National Fuel Gas Company · NYSE:NFG
National Fuel Gas — Q3 FY2016 Earnings Presentation
58 slides from National Fuel Gas's earnings presentation, Aug 4, 2016
Slide 1: Investor Presentation Q3 Fiscal 2016 Update
Exhibit 99 Investor Presentation Q3 Fiscal 2016 Update August 2016
Slide 2: Safe Harbor For Forward Looking Statements
Safe Harbor For Forward Looking Statements Thispresentationmay contain“forward-looking statements”as definedby the PrivateSecuritiesLitigationReformActof 1995,includingstatementsregardingfuture prospects, plans,objectives,goals,projections, estimatesof oil andgasquantities,strategies,futureeventsor
Slide 3: National Fuel Gas Company
National Fuel Gas Company Quality Assets | Exceptional Location | Unique Integration Upstream • 2.3 TcfeProved Reserves (1) • 785,000 net acres in Marcellus Shale • 3 million Bbls/year of crude oil production in California Midstream • $267 million annual adjusted EBITDA (2) • $1.2 billion midstream
Slide 4: Integrated Vision for Long-term Growth in Appalachia
Integrated Vision for Long-term Growth in Appalachia Exploration & Production 1 Long-term, return- driven approach to developing vast Marcellus & Utica acreage position 3 Gathering Northern Access projects to 2 transport 660 MDth/d of Seneca- Connecting Our operated WDA production by FY18 Production
Slide 5: FY 2017 Capital Budget and Operating Plan
FY 2017 Capital Budget and Operating Plan Capital Expenditures by Segment ($MM) FY2017 Operating Plan Highlights Upstream $1,500 (1) Exploration & Production Segment Gathering Segment Appalachia: 1-rig program / daylight-only frac crew Pipeline & Storage Segment FY17 development pace is designed to
Slide 6: The National Fuel Value Proposition
The National Fuel Value Proposition Corporate Creating long-term sustainable value remains our #1 shareholder priority 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
Slide 7: Appalachia Overview
Appalachia Overview Exploration & Production | Gathering | Pipeline & Storage 7
Slide 8: Significant Appalachian Acreage Position
Significant Appalachian Acreage Position Exploration & Production Appalachia Eastern Development Area (EDA) Western Development Area (WDA) 70,000 Acres 715,000 Acres • 153 wells able to produce 280 MMcf/d • 50-60 remaining Marcellus locations • Additional strong Utica & Geneseo potential • 125 wells
Slide 9: 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 o ~1,100 locations economic < $2.00/MMBtu realized NFG midstream infrastructure supporting growth o NFG Clermont Gather
Slide 10: Seneca WDA Joint Development Agreement
Seneca WDA Joint Development Agreement Exploration & Production Appalachia On June 13, 2016, Seneca announced the extension of asset-level joint development agreement with IOG CRV - Transaction Marcellus Capital, LLC, an affiliate of IOG Capital, LP, and funds managed by affiliates of Fortress Inves
Slide 11: Integrated WDA Development - Upstream
IntegratedWDADevelopment- Upstream Exploration & Production Appalachia Clermont/Rich Valley Development Map CRV Development Summary • Current: 103 wells able to produce ~280 MMcf/d • Dropped to 1 rig in March 2016 (down from 3 rigs to start fiscal 2016) • Just-in-time gathering infrastructure build-
Slide 12: Best in Class Marcellus Well Costs
Best in Class Marcellus Well Costs Exploration & Production Appalachia WDA Acreage Position & Operational Efficiencies Driving Best-in-Class Well Costs in Marcellus Marcellus Drilling Cost per Foot Marcellus Completion Cost per Stage ($000s) $300 $275 $300 $248 $208 $200 $174 $200 $153 $148 $120 $10
Slide 13: Integrated WDA Development - Gathering
IntegratedWDADevelopment- Gathering Gathering Appalachia Gathering System Build-Out Tailored to Accommodate Seneca’s WDA Development Clermont Gathering System Map Current System In-Service • ~67 miles of pipe/26,220 HP of compression • Current Capacity: 470 MMcfper day • Interconnects with TGP 300 •
Slide 14: 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) Niagara • System: NFG Supply Corp. • Capacity: 140,00
