Exhibit 99 Investor Presentation Q2 Fiscal 2022 Update May 5, 2022

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 Upstream acreage position in Marcellus & Utica Exploration & (1) shales Production ~1.2 Million ~930 MMcf/day 50% of NFG Net acres in Net Appalachian natural (2) EBITDA (3) Appalachia gas production Expanding and modernizing pipeline Midstream infrastructure to provide outlets for Gathering Appalachian natural gas production Pipeline & Storage ~4.5 MMDth $2.2 Billion 35% of NFG 38% of NFG Daily interstate Investments (2) (1) EBITDA EBITDA pipeline capacity since 2010 (4) under contract Providing safe, reliable and affordable Downstream service to customers in WNY and NW Utility Pa. % of NFG $359 Million 15% of NFG 753,000 (1) 20EBITDA (2) Investments in safety Utility EBITDA customers since 2017 (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 March 31, 2022. 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 March 31, 2022. Total net Seneca production for the three months ended March 31, 2022 was ~970 MMcf/day. 3 (4) Includes Leidy South leased capacity of 330,000 Dth/day.

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

1 Integrated Model Enhances Shareholder Value . . . Geographic and Operational Integration Benefits of National Fuel’s Upstream Drives Synergies: Integrated Structure: Exploration & ü Ability to adjust to changing commodity Production Upstream Midstream price environments ü Co-development of Marcellus and Utica ü More efficient capital investment ü Just-in-time gathering facilities ü Higher returns on investment Midstream ü Enhanced capital efficiency Gathering ü Operational scale Pipeline & Storage ü Lower cost of capital Midstream Downstream ü Lower operating costs ü Gathering, Pipeline & Storage, and Utility Downstream ü More competitive pipeline infrastructure businesses share common resources, Utility reducing operating expense projects ü Strong balance sheetü Utility business is a large Pipeline & Storage customer ü Growing, stable dividend Financial Efficiencies: ü Investment grade credit ratingü Shared borrowing capacityü Consolidated income tax return 5

. . . and Continues to Drive Growth Opportunities Near Term Strategy Leverages Integration Across the Value Chain Pipeline & Exploration & Gathering Utility Storage Production ü 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 firm takeaway capacity ü Develop 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 ü Ongoing investment in safety and modernization of pipeline transportation and distribution systems § $500+ million in new investments expected over the next 5 years (1) ü Expect to generate significant consolidated free cash flow in fiscal 2022 and beyond 6 (1) The Company defines free cash flow at the end of this presentation.

2 Consolidated Business Expected to Generate Significant Free Cash Flow . . . . . . With Sustainable, Growing Free Cash Flow Generation . . . In Fiscal 2022 and Fiscal 2023. . . Expected Over the Long-Term ✓ Consolidated capital expenditure optimization to maximize long- Free Cash Flow Annualized Dividend $350 term free cash flow growth (2) ▪ Exploration & Production / Gathering: focus on enhancing returns ~$290 $300 through ongoing operating efficiencies and just-in-time build-out of Expect long- supporting gathering facilities term growing $250 free cash flow ▪ Pipeline & Storage / Utility: current plans focus on system maintenance and pipeline modernization, while leveraging existing $200 facilities to drive further potential growth opportunities $150 ✓ Regulated businesses expected to generate stable, predictable ~$122 earnings and cash flows $100 ✓ Mitigation of Upstream business commodity risk through consistent $50 hedging and marketing program, while maintaining upside to rising commodity prices $0 ✓ Improvement of investment grade credit profile through consistent FY 2021 FY 2022E FY 2023E free cash flow generation (1) Consolidated free cash flow. The Company defines free cash flow at the end of this presentation. Assumes current commodity price assumptions for remainder of fiscal 2022. 7 (2) Excludes items related to California after expected closing date of June 30, 2022. (1) Free Cash Flow ($ Millions)

Optimization of Interstate Pipeline Drives Future Expected Opportunities 3 ü Near Term Growth: TCPL – Canada/Dawn TGP - Hopewell § FM100: $35 MM in Expansion Revenues (placed into service December 1, 2021) § Supply Rate Case Settlement - additional $15 MM step-up in base rates (April 2022) Millenium ü Ongoing Investments in Safety, Emissions Reductions, and System Modernization: § $150-$250 MM expected over the next 5 FM100 years Delivery: Transco (Leidy) 330,000 Dth/d ü Well Positioned to Capitalize on Future Transco - Leidy Growth Opportunities: TGP – Mercer § Interconnectivity of the system to other long-haul pipelines, and proximity to producers, provides on-going opportunity to transport volumes out of the basin § Ability to optimize throughput through modest expansion projects TETCO - Holbrook 8

4 Over Half Century of Dividend Growth $1.82 2.6% 51Years 119 Years (1) per share yield Consecutive Dividend Increases Consecutive Payments $3.4 Billion Dividend payments since 1970 $0.19 per share Annual Rate at Fiscal Year End 9 (1) As of May 3, 2022.

5 Focused on Corporate Responsibility and ESG Recently Published Inaugural Climate Report Provides Enhanced Climate-Risk Disclosures, Responsive to Key Stakeholder Priorities ü Alignment with TCFD – report further aligns the Company’s climate-risk disclosures with the TCFD framework ü Evaluating our Resilience to Climate Scenarios – report evaluated the resilience of our operations to potential transitional and physical risks associated with climate change, including a less than 2-degree Celsius scenario § Transitional Risk – “analysis showed that National Fuel can continue to operate profitably and generate free cash flow through 2050 even using the IEA’s long-term natural gas price of $2.00 per dekatherm and dramatically reduced demand” § Physical Risk – “comprehensive review of future physical risks across our businesses indicated that there is relatively low financial risk from climate hazards in 2030 and 2050 to our facilities and operations” ü Identifying Climate Related Opportunities – “significant pipeline assets provide the Company with potential long-term opportunities to transport and store low and zero-carbon fuels” 10

Emissions Reduction Targets and Initiatives Significant Methane Intensity and Greenhouse Gas Emissions Reduction Ongoing Sustainability Initiatives (1) Targets Across the Energy Value Chain ü ONE Future NFG 25% Reduction in GHG Emissions by 2030 ü EPA Methane Challenge ü Responsible Gas Certifications Exploration & 40% Reduction in Methane Intensity by 2030 ü Pneumatic Device Replacement Production ü Use of Best-in-Class Emissions Controls for Gathering 30% Reduction in Methane Intensity by 2030 New Facilities ü Equipment upgrades at Existing Facilities v 50% Reduction in Methane Intensity by 2030 Pipeline & Storage ü Use of Best-in-Class Emissions Controls for New Facilities ü Investment in System Modernization v 30% Reduction in Methane Intensity by 2030 ü Low Carbon Resources Initiative v 75% Reduction in delivery system GHG emissions by 2030 Utility ü Advancing RNG in Service Territory ü Evaluation of Hydrogen v 90% Reduction in delivery system GHG emissions by 2050 11 (1) All emissions reduction targets based on 2020 baseline, except Utility reduction in delivery system targets (1990 baseline).

