National Fuel Gas Company · NYSE:NFG
National Fuel Gas — Scotia Howard Weil Energy Conference 2016
62 slides from National Fuel Gas's conference presentation, Mar 21, 2016
Slide 1: Investor Presentation
Exhibit 99 Investor Presentation Scotia Howard Weil Energy Conference March 21 –23, 2016
Slide 2: Safe Harbor For Forward Looking Statements
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, objectives, goals, projections, estimates of oil and gas quantities, strat
Slide 3: National Fuel Gas Company
National Fuel Gas Company Quality Assets | Exceptional Location | Unique Integration Upstream • 2.3TcfeProvedReserves(1) • 785,000 net acres in Marcellus Shale • 3 million Bbls/year California crude oil production Midstream • $252 million adjusted EBITDA (2) • $1.2 billion midstream investments sinc
Slide 4: Integrated Vision for Long-term Growth in Appalachia
Integrated Vision for Long-term Growth in Appalachia Exploration & Production 1 Long-term, return- driven approach to developing vast acreage position 3 Gathering Northern Access projects to 2 transport 660 MDth/d of Seneca- Connecting Our operated WDA production by FY18 Production to Our Interstate
Slide 5: Integrated Upstream & Midstream Development
Integrated Upstream & Midstream Development While Seneca has consistently driven down its well costs and improved break-even economics … WDA Well Costs ($millions) WDA Clermont / Rich Valley Economics Normalized for a 8,800 ft. Lateral Length for15%IRR(1) RealizedPriceRequired Normalized for a 8,800
Slide 6: Integrated Upstream & Midstream Development
Integrated Upstream & Midstream Development … near-term commodity prices prompted modification to upstream & midstream development pace WDA Clermont /Rich Valley Economics vs. NYMEX Futures Strip 1-Rig Program/Northern Access 1-year Delay Northern Access In-Service (+490 MDth/d) Original Northern Ac
Slide 7: Consolidated Capital Expenditures
Consolidated Capital Expenditures Exercising Capital Flexibility and Discipline to Respond to Commodity Price Environment Key Capital Budget Actions $1,500 (1) Exploration & Production Segment (1) Executed “Drill-Co” JDA Gathering Segment (2) 1-rig Marcellus program Pipeline & Storage Segment (3) No
Slide 8: National Fuel is Well Positioned
National Fuel is Well Positioned Fee ownership on Marcellus acreage limits drilling commitments (& royalties) Flexibility to Just-in-time midstream development model for upstream affiliate limits risk of idle capitalandminimizescontractualcommitmentsto 3 rd party pipelines Deploy Capital Modest 1-ri
Slide 9: Appalachia Overview
Appalachia Overview Exploration & Production | Gathering | Pipeline & Storage 9
Slide 10: Significant Appalachian Acreage Position
Significant Appalachian Acreage Position Exploration & Production Appalachia Seneca Fee Seneca Lease Western Development Area (WDA) Eastern Development Area (EDA) 715,000 Acres 70,000 Acres • 153 wells able to produce 350 MMcf/d • 40-50 remaining Marcellus locations • 83 wells able to produce 255 MM
Slide 11: Marcellus Shale: Western Development Area
Marcellus Shale: Western Development Area Exploration & Production Appalachia WDA Tier 1 Acreage200,000 – Acres WDA Highlights Large drilling inventory of quality Marcellus dry gas SRC Fee Acreage o ~1,200 locations economic < $2.25/MMBtu realized SRC Lease Acreage NFG midstream infrastructure suppo
Slide 12: Seneca WDA Joint Development Agreement
Seneca WDA Joint Development Agreement Exploration & Production Appalachia On December 2, 2015, Seneca entered into an asset-level joint development agreement with IOG CRV-Marcellus Transaction Capital, LLC, an affiliate of IOG Capital, LP, and funds managed by affiliates of Fortress Investment Grou