Slide 15: 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 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 Chippawa •
Slide 16: 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 (Tioga) o Marcellus locations fully developed o 92 wells(1) with 90 MMcf/d productive capacity 3 o 70-80 MDth/d firm sales in FY17 o NFG Covington Gath
Slide 17: 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): $33 Million • Capacity: 220,000 Dth per day • ProductionSource:SenecaResour
Slide 18: Utica Shale Opportunities in WDA
Utica Shale Opportunities in WDA Exploration & Production Appalachia st 1 Clermont Rich Valley Utica Well Test On Trend with Northeast Pa. Results CRV Utica Test Well Results st Seneca tested 1Utica well off 10-well Marcellus Northeast Pa. Utica Well Results pad in Clermont Rich Valley in June 2016:
Slide 19: Recent 3rd Party Expansions Highly Successful
rd Recent 3 Party Expansions Highly Successful Pipeline & Storage Appalachia rd rd Expansions for 3 Parties since 2010 3 Party Expansion Capital Cost ($MM) 1,442 MDth/d $387 million $72 since FY 2010 Northern since FY2010 Access 2012 $183 +320 MDth/d $132 Northern Access 2012 Empire & Lamont Line N
Slide 20: Planned Empire System Expansion
Planned Empire System Expansion Pipeline & Storage Appalachia Providing Optionality for Northeast Pennsylvania Producers Empire North Expansion Project • Target In-Service: Fiscal 2019 • System: EmpirePipeline • Target Market: o Marcellus & Utica producers in Tioga & Potter County, Pa. • Open Season
Slide 21: 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: $82.3 million o Expansion: $43.3 million o Modernization: $39 million • Incremental Annual Revenues: $8.8 mi
Slide 22: Pipeline & Storage Customer Mix
Pipeline & Storage Customer Mix Pipeline & Storage Appalachia Contracted Transportation FT CapacityMarketers - by Shipper Type (1) FT CapacityProducers - 4.1 MMDth/d Outside End User 6% 23% Pipeline 1% 6% 77% Marketer 94% 9% Affiliated Non-Affiliated Producer Affiliated Non-Affiliated 36% FT Capacit
Slide 23: Production and Marketing
Production and Marketing Exploration & Production 23
Slide 24: Proved Reserves & Development Costs
Proved Reserves & Development Costs Production & Marketing 3,000 Natural Gas (Bcf) Crude Oil (MMbbl) 3-Year Fiscal F&D Cost(2) (1) Years ($/Mcfe) 2,500 2,344 2008-2010 $2.37 2,000 1,914 2009-2011 $2.09 2010-2012 $1.87 1,549 2011-2013 $1.67 1,500 1,246 2012-2014 $1.38 2,142 1,683 2013-2015 $1.12 1,00
Slide 25: Seneca Production
Seneca Production Production & Marketing Seneca Resources Net Production (Bcfe) JDA tempers net production growth in FY17 250 (1) Appalachia Gross production expected to grow ~10% Growth is largely being generated from joint West Coast (California) development wells where Seneca has 26% NRI, resulti
Slide 26: Significant Base of Long-Term Firm Contracts
Significant Base of Long-Term Firm Contracts Production & Marketing FY 2016 to FY2017 Fiscal 2018 and beyond 465,000+ Dth/d 914,405 Dth/d 1,000 Atlantic Sunrise (Transco) Delivery Markets: Mid-Atlantic & Southeast U.S. 750 189,405 Dth/d Northern Access 2016 (NFG(2), TransCanada & Union) Delivery Mar
Slide 27: Firm Transportation Commitments
Firm Transportation Commitments Production & Marketing Production Volume Delivery Demand Charges Gas Marketing Strategy Source (Dth/d) Market ($/Dth) Northeast Supply EDA -Tioga Firm Sales Contracts Diversification County 50,000 Canada $0.50 50,000 Dth/d rd Project Covington & (Dawn) (3 party) Dawn/
Slide 28: Firm Sales Provide Market for Appalachian Production
Firm Sales Provide Market for Appalachian Production Production & Marketing FY 2016 and FY 2017 Net Firm Sales by Fiscal Quarter Pricing Index Key: Fixed Price Net Contracted Volumes (Dth per day) Dawn ContractedIndexPriceDifferentials ($ perDth)(1) DOM SP / TGPL NYMEX 395,500 396,000 384,000 379,50
Slide 29: 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) 150.0 124.3 Remaining FY 2016 Natural Gas Production 90% hedged(1) at $3.31 per MMBtu Fiscal 2017 Natural Gas Production 100.0 59.9 83% hedged (1) at $3.27 per MMBtu 22.
