National Fuel Gas Company · NYSE:NFG
National Fuel Gas — Investor Day (November 2013)
164 slides from National Fuel Gas's investor day presentation, Nov 19, 2013
Slide 1: Analyst Day Presentation November 19, 2013
Analyst Day Presentation November 19, 2013 Exhibit 99 National Fuel Gas Company
Slide 2: Safe Harbor For Forward Looking Statements
National Fuel Gas Company 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 c
Slide 3: Analyst Day – Schedule of Speakers
Presenter Topic National Fuel Gas Company Analyst Day – Schedule of Speakers Ron Tanski President and Chief Executive Officer Corporate Overview Matt Cabell President of Seneca Resources Corporation Exploration & Production Overview John McGinnis Senior VP of Seneca Resources Corporation Appraisal &
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Slide 5: Exceptional Assets, Focused on Execution
1.549 Tcfe of Proved Reserves 800,000 Net Acres in Pennsylvania 2.8 MMBbl of Crude Oil Production $191 Million of Midstream EBITDA National Fuel Gas Company Exceptional Assets, Focused on Execution
Slide 6: A History of Success & A Future of Opportunity: Recent Success
35% Production CAGR Since 2010 Nearly $600 Million Invested in New Pipeline Infrastructure De-risked 2,000 Well Locations in the Marcellus National Fuel Gas Company A History of Success & A Future of Opportunity Recent Success
Slide 7: Corporate Overview
Corporate Overview Integrated Businesses Provide Complimentary Benefits
Slide 8: Consistent Growth in Low Natural Gas Price Environment
Fiscal Year Natural Gas (1) ($/MMBtu) Corporate Overview Consistent Growth in Low Natural Gas Price Environment $4.68 $4.49 $4.10 $2.83 $3.60 Natural gas prices dropped 23% from 2009 to 2013
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Slide 10: Formula to Grow Our Marcellus Development Program
High-Quality Reservoir Realized Natural Gas Price Operating Efficiencies Corporate Overview Formula to Grow Our Marcellus Development Program ? Increased Capital Deployment
Slide 11: Opportunities to Move Gas Out of the Northeast
Corporate Overview Opportunities to Move Gas Out of the Northeast 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
Slide 12: Marcellus Infrastructure Growth Still Has Room to Run
2010 to 2013 Expansions 2014+ Expansions Corporate Overview Marcellus Infrastructure Growth Still Has Room to Run Capacity Added 1,819 MDth per day Capital Deployed $422 million Capacity Planned 1,724 to 2,224 MDth per day Capital Expenditures Planned ~$1.5 billion Plans are in place to deploy signi
Slide 13: A History of Success & A Future of Opportunity: Future Goals
10-15% Adjusted EBITDA Growth 15-25% Production Growth $1.5 Billion of Midstream Investment Over 5 Years National Fuel Gas Company A History of Success & A Future of Opportunity Future Goals
Slide 14: Maintaining Our View on Corporate Structure
Today Future (2015+) Strong Balance Sheet Ability to modestly increase leverage 1.89x Debt/Adjusted EBITDA Balanced Business Mix 58% E&P (1) 42% Midstream/Utility (1) Operational synergies Investment Grade Credit Diversification of businesses provide credit support Leverage is the cheapest cost of c
Slide 15: Exploration & Production Overview
Exploration & Production Overview
Slide 16: Seneca’s Evolution
Seneca Resources Seneca’s Evolution
Slide 17: Fiscal 2013 Highlights
351% WDA Success Total production increased 45% to 120.7 Bcfe Seneca Resources Fiscal 2013 Highlights Replaced 351% of proved reserves Finding & Development Cost: $1.31/Mcfe Marcellus Finding & Development Cost: $0.99/Mcfe Achieved major breakthrough in the Marcellus Shale Western Development Area (
Slide 18: Disciplined Capital Spending
Seneca Resources Disciplined Capital Spending
Slide 19: Proven Record of Growth
Fiscal Years 3-Year F&D Cost (1) ($/Mcfe) Seneca Resources Proven Record of Growth 2006-2008 $7.63 2007-2009 $5.35 2008-2010 $2.37 2009-2011 $2.09 2010-2012 $1.87 2011-2013 $1.67 2013 F&D Cost = $1.31 Marcellus F&D: $0.99 Doubled Proved Reserves Since 2010 71% Proved Developed
Slide 20: Best-In-Class Marcellus Shale Reserve Growth
Seneca Resources Best-In-Class Marcellus Shale Reserve Growth
Slide 21: Delivering Tremendous Production Growth
Seneca Resources Delivering Tremendous Production Growth
Slide 22: Delivering More than Just Absolute Growth
Seneca Resources Delivering More than Just Absolute Growth
Slide 23: Significant Position & Integral Part of Seneca’s Future
Company Net Marcellus Acreage (1) Enterprise Value (2) ($ Billions) Acres per $ Million of EV Marcellus Shale Significant Position & Integral Part of Seneca’s Future 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 AR 334,000 $17.2 19.4 COG 200,000 $15.2 13
