 National Fuel Gas Company Investor Presentation August 2012 Exhibit 99 |
 August 2012 National Fuel Gas Company 2 Safe Harbor For Forward Looking Statements www.nationalfuelgas.com.You can also obtain this form on the SEC’s website at www.sec.gov. 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 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, 2011 and Forms 10-Q for the periods ended December 31, 2011, March 31, 2012, and June 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. |
 August 2012 National Fuel Gas Company 3 Our Business Mix Leads to Long-Term Value Creation Upstream Crude Oil Midstream Downstream 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 created by the integrated mix of assets continues to generate significant long-term value for the Company in nearly all economic and commodity price scenarios Upstream Natural Gas Seneca Resources Corporation (West Division) Seneca Resources Corporation (East Division) |
 August 2012 $162 25% $164 28% $167 26% $169 25% $156 23% $129 20% $131 23% $121 19% $111 17% $128 19% $362 55% $280 48% $327 52% $377 57% $379 56% $654 $581 $632 $668 $672 $0 $250 $500 $750 $1,000 2008 2009 2010 2011 12 Months Ended 6/30/12 Fiscal Year Pipeline & Storage Segment Exploration & Production Segment Midstream, Energy Marketing & Other National Fuel Gas Company 4 Integrated Business Mix Provides Financial Balance Note: A reconciliation of EBITDA to Net Income as presented on the Consolidated Statement of Income and Earnings is included at the end of this presentation. Utility Segment |
 August 2012 National Fuel Gas Company 5 Highly Integrated Assets with Significant Marcellus Exposure… |
 August 2012 National Fuel Gas Company 6 …And Exposure to Growth from the Utica Shale |
 August 2012 National Fuel Gas Company Business Mix Allows for Strategic Capital Allocation Predictable Earnings and Cash Flow Capital Allocation Priorities 7 Ongoing maintenance capital spending in regulated businesses Returning earnings to shareholders through consistent dividends Flexible, return-driven growth capital spending |
 August 2012 National Fuel Gas Company 8 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. To the extent additional infrastructure expansions are available, additional capital remains flexible and will be deployed based upon return-driven decision making |
 August 2012 Short-Term Debt 2.0% National Fuel Gas Company 9 Strong Balance Sheet and Liquidity Position $3.458 Billion (1) As of June 30, 2012 (1) Includes Notes Payable to Banks and Commercial Paper of $70.2 million and Current Portion of Long-Term Debt of $250.0 million as of June 30, 2012. 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 $20.2 million of outstanding short-term notes payable to banks as of June 30, 2012 $300.0 Million Commercial Paper Program backed by Committed Credit Facility $50.0 million of outstanding commercial paper as of June 30, 2012 |
 August 2012 National Fuel Gas Company 10 Dividend Track Record Current Dividend Yield (1) 3.0% (1) As of July 31, 2012 Dividend Consistency Consecutive Dividend Payments 110 Years Consecutive Dividend Increases 42 Years Current Annualized Dividend Rate $1.46 per Share |
 August 2012 Pipeline & Storage / Midstream 11 |
 August 2012 Pipeline & Storage / Midstream 12 Ongoing Expansion to Transport Appalachian Production Longer-Term Infrastructure Expansions Shipping Gas to Canada & Northeast Serving Southwest PA Producers Gathering Marcellus Production |