Slide 30: Fiscal 2017 Production and Price Certainty
Fiscal 2017 Production and Price Certainty Production & Marketing Remaining Fiscal 2016 Production Fiscal 2017 Production Remaining FY16 Natural Gas Price Certainty FY17 Natural Gas Price Certainty (1) (1) 34 Bcf realizing net ~$3.10/Mcf 120 Bcf realizing net ~$3.05/Mcf 12.5 Bcf of Additional Basis
Slide 31: Operating Costs
Operating Costs Production & Marketing Appalachia LOE & Gathering California LOE Seneca Resources Consolidated $/Mcfe $/Boe $/Mcfe $1.70 $1.55 $1.58 $0.81 $17.88 $0.22 $0.73 $0.72 $0.20 $0.20 $16.17 $15.06 $0.42 $0.25 $0.14 $0.11 (1) $0.38 $0.38 (1) (2) $17.88 $0.57 $0.43 $0.40(2) $16.17 $15.06 $0.5
Slide 32: California Overview
California Overview Exploration & Production 32
Slide 33: California
California Upstream Stable Oil Production | Minimal Capital Investment | Free Cash Flow Positive East Coalinga 6,000 FY 2010 Temblor Formation FY 2015 Primary 4,500 3,000 North Lost Hills Tulare & Etchegoin Formation 1,500 Primary/Steamflood 0 North South South LostNorth Lost Sespe East South Lost H
Slide 34: Economic Development Focused on Midway Sunset
Economic Development Focused on Midway Sunset Upstream North Midway Sunset Economics North MWSS Project IRRs at $50/Bbl (1) Sec. 17N MWSS Acreage 49% 37% ~30% NMWSS SMWSS Farm-in Projects Hoyt FY16 Budgeted D&C Portfolio South Modest near-term capital program focused on MWSS Acreage locations that e
Slide 35: California Average Daily Net Production
California Average Daily Net Production Upstream $35-$45 Million Annual Capital Spending Expected to Keep CA Production Flat 10,000 9,699 9,674 9,400 9,600 9,322 9,078 7,500 5,000 2,500 0 2012 2013 2014 2015 2016 2017 Fiscal Year Forecast Forecast 35
Slide 36: Strong Margins Support Significant Free Cash Flow
Strong Margins Support Significant Free Cash Flow Upstream (1) West Division Adjusted EBITDA per BOE Trailing 12-months Ended 6/30/16 Non-Steam Fuel LOE $11.79 Steam Fuel $3.19 California Margins (per BOE) Average Revenue $ 54.81 G&A $4.91 Less: Cash Costs $ 24.37 = Adjusted EBITDA $ 30.44 Productio
Slide 37: Downstream Overview
d National Fuel Downstream Overview Utility | Energy Marketing 37
Slide 38: 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 Function Charge (Uncollectibles Adj.) o 90/10
Slide 39: New York Rate Case
New York Rate Case Downstream On April 28, 2016, National Fuel Gas Distribution Corporation filed a request with the New York Background Public Service Commission (NY PSC) to amend its tariff and increase its base rates. National Fuel’s base rates have not changed since the last base rate case was l
Slide 40: Utility: Shifting Trends in Customer Usage
Utility: Shifting Trends in Customer Usage Downstream Residential Usage Industrial Usage 120 40 110 35 100 30 90 25 80 20 12-Months Ended June 30 12-Months Ended June 30 (1) Weighted Average of New York and Pennsylvania service territories (assumes normal weather). 40
Slide 41: 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 $195 $200 $193 $179 $9 $7 $177 $178 $10 $11 $9 $6 (1) $28 $24 $20 $33 $16 $16 $150 $100 $152 $152 $163 $164 $152 $151 $50 $0 2011 2012 2013 2014 2015 12 Months Fiscal Year
Slide 42: Utility: Strong Commitment to Safety
Utility: Strong Commitment to Safety Downstream $150.0 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 $120.0 $94.4 $90-$100 $90-$100 $88.8 $90.0
Slide 43: Consolidated Financial Overview
Consolidated Financial Overview Upstream | Midstream | Downstream 43
