial Paper Program backed by Committed Credit Facility $165.0 million of outstanding commercial paper as of September 30, 2012 |
 November 2012 National Fuel Gas Company 9 Dividend Track Record Current Dividend Yield (1) 2.9% Dividend Consistency Consecutive Dividend Payments 110 Years Consecutive Dividend Increases 42 Years Current Annualized Dividend Rate $1.46 per Share (1) As of November 16, 2012 |
 November 2012 Midstream Businesses 10 Pipeline & Storage/NFG Midstream |
 November 2012 Midstream Businesses 11 Pipeline Expansions to Transport Appalachian Production Gathering Marcellus Production Shipping Gas to Canada & Northeast Line N Corridor Expansions |
 November 2012 Midstream Businesses 12 A Closer Look at the Expansion Progress COVINGTON GATHERING SYSTEM (In-Service) TROUT RUN GATHERING SYSTEM (In-Service) TIOGA COUNTY EXTENSION (In-Service) NORTHERN ACCESS EXPANSION (In-Service) CENTRAL TIOGA COUNTY EXTENSION (2015) LINE “N” 2012 EXPANSION (In-Service) MERCER EXPANSION PROJECT (2014) LINE “N” 2013 EXPANSION (Nov. 2013) LINE “N” EXPANSION (In-Service) |
 November 2012 Midstream Businesses 13 Pursuing Additional Opportunities Near the Line N Corridor Activity along the Pennsylvania/Ohio border continues to remain robust and is shifting north as the Utica begins to be delineated National Fuel’s Line N system is well- positioned to expand in conjunction with growth from both the Marcellus and Utica shales Significant expansion opportunities may be present in the next few years 2013: Smaller lateral pipeline extensions between $3 and $20 million 2014/2015: Larger expansion projects, possibly including an integrated wet gas solution, with National Fuel focused on the high-pressure wet gas gathering systems and dry gas interstate pipelines |
 November 2012 NFG Midstream 14 Midstream’s gathering systems are critical to unlock remote, but highly productive Marcellus acreage History of operational success and efficiency within Pennsylvania Current focus is on developing and expanding gathering infrastructure for both Seneca and other producers in the Appalachian Basin Using a History of Excellence to Serve Appalachian Producers |
 November 2012 Utility 15 |
 November 2012 Rate Mechanisms Low Income Rates Choice Program/POR Merchant Function Charge Revenue Decoupling 90/10 Sharing Weather Normalization Utility 16 Providing Financial Stability New York & Pennsylvania New York only 9.8% 10.6% 10.5% 12.6% 13.2% 14.7% 18.8% 12.5% 0.0% 10.0% 20.0% 30.0% 2009 2010 2011 2012 Fiscal Year Return on Equity NY PA Allowed ROE - NY Approx. Settled ROE - PA |
 November 2012 Utility 17 Continued Cost Control Helps Provide Earnings Stability Low natural gas prices, combined with a focus on cost control, continue to help reduce expenses $178 $164 $167 $168 $168 $25 $27 $14 $11 $9 $203 $191 $181 $179 $177 $0 $50 $100 $150 $200 $250 2008 2009 2010 2011 2012 Fiscal Year All Other O&M Expenses O&M Expense - Uncollectibles |
 November 2012 Utility 18 Strong Commitment to Safety The anticipated increase in 2013 capital expenditures is largely due to the implementation of a new Customer Information System The Utility remains focused on consistent spending to maintain the ongoing safety and reliability of its system $45.1 $44.4 $45.0 $44.3 $43.8 $57.5 $56.2 $58.0 $58.4 $58.3 $65-$70 $0 $20 $40 $60 $80 2008 2009 2010 2011 2012 2013 Forecast Fiscal Year Capital Expenditures for Safety Total Capital Expenditures |
 November 2012 Exploration & Production 19 |