 August 2012 Pipeline & Storage / Midstream 13 A Closer Look at the Expansion Progress MERCER EXPANSION PROJECT (2014 In-Service) LINE “N” 2012 EXPANSION (Under Construction) LINE “N” EXPANSION (In-Service) TROUT RUN GATHERING SYSTEM (In-Service) COVINGTON GATHERING SYSTEM (In-Service) CENTRAL TIOGA COUNTY EXTENSION (2014/2015) TIOGA COUNTY EXTENSION (In-Service) NORTHERN ACCESS EXPANSION (Under Construction) WEST TO EAST OVERBECK TO LEIDY |
 August 2012 Midstream 14 Using a History of Excellence to Serve Appalachian Producers Midstream’s gathering systems are critical to unlock remote, but highly productive Marcellus acreage History of operational success and efficiency within Pennsylvania Original priority had been to assist Seneca’s growing development program and utilize those systems to gather 3 rd party producer volumes As a result of Seneca’s delayed development plans, the current focus is shifting to expanding infrastructure for others in the basin Transco Lycoming County Tioga County TGP 300 |
 August 2012 Pipeline & Storage 15 Regulatory Rate Filings National Fuel Gas Supply Corporation Filed a general rate case with FERC on October 31, 2011 as part of an agreement from a 2006 rate settlement On April 14, 2012 an agreement in principle was reached to settle the rate case, with new rates effective May 1, 2012 Rates are effective subject to refund beginning May 1, 2012 Empire Pipeline, Inc. Filing did not propose any changes to the current rate structure Filed a cost and revenue study on March 14, 2012 as part of a 2006 FERC order related to Empire’s transition to a FERC-regulated interstate pipeline |
 August 2012 Utility 16 |
 August 2012 Rate Mechanisms Low Income Rates Choice Program/POR Merchant Function Charge Revenue Decoupling 90/10 Sharing Weather Normalization Utility 17 Providing Financial Stability 9.8% 10.6% 10.5% 10.9% 13.2% 14.7% 18.8% 12.4% 0.0% 10.0% 20.0% 30.0% 2009 2010 2011 TME 6/30/2012 Fiscal Year Return on Equity NY PA Allowed ROE - NY Approx. Settled ROE - PA New York & Pennsylvania New York only |
 August 2012 Utility 18 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 12 Months Ended June 30, 2012 Fiscal Year All Other O&M Expenses O&M Expense - Uncollectibles |
 August 2012 Utility 19 Strong Commitment to Safety The Utility remains focused on consistent spending to maintain the ongoing safety and reliability of its system The anticipated increase in 2013 capital expenditures is largely due to the implementation of a new Customer Information System $42.8 $45.1 $44.4 $45.0 $44.3 $54.2 $57.5 $56.2 $58.0 $58.4 $55-$60 $60 $70 $0 $20 $40 $60 $80 2007 2008 2009 2010 2011 2012 Forecast 2013 Forecast Fiscal Year Capital Expenditures for Safety Total Capital Expenditures - |
 August 2012 Exploration & Production 20 |
 August 2012 Seneca Resources 21 Ongoing Strategic Responses to Low Gas Prices Maintain Focus on California Crude Oil Ongoing Delineation in Appalachia Delaying Marcellus Completions Reduction In Rig Count Production Curtailment • Generated $175 million of EBITDA in the first nine months of fiscal 2012 • Increased capital spending in California • Continue to delineate Seneca’s Utica Shale acreage potential • Evaluate Marcellus rich-gas potential in the Western Development Area • Delaying completions in Tioga County (DCNR Tract 595) due to low natural gas prices on TGP 300 • Seneca began fiscal 2012 with 6 rigs and will operate a 3 rig program in fiscal 2013 • EOG advised Seneca that it likely will not be drilling any wells in fiscal 2013 • Managing production volumes and future completions in Tioga County, targeting consistent gross volumes of 130 MMcf per day into TGP 300, which is equivalent to existing firm sales commitments |
