Investor Presentation Q3 Fiscal 2021 Update August 5, 2021 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 review our Corporate Responsibility Report. 2

NFG: A Diversified, Integrated Natural Gas Company Developing our large, high-quality acreage position in Marcellus & Utica shales(1) 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 % of NFG 20EBITDA(1) Expanding and modernizing pipeline infrastructure to provide outlets for Appalachian natural gas production ~1.2 Million Net acres in Appalachia ~870 MMcf/day Net Appalachian natural gas production(3) $2.0 Billion Investments since 2010 4.4 MMDth Daily interstate pipeline capacity under contract 747,000 Utility customers $341 Million Investments in safety since 2016 (1) This presentation includes forward-looking statements. Please review the safe harbor for forward looking statements at the end of this presentation. (2) Twelve months ended June 30, 2021. 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. (3) Average net Appalachian production for the three months ended June 30, 2021. Total net Seneca production for the three months ended June 30, 2021 was ~910 MMcf/day. 44% of NFG EBITDA(2) 39% of NFG EBITDA(2) 17% of NFG EBITDA(2)

Why National Fuel? Diversified Assets Provide Stability and Long-Term Growth Opportunities Integrated Model Enhances Shareholder Value Expect to Generate Significant Free Cash Flow in Fiscal 2022 and Beyond Interstate Pipeline Business Drives Significant Regulated Growth Long History of Returning Capital to Shareholders Focused on Corporate Responsibility and ESG 1 3 4 2 5

Integrated Model Enhances Shareholder Value . . . 1 Midstream Ability to adjust to changing commodity price environments More efficient capital investment Higher returns on investment Operational scale Lower cost of capital Lower operating costs More competitive pipeline infrastructure projects Strong balance sheet Growing, stable dividend Geographic and Operational Integration Drives Synergies: Benefits of National Fuel’s Integrated Structure: Financial Efficiencies: Investment grade credit rating Shared borrowing capacity Consolidated income tax return Downstream Utility Midstream Gathering Pipeline & Storage Upstream Exploration & Production Co-development of Marcellus and Utica Just-in-time gathering facilities Enhanced capital efficiency Upstream Rate-regulated entities share common resources, reducing operating expense Utility business is a large Pipeline & Storage customer Downstream Midstream

. . . and Continues to Drive Growth Opportunities Integrated Upstream and Midstream development of high-quality Appalachian assets ~1.2 million net acres in the Marcellus and Utica shales NFG’s gathering systems move Seneca’s natural gas production, driving consolidated returns NFG’s interstate pipelines support Appalachian development and provide new firm takeaway capacity Further expansion of interstate pipeline systems to satisfy growing natural gas supply and demand Supply push – Appalachian producers Demand pull – regional demand-driven projects and utilities Ongoing investment in safety and modernization of pipeline transportation and distribution systems $500+ million in new investments expected over the next 5 years Expect to generate significant consolidated free cash flow in fiscal 2022 and beyond(1) Near Term Strategy Leverages Integration Across the Value Chain Utility Gathering Pipeline & Storage Exploration & Production The Company defines free cash flow on page 61 of this presentation.

Consolidated Business Expected to Generate Significant Free Cash Flow . . . 2 Consolidated free cash flow. The Company defines free cash flow on page 61 of this presentation. Assumes current hedges and $65.00 per Bbl WTI oil price. . . . In Fiscal 2022 at Natural Gas Prices Well Below Current NYMEX Strip . . . @ NYMEX Price ($/MMBtu) 270 . . . With Sustainable, Growing Free Cash Flow Generation Expected Over the Long-Term Consolidated capital expenditures expected to further decrease, supporting continued free cash flow growth Exploration & Production / Gathering: activity level moderates once new transport capacity filled, with ongoing just-in-time build-out of supporting gathering facilities Pipeline & Storage / Utility: current plans focus on system maintenance and pipeline modernization Regulated businesses expected to generate stable, predictable earnings and cash flows Mitigation of Upstream business commodity risk through consistent hedging program Improvement of investment grade credit profile through enhanced free cash flow generation

Significant Interstate Pipeline Growth 3 Northern Access Delivery: NY & Canada 490,000 Dth/d (remains under development) Line N to Monaca Delivery: Shell ethane cracker facility (Beaver Co., Pa) 133,000 Dth/d FM100 Delivery: Transco (Leidy) 330,000 Dth/d Empire North Delivery: Canada & NY 205,000 Dth/d Supply Corp. Rate Case Settlement: $35 million increase in base rates (effective February 2020) Additional $15 million step-up (expected April 2022) Significant Expansion Revenues: Line N to Monaca: $5 MM (placed into service November 2019) Empire North: $27 MM (placed into service September 2020) FM100: $35 MM (In-service target of late calendar 2021) Ongoing Investments in Safety and System Modernization: $150-$250 MM expected over the next 5 years (Supply Corp.)

Over Half Century of Dividend Growth 4 $3.2 Billion Dividend payments since 1970 $1.82 per share 51Years Consecutive Dividend Increases $0.19 per share 119 Years Consecutive Payments 3.5% yield(1) As of August 3, 2021.