Slide 24: Marcellus Shale: Factors for Success
Marcellus Shale Factors for Success Acreage Position – Quantity & Quality Operating Expertise Control costs Maximize production Gathering, Transportation and Marketing Financial Stability Ability to withstand price swings and market dislocations
Slide 25: Prolific Pennsylvania Acreage
Marcellus Shale Prolific Pennsylvania Acreage
Slide 26: 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 Requires Gas Price Above $4/Mcf ~300,000 acres Seneca Acreage Huge Position – Varies in Understanding Understanding Seneca’s 780,000 Net Acres
Slide 27: Fee Ownership & Contiguity are Beneficial
No Royalty No Lease Expiration Contiguous Acreage Blocks Seneca’s Tier I acreage is approaching Northeast Core economics Seneca Acreage Fee Ownership & Contiguity are Beneficial
Slide 28: Seneca’s Marcellus Acreage Provides a Unique Advantage
Seneca Acreage Seneca’s Marcellus Acreage Provides a Unique Advantage Seneca Advantage #1 Fee Ownership Position 28% IRR 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 Int
Slide 29: Best-In-Class Operator in Lycoming County (EDA)
Seneca’s Operations Best-In-Class Operator in Lycoming County (EDA)
Slide 30: Top-Notch Lycoming Economics
Seneca’s Operations Top-Notch Lycoming Economics
Slide 31: Seneca’s Lycoming Economics are in the Top 3
Seneca’s Operations Seneca’s Lycoming Economics are in the Top 3
Slide 32: Driving Down Well Costs
Seneca’s Operations Driving Down Well Costs In 2014, total well costs are expected to be ~35-40% lower than 2012
Slide 33: Seneca’s Overall Marketing Strategy
Develop gathering infrastructure with NFG Midstream Firm sales at interstate pipeline interconnects Firm transport (FT) to major markets Firm sales tied to FT contracts Financial hedges to lock in benchmark and basis risk Financial hedges to lock in benchmark and basis risk Seneca’s Gathering & Mark
Slide 34: Ability to Withstand Pricing Challenges
National Fuel’s Financial Stability Ability to Withstand Pricing Challenges
Slide 35: Marcellus Shale: Factors for Success
Marcellus Shale Factors for Success Acreage Position – Quantity & Quality Operating Expertise Control costs Maximize production Gathering, Transportation and Marketing Financial Stability Ability to withstand price swings and market dislocations
Slide 36: California: Outstanding Cash Flow
California Outstanding Cash Flow (1)
Slide 37: Looking Back at the Successful Ivanhoe Acquisition
California Looking Back at the Successful Ivanhoe Acquisition
Slide 38: California: Looking Forward
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 3. Continue to pursue additional acquisition and farm-in opportunities
Slide 39: Seneca Resources Key Metrics
Operational Strategy Metric Fiscal 2009 Strategic Improvements Fiscal 2013 Focus on growth- oriented Marcellus Shale assets with significant fee acreage Maintain and grow strong cash flow assets in California 12x Production Growth 7x Reserve Growth 5x EBITDA Growth 49% Decrease per Mcfe 25% EBITDA G
Slide 40: What Will Seneca Look Like Moving Forward?
Consistent Production Growth: 15-25% CAGR Driven by a very large, high-quality Appalachian acreage position Maintain Oil Production Expand When Possible Excellent operator and significant cash flow generation Disciplined Spending Driven by Rates of Return Pace of development adapts to changing marke
Slide 41: Appraisal & Development Overview
Appraisal & Development Overview
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Slide 45: WDA Is the Key to Seneca’s Long-Term Growth Outlook
Full Development Since 2010 ~225 locations remaining 70-90 wells in Lycoming County Near-term driver of growth Full Development Started in 2013 1,700 to 2,000 locations de-risked Long-term driver of growth Marcellus Shale WDA Is the Key to Seneca’s Long-Term Growth Outlook Seneca Lease Seneca Fee 72
Slide 46: Significantly Improved Understanding of the WDA
James City Church Run Owl’s Nest Mt. Jewett W. Branch Clermont St. Mary’s Kyler’s Corner Boone Mtn Sulger Farm Tionesta Beechwood Red Hill/ Leasgang Punxy Rich Valley Ridgway Key Statistics Vertical Wells: 30 Full Core: 8 Sidewall Core: 2 3D Seismic: 432 sq m Marcellus Shale Significantly Improved U
Slide 47: Northwest PA Generalized Cross-Section
TOC Marcellus Shale Northwest PA Generalized Cross-Section Transitional Outer Shelf CaCO Sed. Rate Platform Basin Rich Valley Clermont Beechwood Owl’s Nest James City Leasgang Punxy Ridgway High variability, very poor rock quality in areas High organics, great rock quality, less variability Medium r
