National Fuel Gas Company · NYSE:NFG
National Fuel Gas — Investor Presentation (November 2012)
54 slides from National Fuel Gas's investor presentation, Nov 27, 2012
Slide 1: National Fuel Gas Company Investor Presentation November 2012
National Fuel Gas Company Investor Presentation November 2012 Exhibit 99
Slide 2: Safe Harbor For Forward Looking Statements
2 November 2012 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 structur
Slide 3: Our Business Mix Leads to Long-Term Value Creation
November 2012 Upstream Crude Oil Upstream Natural Gas Midstream Downstream 3 National Fuel Gas Company Our Business Mix Leads to Long-Term Value Creation National Fuel Gas Supply Corporation Empire Pipeline, Inc. National Fuel Gas Midstream Corporation National Fuel Gas Distribution Corporation Nati
Slide 4: Integrated Business Mix Provides Financial Balance
4 November 2012 National Fuel Gas Company Integrated Business Mix Provides Financial Balance Note: A reconciliation of Adjusted EBITDA to Net Income as presented on the Consolidated Statement of Income and Earnings is included at the end of this presentation.
Slide 5: Integrated Businesses with Significant Marcellus Exposure
5 November 2012 National Fuel Gas Company Integrated Businesses with Significant Marcellus Exposure…
Slide 6: And Exposure to Growth from the Utica Shale
November 2012 6 National Fuel Gas Company …And Exposure to Growth from the Utica Shale
Slide 7: Capital Spending Flexibility to Maintain Financial Strength
November 2012 7 National Fuel Gas Company Capital Spending Flexibility to Maintain Financial Strength Note: A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation. (1) Does not include the $34.9 MM Seneca Resource
Slide 8: Strong Balance Sheet and Liquidity Position
November 2012 8 Shareholders’ Equity 56 % Capital Resources Total Short-Term Capacity: $1,085 Million Committed Credit Facility: $750 Million Syndicated facility extends until January 6, 2017 Uncommitted Lines of Credit: $335 Million $6.0 million of outstanding short-term notes payable to banks as o
Slide 9: Dividend Track Record
November 2012 9 Dividend Consistency National Fuel Gas Company Dividend Track Record Current Dividend Yield (1) 2.9% Consecutive Dividend Payments 110 Years Consecutive Dividend Increases 42 Years Current Annualized Dividend Rate $1.46 per Share (1) As of November 16, 2012
Slide 10: Midstream Businesses
November 2012 10 Midstream Businesses Pipeline & Storage/NFG Midstream
Slide 11: Pipeline Expansions to Transport Appalachian Production
November 2012 11 Gathering Marcellus Production Shipping Gas to Canada & Northeast Line N Corridor Expansions Midstream Businesses Pipeline Expansions to Transport Appalachian Production
Slide 12: A Closer Look at the Expansion Progress
November 2012 12 COVINGTON GATHERING SYSTEM (In-Service) TROUT RUN GATHERING SYSTEM (In-Service ) TIOGA COUNTY EXTENSION (In-Service) NORTHERN ACCESS EXPANSION (In-Service) CENTRAL TIOGA COUNTY EXTENSION (2015) LINE “N” 2012 EXPANSION (In-Service) MERCER EXPANSION PROJECT (2014) LINE “N” 2013 EXPANS
Slide 13: Pursuing Additional Opportunities Near the Line N Corridor
November 2012 13 Midstream Businesses Pursuing Additional Opportunities Near the Line N Corridor Activity along the Pennsylvania/Ohio border continues to remain robust and is shifting north as the Utica begins to be delineated National Fuel’s Line N system is well- positioned to expand in conjunctio
Slide 14: Using a History of Excellence to Serve Appalachian Producers
November 2012 14 NFG Midstream Midstream’s gathering systems are critical to unlock remote, but highly productive Marcellus acreage History of operational success and efficiency within Pennsylvania Current focus is on developing and expanding gathering infrastructure for both Seneca and other produc
Slide 15: Utility
November 2012 15 Utility
Slide 16: Providing Financial Stability