Focused on Corporate Responsibility and ESG 5 NFG Upstream Segment Midstream Segment Downstream Segment Ongoing Sustainability-Focused Initiatives Across the Energy Value Chain Initial Corporate Responsibility Report published in September 2020 (SASB/GRI disclosures for each segment) Each business is a participant in the EPA Methane Challenge Program, focused on emissions reductions Anchor sponsor of Low Carbon Resources Initiative, an effort to accelerate low/zero-carbon energy technologies Focused on operational emissions reductions in Appalachia, including ongoing study of low-carbon production equipment Significant investments in water handling and recycling facilities, limiting environmental footprint California operations focused on offsetting emissions, with continued investments in solar facilities Facilitating transportation of renewable natural gas (RNG) on interstate pipeline systems, with first interconnect with RNG developer in Western New York completed during fiscal 2020 Continuing to modernize transmission systems, with focus on reducing operational and fugitive emissions, including the use of electric motor drive compression and vent gas recovery systems for recently-completed Empire North project Targeting GHG emissions reduction of 75% by 2030, and 90% by 2050, from 1990 levels for utility delivery system(1) Ongoing promotion of energy conservation and efficiency programs, which have reduced end-use GHG emissions by over 1.3 million metric tons since 2007(2) Focused on RNG opportunities, with meaningful potential in New York Baseline emissions & emissions reduction targets are calculated pursuant to the reporting methodology under the EPA GHG Reporting Program (current Subpart W, and using AR5), primarily Distribution pipeline mains & services. Metric Tons CO2e, as reported to New York State Public Service Commission. 10

Third Quarter Fiscal 2021 Financial Highlights

Third Quarter Fiscal 2021 Results and Drivers Increased Scale (Appalachian Acquisition) Net Oil and Gas Production A Reconciliation of Adjusted Operating Results to Earnings Per Share is provided at the end of this presentation. Realized price after hedging. Combined Lease Operating Expense, General & Administrative Expense, All Other Operation and Maintenance Expense, and Property, Franchise and Other Taxes, all on a per unit of production basis ($/Mcfe). Oil and Gas Pricing(2) Natural Gas ($/Mcfe) Crude Oil ($/Bbl) Oil Prices Natural Gas Prices E&P Cash OpEx ($/Mcfe)(3) Major Drivers Natural Gas Production (Appalachian Acquisition) Oil Production (Reduced Activity) Crude Oil (Mbbl) Natural Gas (Bcf) Adjusted Operating Results ($/share)(1) $1.13/Mcfe Utility $0.07 Utility $0.05

Earnings Guidance FY2021 Adjusted Operating Results Exploration & Production Gathering $4.05 to $4.15/share(1) $4.40 to $4.80/share FY2022 Preliminary Earnings Guidance 335-365 Bcfe (up 8% vs. FY21E) ~$2.35/Mcf(2) (vs. ~$2.23/Mcf in FY21E) Key Guidance Drivers Excludes items impacting comparability. A reconciliation of Adjusted Operating Results is provided at the end of this presentation. Assumes NYMEX natural gas pricing of $3.50/MMBtu and in-basin spot pricing of $2.85/MMBtu for winter and $2.25/MMBtu for summer fiscal 2022, and reflects the impact of existing financial hedges, firm sales and firm transportation contracts. Assumes NYMEX (WTI) oil pricing of $65.00/Bbl and California-MWSS pricing differentials of 96% to WTI, and reflects impact of existing financial hedge contracts. Net Production Realized natural gas prices (after-hedge) Utility Operating Income Pipeline & Storage Utility Guidance assumes return to normal weather $360-$380 million (up 8% from FY21 - FM100 Project) Pipeline & Storage Revenues Tax Rate Realized oil prices (after-hedge) Effective Tax Rate ~25-26% (availability of Enhanced Oil Recovery Credit) Pipeline & Storage Depreciation Expense ~$7 million increase (primarily FM100 Project) G&A Expense $0.19-$0.21/Mcf (vs. $0.20-$0.22 in FY21E) DD&A Expense $0.59-$0.62/Mcf (vs. $0.55-$0.57 in FY21E) 4-5% increase (FM100 / FY21 reversal of project development costs) Pipeline & Storage O&M Expense Non-Regulated Regulated $200-$225 million (up 10% vs. FY21E) ~$58.50/Bbl(3) (vs. ~$56.00/Bbl in FY21E) Gathering Revenues Gathering O&M Expense ~$0.09/Mcf of throughput Exploration & Production Gathering Pipeline & Storage Utility LOE Expense $0.82-$0.85/Mcf (vs. $0.81-$0.83 in FY21E)

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

Growing Production within Disciplined Capital Program Near-Term Strategy E&P Net Capital Expenditures ($ millions)(1) E&P Net Production (Bcfe) 2nd drilling rig added in January 2021 (additional activity focused in EDA) Additional production will support Leidy South capacity (330 Mdth/d) Gross production growth will benefit NFG’s Gathering segment EDA Tioga: development focused on return trip pads (Seneca and legacy Shell) EDA Lycoming: activity focused on fully utilizing valuable Atlantic Sunrise capacity WDA: development focused on Utica shale, with step-out into Beechwood area and return trips in Clermont-Rich Valley area California: modest development across Midway and Coalinga areas A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation. FY18 reflects the netting of $17 million of up-front proceeds received from joint development partner for working interest in joint development wells. FY20 reflects the netting of $286 million related to the acquisition of Appalachian upstream assets in July 2020. E&P and Gathering