Slide 48: WDA Log Summary Cross-Section
Marcellus Shale WDA Log Summary Cross-Section TOC/PHI/BWV 0 Wt% 50 0.2 v/v 0 0.2 v/v 0 Mineralogy Volume % Gas Resource 0 Mcf/ac-ft 1500 0 Bcf/mi 100 = 6.8 - 8.1% Total GIP = ~70/sect = 5.6 - 6.7% Total GIP = ~75/sect TOC/PHI/BWV 0 Wt% 50 0.2 v/v 0 0.2 v/v 0 Mineralogy Volume % Gas Resource 0 Mcf/ac
Slide 49: 2013 & 2014 WDA Delineation Program
SRC Lease Acreage SRC Fee Acreage EOG Earned JV Acreage Marcellus Shale 2013 & 2014 WDA Delineation Program Owl’s Nest – Delineating 2 High Btu Wells Completed Rich Valley – Full Development 2 Wells Completed 7-Day IP of 7.8 MMcf/d & EUR of 7.4 Bcf Well 7-Day IP: 4.5 MMcf/d Tionesta – Delineating 1
Slide 50: Rich Valley/Clermont is in Full Development Mode
Rich Valley 2 Well 7-day IP: 4.5 MMcf/d Lateral Length: 4,492’ 200-250 Horizontal Locations Pad N: Spacing Test JV Wells Pad H Pad D Pad E Pad O Clermont RCS: 9H 7-day IP: 10.0 MMcf/d (EUR: 8.6 Bcf) Non-RCS: 10H 7-day IP: 7.4 MMcf/d Rich Valley 7-day IP: 7.8 MMcf/d EUR: 7.4 BCF Lateral Length: 6,372
Slide 51: Clermont Wells Improved from Early Non-Op JV Wells
Marcellus Shale Clermont Wells Improved from Early Non-Op JV Wells Clermont 5H & 6H (Non-op wells) Avg. lateral length: 3,344’ Small casing: 4.5” Restricted pump rates Wide stage spacing: 350’ No soaking, low Sw’s Clermont 9H & 10H (Seneca wells) Avg. lateral length: >5,500’ Large casing: 5.5” Incre
Slide 52: Moving All Completions to Reduced Cluster Spacing (RCS)
Marcellus Shale Moving All Completions to Reduced Cluster Spacing (RCS) RCS Design Conventional Design Twice the number of stages/perforations Increases stimulated reservoir volume Increased proppant near the wellbore improves fracture conductivity
Slide 53: Consistently Improved Results in the Owl’s Nest Area
Marcellus Shale Consistently Improved Results in the Owl’s Nest Area 2013 Appraisal Program Lateral length >4,400’ to 6,200’ RCS completions 150’ spacing Soaked wells 30 – 60 days Target interval Union Springs: 100% in target
Slide 54: Strong Wells Across WDA Acreage
Well Name Completion Design Treatable Lateral Length Stages Peak 24-Hour Rate (MMcfd) Peak 7-Day Rate (MMcfd) EUR (Bcf) Status Marcellus Shale Strong Wells Across WDA Acreage Rich Valley 27H RCS 6,372’ 8.1 7.8 7.4 Producing Clermont 9H RCS 5,500’ 11.4 10.0 8.6 Producing Clermont 10H Non-RCS 5,565’ 8
Slide 55: Key Areas of Improvement in Recent Delineation Program
Areas of Improvement 2012-2013 Delineation Program Marcellus Shale Key Areas of Improvement in Recent Delineation Program Target Selection (Landing Depth) Identification of specific target interval is key Target Execution Percent of wellbore in target interval increased from prior years Completion D
Slide 56: Selection of Target Interval is Critical
Previous programs spent a significant portion ( > 60% ) of the wellbore outside of the current target interval, identified to have improved productivity Marcellus Shale Selection of Target Interval is Critical
Slide 57: Optimized Landing Depth
Marcellus Shale Optimized Landing Depth EDA Lycoming Type Log ROP (ft/hr) ROP vs Height Above Onondaga Improved Target Zone Drivers Best rock quality in terms of organic content, brittleness, and porosity Highest rate of penetration (ROP)
Slide 58: Continued Improvement Staying within Targeted Interval
Marcellus Shale Continued Improvement Staying within Targeted Interval Reasons for Improvement 3D seismic acquisition Improved communication between Geology, Drilling and Completion teams Geosteering technology (azimuthal GR)
Slide 59: RCS & Increased Sand Volume Generating Better Results
Reducing stage length, increasing the number of stages, and increasing proppant volume have been integral in improving well productivity Marcellus Shale RCS & Increased Sand Volume Generating Better Results Improved near wellbore fracture conductivity Increases near wellbore fracturing & stimulated
Slide 60: Longer Laterals Drive Improved Economics
Lateral lengths have increased even as target selection and execution have improved Marcellus Shale Longer Laterals Drive Improved Economics
Slide 61: 2013 Appraisal Program was a Success
P10 P50 P90 Mean StDev Marcellus Shale 2013 Appraisal Program was a Success 50-hr Flowback Rate (Mcf/d/1000') FY13 Program 1,427 1,128 1,147 Previous Programs 1,002 Avg Rate. Peak 50 ht/1000’
Slide 62: 200,000 Acres With 6-8 Bcfe EUR Wells
Marcellus Shale 200,000 Acres With 6-8 Bcfe EUR Wells
Slide 63: 1,700 To 2,000 Economic WDA Locations Below $4/Mcfe
