National Fuel Gas Company · NYSE:NFG
National Fuel Gas — Investor Presentation (August 2015)
61 slides from National Fuel Gas's investor presentation, Aug 6, 2015
Slide 1: National Fuel Gas Company Investor Presentation August 2015
National Fuel Gas Company Investor Presentation August 2015 Exhibit
Slide 2: Forward-looking statements
Corporate 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, strategies, future events or performan
Slide 3: Quality Assets, Exceptional Location, Unique Integration
Corporate 3 Million BBls of Annual Crude Oil Production $262 Million of Midstream Adjusted EBITDA (2) 790,000 Net Acres in Marcellus Shale 1.9 Tcfe of Proved Reserves (1) Quality Assets, Exceptional Location, Unique Integration (1) Total proved reserves are as of September 30, 2014. (2) For the trai
Slide 4: The National Fuel Value Proposition
Corporate Creating sustainable value for shareholders remains our #1 priority Unique Integrated Business Model Provides Competitive Advantage The National Fuel Value Proposition (1) Per NGI’s Shale Daily (January 5, 2015). 790,000 net acres in Marcellus Shale – nd largest acreage position in the ind
Slide 5: National Fuel
d National Fuer
Slide 6: EBITDA Contribution by Segment
Corporate $121 $111 $137 $161 $186 $190 $64 $72 $327 $377 $397 $492 $539 $464 $167 $169 $160 $172 $165 $169 $632 $668 $704 $852 $953 $896 $0 $250 $500 $750 $1,000 $1,250 TTM 6/30/15 Fiscal Year Exploration & Production Segment Gathering Segment Pipeline & Storage Segment Utility Segment Energy Marke
Slide 7: Adjusting Capex to Capitalize on Opportunities
Corporate $129 $144 $56 $140 $235-$245 $500-$550 $80 $55 $138 $110-$120 $125-$150 $398 $649 $694 $533 $603 $550-$575 $400-$475 Adjusting Capex to Capitalize on Opportunities Note: A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end
Slide 8: Maintaining a Strong Balance Sheet
Corporate Shareholders’ Equity 52% Total Debt 48% Maintaining a Strong Balance Sheet Note: A reconciliation of Adjusted EBITDA to Net Income is included at the end of this presentation. $4.3 Billion As of June 30, 2015 1.98 x 1.75 x 1.89 x 1.89 x 1.77 x 2.09 x 0.0 0.5 1.0 1.5 2.0 2.5 TTM 6/30/15 Fis
Slide 9: Dividend Consistency
Corporate Dividend Consistency Dividend Track Record (1) As of August 5, 2015. $0.00 $0.50 $1.00 $1.50 $2.00 Annual Rate at Fiscal Year End Current Dividend Yield (1) 2.9% Consecutive Dividend Payments 113 Years Consecutive Dividend Increases 44 Years Current Annualized Dividend Rate $1.58 per Share
Slide 10: Overview Exploration & Production
Upstream Overview Exploration & Production
Slide 11: Proven Record of Reserve Growth
Upstream 4 5.2 4 3.3 4 2.9 4 1.6 3 8.5 428 675 988 1,300 1,683 Fiscal Years 3-Year F&D Cost (1) ($/Mcfe) Proven Record of Reserve Growth (1) Represents a three-year average U.S. finding and development cost. 1,246 1,549 1,914 1,000 1,500 2,000 2,500 At September 30 2007-2009 $5.35 2008-2010 $2.37 20
Slide 12: Marcellus Shale Driving Production Growth
Upstream 19.8 19.2 20.5 20.0 21.2 20-21 20-21 16.5 43.2 62.9 100.7 139.3 135- 139 138 13.3 Spot Gas Sales 49.6 67.6 83.4 120.7 160.5 155- (1) ~195 (2) 2015E 2016E Fiscal Year Gulf of Mexico (Divested in 2011) East Division West Division Marcellus Shale Driving Production Growth (1) Midpoint of fisca
Slide 13: Disciplined Capital Spending