Significant Appalachian Acreage Position Average Seneca gross production(1): ~610 MMcf/d ~300 potential Utica and Marcellus locations Large, highly-contiguous acreage position, with limited near-term lease expirations (~15% royalty) Low breakeven consolidated economics (15% IRR) Tioga Utica: $1.07/MMBtu Lycoming Marcellus: $1.04/MMBtu Eastern Development Area (EDA) Western Development Area (WDA) Average Seneca gross production(1): ~420 MMcf/d Over 1,000 potential Marcellus and Utica locations Breakeven (15% IRR) consolidated economics - Seneca and Gathering - of $1.47/MMBtu or less Royalty free mineral ownership Highly contiguous nature drives efficiencies Average production is for the quarter ended June 30, 2021, and includes the impact of price-related curtailments. Seneca Appalachian acreage is fee-owned, or leased from either the Pennsylvania Department of Conservation and Natural Resources or private landowners. WDA – 915,000 Acres(2) EDA – 270,000 Acres(2) E&P and Gathering EASTERN

Eastern Development Area EDA – ~270,000 Acres Seneca EDA Highlights ~180 undeveloped Utica locations, including ~40 return trip locations ~90 undeveloped Marcellus locations Gathering infrastructure: NFG Tioga gathering systems Numerous marketing opportunities: Ability to utilize Seneca’s firm transportation capacity: Empire Tioga County Extension, Leidy South and Northeast Supply Diversification Interconnections with multiple interstate pipelines: Empire, Eastern, TGP (300 Line), UGI ~25 remaining Marcellus locations Geneseo Shale expected to provide 100 - 120 return trip locations Gathering infrastructure: NFG Midstream Trout Run Firm transportation capacity: Atlantic Sunrise (189 MDth/d) Tioga County, PA Lycoming County, PA 1 2 E&P and Gathering 1 2 Eastern

EDA: Tioga County Development Large Contiguous Acreage Position, with Highly-Economic Utica and Marcellus Inventory (1) Significant Tioga County Acreage Position Undeveloped Utica Undeveloped Marcellus Tioga Development Plan Significant assets acquired in mid-2020, contiguous to NFG’s existing Tioga County production and gathering operations Near-term development expected to focus on return trips to both acquired and DCNR Tract 007 pads Return trips to existing pads allow use of existing infrastructure, enhancing consolidated drilling program returns(1) Continuing to optimize development plan through incorporation of acquired assets E&P and Gathering EASTERN (1) Similar to Seneca’s prior WDA return trips to Marcellus pads to drill Utica wells, Seneca expects to return to Legacy Shell pads to drill remaining locations (allows use of existing gathering, pad, and water infrastructure).

Integrated Development – EDA Tioga Gathering NFG Tioga Gathering Systems Support Growing Seneca Production Tioga County Gathering Systems Map Current Systems In-Service Empire Eastern TGP E&P and Gathering Tioga Gathering System Capacity: up to 550,000 Dth per day (Interconnects with Empire, Eastern, and TGP 300) Production Source: Seneca Resources (acquired Tioga acreage and future development) Tie in completed with NFG Covington Gathering System, providing access to Eastern and Empire markets Covington Gathering System Total Investment (to date): ~$48 million Capacity: 220,000 Dth per day (Interconnect w/ TGP 300 line) Production Source: Seneca Resources (Covington/DCNR Tract 595) Wellsboro Gathering System Total Investment (to date): ~$42 million Capacity: up to 200,000 Dth per day (Interconnect w/ TGP 300 line) Production Source: Seneca Resources (DCNR Tract 007) EASTERN

EDA: Tioga County Development Production Underpinned by Firm Sales and Firm Transportation Contracts (1) Includes physical fixed price and NYMEX-based firm sales contracts that do not carry any additional transportation costs. Production supported by firm transportation capacity to premium markets: 200 MDth/d (Empire-NFG) provides access to Dawn/TGP 200 markets Tioga production expected to be utilized to fill a portion of Leidy South expansion capacity Seneca’s other existing firm transportation and firm sales support DCNR Tract 007, DCNR Tract 595, and Covington area production Tioga County Gas Marketing Strategy Tioga County Gross Firm Contract Volumes (MDth/d) E&P and Gathering Northeast Supply Diversification Project FT Capacity: 50,000 Dth/d Northeast Supply Diversification Project FT Capacity: 50,000 Dth/d Tioga County Extension (NFG - Empire) FT Capacity: 180,000 - 200,000 Dth/d Leidy South Firm Sales EDA - TGP 300 Firm Sales(1)

EDA: Lycoming County Development Includes physical fixed price and NYMEX-based firm sales contracts that do not carry any additional transportation costs. Marcellus Development in Lycoming County Fully Utilizes Firm Transportation Prolific Marcellus acreage with peer-leading well results ~25 remaining Marcellus locations – breakeven (15% IRR) consolidated economics of ~$1.04/MMBtu Development focused on filling valuable Atlantic Sunrise capacity E&P and Gathering Transco Firm Sales(1) Atlantic Sunrise (Transco) FT Capacity: 189,405 Dth/d Firm Sales: NYMEX/Market Indices Leidy South Firm Sales