Prospect County Product Approx. Remaining Locations EUR (Bcfe) BTU IRR (1) @ $4/MMBtu 15% IRR (1) Breakeven Price ($/Mcf) Marcellus Shale 1,700 To 2,000 Economic WDA Locations Below $4/Mcfe Tract 100 Lycoming Dry Gas 11.5 1,030 90% $2.20 Gamble Lycoming Dry Gas 10-11 1,030 77% $2.33 Tract 595 Tioga
Slide 64: Intercompany Gathering Ensures Timely Gas Sales
Develop gathering infrastructure with NFG Midstream Firm transport (FT) to major markets Firm sales tied to FT contracts Financial hedges to lock in benchmark and basis risk Financial hedges to lock in benchmark and basis risk Firm sales at interstate pipeline interconnects Marcellus Shale Marketing
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Slide 66: TGP Production & Firm Sales Aligned Thru 2014
Marcellus Shale Marketing TGP 300 Production & Firm Sales Aligned Thru 2014
Slide 67: Targeting Future Firm Sales on Transco
Marcellus Shale Marketing Targeting Future Firm Sales on Transco
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Slide 69: Mississippian Lime: Commencing Evaluation Program in Fiscal 2014
Mississippian Lime Commencing Evaluation Program in Fiscal 2014 The initial entry into the Mississippian Lime play furthers the Company’s goal of maintaining a significant contribution from oil-producing properties Unit 30-day IP: 352 BOED (92% Oil/NGLs) Total Net Acres: 13,615 100% working interest
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Slide 71: Stable Production Fields; Modest Growth Potential
East Coalinga Temblor Formation Primary North Lost Hills Tulare & Etchegoin Formation Primary/Steamflood South Lost Hills Monterey Shale Primary North Midway Sunset Tulare & Potter Formation Steamflood South Midway Sunset Antelope Formation Steamflood Sespe Sespe Formation Primary Key Areas of Focus
Slide 72: South Midway Sunset Has Delivered Significant Growth
California South Midway Sunset Has Delivered Significant Growth Highlights Since Acquisition Increased daily production by 130% Drilled 80 new producers Added 3.3 MMBO of proven reserves Increased steam capacity by 280% Identified opportunities for additional pool development Extended Pool Boundary
Slide 73: South MWSS Growth Opportunities Continue into 2014
California South MWSS Growth Opportunities Continue into 2014
Slide 74: Early Success in Farm-In with Chevron at East Coalinga
California Early Success in Farm-In with Chevron at East Coalinga 1-Acre Test 48 BOPD 5-Acre Test 54 BOPD 2-Acre Test 18 BOPD 2000’ Returned to Production 1-acre (~30 locations) 2-acre (~40 locations) 5-acre (~120 locations) Downspacing Potential 2013 Evaluation Wells Seneca Lease Existing Wells Hig
Slide 75: Ramping Up the Coalinga Drill Program in Fiscal 2014
California Ramping Up the Coalinga Drill Program in Fiscal 2014 2014 Development Program (Tentative) Location Selection Criteria 2014 Locations (30) 2013 Locations (12) • 2013 new well production • Reservoir pressure mapping • Historical production • Past EOR attempts
Slide 76: Ongoing Evaluation of Long-Term Sespe Potential
TC 524-28 IP: 100 BOEPD 1 Oil 10/13 TC 525-28 IP: 160 BOEPD 1 Oil 10/13 WS 525-33 1 Oil in 11/13 WS 535-33 1 Oil in 11/13 Year Target # of Wells Average IP (BOEPD) st st st st California Ongoing Evaluation of Long-Term Sespe Potential “X” SANDS ISOCHORE (Thickness) Mile 2011 Wells (5) 2012 Wells (6)
Slide 77: Evaluating the Monterey Shale at South Lost Hills
California Evaluating the Monterey Shale at South Lost Hills
Slide 78: Limited Growth Opportunities, But Strong Economics
Field Average Well Cost Average EUR (MBO) Estimated IRR @$100/Bbl Fiscal 2014 Locations California Limited Growth Opportunities, But Strong Economics South Midway Sunset $250,000 75% East Coalinga $400,000 50% Sespe – 5 Acre Infill $2,800,000 25% Sespe - Coldwater $2,800,000 35%
Slide 79: Modest Growth Anticipated in 2014 and 2015
California Modest Growth Anticipated in 2014 and 2015
Slide 80: Marcellus Operational & Environmental Overview
Marcellus Operational & Environmental Overview
Slide 81: Our Development Approach Drives Major Efficiencies
Multi-Well Pads Focused Development Areas Faster Spud-to-Sales Timing Economies of Scale Reduces Costs Minimal Infrastructure Constraints & Well Backlog Technical & Operational Expertise Marcellus Shale Our Development Approach Drives Major Efficiencies
Slide 82: EDA Delivering Significant Growth
Covington – Fully Developed Gross Production: ~60 MMcf per Day 47 Wells Drilled and Producing Marcellus Shale EDA Delivering Significant Growth 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 D
Slide 83: EDA – Historical Well Results Are Exceptional
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) Marcellus Shale EDA – Historical Well Results Are Exceptional Covington Tioga County 5.2 4.7 4.1 5.7 4,023’
