Investor Presentation Q1 Fiscal 2019 Update January 31, 2019 Exhibit 99

National Fuel is committed to the safe and environmentally conscious development, transportation, storage, and distribution of natural gas and oil resources. For additional information, please visit our corporate responsibility website at https://responsibility.natfuel.com

Developing our large, high quality acreage position in Marcellus & Utica shales(1) NFG: A Diversified, Integrated Natural Gas Company Providing safe, reliable and affordable service to customers in WNY and NW Pa. Upstream Exploration & Production Midstream Gathering Pipeline & Storage 38% of NFG EBITDA(1) Downstream Utility Energy Marketing % of NFG 20EBITDA(1) Expanding and modernizing pipeline infrastructure to provide outlets for Appalachian natural gas production 785,000 Net acres in Appalachia 492 MMcf/day Net Appalachian natural gas production $1.6 Billion Investments since 2010 4.2 MMDth Daily interstate pipeline capacity under contract 750,000 Utility Customers $300 Million Investments in safety since 2014 California: oil production generates significant cash flow (1) This presentation includes forward-looking statements. Please review the safe harbor for forward looking statements on slide 55 of this presentation. (2) Twelve months ending December 31, 2018. 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.. 42% of NFG EBITDA(2) 36% of NFG EBITDA(2) 22% of NFG EBITDA(2) :

Why National Fuel? Large Appalachian Footprint Driving Significant Growth

Integrated Model Enhances Shareholder Value Operational scale Lower cost of capital Lower operating costs More efficient capital investment More competitive pipeline infrastructure projects Ability to adjust to changing commodity price environments Higher returns on investment Strong balance sheet Growing, stable dividend Geographic and Operational Integration Drives Synergies: Upstream and Midstream Co-Development of Marcellus and Utica Installation of just-in-time gathering facilities Expansion of pipeline transmission infrastructure to reach demand markets Midstream and Downstream Rate-regulated entities reduce operating expenses by sharing common resources Utility and Energy Marketing segments are significant Pipeline & Storage customers 1 Benefits of National Fuel’s Integrated Structure: Financial Efficiencies: Investment grade credit rating Shared borrowing capacity Consolidated income tax return Downstream Utility Energy Marketing Midstream Gathering Pipeline & Storage Upstream Exploration & Production

Nearly 50 Years of Consecutive Dividend Increases $2.9 Billion Dividend payments since 1970 $1.70 per share 48 Years Consecutive Dividend Increases $0.19 per share 116 Years Consecutive Payments 3.0% yield(1) As of January 29, 2019. 2

1 Production and Gathering Growth of 15-20% Through 2022 Production Growth Supported by Firm Transportation Portfolio (1) Production trend line represents 17.5% net growth, on average, from fiscal 2018 through fiscal 2022 15-20% Production CAGR(1) Production Growth Drives Significant Increase in Gathering Revenues E&P 3 (2) Revenue trend line represents 17.5% growth, on average, from fiscal 2018 through fiscal 2022

Utilization of Existing Infrastructure for Ongoing Utica Development Amplifies Consolidated Returns L Leveraging Existing Infrastructure to Enhance Returns Approximate WDA Marcellus gathering facility costs for 192 wells drilled and completed as of September 30, 2018. Estimated WDA Utica gathering facility costs for the assumed 120 well locations in Clermont Rich Valley area of redevelopment. Internal Rate of Return for Seneca WDA includes estimated well costs under current cost structure, and anticipated LOE and Gathering costs. Internal Rate of Return for Seneca WDA and Gathering includes expected gathering capital expenditures through FY 2022, well costs under current cost structure, and non-gathering LOE. Gathering CapEx/Well ($ thousands) Marcellus (pre-2019) $1,489(1) Utica (2019-2022) $392(2) Gathering Pipelines Compression Water Handling Facilities Roadways and Pads Gathering Costs in Western Development Area (CRV) 10+% IRR Uplift Expected(3) Requires modest investment in new Gathering facilities to support production growth Utica development on Marcellus pads allows use of existing: Resulting in significant consolidated return uplift for E&P and Gathering 4

$1 Billion+ Backlog in Pipeline & Storage Projects Line N to Monaca - $23 MM (July 2019)(1) Empire North - $145 MM (second half of fiscal 2020) FM100 - $280 MM (late calendar 2021) Companion project to Seneca-anchored Leidy South project Northern Access - $500 MM (as early as fiscal 2022) Supply Corp. Modernization - $150 - $250 MM (fiscal 2019-2022) FUTURE INVESTMENTS = $1.1 – $1.2 Billion FUTURE EXPANSION REVENUES = ~$150 Million Line N to Monaca Northern Access FM100 Empire North 5 (1) Parentheticals represent target in-service dates for the respective expansion projects.

Financial Highlights First Quarter Fiscal 2019

Net Oil and Gas Production First Quarter Fiscal 2019 Results and Drivers Adjusted Operating Results ($/share)(1) Adjusted Operating results of $1.02 for Q1 Fiscal 2018 and $1.12 for Q1 Fiscal 2019 include operating results of Energy Marketing and Corporate & All Other segments. See slide 61 for a Reconciliation of Adjusted Operating Results to Earnings Per Share. Realized price after hedging. Oil and Gas Pricing(2) Natural Gas ($/Mcfe) Crude Oil ($/Bbl) Oil Prices Natural Gas Prices Gathering Revenue ($MM) Increased Seneca Natural Gas Production Drivers Natural Gas Production Oil Production (sale of Sespe field) Crude Oil (Mbbl) Natural Gas (Bcf)