Slide 13: Integrated WDA Development - Upstream
IntegratedWDADevelopment- Upstream Exploration & Production Appalachia Clermont/Rich Valley Development Map Clermont/Rich CRV Development Summary Valley Area • Current: 62 wells able to produce ~200 MMcf/d • 200+ MMcf/d gross firm sales in fiscal 2016 • Dropped to 1 rig in March 2016 (down from 3 Pi
Slide 14: Integrated WDA Development - Gathering
Integrated WDA DevelopmentGathering - Gathering Appalachia Gathering System Build-Out Tailored to Accommodate Seneca’s WDA Development Clermont Gathering System Map Current System In-Service • ~60 miles of pipe/13,800 HP of compression • Current Capacity: 470 MMcfper day • Interconnects with TGP 300
Slide 15: Integrated WDA Development - Interstate Pipelines
Integrated WDA DevelopmentInterstate - Pipelines Pipeline & Storage Appalachia Expanding Our Interstate Pipelines to Deliver Seneca’s WDA Production to Canada Northern Access 2015 • Customer: Seneca Resources (NFG) • In-Service: November 2015 (1) • System: NFG Supply Corp. • Capacity: 140,000 Dth pe
Slide 16: Integrated WDA Development - Interstate Pipelines (Northern Access 2016)
Integrated WDA DevelopmentInterstate - Pipelines Pipeline & Storage Appalachia Northern Access 2016 to Increase Transport Capacity out of WDA to Canada by 490,000 Dth/d by FY18 Northern Access 2016 • Customer: Seneca Resources (NFG) • In-Service: Now targeting Nov. 1, 2017 • Capacity: 490,000 Dth/d
Slide 17: Marcellus Shale: Eastern Development Area
Marcellus Shale: Eastern Development Area Exploration & Production Appalachia EDA Highlights EDA Acreage 70,000 – Acres 1 Covington & DCNR Tract 595 o Tioga County, Pa. o 92 wells(1) with 110 MMcf/d productive capacity 3 o 75 MMcf/d firm sales/FT in FY16 o NFG Covington Gathering System o Opportunit
Slide 18: Integrated EDA Development - Gathering
IntegratedEDADevelopment- Gathering Gathering Appalachia Gathering Segment Supporting Seneca’s EDA Production & Future Development Covington Gathering System • In-Service Date: November 2009 • Capital Expenditures (to date): $33 Million • Capacity: 220,000 Dth per day • Production Source: Seneca Res
Slide 19: Utica Shale Opportunities in EDA & WDA
Utica Shale Opportunities in EDA & WDA Exploration & Production Appalachia Seneca - DCNR 007 IP: 22.7 MMcf/d Shell 26.5 MMcf/d Seneca – Mt. Jewett IP: 8.9 MMcf/d Seneca – WDA 2 Utica Test Wells Planned for FY16/17 Range 59 MMcf/d Rice Seneca Horiz. CNX 42 MMcf/d 61 MMcf/d Seneca Vert. CNX Permitted
Slide 20: Pipeline & Storage: Premier Appalachian Position
Pipeline & Storage: Premier Appalachian Position Pipeline& Storage Appalachia In addition to serving our own upstream and downstream subsidiaries, NFG is uniquely positioned to expand our regional pipeline systems and provide valuable outlets forrd3party producers and shippers in Appalachia Canada &
Slide 21: Recent 3rd Party Expansions Highly Successful
rd Recent 3 Party Expansions Highly Successful Pipeline & Storage Appalachia Expansions forrd3Parties since 2010 3 rd Party Expansion Capital Cost ($MM) 1,442 MDth/d $387 million since FY2010 $72 since FY 2010 Northern Access 2012 $183 +320 MDth/d $132 Northern Access 2012 Empire & Lamont Line N Pro
Slide 22: Planned Empire System Expansion
Planned Empire System Expansion Pipeline & Storage Appalachia Empire North Expansion Project • Target In-Service: Late 2018 • System: Empire Pipeline • Target Market: o Marcellus & Utica producers in Tioga & Potter County, Pa. • Open Season Capacity: 300,000 Dth/d • Delivery Points: o 180,000 Dth/d
