Corporate Corporate Overview Still in the Early Stages of Our Marcellus Growth Story 2008-2009 2010-2011 2012-2013 2014-2015 2016+ Development Area Initial Delineation Delineation (New Areas/Depths) Eastern Full Development Production (200-220 Locations) Decline Optimization & Enhancement Delineation Development Area Initial Delineation Analyst Day - November 2013 (New Areas/Depths) Western Full Development (1,700-2,000 Locations) Optimization & Enhancement 9
Corporate Corporate Overview Formula to Grow Our Marcellus Development Program ? High-Quality Reservoir Increased Realized Natural Gas Capital Price Deployment Operating Efficiencies Analyst Day - November 2013 National Fuel is maintaining a proactive Infrastructure approach to securing & Marketing markets for its growing natural gas production 10
Corporate Corporate Overview Opportunities to Move Gas Out of the Northeast % of Year that Northeast will be Long Gas Supply 100% 93% 90% 86% 76% 75% 69% 62% 52% 50% 31% 25% Analyst Day - November 2013 0% 2013 2014 2015 2016 2017 2018 2019 2020 The oversupply of natural gas in the Northeast is creating opportunities for the midstream businesses to develop projects to deliver to higher-priced markets such as Eastern Canada and the Southeast 11 Source: TPH Research
Corporate Corporate Overview Marcellus Infrastructure Growth Still Has Room to Run 2010 to 2013 Expansions Capacity Added 1,819 MDth per day Capital Deployed $422 million 2014+ Expansions Capacity Planned 1,724 to 2,224 MDth per day Capital Expenditures Planned ~$1.5 billion Analyst Day - November 2013 Plans are in place to deploy significant capital to double the expansion capacity added since 2010 12
Corporate National Fuel Gas Company A History of Success & A Future of Opportunity Future Goals 10-15% Adjusted EBITDA Growth 15-25% Production Growth Analyst Day - November 2013 $1.5 Billion of Midstream Investment Over 5 Years 13
Corporate Corporate Overview Maintaining Our View on Corporate Structure Today Future (2015+) Strong Balance Sheet More Aggressive Growth Ability to modestly increase Requires Capital leverage Goal is to accelerate value 1.89x Debt/Adjusted EBITDA creation Need stronger natural gas Balanced Business Mix prices 58% E&P (1) Additional leverage is limited 42% Midstream/Utility (1) Result may lead to a shift in Operational synergies business mix Investment Grade Credit Options to Consider Diversification of businesses Midstream MLP Analyst Day - November 2013 provide credit support Upstream/Midstream JV Leverage is the cheapest cost of capita l today In today’s commodity price environment, our current structure can handle near-term growth. Look to accelerate development when the economics of doing so are favorable. 14 (1) Based on Adjusted EBITDA
Upstream Exploration & Production Overview Analyst Day - November 2013 15
Upstream Seneca Resources Seneca’s Evolution 2011 2008 2014 Gulf of Mexico Shallow Appalachia California Marcellus Shale – Eastern Development Area Marcellus Shale – Western Development Area Geneseo Shale (Delineation) Utica Shale (Delineation) Analyst Day - November 2013 ~400% Production Growth ~200 Bcfe (1) Total Production (2008 to 2015) ~155 Bcfe (1) 121 Bcfe 83 Bcfe 68 Bcfe 50 Bcfe 43 Bcfe 41 Bcfe 16 (1) Represents the midpoint of current guidance (Fiscal 2014: 145 – 165 Bcfe; Fiscal 2015: 180 – 220 Bcfe)
Upstream Seneca Resources Fiscal 2013 Highlights Total production increased 45% to 120.7 Bcfe 45% Replaced 351% of proved reserves 351% Finding & Development Cost: $1.31/Mcfe Marcellus Finding & Development Cost: $0.99/Mcfe Analyst Day - November 2013 WDA Achieved major breakthrough in the Marcellus Shale Western Development Area (WDA) Success De-risked 1,700 to 2,000 future drilling locations 17
Upstream Seneca Resources Disciplined Capital Spending Gulf of Mexico (Divested in 2011) $1,000 East Division (Appalachia) West Division (California/Kansas) Capital Expenditures ($ Millions) $800 $650-$750 $694 $649 $550-$650 $600 $533 $398 $560- $400 $460- $631 $620 $596 $520 $428 $188 (1) Analyst Day - November 2013 $356 $200 $139 $90- $90- $105 $63 $130 $130 $47 $31 $28 $0 2009 2010 2011 2012 2013 2014 2015 Forecast Forecast Fiscal Year (1) Does not include the $34.9 MM acquisition of Ivanhoe’s U.S.-based assets in California, as this was accounted for as an investment in subsidiaries on the Statement of Cash Flows, and was not 18 included in Capital Expenditures
Upstream Seneca Resources Proven Record of Growth 3-Year 2000 F&D Cost (1) Fiscal Natural Gas (Bcf) Years ($/Mcfe) Crude Oil (MMbbl) 2006-2008 $7.63 1,549 Total Proved Reserves (Bcfe) 1500 2007-2009 $5.35 1,246 2008-2010 $2.37 2009-2011 $2.09 935 1000 2010-2012 $1.87 1,300 700 2011-2013 $1.67 988 528 675 503 500 428 2013 F&D Cost = $1.31 Analyst Day - November 2013 249 226 Marcellus F&D: $0.99 Doubled Proved Reserves 46.2 46.6 45.2 43.3 42.9 41.6 0 Since 2010 2008 2009 2010 2011 2012 2013 71% Proved Developed At September 30 19 (1) Represents a three-year average U.S. finding and development cost
Upstream Seneca Resources Best-In-Class Marcellus Shale Reserve Growth 2009 to 2012 Proved Reserves CAGR (1) 45% 33% 30% 24% 21% 19% 15% 7% 0% Analyst Day - November 2013 -10% -15% NFG Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 20 (1) Peers consist of AR, COG, EQT, RRC, SWN