Earnings Guidance FY2018 Adjusted Operating Results Non-regulated Businesses Exploration & Production Gathering $3.34 /share(1) $3.45 to $3.65 /share FY2019 Earnings Guidance Seneca Net Production: 210 to 230 Bcfe Gathering Revenues: $130-140 million Natural Gas: ~$2.45/Mcf(2) (vs. $2.52/Mcf in FY 2018) Crude Oil: ~$59/Bbl(3) (vs. $58.66/Bbl in FY 2018) Key Guidance Drivers Excludes the $103.5 million, or $1.20 per share, reduction in tax expense due to the remeasurement of deferred taxes resulting from the 2017 Tax Reform Act. See non-GAAP disclosure on slide 61 of this presentation. Assumes NYMEX natural gas pricing of $3.25/MMBtu (winter) and $2.75/MMBtu (summer) and basin spot pricing of $2.75/MMBtu (winter) and $2.25/MMBtu (summer) for FY19, and reflects the impact of existing financial hedges, firm sales and firm transportation contracts. Assumes NYMEX (WTI) oil pricing of $55.00/Bbl and California-MWSS pricing differentials of 102% to WTI for FY19, and reflects impact of existing financial hedge contracts. Production & Gathering Throughput Realized natural gas prices (after-hedge) Utility Operating Income Regulated Businesses Pipeline & Storage Utility Guidance assumes normal weather; modestly higher gross margin expected to be offset by cost inflation ~$285 million in revenues (expected decrease primarily due to expiration of contract on Empire system) Pipeline & Storage Revenues Tax Reform Realized oil prices (after-hedge) Lower effective tax rate Effective tax rate ~24-25% (federal rate 21%)

Exploration & Production and Gathering Overview Seneca Resources Company, LLC ~ National Fuel Gas Midstream Company, LLC

Proved Reserves 361% Reserve Replacement Rate Seneca Drill-bit F&D = $0.66/Mcfe(1) Appalachia Drill-bit F&D = $0.65/Mcfe(1) Seneca “Drill-bit” finding and development (“F&D”) costs exclude the impact of reserve revisions. Total Proved Reserves (Bcfe) Fiscal 2018 Proved Reserves Stats 3-Year Average F&D Cost ($/Mcfe) E&P and Gathering

3 rig development program, with second rig in WDA focused on Utica 15-20% net production growth expected through fiscal 2022 New EDA Utica development with production expected in Q2 fiscal 2019 Utilize new Atlantic Sunrise firm transportation capacity Layer-in firm sales to take advantage of attractive regional pricing Gross production growth will benefit NFG’s Gathering segment Minimal capital investment in California to generate significant cash flow Growing Production within Disciplined Capital Program Near-Term Growth Strategy E&P Net Capital Expenditures ($ millions)(1) E&P Net Production (Bcfe) E&P and Gathering A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation. FY16, FY17, and FY18 guidance reflects the netting of $157 million, $7 million and $17 million, respectively, of up-front proceeds received from joint development partner for working interest in joint development wells.

Significant Appalachian Acreage Position Average gross production: ~311 MMcf/d Mostly leased (16-18% royalty) with no significant near-term lease expirations ~90 remaining Marcellus & Utica locations economic at ~$1.84/Mcf Additional Marcellus (Tioga Co.) & Geneseo (Lycoming Co.) potential Eastern Development Area (EDA) Western Development Area (WDA) Average gross production(1): ~327 MMcf/d Large inventory of Marcellus & Utica locations economic at ~$2.00/Mcf Royalty free mineral ownership enhances well economics Highly contiguous nature drives cost and operational efficiencies E&P and Gathering EDA - 70,000 Acres WDA - 715,000 Acres (1) Average EDA and WDA gross production, as well as WDA-CRV Utica production (see slide 19) and Covington/Tract 595 Production (see slide 23), is for the quarter ended December 31, 2018.

Western Development Area Marcellus Core Acreage vs. Utica Appraisal Trend(1) The Utica Shale lies approximately 5,000 feet beneath Seneca’s WDA Marcellus acreage. Appraisal program currently in progress. Additional tests are planned. Prior Marcellus delineation tests helped define the prospective limits of the Marcellus core acreage; planned testing in the Utica expected to do the same. Area of Re-Development ~120 Utica locations on existing Marcellus pads ? Key Utica tests Past Marcellus delineation tests Utica Trend (currently evaluating) Marcellus Core Acreage Large well inventory economic at ~$2.00 /Mcf Marcellus Shale: 600+ well locations remaining / 200,000 acres Utica Shale: 500+ potential locations across Utica trend / evaluating extent of prospective acreage(2) Fee acreage (no royalty) enhances economics and provides development flexibility Addition of 2nd WDA drilling rig in Q3 FY18 focused on redevelopment of Clermont-Rich Valley acreage for Utica Use of existing gathering, pad, and water infrastructure for Utica drives increased Appalachian program returns Highly contiguous position drives best in class well costs Utica test results on trend with other Utica wells in NE Pa. Long-term firm contracts support growth Boone Mountain Utica Test Well 2.3 Bcf /1,000ft Rich Valley Utica Test Well 2.3 Bcf /1,000ft E&P and Gathering WDA Highlights

WDA Utica Appraisal Results and Initial Type Curve Tested / producing from 17 Utica wells in WDA-CRV Higher pressure significantly enhances well productivity (Utica ~5,000’ deeper than Marcellus) Drawdown management is critical: restricted drawdown appears to improve well EURs Early production declines much shallower vs. Marcellus WDA Utica Appraisal Update WDA Economics Internal Rate of Return (IRR) is pre-tax and includes estimated well costs under current cost structure, LOE, and anticipated gathering tariffs. Initial WDA-CRV Utica type curve based on production results and reservoir expectations from the first 5 appraisal wells in the WDA-CRV area. WDA-CRV Utica Average includes all 17 producing wells, including 2 wells (pad E09-S) for which drawdown management was not used. E&P and Gathering EUR Bcf/1000’ Well Cost $M/1000’ IRR % $2.25 Break-even 15% IRR(1) Utica - CRV 1.7 $887 23% $1.97 Marcellus 1.0 – 1.1 $643 19% $2.06 (2)