Slide 23: 2015 Pipeline Expansion Projects In-Service
2015 Pipeline Expansion Projects In-Service Pipeline & Storage Appalachia Westside Expansion & Modernization 2015 Completed Pipeline Expansion Projects In-Service (October 2015) • Total Cost: $86 million o Expansion: $45 million o Modernization: $41 million • Incremental Annual Revenues: $8.8 millio
Slide 24: Pipeline & Storage Customer Mix
Pipeline & Storage Customer Mix Pipeline & Storage Appalachia Contracted Transportation by Shipper Type (1) FT CapacityMarketers - FT CapacityProducers - 4.1 MMDth/d Outside End User 6% Pipeline 1% 23% 6% 77% Marketer 94% 9% Affiliated Non-Affiliated Producer Affiliated Non-Affiliated 36% FT Capacit
Slide 25: Production and Marketing
Production and Marketing Exploration & Production 25
Slide 26: Proved Reserves & Development Costs
Proved Reserves & Development Costs Production & Marketing 3,000 Natural Gas (Bcf) Crude Oil (MMbbl) 3-Year Fiscal F&D Cost(2) 2,500 (1) Years ($/Mcfe) 2,344 2008-2010 $2.37 1,914 2009-2011 $2.09 2,000 2010-2012 $1.87 1,549 2011-2013 $1.67 1,500 1,246 2012-2014 $1.38 2,142 1,683 2013-2015 $1.12 1,00
Slide 27: Seneca Production
Seneca Production Production & Marketing 200 Appalachia - Spot Exposure (1) (1) Appalachia - Firm Commitments West Coast (California) 160.5 150-180 Bcfe 157.8 Appalachia 150 Spot Sales 120.7 100 67.6 139.3 136.6 129 100.7 50 62.9 20.5 20.0 21.2 21.2 ~21 0 2012 2013 2014 2015 2016E JointDevelopmentPa
Slide 28: Significant Base of Long-Term Firm Contracts
Significant Base of Long-Term Firm Contracts Production & Marketing FY2016 to FY2017 Fiscal 2018 and beyond ~450,000 Dth/d 914,405 Dth/d 1,000 Atlantic Sunrise (Transco) Delivery Markets: Mid-Atlantic & Southeast U.S. 189,405 Dth/d 750 NorthernAccess2016(NFG(2), TransCanada& Union) 500 Delivery Mark
Slide 29: Firm Transportation Commitments
Firm Transportation Commitments Production & Marketing Production Volume Delivery Demand Charges Gas Marketing Strategy Source (Dth/d) Market ($/Dth) Northeast Supply EDA -Tioga Firm Sales Contracts Diversification County 50,000 Canada $0.49 50,000 Dth/d Project Covington & (Dawn) Dawn/NYMEX+ Tennes
Slide 30: Firm Sales Provide Market for Appalachian Production
Firm Sales Provide Market for Appalachian Production Production & Marketing Fiscal 2016 Firm Sales by Fiscal Quarter GrossContracted Volumes(Dthperday)(1) Pricing Index Key: Fixed Price ContractedIndexPriceDifferentials ($ perDth)(2) Dawn 600,000 Dominion SP NYMEX 469,698 468,098 468,098 400,000 160
Slide 31: Strong Hedge Book in Fiscal 2016 and 2017
Strong Hedge Book in Fiscal 2016 and 2017 Production & Marketing Natural Gas Swap & Fixed Physical Sales Contracts (Million MMBtu) 150 FY 2016 = 78% hedged (1) (2) at $3.53 per MMBtu 100 92.0 97.2 30.4 32.9 50 19.0 22.1 14.1 12.7 30.2 8.0 17.2 28.5 29.5 5.8 4.9 20.4 11.4 0 (2) FY 2016 FY 2017 FY 201
Slide 32: FY 2016 Production - Firm Sales & Spot Exposure
FY 2016 ProductionFirm – Sales & Spot Exposure Production & Marketing Fiscal 2016 Price Certainty 200 88.7 Bcf realizing net ~$3.25/Mcf (1) 4.9 Bcf of Additional Basis Protection (2) 1 million Bblscrude oil hedged at $87.70/Bbl(3) 150-180 Bcfe 150 ~21 Bcfe 0-30 Bcf 2.5 Bcf(4) 29.3 Bcf 100 4.9 Bcf(2)
Slide 33: Operating Costs
Operating Costs Production & Marketing Appalachia Division West Division (California) Seneca Resources Consolidated $/Mcfe $/Boe $/Mcfe LOE (Affiliated Gathering) LOE (non-Gathering) G&A Taxes & Other $1.65 $1.70 $1.63 $27.97 $0.22 $0.22 $0.20 $27.16 $1.27 $1.19 $0.11 $5.20 $5.70 $0.40 $0.42 (1) $0.