Upstream Seneca Resources Delivering Tremendous Production Growth 225 Gulf of Mexico (Divested in 2011) 180-220 East Division (Appalachia) West Division (California/Kansas) 145-165 Annual Production (Bcfe) 150 120.7 158-196 83.4 125-143 67.6 75 100.7 Analyst Day - November 2013 49.6 62.9 13.3 43.2 16.5 22-24 19.8 20.5 20.0 20-22 19.2 0 2010 2011 2012 2013 2014 2015 Forecast Forecast Fiscal Year 21
Upstream Seneca Resources Delivering More than Just Absolute Growth Proved Reserves per Total Production per 20 1.5 Debt-Adjusted Share (1) (Mcfe) Debt-Adjusted Share (2) (Mcfe) Total Proved Reserves per Debt-Adjusted Share (Mcfe) Total Production per Debt-Adjusted Share (Mcfe) 1.1 14.4 15 1.0 11.5 0.8 10 9.0 0.7 7.1 0.5 0.4 0.5 5.5 5 Analyst Day - November 2013 - - 2009 2010 2011 2012 2013 2009 2010 2011 2012 2013 At September 30 Fiscal Year (1) Year-end proved reserves divided by debt-adjusted year-end diluted shares outstanding 22 (2) Annual production per share divided by debt-adjusted year-end diluted shares outstanding
Upstream Marcellus Shale Significant Position & Integral Part of Seneca’s Future Enterprise Value (2) Net Marcellus Acres per Company Acreage (1) ($ Billions) $ Million of EV NFG 780,000 $7.4 105.4 RRC 835,000 $15.5 53.9 EQT 560,000 $15.5 36.1 SWN 337,000 $14.6 23.0 Analyst Day - November 2013 AR 334,000 $17.2 19.4 COG 200,000 $15.2 13.1 (1) Source: ITG Investment Research, & Company Data 23 (2) Source: Bloomberg - As of November 8, 2013
Upstream Marcellus Shale Factors for Success Acreage Position – Quantity & Quality Operating Expertise Control costs Maximize production Gathering, Transportation and Marketing Financial Stability Analyst Day - November 2013 Ability to withstand price swings and market dislocations 24
Upstream Marcellus Shale Prolific Pennsylvania Acreage Seneca Fee Seneca Lease 720,000 Acres 60,000 Acres Eastern Development Area (EDA) Mostly leased (16-18% royalty) No near-term lease expiration Analyst Day - November 2013 Western Development Area (WDA) First large expiration: 2018 Mineral ownership: 83% Ongoing development drilling in No royalty; No lease expiration Tioga and Lycoming Counties Net revenue interest: 98% Highly contiguous Significant economies of scale 25
Upstream Seneca Acreage Huge Position – Varies in Understanding Seneca Fee Seneca Lease Understanding Seneca’s 780,000 Net Acres Northeast Core ~30,000 acres in NE Core Tier I Acres ~200,000 acres Economic less than $4/Mcf Awaiting Evaluation ~250,000 acres Analyst Day - November 2013 Requires Gas Price Above $4/Mcf ~300,000 acres Tier I ~200,000 Acres 26
Upstream Seneca Acreage Fee Ownership & Contiguity are Beneficial Contiguous No Lease No Royalty Acreage Expiration Blocks Analyst Day - November 2013 Seneca’s Tier I acreage is approaching Northeast Core economics 27
Upstream Seneca Acreage Seneca’s Marcellus Acreage Provides a Unique Advantage Seneca Advantage #1 Fee Ownership Position 28% IRR Seneca Advantage Competitor Fee Ownership + Single Pad Working Interest: 100% Contiguous Acreage Revenue Interest: 84% 43% IRR 18% IRR Seneca Advantage #2 Contiguous Acreage for Multiple Pads 29% IRR Analyst Day - November 2013 Competitor Advantage #1 Advantage #2 Seneca Advantage Capital Expenditures $9,000 $9,000 $7,000 $7,000 Multiple Pads No No Yes Yes Working Interest 100% 100% 100% 100% Revenue Interest 84% 100% 84% 100% IRR 18% 28% 29% 43% Note: Assuming a 7.8 Bcf well, with a 6,000’ lateral and 40 frac stages 28 Note: Assumes $4/MMBtu realized natural gas pricing
Upstream Seneca’s Operations Best-In-Class Operator in Lycoming County (EDA) 9.0 180 Average MMcf per Day 8.2 Horizontal Well Count 8.0 160 Average Production per Well (MMcf per Day) 7.0 140 Horizontal Well Count 6.0 120 5.0 100 4.2 4.0 4.0 80 3.3 3.1 3.0 60 2.2 2.1 2.0 40 Analyst Day - November 2013 1.5 1.0 1.0 20 0.0 0 Seneca Co. 2 Co. 3 Co. 4 Co. 5 Co. 6 Co. 7 Co. 8 Co. 9 29 Source: DEP Production Data (January 2013 to June 2013)
Upstream Seneca’s Operations Top-Notch Lycoming Economics Lycoming County: EURs & Breakeven Prices 15.0 $6 EUR (Bcfe) Breakeven Price 12.3 Breakeven Price ($/Mcfe) 10.0 $4 EUR (Bcfe) 6.6 6.3 4.9 5.0 $2 3.7 Analyst Day - November 2013 0.0 $0 NFG APC SWN RRC XCO 30 Source: ITG IR, raw data provided by didesktop and state agencies
Upstream Seneca’s Operations Seneca’s Lycoming Economics are in the Top 3 Top Marcellus Breakevens by Operator & County $5.00 (Source: ITG Investment Research) There are an additional 109 breakeven data points greater than $3.69/Mcf Breakeven NYMEX ($/Mcf) $3.69 $4.00 $3.65 $3.62 $3.54 $3.46 $3.35 $3.33 $3.25 $3.23 $3.21 $3.11 $3.09 $3.06 $3.03 $2.96 $2.95 $2.95 $2.80 $2.79 $3.00 $2.41 Analyst Day - November 2013 $2.00 31 Source: ITG IR, raw data provided by didesktop and state agencies
Upstream Seneca’s Operations Driving Down Well Costs In 2014, total well costs are expected to be ~35-40% lower than 2012 DCNR Tract 100 Total Well Costs RCS Well Normalized for 5,500’ Lateral & 37 RCS Stages $12.0 $10.0 Total Well Costs ($ Millions) $9.0 $8.1 $6.7 $5.8 $6.0 Analyst Day - November 2013 $3.0 $0.0 2012 2013 2014 (Est.) Best YTD Fiscal Year Tract 100 (EDA) 32