Integrated Development – EDA Lycoming Gathering NFG Trout Run Gathering System Supports Seneca and Third-Party Development Trout Run Gathering System Map Current System In-Service Opportunities for Third-Party Volumes Long-term contract executed, with volumes online in late calendar 2020 Completed construction of new facilities, leveraging existing Trout Run system Expected to generate $7 million - $10 million in additional gathering revenues for fiscal 2022 (supported by minimum volume commitments) Total Investment (to date): ~$270 million Capacity: 466,000 to 585,000 Dth per day Current Production Source: Seneca Resources (DCNR Tract 100 & Gamble) Interconnect: Transco (Leidy Line) E&P and Gathering

Western Development Area Marcellus Core Acreage vs. Utica 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 is expected to do the same. Large well inventory: 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 Highly contiguous position drives best in class well costs and program efficiencies Long-term firm contracts provide access to premium markets and support growth Beechwood area is focus of near-term Utica development program WDA Highlights E&P and Gathering ? Boone Mountain Utica Test Well Past Marcellus delineation tests Utica Trend (currently evaluating) Marcellus Core Acreage Beechwood Utica Development Area

WDA Development Plan (1) Internal Rate of Return is for consolidated Seneca and Gathering, is pre-tax, and includes expected gathering capital expenditures, well costs under current cost structure, and non-gathering LOE. WDA – Potential RV-Beechwood Utica Development Area Beechwood Development Area Provides ~90 Potential Utica Locations with Strong Economics WDA-CRV Area: producing from both Utica and Marcellus wells, with recent development focused on return trips to existing pads Avg. CRV Utica Production: ~180 MMcf/d Avg. CRV Marcellus Production: ~215 MMcf/d WDA RV-Beechwood Area: ~90 potential Utica locations, with economics equal to or greater than prior CRV-Utica development program WDA Development Update EUR (Bcf/1000’) IRR% $2.25(1) 15% IRR ($/MMBtu) Utica (RV-Beechwood) 1.5 - 1.8 42% $1.42 Marcellus (CRV Return Trip) 1.1 - 1.2 39% $1.47 Consolidated WDA Economics E&P and Gathering

Integrated Development – WDA Gathering System Current System In-Service Capacity: 470 MMcf per day Interconnects with TGP 300 and NFG Supply Total Investment (to date): $343 million 38,120 HP of compression (3 stations) Future Build-Out Modest gathering pipeline and compression investment required to support Seneca’s Utica return-trip development Beechwood development area expected to require extension of existing trunkline and incremental centralized compression 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 15¢ - 20¢ better than TGP Marcellus Zone 4 Leidy South will provide additional capacity to premium markets (Transco Zone 6 NNY) WDA Exit Capacity Supports Production and Enhances Consolidated Returns WDA Contracted Firm Transport and Gross Sales Volumes (MDth/d) WDA Gas Marketing Strategy E&P and Gathering Niagara Expansion Project (TGP and NFG) NYMEX & Dawn 158,000 Dth/d WDA - TGP 300 Firm Sales Leidy South Firm Sales

Long-term Contracts Supporting Appalachian Production Seneca Appalachia Natural Gas Marketing Firm Contract / Transport Volumes (MDth/day) E&P and Gathering 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. Northeast Supply Diversification (TGP) 50,000 Dth/d (Canada-Dawn) Niagara Expansion (TGP & NFG - Supply) Canada-Dawn & TGP 200 158,000 Dth/d Atlantic Sunrise (Transco) Mid-Atlantic & Southeast U.S. 189,405 Dth/d In-Basin Firm Sales Contracts(1) Leidy South (Transco & NFG - Supply) Transco Zone 6 Non-NY 330,000 Dth/d *Capacity can be utilized by all three producing areas (WDA, EDA-Tioga, and EDA-Lycoming) Tioga County Extension (NFG - Empire) Canada-Dawn & NY Markets 180,000 - 200,000 Dth/d 27

Near-term Firm Sales Provide Market & Price Certainty Net Contracted Firm Sales / Transport Volumes (Dth per day) Contracted Index Price Differentials ($ per Dth)(1) E&P and Gathering Values shown represent the weighted average fixed price or weighted average differential relative to NYMEX (netback price), and are net of any associated transportation costs. Transportation costs include minor variable components such as the Canadian exchange rate and fuel components. With respect to “Other”, the weighted average differential relative to NYMEX (netback price) includes net contracted firm sales at various indices, which are to subject to fluctuations in the market, such as seasonal demand swings, and is calculated using forward basis at various associated locations as specified by the underlying contract. (2) “Other” volumes included in fiscal 2022 are primarily TGP 200 and Transco Zone 6 Non-NY markets, with the balance to other Transco markets. (2) (2) (2) (2) (2)