Upstream $28 $47 $63 $105 $83 $40-$50 $30-$50 $356 $596 $631 $428 $520 $510 - $525 $370 - $425 Disciplined Capital Spending $398 $649 $694 $533 $603 $550 - $575 $400 - $475 $0 $200 $400 $600 $800 $1,000 2015E 2016E Fiscal Year Gulf of Mexico (Divested in 2011) East Division West Division
Slide 14: Highly Competitive Cost Structure
Upstream $1.17 $0.91 $0.76 $0.65 $0.57 $0.56 $0.51 $0.17 $0.24 $0.34 $0.46 $0.49 $0.49 $0.64 $0.73 $0.65 $0.52 $0.40 $0.43 $0.38 (1) (2) (2) (1) (2) (2) $0.21 $0.18 $0.28 $0.14 $0.13 $0.10 $0.13 $2.23 $2.09 $2.01 $1.74 $1.65 $1.65 $1.58 $0.00 $1.00 $2.00 $3.00 $4.00 2015E 2016E Fiscal Year Property,
Slide 15: Marcellus Shale: Prolific Pennsylvania Acreage
Upstream Eastern Development Area (EDA) • Mostly leased (16-18% royalty) • No near-term lease expiration • Limited development drilling until firm transportation capacity on Atlantic Sunrise becomes available in late 2017 o Drilling activity will HBP key acreage Western Development Area (WDA) • Aver
Slide 16: Marcellus Shale: Eastern Development Area
Upstream Covington – Fully Developed • Productive Capacity: ~40MMcf per Day • 47 Wells Producing DCNR Tract 595 • Productive Capacity: ~95 MMcf per Day • 52 Total Marcellus Locations • 44 Wells Producing (1) DCNR Tract 100 • Productive Capacity: ~310 MMcf per Day • 70 Total Marcellus Locations • 58
Slide 17: Marcellus Shale: Western Development Area
Upstream Seneca’s Tier I WDA Acreage • 200,000 acres economic <$3 /MMbtu • 860+ locations economic at realized prices $2.19-$2.45/MMbtu • FY15 / FY16 development focused on Clermont/Rich Valley (CRV) area • Planning to drill 2 Utica test wells in FY16 2 - 4 BCF/well 6 - 10 BCF/well 4 - 6 BCF/well EU
Slide 18: Focusing on Clermont/Rich Valley (CRV) Area
Upstream Pad E9-J Drilling 4 wells Pad C9-D Drilling 9 wells Pad C8-J Drilling 8 wells • 200-250 total horizontal locations • 40 wells currently on-line • Current productive capacity: 150 MMcf/d • Development strategy focused on: (1) Preserving capital – currently running 3 rigs with plans to drop a
Slide 19: Marcellus Operated Well Results
Upstream Area Producing Well Count Average IP Rate (MMcfd) Average 30-Day (MMcf/d) Average Treatable Lateral Length (ft) Area Producing Well Count Average IP Rate (MMcfd) Average 30-Day (MMcf/d) Average Treatable Lateral Length (ft) Marcellus Operated Well Results (1) Excludes wells drilled and comp
Slide 20: Marcellus Drilling and Completion Efficiencies
Upstream $8.7 MM Well Cost $5.8 MM Well Cost Fiscal 2012 Average Development Well Fiscal 2015 (1) Average Development Well Marcellus Drilling and Completion Efficiencies $275 $208 $174 $154 $0 $100 $200 $300 FY 2012 FY 2013 FY 2014 FY 2015 $248 $148 $109 $98 $0 $100 $200 $300 FY 2012 FY 2013 FY 2014
Slide 21: Marcellus Shale Program Economics
Prospect Product Locations Remaining to Be Drilled Completed Lateral Length (ft) Average EUR (Bcf) BTU $3.50 Dawn/NYMEX $3.25 Dawn/NYMEX IRR % (1) Realized Price (2) 78% 59% $1.68 50% 38% $1.91 27% 21% $2.19 23% 17% $2.36 20% 15% $2.45 11% 7% $3.00 Upstream 15% IRR IRR % (1) Marcellus Shale Program
Slide 22: WDA Mineral Interests Significantly Enhance Returns
Upstream ($/Mcf) The Seneca Advantage 0% Royalty A producer burdened by a 15% royalty would require a $0.39 higher realized price to achieve same level of economics as Seneca Resources Producer Paying 15% Royalty WDA Mineral Interests Significantly Enhance Returns (1) For illustration purposes only.
