National Fuel Gas Company · NYSE:NFG
National Fuel Gas — Q4 FY2016 Earnings Presentation
58 slides from National Fuel Gas's earnings presentation, Nov 3, 2016
Slide 1: Investor Update Fiscal 2016 Q4
Exhibit 99 Investor 1Q4 FiscalPresentation 2016 Update November 3, 2016
Slide 2: Safe Harbor for Forward-Looking Statements
Safe This Reform “estimates,” those“may,” expressed looking of orders environmental/safety ofunder conditions; viable need otherchanges involvingchanges locations, hydrocarbon or changes services; infestation; operatingbenefits, care coverage reserves oil realized. “Risk 10-Q statements regulatory o
Slide 3: Quality Assets, Exceptional Location
Quality 1.8 Upstream 785,000 $278 Midstream 740,000 Downstream (1) presented Total Tcfe million Assets—Exceptional Proved net Utility proved onacres the annual customer Reserves reserves Consolidated in Appalachia—mostly adjusted are accounts (1) as Location—Unique EBITDA Statement of September Stab
Slide 4: Creating Long-Term Value Proposition
The ownership Considerable Fee Geneseo Unique growth Geographical Investment Disciplined Capital Strong 4Creating National hedge allocation Asset shales long-term, grade Approach Fuel Upstream book Mix and on across credit operational that ~715,000 Value and helps sustainable To is Marcellus Integra
Slide 5: Balanced Adjusted EBITDA by Segment
Balanced Adjusted Exploration Gathering $1,500 Pipeline Utility Energy $1,000 $852 $492 $539 $704 $789 $500 $64 $137 15 30 $160 2012 $0 Fiscal Note:$69 $843 $422 $397 $161 $172 2013 A Year Segment $953 Marketing reconciliation $79 &EBITDA Earnings Segment $364 $186 $165 2014 Storage & Production $18
Slide 6: Capital Expenditure Flexibility
Flexibility Capital $1,500 CapEx Gathering Pipeline Utility Energy $1,001 $65—$75 $80 $58 Fiscal (1) 6the presentation. FY netting $54 $72 Year Segment 2016 Reconciliation Exploration Net Marketing Expenditures $230 $89 &Segment $500 to of Storage CapEx actual $94 Responsibly anticipated $144 $533 G
Slide 7: Strong Balance Sheet and Liquidity
Strong Debt/Adjusted 2.66 2.27 1.89 1.77 42% $3.6 58% 2012 Fiscal Debt $600 $500 $400 $250 $300 Cash $200 $0 7N ote: Total xTotal Billion Maturity Available 2013 $549 $500 Short-term Balance AYear 1.89 Balance reconciliation Liquidity Debt 2014 Committed End xTotal Total atProfile EBITDA Short-term
Slide 8: Dividend Consecutive Payments
Dividend 114 $2.00 46 Consecutive $1.50 Payments $1.00 Increases $1.62 Current $0.50 Rate Yield 3.1% Annual $0.00 (1) Years As Years (1) per ofRate Dividend Dividend November Track Share at Fiscal Record Rate 2,Year ($ 2016. /share) End 8 NFG’s Dividend Consistency
Slide 9: FY2017 Capital Expenditure Forecast
Capital Exploration Gathering Pipeline $725—$835 Utility available $750 $180—$220 $65—$75 $99 $98 $0 FY Forecast (1) the presentation. Downstream FY netting 2017 2016 $390—$440 $90—$100 Energy Segment 2016 Expenditures & miles Capital FY by Segment $500 of Storage & the actual 2017 Development Flexi
Slide 10: Appalachia Overview
Appalachia Overview Exploration 10 & Production ~ Gathering ~ Pipeline & Storage
Slide 11: Integrated Appalachian Growth Vision
Integrated Exploration Long-term, 2Gathering Production Just-in-time 3E 200,000 11xpanding Northern “Tier 3Vision Access Our to return-driven & build-out Our 1” Production Interstate fee-held for Interstate projects Long-term of Clermont approach 1acres 1toPipeline transport in Growth Pa. Gathering
Slide 12: Significant Upstream Acreage Position
Significant Upstream Western Lease 139 Highly Eastern 153 potential 12 wells Acreage contiguous Development Development Limited able Appalachian to produce development nature Area Area Acreage drives 290 270 (EDA) (WDA) MMcf/d drilling cost Position Fee and until EDA—70,000 Mostly Acreage operationa