Transitioning to Utica Development in CRV WDA-CRV Marcellus (Depth ~7,000 feet) WDA-CRV Utica (Depth ~12,000 feet) Avg. CRV Marcellus Production: 270 MMcf/d Rem. Avg. EUR 1.0-1.1 Bcf / 1,000 lat ft. Rem. Avg. Well Costs = $643/lat ft. 120+ locations on existing Marcellus pads Est. EURs 1.7 Bcf / 1,000 lat ft. Est. Development Well Costs = $887/lat ft. CRV Utica Transition Plan Finish Marcellus Pads in Development Drill 24 / complete 24 Marcellus wells Continue Optimizing Utica D&C design Additional optimization wells focusing on: Completion design Landing zone targets Continue transition to Utica development Future drilling on multi-well pads Continue using optimization results to determine development well design Tailor development plan to use existing pad, water and gathering infrastructure CRV Utica Development Utilizes Existing Pad, Water, and Gathering Infrastructure to Drive Economics E&P and Gathering Rich Valley Utica Test Existing Line Leased Seneca Fee Producing FY19 Producer Development

Leveraging Existing Gathering, Water and Pad Infrastructure Enhances Returns Limited New Infrastructure Needed to Support Production Growth WDA Well Costs(1) WDA Consolidated Economics Steady activity levels and coordination between upstream and midstream activities enhance returns, provide economies of scale and significant operational flexibility WDA Marcellus well costs reflect drilling, completion & gathering costs for 192 drilled and completed wells as of 9/30/18. WDA Utica well costs reflect expected drilling, completion & gathering costs for the ~120 well locations in area of redevelopment. Internal Rate of Return for Seneca WDA includes estimated well costs under current cost structure, and anticipated LOE and Gathering costs. Internal Rate of Return for Seneca WDA and Gathering includes expected gathering capital expenditures through FY 2022, well costs under current cost structure, and non-gathering LOE. Total cost per well expected to marginally increase WDA EURs At a $2.25 netback price, consolidated Seneca WDA and Gathering IRR is approximately 33%, an uplift of ~12% over standalone Seneca WDA economics(2) 10+% IRR Uplift Expected

Integrated Development – WDA Gathering System Current System In-Service ~78 miles of pipe / 36,220 HP of compression Current Capacity: 470 MMcf per day Interconnects with TGP 300 Total Investment to Date: $301 million Future Build-Out FY 2019 CapEx: $10 - $15 million Modest gathering pipeline and compression investment required to support Seneca’s transition to Utica development Opportunity for 300 miles of pipelines and five compressor stations (+60,000 HP installed) as Seneca’s drilling activity continues Deliverability into TGP 300 and NFG Supply Gathering System Build-Out Tailored to Accommodate Seneca’s WDA Development Clermont Gathering System Map E&P and Gathering

WDA Firm Transportation and Sales Capacity Will continue to layer-in firm sales deals of short and longer duration on TGP 300 to reduce spot exposure WDA spot realizations track TGP Station 313 pricing, typically 10¢ - 30¢ better than TGP Marcellus Zone 4 Leidy South will provide additional capacity to premium markets (Transco Zone 6) WDA Exit Capacity Supports Long-term Production Growth and Enhances Consolidated Returns WDA Contracted Firm Transport and Gross Sales Volumes (MDth/d) Seneca gross production trend E&P and Gathering Niagara Expansion Project (TGP and NFG) FT Capacity: 158,000 Dth/d @ $0.67/Dth Firm Sales: NYMEX & DAWN WDA - TGP 300 Firm Sales Leidy South Transco Zone 6 Markets 330,000 Dth/d(1) Will layer-in firm sales to minimize spot exposure Portion of Transco Project capacity will likely be utilized by EDA Lycoming County production. WDA Gas Marketing Strategy

Eastern Development Area EDA Acreage – 70,000 Acres EDA Highlights 1 DCNR Tract 007 (Tioga Co., Pa) Utica development resumed in third quarter fiscal 2018 ~43 remaining Utica locations economic at ~$1.84 /Mcf Gathering Infrastructure: NFG Midstream Wellsboro Marcellus Shale expected to provide ~60 additional locations E&P and Gathering 2 1 3 2 Covington & DCNR Tract 595 (Tioga Co., Pa.) Marcellus locations fully developed (average daily gross production of ~93 MMcf/d) Gathering Infrastructure: NFG Midstream Covington Opportunity for future Utica appraisal 3 DCNR Tract 100 & Gamble (Lycoming Co., Pa.) ~45 remaining Marcellus locations economic at ~$1.53 /Mcf Firm Transportation Capacity: Atlantic Sunrise (189 MDth/d) Gathering Infrastructure: NFG Midstream Trout Run Geneseo Shale expected to provide 100-120 additional locations

EDA Marcellus: Lycoming County Development Marcellus Development in Lycoming County has Resumed in Connection with Atlantic Sunrise Includes physical fixed price and NYMEX-based firm sales contracts that do not carry any additional transportation costs. E&P and Gathering Prolific Marcellus acreage with peer leading well results ~45 remaining Marcellus locations economic at ~$1.53 /Mcf Near-term development focused on filling Atlantic Sunrise capacity Existing Line Leased Seneca Fee Producing FY19 Producer Development Transco Firm Sales(1)