Second Quarter Fiscal 2022 Financial Highlights 12

Second Quarter Fiscal 2022 Results and Drivers (1) Adjusted Operating Results ($/share) Q2 FY 2021 Q2 FY 2022 Major Drivers $1.68 Natural Gas Prices $70.45 $2.60 $57.11 $2.28 $1.34 Exploration & Oil Prices Production $0.77 Exploration & Crude Oil ($/Bbl) Natural Gas ($/Mcfe) Production $0.52 Natural Gas Production Gathering 87.1 85.2 Gathering $0.24 562 523 $0.23 Oil Production Pipeline & Storage Pipeline & Storage $0.28 Crude Oil (Mbbl) Natural Gas (Bcf) $0.27 Utility Utility $0.42 $0.35 System Modernization $62.5 $59.6 Tracker (NY territory) / Corporate/Other: ($0.03) Corporate/Other: ($0.03) MM MM Colder than Prior Year Q2 FY21 Q2 FY22 Weather (PA territory) (1) A Reconciliation of Adjusted Operating Results to Earnings Per Share is provided at the end of this presentation. 13 (2) Realized price after hedging. Utility Operating Net Oil and Gas (2) Oil and Gas Pricing Income ($MM) Production

Earnings Guidance FY2021 Adjusted Operating Results FY2022 Earnings Guidance (1) (1) $4.29/share $5.70 to $6.00/share Key Guidance Drivers ▪ 340-360 Bcfe (up 7% vs. FY21) Net Production (2) ▪ ~$2.65/Mcf (vs. $2.25/Mcf in FY21) Realized natural gas prices (after-hedge) (3) Exploration & ▪ ~$70.00/Bbl (vs. $56.54/Bbl in FY21) Realized oil prices (after-hedge) Exploration & Production (4) Production G&A Expense ▪ $0.19-$0.20/Mcf (vs. $0.21/Mcf in FY21) ▪ $0.58-$0.60/Mcf (vs. $0.56/Mcf in FY21) DD&A Expense Gathering ▪ $0.78-$0.80/Mcf (vs. $0.82/Mcf in FY21) LOE Expense Gathering Revenues▪ $205-$225 million (up 11% vs. FY21) Gathering Gathering O&M Expense ▪ ~$0.09/Mcf of throughput Pipeline & Storage Revenues ▪ $360-$380 million (up 8% from FY21 - FM100 Project) Pipeline & Pipeline & Pipeline & Storage O&M Expense ▪ ~8% increase (FM100 / FY21 reversal of project development costs) Storage Storage Pipeline & Storage Depreciation Expense ▪ ~$6 million increase (primarily FM100 Project) Utility Utility (1) Utility Net Income ▪ ~2-3% increase (System Modernization Tracker) Tax Rate Effective Tax Rate ▪ ~25-26% (1) Excludes items impacting comparability. A reconciliation of Adjusted Operating Results is provided at the end of this presentation. (2) Assumes NYMEX pricing of $7.25/MMBtu and in-basin spot pricing of $6.25/MMBtu for the remainder of fiscal 2022, respectively, and reflects the impact of existing financial hedges, firm sales and firm transportation contracts. (3) Assumes NYMEX (WTI) oil pricing of $100.00/Bbl and California-MWSS pricing differentials of 99% to WTI for the remainder of fiscal 2022, and reflects impact of existing financial hedge contracts 14 (4) Includes the impact of divestiture of Seneca’s California assets as of June 30, 2022. Regulated Non-Regulated

Divestiture of Seneca’s California Assets 15

E&P and Gathering California Divestiture Overview Divestiture of Seneca’s California assets for total consideration of between $280 - $310 MM ü $280 million cash at closing ü Up to three annual contingent payments that can total $30 million in aggregate, from 2023 – 2025 § Value of contingent payments is $1 million for each dollar that Brent crude oil prices average over $95 per barrel in each respective year, with a maximum of $10 million in any year ü ~40 MMcfe/day (92% oil) (1) Seneca to divest California assets ~$47,000/BOE/D Significantly reduces Seneca emissions • Primarily higher cost, steam flood heavy oil • ~55% reduction in CO e 2 production üü Significant improvement to per unit cash cost Expected to accelerate deleveraging efforts and structure provide additional financial flexibility in the near- • Expected annualized reduction >$0.15/Mcfe term üü 16 (1) Assuming total realized consideration of $310 million.

Exploration & Production & Gathering Overview Seneca Resources Company, LLC National Fuel Gas Midstream Company, LLC 17

E&P and Gathering Growing Production within Disciplined Capital Program E&P Net Production (Bcfe) Near-Term Strategy 400 ü Continue two rig development program with focus on maximizing returns and cash flows 300 200 § EDA share of total drilling activity increasing (2) 340-360 327.4 from ~25% (FY20) to ~50% (FY22+) 241.5 211.8 100 178.1 0§ Additional production utilizes new Leidy South 2018 2019 2020 2021 2022E capacity (330 MDth/d) (1) E&P Net Capital Expenditures ($ millions) ü EDA Tioga: development focused primarily on Utica $600 (modest Marcellus activity) $500 ü EDA Lycoming: activity focused on fully utilizing $400 valuable Atlantic Sunrise capacity $300 $475- $492 $550 $200 $384 $381 ü WDA: development focused on Utica Shale, with $356 step-out into Beechwood area and return trips in $100 Clermont-Rich Valley area $0 2018 2019 2020 2021 2022E (1) 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. 18 (2) Revised production range includes the reduction of approximately ~4 Bcfe resulting from divestiture of Seneca’s California assets.