Slide 13: Marcellus Upstream Highlights and Economics
Marcellus Upstream Rich Clermont/ Ridgway Hemlock Large ~1,100 Fee No Highly Multi-well Water NFG Early Will WDA Avg EUR Locations 47- 2Hemlock/Ridgway (1) 13-9.5 46Internal royalty lease acreage Avg have BCF/well Valley Color midstream Clermont Northern Utica drilling Tier Highlights BCF/well manag
Slide 14: WDA Development Summary
WDA Upstream CRV 117 joint program 14 wells development Development Clermont Regional able to/ produce Rich focus partner Summary Valley of~280 (IOG) development Development MMcf/d 63 wellsDropped minimizes drilled 50 tocapital wells 1 rig in online outlay March / and producing 2016 improves Just-in
Slide 15: Upstream Joint Development Agreement
Upstream On Fortress Key Assets: Initial Locations Remaining Validates December hurdle. Seneca Working expansion of (1)firm Estimated June Terms 39 transportation. Seneca WDA IOG 75 Investment 13, Interest wells—$170 quality Developed projects 31, current of 36 Locations 2016, Midstream’s Joint redu
Slide 16: EDA Upstream Highlights
Marcellus Upstream •321EDA (1) 16 Atlantic Marcellus 92 70-80 Opportunity 61 115-160 55 Production 1Geneseo Expected Utica Covington DCNR Utica One wells(1) remaining Highlights well Resource MDth/d well Tract and Sunrise MDth/d Shale: well to tolocations 24 & flows included provide with 1be for 100
Slide 17: Best-in-Class Marcellus Well Costs
Best Upstream Marcellus $300 $0 2012 Average (1) 17 $0 Appalachian in $275 2013 Class Marcellus Drilling $300 2014 Marcellus peers $248 2015 Cost Well $208 2016 include Well per Costs $200 2017 Foot Costs AR, vs.Marcellus $174 2012 Appalachian CG, 2013 $200 EQT,Completion $153 2014 RICE, Peers $148
Slide 18: Utica Upstream Test Results
Utica Upstream 1st Northeast WDA 2.6 1.6 1.9 2+ March 2.4 NC June SRC 1.8 Net Permitted Completed (1) 18 Bcf Estimated Clermont Bcf PA EUR/1,000 2016 Vertical –Shale –2015 Tract CRV 1.9 Industry 1.6 30 SRC CRV Pa. Drilling Test Day Bcf Seneca’s Bcf Opportunities Test SRC 007 Planning Rich Test Utica
Slide 19: WDA Upstream Next Steps
WDA Upstream Next Pad 3Plan 5Currently Seeking 6Evaluation Expect Will 19E09 2D08 #use to Steps Wells Utica S2 UUtica drill to existing 3TD’d testing Planned optimize will WDA Appraisal 8Status WDA additional Target consider pad, 2nd UTICA Test Target development target well water Q3Timing Utica com
Slide 20: Midstream Businesses Adjusted EBITDA
Midstream Empire FERC-Regulated Pipeline $152 $186 $15 $137 NFG Marcellus Gathering 2012 Fiscal Note: $30 $188 $161 2013 Supply Midstream A Year Pipeline, reconciliation && Segment $199 2014 Storage Businesses Compression Utica Corp.2015 Corp Inc. $250 $79 Pipeline Segment $191 $278 2016 of System $
Slide 21: Integrated Midstream Gathering System
Integrated Midstream Gathering Clermont ~67 FY17 Adjusted Future Ultimate Over 21 miles 300 CapEx: Build-Out capacity timing miles Gathering of System Development pipe/26,220 $40 of ofcan Build-Out pipelines to gathering System $50 exceed –HP million WDA and Map Tailored of & 1 Bcf/d compression fiv
Slide 22: Integrated Midstream Gathering System
Integrated Midstream Gathering Covington Interconnect: Facilities: Trout In-Service Capital Capacity: Production Future Run third-party Expenditures 220,000 466,000 Pipelines Segment Development Gathering Date: Gathering Source: TGP November May volume Dth to 300 Seneca Supporting and System 585,000
Slide 23: Midstream Expanding Northern Access 2015