 August 2012 California 22 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 |
 August 2012 California 23 Stable Production Fields South Lost Hills ~1,700 BOEPD Monterey Shale Primary 215 Active Wells Sespe ~1,200 BOEPD Sespe Formation Primary 188 Active Wells North Lost Hills ~1,200 BOEPD Tulare & Etchegoin Formation Primary & Steamflood 181 Active Wells North Midway Sunset ~4,400 BOEPD Potter & Tulare Formation Steamflood 728 Active Wells South Midway Sunset ~1,000 BOEPD Antelope Formation Steamflood 109 Active Wells |
 August 2012 California 24 Strong Margins Support Significant Free Cash Flow Average Revenue in First Nine Months of Fiscal 2012 $86.23 per BOE $8.64 3.18 $2.60 $2.37 $1.03 Non Steam Fuel LOE Steam Fuel G&A Production & Other Taxes Other Operating Costs EBITDA Fiscal Year 2012 (First Nine Months) EBITDA per BOE $ $67.64 Note: A reconciliation of Exploration & Production West Division EBITDA to Exploration & Production Segment Net Income is included at the end of this presentation. |
 August 2012 Seneca Resources 25 California – Recent Initiatives Driving Near-Term Growth Production Increase Drivers 1. North Midway Sunset Steaming 2. South Midway Sunset Field Extensions 3. Sespe Infill Drill Program 8,500 9,000 9,500 10,000 Actual Forecast 8,000 |
 August 2012 26 Midway Sunset South Activity Update 2011 Drill Program 2012 Drilling Locations Updip Sand Pinch-out Approx. Oil/Water Contact 100 ft 100 ft 50 ft Antelope “A-1” and “A-2” Sands Antelope “B” and “C” Sands Antelope “A-1” Sand Seneca Western Minerals 251T Extended 251 Pool to the West Seneca Western Minerals 242I Extended 252 Pool to the West 100 ft 400’ 50 ft 50 ft 50 ft Seneca Resources 2011 Drill Program: 12 Wells / 4 Injectors 2012 Drill Program: 23 Wells / 3 Injectors |
 August 2012 27 350’ Thick (Medium Blue) 800’ Thick (Dark Red) ~550’ Thick (Green) White Star – 5 Acre Tests Powell – 10 Acre Tests Powell 4 61 BOEPD 1 Oil 11/11 WS 534-33 42 BOEPD 1 Oil 1/12 White Star – 10 Acre Test WS 48-33 1 Production August 2012 WS 533-33 88 BOEPD 1 Oil 1/12 “X” SANDS ISOCHORE (Thickness) Seneca Resources Sespe Field – 2011 Drilling Highlights and Results Powell 3 136 BOEPD 1 Oil 10/11 2011 Sespe Highlights 5 Wells Drilled (Two 5-acre infill tests) Estimated EURs: 150-200 MBoe/Well 1 Mile st st st st st |
 August 2012 28 Oak Flat (10) Frankel A (5) Thornbury (10/5) Coldwater Tests “X” SANDS ISOCHORE (Thickness) Seneca Resources Sespe Field – 2012 Drill Plan Builds Upon 2011 Successes 350’ Thick (Medium Blue) 800’ Thick (Dark Red) ~550’ Thick (Green) 2012 Sespe Plans 6 Wells Planned (2 5-acre infill wells) Estimated EURs: 140-170 MBoe/Well 1 Mile Proposed Bottom Hole Locations |
 August 2012 Seneca Resources 29 Monterey Shale Play Monterey Shale Play Belridge Field 5 AMIs across the field Seneca WI: 12.5% Seneca NRI: 11.1% Producing (Gross): 50 BOPD 3-4 Delineation Wells Planned AMI Outlines Gross Thickness of Monterey Interval |
 August 2012 Seneca Resources 30 Expansive Pennsylvania Acreage Position SRC Lease Acreage SRC Fee Acreage Eastern Development Area Net Acreage: 55,000 acres Mostly leased (16-18% royalty) No near-term lease expiration First large expiration: 2018 Ongoing development drilling in Western Development Area Net acreage: ~700,000 acres Own most mineral rights Minimal royalty obligation Minimal lease expiration Evaluating Marcellus rich-gas NFG Storage Acreage and Utica Shale potential Tioga and Lycoming Counties |