E&P and Gathering Significant Appalachian Acreage Position ~1,000 Economic Drilling Locations (1) at $2.50 NYMEX Prices ( ) ü Decades of highly-economic inventory (~40 wells per year at current 2-rig pace) ü Large, contiguous acreage position, driving increased capital efficiency ü Development supported by wholly-owned gathering infrastructure, enhancing returns Development Locations at 20% IRR ( ) 2,000 Utica 1,500 Marcellus 1,000 500 EASTERN 0 $2.00 $2.25 $2.50 $2.75 $3.00 NYMEX Price ($/MMBtu) (1) Drilling locations with expected consolidated Exploration & Production and Gathering segments pre-tax IRR’s at 20%. 19 (2) Seneca Appalachian acreage is fee-owned, or leased from either the Pennsylvania Department of Conservation and Natural Resources or private landowners.

E&P and Gathering Eastern Development Area Seneca EDA Highlights EDA – ~270,000 Acres 1 Tioga County, PA ü ~150 undeveloped Utica locations ü ~90 undeveloped Marcellus locations ü Gathering infrastructure: NFG Tioga gathering systems ü Numerous marketing opportunities: § Ability to utilize Seneca’s firm transportation capacity: Empire Tioga County Extension, Leidy South and Northeast Supply Diversification 1 § Interconnections with multiple interstate pipelines: Empire, Eastern, TGP (300 Line), UGI 2 Lycoming County, PA 2 ü ~30 remaining Marcellus locations ü Geneseo Shale expected to provide return trip locations ü Gathering infrastructure: NFG Midstream Trout Run ü Firm transportation capacity: Atlantic Sunrise (189 MDth/d) 20

E&P and Gathering EDA: Tioga County Development Large Contiguous Acreage Position, with Highly-Economic Utica and Marcellus Inventory Tioga Development Plan Significant Tioga County Acreage Position ü Significant additional assets acquired in mid-2020, contiguous to NFG’s existing Tioga County Undeveloped production and gathering operations Utica ü Near-term development expected to focus on acquired and DCNR Tract 007 pads Undeveloped Marcellus § Utica average lateral length of 10,000-11,000’ and consolidated well costs of $950-$1,050/ft (1) ü Continuing to optimize consolidated upstream and gathering development plan across expanded Tioga footprint 21

E&P and Gathering Integrated Development – EDA Tioga Gathering NFG Tioga Gathering Systems Support Growing Seneca Production Current Systems In-Service Tioga County Gathering Systems Map ü Tioga Gathering System (1) § Total Investment (to date): ~$237 million § 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) and Third-Party § NFG Covington Gathering System tie-in provides access to Eastern and Empire markets ü Covington Gathering System § Total Investment (to date): ~$50 million § Capacity: 220,000 Dth per day (Interconnect w/ TGP 300 line) § Production Source: Seneca Resources (Covington & DCNR Tract 595) ü 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) 22 (1) Includes Company’s acquisition of midstream gathering assets in July 2020, in the amount of ~$223 million.

E&P and Gathering EDA: Tioga County Development Production Underpinned by Firm Sales and Firm Transportation Contracts Tioga County Gas Marketing Strategy Tioga County Gross Firm Contract Volumes (MDth/d) 500 ü Production supported by firm transportation capacity to premium markets: 450 400 Leidy South Firm Sales § 250 MDth/d (Empire-NFG & Northeast Supply Diversification Project) provides *Capacity can be utilized by all three producing areas 350 (WDA, EDA-Tioga, and EDA-Lycoming) access to Dawn/TGP 200 markets 300 § Tioga production can be utilized to fill a 250 portion of Leidy South expansion Tioga County Extension (NFG - Empire) capacity 200 FT Capacity: 185,000 - 200,000 Dth/d 150 ü Seneca’s firm transportation and firm sales support DCNR Tract 007, DCNR Tract 595, 100 and Covington area production (1) EDA - TGP 300 Firm Sales 50 Northeast Supply Diversification Project FT Capacity: 50,000 Dth/d - Apr-22 Jul-22 Oct-22 Jan-23 Apr-23 Jul-23 Oct-23 23 (1) Includes physical fixed price and NYMEX-based firm sales contracts that do not carry any additional transportation costs.

E&P and Gathering EDA: Lycoming County Development Marcellus Development in Lycoming County Fully Utilizes Valuable Firm Transportation ü Prolific Marcellus acreage with average EUR of 2.5-3.0 Bcf / 1,000 ft ü ~30 remaining Marcellus locations § Average lateral length of 5,500-6,000’ and consolidated well costs of $1,050-$1,150/ft ü Potential for return trip Geneseo development EDA - Transco Firm Contracts 300 250 (1) Leidy South Firm Sales (2) 200 Transco Firm Sales 150 Atlantic Sunrise (Transco) FT Capacity: 189,405 Dth/d 100 Firm Sales: NYMEX/Market Indices 50 - Apr-22 Jul-22 Oct-22 Jan-23 Apr-23 Jul-23 Oct-23 (1) Capacity can be utilized by all three producing areas (WDA, EDA-Tioga, and EDA-Lycoming) 24 (2) Includes physical fixed price and NYMEX-based firm sales contracts that do not carry any additional transportation costs. Gross Firm Volumes (MDth/d)

E&P and Gathering Integrated Development – EDA Lycoming Gathering NFG Trout Run Gathering System Supports Seneca and Third-Party Development Current System In-Service Trout Run Gathering System Map ü Total Investment (to date): ~$272 million ü Capacity: 466,000 to 585,000 Dth per day ü Current Production Source: Seneca Resources (DCNR Tract 100 & Gamble) & Third-Party ü Interconnect: Transco (Leidy Line) Third-Party Volumes ü Gathering contracts executed, with volumes first online in November 2020 § Completed construction of new facilities, leveraging existing Trout Run system ü Expected to generate $10 million - $12 million in additional gathering revenues for fiscal 2022 (supported by minimum volume commitments) 25

E&P and Gathering Western Development Area (1) Marcellus Core Acreage vs. Utica Trend WDA Highlights ü Large well inventory: § Marcellus Shale: 600+ well locations remaining / 200,000 acres § Utica Shale: 500+ potential locations across Utica trend (2) / evaluating extent of prospective acreage ü Fee acreage (no royalty) enhances economics and provides development flexibility ü Highly contiguous position drives best in class well costs and program efficiencies Beechwood Utica Development Area ü Long-term firm contracts provide access to premium markets and support growth Boone Mountain Utica Test Well ü Beechwood area is focus of near-term Utica development Past Marcellus delineation tests Utica Trend (currently evaluating) program ? Marcellus Core Acreage (1) The Utica Shale lies approximately 5,000 feet beneath Seneca’s WDA Marcellus acreage. 26 (2) 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.