November 2012 16 Rate Mechanisms Low Income Rates Choice Program/POR Merchant Function Charge Revenue Decoupling 90/10 Sharing Weather Normalization Utility Providing Financial Stability New York & Pennsylvania New York only 9.8% 10.6% 10.5% 12.6% 13.2% 14.7% 18.8% 12.5% 0.0% 10.0% 20.0% 30.0% 2009
Slide 17: Continued Cost Control Helps Provide Earnings Stability
November 2012 17 $178 $164 $167 $168 $168 Utility Continued Cost Control Helps Provide Earnings Stability Low natural gas prices, combined with a focus on cost control, continue to help reduce expenses $25 $27 $14 $11 $9 $203 $191 $181 $179 $177 $0 $50 $100 $150 $200 $250 2008 2009 2010 2011 2012 Fi
Slide 18: Strong Commitment to Safety
November 2012 18 Utility Strong Commitment to Safety The anticipated increase in 2013 capital expenditures is largely due to the implementation of a new Customer Information System The Utility remains focused on consistent spending to maintain the ongoing safety and reliability of its system $45.1 $
Slide 19: Exploration & Production
November 2012 19 Exploration & Production
Slide 20: Remaining Strategically Opportunistic in Fiscal 2013
November 2012 20 Marcellus Shale Utica Shale California Oil Mississippian Lime Seneca Resources Remaining Strategically Opportunistic in Fiscal 2013 presentation. Seneca’s acreage position and operational strategy allows the flexibility to ramp up, pull back, or redirect its spending according to it
Slide 21: Another Strong Year of Reserve Growth
November 2012 21 47.6 46.2 46.6 45.2 43.3 226 249 428 675 988 Fiscal Years 3-Year F&D Cost (1) ($/Mcfe) Seneca Resources Another Strong Year of Reserve Growth Seneca has more than doubled its proved reserves since 2009, while maintaining a relatively high percentage of proved developed reserves (67%
Slide 22: Increased Oil Spending and Tempered Marcellus Spending
November 2012 22 Seneca Resources Increased Oil Spending and Tempered Marcellus Spending (1) Does not include the $34.9 MM acquisition of Ivanhoe’s U.S.-based assets in California, as this was accounted for as an investment in subsidiaries on the Statement of Cash Flows, and was not included in Capi
Slide 23: Production Still Growing
November 2012 23 Seneca Resources Production Still Growing
Slide 24: Continuing to Focus on Improving Its Cost Structure
November 2012 24 Seneca Resources Continuing to Focus on Improving Its Cost Structure Even after the new Pennsylvania Impact Fee, 2012 unit cash costs decreased from the prior year. We expect this trend to continue in Fiscal 2013. (1) Represents the midpoint of current General & Administrative Expen
Slide 25: Stable Production and Increasing Cash Flows
November 2012 25 Rank Company California 2011 BOEPD 7 Seneca Resources 9,209 California Stable Production and Increasing Cash Flows Net Acreage: 11,833 Acres Net Wells: 1,322 Oil Gravity: 12 – 37° Api NRI: 87.64 Occidental 164,796 Chevron 163,153 Aera (Shell/Exxon) 149,974 Plains Exploration 36,775
Slide 26: Stable Production Fields
November 2012 26 South Lost Hills ~1,600 BOEPD Monterey Shale Primary 219 Active Wells Sespe ~1,200 BOEPD Sespe Formation Primary 172 Active Wells North Lost Hills ~1,200 BOEPD Tulare & Etchegoin Formation Primary & Steamflood 175 Active Wells North Midway Sunset ~4,300 BOEPD Potter & Tulare Formati
Slide 27: Strong Margins Support Significant Free Cash Flow
November 2012 27 California Strong Margins Support Significant Free Cash Flow Average Revenue In Fiscal 2012 $85.16 per BOE $9.09 $2.82 $2.74 $2.46 $1.08 Non- Steam Fuel LOE Steam Fuel G&A Production & Other Taxes Other Operating Costs Adjusted EBITDA Fiscal Year 2012 Adjusted EBITDA per BOE $70.86
Slide 28: California – Recent Initiatives Driving Near-Term Growth
November 2012 28 Seneca Resources California – Recent Initiatives Driving Near-Term Growth Key Areas of Focus in 2013 6,500 7,000 7,500 8,000 8,500 9,000 9,500 10,000 6,000 Actual Forecast 1. North Midway Sunset Steaming 2. South Midway Sunset Field Extensions 3. Sespe Infill Drill Program
Slide 29: Midway Sunset South Activity Update