 August 2012 Seneca Resources 31 Net Rig Count (Working Interest) Seneca anticipates minimal joint venture activity in fiscal 2013 Seneca Resources - Delineation Seneca Resources - Development EOG Resources 0 4 6 8 10 Fiscal 2012 - Q1 Fiscal 2012 - Q2 Fiscal 2012 - Q3 Current Rig Count Fiscal 2013 Forecast 2 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 |
 August 2012 Seneca Resources 32 Ramping Marcellus Shale Production Seneca anticipates ongoing curtailments of production into TGP 300 due to low pricing basis Covington DCNR 595 DCNR 100 EOG JV WDA/Other Forecast 0 75 150 225 |
 August 2012 Seneca Resources 33 Eastern Development Area (EDA) – Results & Plan Forward DCNR Tract 100 17 Wells Drilled; 5 Wells Producing FY2013: 1-2 Rigs Operating Peak IPs: 10.1 to 16.1 MMcf per Day Net Production: ~30 MMcf per Day Average EUR: 10 Bcf ~20 MMcf per day of gross production is curtailed due to very low pricing basis on uncontracted sales volumes Covington – Fully Developed 47 Wells Drilled and Producing Net Production: ~55 MMcf per Day Average EUR: 5.5 Bcf per Well DCNR Tracts 007 & 001 Expiration Date: January 2020 DCNR Tract 595 33 Wells Drilled; 19 Wells Producing FY2013: 0-1 Rigs Operating Net Production: ~60 MMcf per Day Average EUR: 7 Bcf per Well SRC Fee Acreage SRC Lease Acreage |
 August 2012 Seneca Resources 34 Evaluating Marcellus Wet Gas Potential More than 100,000 acres within the targeted window of 1,100 Btu to 1,200 Btu Will need cryogenic processing plant running in “ethane rejection mode” processing SRC Lease Acreage SRC Fee Acreage EOG Acreage Proposed Hz Well Owl’s Nest (2 Wells) Church Run (1 Well) |
 August 2012 35 Chesapeake 9.5 MMCFD 1,425 BLPD Chesapeake 3.8 MMCFD 980 BLPD Chesapeake 3.1 MMCFD 1,015 BLPD Dry Wet Hess 11 MMCFD Utica Shale – Activity Summary Seneca Resources Vertical Well Drilled Horizontal Well Permit Horizontal Well Drilled Mt. Jewett Vertical: Tested Dry Gas Horizontal: Completing Fall 2012 Henderson Vertical Well Tionesta Horizontal: Completing Fall 2012 Owl’s Nest Horizontal FY2013 Chesapeake 6.4 MMCFD Rex 9.2 MMCFD |
 August 2012 Seneca Resources 36 Increased California Spending with Ongoing Marcellus Cuts (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 $31 $31 $47 ~$50 $60-$75 $68 $71 $332 $585 $625-$640 $340-$425 $188 $398 $649 $675-$690 $400-$500 $0 $250 $500 $750 $1,000 2009 2010 2011 2012 Forecast 2013 Forecast Fiscal Year California Upper Devonian Marcellus/Utica Gulf of Mexico (1) (1) |
 August 2012 Seneca Resources 37 Production Still Growing 20.1 19.8 19.2 20-21 20-22 8.7 9.3 7.9 7 5-7 7.2 35.3 54-57 67-76 13.7 13.3 5.2 42.5 49.6 67.6 81-85 92-105 0 25 50 75 100 125 150 2009 2010 2011 2012 Forecast 2013 Forecast Fiscal Year California Upper Devonian Marcellus/Utica Gulf of Mexico |
 August 2012 National Fuel Gas Company 38 Appendix |
 August 2012 National Fuel Gas Company 39 Fiscal Year 2013 Earnings Guidance Drivers 2013 Forecast GAAP Earnings per Share $2.45 - $2.75 Exploration & Production Drivers Total Production (Bcfe) 92 - 105 DD&A Expense $2.30 - $2.40 LOE Expense $0.90 - $1.10 G&A Expense $59 - $63 MM Pipeline & Storage Drivers O&M Expense +3% Revenue $255 - $265 MM Utility Drivers O&M Expense +3% Normal Weather in PA |
