National Fuel Gas Company · NYSE:NFG
National Fuel Gas — Investor Presentation (November 2015)
59 slides from National Fuel Gas's investor presentation, Nov 5, 2015
Slide 1: National Fuel Gas Company Investor Presentation November 2015
National Fuel Gas Company Investor Presentation November 2015 Exhibit 99
Slide 2: 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, strategies, future events or performance and und
Slide 3: Quality Assets, Exceptional Location, Unique Integration
$257 Million of Midstream Adjusted EBITDA(2) $1.2 Billion Midstream Investments since 2010 790,000 Net Acres in Marcellus Shale 2.3 Tcfe of Proved Reserves(1) Quality Assets, Exceptional Location, Unique Integration Total proved reserves are as of September 30, 2015. For the fiscal year ended Septem
Slide 4: Unique Integrated Business Model Provides Competitive Advantage
Unique Integrated Business Model Provides Competitive Advantage The National Fuel Value Proposition 4 Mineral ownership on ~720,000 acres in WDA = limited royalties or drilling commitments Seneca has >900,000 Dth/day of firm transportation & sales contracts by end of fiscal 2017 Stacked pay potentia
Slide 5: Appalachia Overview
Appalachia Overview Exploration & Production | Gathering | Pipeline & Storage
Slide 6: NFG Appalachia – Integrated Vision for Growth
200,000 “Tier 1” WDA Acres in Pa. Fee Acreage Economic < $3/MMbtu Clermont Gathering System Capacity to Approach 1Bcf/d Northern Access Projects to Transport 660 MDth/d of Seneca production by FY17 NFG Appalachia – Integrated Vision for Growth Exploration & Production Pipeline & Storage Gathering WD
Slide 7: Appalachia Upstream & Midstream CapEx
Appalachia Upstream & Midstream CapEx 7 Note: A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation. Refer to slide 39 for NFG consolidated capital expenditures. Exercising Capital Flexibility & Efficiency to Res
Slide 8: Significant Appalachian Acreage Position
Significant Appalachian Acreage Position 8 153 wells able to produce 415 MMcf/d(1) 40-50 remaining Marcellus locations Additional strong Utica & Geneseo potential Limited development drilling until firm transportation on Atlantic Sunrise (190 MDth/d) is available in late 2017 Mostly leased (16-18% r
Slide 9: Marcellus Shale: Western Development Area
Marcellus Shale: Western Development Area 9 Internal rate of return (IRR) is pre-tax and includes estimated well costs under the current well design and cost structure and projected firm transportation, gathering, LOE and other operating costs. CRV and Hemlock/Ridgway well designs assume 8,800 ft. l
Slide 10: Integrated WDA Development – Upstream
Integrated WDA Development – Upstream Clermont/Rich Valley Development Map Pittsburgh Clermont/Rich Valley Area Legend Drilled Wells Planned Wells Clermont Gathering System (in-service) Clermont Gathering System (future) CRV Development Summary 48 wells currently producing 185 MMcf/d >200 MMcf/d fir
Slide 11: Integrated WDA Development - Gathering
Integrated WDA Development - Gathering 11 Current System In-Service ~44 miles of pipe/13,800 HP of compression Current Capacity: 470 MMcf per day Interconnect with TGP 300 Total CapEx To Date: $216 MM Fiscal 2016 Build Out FY16 CapEx: $100 MM to $140 MM Exit FY16 with > 60 miles of pipe installed an
Slide 12: Integrated WDA Development - Interstate Pipelines
Integrated WDA Development - Interstate Pipelines 12 (1) 40,000 Dth per day went in-service on November 1, 2015. The remaining 100,000 Dth per day is expected to be placed in-service by December 1, 2015. Northern Access 2015 Customer: Seneca Resources (NFG) In-Service: November 2015(1) System: NFG S
Slide 13: Northern Access 2016
13 Northern Access 2016 Customer: Seneca Resources (NFG) In-Service: Targeting Late 2016 Capacity: 490,000 Dth/d Interconnects: TransCanada – Chippawa (350 MDth/d) TGP 200 – East Aurora (140 MDth/d) Total Cost: ~$455 Million Major Facilities: 98.5 miles – 16/24” Pipeline 22,214 hp & 5,350 hp Compres