Slide 34: Appalachian Price Realizations & Margins
Appalachian Price Realizations & Margins Production & Marketing Strong hedge book,firm sales portfolio, and cost discipline generating impressive natural gas price realizations and margins in challenging commodity environment Q1 FY16 Average Natural Gas Realizations per Mcf Q1 FY16 Adjusted EBITDA p
Slide 35: California Overview
California Overview Exploration & Production 35
Slide 36: California: Stable Production; Modest Growth
California: Stable Production; Modest Growth Upstream East Coalinga Temblor Formation Primary North Lost Hills Tulare & Etchegoin Formation Primary/Steamflood North South South LostNorth Lost Sespe East Midway Midway Hills Hills Coalinga South Lost Hills Sunset Sunset Monterey Shale Primary North Mi
Slide 37: Economic Development Focused on Midway Sunset
Economic Development Focused on Midway Sunset Upstream North Midway Sunset Economics North MWSS Project IRRs at $40/Bbl (1) Sec. 17N MWSS Acreage 36% 25% NMWSS SMWSS Hoyt FY16 Budgeted D&C Portfolio South Modest near-term capital program focused on MWSS Acreage locations that earn attractive returns
Slide 38: California Average Daily Net Production
California Average Daily Net Production Upstream $35-$40 Million Annual Capital Spending Will Keep Production Flat 10,000 9,699 9,674 9,560 9,322 9,078 8,773 7,500 5,000 2,500 0 2011 2012 2013 2014 2015 2016 Forecast Fiscal Year 38
Slide 39: Strong Margins Support Significant Free Cash Flow
Strong Margins Support Significant Free Cash Flow Upstream West Division Adjusted EBITDA per(1)BOE Trailing 12-months Ended 12/31/15 Non-Steam Fuel LOE $12.74 Steam Fuel $3.37 Average Revenue for TTM 12/31/15(1) G&A $5.56 $60.84 per BOE Production & Other Taxes $2.90 DD&A Other Operating Costs $2.58
Slide 40: Downstream Overview
Downstream Overview Utility | Energy Marketing 40
Slide 41: New York & Pennsylvania Service Territories
New York & Pennsylvania Service Territories Downstream New York Total Customers (1): 526,323 ROE: 9.1% (NY PSC Rate Case Settlement, May 2014) Rate Mechanisms: o Earnings Sharing o Revenue Decoupling o Weather Normalization o Low Income Rates o Merchant FunctionCharge(UncollectiblesAdj.) o 90/10 Sha
Slide 42: Utility: Shifting Trends in Customer Usage
Utility: Shifting Trends in Customer Usage Downstream Residential Usage Industrial Usage 12-Months Ended December 31 12-Months Ended December 31 (1) Weighted Average of New York and Pennsylvania service territories (assumes normal weather). 42
Slide 43: A Proven History of Controlling Costs
A Proven History of Controlling Costs Downstream $250 All Other O&M Expenses O&M Pension Expense O&M Uncollectible Expense $200 $198 $200 $193 $179 $9 $10 $177 $178 $10 $11 $9 $6 (1) $28 $28 $20 $33 $16 $16 $150 $100 $152 $152 $163 $160 $152 $151 $50 $0 2011 2012 2013 2014 2015 12 Months Fiscal Year
Slide 44: Utility: Strong Commitment to Safety
Utility: Strong Commitment to Safety Downstream 150 Capital Expenditures for Safety Recent increase due to ~$60MM upgrade Total Capital Expenditures of the Utility’s Customer Information Systemand anticipated acceleration of pipeline replacement program 120 $95 -$105 $94.4 $88.8 90 $72.0 $58.4 $58.3