E&P and Gathering WDA Development Plan Beechwood Development Area Provides ~90 Potential Utica Locations with Strong Economics WDA Development Update WDA – Potential RV-Beechwood Utica Development Area ü WDA-CRV Area: producing from both Utica and Marcellus wells, with development focused on new Utica development pads as well as Utica/Marcellus return trips to existing pads § Avg. CRV Utica Production: ~210 MMcf/d § Avg. CRV Marcellus Production: ~215 MMcf/d ü WDA Beechwood Expansion: ~90 potential Utica locations § Average consolidated well costs of $950-$1,000/ft § Average lateral length of 10,000-11,000’ 27

E&P and Gathering Integrated Development – WDA Gathering System Gathering System Build-Out Tailored to Accommodate Seneca’s WDA Development Clermont Gathering System Map Current System In-Service § Capacity: 750 MMcf per day § Interconnects with TGP 300 and NFG Supply § Total Investment (to date): $358 million § 40,620 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 28

E&P and Gathering WDA Firm Transportation and Sales Capacity WDA Exit Capacity Supports Production and Enhances Consolidated Returns WDA Gas Marketing Strategy WDA Contracted Firm Transport and Gross Sales Volumes (MDth/d) 500 ü Will continue to layer-in firm sales deals of short and longer duration on TGP 300 to reduce spot 400 Leidy South Firm Sales exposure *Capacity can be utilized by all three producing areas (WDA, EDA-Tioga, and EDA-Lycoming) 300 ü WDA spot realizations track TGP Station 313 pricing, typically 15¢ - WDA - TGP 300 Firm Sales 200 20¢ better than TGP Marcellus Zone 4 100 Niagara Expansion Project (TGP and NFG) NYMEX & Dawn ü Leidy South provides additional 158,000 Dth/d capacity to premium markets - (Transco Zone 6 NNY) 29

E&P and Gathering Long-term Contracts Supporting Appalachian Production Seneca Appalachia Natural Gas Marketing Firm Contract / Transport Volumes (MDth/day) 1,200 Leidy South (Transco & NFG - Supply) Transco Zone 6 Non-NY 1,000 330,000 Dth/d *Capacity can be utilized by all three producing areas (WDA, EDA-Tioga, and EDA-Lycoming) 800 Tioga County Extension (NFG - Empire) Canada-Dawn & NY Markets 185,000 - 200,000 Dth/d 600 (1) In-Basin Firm Sales Contracts 400 Atlantic Sunrise (Transco) Mid-Atlantic & Southeast U.S. 189,405 Dth/d 200 Niagara Expansion (TGP & NFG - Supply) Canada-Dawn & TGP 200 158,000 Dth/d Northeast Supply Diversification (TGP) 50,000 Dth/d (Canada-Dawn) - Apr-22 Jul-22 Oct-22 Jan-23 Apr-23 Jul-23 Oct-23 30 (1) 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.

E&P and Gathering Near-term Firm Sales Provide Market & Price Certainty Net Contracted Firm Sales / Transport Volumes (Dth per day) (1) Contracted Index Price Differentials ($ per Dth) NYMEX Dawn Other Capped Fixed Price 934,800 900,600 881,900 199,700 210,000 203,200 $2.45 $2.67 $2.63 (3) 46,800 7,400 ($0.92) (3) (3) (3) 86,800 85,800 (2) 159,800 ($0.79) (2) (2) 30,800 ($1.12) 30,400 ($1.13) 36,200 ($0.85) 565,600 562,500 492,300 ($0.70) ($0.70) ($0.66) Q3 FY22 Q4 FY22 FY23 (Avg.) Gross Firm Sales Volumes (Dth per day) 1,051,400 1,079,600 1,026,700 (1) 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 and fiscal 2023 average, are primarily TGP 200 and Transco Zone 6 Non-NY markets, with the balance to other Transco markets. 31 (3) Refer to NYMEX Capped Firm Sales Additional Detail on appendix slide 54.

E&P and Gathering Fiscal 2022 Production Profile 158 Bcf of Appalachian Production Protected by Firm Sales (1) § 137 Bcf locked-in realizing net ~$2.28/Mcf (2) § 21 Bcf of additional firm sales 400 (4) 340-360 Bcfe ~3 Bcfe ~17 Bcf (3) 350 ~17 Bcf ~4 Bcf Spot production 300 assumed to be sold at $6.25 250 ~137 Bcf 200 150 100 ~172 Bcfe 50 0 YTD FY22 Price Certainty Hedged Firm Sales Unhedged Firm Spot Sales California Total Actuals Sales Seneca (1) Average realized price reflects uplift from financial hedges less fixed differentials under firm sales contracts and any firm transportation costs. (2) Includes ~17 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 ~4 Bcf of non-NYMEX indexed firm sales with existing NYMEX hedge. (3) Includes ~15 Bcf of firm sales with caps tied to NYMEX prices. See NYMEX Capped Firm Sales Additional Detail on appendix slide 54. 32 (4) Expected production through divestiture close date at June 30, 2022. Production (Bcfe)