Slide 23: Adding Long-Term Firm Transport to the Portfolio
Upstream Project (Counterparty) In- Service Date Contract Term Delivery Market FT Capacity (Dth/day) Matched Firm Sales Contracts Fiscal 2015 Fiscal 2016 Fiscal 2017 Fiscal 2018 Adding Long-Term Firm Transport to the Portfolio (1) A large majority of the executed firm sales agreements continue for t
Slide 24: Significant Base of Long-Term Firm Contracts
Upstream 20152016201620162016201720172017201720182018201820182019201920192019202020202020202020212021202120212022202220222022202320232023 Atlantic Sunrise Williams Co. (Transco) 189,405 Dth/d Northern Access 2016 NFG (1) , TransCanada & Union 490,000 Dth/d Niagara Expansion / TETCO TGP & NFG 170,000
Slide 25: Reaching High Value Markets
Upstream Seneca FT Capacity by Fiscal 2018 (Dth per day) To Mid-Atlantic & Southeast Markets To Canadian Markets Reaching High Value Markets Canadian Markets 558,000 Mid-Atlantic, Southeast & Other + 341,405 Total Firm Transport Capacity 899,405
Slide 26: Firm Sales Provide Market for Appalachian Production
Upstream 205,936 Less: $0.53 188,034 Less: $0.27 178,936 Less: $0.12 128,036 Less: $0.18 128,036 Less: $0.18 85,000 Less: $0.47 71,739 Less: $0.52 65,000 Less: $0.55 50,000 Less $0.33 50,000 Less $0.33 100,000 $3.39 100,000 $3.39 100,000 $3.39 100,000 $3.39 100,000 $3.39 EDA (1) 280,036 /d 226,993 /
Slide 27: Natural Gas Financial Hedge Positions
Upstream 14.5 44.4 24.1 11.0 6.2 18.8 12.7 19.0 22.1 21.0 82.2 59.0 12.8 7.2 1.8 Fiscal Year NYMEX Dominion Dawn & MichCon SoCal (2) Natural Gas Financial Hedge Positions (1) (1) Excludes fixed price physical firm sales. (2) For the remaining three months of fiscal 2015. A table of volumes and avera
Slide 28: FY 2015 Production and Firm Sales
Upstream 120.1 Bcfe 14.0 Bcf 6.0 Bcf 8.8 Bcf FY 2015 Production Q4 FY15 Firm Sales with Price Certainty 28.7 Bcf Realizing ~$3.60/Mcf 2.5 Bcf of Additional Basis Protection 2.0 Bcf (1) 2.2 Bcf (1) 5.2 Bcfe 0 Bcf (2) FYTD Production NYMEX Firm Sales DOM Firm Sales Fixed Price Sales Spot Sales West Di
Slide 29: FY 2016 Production - Firm Sales & Spot Exposure
Upstream FY 2016 Production - Firm Sales & Spot Exposure (1) Indicates firm sales not backed by matching index financial hedges. (2) Includes 6.3 Bcf of non-operated production and 0.3 Bcf of DOM financial hedges not associated with DOM firm sales. (3) EPS guidance assumes production sold into spot
Slide 30: Utica/Point Pleasant: Industry Activity
Upstream PGE Seneca – Mt. Jewett IP: 8.9 MMcfd Seneca – WDA 2 Utica Test Wells Planned for 2016 Seneca - DCNR 007 IP: 22.7 MMcfd Utica/Point Pleasant: Industry Activity Range 59 Mmcf/d Rice 42 Mmcf/d Shell 26.5 Mmcf/d Permitted Drilling Completed Production Seneca Vert. Seneca Horiz. EQT 73 Mmcf/d C
Slide 31: Utica/Point Pleasant: EDA Opportunities
Upstream DCNR Tract 001 Potential Future Location Covington Potential Future Location Seneca DCNR Tract 007 IP: 22.7 MMcfd Lateral Length: 4,640’ Potential locations: ~ 70 Anticipated Development Well Cost: $7-$10 Million (5,500’ Lat.) Utica/Point Pleasant: EDA Opportunities Shell: Gee 11.2 Mmcf/d P
Slide 32: California: Stable Production; Modest Growth
Upstream 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 Californi
Slide 33: South Midway Sunset Development
Upstream Seneca Acquired in June 2009 South Midway Sunset Development 252 Pool 97X Pool SE Pool 251 Pool B Pool A Pool Extended Pool Boundary Original Pool Boundary Existing Wells 1000’ 16X Pool Highlights Since Acquisition • Significantly increased daily production • Drilled 135 new producers • Add
Slide 34: California Average Daily Net Production
Upstream 9,056 8,773 9,322 9,078 9,699 ~9,600 9,100 - 9,600 7,000 8,000 9,000 10,000 11,000 Forecast Forecast Fiscal Year California Average Daily Net Production
Slide 35: Strong Margins Support Significant Free Cash Flow
Upstream DD&A Strong Margins Support Significant Free Cash Flow $12.45 $3.75 $4.59 $3.14 $2.70 $40.33 Non-Steam Fuel LOE Steam Fuel G&A Production & Other Taxes Other Operating Costs EBITDA FYTD 2015 West Division EBITDA per BOE (1) Average Revenue for FYTD 2015 (1) $66.96 per BOE (1) Reflects the n
Slide 36: Midstream Overview Pipeline & Storage Gathering
Midstream Overview Pipeline & Storage Gathering
Slide 37: Gathering is the First Step to Reaching a Market
Midstream Covington Gathering System (In-Service) Trout Run Gathering System (In-Service) Clermont Gathering System (In-Service) Gathering Interconnects TGP 300 Transco Gathering is the First Step to Reaching a Market TGP 200 (1) Fiscal 2015 estimated revenue reflects projected throughput based on t