Slide 84: Faster Spud-to-Sales: Drilling Efficiencies
Marcellus Shale Faster Spud-to-Sales: Drilling Efficiencies How has this been accomplished? Directional Plan Optimization Minimize drilling path corrections Bit Selection Increases drilling rate and durability Drill Top-hole Sections Deeper with Water More efficient and cost effective Optimize Landi
Slide 85: Faster Spud-to-Sales: Multi-Well Pads Are Key
Marcellus Shale Faster Spud-to-Sales: Multi-Well Pads Are Key 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
Slide 86: Drilling Efficiencies Allow for More Wells per Year
Marcellus Shale Drilling Efficiencies Allow for More Wells per Year In spite of increasing the average lateral length, each rig is drilling more wells per year
Slide 87: Faster Spud-to-Sales: Completing More Stages per Day
Marcellus Shale Faster Spud-to-Sales: Completing More Stages per Day
Slide 88: Faster Spud-to-Sales: The Overall Picture
Marcellus Shale Faster Spud-to-Sales: The Overall Picture (1)
Slide 89: Faster Spud-to-Sales: More Lateral Feet Completed Yearly
Marcellus Shale Faster Spud-to-Sales: More Lateral Feet Completed Yearly
Slide 90: Drilling Cost Reductions: Several Contributing Factors
Marcellus Shale Drilling Cost Reductions: Several Contributing Factors 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
Slide 91: Completion Cost Reductions: Ongoing Optimization
Marcellus Shale Completion Cost Reductions: Ongoing Optimization
Slide 92: Completion Cost Reductions: New Efficient Technologies
Marcellus Shale Completion Cost Reductions: New Efficient Technologies Toe Sub $60,000 savings per well Time Savings Time Savings Time Savings Sleeve $200,000 savings per well Dissolvable Balls $300,000 savings per well $3.4 million saved on a 6-well pad from the utilization of new technologies
Slide 93: Completion Cost Reductions: Water Infrastructure
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
Slide 94: Minimizing Backlogs: Coordinated Development
Sales Lag (Months) 0 6 12 18 Marcellus Shale Minimizing Backlogs: Coordinated Development 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-wel
Slide 95: Committed to Health, Safety, and the Environment
“…creating a systematically integrated model of EHS stewardship beyond mere compliance.” 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 healt
Slide 96: Midstream Businesses Overview
Midstream Businesses Overview
Slide 97: National Fuel’s Midstream Businesses
Midstream Businesses National Fuel’s Midstream Businesses Reporting Segments Subsidiaries
Slide 98: Positioned Well to Serve Appalachian Producers
National Fuel Gas Supply Corporation Midstream Businesses Positioned Well to Serve Appalachian Producers System Length ~ 2,550 Miles Storage Capacity 73.4 Bcf Contracted Transport 2.58 MMDth/d 2013 Revenue $191.2 Million 2010 – Capital Expenditures $304.6 Million
Slide 99: Positioned Well to Serve Appalachian Producers
Midstream Businesses Positioned Well to Serve Appalachian Producers
Slide 100: Positioned Well to Serve Appalachian Producers
Midstream Businesses Positioned Well to Serve Appalachian Producers
Slide 101: Long-Term Strategy Driven by Both Seneca & 3rd Parties
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
Slide 102: Positioned to Serve Seneca’s Rapidly Growing Production
Midstream Businesses Positioned to Serve Seneca’s Rapidly Growing Production
Slide 103: Gathering is the Crucial First Step to Reaching a Market
Gathering Gathering is the Crucial First Step to Reaching a Market
Slide 104: Existing Systems Supporting Seneca’s Near-Term Growth
Gathering Existing Systems Supporting Seneca’s Near-Term Growth Covington Gathering System In-service date: November 2009 Capacity: 220,000 Dth per day Interconnect: TGP 300 Capital expenditures (to date): $28.3 million Capital expenditures (future): $7.5 million Trout Run Gathering System In-servic
Slide 105: Developing a 1+ Bcf/d Gathering System in the WDA
Gathering Developing a 1+ Bcf/d Gathering System in the WDA In-Service: August 2014 Initial Trunkline Capacity: 700 MMcf per day Interconnect TGP 300 Total Cost: $60-$92 Million Major Facilities 24” Pipeline – 6 Miles 8”-20” Pipeline – 25+ Miles Seneca Pads Producing 2 in Fiscal 2014 (15 Wells)
Slide 106: Clermont Gathering System has Large Expandability
Gathering Clermont Gathering System has Large Expandability In-Service: Ongoing build-out Ultimate Trunkline Capacity: 700 to 1,000 MMcf per day Interconnects TGP 300 and National Fuel Gas Supply Corporation (anticipated) Total Cost: $75 - $125 million Major Facilities Additional Gathering Clermont
Slide 107: A Number of Options to Serve 3rd Party Producers