Slide 45: Consolidated Financial Overview
Consolidated Financial Overview Upstream | Midstream | Downstream 45
Slide 46: EBITDA Contribution by Segment
EBITDA Contribution by Segment Corporate $1,250 Exploration & Production Segment Gathering Segment Pipeline & Storage Segment Utility Segment $1,000 Energy Marketing & Other $953 $852 $843 $785 $750 $704 $539 $492 $422 $378 $500 $397 $64 $69 $62 $250 $161 $186 $188 $190 $137 $160 $172 $165 $164 $157
Slide 47: Capital Expenditures by Segment
Capital Expenditures by Segment Corporate $1,500 Exploration & Production Segment (1) Gathering Segment Pipeline & Storage Segment Utility Segment Energy Marketing & Other $977 $970 $1,001 $1,000 $717 $557 $603 $694 $455-$575 $500 533 $150-$200 $118 $138 $85-$95 $80 $230 $55 $140 $125-$175 $144 $56
Slide 48: Financial Position & Liquidity
Financial Position & Liquidity Corporate Debt/Adjusted EBITDA Capitalization 2.52 x 2.27 x 1.89 x 1.89 x 1.77 x 1.75 x TotalEquity TotalDebt 46% 54% 2011 2012 2013 2014 2015 TTM $3.9 Billion Total Capitalization 12-31-15 as of December 31, 2015 Fiscal Year Debt Maturity Profile ($MM) Liquidity $600
Slide 49: Dividend Track Record
Dividend Track Record Corporate $2.00 Dividend Consistency Consecutive Dividend Payments 113 Years Consecutive Dividend Increases 45 Years $1.50 CurrentAnnualized Dividend Rate$1.58per Share $1.00 Current $0.50 Dividend Yield (1) 3.1% $0.00 (1) As of March 16, 2016. Annual Rate at Fiscal Year End 49
Slide 50: The National Fuel Value Proposition
The National Fuel Value Proposition Corporate Considerable Upstream and Midstream Growth Opportunities in Appalachia Fee ownership on ~715,000 net acres in WDA = limited royalties or drilling commitments Seneca has >900,000 Dth/day of firm transportation & sales contracts by start of fiscal 2018 Sta
Slide 51: Appendix
Appendix 51
Slide 52: Total Seneca Capital Spending by Division
Total Seneca Capital Spending by Division Appendix $1,000 Appalachia (1) (2) West Coast (California) $800 $694 $603 $600 $557 $533 $400 $631 $520 $428 $500 $200 $150 -$200 $110-$150 $63 $105 $83 $57 $40-$50 $0 2012 2013 2014 2015 2016E Fiscal Year (1) FY2016 capital expenditure guidance reflects the
Slide 53: Marcellus Operated Well Results
Marcellus Operated Well Results Appendix WDA Development Wells: Producing Well Average IP Rate Average Average Treatable Area Count (MMcfd) 30-Day (MMcf/d) Lateral Length (ft) Clermont/Rich Valley (CRV) & Hemlock 56(1) 7.5 5.7 (1) 6,823’ Elk, Cameron & McKeancounties EDA Development Wells: Producing
Slide 54: Marcellus Shale Program Economics
Marcellus Shale Program Economics Appendix ~1,200 WDA Locations Economic Below $2.25/MMBtu Locations Completed NYMEX / DAWN Pricing (1) Average 15% IRR Prospect Product Remaining Lateral BTU $3.00 $2.75 $2.50 EUR (Bcf) (1) (1) (1) Realized Price to Be Drilled Length (ft) IRR % IRR % IRR % DCNR 100 D
Slide 55: Natural Gas Hedge Positions
Natural Gas Hedge Positions Appendix (Volumes in thousands MMBtu; Prices in $/MMBtu) (1) Fiscal 2016 Fiscal 2017 Fiscal 2018 Fiscal 2019 Fiscal 2020 Avg. Avg. Avg. Avg. Avg. Volume Price Volume Price Volume Price Volume Price Volume Price NYMEX Swaps 28,440 $3.92 29,530 $4.20 20,350 $3.62 11,400 $3.