 November 2012 Seneca Resources 20 Remaining Strategically Opportunistic in Fiscal 2013 presentation. Seneca’s acreage position and operational strategy allows the flexibility to ramp up, pull back, or redirect its spending according to its opportunities • Maintain two rigs drilling in the Eastern Development Area (EDA), largely in DCNR Tract 100 in Lycoming County, Pennsylvania • Continue wet/dry gas delineation in the Western Development Area (WDA) Marcellus Shale • Evaluate initial results on the first two Utica delineation wells in the Tionesta and Mt. Jewett prospect areas • Drill two additional delineation wells, one each in the Henderson and Owl’s Nest prospect areas Utica Shale • Continue ongoing efforts to grow production in Sespe and South Midway Sunset, which were large drivers of the $227 million of EBITDA in fiscal 2012 • Evaluate and pursue opportunities in the East Coalinga field as part of a new farm-in agreement California Oil • Evaluating 9,300 net acres acquired in late fiscal 2012 • Participate in 4 to 10 gross horizontal wells to further evaluate potential Mississippian Lime Note: A reconciliation of Exploration & Production West Division Adjusted EBITDA to Exploration & Production Segment Net Income is included at the end of this |
 November 2012 Seneca Resources 21 Another Strong Year of Reserve Growth Seneca has more than doubled its proved reserves since 2009, while maintaining a relatively high percentage of proved developed reserves (67%), given its large resource base (1) Represents a three-year average U.S. finding and development cost 47.6 46.2 46.6 45.2 43.3 226 249 428 675 988 503 528 700 935 1,246 0 300 600 900 1200 1500 2008 2009 2010 2011 2012 At September 30 Natural Gas (Bcf) Crude Oil (MMbbl) Fiscal Years 3-Year F&D Cost (1) ($/Mcfe) 2006-2008 $7.63 2007-2009 $5.35 2008-2010 $2.37 2009-2011 $2.09 2010-2012 $1.87 |
 November 2012 Seneca Resources 22 Increased Oil Spending and Tempered Marcellus Spending (1) Does not include the $34.9 MM acquisition of Ivanhoe’s U.S.-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 |
 November 2012 Seneca Resources 23 Production Still Growing |
 November 2012 Seneca Resources 24 Continuing to Focus on Improving Its Cost Structure Even after the new Pennsylvania Impact Fee, 2012 unit cash costs decreased from the prior year. We expect this trend to continue in Fiscal 2013. (1) Represents the midpoint of current General & Administrative Expense guidance of $58 to $62 million, divided by the midpoint of current production guidance of 95 to 107 Bcfe (2) Represents the midpoint of current Lease Operating Expense Guidance of $0.90 to $1.10 per Mcfe |
 November 2012 California 25 Stable Production and Increasing Cash Flows Net Acreage: 11,833 Acres Net Wells: 1,322 Oil Gravity: 12 – 37° Api NRI: 87.64 Rank Company California 2011 BOEPD 1 Occidental 164,796 2 Chevron 163,153 3 Aera (Shell/Exxon) 149,974 4 Plains Exploration 36,775 5 Venoco Inc. 18,988 6 Berry Petroleum 18,872 7 Seneca Resources 9,209 8 Macpherson Oil 9,022 9 E&B Natural Resources 5,992 10 ExxonMobil 3,238 |
 November 2012 California 26 Stable Production Fields South Lost Hills ~1,600 BOEPD Monterey Shale Primary 219 Active Wells Sespe ~1,200 BOEPD Sespe Formation Primary 172 Active Wells North Lost Hills ~1,200 BOEPD Tulare & Etchegoin Formation Primary & Steamflood 175 Active Wells North Midway Sunset ~4,300 BOEPD Potter & Tulare Formation Steamflood 728 Active Wells South Midway Sunset ~1,100 BOEPD Antelope Formation Steamflood 110 Active Wells East Coalinga Temblor Formation Primary |
 November 2012 California 27 Strong Margins Support Significant Free Cash Flow Average Revenue In Fiscal 2012 $85.16 per BOE $9.09 $2.82 $2.74 $2.46 $1.08 Non- Steam Fuel LOE Steam Fuel G&A Production & Other Taxes Other Operating Costs Adjusted EBITDA Fiscal Year 2012 Adjusted EBITDA per BOE $70.86 Note: A reconciliation of Exploration & Production West Division Adjusted EBITDA to Exploration & Production Segment Net Income is included at the end of this presentation. |