Slide 38: Gathering Supporting Seneca's EDA Production
Midstream Covington Gathering System Trout Run Gathering System Gathering Supporting Seneca’s EDA Production • In-Service Date: November 2009 • Capital Expenditures (to date): $33 Million • Capacity: 220,000 Dth per day • Production Source : Seneca Resources – Tioga Co. (Covington and DCNR Tract 595
Slide 39: Clermont Gathering System: Coordinated Build-out
Midstream Current System In-Service (July ‘14) Current Build-Out (FY15-FY16) Future Build-Out (FY17+) Clermont Gathering System: Coordinated Build-out C C Compressor Station Interconnect C C C • 26 miles of pipe / 13,800 HP of compression • Current Capacity of 400 mmcfd • Interconnect with TGP 300 •
Slide 40: Gathering Delivering Growth
Midstream Throughput by Gathering System since 2011 (MMdth) Total Gathering Revenues since 2011 ($MM) Gathering Delivering Growth $11.3 $17.5 $34.8 $70.6 ~$77 ~$95 $0 $25 $50 $75 $100 $125 2015E (1) 2016E (1) Fiscal Year 2015E (1) 2016E (1) Fiscal Year Covington Trout Run Clermont (1) Reflects the m
Slide 41: Pipeline & Storage: Premier Appalachian Position
Midstream NFG is uniquely positioned to expand our regional pipeline systems and provide valuable outlets for producers and shippers in Appalachia Canada New England & Northeast Midwest & Southeast Mid-Atlantic Pipeline & Storage: Premier Appalachian Position
Slide 42: Major Expansion Designed for Canadian Deliveries
Midstream Northern Access 2015 Northern Access 2015 (November 2015) Major Expansion Designed for Canadian Deliveries • Customer: Seneca Resources • In-Service: November 2015 • System: NFG Supply Corp. • Capacity: 140,000 Dth per day o Leased to TGP as part of TGP’s Niagara Expansion project • Interc
Slide 43: Northern Access 2016 Provides Access to Canada
Midstream Northern Access 2016 Northern Access 2016 (Late 2016) Northern Access 2016 Provides Access to Canada • Customer: Seneca Resources • In-Service: Targeting Late • Capacity: 490,000 Dth/d • Interconnects: o TransCanada – Chippawa (350 MDth/d) o TGP 200 – East Aurora (140 MDth/d) • Total Cost:
Slide 44: Recent 3rd Party Expansions Highly Successful
Midstream Completed Expansions Line N Projects Northern Access 2012 Tioga County Extension Recent 3 rd Party Expansions Highly Successful Capacity (Dth/day) Northern Access 2012 320,000 Tioga County Ext. & Lamont 440,000 Line N & Mercer Expansion 458,000 Total New Capacity 1,218,000 Capital Cost ($M
Slide 45: Pairing Line N Expansions with System Modernization
Midstream Westside Expansion & Modernization Westside Expansion & Modernization Pairing Line N Expansions with System Modernization Mercer (TGP Station 219) Holbrook (TETCO) • In-Service: October 2015 • System: NFG Supply Corp. • Capacity: 175,000 Dth per day o Range Resources (145,000 Dth/d) o Sene
Slide 46: Developing Unique Solutions for Shippers
Midstream Tuscarora Lateral Tuscarora Lateral Developing Unique Solutions for Shippers • In-Service: November 2015 • System: NFG Supply & Empire Pipeline • New No-Notice Services o Precedent agreements executed with RG&E, NYSEG & NFG Utility o Preserving 172,500 Dth per day (RG&E) o Preserving 20,00
Slide 47: Significant Expansions Are Driving Growth
Midstream Total Expansion (2009-2016+) Planned Projects (2015+) Precedent Agreements Executed Completed Projects (Since 2009) Significant Expansions Are Driving Growth Capacity Additions 2,072,000 Dth/day In-Service 2015 364,000 Dth/day In-Service 2016+ 490,000 Dth/day Delivering Gas North Tioga Cou
Slide 48: Capitalizing on Appalachian Opportunities
Corporate $129 $144 $56 $140 $235 - $245 $500 - $550 $80 $55 $138 $110 - $120 $125 - $150 Capitalizing on Appalachian Opportunities Note: A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation. $45 $146 $224 $111
Slide 49: Midstream EBITDA Growth
Corporate $121 $111 $137 $161 $186 $190 $9 $15 $30 $64 $72 Note: A reconciliation of Adjusted EBITDA to Net Income as presented on the Consolidated Statement of Income and Earnings Reinvested in the Business is included at the end of this presentation. Midstream EBITDA Growth $123 $121 $152 $191 $25
Slide 50: Downstream Overview Utility Energy Marketing
Downstream Overview Utility Energy Marketing
Slide 51: New York & Pennsylvania Service Territories
Downstream New York Pennsylvania New York & Pennsylvania Service Territories Total Customers: 524,300 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.)