Gathering A Number of Options to Serve 3 rd Party Producers
Slide 108: 2014 Spending Driven by Seneca Development
Gathering 2014 Spending Driven by Seneca Development $100 to $150 Million
Slide 109: More than 1.5 Bcf per day of Gathering Capacity by 2015
Gathering More than 1.5 Bcf per day of Gathering Capacity by 2015
Slide 110: Capital Deployment Will Deliver Long-Term Growth
Gathering Capital Deployment Will Deliver Long-Term Growth Revenue Growth (2013 to 2015): ~60% CAGR Capital Investment (2013 to 2015): ~60% CAGR
Slide 111: Project Opportunities to Support WDA Growth
Develop multiple outlets to high-value markets Pipeline & Storage Project Opportunities to Support WDA Growth
Slide 112: Providing Transportation to Higher-Priced Markets
Currently Short Supply Short Supply Midstream Businesses Providing Transportation to Higher-Priced Markets
Slide 113: NE Supply Approaching NE Peak Demand
Midstream Businesses NE Supply Approaching NE Peak Demand Forecasted Actual Peak Demand (24-25 Bcf per day) Median Demand (11.5 Bcf per day) Supply exceeds demand for 70% of the year by 2016
Slide 114: Focusing on Projects to Non-Traditional Demand Markets
The markets of Eastern Canada, the Mid-Atlantic and Southeast look to be the most desirable markets for shippers to reach over the long-term Midstream Businesses Focusing on Projects to Non-Traditional Demand Markets
Slide 115: Delivering Into the Eastern Canadian Market is Valuable
Pipeline & Storage Delivering Into the Eastern Canadian Market is Valuable
Slide 116: Northeast PA Spot Markets are Heavily Discounted
Pipeline & Storage Northeast PA Spot Markets are Heavily Discounted
Slide 117: Major Expansion Designed for Canadian Deliveries
Northern Access 2015 Pipeline & Storage Major Expansion Designed for Canadian Deliveries Northern Access 2015 Niagara (TCPL) Delivery Point In-Service: November 2015 System: NFG Supply Corp. Capacity: 140,000 Dth per day Interconnect Niagara (TransCanada) Total Cost: $67 Million Major Facilities 23,
Slide 118: Clermont to Chippawa Provides Delivery Options
Clermont to Chippawa Pipeline & Storage Clermont to Chippawa Provides Delivery Options Delivery Point Clermont to Chippawa Chippawa (TCPL) Hopewell (TGP 200) Corning (Millennium) In-Service: 2016 System: Supply & Empire Capacity 250,000+ Dth per day Interconnects Corning (Millennium) Hopewell (TGP 2
Slide 119: Longer-Term: Reaching Markets Along the Atlantic
Clermont to Transco Pipeline & Storage Longer-Term: Reaching Markets Along the Atlantic Transco In-Service: 2017 System: NFG Supply Corp. Capacity 300,000 to 500,000 Dth per day Interconnect Transco Leidy Line Total Cost: $100 to $150 Million To Mid-Atlantic & Southeast Clermont to Transco Delivery
Slide 120: Expansions to Move Gas from the WDA are Significant
Projects to Support WDA Growth Pipeline & Storage Expansions to Move Gas from the WDA are Significant Project Capacity (Dth/day) Northern Access 2015 140,000 Clermont to Chippawa 250,000+ Clermont to Transco 300,000-500,000 Total New Capacity 690,000-890,000+ Project Capital Cost Northern Access 201
Slide 121: Seneca Currently Represents a Small Portion of Capacity
Pipeline & Storage Seneca Currently Represents a Small Portion of Capacity Total Contracted Transportation Capacity (at 9/30/13): 3.6 MMDth per Day
Slide 122: Recent 3rd Party Expansions Have Been Highly Successful
Projects to Support 3 rd Parties Pipeline & Storage Recent 3 rd Party Expansions Have Been Highly Successful Project Capacity (Dth/day) Northern Access 2013 320,000 Tioga County Extension 350,000 Line N (2011, 2012 & 2013) 353,000 Total New Capacity 1,023,000 Project Capital Cost Northern Access 201
Slide 123: NFGSC is Now a Net Exporter of Natural Gas to Canada
Northern Access project was placed in-service November 2011 Pipeline & Storage NFGSC is Now a Net Exporter of Natural Gas to Canada
Slide 124: National Fuel Becoming a Major SW PA Transporter
Pipeline & Storage National Fuel Becoming a Major SW PA Transporter National Fuel Gas Supply Corp. went from no SW Pennsylvania receipts in 2008 to nearly 40% of all volumes today
Slide 125: Additional Line N Expansions Planned for the Future
Mercer Expansion Pipeline & Storage Additional Line N Expansions Planned for the Future In-Service: November 2014 System: NFG Supply Corp. Capacity: 105,000 Dth per day Precedent agreements signed for all available capacity Interconnect Mercer (TGP Station 219) Total Cost: $30 Million Expansion: $27
Slide 126: Pairing Line N Expansions with System Modernization