California Oil Stable Oil Production | Minimal Capital Investment | Steady Free Cash Flow 1 2 3 4 5 Location Formation Production Method Avg. Daily Production (net BOE/d) 1 East Coalinga/ Other Temblor Primary 534 2 North Lost Hills Tulare & Etchegoin Primary/ Steam flood 806 3 South Lost Hills Monterey Shale Primary 1,066 4 North Midway Sunset Tulare & Potter Steam flood 2,462 5 South Midway Sunset Antelope Steam flood 2,050 TOTAL WEST DIVISION AVG. NET PRODUCTION(1) 6,918 BOE/d (1) Average daily net production (oil and natural gas) for West division for quarter ended June 30, 2021. 1 2 3 4 5 E&P and Gathering

California – Continued Focus on Integrating Renewable Energy North Midway Sunset Field (2016) Bakersfield Office (2018) South Midway Sunset Field (2021E) Ongoing Investments in Solar Facilities Offset Operational Power Needs Capacity: 3.1 Megawatts Online Date: August 2016 Cost: $6.6 MM Annual Electricity Savings: ~$1.3MM in FY20 Offset: 21% of field electricity use First CA producer to utilize Low Carbon Fuel Standard credits Capacity: 90 Kilowatts Online Date: October 2018 Cost: $270,000 Annual Electricity Savings: ~$30,000 in FY20 Offset: 100% of office electricity use Expected Capacity: 1.8 Megawatts Target Online Date: Late 2021 Estimated Cost: $2.8 MM Estimated Annual Electricity Savings: ~$740,000 Expected Offset: ~30% of field electricity use E&P and Gathering 30

Fiscal 2021 Production Profile Average realized price reflects uplift from financial hedges less fixed differentials under firm sales contracts and any firm transportation costs. Average weighted ceiling price (average weighted floor price of $2.37/Mcf). Includes ~2 Bcf of firm sales contracts with fixed index differentials, as well as production with associated firm transport volumes, but not backed by a matching financial hedge. Also includes ~2 Bcf of non-NYMEX indexed firm sales with existing NYMEX hedge. Spot production assumed to be sold at ~$2.75 for remainder of FY21 ~72% of oil production hedged at $56.91 58 Bcf locked-in realizing net ~$2.17/Mcf (1) 7 Bcf of no-cost collars with $2.89/Mcf ceiling(2) 4 Bcf of additional firm sales(3) 69 Bcf of Appalachian Production Protected by Firm Sales E&P and Gathering

Fiscal 2022 Production Profile Average realized price reflects uplift from financial hedges less fixed differentials under firm sales contracts and any firm transportation costs. Average weighted ceiling price (average weighted floor price of $2.37/Mcf). Includes ~57 Bcf of firm sales with fixed index differentials, as well as production with associated firm transport volumes, but not backed by a matching financial hedge. Also includes ~43 Bcf of non-NYMEX indexed firm sales with existing NYMEX hedge. Spot production assumed to be sold at ~$2.85 for winter and $2.25 for summer FY22 ~61% of oil production hedged at $57.40 210 Bcf locked-in realizing net ~$2.21/Mcf (1) 2 Bcf of no-cost collars with $2.89/Mcf ceiling(2) 100 Bcf of additional firm sales(3) 312 Bcf of Appalachian Production Protected by Firm Sales E&P and Gathering

Hedge Positions and Prices Production Supported by Strong Hedge Positions E&P and Gathering 33 Pro Forma Natural Gas - MMDth, $/MMBtu 154.5 MMDth 262.0 MMDth ~76% Hedged(2) 70.0 MMDth ~91% Hedged(1) $2.62 $2.27 $2.75 $2.27 $2.28 / $2.77(3) $2.28 / $2.77(3) $2.69 $2.23 $2.76 / $3.16(3) Crude Oil - MBbl, $/Bbl 480 MBbl 1,296 MBbl ~61% Hedged(2) 393 MBbl ~72% Hedged(1) $57.57 $51.00 $58.28 $51.00 $58.48 - Fiscal 2021 Fiscal 2022 Fiscal 2023 Fiscal 2021 Fiscal 2022 Fiscal 2023 Reflects percentage of remaining projected production for FY21 hedged at the midpoint of the production guidance range. Reflects percentage of projected production for FY22 hedged at the midpoint of the production guidance range. Average weighted floor and ceiling prices. Fixed price physical sales exclude joint development partner’s share of fixed price contract WDA volumes as specified under the joint development agreement. Swaps and no cost collar prices do not include cost of transport.

Continued Decrease in E&P Operating Costs Increased Scale and Highly-Contiguous Operations Expected to Drive Lower Cash Unit Costs Seneca Cash OpEx ($/Mcfe) (2) (2) (1) Appalachia LOE ($/Mcfe)(3) Approximately $0.25/Mcfe Reduction in Expected Cash Unit Costs vs. 2018 Levels Fees Paid to NFG’s Gathering Segment Comprise ~90% of Expected Appalachian Gathering & Transport LOE G&A estimate represents the midpoint of the G&A guidance ranges for fiscal 2021 and fiscal 2022, respectively. The total of the two LOE components represents the midpoint of the LOE guidance ranges for fiscal 2021 and fiscal 2022, respectively. FY20 Seneca LOE was $0.84/Mcfe (vs. total shown of $0.85) due to rounding. See Non-GAAP Reconciliation at the end of this presentation for additional detail on Appalachian LOE & Gathering and Seneca LOE. (2) (2) E&P and Gathering (1)