 November 2012 Seneca Resources 28 California – Recent Initiatives Driving Near-Term Growth Key Areas of Focus in 2013 6,500 7,000 7,500 8,000 8,500 9,000 9,500 10,000 6,000 Actual Forecast 1. North Midway Sunset Steaming 2. South Midway Sunset Field Extensions 3. Sespe Infill Drill Program |
 November 2012 Midway Sunset South Activity Update Seneca Resources 500’ 2012 Drill Program: 21 Wells / 3 Injectors 2013 Drill Program: 17 - 23 Wells / 5 - 9 Injectors 0 ft 50 ft 100 ft 100 ft 50 ft 50 ft Antelope “A-1” and “A-2” Sands Antelope “B” and “C” Sands Antelope “A-1” Sand Seneca 232M Extended 252 Pool to the West Seneca 252I Extended 252 Pool to the East Seneca 222W Extended S Ext Pool to the East Seneca 251U Extended 251 Pool to the West 2012 Drill Program Producers Injectors 2013 Drilling Locations Producers Injectors 100 ft 50 ft 100 ft 50 ft 0 ft 50 ft 0 ft 0 ft 0 ft 0 ft 29 |
 November 2012 30 WS 48-33 80 BOEPD 1 Oil 09/12 “X” SANDS ISOCHORE (Thickness) Seneca Resources Sespe Field – 2011 & 2012 Drilling Programs and Results 2011 Sespe Wells (5) 2012 Sespe Wells (6) Oak Flat 1-31 110 BOEPD 1 Oil 08/12 FA 502-33 Completing 1 Oil 12/12 FA 501-33 Completing 1 Oil 12/12 Oak Flat 2-31 100 BOEPD 1 Oil 08/12 TG 562-29 Completing 1 Oil 12/12 TG 53-29 Completing 1st Oil 12/12 2013 Sespe Wells (6) 1 Mile st st st st st st st |
 Seneca Resources 31 Monterey Shale Play Monterey Shale Play Belridge Field 5 AMIs across the field Seneca WI: 12.5% Seneca NRI: 11.4% Producing (Gross): 65 BOEPD 5 Delineation Wells Planned AMI Outlines Gross Thickness of Monterey Interval Drilling/Drilled Planned November 2012 |
 November 2012 Seneca Resources 32 Expansive Pennsylvania Acreage Position SRC Lease Acreage SRC Fee Acreage NFG Storage Acreage Western Development Area Net acreage: ~720,000 acres Own most mineral rights Minimal royalty obligation Minimal lease expiration Evaluating Marcellus rich-gas and Utica Shale potential Net Acreage: 55,000 acres Mostly leased (16-18% royalty) No near-term lease expiration First large expiration: 2018 Ongoing development drilling in Tioga and Lycoming Counties Eastern Development Area |
 November 2012 Seneca Resources 33 Net Rig Count (Working Interest) Seneca anticipates minimal joint venture activity in fiscal 2013 1.0 1.0 1.0 1.0 5.0 3.0 2.0 2.0 2.0 1.5 1.5 1.5 0.5 7.5 5.5 4.5 2.5 3.0 0 2 4 6 8 10 Fiscal 2012 - Q1 Fiscal 2012 - Q2 Fiscal 2012 - Q3 Fiscal 2012 - Q4 Fiscal 2013 Forecast Seneca Operated - Delineation Seneca Operated - Development EOG Operated |
 November 2012 Seneca Resources 34 Eastern Development Area (EDA) – Results & Plan Forward DCNR Tract 595 Gross Production: ~70 MMcf per Day 34 Wells Drilled 19 Wells Producing DCNR Tract 100 Area IPs: 10.5 – 16.1 MMcf per Day Gross Production: ~50 MMcf per Day 20 Wells Drilled 8 Wells Producing SRC Lease Acreage SRC Fee Acreage Covington – Fully Developed 47 Wells Drilled and Producing Gross Production: ~75 MMcf per Day |
 November 2012 Seneca Resources 35 Lycoming and Tioga Counties Are Highly Productive Areas Development Area Producing Well Count Average IP Rate (MMcf/d) Average 7-Day (MMcf/d) Average 30-Day (MMcf/d) Average EUR per Well (Bcf) Average Lateral Length EUR per 1,000’ of Lateral (Bcfe) Covington (Tioga County) 47 5.2 4.7 4.1 5.3 4,049’ 1.30 Tract 595 (Tioga County) 19 6.9 6.0 5.1 7.3 4,455’ 1.65 Tract 100 (Lycoming County) 7 12.7 11.6 10.4 11.6 5,788’ 2.00 |
 November 2012 Seneca Resources 36 Ramping Marcellus Shale Production Forecast 0 50 100 150 200 250 WDA/Other EOG JV Lycoming DCNR 595 Covington |
 November 2012 Seneca Resources 37 Delineating the Western Development Area Owl’s Nest (2 Wells) Church Run (1 Well) Currently Drilling Ridgway (1 Well) Rich Valley (1 Well) Peak IP: 6.3 MMcf per Day Estimated EUR: 6.4 Bcf BTU Contours Proposed Hz Well SRC Fee Acreage SRC Lease Acreage |