Slide 14: Marcellus Shale: Eastern Development Area
Marcellus Shale: Eastern Development Area (1) One well included in the total for both Tract 595 and Tract 100 is drilled into and producing from the Geneseo Shale. EDA Acreage – 70,000 Acres 1 2 3 EDA Highlights 1 Covington & DCNR Tract 595 Tioga County, Pa. 92 wells(1) with 125 MMcf/d productive ca
Slide 15: Integrated EDA Development - Gathering
Integrated EDA Development - Gathering 15 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 acreage) Interconnect: TGP 300 Facilities: Pipelines and dehydration Future
Slide 16: Utica/Point Pleasant: Industry Activity
Utica/Point Pleasant: Industry Activity Range 59 MMcf/d Rice 42 MMcf/d Shell 26.5 MMcf/d PGE Permitted Drilling Completed Production Seneca Vert. Seneca Horiz. EQT 73 MMcf/d Color-filled contours are Trenton TVDSS; CI = 1000’ Seneca – Mt. Jewett IP: 8.9 MMcf/d CNX 61 MMcf/d MHR 46 MMcf/d Seneca – WD
Slide 17: Marcellus Drilling and Completion Efficiencies
Marcellus Drilling and Completion Efficiencies Includes dollars spent to drill and complete development wells only. Excludes exploration and delineation wells. Down 44% since 2012 Down 63% since 2012 $8.7 MM Well Cost $5.7 MM Well Cost Fiscal 2012 Average Development Well Fiscal 2015 Average Develop
Slide 18: FY 2016 Production - Firm Sales & Spot Exposure
FY 2016 Production - Firm Sales & Spot Exposure 18 Fiscal 2016 Firm Sales with Price Certainty 119.9 Bcf Realizing ~$3.45/Mcf (1) 15.0 Bcf of Additional Basis Protection (2) 6.3 Bcf(3) Appalachia Productive Capacity Seneca Total Productive Capacity Realized price is net of firm transportation costs.
Slide 19: Significant Base of Long-Term Firm Contracts
Significant Base of Long-Term Firm Contracts Atlantic Sunrise (Transco) Delivery Markets: Mid-Atlantic & Southeast U.S. 189,405 Dth/d Northern Access 2016 (NFG(1), TransCanada & Union) Delivery Markets: Canada-Dawn & NY-TGP200 490,000 Dth/d Niagara Expansion (TGP & NFG) Delivery Markets: Canada-Dawn
Slide 20: Natural Gas Hedge Position
Natural Gas Hedge Position (1) Assumes production at midpoint of East Division Productive Capacity and 3 Bcf of natural gas production in California. FY 2016 = 67% hedged(1) at $3.66 per MMbtu Natural Gas Swap & Fixed Physical Sales Contracts (Million MMBtu)
Slide 21: Appalachian Price Realizations & Margins
Appalachian Price Realizations & Margins 21 Appalachian peer group includes AR, COG, CNX, EQT, GPOR, RICE, & RRC . Peer group information obtained or estimated by National Fuel Gas Company from peer company quarterly public filings (press release & Form 10-Q) for the quarter-ended September 30, 2015
Slide 22: Pipeline & Storage: Premier Appalachian Position
Pipeline & Storage: Premier Appalachian Position 22 In addition to serving our own upstream and downstream subsidiaries, NFG is uniquely positioned to expand our regional pipeline systems and provide valuable outlets for 3rd party producers and shippers in Appalachia Canada & Michigan New England &
Slide 23: Recent 3rd Party Expansions
Recent 3rd Party Expansions Highly Successful Expansions for 3rd Parties since 2010 Line N Projects +633 MDth/d Northern Access 2012 +320 MDth/d Empire & Lamont Expansions +489 MDth/d 3rd Party Expansion Capital Cost ($MM) Expansion Revenues ($MM) $387 million since FY 2010 1,442 MDth/d since FY2010
Slide 24: Planned Empire System Expansion
Planned Empire System Expansion Empire North Expansion Project Target In-Service: Late 2018 System: Empire Pipeline Target Market: Marcellus & Utica producers in Tioga & Potter County, Pa. Open Season Capacity: 300,000 Dth/d Delivery Points: 180,000 Dth/d to Chippawa (TCPL) 120,000 Dth/d to Hopewell
Slide 25: Midstream EBITDA Growth
Midstream EBITDA Growth 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.