Slide 44: 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 $725-$835 $717 $557 $160-$200 $603 $694 $75-$85 $500 $390-$440 533 $118 $120-$135 $138 $400-$450 $80 $55
Slide 45: 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 $772 $750 $704 $539 $492 $422 $366 $500 $397 $64 $69 $74 $250 $161 $186 $188 $193 $137 $160 $172 $165 $164 $142
Slide 46: Financial Position & Liquidity
Financial Position & Liquidity Corporate Debt/Adjusted EBITDA Capitalization 2.72 x 2.27 x 1.89 x 1.89 x 1.77 x TotalEquity TotalDebt 42% 58% $3.6 Billion Total Capitalization 2012 2013 2014 2015 TTM as of June 30, 2016 Fiscal Year 06-30-16 Debt Maturity Profile ($MM) Liquidity $600 $500 $549 $500 C
Slide 47: Dividend Track Record
Dividend Track Record $2.00 Dividend Consistency Consecutive Dividend Payments 114 Years Consecutive Dividend Increases 46 Years $1.50 CurrentAnnualized Dividend Rate$1.62per Share $1.00 Current $0.50 Dividend Yield (1) 2.9% $0.00 (1) As of August 3, 2016. 47
Slide 48: Appendix
Appendix 48
Slide 49: Total Seneca Capital Spending by Division
Total Seneca Capital Spending by Division Appendix $800 Appalachia(1) (2) West Coast (California) $694 $603 $600 $557 $533 $400 $631 $520 $428 $500 $200 $160-$200 $120-$135 $125-$155 $85-$100 $105 $83 $63 $57 ~$35 $35-$45 $0 2012 2013 2014 2015 2016E 2017E Fiscal Year (1) FY2016 and FY 2017 capital
Slide 50: 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 100(1) 6.9 5.2 (1) 7,045’ Elk, Cameron & McKeancounties EDA Development Wells: Producin
Slide 51: Marcellus Shale Program Economics
Marcellus Shale Program Economics Appendix ~1,100 WDA Locations Economic Below $2.00/MMBtu NYMEX / DAWN Pricing Net Realized Locations Completed (2) Anticipated Average Price Prospect Product Remaining Lateral $3.00 $2.75 $2.50 Delivery EUR (Bcf) Required for to Be Drilled Length (ft) IRR % (1) IRR
Slide 52: 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 9,930 $3.96 35,710 $4.29 26,070 $3.49 25,560 $3.1
Slide 53: 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 51,000 $94.06 123,000 $92.27 24,000 $91.00 NYMEX Swaps 432,000 $73.82 885,000 $64.17 207,000 $62.27 Total 483,000 $75.96 1,008,000 $6
Slide 54: Comparable GAAP Financial Measure Slides & Reconciliations
Comparable GAAP Financial Measure Slides & Reconciliations Appendix Thispresentationcontainscertainnon-GAAPfinancialmeasures. Forpagesthat contain non-GAAPfinancial measures, pages containing the most directly comparableGAAPfinancial measuresand reconciliationsare provided in the slidesthat follow.
Slide 55: Reconciliation of Adjusted EBITDA to Consolidated Net Income
National Fuel Gas Company Appendix Reconciliation of Adjusted EBITDA to Consolidated Net Income ($ Thousands) 12-Months FY 2012 FY 2013 FY 2014 FY 2015 Ended 6/30/16 Total Adjusted EBITDA Exploration & Production Adjusted EBITDA $ 397,129 $ 492,383 $ 539,472 $ 422,289 366,255 Pipeline & Storage Adju
Slide 56: Reconciliation of Segment Capital Expenditures to Consolidated Capital Expenditures
National Fuel Gas Company Appendix Reconciliation of Segment Capital Expenditures to Consolidated Capital Expenditures ($ Thousands) FY 2016 FY 2017 FY 2012 FY 2013 FY 2014 FY 2015 Forecast Forecast Capital Expenditures from Continuing Operations (1) Exploration & Production Capital Expenditures $ 6
Slide 57: Reconciliation of E&P Adjusted EBITDA for Appalachia and West Coast
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 June 30, 2016 June 30, 2016 Appalachia West Coast Total E&P Appala
Slide 58: Reconciliation of E&P Segment 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