 November 2012 Seneca Resources Utica Shale – Activity Summary Permitted Well Drilled Well Completed Well Mt. Jewett Vertical: Tested Dry Gas Horizontal: Completing Fall 2012 Henderson Vertical Well: Tested Horizontal: FY2013 Tionesta Horizontal: Completed Fall 2012 Peak 24-Hour Rate: 3.9 MMcfd Owl’s Nest Horizontal: FY2013 Rex 9.2 MMcfd Chesapeake 6.4 MMcfd Range Resources 4.4 MMcfd Wet Dry 38 |
 November 2012 Seneca Resources 39 Initial Entry into the Mississippian Lime Play in Kansas The initial entry into the Mississippian Lime play furthers the Company’s goal of maintaining a significant contribution from oil-producing properties 100% working interest in 4,600 gross acres 25% net working interest in 18,500 gross acres 2013: Participate in 4 to 10 gross horizontal wells Total Net Acres: 9,300 |
 November 2012 National Fuel Gas Company 40 Appendix |
 November 2012 National Fuel Gas Company 41 Fiscal Year 2013 Earnings Guidance Drivers 2013 Forecast GAAP Earnings per Share $2.65 - $2.95 Exploration & Production Drivers Total Production (Bcfe) 95 - 107 DD&A Expense $2.10 - $2.25 LOE Expense $0.90 - $1.10 G&A Expense $58 - $62 MM Pipeline & Storage Drivers O&M Expense +3% Revenue $255 - $265 MM Utility Drivers O&M Expense +3% Normal Weather in PA |
 November 2012 National Fuel Gas Company 42 Manageable Debt Maturity Schedule The Company is planning a new long-term debt issuance in fiscal 2013, likely totaling $350 million, to refinance maturing long- term and outstanding short-term debt $250 $300 $250 $500 $49 $50 7.395% 7.375% $0 $100 $200 $300 $400 $500 $600 Fiscal Year |
 November 2012 National Fuel Gas Company 43 Targeted Capital Structure Long-Term Consolidated Capital Structure Target Capital Structure Targets by Segment 40% 30% 50% 50% 60% 70% 50% 50% All Other E&P P&S Utility Debt Equity Debt 35% - 45% Equity 55% - 65% |
 Pipeline & Storage / Midstream 44 Appendix November 2012 |
 November 2012 Pipeline & Storage 45 Expansion Initiatives Project Name Capacity (Dth/D) Est. CapEx In-Service Market Status Lamont Compressor Station 40,000 $6 MM 6/2010 Fully Subscribed Completed Lamont Phase II Project 50,000 $8 MM 7/2011 Fully Subscribed Completed Line “N” Expansion 160,000 $22 MM 10/2011 Fully Subscribed Completed Tioga County Extension 350,000 $58 MM 11/2011 Fully Subscribed Completed Northern Access Expansion 320,000 $75 MM 11/2012 Fully Subscribed 240,000 Dth/d In-Service as of 11/1/12 Line “N” 2012 Expansion 163,000 $43 MM 11/2012 Fully Subscribed Completed Line “N” 2013 Expansion 30,000 ~$4 MM 11/2013 OS Concluded Negotiating with an anchor shipper for all capacity Mercer Expansion Project ~150,000 ~$30 MM 2013/2014 OS Concluded In discussions with prospective shippers Central Tioga County Extension ~260,000 ~$135 MM 2015 OS Concluded In discussions with an anchor shipper West to East ~425,000 ~$290 MM ~2015 29% Subscribed Marketing continues with producers in various stages of exploratory drilling Total Firm Capacity: ~1,948,000 Dth/D Capital Investment: ~$671 MM |
 November 2012 Midstream Corporation 46 Expansion Initiatives Project Name Capacity (Mcf/D) Est. CapEx In-Service Date Market Comments Covington Gathering System 220,000 $40 MM Multiple Phases - Most In-Service Capacity Available [Marketing to Third Parties] Completed – Flowing into TGP 300 Line. This includes ~$10 million of current and future spending to build pipeline to connect additional wells Trout Run Gathering System 466,000 $185 MM May 2012 Capacity Available [Marketing to Third Parties] Completed – Flowing into Transco Leidy Line. This includes ~$100 million of current and future spending to build compression and pipeline to connect additional wells Owl’s Nest Gathering System 200,000 $110 MM First Phase FY2014 Fully Subscribed Preliminary work underway with development phased in over a five year period. Any processing costs would be incremental. Total Firm Capacity: ~886,000 Mcf/D Capital Investment: ~$335 MM |