November 2012 29 Midway Sunset South Activity Update Seneca Resources 500’ 2012 Drill Program: 21 Wells / 3 Injectors 2013 Drill Program: 17 - Wells / - Injectors 0 ft 50 ft 100 ft 100 ft 50 ft 50 ft Antelope “A-1” and “A-2” Sands Antelope “B” and “C” Sands Antelope “A-1” Sand Seneca 232M Extended 2
Slide 30: Sespe Field – 2011 & 2012 Drilling Programs and Results
November 2012 30 WS 48-33 80 BOEPD Oil 09/12 “X” SANDS ISOCHORE (Thickness) Seneca Resources Sespe Field – 2011 & 2012 Drilling Programs and Results 2011 Sespe Wells (5) 2012 Sespe Wells (6) Oak Flat 1-31 110 BOEPD 1 Oil 08/12 FA 502-33 Completing 1 Oil 12/12 FA 501-33 Completing 1 Oil 12/12 Oak Fla
Slide 31: Monterey Shale Play
31 Producing (Gross): 65 BOEPD 5 Delineation Wells Planned AMI Outlines November 2012 Seneca Resources Monterey Shale Play Monterey Shale Play Belridge Field 5 AMIs across the field Seneca WI: 12.5% Seneca NRI: 11.4% Gross Thickness of Monterey Interval Drilling/Drilled Planned
Slide 32: Expansive Pennsylvania Acreage Position
November 2012 32 Seneca Resources Expansive Pennsylvania Acreage Position SRC Lease Acreage SRC Fee Acreage NFG Storage Acreage Western Development Area Net acreage: ~720,000 acres Own most mineral rights Minimal royalty obligation Minimal lease expiration Evaluating Marcellus rich-gas and Utica Sha
Slide 33: Net Rig Count (Working Interest)
November 2012 33 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 Seneca Resources Net Rig Count (Working Interest) Seneca anticipates minimal joint venture activity in fiscal 2013 7.5 5.5 4.5 2.5 3.0 Fiscal 2012 - Q1 Fiscal 2012 - Q2 Fiscal 2012 - Q3 Fiscal 2012 - Q4 Fiscal 2013 Forecast Seneca
Slide 34: Eastern Development Area (EDA) – Results & Plan Forward
November 2012 34 Covington – Fully Developed 47 Wells Drilled and Producing Gross Production: ~75 MMcf per Day Seneca Resources Eastern Development Area (EDA) – Results & Plan Forward DCNR Tract 595 Gross Production: ~70 MMcf per Day 34 Wells Drilled 19 Wells Producing DCNR Tract 100 Area IPs: 10.5
Slide 35: Lycoming and Tioga Counties Are Highly Productive Areas
November 2012 35 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) Seneca Resources Lycoming and Tioga Counties Are Highly Productive Areas Covington (Tioga
Slide 36: Ramping Marcellus Shale Production
November 2012 36 Seneca Resources Ramping Marcellus Shale Production Forecast WDA/Other EOG JV Lycoming DCNR 595 Covington
Slide 37: Delineating the Western Development Area
November 2012 37 Owl’s Nest (2 Wells) Church Run (1 Well) Currently Drilling Ridgway (1 Well) Rich Valley (1 Well) Peak IP: 6.3 MMcf per Day Estimated EUR: 6.4 Bcf Seneca Resources Delineating the Western Development Area BTU Contours Proposed Hz Well SRC Fee Acreage SRC Lease Acreage
Slide 38: Utica Shale – Activity Summary
November 2012 Wet Dry 38 Seneca Resources Utica Shale – Activity Summary Permitted Well Drilled Well Completed Well Mt. Jewett Vertical: Tested Dry Gas Horizontal: Completing Fall 2012 Henderson Vertical Well: Tested Horizontal: FY2013 Tionesta Horizontal: Completed Fall 2012 Peak 24-Hour Rate: 3.9
Slide 39: Initial Entry into the Mississippian Lime Play in Kansas
November 2012 39 Seneca Resources Initial Entry into the Mississippian Lime Play in Kansas The initial entry into the Mississippian Lime play furthers the Company’s goal of maintaining a significant contribution from oil-producing properties 100% working interest in 4,600 gross acres 25% net working
Slide 40: Appendix
November 2012 40 National Fuel Gas Company Appendix
Slide 41: Fiscal Year 2013 Earnings Guidance Drivers
November 2012 41 2013 Forecast National Fuel Gas Company Fiscal Year 2013 Earnings Guidance Drivers GAAP Earnings per Share $2.65 - $2.95 Exploration & Production Drivers Total Production (Bcfe) 95 - DD&A Expense $2.10 - $2.25 LOE Expense $0.90 - $1.10 G&A Expense $58 - $62 MM Pipeline & Storage Dri
Slide 42: Manageable Debt Maturity Schedule