E&P and Gathering Continued Decrease in E&P Operating Costs Increased Scale and Highly-Contiguous Operations Expected to Drive Lower Cash Unit Costs (4) Seneca Cash OpEx ($/Mcfe) Appalachia LOE ($/Mcfe) Approximately $0.28/Mcfe Reduction in Fees Paid to NFG’s Gathering Segment Comprise ~90% Expected Cash Unit Costs 2022E vs. 2018 Levels of Expected Appalachian Gathering & Transport LOE $1.40 $1.32 $0.69 $0.68 $0.67 $0.67 ~$0.67 $0.14 $1.22 $0.14 (1) $1.14 ~1.12 $0.09 $0.07 $0.07 $0.08 ~$0.09 $0.12 $0.34 $0.11 $0.13 $0.30 (5) <$1.00 $0.26 (2) $0.21 $0.20 (3) (3) $0.38 $0.32 $0.28 $0.25 $0.23 $0.61 $0.60 $0.60 $0.59 ~$0.58 (3) (3) $0.57 $0.57 $0.56 $0.56 $0.54 FY 2018 FY 2019 FY 2020 FY 2021 FY 2022E FY 2018 FY 2019 FY 2020 FY 2021 FY 2022E FY 2022 Pro Forma LOE (Gathering & Transport) LOE (Other) G&A Taxes & Other (1) Revised operating cost ranges include the impact of divestiture of Seneca’s California assets as of June 30, 2022. (2) G&A estimate represents the midpoint of the G&A guidance ranges for fiscal 2022. (3) The total of the two LOE components represents the midpoint of the LOE guidance ranges for fiscal 2022. FY20 Seneca LOE was $0.84/Mcfe (vs. total shown of $0.85) due to rounding. (4) See Non-GAAP Reconciliation at the end of this presentation for additional detail on Appalachian LOE & Gathering and Seneca LOE. 33 (5) Pro Forma expected operating costs adjusted to exclude California operations for fiscal 2022.

E&P and Gathering Sustainability Initiatives – RSG and Pneumatic Devices Responsible Gas Certification Pneumatic Devices Emissions Reduction Initiative Continue to systematically transition natural gas actuated pneumatic devices to Equitable Origin compressed air, electric, or solar powered compressed air to eliminate vented (100% of Appalachian Assets - Certified December 2021) methane emissions from pneumatic devices Certification focuses on five key principles: ü Committed to using compressed air, electric, or solar powered compressed air ü Social Impacts pneumatic devices on all new well pads ü Human Rights/Community Engagement ü Natural gas pneumatics on existing well pads will be converted to compressed air, ü Indigenous Peoples’ Rights electric, or solar powered compressed air ü Occupational Health & Safety/Fair Labor Standards ü Environmental Impacts/Biodiversity/Climate Change TrustWell by Project Canary (~300 MMcf/d - Certified March 2022) A natural gas generator provides ü Certification focuses on four key areas: power to an air § Air compressor § Water § Land § Community ü Continuous Emissions Monitoring Technology installed November 2021 34

Pipeline & Storage Overview National Fuel Gas Supply Corporation Empire Pipeline, Inc. 35

Pipeline & Storage Pipeline & Storage Segment Overview National Fuel Gas Supply Corporation (1) ü Contracted Capacity : § Firm Transportation: 3,284 MDth per day § Firm Storage: 70,693 Mdth (fully subscribed) (2) ü Rate Base : ~$1,173 million Empire Pipeline ü FERC Rate Proceeding Status: § Rate case settlement approved June 2020 Supply Corp. § Period 2 rates went into effect April 2022 Empire Pipeline, Inc. (1) ü Contracted Capacity : § Firm Transportation: 964 MDth per day § Firm Storage: 3,753 Mdth (fully subscribed) (2) ü Rate Base : ~$341 million ü FERC Rate Proceeding Status: § New rates went into effect January 2019 § Rate case settlement approved May 2019 (1) As of September 30, 2021 as disclosed in the Company’s fiscal 2021 Form 10-K. 36 (2) As of December 31, 2021 calculated from National Fuel Gas Supply Corporation’s and Empire Pipeline, Inc.’s 2021 FERC Form-2 reports, respectively.

Pipeline & Storage FM100 Project – Significant Investment by Supply Corp. (1) ü In-service date: December 1, 2021 ü Estimated capital cost: $230 million ü Annual revenue: ~$50 million § In-service: ~$35 million (lease revenues) (2) § April 2022: ~$15 million (negotiated revenue step-up) ü Underpinned by long-term lease agreement with Transco (15 years) ü Project includes best-in-class emissions controls, limiting carbon footprint from growing operations: § Installation of vent gas systems at both new compressor stations (reducing potential fugitive and operational emissions) § Use of compressed air-driven pneumatics and compressor air starts (reducing operational emissions) (1) Commenced partial in-service on December 1, 2021 (255,000 Dth/d), and full in-service on December 19, 2021. 37 (2) Based on Period 2 rates described in approved settlement of Supply Corporation rate proceeding. Period 2 rates went into effect April 2022.

Pipeline & Storage Continued Expansion of the Supply Corp. Line N System Line N to Monaca Project ü Shell Chemical Appalachia, LLC - On-system Delivery Point § In-service date: November 2019 TGP 219 § Contracted firm transport: 133,000 Dth/d § Capital cost: $24.5 million § Annual revenue: $5.6 million 2021 Line N Market Pull Projects ü Omnis Bailey Plant - On-system Delivery Point § In-service date: May 2021 § Contracted firm transport: 21,000 Dth/d Columbia Interconnect § Capital cost: $2.9 million Rover § Annual revenue: $1.2 million ü Columbia Gas of PA Interconnect – On-system Delivery Point § In-service date: October 2021 § Contracted firm transport/storage: 4,000 Dth/d / 267,000 Dth Omnis Bailey Interconnect § Capital cost: $0.8 million Holbrook § Annual revenue: $0.5 million 38

Pipeline & Storage Northern Access Project Delivery points: ü 350,000 Dth/d to Chippawa (TCPL interconnect) ü 140,000 Dth/d to East Aurora (TGP 200 line) Regulatory/legal status: To Dawn ü Feb. 2017 – FERC 7(c) certificate issued ü Aug. 2018 – FERC issued Order finding that NY DEC waived water quality certification (WQC) ü April 2019 – FERC denied rehearing of WQC waiver order (upholding waiver finding) ü March 2021 – U.S. Second Circuit Court of Appeals dismissed appeal of FERC waiver orders ü FERC certificate extension request pending 39

Pipeline & Storage Pipeline & Storage Customer Mix (1) Customer Transportation by Shipper Type Affiliated Customer Mix (Contracted Capacity) Outside Affiliated Non-Affiliated Pipeline 9% End User 8% 26% 52% Producer Marketer 7% 36% 84% 74% LDC 48% 40% 16% LDCs Producers Firm Storage Firm Transport 40 (1) Contracted as of 9/30/2021.