Upstream Seneca’s Gathering & Marketing Seneca’s Overall Marketing Strategy Historical Strategy Firm sales at Financial hedges to interstate pipeline lock in benchmark interconnects and basis risk Develop gathering infrastructure with NFG Midstream Current/Long-Term Strategy Analyst Day - November 2013 Firm transport (FT) to major markets Financial hedges to Firm sales tied to lock in benchmark FT contracts and basis risk 33
Upstream National Fuel’s Financial Stability Ability to Withstand Pricing Challenges Strong Balance Sheet & Liquidity Position Cash Generation from California Oil No Near-Term Debt Maturities Analyst Day - November 2013 Active Hedging Program 34
Upstream Marcellus Shale Factors for Success Acreage Position – Quantity & Quality Operating Expertise Control costs Maximize production Gathering, Transportation and Marketing Financial Stability Analyst Day - November 2013 Ability to withstand price swings and market dislocations 35
Upstream California Outstanding Cash Flow (1) Capital Expenditures $250 $226.9 Adjusted EBITDA $215.0 $187.8 $187.6 $200 $171.6 $ Millions $150 $104.6 $100 $62.9 Analyst Day - November 2013 $47.4 $50 $31.4 $27.6 $0 2009 2010 2011 2012 2013 Fiscal Year 36 (1) Adjusted EBITDA and Capital Expenditures represent Seneca Resources Corporation’s West Division, which includes its activity in Kansas
Upstream California Looking Back at the Successful Ivanhoe Acquisition Seneca South Midway Sunset Production 1,600 Acquisition Date Net Production at Acquisition 1,400 Gross Prodcution (BOPD) 550 Bbl per Day (March 2009) 1,200 1,000 Net Production at 9/30/13 800 1,157 Bbl per Day 600 400 110% Increase 200 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 SRC Development Production Historical PDP (Assumes 6% Decline) Purchase Price Ivanhoe Acquisition Cash Flow $60 $39.2 million Annual Cash Flow ($ Millions) $45 Cumulative Analyst Day - November 2013 $27.6 $25.6 Proved PV-10 at 9/30/13 (1) $30 $10.9 $11.4 $149.5 million $15 $3.4 $2.6 $0 $10.3 million cumulative ($15) net cash flow ($30) (including purchase price) ($45) 7/1/2009 2009 2010 2011 2012 2013 2014 Est. since acquisition Fiscal Year 37 (1) PV-10 from 10/1/2013 SEC reserves
Upstream California Looking Forward 1. Manage decline of base production 2. Pursue and develop opportunities for growth from current assets Sespe East Coalinga South Midway Sunset Analyst Day - November 2013 3. Continue to pursue additional acquisition and farm-in opportunities 38
Upstream Seneca Resources Key Metrics Operational Strategic Metric Fiscal 2009 Fiscal 2013 Strategy Improvements 12x Production East Division 9 Bcfe 101 Bcfe Growth Production (21% of Total Production) (83% of Total Production) East Division 7x Reserve 152 Bcfe 1,240 Bcfe Focus on growth- Proved Reserves Growth (29% of Proved Reserves) (80% of Proved Reserves) oriented Marcellus Shale assets with significant fee East Division 5x EBITDA $57 million $284 million acreage EBITDA Growth (20% of Total EBITDA) (57% of Total EBITDA) $1.09 per Mcfe 49% Decrease Operating Costs (1) $2.15 per Mcfe One of the lowest cost per Mcfe producers in the region Analyst Day - November 2013 West Division 25% EBITDA $172 million $215 million EBITDA Growth Maintain and grow strong cash flow assets in California 28% Margin Cash Margin (2) $52 per Bbl $66 per Bbl Improvement (1) Defined as LOE and G&A per Mcfe 39 (2) Defined as realized price including the effects of hedging less LOE , G&A and production taxes
Upstream Seneca Resources What Will Seneca Look Like Moving Forward? Consistent Production Growth: 15-25% CAGR Driven by a very large, high-quality Appalachian acreage position Disciplined Spending Driven by Rates of Return Pace of development adapts to changing market dynamics Maintain Oil Production → Expand When Possible Excellent operator and significant cash flow generation Analyst Day - November 2013 A Leader in Technology, Safety & Environmental Responsibility Maintain a leadership role in using technology and developing best practices 40
Upstream Appraisal & Development Overview Analyst Day - November 2013 41
Upstream Marcellus Shale WDA Is the Key to Seneca’s Long-Term Growth Outlook Seneca Fee Seneca Lease 720,000 Acres 60,000 Acres Full Development Since 2010 ~225 locations remaining Analyst Day - November 2013 Full Development Started in 2013 70-90 wells in Lycoming County 1,700 to 2,000 locations de-risked Near-term driver of growth Long-term driver of growth 42
Upstream Marcellus Shale Significantly Improved Understanding of the WDA SRC Fee Acreage SRC Lease Acreage 3D Seismic Outlines Mt. Jewett EOG Earned Acreage W. Branch Rich Valley James City Clermont St. Mary’s Owl’s Nest Ridgway Beechwood Tionesta Church Run Red Hill/ Leasgang Analyst Day - November 2013 Kyler’s Corner Boone Mtn Key Statistics Sulger Farm Punxy Vertical Wells: 30 Full Core: 8 Sidewall Core: 2 3D Seismic: 432 sq m 43
Upstream Marcellus Shale Northwest PA Generalized Cross-Section Transitional Platform Basin Outer Shelf Owl’s Nest Ridgway Rich Valley Beechwood Punxy James City Clermont Leasgang CaCO 3 Sed. Rate Analyst Day - November 2013 TOC Medium rock quality, high pressures High organics, great rock quality, less variability High variability, very poor rock quality in areas 44