Westside Expansion & Modernization Mercer (TGP Station 219) Pipeline & Storage Pairing Line N Expansions with System Modernization In-Service: November 2015 System: NFG Supply Corp. Capacity: 175,000 Dth per day Precedent agreements signed for 145,000 Dth per day Interconnect Mercer (TGP Station 219
Slide 127: Developing Unique Solutions for Shippers
Tuscarora Lateral Pipeline & Storage Developing Unique Solutions for Shippers In-Service: November 2015 System: NFG Supply & Empire Pipeline New No-Notice Services Preserving 172,500 Dth per day (RG&E) Preserving 20,000 Dth per day (NYSEG) Precedent agreement executed with RG&E Capacity Transportati
Slide 128: Significant Expansions Are Driving Growth
Completed Projects Line N Corridor Line “N” Expansion Line “N” 2012 Expansion Line “N” 2013 Expansion Mercer Expansion West Side Expansion Total Capacity 603 MDth/d Delivering Gas North Tioga County Extension Northern Access Northern Access 2015 Clermont to Chippawa Total Capacity 1,060 MDth/d Leavi
Slide 129: Expansion Project Revenue Growth
Larger projects under consideration for fiscal 2016 and 2017 will drive significant revenue growth Pipeline & Storage Expansion Project Revenue Growth
Slide 130: New Shale Production Driving Tremendous Growth
Midstream Businesses New Shale Production Driving Tremendous Growth
Slide 131: Utility
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Slide 132: New York & Pennsylvania Service Territories
Utility New York & Pennsylvania Service Territories New York Total Customers: 520,000 Rate Mechanisms: Revenue Decoupling Weather Normalization Low Income Rates Choice Program/Purchase of Receivables Merchant Function Charge (Uncollectibles Adjustment) 90/10 Sharing (Large Customers ) Natural Gas Ve
Slide 133: Customer Usage
Utility Customer Usage Residential Usage Industrial Usage
Slide 134: Continued Cost Control Helps Provide Earnings Stability
Utility Continued Cost Control Helps Provide Earnings Stability
Slide 135: Capital Spending Largely Focused on Maintenance
Utility Capital Spending Largely Focused on Maintenance The Utility remains focused on spending to maintain the ongoing safety and reliability of its system
Slide 136: Providing Predictability and Stability
Utility Providing Predictability and Stability
Slide 137: Working Towards a Settlement in New York
Utility Working Towards a Settlement in New York March 27, 2013 Filed a plan with the NY PSC to adopt an earnings sharing and stabilization mechanism on earnings above a 9.96% ROE April 19, 2013 NY PSC issued an Order to Show Cause (OTSC) commencing a proceeding to establish “temporary rates” June 1
Slide 138: Hedging Strategy
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Slide 139: How Does Seneca Sell its Production?
Well Head Interconnection with Interstate Pipeline Network 3rd Party Marketer (or spot market) Firm Transport Demand Center (firm sales or spot market) Spot Market Hedging Overview How Does Seneca Sell its Production? Gathering System Contracted Basis Differential FT Rate The 1,700 to 2,000 economic
Slide 140: Firm Sales Provide a Market for Appalachian Production
52 Hedging Overview Firm Sales Provide a Market for Appalachian Production Prices shown represent the sales (netback price) at the first non-affiliated interstate pipeline, including the cost of all related downstream transportation.
Slide 141: Seneca Methodically Layers in Index Hedges Over Time
Hedging Overview Seneca Methodically Layers in Index Hedges Over Time
Slide 142: Current Hedge Book has Seneca Positioned Very Well
Hedging Overview Current Hedge Book has Seneca Positioned Very Well
Slide 143: Oil & Natural Gas Hedges are Above the Current Strip
Commodity Risk Management Oil & Natural Gas Hedges are Above the Current Strip (1)
Slide 144: Determining Seneca’s Realized Price on Firm Sales
Hedging Overview Determining Seneca’s Realized Price on Firm Sales NYMEX & Dominion Monthly Settlement Prices Natural Gas Index Swaps Negotiated at time of Agreement Based on Current Market at Sales/Delivery Point
Slide 145: The Impact of Firm Sales on Realized Price
57 Determining the Price of a Firm Sales Contract Hedging Overview The Impact of Firm Sales on Realized Price Contract Reference Point NYMEX Dominion December Settlement $4.000 $3.650 Less: Average Sales Basis Differential ($0.284) ($0.265) Average Realized Price (Before Hedging) $3.716 $3.235
Slide 146: Pairing Firm Sales with Hedges Leads to Price Certainty
58 Determining the Price of a Firm Sales Contract With a $4.25/MMBtu Hedge at the Reference Point Hedging Overview Pairing Firm Sales with Hedges Leads to Price Certainty Contract Reference Point NYMEX Dominion December Settlement $4.000 $3.650 Less: Average Sales Basis Differential ($0.284) ($0.265