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

Pipeline & Storage Segment Overview As of September 30, 2020 as disclosed in the Company’s fiscal 2020 Form 10-K. As of December 31, 2020 calculated from National Fuel Gas Supply Corporation’s and Empire Pipeline, Inc.’s 2020 FERC Form-2 reports, respectively. Empire Pipeline, Inc. National Fuel Gas Supply Corporation Empire Pipeline Supply Corp. Contracted Capacity(1): Firm Transportation: 3,443 MDth per day Firm Storage: 70,693 Mdth (fully subscribed) Rate Base(2): ~$959 million FERC Rate Proceeding Status: New rates went into effect February 2020 Rate case settlement approved June 2020 Contracted Capacity(1): Firm Transportation: 984 MDth per day Firm Storage: 3,753 Mdth (fully subscribed) Rate Base(2): ~$351 million FERC Rate Proceeding Status: New rates went into effect January 2019 Rate case settlement approved May 2019 Pipeline & Storage

FM100 Project - Consolidated Benefit for NFG All Seneca volumes will flow through wholly-owned NFG gathering facilities 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 Target in-service: late calendar year 2021 Estimated annual revenues: ~$50 million In-service: ~$35 million (lease revenues) April 2022: ~$15 million (negotiated revenue step-up)(2) Supply Corp. Project expected to provide long-term earnings uplift to Seneca, Supply Corp. and Gathering Gathering Includes lease of new capacity from Supply Corp. to Transco. Based on Period 2 rates described in recently approved settlement of Supply Corporation rate proceeding. Period 2 rates go into effect the later of the in-service date of FM100 project, or April 2022. Pipeline & Storage

FM100 Project – Significant Investment by Supply Corp. Estimated capital cost: $279 million Expansion facilities: ~$159 million Modernization facilities: ~$120 million 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: FERC certificate issued July 2020 FERC notice to proceed issued February 2021, with construction underway Pipeline & Storage

Empire North Project In-service date: September 15, 2020 Capital cost: $129 million Annual revenues: ~$27 million Underpinned by long-term firm transportation contracts (10-15 years): Repsol Oil & Gas: 150 MDth/d National Fuel Gas Distribution Corporation: 35 MDth/d Greenidge Markets & Trading: 15 MDth/d EnergyMark: 5 MDth/d Project designed to significantly mitigate operational and fugitive emissions: Use of electric motor drive units to power new compressor station in Farmington, NY (limiting operational emissions) Installation of vent gas recovery system at both new compressor stations (reducing potential fugitive emissions) Fully Subscribed Project Provides 205,000 Dth/day of Incremental Firm Transportation Pipeline & Storage

Continued Expansion of the Supply Corp. Line N System Shell Chemical Appalachia, LLC - On-system Delivery Point In-Service Date: November 2019 Contracted Firm Transport: 133,000 Dth/d Capital Cost: $24.5 million Annual Revenue: $5.6 million Pipeline & Storage TGP 219 Rover Holbrook Columbia Interconnect Omnis Bailey Interconnect Line N to Monaca Project 2021 Line N Market Pull Projects Omnis Bailey Plant - On-system Delivery Point In-Service Date: May 2021 Contracted Firm Transport: 21,000 Dth/d Capital Cost: ~$4 million Annual Revenue: $1.2 million Columbia Gas of PA Interconnect – On-system Delivery Point Target In-Service Date: late fiscal 2021 Contracted Firm Transport/Storage: 4,000 Dth/d / 267,000 Dth Estimated Capital Cost: ~$1 million Estimated Annual Revenue: $0.5 million

Northern Access Project Delivery points: 350,000 Dth/d to Chippawa (TCPL interconnect) 140,000 Dth/d to East Aurora (TGP 200 line) Regulatory/legal status: Feb. 2017 – FERC 7(c) certificate issued Aug. 2018 – FERC issued Order finding that NY DEC waived water quality certification (WQC) April 2019 – FERC denied rehearing of WQC waiver order (upholding waiver finding) March 2021 – U.S. Second Circuit Court of Appeals dismissed appeal of FERC waiver orders Supply and Empire currently working to finalize remaining federal authorizations To Dawn NE US (TGP 200) Pipeline & Storage

Pipeline & Storage Customer Mix 4.4 MMDth/d Firm Transport Customer Transportation by Shipper Type(1) Affiliated Customer Mix (Contracted Capacity) Contracted as of 9/30/2020. Pipeline & Storage

Utility Overview National Fuel Gas Distribution Corporation

New York & Pennsylvania Service Territories New York Total Customers(1): 534,000 ROE: 8.7% (NY PSC Rate Case Order, April 2017)(2) Rate Mechanisms: Revenue Decoupling Weather Normalization Low Income Rates Merchant Function Charge (Uncollectibles Adj.) 90/10 Sharing (Large Customers) System Modernization Tracker(3) Pennsylvania Total Customers(1): 213,000 ROE: Black Box Settlement (2007) Rate Mechanisms: Low Income Rates Merchant Function Charge As of September 30, 2020. Earnings sharing under Rate Case Order started April 1, 2018 (50/50 sharing starts at ROE in excess of 9.2%). Applied to new plant placed in service through March 31, 2021. Utility