EDA Utica: Tioga County Development Utica Development in Tioga County – Tract 007 Development Resumed in Q3 Fiscal 2018 In-Service November 2016 Lateral Length 4,640 ft 30 Day IP /1,000 ft 3.4 MMcf/d Est. EUR /1,000 ft 2.4 Bcf Inventory: ~43 locations economic at ~$1.84 /Mcf Targeting to grow production by 100 to 150 MDth/d by fiscal 2020 Expected Development Costs: $1,045 per lateral ft. Gathering Infrastructure: NFG Midstream Wellsboro Modest build-out required to connect to TGP 300 Sales/Takeaway Strategy: Layer-in firm sales with shippers holding capacity on TGP 300 Includes physical fixed price and NYMEX-based firm sales contracts that do not carry any additional transportation costs. Tract 007 Utica Appraisal Well Results vs. Industry E&P and Gathering Northeast Supply Diversification Project FT Capacity: 50,000 Dth/d @ $0.50/Dth Firm Sales: NYMEX and DAWN EDA - TGP 300 Firm Sales(1)

Integrated Development – EDA Gathering Systems Total Investment (to date): ~$46 million FY 2019 Estimated Capital Expenditures: $1 MM - $2 MM Capacity: 220,000 Dth per day (Interconnect w/ TGP 300) Production Source: Seneca Resources – Tioga Co. (Covington and DCNR Tract 595) Total Investment (to date): ~$208 million FY 2019 Estimated Capital Expenditures: $25 MM - $35 MM Capacity: 466,000 to 585,000 Dth per day (Interconnect w/ Transco) Production Source: Seneca Resources – Lycoming Co. (DCNR Tract 100 and Gamble) Future third-party volume opportunities Covington Gathering System Trout Run Gathering System Gathering Segment Supporting Seneca’s EDA Production & Future Development Wellsboro Gathering System Total Investment (to date): ~$14 million FY 2019 Estimated Capital Expenditures: $8 MM - $15 MM Capacity: up to 200,000 Dth per day (Interconnect w/ TGP 300) Production Source: Seneca Resources – Tioga Co. (DCNR Tract 007) E&P and Gathering 2 1 3

Long-term Contracts Supporting Appalachian Growth Represents base firm sales contracts not tied to firm transportation capacity. Base firm sales are either fixed priced or priced at an index (e.g., NYMEX ) +/- a fixed basis and do not carry any transportation costs. Seneca continues to layer-in firm sales contracts with attractive realizations to lock-in drilling economics and minimize spot exposure ahead of firm transportation in-service dates E&P and Gathering FY 2019 FY 2020 15% - 20% Gross Production CAGR FY 2021 FY 2022 Northeast Supply Diversification 50,000 Dth/d Niagara Expansion (TGP & NFG) Delivery Markets: Canada-Dawn & TETCO 158,000 Dth/d Atlantic Sunrise (Transco) Delivery Markets: Mid-Atlantic & Southeast U.S. 189,405 Dth/d In-Basin Firm Sales Contracts(1) Leidy South (Transco & NFG) Transco Zone 6 Markets 330,000 Dth/d Seneca Appalachia Natural Gas Marketing Gross Firm Contract Volumes (Mdth/day)

Near-term Firm Sales Provide Market & Price Certainty Net Contracted Firm Sales Volumes (Dth per day) Contracted Index Price Differentials ($ per Dth)(1) Values shown represent the weighted average fixed price or contracted fixed differential relative to NYMEX (netback price) less any associated transportation costs. Actual Daily Net Production 641,200 716,500 708,700 693,500 708,400 674,400 667,000 Gross Firm Sales Volumes (Dth/d) E&P and Gathering

California Oil Stable Oil Production | Minimal Capital Investment | Steady Free Cash Flow 1 2 3 4 5 Location Formation Production Method FY18 Daily Production (net Boe/d) 1 East Coalinga/ Other Temblor Primary 512 2 North Lost Hills Tulare & Etchegoin Primary/ Steam flood 892 3 South Lost Hills Monterey Shale Primary 1,359 4 North Midway Sunset Tulare & Potter Steam flood 2,786 5 South Midway Sunset Antelope Steam flood 2,048 TOTAL WEST DIVISION NET PRODUCTION(1) 7,597 Boe/d E&P and Gathering (1) West division net production for FY 2018 excludes production from Sespe field, which was divested on May 1, 2018.

California Capital Expenditures vs. Production West Division Average Net Daily Production (Boe) West Division Annual Capital Expenditures ($ MM)(1) Guidance Guidance Seneca West Division capital expenditures includes Seneca corporate and eliminations. E&P and Gathering Sepse Sale Closed on 5/1/18 (reduced production by ~900 boe/d)

Pioneer South MWSS Acreage North MWSS Acreage Sec. 17N California Development Activities Modest near-term capital program focused on locations that earn attractive returns in current oil price environment A&D will focus on low cost, bolt-on opportunities Sec. 17, Pioneer, and East Coalinga development to provide future growth Midway-Sunset North Project IRRs at $55/Bbl(1) Reflects pre-tax IRRs at a $55/Bbl WTI. E&P and Gathering Seneca West Economics South East Coalinga North South

Fiscal 2019 Production and Price Certainty Average realized price reflects uplift from financial hedges less fixed differentials under firm sales contracts and any firm transportation costs. Indicates firm sales contracts with fixed index differentials but not backed by a matching financial hedge. 114 Bcf locked-in realizing net ~$2.41/Mcf (1) 29 Bcf of additional basis protection Spot production assumed to be sold at ~$2.75/Mmbtu (winter) and ~$2.25 (summer) 143 Bcf of Appalachian Production Protected by Firm Sales for Remainder of Year 79% of oil production hedged at $57.57 /Bbl E&P and Gathering