Utility Overview National Fuel Gas Distribution Corporation 41

Utility New York & Pennsylvania Service Territories New York (1) Total Customers : 539,000 (2) ROE: 8.7% (NY PSC Rate Case Order, April 2017) Rate Mechanisms: o Revenue Decoupling o Weather Normalization o Low Income Rates o Merchant Function Charge (Uncollectibles Adj.) o 90/10 Sharing (Large Customers) (3) o System Modernization Tracker Pennsylvania (1) Total Customers : 214,000 ROE: Black Box Settlement (2007) Rate Mechanisms: o Low Income Rates o Merchant Function Charge (1) As of September 30, 2021. (2) Earnings sharing under Rate Case Order started April 1, 2018 (50/50 sharing starts at ROE in excess of 9.2%). 42 (3) Applied to new plant placed in service through March 31, 2023.

Utility Utility Continues its Significant Investments in Safety Long-Standing Focus on Distribution System Safety and Reliability $125.0 (1) Capital Expenditures for Safety Total Capital Expenditures $100-$110 $100.8 $98.0 $95.8 $94.3 $100.0 $85.6 $80.9 $79.7 $74.1 $71.4 $75.0 $69.9 $63.6 $61.8 $50.0 $25.0 Modernization Spending in NY Expected to Add $3 MM - $4 MM in Gross Margin in FY 2022 $0.0 2016 2017 2018 2019 2020 2021 2022E Fiscal Year 43 (1) A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation. Utility Capital Expenditures ($ millions)

Utility Long-Standing Pipeline Replacement & Modernization (1) Utility Mains by Material Miles of Utility Main Pipeline Replaced Wrought Iron 159 158 156 154 Coated Bare 144 Cast Iron NY 9,782 miles Plastic Wrought Iron Bare Coated PA* 4,850 miles Plastic 2017 2018 2019 2020 2021 Calendar Year * No Cast Iron Mains in Pa.* 44 (1) All values are reported on a calendar year basis as of December 31, 2021.

Utility Utility Targeting Substantial Emissions Reductions Significant Reductions in Utility GHG Emissions to Date, GHG Reduction Targets, Continuing Focus on Lowering Driven by System Modernization Efforts Carbon Footprint (1) Utility GHG Emissions Reduction Targets Utility EPA Subpart W Emissions (Based on 1990 EPA Subpart W Emissions) (Thousand Metric Tons, CO e) 2 800 2030 2050 700 600 500 75% 90% 400 300 ü Targets Exceed Those Included in New York 200 (2) State Climate Act (CLCPA) 100 ü Reductions Primarily Driven by Ongoing 0 Modernization of Mains and Services 1990 1995 2000 2005 2010 2015 2020 (1) 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. 45 (2) New York Climate Leadership and Community Protection Act, enacted in 2019.

Utility Promoting Renewable Natural Gas and Hydrogen July 2021 Through Fiscal 2020 October 2020 Ongoing Accepted first RNG deliveries Petitioned NY PSC to include Awarded three RNG grants Continue to advance RNG into NY system from RNG in the supply mix and for $1.2 million through the anaerobic digester project and evaluate investment recover purchased RNG Utility’s Area Development (receipts estimated to be ~50 opportunities costs through gas supply Program MMcf/year) rates Substantial RNG Potential in New York Continuing to Work with Regulators and Third Parties to Advance Zero and Low Carbon Opportunities (1) RNG Potential in New York State (Bcf/Year) ü Distribution Corporation received approval from NY and PA utility Low Resource High Resource Technical commissions to accept RNG into its distribution system Scenario Scenario Potential Landfill 20 33 50 ü Low Carbon Resources Initiative (LCRI) expected to provide opportunities for NFG to leverage technology acceleration within Animal/Food Waste 7 13 37 its regional footprint Wastewater 2 3 7 ü Focused on the development of potential hydrogen projects Other 24 56 177 through membership in the Clean Hydrogen Economy consortium led by Guidehouse and NYSERDA-led Regional Clean Hydrogen All Sources 53 105 271 Hub consortium 46 (1) American Gas Foundation – Renewable Sources of Natural Gas: Supply and Emissions Reduction Assessment (December 2019).

Consolidated Financial Overview Upstream I Midstream I Downstream 47

Diversified, Balanced Earnings and Cash Flows (1) (2) Adjusted Operating Results ($ per share) Adjusted EBITDA ($ millions) $1,200 $5.70 to $6.00 $6.00 $1,086 $1,000 $1,000 $5.00 $4.29 E&P $542 $800 $4.00 $465 $1.83 $600 $3.00 $165 $159 Gathering $0.88 $2.00 $400 $219 $221 Rate Pipeline & Rate $1.01 $1.00 Storage Regulated $200 Regulated ~36% ~30% $171 $170 Utility $0.59 $0.00 $0 FY 2021 FY 2022 Guidance FY 2021 TTM 3/31/22 (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. (2) 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. 48

Disciplined, Flexible Capital Allocation (1) Capital Expenditures by Segment ($ millions) $1,000 (2) (3) Exploration & Production Gathering Pipeline & Storage Utility $725-$870 $781 $770 $719 $750 $583 $381 $475-$550 $492 $384 $500 $455 $356 $35 $246 $74 $50 $50-$60 $250 $252 $48 $33 $167 $143 $100-$150 $93 $95 $101 $100-$110 $96 $94 $81 $86 $0 2017 2018 2019 2020 2021 2022E Fiscal Year (1) 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. (2) 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. 49 (3) FY20 reflects the netting of $224 million related to the acquisition of Appalachian gathering assets in July 2020.

Maintaining Strong Balance Sheet & Liquidity (1) Net Debt / Adjusted EBITDA Capitalization Expect AOCI 3.08 x further 2.72 x 7% 2.61 x reduction in Total 2.47 x 2.48 x 2.45 x FY22 Equity Debt 40% 53% $4.7 Billion Total Capitalization 2017 2018 2019 2020 2021 TTM 2022E 3/31/2022 as of March 31, 2022 Fiscal Year Debt Maturity Profile by Fiscal Year ($MM) Liquidity $600 $549 $500 $500 $500 Committed Credit Facilities $ 1,000 MM Short-term Debt Outstanding (218 MM) $400 $300 $300 Available Short-term Credit Facilities 782 MM $200 Cash Balance at 3/31/22 53 MM Total Liquidity at 3/31/22 $ 835 MM $0 (1) 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. 50 (2) Includes Accumulated Other Comprehensive Loss of $654 MM as of March 31, 2022.