Utility Continues its Significant Investments in Safety (1) A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation. Long-Standing Focus on Distribution System Safety and Reliability Utility

Long-Standing Pipeline Replacement & Modernization NY 9,758 miles PA* 4,850 miles * No Cast Iron Mains in Pa.* Miles of Utility Main Pipeline Replaced Utility Mains by Material(1) (1) All values are reported on a calendar year basis as of December 31, 2020. Utility

A Proven History of Controlling Costs Utility O&M Expense and Non-Service Pension Costs ($ millions)(1) (1) As of October 1, 2018, Operation and Maintenance Expense does not include non-service pension costs, which were re-classified as Other Income (Deductions) on the Company’s Income Statement. Utility

Baseline emissions & emissions reduction targets are calculated pursuant to the reporting methodology under the EPA GHG Reporting Program (current Subpart W, and using AR5), primarily Distribution pipeline mains & services. New York Climate Leadership and Community Protection Act, enacted in 2019. Targets Exceed Those Included in New York State Climate Act (CLCPA)(2) Reductions Primarily Driven by Ongoing Modernization of Mains and Services Utility Targeting Substantial Emissions Reductions 2030 75% Significant Reductions in Utility GHG Emissions to Date, Driven by System Modernization Efforts Recently Announced GHG Reduction Targets, Continuing Focus on Lowering Carbon Footprint ~64% Reduction Since 1990 (462,000 Metric Tons CO2e) Utility GHG Emissions Reduction Targets(1) (Based on 1990 EPA Subpart W Emissions) 90% 2050 Utility 48

Promoting Renewable Natural Gas Low Resource Scenario High Resource Scenario Technical Potential Landfill 20 33 50 Animal/Food Waste 7 13 37 Wastewater 2 3 7 Other 24 56 177 All Sources 53 105 271 Awarded three RNG grants for $1.2 million through the Utility’s Area Development Program Petitioned NY PSC to include RNG in the supply mix and recover purchased RNG costs through gas supply rates Accepted first RNG injections into NY system from anaerobic digester project (receipts estimated to be ~50 MMcf/year) Through Fiscal 2020 October 2020 Ongoing Substantial RNG Potential in New York Distribution Corporation received approval from NY and PA utility commissions to accept RNG into its distribution system First natural gas utility in Pennsylvania to have this approval in place Low Carbon Resources Initiative (LCRI) expected to provide opportunities for NFG to leverage technology acceleration within its regional footprint Continuing to Work with Regulators and Third Parties to Advance Zero and Low Carbon Opportunities Utility American Gas Foundation – Renewable Sources of Natural Gas: Supply and Emissions Reduction Assessment (December 2019). 49 RNG Potential in New York State (Bcf/Year)(1) Continue to advance RNG and evaluate investment opportunities July 2021

Consolidated Financial Overview Upstream I Midstream I Downstream

Diversified, Balanced Earnings and Cash Flows Adjusted Operating Results ($ per share)(1) 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 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% Rate Regulated ~40%

Disciplined, Flexible Capital Allocation (2) Total Capital Expenditures include 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. FY17 and FY18 reflects the netting of $7 million, and $17 million, respectively, of up-front proceeds received from joint development partner for working interest in joint development wells, and $21 million in intercompany asset transfers in FY18. FY20 reflects the netting of $286 million related to the acquisition of Appalachian upstream assets in July 2020. FY20 reflects the netting of $224 million related to the acquisition of Appalachian gathering assets in July 2020. Capital Expenditures by Segment ($ millions)(1) (3)

Maintaining Strong Balance Sheet & Liquidity Total Debt 57% $4.6 Billion Total Capitalization as of June 30, 2021 Net Debt / Adjusted EBITDA(1) Capitalization Debt Maturity Profile by Fiscal Year ($MM) Liquidity Committed Credit Facilities Short-term Debt Outstanding Available Short-term Credit Facilities Cash Balance at 6/30/21 Total Liquidity at 6/30/21 $ 1,000 MM 0 MM 1,000 MM 118 MM $ 1,118 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. Includes Accumulated Other Comprehensive Loss. Total Equity 43% (2)

Appendix 54

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: 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; 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; the length and severity of the ongoing COVID-19 pandemic, including its impacts across our businesses on demand, operations, global supply chains and liquidity; 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; changes in the price of natural gas or oil; Impairments under the SEC’s full cost ceiling test for natural gas and oil reserves; the creditworthiness or performance of the Company’s key suppliers, customers and counterparties; 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; the Company’s ability to estimate accurately the time and resources necessary to meet emissions targets; disallowance by applicable regulatory bodies of appropriate rate recovery for system modernization; moves to reduce or eliminate reliance on natural gas; delays or changes in costs or plans with respect to Company projects or related projects of other companies, including disruptions due to the COVID-19 pandemic, as well as difficulties or delays in obtaining necessary governmental approvals, permits or orders or in obtaining the cooperation of interconnecting facility operators; the Company's ability to complete planned strategic transactions; the Company's ability to successfully integrate acquired assets and achieve expected cost synergies; changes in price differentials between similar quantities of natural gas or oil 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; the impact of information technology disruptions, cybersecurity or data security breaches; 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;  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; 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.nationalfuel.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, 2020 and the Forms 10-Q for the quarter ended December 31, 2020, March 31, 2021 and June 30, 2021. 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