Strong Hedge Book Natural Gas Swap & Fixed Physical Sales Contracts (Millions MMBtu) Fixed price physical sales exclude joint development partner’s share of fixed price contract WDA volumes as specified under the joint development agreement. Reflects percentage of projected production for FY19 hedged at the midpoint of the production guidance range. Seneca’s remainder FY19 Production reflects the total FY19 production guidance of 210-230 Bcfe, or 220 Bcfe at the midpoint, less Q1 actual production. Crude Oil Swap Contracts (Thousands Bbls) FY 2019 Remaining Production (3) E&P and Gathering (1) FY 2019 Remaining Production (3) FY 19 Nat Gas 71% Hedged (2)

Seneca Operating Costs Competitive, low cost structure in Appalachia and California supports strong cash margins Gathering fee generates significant revenue stream for affiliated gathering company Seneca DD&A Rate $/Mcfe Appalachia LOE & Gathering $/Mcfe California LOE $/Boe Total Seneca Cash OpEx $/Mcfe (1) (2) (2) G&A estimate represents the midpoint of the G&A guidance range of $0.25 to $0.35 for fiscal 2019. The total of the two LOE components represents the midpoint of the LOE guidance range of $0.85 to $0.90 for fiscal 2019. E&P and Gathering

Seneca’s Continuing Commitment to the Environment Produced Water Recycled in Appalachia 100% 70% Recycled Water Used in New Shale Well Completions Water and Fluids Management Air Quality and Emissions Seneca Resources Water Operations Fiscal 2018 Seneca Resources Remains Focused on Minimizing GHG Emissions The Environmental Partnership EPA Natural Gas Star Program Green Completions (all fiscal 2018 wells) Ultrasonic Leak Detection Technology Emissions Controls Rig and Vehicle Fuel Conversion Integrating Renewable Energy into Operations E&P and Gathering

Pipeline and Storage Overview National Fuel Gas Supply Corporation ~ Empire Pipeline, Inc.

Pipeline & Storage Segment Overview As of September 30, 2018 as disclosed in the Company’s fiscal 2018 form 10-K. As of December 31, 2017 calculated from National Fuel Gas Supply Corporation’s and Empire Pipeline, Inc.’s 2017 FERC Form-2 reports, respectively. Empire Pipeline, Inc. National Fuel Gas Supply Corporation Empire Pipeline Supply Corp. Contracted Capacity(1): Firm Transportation: 3,187 MDth per day Firm Storage: 71,938 Mdth (fully subscribed) Rate Base(2): ~$820 million FERC Rate Proceeding Status: Rate case settlement extension approved Nov. ‘15 Rate case filing expected by 7/31/19 Contracted Capacity(1): Firm Transportation: 978 MDth per day Firm Storage: 3,753 Mdth (fully subscribed) Rate Base(2): ~$249 million FERC Rate Proceeding Status: Rate case settlement in principle reached on 12/21/18; FERC approval pending New transportation rates went into on 1/1/19 Pipeline & Storage

All Seneca volumes will flow through wholly-owned NFG gathering facilities FM100 Project - Consolidated Benefit for NFG 330,000 Dth/d of new transportation capacity from WDA and EDA acreage positions to premium markets New Transco capacity (Leidy South): 330,000 Dth/day Rate(1) : competitive with other expansion project rates in Seneca’s current transportation portfolio Delivery Point(s): Transco Zone 6 interconnections Seneca Lease to Transco of new capacity: 330,000 Dth/day Estimated annual lease revenues: ~$35 million Target In-Service: late calendar year 2021 Supply Corp. Project expected to provide long-term earnings uplift to Seneca, Supply Corp. and Gathering Pipeline & Storage Gathering (1) Includes lease of new capacity from Supply Corp. to Transco.

FM100 Project – Significant Investment by Supply Corp. Pipeline & Storage Estimated Capital Cost: $280 million(1) Facilities (all in Pennsylvania) include: Approximately 30 miles of new pipeline 2 new compressor stations (totaling approximately 37,000 HP) New interconnection station and modification of existing interconnection station Abandonment of approximately 45 miles of existing pipeline and compressor station Regulatory Process: Pre-filing application submitted to FERC in 2017 for original modernization project FERC 7(b) / 7(c) filing expected summer 2019 (1) Includes expansion and modernization portions of the project.

Empire North Project Target In-Service: second half of fiscal 2020 Est. Capital Cost: $145 million Est. Annual Revenues: ~$25 million Receipt Point: Jackson (Tioga Co., Pa. production) Design Capacity and Delivery Points: 175,000 Dth/d to Chippawa (TCPL interconnect) 30,000 Dth/d to Hopewell (TGP 200 interconnect) Customers: Fully subscribed (205,000 Dth/day) Major Facilities: 2 new compressor stations in NY (1) & Pa. (1) No new pipeline construction Regulatory Process: FERC 7(c) application filed on 2/16/18 FERC Environmental Assessment issued 10/30/18 Pipeline & Storage Fully Subscribed Project will Provide 205,000 Dth/day of Incremental Firm Transportation

National Fuel Remains Committed to Northern Access Project Target In-Service: as early as fiscal 2022 Total Cost: ~$500MM (~$76MM spent to date) Estimated Annual Revenues: ~$84 million Delivery Points: 350,000 Dth/d to Chippawa (TCPL interconnect) 140,000 Dth/d to Hopewell (TGP 200 line) Regulatory Status: February 3, 2017 – FERC 7(c) certificate issued August 6, 2018 – FERC issued Order finding that NY DEC waived water quality certification Supply and Empire currently working to finalize remaining federal authorizations Pipeline & Storage To Dawn NE US (TGP 200)