Upstream Marcellus Shale WDA Log Summary Cross-Section Platform Transitional Outer Shelf Basin TOC/PHI/BWV TOC/PHI/BWV TOC/PHI/BWV TOC/PHI/BWV Gas Resource Gas Resource Gas Resource Gas Resource 0 Wt% 50 0 Wt% 50 0 Wt% 50 0 Wt% 50 Mineralogy Mineralogy Mineralogy 0 Mcf/ac-ft 1500 Mineralogy 0 Mcf/ac-ft 1500 0 Mcf/ac-ft 1500 0 Mcf/ac-ft 1500 0.2 v/v 0 0.2 v/v 0 0.2 v/v 0 0.2 v/v 0 0 Bcf/mi 100 0 Bcf/mi 100 0 Bcf/mi 100 0 Bcf/mi 100 0.2 v/v 0 Volume % Volume % 0.2 v/v 0 Volume % 0.2 v/v 0 Volume % 0.2 v/v 0 Very poor rock quality. Low gas in place. Analyst Day - November 2013 ɸ = 2.8 – 4.3% ɸ = 6.8 - 8.1% ɸ = 5.6 - 6.7% ɸ = 5.5 - 6.6% Total GIP = < 40/sect Total GIP = ~70/sect Total GIP = ~75/sect Total GIP = ~60/sect 45
Upstream Marcellus Shale 2013 & 2014 WDA Delineation Program Clermont – Full Development SRC Fee Acreage 2 Wells Completed Rich Valley – Full Development 9H: 7-Day IP of 10 MMcf/d & EUR of 8.6 Bcf SRC Lease Acreage 2 Wells Completed 10H: 7-Day IP of 7.4 MMcf/d & EUR of 6.6 Bcf 7-Day IP of 7.8 MMcf/d & EUR of 7.4 Bcf EOG Earned JV Acreage 2 nd Well 7-Day IP: 4.5 MMcf/d Owl’s Nest – Delineating 2 High Btu Wells Completed Church Run – Delineating 1 Well Completed Hemlock – Delineating 1 Well Planned Tionesta – Delineating Analyst Day - November 2013 Ridgway – Delineating 1 Well Completed 1 Well Completed Heath – Delineating 1 Well Planned 2013 Drill Program Sulger Farms – Delineating 1 Well Planned Seneca Operated 2014 Drill Program 46
Upstream Marcellus Shale Rich Valley/Clermont is in Full Development Mode Marcellus Faults Marcellus & Basement Faults Pad N: Spacing Test Clermont RCS: 9H 7-day IP: 10.0 MMcf/d (EUR: 8.6 Bcf) Rich Valley Non-RCS: 10H 7-day IP: 7.4 MMcf/d 7-day IP: 7.8 MMcf/d EUR: 7.4 BCF Lateral Length: 6,372’ Pad O Rich Valley Pad D Pad E Rich Valley 2 nd Well 7-day IP: 4.5 MMcf/d Analyst Day - November 2013 Lateral Length: 4,492’ Pad H Clermont JV Wells SRC Fee Acreage SRC Lease Acreage 200-250 Horizontal Locations 47
Upstream Marcellus Shale Clermont Wells Improved from Early Non-Op JV Wells SRC Clermont vs. Non-Op JV Clermont 10,000 9H 10H COP 2316 5H COP 2316 6H 9,000 Clermont 5H & 6H (Non-op wells) Avg. lateral length: 3,344’ 9H: RCS Completion (150’ stage spacing) 8,000 Small casing: 4.5” Restricted pump rates 7,000 Wide stage spacing: 350’ No soaking, low Sw’s 6,000 Mcf per Day 10H: Standard Completion (240’ stage spacing) 5,000 Clermont 9H & 10H (Seneca wells) 4,000 Avg. lateral length: >5,500’ Large casing: 5.5” 3,000 Increased pump rates 9H (RCS): 150’ spacing Non-Op JV Wells (5H, 6H) Analyst Day - November 2013 2,000 10H (Standard): 240’ spacing Soaked both wells: 30 Days 1,000 0 0 5 10 15 20 25 30 Days On 48
Upstream Marcellus Shale Moving All Completions to Reduced Cluster Spacing (RCS) RCS Design Conventional Design ~1000’ ~1000’ 300’ 300’ Formation Formation Fracture Fracture Wellbore Wellbore Twice the number of stages/perforations Analyst Day - November 2013 Increases stimulated reservoir volume Increased proppant near the wellbore improves fracture conductivity 49
Upstream Marcellus Shale Consistently Improved Results in the Owl’s Nest Area Owl’s Nest Area 8,000 2013 Appraisal Program 7,000 Lateral length >4,400’ to 6,200’ Ridgway 6,000 RCS completions 150’ spacing Owl’s Nest Flowback Gas Rate (Mcfd) 5,000 Soaked wells 30 – 60 days Church Run 4,000 Target interval Union Springs: 100% in 3,000 target 2,000 Analyst Day - November 2013 1,000 0 0 100 200 300 400 500 600 700 Elapsed Time Ridgway Church Run ON1H-Sales ON3H-Sales ON54H 50
Upstream Marcellus Shale Strong Wells Across WDA Acreage Peak Peak Treatable 24-Hour 7-Day Completion Lateral Rate Rate EUR Well Name Design Length Stages (MMcfd) (MMcfd) (Bcf) Status RCS 1 6,372’ 42 8.1 7.8 7.4 Producing Rich Valley 27H Clermont 9H RCS 5,500’ 37 11.4 10.0 8.6 Producing Clermont 10H Non-RCS 5,565’ 23 8.1 7.3 6.6 Producing Flowback Ridgway 19H RCS 5,537’ 37 7.1 6.4 5-8 Test Flowback Analyst Day - November 2013 Church Run 2H RCS 4,435’ 29 4.8 4.5 4-6 Test Flowback Owl’s Nest 54H RCS 6,139’ 41 6.1 5.8 4-7 Test Flowback Owl’s Nest 59H RCS; Gel 2 5,371’ 36 3.4 3.1 2-4 Test (1) RCS – Reduced Cluster Spacing 51 (2) Completed using linear gel to place larger proppant near the wellbore
Upstream Marcellus Shale Key Areas of Improvement in Recent Delineation Program Areas of Improvement 2012-2013 Delineation Program Identification of specific target interval is key Target Selection (Landing Depth) Percent of wellbore in target interval increased Target Execution from prior years Reduced Cluster Spacing (RCS) Completion Design Shorter stages: From 240-350’ down to 150’ Increased volume of sand per foot Drilled laterals 15-45% longer than in prior years Lateral Length Analyst Day - November 2013 52
Upstream Marcellus Shale Selection of Target Interval is Critical Percentage of Wellbore in Current Target Interval 260% 100% Wells Percent In Current Target (% of CLL) Improvement Averages 83% 75% 50% 33% 25% 23% Analyst Day - November 2013 0% 2009 2010 2011 2012 2013 2014 Well Year Previous programs spent a significant portion ( > 60% ) of the wellbore outside of the current target interval, identified to have improved productivity 53