Appendix 51

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: 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 and system modernization), 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 inflationary pressures and 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; 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; impairments under the SEC’s full cost ceiling test for natural gas and oil reserves; the Company’s ability to estimate accurately the time and resources necessary to meet emissions targets; governmental/regulatory actions and/or market pressures to reduce or eliminate reliance on natural gas; increased costs or delays or changes in 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 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; 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; negotiations with the collective bargaining units representing the Company's workforce, including potential work stoppages during negotiations; 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, 2021 and the Form 10-Q for the quarter ended December 31, 2021 and March 31, 2022. 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. 52

Appendix Hedge Positions and Prices (1) 53 (1) Fixed price physical sales exclude joint development partner’s share of fixed price contract WDA volumes as specified under the joint development agreement.

Appendix NYMEX Capped Firm Sales Additional Detail $3.00 capped firm sales expire 10/31/22 (1) Values shown represent the 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 54 components.

Appendix Firm Transportation Commitments Volume Delivery Demand Charges Production Source Gas Marketing Strategy (Dth/d) Market ($/Dth) Northeast Supply Canada Firm Sales Contracts rd EDA – Tioga 50,000 $0.46 (3 party) Diversification (Dawn) Dawn/NYMEX Tennessee Gas Pipeline NFG pipelines - $0.24 158,000 Canada (Dawn) rd Niagara Expansion 3 party - $0.40 Firm Sales Contracts WDA – CRV TGP & NFG - Supply Dawn/NYMEX 12,000 TGP 200 (PA) $0.14 (NFG pipelines) Atlantic Sunrise Mid-Atlantic/ Firm Sales Contracts rd EDA - Lycoming 189,405 $0.73 (3 party) WMB - Transco Southeast NYMEX/Market Indices TGP 200 (NY) / Tioga County Extension Firm Sales Contracts 200,000 $0.23 (NFG pipelines) EDA – Tioga Canada (Dawn) NFG - Empire TGP 200 (PA)/NYMEX rd Eastern EDA – Tioga 100,000 In-Basin $0.14 (3 Party) Capacity release WDA – CRV Transco Zone Firm Sales Contracts Leidy South / FM100 rd 330,000 $0.66 (3 Party) WMB – Transco; NFG - Supply EDA - Lycoming 6 NNY Transco Zone 6 NNY/NYMEX NFG pipelines - $0.50 Canada (Dawn) Seneca to pursue firm sales 350,000 rd 3 party - $0.19 Northern Access WDA – CRV contracts as project development NFG – Supply and Empire TGP 200 (NY) 140,000 $0.38 (NFG pipelines) progresses 55 Currently In-Service

Appendix Primary Development Area Type Curves Lycoming Marcellus Tioga Utica WDA Utica 20 18 16 14 12 10 8 Estimated Cumulative Volumes (Bcf) Lycoming Tioga Utica WDA Utica 6 Year Marcellus (10,000 - (10,000- (5,500-6,000') 11,000') 11,000’) 4 1 3.5 5.9 2.7 5 9.5 14.1 8.0 10 12.2 17.3 10.8 2 EUR (Bcf) 14.5-16.8 19.0-24.0 15.8-18.9 NRI 84% 82-87% 100% 0 0 12 24 36 48 60 72 84 96 108 120 Months On 56 Cumulative Production, BCF

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 financialmeasuresandreconciliations areprovidedinthe slidesthat follow. The Company believes that its non-GAAP financial measures are useful to investors because they provide an alternative method for assessing theCompany’s ongoing operating results and for comparing theCompany’s financial performance to other companies. TheCompany’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 accordancewith GAAP. TheCompany’s fiscal 2022 earnings guidance range does not include the impact of certain items that impacted the comparability of earnings during the three months ended March 31, 2022, including: (1) the unrealized loss on other investments; and (2) the reduction of other post-retirement regulatory liability. While the Company expects to record additional adjustments to unrealized gain or loss on other investments during the six months ending September 30, 2022, the amounts of these and other potential adjustments arenot reasonablydeterminable atthistime. Assuch,the Company isunable toprovideearningsguidanceother than onanon-GAAPbasis. 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, other income and deductions, impairments, and other items reflected inoperating incomethat impactcomparability. Management defines Free Cash Flow as Funds from Operations (Net Cash Provided by Operating Activities less changes in working capital) 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,giventhe unknown effect,timing,and potential significanceofcertain incomestatement items. 57