 August 2012 National Fuel Gas Company 40 Manageable Debt Maturity Schedule $250 $300 $250 $500 $49 $50 7.395% 7.375% $0 $100 $200 $300 $400 $500 $600 Fiscal Year |
 August 2012 National Fuel Gas Company 41 Targeted Capital Structure Long-Term Consolidated Capital Structure Target Capital Structure Targets by Segment Debt 35% - 45% Equity 55% - 65% 40% 30% 50% 50% 60% 70% 50% 50% All Other E&P P&S Utility Debt Equity |
 August 2012 Pipeline & Storage / Midstream 42 Appendix |
 August 2012 Pipeline & Storage 43 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 $7.6 MM 7/2011 Fully Subscribed Completed Line “N” Expansion 160,000 $22 MM 10/2011 Fully Subscribed Completed Tioga County Extension 350,000 $56 MM 11/2011 Fully Subscribed Completed Northern Access Expansion 320,000 ~$75 MM ~11/2012 Fully Subscribed Currently under construction Line “N” 2012 Expansion 163,000 ~$43 MM ~11/2012 Fully Subscribed Currently under construction 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 ~6/2014 OS Concluded In discussions with an anchor shipper Central Tioga County Extension ~260,000 ~$135 MM 2014/2015 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: ~$669 MM |
 August 2012 Midstream Corporation 44 Expansion Initiatives Project Name Capacity (Mcf/D) Est. CapEx In-Service Date Market Comments Covington Gathering System 220,000 $54 MM Multiple Phases - Most In-Service Capacity Available [Marketing to Third Parties] Completed – Flowing into TGP 300 Line. This includes $30 million of spending to build pipeline and compression needed to connect future wells. Trout Run Gathering System 466,000 $130 MM May 2012 Capacity Available [Marketing to Third Parties] Completed – Flowing into Transco Leidy Line. This includes $55 million of spending to build pipeline and compression needed to connect future 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: ~$294 MM |
 August 2012 Exploration & Production 45 Appendix |
 August 2012 National Fuel Gas Company 46 Hedge Positions and Strategy Natural Gas Swaps Volume (Bcf) Average Hedge Price Fiscal 2012 (1) 12.4 $4.99 / Mcf Fiscal 2013 46.7 $4.82 / Mcf Fiscal 2014 27.4 $4.26 / Mcf Fiscal 2015 17.8 $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 2012 (1) 0.4 $77.03 / Bbl Fiscal 2013 1.5 $92.52 / Bbl Fiscal 2014 0.6 $95.68 / Bbl Most hedges executed at sales point to eliminate basis risk (1) Fiscal 2012 hedge positions are for the remaining three months of the fiscal year Seneca has hedged approximately 57% of its forecasted production for Fiscal 2013 |
 August 2012 Marcellus Shale 47 Western Development Area (WDA) – Results & Plan Forward Approx. Outline of JV Acreage 200,000 Gross Acres Seneca 50% W.I. (Avg. 58% NRI) Punxy (EOG Operated) 80 Wells Drilled; 55 Producing FY2012: 1 Rig Operating Gross Production: ~60 MMcf per Day Owl’s Nest Drilled 3 Horizontal Wells Acquiring 3D Seismic Potential 2013 Wet Gas Development Expected IPs: 4-5 MMcf per Day Mt. Jewett Drilled 3 Horizontal Wells IPs: 2.4 - 3.1 MMcf per Day Boone Mountain Drilled 3 Horizontal Wells IPs: 3.8 - 4.6 MMcf per Day Rich Valley To be completed in August 2012 Church Run FY2012: 1 Well To Test EUR & BTU Content SRC Fee Acreage SRC Lease Acreage SRC Contributed JV Acreage EOG Contributed JV Acreage Seneca Operated EOG Operated |
 August 2012 Marcellus Shale 48 Expanding 3D Seismic Coverage Completed In Progress Punxy West Branch Mt. Jewett DCNR 001 DCNR 007 Covington DCNR 595 DCNR 100 Owl’s Nest |