Upstream Marcellus Shale Optimized Landing Depth EDA Lycoming Type Log Improved Target Zone Drivers Best rock quality in terms of organic content, brittleness, and porosity Highest rate of penetration (ROP) ROP vs Height Above Onondaga Analyst Day - November 2013 20 40 60 80 100 120 140 160 ROP (ft/hr) 54
Upstream Marcellus Shale Continued Improvement Staying within Targeted Interval Percent of Wellbore In Target Zone (15-20’ Interval) 100% 17% Percent In Target (% of CLL) Wells 83% Improvement Averages 75% 69% 71% 50% 25% 0% 2009 2010 2011 2012 2013 2014 Well Year Analyst Day - November 2013 Reasons for Improvement 3D seismic acquisition Improved communication between Geology, Drilling and Completion teams Geosteering technology (azimuthal GR) 55
Upstream Marcellus Shale RCS & Increased Sand Volume Generating Better Results Increases near wellbore fracturing Improved near wellbore & stimulated reservoir volume fracture conductivity Stage Spacing & Count Pounds of Sand per Foot 400 60 1,700 Avg. Stage Spacing per Foot Pounds of Sand per Foot 350 50 349 1,600 300 40 Stage Count 1,500 1,479 266 250 30 1,448 1,400 200 20 162 1,300 150 10 1,275 100 0 1,200 Analyst Day - November 2013 2009 2010 2011 2012 2013 2014 2009 2010 2011 2012 2013 2014 Well Year Well Year Wells Averages Stage Count Wells Averages Reducing stage length, increasing the number of stages, and increasing proppant volume have been integral in improving well productivity 56
Upstream Marcellus Shale Longer Laterals Drive Improved Economics Completed Lateral Length (ft) 7,000 Wells Completed Lateral Length (ft) Averages 6,000 5,586 50% Increase 5,000 4,838 4,000 3,709 3,000 2,000 2009 2010 2011 2012 2013 2014 Analyst Day - November 2013 Well Year Lateral lengths have increased even as target selection and execution have improved 57
Upstream Marcellus Shale 2013 Appraisal Program was a Success 50-hr Flowback Rate (Mcf/d/1000') P10 P50 P90 Mean StDev FY13 Program 1,427 1,128 893 1,147 211 Previous Programs 1,002 519 270 589 329 P1 2.100 95% improvement 1.600 P10 1.100 P20 0.600 2013 Program P30 P40 2010-2011 Program 0.100 P50 P60 -0.400 P70 Analyst Day - November 2013 P80 -0.900 Rich Valley Flowback EUR: 7.4 BCF P90 -1.400 -1.900 P99 -2.400 100 1000 Avg Rate, Peak 50 hr/1000' 58
Upstream Marcellus Shale 200,000 Acres With 6-8 Bcfe EUR Wells SRC Fee Acreage SRC Lease Acreage 2-4 BCF/well EOG Earned JV Acreage 2014 Hz Appraisal Program 2015+ Locations 6 - 8 BCF/well 4 - 6 BCF/well 2-4 BCF/well Analyst Day - November 2013 4 - 6 BCF/well Vertical well data base Note: Assumes 6,000’ treated lateral length 59
Upstream Marcellus Shale 1,700 To 2,000 Economic WDA Locations Below $4/Mcfe Approx. 15% IRR (1) IRR (1) @ Remaining EUR Breakeven Price Prospect County Product Locations (Bcfe) BTU $4/MMBtu ($/Mcf) Tract 100 Lycoming Dry Gas 40 11.5 1,030 90% $2.20 Gamble Lycoming Dry Gas 29 10-11 1,030 77% $2.33 Tract 595 Tioga Dry Gas 20 8.4 1,030 45% $2.63 Clermont/Rich Valley Elk/Cameron Dry Gas 228 6-8 1,050 38% $2.80 Ridgway Elk Dry Gas 450-570 6-8 1,111 26% $3.30 Hemlock Elk Dry Gas 130-170 6-8 1,070 23% $3.40 Church Run Elk Dry Gas 60-70 6-8 1,125 22% $3.45 (W) West Branch McKean Dry Gas 47 6-8 1,050 22% $3.48 Covington Tioga Dry Gas Developed 5.7 1,030 22% $3.49 Heath Jefferson Dry Gas 260-330 5-8 1,060 19% $3.65 Sulger Farms Jefferson Dry Gas 170-210 5-8 1,020 19% $3.66 Owl’s Nest/James City Elk/Forest Dry Gas 120-160 5-8 1,125 18% $3.69 Boone Mt. Elk Dry Gas 230-290 4-6 1,020 18% $3.76 Analyst Day - November 2013 Church Run Elk Wet Gas 40-50 2-4 1,140 13% $4.32 Wet Gas/ Tionesta Forest/Venango 300-340 4-6 1,325 12% $4.50 Liquids Owl’s Nest/James City Elk/Forest Wet Gas 150-180 4-6 1,140 11% $4.51 Mt. Jewett McKean Wet Gas 90-110 2-4 1,140 6% $5.50 Beechwood Cameron Dry Gas 210-280 2-4 1,030 2% $7.14 Red Hill Cameron Dry Gas 150-200 2-4 1,030 2% $7.14 2013 Appraisal prospects 2014 Appraisal prospects 60 (1) Internal Rate of Return (IRR) includes estimated well costs, LOE, and Gathering tariffs anticipated for each prospect
Upstream Marcellus Shale Marketing Intercompany Gathering Ensures Timely Gas Sales Historical Strategy Firm sales at Financial hedges to interstate pipeline lock in benchmark interconnects and basis risk Develop gathering infrastructure with NFG Midstream Current/Long-Term Strategy Analyst Day - November 2013 Firm transport (FT) to major markets Financial hedges to Firm sales tied to lock in benchmark FT contracts and basis risk 61
Upstream Marcellus Shale Marketing Securing Firm Transportation to Major Markets Firm transport to Canada, Northeast and Southeast U.S. markets Analyst Day - November 2013 Current Seneca Development Areas 62
Upstream Marcellus Shale Marketing TGP 300 Production & Firm Sales Aligned Thru 2014 200 Dawn NYMEX Dominion Production (Forecast) 180 160 Gross MMBtu per Day 140 120 100 NYMEX Index Less $0.24 80 Dawn Index 60 Less $0.44 Analyst Day - November 2013 40 Dominion Index Less $0.37 20 0 63
Upstream Marcellus Shale Marketing Targeting Future Firm Sales on Transco 400 Transco Z6 NY/NNY NYMEX Dominion Production (Forecast) 350 300 Gross MMBtu per Day 250 200 150 Transco Zone 6 Index Less $0.57 Analyst Day - November 2013 100 NYMEX Index Less $0.29 50 Dominion Index Less $0.14 0 64