Midstream Expanding Northern Customer: Capacity: Niagara million (1) 23 40,000 Annual Access 140,000 Dth Seneca Ourper Revenues: Interstate Expansions 2015 Resources Dth day per went Pipelines $13.3 day in-service for (NFG) o Seneca million Leased toIn-Service: Deliver onResources toNovember TGP Sen
Slide 24: Midstream Northern Access 2016
Midstream Northern •Customer: 22,214 24 Delivery hpAccess & Interconnects: Seneca 5,350 Expansions 2016 Resources hp Compression to Increase Eastfor (NFG) Aurora Seneca Transport FERC/Regulatory In-Service: o TransCanada Resources Capacity Now –Out targeting Status: Chippawa of WDA oNov. FERC (350 b
Slide 25: Recent Midstream Expansions
Recent Midstream Expansions 1,442 +320 Northern $132 Empire Lamont +489 $50 $19 +633 FY11$37 $27 MDth/d FY12 MDth/d 3rd &~$95 Line Access Annual Party for FY13 N Expansions $183 $75 $4 $387 3rd Projects 2012 Expansions $4 Expansion FY14 Parties million $5Empire $0$25 FY15 $100 since since Highly Rev
Slide 26: Midstream Planned Empire Expansion
Midstream Planned Empire Target Open Facilities: 26 Season In-Service: System North Empire o 3 Capacity: new Expansion Expansion Expansion Fiscal compressor 300,000 2019 Project Will System: stations Dth/d Provide Receipt FERC Empire Optionality Status: Point: Pipeline for oJackson Open Target North
Slide 27: Midstream Westside and Tuscarora Expansions
Midstream Westside 2015 Tuscarora Lateral In-Service Total Incremental Preserves 27 Pipeline Completed Cost: Expansion $16.1 o(November Lateral (October $82.3 $64.8 Seneca Annual annual Expansion million Pipeline million revenues Resources Revenues: 2015) & 2015) Modernization inProjects oExpansion
Slide 28: Customer Mix and Outside Pipeline
Customer 4.1 Outside Pipeline Marketer 40% 10% 35% LDC 60% 47% LDCs 6% Firm Storage (1) Upstream Contracted MMDth/d Producer 94% 20% Transport 46% Producers End &54% 2% Transportation Storage User Affiliated 80% as 28Marketers ofCustomer 10/20/2016. Non-Affiliated byFirm Shipper Mix Type(1) Affiliat
Slide 29: California Overview
California Overview Exploration 29 & Production
Slide 30: Stable California Upstream Production
Stable California Upstream Production 32Etchegoin 1054Gross 500 6North ,500 ,760 Antelope Tulare East North South Sunset 0Sespe 1, Midway 80,200 77FY South Daily Coalinga Oil Lost Sespe & South 2010 Production Steamflood Midway 000 Potter Steamflood Location Production North Hills Primary 3,640 1,70
Slide 31: California Production and Capital Spending
Upstream $35-$45 California 9,699 $63 $83 $38 2012 Fiscal 31 $57 $35-$45 2013 9,674 Year Million Average Annual 2014 Fiscal ~9,600 2015 Annual Year Capital Daily 9,322 2016 Capital Net 9,078 Expenditures 2017 Production 9,315 Spending 2012 $105 2013 ($MM) Needed 2014 California 2015 to Keep 2016 Ave
Slide 32: Economic Upstream Projects in California
Economic Upstream Sec. Pioneer ~23% 34% 56% Acreage ?MWSS North South (1) A&D Modest 17N Midway South will MWSS NMWSS Reflects earn near-term Development focus attractive Sunset Project pre-tax SMWSS oncapital low Economics IRRs returns Focused IRRs cost, Farm-in program atat bolt-on in $50/Bbl(1) a
Slide 33: Strong West Coast Margins
Strong West Trailing Non-Steam Steam California G&A Production Taxes $2.46 Other Adjusted (1) $29.34 Note: per results Average BOE Division A $4.49 Operating =Fuel and Margins Adjusted reconciliation 12-months includes EBITDA Margins eliminations. &$3.23 Fuel Average revenue Other Adjusted Support C
Slide 34: Production and Marketing
Production and Exploration 34 & Production Marketing
Slide 35: Proved Reserves