Continued Expansion of the NFG Supply System Line N Expansion Opportunities Line N to Monaca Project Project: Firm transportation service to a new ethane cracker facility being built by Shell Chemical Appalachia, LLC Target In-Service: July 2019 Estimated Capital Cost: $23 million Contracted Capacity: 133,000 Dth/day Additional Line N Expansion Opportunity (Supply OS #221) Project: New firm transportation service for on-system demand Open Season Capacity: Awarded 165,000 to foundation shipper. Precedent agreement in negotiations. Pipeline & Storage

Pipeline & Storage Customer Mix 4.2 MMDth/d Contracted as of 10/31/2018. Customer Transportation by Shipper Type(1) Affiliated Customer Mix (Contracted Capacity) Firm Transport Pipeline & Storage

Utility Overview National Fuel Gas Distribution Corporation

New York & Pennsylvania Service Territories New York Total Customers(1): 535,800 ROE: 8.7% (NY PSC Rate Case Order, April 2017) Rate Mechanisms: Revenue Decoupling Weather Normalization Low Income Rates Merchant Function Charge (Uncollectibles Adj.) 90/10 Sharing (Large Customers) System Modernization Tracker Pennsylvania Total Customers(1): 214,400 ROE: Black Box Settlement (2007) Rate Mechanisms: Low Income Rates Merchant Function Charge As of September 30, 2018. Utility

New York Rate Case Outcome Rate Order Summary: Revenue Requirement:$5.9 million Rate Base:$704 million Allowed Return on Equity (ROE):8.7% Capital Structure:42.9% equity Other notable items: New rates became effective 5/1/17 Retains rate mechanisms in place under prior order (revenue decoupling, weather normalization, merchant function charge, 90/10 large customer sharing) No stay-out clause System modernization tracker for Leak Prone Pipe (LPP) Earnings sharing started 4/1/18 (50/50 sharing starts at earnings in excess of 9.2%) Article 78 appeal filed on 7/28/17, with oral argument completed in January 2019 On April 20, 2017, the New York Public Service Commission issued a Rate Order relating to NFG Distribution’s rate case (No. 16-G-0257) filed in April 2016. Utility

Utility Continues its Significant Investments in Safety Modernization Spending in NY Expected to Grow Gross Margin By $2 MM - $5 MM in FY 2019 (1) A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation. Utility System modernization tracker in NY allows recovery of pipeline replacement costs, which is expected to drive modest gross margin and rate base growth

Accelerating Pipeline Replacement & Modernization NY 9,726 miles PA* 4,830 miles * No Cast Iron Mains in Pa.* Miles of Utility Main Pipeline Replaced Utility Mains by Material(1) Utility (1) All values are reported on a calendar year basis as of December 31, 2018.

A Proven History of Controlling Costs O&M Expense ($ millions) Utility (1) (1) For purposes of comparability to FY 2015, 2016 and 2017, Utility Operation and Maintenance Expense for FY 2018 and the twelve months ended December 31, 2018 was adjusted by approximately $31.4 million and $31.2 million, respectively, to include non-service pension costs, which were re-classified as Other Income (Deductions) as of October 1, 2018 on the Company’s Income Statement. See Slide 64 for non-GAAP reconciliation of Adjusted Operation and Maintenance Expense to Operation and Maintenance Expense, by segment.

Consolidated Financial Overview Upstream I Midstream I Downstream

Adjusted Operating Results ($ per share)(1) Diversified, Balanced Earnings and Cash Flows A reconciliation of Adjusted Operating Results to Earnings per Share, by segment, as presented on the Consolidated Statement of Income and Earnings Reinvested in the Business is included at the end of this presentation Consolidated Adjusted EBITDA includes Energy Marketing, and Corporate & All Other Segments. A reconciliation of Adjusted EBITDA to Net Income, by segment, as presented on the Consolidated Statement of Income and Earnings Reinvested in the Business is included at the end of this presentation Adjusted EBITDA ($ millions)(2) Rate Regulated 40-45% $728 Rate Regulated ~46%

Disciplined, Flexible Capital Allocation (2) Total Capital Expenditures include Energy Marketing, Corporate and All Other. A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation. FY16, FY17, and FY18 reflects the netting of $157 million, $7 million, and $17 million, respectively, of up-front proceeds received from joint development partner for working interest in joint development wells, and $21M in intercompany asset transfers in FY18. Capital Expenditures by Segment ($ millions)(1)

Maintaining Strong Balance Sheet & Liquidity Total Debt 51% $4.2 Billion Total Capitalization as of December 31, 2018 Net Debt / Adjusted EBITDA(1) Capitalization Debt Maturity Profile ($MM) Liquidity Committed Credit Facilities Short-term Debt Outstanding Available Short-term Credit Facilities Cash Balance at 12/31/18 Total Liquidity at 12/31/18 $ 750 MM 0 MM 750 MM 110 MM $ 860 MM Net Debt is net of cash and temporary cash investments. Reconciliations of Net Debt and Adjusted EBITDA to Net Income are included at the end of this presentation.