Upstream Point Pleasant & Utica Shale Continuing to Delineate Range Resources Point Pleasant 1.4 MMcf/d Permitted Northern Boundary “Not Effectively Stimulated” Drilled/Drilling Completed Mt. Jewett Producing Horizontal: completed September 2013 Peak 24-Hour Rate: 8.5 MMcf/d Halcon 2.5 MMcf/d, 360 Bbls/d Tionesta Horizontal: Completed Fall 2012 Halcon Peak 24-Hour Rate: 3.9 MMcf/d 4.5 MMcf/d, 860 Bbls/d Halcon Rex 6.6 MMcf/d, 9.2 MMcf/d 750 Bbls/d Analyst Day - November 2013 Range Resources 4.4 MMcf/d Chesapeake 6.4 MMcf/d Eastern Ohio Point Pleasant Core 65
Upstream Mississippian Lime Commencing Evaluation Program in Fiscal 2014 Total Net Acres: 13,615 Unit 100% working interest in 4,400 30-day IP: gross acres 352 BOED (92% Oil/NGLs) 55% net working interest in 17,365 gross acres Negotiated an increase in Seneca’s working interest and have taken over as operator Currently drilling first well Will drill up to 5 evaluation wells in Analyst Day - November 2013 2014 The initial entry into the Mississippian Lime play furthers the Company’s goal of maintaining a significant contribution from oil-producing properties 66
Analyst Day - November 2013 Upstream California Update 67
Upstream California Stable Production Fields; Modest Growth Potential 6,000 2010 4,500 East Coalinga 4,000 2013 Gross Operated Daily Temblor Formation Production (Boe/d) 4,500 Primary 1,700 3,000 1,500 1,200 1,200 1,100 1,100 800 North Lost Hills 1,500 500 500 Tulare & Etchegoin Formation Primary/Steamflood 0 North South South North Sespe East Midway Midway Lost Hills Lost Hills Coalinga South Lost Hills Sunset Sunset Monterey Shale Primary Key Areas of Focus in 2014 1. East Coalinga Evaluation North Midway Sunset Analyst Day - November 2013 2. South Midway Sunset Extensions Tulare & Potter Formation 3. Sespe Coldwater Evaluation Steamflood South Midway Sunset Antelope Formation Sespe Steamflood Sespe Formation Primary 68
Upstream California South Midway Sunset Has Delivered Significant Growth Monthly Production at South Midway Sunset 2,000 Daily Production (Boe per day) Seneca Acquired in 1,500 June 2009 B Pool A Pool 1,000 500 0 16X Pool 97X Pool Highlights Since Acquisition Analyst Day - November 2013 251 Pool 252 Pool Increased daily production by 130% SE Pool 1000’ Drilled 80 new producers Added 3.3 MMBO of proven reserves Existing Wells Increased steam capacity by 280% Identified opportunities for additional Original Pool Boundary pool development Extended Pool Boundary 69
Upstream California South MWSS Growth Opportunities Continue into 2014 Analyst Day - November 2013 70
Upstream California Early Success in Farm-In with Chevron at East Coalinga Monthly Production @ East Coalinga Returned to Production 750 2013 Evaluation Wells Daily Production (Boe per Day) 1-Acre Test Seneca Lease 48 BOPD Seneca Acquired in Existing Wells 500 January 2013 Downspacing Potential 1-acre (~30 locations) 2-acre (~40 locations) 250 5-acre (~120 locations) 0 2-Acre Test Highlights Since Acquisition 18 BOPD Analyst Day - November 2013 Achieved highest field production in 10 years Production increased 130% since 1/2013 Drilled 12 evaluation wells that confirmed downspacing potential 5-Acre Test Returned 40 idle wells back to production 54 BOPD 2000’ 71
Upstream California Ramping Up the Coalinga Drill Program in Fiscal 2014 2014 Development Program (Tentative) 2014 Locations (30) 2013 Locations (12) Location Selection Criteria • 2013 new well production • Reservoir pressure mapping • Historical production Analyst Day - November 2013 • Past EOR attempts 72
Upstream California Ongoing Evaluation of Long-Term Sespe Potential 2011 Wells (5) TC 524-28 IP: 100 BOEPD 2012 Wells (6) 1 1 st Oil 10/13 Mile 2013 Wells (6) TC 525-28 2014 Wells (4) IP: 160 BOEPD 1 st Oil 10/13 WS 535-33 1 st Oil in 11/13 # of Average IP Year Target Wells (BOEPD) WS 525-33 Analyst Day - November 2013 2011 Sespe (5-Acre Infill) 2 75 1 st Oil in 11/13 2011 Sespe (10-Acre) 3 90 2012 Sespe (5-Acre Infill) 2 70 2012 Coldwater 2 125 2012 Sespe (10 Acre) 2 110 2013 Sespe (5-Acre Infill) 2 NA “X” SANDS ISOCHORE (Thickness) 2013 Coldwater 2 130 2013 Sespe (10 Acre) 2 85 73
Upstream California Evaluating the Monterey Shale at South Lost Hills Brittleness GR Oil ResD SP Gas Truman 2H Lower Reef Ridge Planned FY14 Seneca Lease 1000’ Upper Antelope A Truman 1H 2013 Upper Antelope B 190 BOEPD Analyst Day - November 2013 Citrus 2H Planned FY14 McDonald 18 potential locations in each of the three horizons (concept) Citrus 11 74
Upstream California Limited Growth Opportunities, But Strong Economics Average Estimated Average EUR IRR Fiscal 2014 Field Well Cost (MBO) @$100/Bbl Locations South Midway Sunset $250,000 30 75% 23 East Coalinga $400,000 40 50% 30 Sespe – 5 Acre Infill $2,800,000 150 25% 0 Sespe - Coldwater $2,800,000 180 35% 4 Analyst Day - November 2013 75
Upstream California Modest Growth Anticipated in 2014 and 2015 Forecast 10,000 Average Daily Net Production (BOE per Day) 9,322 9,078 9,056 9,000 8,773 8,000 7,000 Analyst Day - November 2013 6,000 2010 2011 2012 2013 2014 (Est.) 2015 (Est.) Fiscal Year 76
Upstream Marcellus Operational & Environmental Overview Analyst Day - November 2013 77