Slide 26: Downstream Overview
d National Fuel Downstream Overview Utility | Energy Marketing
Slide 27: New York & Pennsylvania Service Territories
New York & Pennsylvania Service Territories New York Pennsylvania Total Customers: 526,323 ROE: 9.1% (NY PSC Rate Case Settlement, May 2014) Rate Mechanisms: Earnings Sharing Revenue Decoupling Weather Normalization Low Income Rates Merchant Function Charge (Uncollectibles Adj.) 90/10 Sharing (Large
Slide 28: Utility: Shifting Trends in Customer Usage
Utility: Shifting Trends in Customer Usage (1) Weighted Average of New York and Pennsylvania service territories (assumes normal weather). Residential Usage Industrial Usage
Slide 29: A Proven History of Controlling Costs
A Proven History of Controlling Costs $10 million of increase in pension costs from fiscal 2013 primarily due to the NY PSC rate case settlement in May 2014. (1) (1)
Slide 30: Utility: Strong Commitment to Safety
Utility: Strong Commitment to Safety The Utility remains focused on maintaining the ongoing safety and reliability of its system Near-term increase due to ~$60MM upgrade of the Utility’s Customer Information System
Slide 31: California Exploration & Production
d National Fuel California Exploration & Production
Slide 32: California: Stable Production; Modest Growth
California: Stable Production; Modest Growth 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 Ses
Slide 33: California Average Daily Net Production
California Average Daily Net Production 33 $40-$50 million Annual CapEx to Keep California Oil Production Flat
Slide 34: Strong Margins Support Significant Free Cash Flow
Strong Margins Support Significant Free Cash Flow Average revenue per BOE includes impact of hedging and other revenues. A reconciliation of Adjusted EBITDA margin to Net Income as presented on the Consolidated Statement of Income and Earnings Reinvested in the Business is included at the end of thi
Slide 35: Consolidated Financial Overview
d National Fuel Consolidated Financial Overview Upstream | Midstream | Downstream
Slide 36: Appalachia Driving Proved Reserve Growth
Appalachia Driving Proved Reserve Growth (1) Represents a three-year average U.S. finding and development cost. 4 Year CAGR: 26% Fiscal Years 3-Year F&D Cost(1) ($/Mcfe) 2008-2010 $2.37 2009-2011 $2.09 2010-2012 $1.87 2011-2013 $1.67 2012-2014 $1.38 2013-2015 $1.12 2015 F&D Cost = $0.96 Marcellus F&
Slide 37: Seneca Production
Seneca Production 37 Refer to slide 18 for additional details on fiscal 2016 firm sales and local Appalachian spot market exposure. (1)
Slide 38: EBITDA Contribution by Segment
EBITDA Contribution by Segment 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.
Slide 39: Capital Expenditures by Segment
Capital Expenditures by Segment Note: A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation.
Slide 40: Maintaining a Strong Balance Sheet
Maintaining a Strong Balance Sheet Note: A reconciliation of Adjusted EBITDA to Net Income is included at the end of this presentation. Total Debt 51% $4.1 Billion Total Capitalization as of September 30, 2015 Debt/Adjusted EBITDA Capitalization Debt Maturity Profile ($MM) Liquidity Committed Credit
Slide 41: Dividend Track Record
Dividend Track Record (1) As of November 4, 2015. Current Dividend Yield(1) 3.0% Dividend Consistency Consecutive Dividend Payments 113 Years Consecutive Dividend Increases 45 Years Current Annualized Dividend Rate $1.58 per Share
Slide 42: Appendix
National Fuel H Fy. | vit Appendix
Slide 43: 2015 Pipeline Expansion Projects In-Service
2015 Pipeline Expansion Projects In-Service Westside Expansion & Modernization In-Service (October 2015) Tuscarora Lateral In-Service (November 2015) 2015 Completed Pipeline Expansion Projects Total Cost: $60.0 Million Incremental annual revenues of $10.9 MM on 49,000 Dth per day capacity Preserves
Slide 44: Total Seneca Capital Spending by Division
Total Seneca Capital Spending by Division (1) Seneca’s West Coast division includes Seneca corporate and eliminations. (1)
Slide 45: Marcellus Operated Well Results
Marcellus Operated Well Results Excludes 5 wells drilled and completed without sufficient production data for inclusion in table. Also excludes 2 wells now operated by Seneca that were drilled by another operator as part of a joint-venture. 30-day average excludes 1 well that has not been on line 30
Slide 46: Highly Competitive Cost Structure