Proved Total Natural 3,000 Crude 2,500 FY 2,000 Net 1,549 1,500 1,000 2,142 988 1,300 500 65% 042.9 2012 At (1) (2) (3) 35% September Includes Reflects FY ‘16 Negative 117% (adjusted 41.6 Proved 2013 Proved Fiscal 2,344 1,914 Extensions 1,246 1,683 Oil Proved 2016 Production Reserves Gas 38.5 (MMbbl
Slide 36: Upstream Production Growth
Upstream Seneca 250 Joint 200 160.5 83.4 100.7 ?50 20.5 (1) 36Gross Growth Utilization 62.9 Appalachia 139.3 20.0 Development ?157.8 Production Resources Gathering production Refer is will 21.2 136.6 largely 161.1 ofin to 21.2 firm (1) gross slide 140.6 Net segment 145-170 Agreement expected being 2
Slide 37: Long-Term Firm Sales and Transportation
Long-Term Upstream Gross Atlantic Northern ~500 500 Firm Niagara 250 Delivery -2Northeast (1) See 37 017Includes slide Delivery Sales(1) 2018 MDth/d Firm Expansion Sunrise Markets: Access 39 Supply 2019 Sales Contracts base for Markets: gross details now 2020 on firm and Diversification Mid-Atlantic
Slide 38: Firm Transportation and Sales Contracts
Firm Upstream Volume eProduction Diversification -Servic In 12,000 Northern WDA /Rich Atlantic Future In-service: First (1) 38 Tennessee Firm 10 WMB 5Transportation years Valley –(Dawn) years Mid-Atlantic/ Sales NFG Clermont Delivery Sunrise Access isMid-2018(1) Source Canada Gas now TGP Contracts p
Slide 39: FY17 Firm Sales Volumes
Firm Upstream FY 345,400 .355,800 Gross 19,400 58,200 61,600 33,300 170,500 161,200 Q1 Fixed (1) interests 39 $2.45 Values FY17 17Sales Price vs. 493,000/d Net $2.45 Less 337,900 Net Less assigned Net Q2 shown Contracted Provide Dawn $0.01 $0.02 $0.33 355,800/d FY17 $0.17 Firm 483,000/d 325,600 repr
Slide 40: Natural Gas Hedge Position
Strong Upstream Natural Fiscal 120.5 150.0 83% 56.2 100.0 50.0 32.1 6.5 8.4 7.2 35.7 27.1 -F NYMEX (1) (2) Y Assumes Fixed 2017 12.2 27.7 83.1 22.1 42.6 16.9 hedged(1) 2017 Hedge Gas FY Dominion price 46.5 7.2 Natural Swap midpoint 2018 Book physical at $3.38 FY &Gas in Dawn Fixed 2019 of Fiscal sal
Slide 41: Fiscal 2017 Price Certainty
Fiscal Upstream FINANCIAL 116 420-22 Firms (1) (2) ~5Bcf Bcf(2) Bcf. Average Indicates Bcf of Bcfe Firm 2017 41 realizing Additional 5—28 Sales Production realized firm HEDGE Bcf(3) Spot net sales Basis price ~$3.10/Mcf 116 California +contracts and FIRM Protection reflects Bcf Price SALE with Total
Slide 42: Operating Costs
Operating Upstream .Appalachia FY Gathering Competitive, $0.87 $0.75 (1) LOE $0.17 Excludes 2015 guidance $0.65 DD&A $0.22 FY Costs & LOE -2016 Transport $7.9 low $14.83 decrease range &cost million FY Gathering $0.42 of2017E structure due LOE $0.95 , or $0.14 to(non-Gathering) FY improving $0.05 to
Slide 43: Downstream Overview
Downstream Utility 43 ~ Energy Overview Marketing
Slide 44: Downstream Utility Overview
Downstream New Filed Total Pennsylvania ROE: Rate (1) 44 AsMechanisms: York Customers(1): Rate 9.1% Black of September & Case (NY Box Pennsylvania with PSC Settlement o 213,924 528,312 30, Earnings Low NY Rate 2016. PSC Income Service Case (2007) Sharing onSettlement, 4/28/16 Rates Territories o oRe
Slide 45: New York Rate Case Filed
New Downstream On rates Filed period October Timeline Evidentiary Significant •and 45 Accelerated Requesting Key Replacement April system York have Notice drivers with 19, 5-7, 28, not Rate increase modernization “make Hearings 2016 of 2016, 2016 rate of removal changed of Impending Case revenue rel
Slide 46: Utility Usage Trends
Utility: Downstream Usage Residential 106 35 104 30 100 25 96 92 12-Months (1) 46 102 98 94 20 Weighted 40Per Shifting Account Ended (Mcf) Average Trends Industrial September (1)ofinNew Customer (MMcf) 30 York and Usage Pennsylvania service territories (assumes normal weather).