Upstream Marcellus Shale Our Development Approach Drives Major Efficiencies Focused Technical & Multi-Well Development Operational Pads Areas Expertise Analyst Day - November 2013 Faster Spud-to-Sales Timing Economies of Scale Reduces Costs Minimal Infrastructure Constraints & Well Backlog 78
Upstream Marcellus Shale EDA Delivering Significant Growth Covington – Fully Developed Gross Production: ~60 MMcf per Day 47 Wells Drilled and Producing DCNR Tract 595 Gross Production: ~100 MMcf per Day 34 Wells Drilled (52 Total Locations) 26 Wells Producing DCNR Tract 100 Gross Production: ~220 MMcf per Day 40 Wells Drilled (70 Total Locations) 30 Wells Producing Analyst Day - November 2013 Gamble Recently, 30 to 50 future locations were added in Lycoming County 79
Upstream Marcellus Shale EDA – Historical Well Results Are Exceptional Average EUR per Average Average Average EUR Average 1,000’ of Producing IP Rate 7-Day 30-Day per Well Lateral Lateral Development Area Well Count (MMcf/d) (MMcf/d) (MMcf/d) (Bcf) Length (Bcfe) Covington Tioga 47 5.2 4.7 4.1 5.7 4,023’ 1.42 County Tract 595 Tioga 26 7.1 6.0 5.1 8.4 4,639’ 1.81 County Tract 100 Analyst Day - November 2013 Lycoming 30 16.1 14.2 11.9 11.5 5,210’ 2.21 County Seneca’s acreage in Lycoming County has consistently delivered some of the most prolific wells in the Marcellus Shale 80
Upstream Marcellus Shale Faster Spud-to-Sales: Drilling Efficiencies DCNR Tract 100 (Lycoming) Average Daily Drilling Footage 1,500 How has this been accomplished? 1,320 Directional Plan Optimization 1,200 Minimize drilling path corrections 1,050 Bit Selection 1,000 Daily Footage Increases drilling rate and durability 829 Drill Top-hole Sections Deeper 642 624 with Water More efficient and cost effective 500 Analyst Day - November 2013 Optimize Landing Depth Improves production and rate of penetration 0 2011 2012 2013 2013 2014 Best Q4 (Est.) FYTD Fiscal Year 81
Upstream Marcellus Shale Faster Spud-to-Sales: Multi-Well Pads Are Key Average Number of Yearly Rig Moves Average Rig Move Cost per Well Cumulative Annual Cost Savings ($ Millions) Average per Well Move Cost ($ Thousands) 24 24 $500 $6.0 $4.8 $4.6 20 22.1 $5.0 21.9 $400 22 21.4 $4.0 $390 18.2 16 $4.0 Wells per Year $300 20.2 Rig Moves $2.6 12 20 $3.0 $200 $225 10.1 8 $2.0 18 $143 18.2 $100 $115 4 $1.0 5.4 $103 3.7 2.8 0 16 $0 $0.0 1 2 4 6 8 1 2 4 6 8 Wells per Pad Wells per Pad Analyst Day - November 2013 Average Rig Moves (per Rig) Average Wells per Year (per Rig) Average per Well Move Cost Average Savings per Year (per Rig) Limiting the movement of rigs between pads allows for more drilling Using LEAN practices has eliminated four days from each rig move Staying in smaller regional areas further limits move time 82
Upstream Marcellus Shale Drilling Efficiencies Allow for More Wells per Year Drilling Efficiency vs. Lateral Length 30 6,000 5,500 All Marcellus Wells 5,021 Average Lateral Length (Feet) 4,650 4,614 Wells per Rig per Year 3,929 18.7 20 4,000 14.5 12.0 11.6 11.3 10 2,000 Analyst Day - November 2013 0 0 2010 2011 2012 2013 2014 (Est.) Fiscal Year In spite of increasing the average lateral length, each rig is drilling more wells per year 83
Upstream Marcellus Shale Faster Spud-to-Sales: Completing More Stages per Day DCNR Tract 100 (Lycoming) RCS Stages per Day 15 How has this been accomplished? 12 Completion Efficiency Technologies 10 RCS Stages per Day 10 Hydraulic toe sleeves, frac sleeves, Lean fundamentals (NPT tracking) 7 24-Hour Operations Double the stages per day 5 Water Pipelines Analyst Day - November 2013 3 More efficient than trucking water 0 2012 2013 2014 2014 Q1 (Est.) Fiscal Year 84
Upstream Marcellus Shale Faster Spud-to-Sales: The Overall Picture Average Spud-to-Sales for a 6-Well Pad (Normalized for 5,500’ Laterals per Well) (1) 2010 253 Days 164 89 2011 233 Days 161 72 2012 259 Days 158 101 Analyst Day - November 2013 2013 226 Days 131 95 2014 (Est.) 149 Days 89 60 Drilling Completion 85 (1) 2010 completion time based on a 5-well pad normalized to a 6-well pad
Upstream Marcellus Shale Faster Spud-to-Sales: More Lateral Feet Completed Yearly Total Lateral Feet & Stages Completed 2,000 400 1,888 Stages per Year (RCS) Stages per Year (Non-RCS) Lateral Feet Completed Lateral Feet Completed (Thousands) 1,500 Stages Completed 1,298 1,000 200 1,888 1,052 611 591 120 500 270 Analyst Day - November 2013 591 491 270 246 7 0 0 2009 2010 2011 2012 2013 2014 (Est.) Fiscal Year 86
Upstream Marcellus Shale Drilling Cost Reductions: Several Contributing Factors DCNR Tract 100 (Lycoming) DCNR Tract 100 (Lycoming) Average Drilling Days to TD Average Drilling Cost (Normalized for a 5,500’ Treatable Lateral) (Normalized for a 5,500’ Treatable Lateral) 30 $5.0 Drilling Cost ($ Millions) $4.4 22.0 24.0 $3.8 $4.0 Drilling Days $3.3 18.0 20 $3.0 $2.5 $2.3 $2.0 14.8 12.0 11.1 $2.0 10 $1.0 0 $0.0 2011 2012 2013 2013 2014 Best 2011 2012 2013 2013 2014 Best Q4 (Est.) FYTD Q4 (Est.) FYTD Fiscal Year Fiscal Year Analyst Day - November 2013 Improvements From 2012 to 2013 ($525,000 per well) Shorter drilling days to TD: $300,000 Faster rig moves (2012: 8.5 Days → 2013: 4.5 Days): $20,000 (6-well pad) Procurement and supply chain initiatives: $120,000 Directional plan optimization: $60,000 Natural gas-powered rigs: $25,000 87