Slide 147: Price Certainty only if Firm Sales & Hedge Index Match
59 Hedging Dominion Firm Sales Contracts With a $4.25/MMBtu Hedge at NYMEX vs. Dominion Hedging Overview Price Certainty only if Firm Sales & Hedge Index Match Contract Reference Point Dominion Dominion December Settlement $3.650 $3.650 Less: Average Sales Basis Differential ($0.265) ($0.265) Averag
Slide 148: FY 2014 Production – Firm Sales & Hedge Composition
Hedging Overview FY 2014 Production – Firm Sales & Hedge Composition Price Certainty 100% Hedged @ $4.24 /MMcf Price Certainty 92% Hedged @ $4.26/MMcf Seneca has an additional 12.7 Bcf of NYMEX hedges to help mitigate commodity exposure on its WDA sales EDA NYMEX Firm Sales EDA DOM Firm Sales EDA Sp
Slide 149: Financial Wrap-Up
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Slide 150: Targeting Sustained Growth for the Next Five Years
National Fuel Gas Company Targeting Sustained Growth for the Next Five Years
Slide 151: Capital Spending Adjusts to Capitalize on Opportunities
National Fuel Gas Company Capital Spending Adjusts to Capitalize on Opportunities
Slide 152: Forecasting a Modest Outspend in 2014
National Fuel Gas Company Forecasting a Modest Outspend in 2014 Forecast
Slide 153: Maintaining a Strong Balance Sheet
Total Debt (1) 43% Debt / Adjusted EBITDA Capitalization National Fuel Gas Company Maintaining a Strong Balance Sheet $3.843 Billion As of September 30, 2013
Slide 154: Strong Liquidity with an Investment Grade Rating
5.58% Embedded Cost of Long-Term Debt Liquidity ($Millions) National Fuel Gas Company Strong Liquidity with an Investment Grade Rating Cash and Temporary Investments $ 65 Available Short-Term Credit Facilities $1,085 Total Short-term Liquidity $1,150
Slide 155: Focused on Delivering Strong Returns
2009-2011 2010-2012 2011-2013 National Fuel Gas Company Focused on Delivering Strong Returns NFG Percentile 81% 75% 88%
Slide 156: Dividend Track Record
Dividend Consistency National Fuel Gas Company Dividend Track Record Current Dividend Yield (1) 2.1% Consecutive Dividend Payments 111 Years Consecutive Dividend Increases 43 Years Current Annualized Dividend Rate $1.50 per Share
Slide 157: A History of Success & A Future of Opportunity
Adjusted EBITDA Growth Production Growth Midstream Businesses EBITDA Adjusted EBITDA Growth Production Growth Midstream Businesses EBITDA A History of Success A Future of Opportunity National Fuel Gas Company A History of Success & A Future of Opportunity 30% CAGR Since 2009 10-15% CAGR 2014 to 2018
Slide 158: Appendix
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Slide 159: Gathering Historical Financials – 2010 & 2011
Gathering Historical Financials – 2010 & 2011 QTD ended QTD ended QTD ended QTD ended 12/31/2009 3/31/2010 6/30/2010 9/30/2010 FISCAL 2010 Operating Revenue $ $ 1,224 $ 1,237 $ 3,398 $ Operating Expenses: Operation & Maintenance Expense 1,369 Property, Franchise & Other Taxes - Depreciation, Depleti
Slide 160: Gathering Historical Financials – 2012 & 2013
Gathering Historical Financials – 2012 & 2013 QTD ended QTD ended QTD ended QTD ended 12/31/2011 3/31/2012 6/30/2012 9/30/2012 FISCAL 2012 Operating Revenue 3,565 $ 3,346 $ 4,494 $ 6,069 $ 17,474 $ Operating Expenses: Operation & Maintenance Expense 2,440 Property, Franchise & Other Taxes Depreciati
Slide 161: Comparable GAAP Financial Measure Slides and Reconciliations
National Fuel Gas Company 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 pro
Slide 162: Reconciliation of E&P West Division Adjusted EBITDA to Segment Net Income
Reconciliation of Exploration & Production West Division Adjusted EBITDA to Exploration & Production Segment Net Income ($ Thousands) FY 2013 Exploration & Production - West Division Adjusted EBITDA 215,042 $ Exploration & Production - All Other Divisions Adjusted EBITDA 277,341 Total Exploration &
Slide 163: Reconciliation of Adjusted EBITDA to Consolidated Net Income
Reconciliation of Adjusted EBITDA to Consolidated Net Income ($ Thousands) FY 2009 FY 2010 FY 2011 FY 2012 Exploration & Production - West Division Adjusted EBITDA 171,572 $ 187,838 $ 187,603 $ 226,897 $ 215,042 $ Exploration & Production - East Division Adjusted EBITDA 57,179 $ 75,098 $ 175,392 $ 1
Slide 164: Reconciliation of Segment Capital Expenditures to Consolidated
Reconciliation of Segment Capital Expenditures to Consolidated Capital Expenditures ($ Thousands) FY 2014 FY 2009 FY 2010 FY 2011 FY 2012 FY 2013 Forecast Capital Expenditures from Continuing Operations Exploration & Production Capital Expenditures 188,290 $ 398,174 $ 648,815 $ 693,810 $ 533,129 $ $