 August 2012 Marcellus Shale 49 Targeting Continued Cost Reductions $200 $300 $400 $500 $600 $700 $800 2010 2011 2012 Forecast 2013 Target Drilling Cost per Lateral Foot WDA/DCNR 595 DCNR 100 $100 $150 $200 $250 $300 $350 $400 2010 2011 2012 Forecast 2013 Target Completion Cost per Stage ($000) WDA/DCNR 595 DCNR 100 |
 August 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 Investigating underground injection Seneca is committed to protecting the surface from any type of pollution |
 August 2012 Marcellus Shale 51 “Zero Liquid Discharge Operation” Utilizing a state-of-the-art evaporative technology to ensure no liquid is discharged at the surface Building a centrally located unit in Eastern Development Area (EDA) Removes all liquids from the production stream Has the ability to be powered by the waste heat from a compressor station End products: Non-hazardous solidified salt material Clean water vapor emissions |
 August 2012 National Fuel Gas Company 52 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. |
Reconciliation of Segment Capital Expenditures to Consolidated Capital Expenditures
($ Thousands)
| FY 2009 | FY 2010 | FY 2011 | FY 2012 Forecast | FY 2013 Forecast | ||||||||||||
Capital Expenditures from Continuing Operations | ||||||||||||||||
Exploration & Production Capital Expenditures | $ | 188,290 | $ | 398,174 | $ | 648,815 | $675,000-690,000 | $400,000-500,000 | ||||||||
Pipeline & Storage Capital Expenditures - Expansion | 52,504 | 37,894 | 129,206 | $160,000-175,000 | $45,000-65,000 | |||||||||||
Utility Capital Expenditures | 56,178 | 57,973 | 58,398 | $55,000-60,000 | $60,000-70,000 | |||||||||||
Marketing, Corporate & All Other Capital Expenditures | 9,829 | 7,311 | 17,767 | $90,000-110,000 | $50,000-75,000 | |||||||||||
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Total Capital Expenditures from Continuing Operations | $ | 306,801 | $ | 501,352 | $ | 854,186 | $980,000-1,035,000 | $555,000-710,000 | ||||||||
Capital Expenditures from Discountinued Operations | ||||||||||||||||
All Other Capital Expenditures | 216 | $ | 150 | $ | — | $— | $— | |||||||||
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Plus (Minus) Accrued Capital Expenditures | ||||||||||||||||
Exploration & Production FY 2011 Accrued Capital Expenditures | $ | — | $ | — | $ | (63,460 | ) | $— | $— | |||||||
Pipeline & Storage FY 2011 Accrued Capital Expenditures | — | — | (7,271 | ) | — | — | ||||||||||
All Other FY 2011 Accrued Capital Expenditures | — | — | (1,389 | ) | — | — | ||||||||||
Exploration & Production FY 2010 Accrued Capital Expenditures | — | (55,546 | ) | 55,546 | — | — | ||||||||||
Exploration & Production FY 2009 Accrued Capital Expenditures | (9,093 | ) | 9,093 | — | — | — | ||||||||||
Pipeline & Storage FY 2008 Accrued Capital Expenditures | 16,768 | — | — | — | — | |||||||||||
All Other FY 2009 Accrued Capital Expenditures | (715 | ) | 715 | — | — | — | ||||||||||
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Total Accrued Capital Expenditures | $ | 6,960 | $ | (45,738 | ) | $ | (16,574 | ) | $— | $— | ||||||
Eliminations | $ | (344 | ) | $ | — | $ | — | $— | $— | |||||||
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Total Capital Expenditures per Statement of Cash Flows | $ | 313,633 | $ | 455,764 | $ | 837,612 | $980,000-1,035,000 | $555,000-710,000 | ||||||||
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Reconciliation of Exploration & Production West Division EBITDA to Exploration & Production Segment Net Income
($ Thousands)
| 9 Months Ended June 30, 2012 | ||||