Appendix

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, strategies, future events or performance and underlying assumptions, capital structure, anticipated capital expenditures, completion of construction projects, projections for pension and other post-retirement benefit obligations, impacts of the adoption of new accounting rules, and possible outcomes of litigation or regulatory proceedings, as well as statements that are identified by the use of the words “anticipates,” “estimates,” “expects,” “forecasts,” “intends,” “plans,” “predicts,” “projects,” “believes,” “seeks,” “will,” “may,” and similar expressions. Forward-looking statements involve risks and uncertainties which could cause actual results or outcomes to differ materially from those expressed in the forward-looking statements. The Company’s expectations, beliefs and projections are expressed in good faith and are believed by the Company to have a reasonable basis, but there can be no assurance that management’s expectations, beliefs or projections will result or be achieved or accomplished. In addition to other factors, the following are important factors that could cause actual results to differ materially from those discussed in the forward-looking statements: delays or changes in costs or plans with respect to Company projects or related projects of other companies, including difficulties or delays in obtaining necessary governmental approvals, permits or orders or in obtaining the cooperation of interconnecting facility operators; governmental/regulatory actions, initiatives and proceedings, including those involving rate cases (which address, among other things, target rates of return, rate design and retained natural gas), environmental/safety requirements, affiliate relationships, industry structure, and franchise renewal; changes in laws, regulations or judicial interpretations to which the Company is subject, including those involving derivatives, taxes, safety, employment, climate change, other environmental matters, real property, and exploration and production activities such as hydraulic fracturing; financial and economic conditions, including the availability of credit, and occurrences affecting the Company’s ability to obtain financing on acceptable terms for working capital, capital expenditures and other investments, including any downgrades in the Company’s credit ratings and changes in interest rates and other capital market conditions; changes in the price of natural gas or oil; impairments under the SEC’s full cost ceiling test for natural gas and oil reserves; factors affecting the Company’s ability to successfully identify, drill for and produce economically viable natural gas and oil reserves, including among others geology, lease availability, title disputes, weather conditions, shortages, delays or unavailability of equipment and services required in drilling operations, insufficient gathering, processing and transportation capacity, the need to obtain governmental approvals and permits, and compliance with environmental laws and regulations; increasing health care costs and the resulting effect on health insurance premiums and on the obligation to provide other post-retirement benefits; changes in price differentials between similar quantities of natural gas or oil sold at different geographic locations, and the effect of such changes on commodity production, revenues and demand for pipeline transportation capacity to or from such locations; other changes in price differentials between similar quantities of natural gas or oil having different quality, heating value, hydrocarbon mix or delivery date; the cost and effects of legal and administrative claims against the Company or activist shareholder campaigns to effect changes at the Company; uncertainty of oil and gas reserve estimates; significant differences between the Company’s projected and actual production levels for natural gas or oil; changes in demographic patterns and weather conditions; changes in the availability, price or accounting treatment of derivative financial instruments; changes in laws, actuarial assumptions, the interest rate environment and the return on plan/trust assets related to the Company’s pension and other post-retirement benefits, which can affect future funding obligations and costs and plan liabilities; changes in economic conditions, including global, national or regional recessions, and their effect on the demand for, and customers’ ability to pay for, the Company’s products and services; the creditworthiness or performance of the Company’s key suppliers, customers and counterparties; the impact of potential information technology, cybersecurity or data security breaches; economic disruptions or uninsured losses resulting from major accidents, fires, severe weather, natural disasters, terrorist activities or acts of war; significant differences between the Company’s projected and actual capital expenditures and operating expenses; or increasing costs of insurance, changes in coverage and the ability to obtain insurance. Forward-looking statements include estimates of oil and gas quantities. Proved oil and gas reserves are those quantities of oil and gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible under existing economic conditions, operating methods and government regulations. Other estimates of oil and gas quantities, including estimates of probable reserves, possible reserves, and resource potential, are by their nature more speculative than estimates of proved reserves. Accordingly, estimates other than proved reserves are subject to substantially greater risk of being actually realized. Investors are urged to consider closely the disclosure in our Form 10-K available at www.nationalfuelgas.com. You can also obtain this form on the SEC’s website at www.sec.gov. For a discussion of the risks set forth above and other factors that could cause actual results to differ materially from results referred to in the forward-looking statements, see “Risk Factors” in the Company’s Form 10-K for the fiscal year ended September 30, 2018 and the Forms 10-Q for the quarter ended March 31, 2018, June 30, 2018, and December 31, 2018. The Company disclaims any obligation to update any forward-looking statements to reflect events or circumstances after the date thereof or to reflect the occurrence of unanticipated events. Appendix

Hedge Positions and Prices Fixed price physical sales exclude joint development partner’s share of fixed price contract WDA volumes as specified under the joint development agreement. (1) Appendix Natural Gas Volumes in thousand MMBtu; Prices in $/MMBtu Fiscal 2019 Fiscal 2020 Fiscal 2021 Fiscal 2022 Fiscal 2023 Volume Avg.Price Volume Avg.Price Volume Avg.Price Volume Avg.Price Volume Avg.Price NYMEX Swaps 60120 $2.93 18640 $3.04 4840 $3.01 - - - - Dawn Swaps 5400 $3 7200 $3 600 $3 - - - - Fixed Price Physical 51914.991000000002 $2.68 45045.881999999998 $2.34 41487.601000000002 $2.2200000000000002 40579.694000000003 $2.23 40589.264999999999 $2.23 Total 117434.99100000001 $2.82 70885.881999999998 $2.59 46927.601000000002 $2.31 40579.694000000003 $2.23 40589.264999999999 $2.23 Crude Oil Volumes & Prices in Bbl Fiscal 2019 Fiscal 2020 Fiscal 2021 Fiscal 2022 Fiscal 2023 Volume Avg. Volume Avg. Volume Avg. Volume Avg. Volume Avg. Price Price Price Price Price Brent Swaps 558000 $63.52 864000 $63.51 576000 $64.680000000000007 300000 $60.07 - - NYMEX Swaps 801000 $53.42 324000 $50.52 156000 $51 156000 $51 - - Total 1359000 $57.57 1188000 $59.96 732000 $61.61 456000 $56.97 - -