Highly Competitive Cost Structure Represents the midpoint of General & Administrative Expense guidance of $0.35 to $0.40 per Mcfe for fiscal 2016. The total of the two LOE components represents the midpoint of LOE guidance of $0.95 to $1.05 per Mcfe for fiscal 2016. The cost of firm transportation i
Slide 47: Marcellus Shale Program Economics
Marcellus Shale Program Economics (1) Internal Rate of Return (IRR) is pre-tax and includes estimated well costs under current cost structure, LOE, and Gathering tariffs anticipated for each prospect. ~1,200 WDA Locations Economic Below $2.50/MMbtu Q3 Prospect Locations Remainingto Be Drilled Comple
Slide 48: WDA Mineral Interests Significantly Enhance Returns
WDA Mineral Interests Significantly Enhance Returns For illustration purposes only. Reflects a hypothetical $0.55 per MMBtu of gathering and compression costs and $0.15 of variable LOE and taxes. Internal Rate of Return (IRR) includes estimated well costs under current cost structure, LOE, and Gathe
Slide 49: Adding Long-Term Firm Transport to the Portfolio
Adding Long-Term Firm Transport to the Portfolio A large majority of the executed firm sales agreements continue for the remainder of the firm transportation contract term. Excludes throughput-based commodity charges, fuel charges and other surcharges. Project (Counterparty) In-Service Date Contract
Slide 50: Firm Sales Provide Market for Appalachian Production
Firm Sales Provide Market for Appalachian Production EDA and WDA carry an average net revenue interest (NRI) of 82% - 84% and 98%, respectively. Note: Values shown represent the price or differential to a reference price (netback price) at the point of sale. WDA (1) 176,629 /d 209,600 /d 208,000 /d
Slide 51: Natural Gas Hedge Positions
Natural Gas Hedge Positions (Volumes in thousands Mmbtu; Prices in $/Mmbtu) Fiscal 2016 Fiscal 2017 Fiscal 2018 Fiscal 2019 Fiscal 2020 Volume Avg.Price Volume Avg.Price Volume Avg.Price Volume Avg.Price Volume Avg.Price NYMEX Swaps 44350 $3.94 29530 $4.2 20350 $3.62 11400 $3.39 2000 $3.49 Dominion
Slide 52: Crude Oil Hedge Positions
Crude Oil Hedge Positions Fiscal 2016 Fiscal 2017 Fiscal 2018 Volume Avg. Price Volume Avg. Price Volume Avg. Price Midway Sunset (MWSS) Swaps 36,000 $92.10 - - - - Brent Swaps 933,000 $95.18 384,000 $92.30 75,000 $91.00 NYMEX Swaps 456,000 $73.74 312,000 $54.20 - - Total 1,425,000 $88.24 696,000 $7
Slide 53: Utica/Point Pleasant: EDA Opportunities
Utica/Point Pleasant: EDA Opportunities Shell: Gee 11.2 MMcf/d PGE Currently Drilling Permitted Drilling Completed Producing Seneca Horizontal Shell: Neal 26.5 MMcf/d Other Operators DCNR Tract 001 Potential Future Location Covington Potential Future Location JKLM Currently Drilling PGE Seneca DCNR
Slide 54: Marcellus Type Curves: WDA
Estimated Cumulative Volumes YEAR CUM (MMCF) 1 1,466 2 2,334 3 2,989 4 3,510 5 3,933 6 4,289 7 4,596 8 4,866 9 5,108 10 5,325 EUR 8,400 Marcellus Type Curves: WDA
Slide 55: Marcellus Type Curves: EDA
Estimated Cumulative Volumes YEAR CUM (MMCF) 1 3,226 2 5,451 3 6,815 4 7,762 5 8,470 6 9,029 7 9,483 8 9,862 9 10,185 10 10,466 EUR 13,495 Marcellus Type Curves: EDA
Slide 56: Comparable GAAP Financial Measure Slides & Reconciliations
Comparable GAAP Financial Measure Slides & Reconciliations This presentation contains certain non-GAAP financial measures. For pages that contain non-GAAP financial measures, pages containing the most directly comparable GAAP financial measures and reconciliations are provided in the slides that fol
Slide 57: Reconciliation of Adjusted EBITDA to Consolidated Net Income
National Fuel Gas Company nate tue a Reconciliation of Adjusted EBITDA to Consolidated Net Income ($ Thousands) Fv2012 Fv2013, justed EBITDA S a77asT $397,129 $492,383 11474 9,386 168,540 usted 13,178 Corporate & A Other Adjusted EBITDA (92,346) $ 789s $ s 7,689 s 78,121) 8.963 (164,381) 1: Deprecia
Slide 58: Capital Expenditures Reconciliation
National Fuel Gas Company wd, a '$400,000-450,000 '$500,000-850,000 '$125,000-150,000 '$80,000-110,000 ay - ‘Total Capital Expenditures from Continuing Operations e105 ‘B7rse4 “$Ti7087 “$869,907 “$9000 $1,175000-7 280,000 Capital Expenditures from Discountinued Operations ‘Al Othor Capital Expenditu
Slide 59: Exploration & Production Segment Reconciliation
National Fuel Gas Company eae {to Experaton & Production Segment Het iceme (6 Mowana) Emir 8 ‘Septembor 38,2014 “Sotonte0,2008 ‘Septomber 30,2044 Hopaena— West ooet Tos caP— och WestCoast TouiESP Appabeha WestCoast Tot EAP— och West Coast TouIERP epoted GAAP aig 5 (weasiny $6206 $ (orm) I2HO4 «SBT |
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