Exploration & Production - West Division EBITDA | $ | 174,568 | ||
Exploration & Production - All Other Divisions EBITDA | 111,944 | |||
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Total Exploration & Production EBITDA | $ | 286,512 | ||
Minus: Exploration & Production Net Interest Expense | (19,794 | ) | ||
Minus: Exploration & Production Income Tax Expense | (56,034 | ) | ||
Minus: Exploration & Production Depreciation, Depletion & Amortization | (136,262 | ) | ||
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Exploration & Production Net Income | $ | 74,422 | ||
Exploration & Production Net Income | $ | 74,422 | ||
Exploration & Production - West Division Production (MBoe) | 2,581 | |||
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Exploration & Production - Net Income per West Division Production (Boe) | $ | 28.83 | ||
Exploration & Production - West Division EBITDA | $ | 174,568 | ||
Exploration & Production - West Division Production (MBoe) | 2,581 | |||
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Exploration & Production - West Division EBITDA per West Division Production (Boe) | $ | 67.64 | ||
Reconciliation of EBITDA to Net Income
($ Thousands)
| FY 2008 | FY 2009 | FY 2010 | FY 2011 | 12 Months Ended June 30, 2012 | ||||||||||||||||
Exploration & Production - West Division EBITDA | $ | 188,008 | $ | 170,611 | $ | 187,838 | $ | 187,603 | $ | 223,155 | ||||||||||
Exploration & Production - All Other Divisions EBITDA | 174,216 | 109,100 | 139,624 | 189,854 | 156,138 | |||||||||||||||
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Total Exploration & Production EBITDA | $ | 362,224 | $ | 279,711 | $ | 327,462 | $ | 377,457 | $ | 379,293 | ||||||||||
Exploration & Production EBITDA | $ | 362,224 | $ | 279,711 | $ | 327,462 | $ | 377,457 | $ | 379,293 | ||||||||||
Utility EBITDA | 161,575 | 164,443 | 167,328 | 168,540 | 155,530 | |||||||||||||||
Pipeline & Storage EBITDA | 129,171 | 130,857 | 120,858 | 111,474 | 128,372 | |||||||||||||||
Energy Marketing EBITDA | 8,699 | 11,589 | 13,573 | 13,178 | 6,107 | |||||||||||||||
Corporate & All Other EBITDA | (8,156 | ) | (5,575 | ) | 2,429 | (2,960 | ) | 2,508 | ||||||||||||
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Total EBITDA | $ | 653,513 | $ | 581,025 | $ | 631,650 | $ | 667,689 | $ | 671,810 | ||||||||||
Total EBITDA | $ | 653,513 | $ | 581,025 | $ | 631,650 | $ | 667,689 | $ | 671,810 | ||||||||||
Minus: Net Interest Expense | (62,555 | ) | (81,013 | ) | (90,217 | ) | (75,205 | ) | (78,234 | ) | ||||||||||
Plus: Other Income | 7,164 | 8,200 | 3,638 | 6,706 | 5,954 | |||||||||||||||
Minus: Income Tax Expense | (167,672 | ) | (52,859 | ) | (137,227 | ) | (164,381 | ) | (135,003 | ) | ||||||||||
Minus: Depreciation, Depletion & Amortization | (169,846 | ) | (170,620 | ) | (191,199 | ) | (226,527 | ) | (255,835 | ) | ||||||||||
Minus: Exploration & Production Impairment | (182,811 | ) | — | |||||||||||||||||
Plus/Minus: Income/(Loss) from Discontinued Operations, Net of Tax | 1,821 | (2,776 | ) | 6,780 | — | — | ||||||||||||||
Plus: Gain on Sale of Unconsolidated Subsidiaries | — | — | — | 50,879 | — | |||||||||||||||
Plus/Minus: Income/(Loss) from Unconsolidated Subsidiaries | 6,303 | 3,366 | 2,488 | (759 | ) | (61 | ) | |||||||||||||
Minus: Impairment of Investment in Partnership | — | (1,804 | ) | — | ||||||||||||||||
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Net Income | $ | 268,728 | $ | 100,708 | $ | 225,913 | $ | 258,402 | $ | 208,631 | ||||||||||