Appalachia Drilling Program Economics Net realized price reflects either (a) price received at the gathering system interconnect or (b) price received at delivery market net of firm transportation charges. 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. Large Marcellus and Utica Inventory Economic at ~$2.00/MMBtu(1) Appendix Prospect Reservoir Locations Remainingto Be Drilled Completed Lateral Length (ft) EUR / 1000' (Bcf) Well Cost$M/1,000 ft Internal Rate of Return % (2) Realized Price(1) Required for 15% IRR Anticipated DeliveryMarkets EUR / 1000' (Bcf) $2.50Realized $2.25Realized $2.00Realized EDA Tract 100 & GambleLycoming Co. Marcellus 45 4900 2.5 $1,057 0.76 0.57999999999999996 0.44 $1.53 Transco Leidy &Atlantic Sunrise Southeast US(NYMEX+) DCNR 007Tioga Co. Utica 43 8300 2 $1,045 0.49 0.36 0.22 $1.84 TGP 300 WDA Clermont Rich Valley Utica 120+ 9000 1.7 $887 0.3 0.23 0.16 $1.97 TGP 300, Niagara Expansion Canada (Dawn), & FM100/Leidy South (Transco Zone 6) Core Areas Marcellus 600+ 8500 1.0 to 1.1 $643 0.26 0.19 0.14000000000000001 $2.06 FY15Q3:

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 follow. The Company believes that its non-GAAP financial measures are useful to investors because they provide an alternative method for assessing the Company’s ongoing operating results and for comparing the Company’s financial performance to other companies. The Company’s management uses these non-GAAP financial measures for the same purpose, and for planning and forecasting purposes. The presentation of non-GAAP financial measures is not meant to be a substitute for financial measures prepared in accordance with GAAP. Management defines Adjusted Operating Results as reported GAAP earnings before items impacting comparability. The Company’s earnings guidance range does not include the impact of certain items that impacted the comparability of earnings during the first quarter, including: (1) the remeasurement of deferred income taxes resulting from the 2017 Tax Reform Act, which reduced the Company’s income tax expense and benefited consolidated earnings in the first quarter by $0.06 per share; (2) the full year impact of the Exploration and Production segment’s unrealized gain on hedging ineffectiveness, which increased earnings by $0.06 per share in the first quarter ($3.2 million, or $0.03 per share, of the unrealized gain relates to hedge contracts that will settle during the remaining nine months ending September 30, 2019); and (3) the unrealized loss on other investments due to the change in an accounting rule, which lowered earnings by $0.06 per share. While the Company expects to record additional adjustments to one or more of these items during the remaining nine months ending September 30, 2019, the amounts of these and other potential adjustments are not reasonably determinable at this time. As such, the Company is unable to provide earnings guidance other than on a non-GAAP basis.   Management defines Adjusted EBITDA as reported GAAP earnings before the following items: interest expense, income taxes, depreciation, depletion and amortization, interest and other income, impairments, and other items reflected in operating income that impact comparability. Appendix 58

Non-GAAP Reconciliations – Adjusted EBITDA Appendix Total Adjusted EBITDA for FY 2018 and the twelve months ended December 31, 2018 include the reclassification of non-service pension costs from Operating and Maintenance Expense to Other Income (Deductions) as of October 1, 2018 on the Company’s Income Statement, which on a consolidated basis were approximately $32.64 million in FY 2018 and approximately $32.57 million for the twelve months ended December 31, 2018.. This reclassification is not reflected in Total Adjusted EBITDA for FY 2015, FY 2016 or FY 2017. (1) (1)

Non-GAAP Reconciliations – Adjusted EBITDA, by Segment Appendix

Non-GAAP Reconciliations – Adjusted Operating Results Appendix ADJUSTED OPERATING RESULTS Three Months EndedDecember 31, (in thousands except per share amounts) 2018 2017 Var Reported GAAP Earnings $,102,660 $,198,654 $,-95,994 Items impacting comparability Remeasurement of deferred income taxes under 2017 Tax Reform -5,000 -,111,000 ,106,000 Unrealized (gain) loss on hedge ineffectiveness (E&P) -6,505 433 -6,938 Tax impact of unrealized (gain) loss on hedge ineffectiveness 1,366 -,106 1,472 Unrealized loss on other investments (Corporate / All Other) 6,347 0 6,347 Tax impact of unrealized loss on other investments -1,333 0 -1,333 Adjusted Operating Results $97,535 $87,981 $9,554 Reported GAAP Earnings per share $1.18 $2.2999999999999998 $-1.1199999999999999 Items impacting comparability Remeasurement of deferred income taxes under 2017 Tax Reform -0.06 -1.29 1.23 Unrealized (gain) loss on hedge ineffectiveness (E&P) -0.08 0.01 -0.09 Tax impact of unrealized (gain) loss on hedge ineffectiveness 0.02 0 0.02 Unrealized loss on other investments (Corporate / All Other) 7.0000000000000007E-2 0 7.0000000000000007E-2 Tax impact of unrealized loss on other investments -0.02 0 -0.02 Rounding 0.01 0 0.01 Adjusted Operating Results per share $1.1199999999999999 $1.0199999999999998 $0.10000000000000009 weighted average shares 86,708,814 86,325,537 impact of remeasurement -5.7664264673254556E-2 -1.2858304026536205 unrealized gain hedging pre-tax -7.502120833990418E-2 5.0158969761172761E-3 unrealized gain hedging - tax impact 1.5753877108733143E-2 -1.2279101142457997E-3 unrealized loss ERP investments pre-tax 7.3199017576229333E-2 0 imrealized loss ERP investments - tax impact -1.5373292961889665E-2 0 adjusted op results 1.1248568109811767 1.0191769788816953

Non-GAAP Reconciliations – Capital Expenditures Appendix

Non-GAAP Reconciliations – E&P Operating Expenses Appendix

Non-GAAP Reconciliations – Adjusted Operation & Maintenance Expense Appendix