November 2012 42 National Fuel Gas Company Manageable Debt Maturity Schedule The Company is planning a new long-term debt issuance in fiscal 2013, likely totaling $350 million, to refinance maturing long- term and outstanding short-term debt $250 $300 $250 $500 $49 $50 7.395% 7.375% $0 $100 $200 $30
Slide 43: Targeted Capital Structure
November 2012 43 40% 30% 50% 50% 60% 70% 50% 50% Debt 35% - 45% Equity 55% - 65% National Fuel Gas Company Targeted Capital Structure Long-Term Consolidated Capital Structure Target Capital Structure Targets by Segment All Other E&P P&S Utility Debt Equity
Slide 44: Pipeline & Storage / Midstream Appendix
44 November 2012 Pipeline & Storage / Midstream Appendix
Slide 45: Pipeline & Storage Expansion Initiatives
November 2012 45 Project Name Capacity (Dth/D) Est. CapEx In-Service Market Status Pipeline & Storage Expansion Initiatives Lamont Compressor Station 40,000 $6 MM 6/2010 Fully Subscribed Completed Lamont Phase II Project 50,000 $8 MM 7/2011 Fully Subscribed Completed Line “N” Expansion 160,000 $22 M
Slide 46: Midstream Corporation Expansion Initiatives
November 2012 46 Project Name Capacity (Mcf/D) Est. CapEx In-Service Date Market Comments Midstream Corporation Expansion Initiatives Covington Gathering System 220,000 $40 MM Multiple Phases - Most In-Service Capacity Available [Marketing to Third Parties] Completed – Flowing into TGP 300 Line. Thi
Slide 47: Exploration & Production Appendix
November 2012 47 Exploration & Production Appendix
Slide 48: Hedge Positions and Strategy
November 2012 48 Natural Gas Swaps Volume (Bcf) Average Hedge Price Oil Swaps Volume (MMBbl) Average Hedge Price National Fuel Gas Company Hedge Positions and Strategy Fiscal 2013 50.2 $4.76 / Mcf Fiscal 2014 30.4 $4.26 / Mcf Fiscal 2015 18.1 $4.07 / Mcf Fiscal 2016 17.9 $4.07 / Mcf Fiscal 2017 17.9
Slide 49: Targeting Continued Cost Reductions
November 2012 49 Marcellus Shale Targeting Continued Cost Reductions $200 $300 $400 $500 $600 $700 $800 2010 2011 2012 2013 Target Drilling Cost per Lateral Foot WDA/DCNR 595 DCNR 100 $100 $150 $200 $250 $300 $350 $400 2010 2011 2012 2013 Target Completion Cost per Stage ($000) WDA/DCNR 595 DCNR 100
Slide 50: Water Management Program
November 2012 50 Marcellus Shale Water Management Program Water Sourcing: Coal mine runoff Permitted freshwater sources Recycled water Water Management: Instituted a “Zero Surface Discharge” policy Recycle Marcellus flowback and produced water Centralized water handling in development areas Tioga Co
Slide 51: Comparable GAAP Financial Measure Slides and Reconciliations
November 2012 51 National Fuel Gas Company Comparable GAAP Financial Measure Slides and Reconciliations This presentation contains certain non-GAAP financial measures. For pages that contain non-GAAP financial measures, pages containing the most directly comparable GAAP financial measures and reconc
Slide 52: Reconciliation of Segment Capital Expenditures to Consolidated Capital Expenditures
November 2012 52 Reconciliation of Segment Capital Expenditures to Consolidated Capital Expenditures ($ Thousands) FY 2013 FY 2009 FY 2010 FY 2011 FY 2012 Forecast Capital Expenditures from Continuing Operations Exploration & Production Capital Expenditures 188,290 $ 398,174 $ 648,815 $ 693,810 $ $4
Slide 53: Reconciliation of E&P West Division Adjusted EBITDA to Segment Net Income
November 2012 53 Reconciliation of Exploration & Production West Division Adjusted EBITDA to Exploration & Production Segment Net Income ($ Thousands) 12 Months Ended September 30, 2012 Exploration & Production - West Division Adjusted EBITDA 226,897 $ Exploration & Production - All Other Divisions
Slide 54: Reconciliation of Adjusted EBITDA to Consolidated Net Income
November 2012 54 Reconciliation of Adjusted EBITDA to Consolidated Net Income ($ Thousands) FY 2008 FY 2009 FY 2010 FY 2011 FY 2012 Exploration & Production - West Division Adjusted EBITDA 188,008 $ 170,611 $ 187,838 $ 187,603 $ 226,897 $ Exploration & Production - All Other Divisions Adjusted EBITD
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