 November 2012 Exploration & Production 47 Appendix |
 November 2012 National Fuel Gas Company 48 Hedge Positions and Strategy Natural Gas Swaps Volume (Bcf) Average Hedge Price Fiscal 2013 50.2 $4.76 / Mcf Fiscal 2014 30.4 $4.26 / Mcf Fiscal 2015 18.1 $4.07 / Mcf Fiscal 2016 17.9 $4.07 / Mcf Fiscal 2017 17.9 $4.07 / Mcf Oil Swaps Volume (MMBbl) Average Hedge Price Fiscal 2013 1.8 $94.75 / Bbl Fiscal 2014 0.9 $97.67 / Bbl Fiscal 2015 0.1 $90.20 / Bbl Most hedges executed at sales point to eliminate basis risk Seneca has hedged approximately 60% of its forecasted production for Fiscal 2013 |
 November 2012 Marcellus Shale 49 Targeting Continued Cost Reductions $200 $300 $400 $500 $600 $700 $800 2010 2011 2012 2013 Target Drilling Cost per Lateral Foot WDA/DCNR 595 DCNR 100 $100 $150 $200 $250 $300 $350 $400 2010 2011 2012 2013 Target Completion Cost per Stage ($000) WDA/DCNR 595 DCNR 100 |
 November 2012 Marcellus Shale 50 Water Management Program Water Sourcing: Coal mine runoff Permitted freshwater sources Recycled water Water Management: Instituted a “Zero Surface Discharge” policy Recycle Marcellus flowback and produced water Centralized water handling in development areas Tioga County – DCNR 595 and Covington Lycoming County – DCNR 100 Elk County - Owl’s Nest Installing new evaporative technology Permitting underground injection Established a Water Protection Team Seneca is committed to protecting the surface and fresh water aquifers from any pollution |
 November 2012 National Fuel Gas Company 51 Comparable GAAP Financial Measure Slides and Reconciliations This presentation contains certain non-GAAP financial measures. For pages that contain non-GAAP financial measures, pages containing the most directly comparable GAAP financial measures and reconciliations are provided in the slides that follow. The Company believes that its non-GAAP financial measures are useful to investors because they provide an alternative method for assessing the Company’s operating results in a manner that is focused on the performance of the Company’s ongoing operations, or on earnings absent the effect of certain credits and charges, including interest, taxes, and depreciation, depletion and amortization. The Company’s management uses these non- GAAP financial measures for the same purpose, and for planning and forecasting purposes. The presentation of non-GAAP financial measures is not meant to be a substitute for financial measures prepared in accordance with GAAP. |
 November 2012 52 Reconciliation of Segment Capital Expenditures to Consolidated Capital Expenditures ($ Thousands) FY 2013 FY 2009 FY 2010 FY 2011 FY 2012 Forecast Capital Expenditures from Continuing Operations Exploration & Production Capital Expenditures 188,290 $ 398,174 $ 648,815 $ 693,810 $ $425,000-525,000 Pipeline & Storage Capital Expenditures - Expansion 52,504 37,894 129,206 144,167 $70,000-90,000 Utility Capital Expenditures 56,178 57,973 58,398 58,284 $65,000-70,000 Marketing, Corporate & All Other Capital Expenditures 9,829 7,311 17,767 81,133 $50,000-75,000 Total Capital Expenditures from Continuing Operations 306,801 $ 501,352 $ 854,186 $ 977,394 $ $610,000-760,000 Capital Expenditures from Discountinued Operations All Other Capital Expenditures 216 150 $ - $ - $ - $ Plus (Minus) Accrued Capital Expenditures Exploration & Production FY 2012 Accrued Capital Expenditures - $ - $ - $ (38,861) $ - $ Exploration & Production FY 2011 