Slide 56: Crude Oil Hedge Positions
Crude Oil Hedge Positions Appendix (Volumes & Prices in Bbl) (1) Fiscal 2016 Fiscal 2017 Fiscal 2018 Avg. Avg. Avg. Volume Price Volume Price Volume Price Brent Swaps 404,000 $94.63 231,000 $92.14 51,000 $91.00 NYMEX Swaps 640,000 $83.33 465,000 $66.77 24,000 $90.52 Total 1,044,000 $87.70 696,000 $7
Slide 57: Utica/Point Pleasant: EDA Opportunities
Utica/Point Pleasant: EDA Opportunities Appendix Shell: Neal Travis Peak: Currently Drilling 26.5 MMcf/d Shell: Gee DCNR Tract 001 11.2 MMcf/d Potential Future Location JKLM Pt Pleasant Test PGE DCNR 595 Vertical Tests Seneca DCNR Tract 007 Potential Future Location IP: 22.7 MMcf/d Lateral Length: 4
Slide 58: Comparable GAAP Financial Measure Slides & Reconciliations
Comparable GAAP Financial Measure Slides & Reconciliations Appendix Thispresentationcontainscertainnon-GAAPfinancialmeasures. Forpagesthat contain non-GAAPfinancial measures, pages containing the most directly comparableGAAPfinancial measuresand reconciliationsare provided in the slidesthat follow.
Slide 59: Reconciliation of Adjusted EBITDA to Consolidated Net Income
National Fuel Gas Company Appendix Reconciliation of Adjusted EBITDA to Consolidated Net Income ($ Thousands) 12-Months FY 2011 FY 2012 FY 2013 FY 2014 FY 2015 Ended 12/31/15 Total Adjusted EBITDA Exploration & Production Adjusted EBITDA $ 377,457 $ 397,129 $ 492,383 $ 539,472 $ 422,289 377,998 Pipe
Slide 60: Reconciliation of Segment Capital Expenditures
National Fuel Gas Company Appendix Reconciliation of Segment Capital Expenditures to Consolidated Capital Expenditures ($ Thousands) FY 2016 (1) FY 2011 FY 2012 FY 2013 FY 2014 FY 2015 Forecast Capital Expenditures from Continuing Operations Exploration & Production Capital Expenditures $ 648,815 $
Slide 61: Reconciliation of E&P Adjusted EBITDA by Division
National Fuel Gas Company Appendix Reconciliation of Exploration & Production Adjusted EBITDA for Appalachia and West Coast divisions to Exploration & Production Segment Net Income ($ Thousands) Three Months Ended Twelve Months Ended December 31, 2015 December 31, 2014 Appalachia West Coast Total E&
Slide 62: Reconciliation of E&P Operating Expenses by Division
National Fuel Gas Company Appendix Reconciliation of Exploration & Production Segment Operating Expenses by Division ($000s unless noted otherwise) Twelve Months Ended Twelve Months Ended September 30, 2015 September 30, 2014 Appalachia West Coast Total E&P Appalachia West Coast Total E&P Appalachia
National Fuel Gas — Scotia Howard Weil Energy Conference 2016 on 6ix