Consolidated Seneca and Gathering Economics Over 1,000 Potential Additional Marcellus and Utica Locations Economic on a Stand-Alone Basis at ~$2.00/MMBtu(1) Stand-alone Seneca breakeven economics (15% pre-tax IRR) by prospect are as follows: Lycoming Marcellus: $1.51; Tioga County: $1.48; WDA-RV/Beechwood Utica: $1.75; WDA-CRV Return Trip Marcellus: $1.86. Approximately 50 remaining WDA-CRV Utica return-trips remaining with breakeven economics of ~$1.75/MMBtu. Internal Rate of Return (IRR) for stand-alone Seneca is pre-tax and includes estimated well costs under current cost structure, LOE, and Gathering tariffs anticipated for each prospect. Net realized price is per MMBtu and reflects either (a) price received at the gathering system interconnect or (b) price received at delivery market net of firm transportation charges. Consolidated Seneca and Gathering IRR is pre-tax and includes expected gathering capital expenditures, well costs under current cost structure, and non-gathering LOE. 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

Firm Transportation Commitments Volume (Dth/d) Production Source Delivery Market Demand Charges ($/Dth) Gas Marketing Strategy Northeast Supply Diversification Tennessee Gas Pipeline Niagara Expansion TGP & NFG - Supply Leidy South / FM100 WMB – Transco; NFG - Supply Target in-service: late 2021 50,000 158,000 EDA – Tioga WDA – CRV WDA – CRV EDA - Lycoming 12,000 Canada (Dawn) Canada (Dawn) TGP (SE Pa.) $0.50 (3rd party) NFG pipelines - $0.24 3rd party - $0.43 $0.12 (NFG pipelines) Firm Sales Contracts Dawn/NYMEX 10 years Currently In-Service Future Capacity Firm Sales Contracts Dawn/NYMEX 8 to 15 years Atlantic Sunrise WMB - Transco 189,405 EDA - Lycoming Mid-Atlantic/ Southeast $0.73 (3rd party) Firm Sales Contracts NYMEX/Market Indices First 5 years 330,000 Transco Zone 6 NNY $0.66 (3rd Party) Firm Sales Contracts Transco Zone 6 NNY/NYMEX Tioga County Extension NFG - Empire EDA – Tioga Utilize acquired firm sales and pursue additional firm sales as needed 200,000 TGP 200 (NY) / Canada (Dawn) $0.23 (NFG pipelines) Eastern EDA – Tioga Capacity release (near-term); access to Leidy South project Northern Access NFG – Supply and Empire WDA – CRV 350,000 140,000 Canada (Dawn) TGP 200 (NY) NFG pipelines - $0.50 3rd party - $0.21 $0.38 (NFG pipelines) Seneca to pursue firm sales contracts as project development progresses $0.14 (3rd Party) 100,000 In-Basin Appendix

EDA Type Curves Estimated Cumulative Volumes (Bcf) Year Lycoming Marcellus (5,800') Tioga Utica (10,000') 1 3.1 6.0 5 8.3 14.3 10 10.8 17.6 EUR (Bcf) 14.5-16.8 20.0-23.0 NRI 84% 82-87% Appendix

WDA Type Curves Estimated Cumulative Volumes (Bcf) Year Utica (10,000') Marcellus (9,000') 1 2.7 1.6 5 7.8 4.2 10 10.5 5.9 EUR (Bcf) 15.0-18.0 9.0-10.8 NRI 100% 100% (1) (1) Type Curve based on the first 19 wells brought online. Appendix

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. The Company’s fiscal 2021 earnings guidance range does not include the impact of certain items that impacted the comparability of earnings during the nine months ended June 30, 2021, including: (1) the impairment of oil and gas properties; (2) the gain on sale of timber properties; (3) the unrealized loss on other investments, and (4) the premium paid on early redemption of debt.  While the Company expects to record additional adjustments to unrealized gain or loss on other investments during the three months ending September 30, 2021, 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 Operating Results as reported GAAP earnings before items impacting comparability. 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. Management defines Free Cash Flow as Funds from Operations less Capital Expenditures. The Company is unable to provide a reconciliation of projected Free Cash Flow as described in this presentation to their respective comparable financial measure calculated in accordance with GAAP without unreasonable efforts. This is due to our inability to calculate the comparable GAAP projected metrics, including operating income and total production costs, given the unknown effect, timing, and potential significance of certain income statement items.   Appendix

Non-GAAP Reconciliations – Adjusted EBITDA Total Adjusted EBITDA for FY 2018, FY 2019, and FY 2020, 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. This reclassification is not reflected in Total Adjusted EBITDA for FY 2016 or FY 2017. Appendix (1)

Non-GAAP Reconciliations – Adjusted EBITDA, by Segment Appendix

Non-GAAP Reconciliations – Adjusted Operating Results Appendix

Non-GAAP Reconciliations – Capital Expenditures Appendix

Non-GAAP Reconciliations – E&P Operating Expenses Appendix