Slide 52: Utility: Shifting Trends in Customer Usage
Downstream Utility: Shifting Trends in Customer Usage (1) Weighted Average of New York and Pennsylvania service territories (assumes normal weather). 12-Months Ended June 30 12-Months Ended June 30 Residential Usage Industrial Usage
Slide 53: A Proven History of Controlling Costs
Downstream $154 $152 $152 $152 $151 $157 $13 $16 $16 $20 $33 $30 $14 $11 $9 $6 $10 $8 (1) (1) $181 $179 $177 $178 $193 $195 $0 $50 $100 $150 $200 $250 12 Months Ended 6/30/15 Fiscal Year All Other O&M Expenses O&M Pension Expense O&M Uncollectible Expense A Proven History of Controlling Costs (1) $1
Slide 54: Utility: Strong Commitment to Safety
Downstream The Utility remains focused on maintaining the ongoing safety and reliability of its system Utility: Strong Commitment to Safety $45.0 $44.3 $43.8 $48.1 $49.8 $58.0 $58.4 $58.3 $72.0 $88.8 $95 - $105 $85-$105 $0 $30 $60 $90 $120 $150 2015E 2016E Fiscal Year Capital Expenditures for Safety
Slide 55: National Fuel
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Slide 56: National Fuel
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Slide 57: Crude Oil Hedge Positions
Appendix Fiscal 2015 (1) Fiscal 2016 Fiscal 2017 Fiscal 2018 Volume Avg. Price Volume Avg. Price Volume Avg. Price Volume Avg. Price Total 450,000 $90.03 1,269,000 $92.95 384,000 $92.30 75,000 $91.00 Crude Oil Hedge Positions (1) For the remaining three months of fiscal 2015. Midway Sunset (MWSS) Sw
Slide 58: Updated Marcellus Type Curves: EDA
Appendix 2,000 4,000 6,000 8,000 10,000 12,000 14,000 16,000 Months Lycoming - Type Curve Lycoming County_5,400 FT. Estimated Cumulative Volumes YEAR CUM (MMCF) 3,226 5,451 6,815 7,762 8,470 9,029 9,483 9,862 10,185 10,466 EUR 13,495 Updated Marcellus Type Curves: EDA
Slide 59: Updated Marcellus Type Curves: WDA
Appendix 1,000 2,000 3,000 4,000 5,000 6,000 7,000 8,000 Months Elk - Cameron Type Curve Elk - Cameron County_7,000 Ft. Estimated Cumulative Volumes YEAR CUM (MMCF) 1,466 2,334 2,989 3,510 3,933 4,289 4,596 4,866 5,108 5,325 EUR 8,400 Updated Marcellus Type Curves: WDA
Slide 60: Reconciliation of Adjusted EBITDA to Consolidated Net Income
Appendix National Fuel Gas Company Reconciliation of Adjusted EBITDA to Consolidated Net Income ($ Thousands) FY 2010 FY 2011 FY 2012 Exploration & Production - West Division Adjusted EBITDA 187,838 $ 187,603 $ 226,897 $ 215,042 $ 217,150 $ 162,017 $ Exploration & Production - All Other Divisions Ad
Slide 61: Reconciliation of Segment Capital Expenditures to Consolidated Capital Expenditures
Appendix National Fuel Gas Company Reconciliation of Segment Capital Expenditures to Consolidated Capital Expenditures ($ Thousands) FY 2015 FY 2016 FY 2010 FY 2011 FY 2012 FY 2013 FY 2014 Forecast Forecast Capital Expenditures from Continuing Operations Exploration & Production Capital Expenditures
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