Slide 47: Utility Capital Expenditures
Utility: Capital $150.0 Total System $120.0 $94.4 $58.3 $72.0 $90.0 $88.8 $60.0 $48.1 $30.0 $43.8 ongoing 2012 $0.0 Fiscal 47 2013 Capital The $98.0 $61.8 $54.4 $49.8 Year Capital pipeline Expenditures Strong and safety Utility 2014 anticipated $90 Expenditures Commitment Expenditures and replacemen
Slide 48: History of Controlling O&M Costs
A Proven Downstream Capital $250 $200 $9 $20 $100 2012 $0 Fiscal 48 $6 $33 All $200 $152 2013 $23 Year Expenditures $16 Other History $193 $163 2014 $150 O&M $189 $160 2015 of Controlling ($ Expenses $9millions) $152 2016 $177 $151 $178 O&M Costs $50$10 Pension $28 $7Expense O&M Uncollectible Expens
Slide 49: Appendix
49 Appendix
Slide 50: Seneca Capital Expenditures
Seneca Appendix Capital $800 West $600 $603 $694 $400 $533 $428 $520 $99 $200 $180-$220 $105 $0 2012 Fiscal (1) (2) $63 FY2016 Seneca’s $145-$175 Appalachia Coast $557 $631 $500 $61 2013 Year $83 Resources Expenditures 2014 $57 (California) and West$38 FY 2015 (1) Coast 2017 $35-$45 by 2016E (2) div
Slide 51: Marcellus Well Results
Marcellus Appendix WDA Clermont/Rich Hemlock Elk, EDA Producing Covington Tioga Tract Lycoming (1) County (2) 51 Excludes 30-day Cameron Development 595 100 47 44(2) Development 5.2 107(1) Operated 60(2) Well average 7.4 4.1 2&wells Valley Average 4.9 17.0 4,023’ 6.9 McKean excludes Wells: 4,754’ We
Slide 52: Marcellus Economics
Marcellus Appendix ~1,150 NYMEX Locations DCNR A ED (1033 Dry CRV (1045 Niagara 631 WDA Remaining 406 Tier (1) at 52 (1033 the Internal Southeast 8,800 8,500 Gas 153 well-head Ridgway BTU) (1045 100 Locations Expansion 8,000 BTU) /Completed Shale 78DAWN Dry Rate 12 89BTU) US 29% 25% 8.5 5,400 Gas (1
Slide 53: Hedge Positions
Hedge Appendix Natural Volume Dominion MichCon Dawn Fixed Crude Fiscal Avg. Vol. Price Brent NYMEX Total (1) 53 Fixed Vol. Avg. 120,500 1,308,000 Price Swaps Price Swaps 2017 Oil Positions Gas Price Vol. Swaps price Swaps Avg. Volumes Swaps Price Physical(1) Fiscal Volumes 123,000 19,100 Volume $3.3
Slide 54: Comparable GAAP Financial Measures
Comparable Appendix This provided Company’s GAAP The comparability 54 Company presentation financial in financial the GAAP and believes defines slides measures contains income Financial performance that Adjusted thatfollow. is taxes. certain its not Measure non-GAAP EBITDA meant non-GAAP to other Sl
Slide 55: Non-GAAP Reconciliation
Non-GAAP Reconciliation ($ FY Exploration Pipeline Gathering Utility Energy Corporate Plus: Minus: Rounding Consolidated Long-Term Current Notes Total Average Thousands) 2012 Adjusted Interest Reversal Elimination Debt Payable Adjusted Interest Income Depreciation, Impairment Pennsylvania New Joint
Slide 56: Non-GAAP Reconciliation
Non-GAAP Appendix Reconciliation Consolidated $390,000—$440,000 $100,000 523,051 Plus Exploration 2014 (38,861) 2015 5,633 Capital Expenditures Total 56 (Minus) Accrued Capital —Expenditures $725,000—$835,000 38,861 -Pipeline Energy & Reconciliations Accrued Expenditures — Capital Capital Production
Slide 57: Non-GAAP Reconciliation
Non-GAAP Appendix Reconciliation Three Reported Depreciation, Taxes — Appalachia Gas Total Adjusted Note: 57 7,855 Production Production Seneca 2,758 Months EBITDA GAAP West Reconciliations 2,048 West Depletion Ended of(MMcf) Earnings (Mmcfe) (Mboe) Coast Exploration 4,806 $Coast Margin 69,425 Twelv
Slide 58: Non-GAAP Reconciliation
Non-GAAP Appendix Reconciliation ($000s Twelve Appalachia Operating Gathering $86,153 General All $9,046 Depreciation, Gas Production: Total (1) 58 Gathering Other Production Production unless $11,121 Months & $0.22 Operating Expenses: & Administrative West Reconciliations Transportation Depletaion