Accrued Capital Expenditures - - (103,287) 103,287 - Exploration & Production FY 2010 Accrued Capital Expenditures - (78,633) 78,633 - - Exploration & Production FY 2009 Accrued Capital Expenditures (9,093) 19,517 - - - Pipeline & Storage FY 2012 Accrued Capital Expenditures - - - (2,696) - Pipeline & Storage FY 2011 Accrued Capital Expenditures - - (7,271) 7,271 - Pipeline & Storage FY 2008 Accrued Capital Expenditures 16,768 - - - - All Other FY 2012 Accrued Capital Expenditures - - - (11,000) - All Other FY 2011 Accrued Capital Expenditures - - (1,389) 1,389 - All Other FY 2009 Accrued Capital Expenditures (715) 715 - - - Total Accrued Capital Expenditures 6,960 $ (58,401) $ (33,314) $ 59,390 $ - $ Eliminations (344) $ - $ - $ - $ - $ Total Capital Expenditures per Statement of Cash Flows 313,633 $ 443,101 $ 820,872 $ 1,036,784 $ $610,000-760,000 |
 November 2012 53 Reconciliation of Exploration & Production West Division Adjusted EBITDA to Exploration & Production Segment Net Income ($ Thousands) 12 Months Ended September 30, 2012 Exploration & Production - West Division Adjusted EBITDA 226,897 $ Exploration & Production - All Other Divisions Adjusted EBITDA 170,232 Total Exploration & Production Adjusted EBITDA 397,129 $ Minus: Pennsylvania Impact Fee Related to Prior Fiscal Years (6,206) Minus: Exploration & Production Net Interest Expense (27,751) Minus: Exploration & Production Income Tax Expense (79,050) Minus: Exploration & Production Depreciation, Depletion & Amortization (187,624) Exploration & Production Net Income 96,498 $ Exploration & Production Net Income 96,498 $ Pipeline & Storage Net Income 60,527 Utility Net Income 58,590 Energy Marketing Net Income 4,169 Corporate & All Other Net Income 293 Consolidated Net Income 220,077 $ |
 November 2012 54 Reconciliation of Adjusted EBITDA to Consolidated Net Income ($ Thousands) FY 2008 FY 2009 FY 2010 FY 2011 FY 2012 Exploration & Production - West Division Adjusted EBITDA 188,008 $ 170,611 $ 187,838 $ 187,603 $ 226,897 $ Exploration & Production - All Other Divisions Adjusted EBITDA 174,216 109,100 139,624 189,854 170,232 Total Exploration & Production Adjusted EBITDA 362,224 $ 279,711 $ 327,462 $ 377,457 $ 397,129 $ Total Adjusted EBITDA Exploration & Production Adjusted EBITDA 362,224 $ 279,711 $ 327,462 $ 377,457 $ 397,129 $ Utility Adjusted EBITDA 161,575 164,443 167,328 168,540 159,986 Pipeline & Storage Adjusted EBITDA 129,171 130,857 120,858 111,474 136,914 Energy Marketing Adjusted EBITDA 8,699 11,589 13,573 13,178 5,945 Corporate & All Other Adjusted EBITDA (8,156) (5,575) 2,429 (2,960) 4,140 Total Adjusted EBITDA 653,513 $ 581,025 $ 631,650 $ 667,689 $ 704,114 $ Total Adjusted EBITDA 653,513 $ 581,025 $ 631,650 $ 667,689 $ �� 704,114 $ Minus: Net Interest Expense (62,555) (81,013) (90,217) (75,205) (82,551) Plus: Other Income 7,164 8,200 3,638 6,706 5,133 Minus: Income Tax Expense (167,672) (52,859) (137,227) (164,381) (150,554) Minus: Depreciation, Depletion & Amortization (169,846) (170,620) (191,199) (226,527) (271,530) Minus: Impairment of Oil and Gas Properties (E&P) - (182,811) - - - Plus/Minus: Income/(Loss) from Discontinued Operations, Net of Tax (Corp. & All Other) 1,821 (2,776) 6,780 - - Plus: Gain on Sale of Unconsolidated Subsidiaries (Corp. & All Other) - - - 50,879 - Plus/Minus: Income/(Loss) from Unconsolidated Subsidiaries (Corp. & All Other) 6,303 3,366 2,488 (759) - Minus: Impairment of Investment in Partnership (Corp. & All Other) - (1,804) - - - Plus: Elimination of Other Post-Retirement Regulatory Liability (P&S) - - - - 21,672 Minus: Pennsylvania Impact Fee Related to Prior Fiscal Years (E&P) - - - - (6,206) Rounding - - - - (1) Consolidated Net Income 268,728 $ 100,708 $ 225,913 $ 258,402 $ 220,077 $ |