Upstream Marcellus Shale Completion Cost Reductions: Ongoing Optimization DCNR Tract 100 (Lycoming) Average RCS Completion Cost per Stage How is this being accomplished? $200 Completion Costs per Stage ($ Thousands) New Frac Contract in 2014 $160 Pumping, sand and chemical costs $150 reduced ~20% $131 Savings: $10,000/stage $120 $113 Completion Efficiencies 24-hour operations $100 New technologies Savings: $5,000/stage Analyst Day - November 2013 Water Infrastructure $50 Full trucking: $7.00/Bbl Limited trucking: $1.50 - $3.00/Bbl Savings: $25,000/stage $0 2012 2013 2014 Best FYTD (Est.) Fiscal Year 88
Upstream Marcellus Shale Completion Cost Reductions: New Efficient Technologies Time Savings Toe Sub • 4 days per well $60,000 savings per well Prep • 24 days per 6-well pad Time Savings Sleeve • 6 days per well $200,000 savings per well Frac • 36 days per 6-well pad Time Savings Dissolvable Balls • 5 days per well Analyst Day - November 2013 $300,000 savings per well Drill-Out • 30 days per 6-well pad $3.4 million saved on a 6-well pad from the utilization of new technologies 89
Upstream Marcellus Shale Completion Cost Reductions: Water Infrastructure System Cost: $8.5 million 8 miles of pipeline 43 million gallons of storage Will serve at least 70 wells Provides 75% of water needs, with the remainder being recycled production fluid Environmental & Cost Benefits Eliminated the need for 47,000 water trucks since February 2012 Saved more than $4 million on Tract 100 development to date Analyst Day - November 2013 Improved Efficiencies Trucking in water across this Water Pipeline challenging terrain would have Storage Impoundment delayed completions and production This model has been successful in Lycoming & Tioga counties and will be utilized in the WDA as development progresses 90
Upstream Marcellus Shale Minimizing Backlogs: Coordinated Development Sales Lag (Months) 0 6 12 18 IRR (1) @ $4/Mcf Realized Pricing 90% 58% 46% 38% Coordination with NFG Midstream to construct gathering systems Development well backlog typically consists of wells on pads in either the drill or complete phase Regional development programs Focus on multi-well pads in smaller geographic areas allows for efficient Analyst Day - November 2013 gathering connectivity Managing completion schedule Ongoing monitoring of operations and maintaining the flexibility to alter completion schedules 91 (1) Assumes 6,000’ completed lateral length, $7.5MM well cost, and 11.5 Bcf EUR
Upstream Seneca Resources Committed to Health, Safety, and the Environment Seneca Resources Corporation – Value Statement “We ask that each employee share in our philosophy and unwavering commitment to each other’s health and safety and the environment.” Management team dedicated to building a culture of continual Best Practices Operating Excellence EHS improvement Incorporating Lean Program Process Strategies Analyst Day - November 2013 “…creating a systematically Dedicated 24-Hour integrated model Compliance EHS Hotline and Department of EHS stewardship E-mail Address beyond mere compliance.” 92
Analyst Day - November 2013 Midstream Midstream Businesses Overview 93
Midstream Midstream Businesses National Fuel’s Midstream Businesses NFG Midstream Businesses Reporting Pipeline & Storage Gathering Segment Segment Segments National Fuel Gas National Fuel Gas Midstream Analyst Day - November 2013 Supply Corporation Corporation Subsidiaries Empire Pipeline, Inc. 94
Midstream Midstream Businesses Positioned Well to Serve Appalachian Producers National Fuel Gas Supply Corporation System Length ~ 2,550 Miles Storage Capacity 73.4 Bcf Contracted Transport 2.58 MMDth/d 2013 Revenue $191.2 Million Niagara(TCPL) 2010 – 2013 $304.6 Million NFG East Aurora (TGP/DTI) Capital Expenditures Independence (Millennium) NFG Ellisburg (TGP 300) Leidy (Transco/TETCO) Mercer Analyst Day - November 2013 (TGP) Holbrook (TETCO) Major Interconnects 95
Midstream Midstream Businesses Positioned Well to Serve Appalachian Producers Empire Pipeline System Length ~250 Miles Contracted Transport 1.07 MMDth/d 2013 Revenue $76.4 Million 2010 – 2013 $62.8 Million Capital Expenditures Lysander Sithe Chippawa (TCPL) Mendon Hopewell (TGP 200) (RG&E) Corning (Millennium) Jackson (Shell/Talisman) Analyst Day - November 2013 Major Interconnects 96
Midstream Midstream Businesses Positioned Well to Serve Appalachian Producers NFG Midstream Corp. System Length 59 Miles 2013 Revenue $34.8 Million Capital Expenditures $168 Million (Since Inception) TGP 300 Analyst Day - November 2013 Transco Major Interconnects 97
Midstream Midstream Businesses Long-Term Strategy Driven by Both Seneca & 3 rd Parties Develop strong partnerships with customers to help them reach diverse, high-value markets 3 rd Party Seneca Midstream Resources Businesses Shippers Analyst Day - November 2013 Diverse Markets 98
Midstream Midstream Businesses Positioned to Serve Seneca’s Rapidly Growing Production Analyst Day - November 2013 99
Midstream Gathering Gathering is the Crucial First Step to Reaching a Market TGP 200 Clermont Gathering System Covington (Under Construction) Gathering System (In-Service) TGP 300 Analyst Day - November 2013 Trout Run Gathering System (In-Service) Transco Gathering Interconnects (In-Service and Under Construction) 100
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