Appendix Non-GAAP Reconciliations – Adjusted EBITDA (1) Reconciliation of Adjusted EBITDA to Consolidated Net Income ($ Thousands) 12-Months FY 2017 FY 2018 FY 2019 FY 2020 FY 2021 Ended 3/31/22 Total Adjusted EBITDA Exploration & Production Adjusted EBITDA $ 361,079 $ 317,707 $ 351,159 $ 312,166 464,529 542,090 Pipeline & Storage Adjusted EBITDA 180,328 183,972 162,181 189,520 218,921 220,734 Gathering Adjusted EBITDA 94,380 91,937 108,292 119,879 159,005 164,876 Utility Adjusted EBITDA 151,078 175,554 176,134 171,418 171,379 170,083 Corporate & All Other Adjusted EBITDA (9,725) (7,704) (12,393) (7,529) (13,521) (11,752) Total Adjusted EBITDA $ 777,140 $ 761,466 $ 785,373 $ 785,454 $ 1,000,313 $ 1,086,031 Total Adjusted EBITDA $ 777,140 $ 761,466 $ 785,373 $ 785,454 $ 1,000,313 $ 1,086,031 Minus: Interest Expense (119,837) (114,522) (106,756) (117,077) (146,357) (124,552) Plus: Other Income (Deductions) 11,156 (21,174) (15,542) (17,814) (15,238) 6,753 Minus: Income Tax Expense (160,682) 7,494 (85,221) (18,739) (114,682) (147,411) Minus: Depreciation, Depletion & Amortization (224,195) (240,961) (275,660) (306,158) (335,303) (347,664) Minus: Impairment of Oil and Gas Properties (E&P) - - - (449,438) (76,152) - Minus: Gain on Sale of Timber Properties - - - - 51,066 - Minus: Unrealized Gain (Loss) on Hedge Ineffectiveness (100) (782) 2,096 - - - Minus: Joint Development Agreement Professional Fees (E&P) - - - - - - Rounding - - - - - - Consolidated Net Income $ 283,482 $ 391,521 $ 304,290 $ ( 123,772) $ 363,647 $ 473,157 Consolidated Debt to Total Adjusted EBITDA Long-Term Debt, Net of Current Portion (End of Period) $ 2,099,000 $ 2,149,000 $ 2,149,000 $ 2,649,000 $ 2,649,000 $ 2,100,000 Current Portion of Long-Term Debt (End of Period) 300,000 - - - - 549,000 Notes Payable to Banks and Commercial Paper (End of Period) - - 55,200 30,000 158,500 218,000 Less: Cash and Temporary Cash Investments (End of Period) (555,530) (229,606) (20,428) (20,541) (31,528) (52,569) Total Net Debt (End of Period) $ 1,843,470 $ 1,919,394 $ 2,183,772 $ 2,658,459 $ 2,775,972 $ 2,814,431 Long-Term Debt, Net of Current Portion (Start of Period) 2,099,000 2,099,000 2,149,000 2,149,000 2,649,000 2,649,000 Current Portion of Long-Term Debt (Start of Period) - 300,000 - - - - Notes Payable to Banks and Commercial Paper (Start of Period) - - - 55,200 30,000 - Less: Cash and Temporary Cash Investments (Start of Period) (129,972) (555,530) (229,606) (20,428) (20,541) (80,467) Total Net Debt (Start of Period) $ 1,969,028 $ 1,843,470 $ 1,919,394 $ 2,183,772 $ 2,658,459 $ 2,568,533 Average Total Net Debt $ 1,906,249 $ 1,881,432 $ 2,051,583 $ 2,421,116 $ 2,717,216 $ 2,691,482 Average Total Net Debt to Total Adjusted EBITDA 2.45 x 2.47 x 2.61 x 3.08 x 2.72 x 2.48 x (1) Total Adjusted EBITDA for FY 2018, FY 2019, FY 2020, and FY 2021, 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 58 reclassification is not reflected in Total Adjusted EBITDA for FY 2017.

Appendix Non-GAAP Reconciliations – Adjusted EBITDA, by Segment Reconciliation of Adjusted EBITDA to Net Income, by Segment FY21 ($ Thousands) FY22 12-Months FY 2017 FY 2018 FY 2019 FY 2020 FY 2021 FYTD FYTD Ended 3/31/22 Exploration and Production Segment Reported GAAP Earnings $ 129,326 $ 180,632 $ 111,807 $ (326,904) $ 101,916 $ 133,490 $ 7,199 $ 228,207 Depreciation, Depletion and Amortization 112,565 124,274 154,784 172,124 182,492 100,054 91,471 191,075 Other (Income) Deductions (707) (307) (1,091) 882 937 241 412 766 Interest Expense 53,702 54,288 54,777 58,098 69,662 24,338 45,713 48,287 Income Taxes 66,093 (41,962) 32,978 (41,472) 33,370 47,328 6,943 73,755 Mark-to-Market Adjustment due to Hedge Ineffectiveness 100 782 (2,096) - - - - - Impairment of Oil and Gas Properties - - - 449,438 76,152 - 76,152 - Adjusted EBITDA $ 361,079 $ 317,707 $ 351,159 $ 312,166 $ 464,529 $ 305,451 $ 227,890 $ 542,090 Pipeline and Storage Segment Reported GAAP Earnings $ 68,446 $ 97,246 $ 74,011 $ 78,860 $ 92,542 $ 50,637 $ 49,112 $ 94,067 Depreciation, Depletion and Amortization 41,196 43,463 44,947 53,951 62,431 33,095 31,197 64,329 Other (Income) Deductions (3,978) (5,926) (9,157) (4,635) (5,840) (3,129) (2,045) (6,924) Interest Expense 33,717 31,383 29,142 32,731 40,976 20,750 21,283 40,443 Income Taxes 40,947 17,806 23,238 28,613 28,812 17,166 17,159 28,819 Adjusted EBITDA $ 180,328 $ 183,972 $ 162,181 $ 189,520 $ 218,921 $ 118,519 $ 116,706 $ 220,734 Gathering Segment Reported GAAP Earnings $ 40,377 $ 83,519 $ 58,413 $ 68,631 $ 80,274 $ 45,229 $ 41,250 $ 84,253 Depreciation, Depletion and Amortization 16,162 17,313 20,038 22,440 32,350 16,753 16,001 33,102 Other (Income) Deductions (995) (778) (460) (260) 12 85 (108) 205 Interest Expense 9,142 9,560 9,406 10,877 17,493 8,219 9,297 16,415 Income Taxes 29,694 (17,677) 20,895 18,191 28,876 16,802 14,777 30,901 Adjusted EBITDA $ 94,380 $ 91,937 $ 108,292 $ 119,879 $ 159,005 $ 87,088 $ 81,217 $ 164,876 Utility Segment Reported GAAP Earnings $ 46,935 $ 51,217 $ 60,871 $ 57,366 $ 54,335 $ 75,178 $ 55,081 $ 74,432 Depreciation, Depletion and Amortization 52,582 53,253 53,832 55,248 57,457 29,827 28,305 58,979 Other (Income) Deductions (1,825) 29,073 24,021 23,380 23,785 (9,510) 17,746 (3,471) Interest Expense 28,492 26,753 23,443 22,150 21,795 11,028 10,947 21,876 Income Taxes 24,894 15,258 13,967 13,274 14,007 23,034 18,774 18,267 Adjusted EBITDA $ 151,078 $ 175,554 $ 176,134 $ 171,418 $ 171,379 $ 129,557 $ 130,853 $ 170,083 Corporate and All Other Reported GAAP Earnings $ (1,602) $ (21,093) $ (812) $ (1,725) $ 34,580 $ (4,814) $ 37,568 $ (7,802) Depreciation, Depletion and Amortization 1,690 2,658 2,059 2,395 573 94 488 179 Gain on Sale of Timber Properties - - - - (51,066) - (51,066) - Other (Income) Deductions (3,651) (888) 2,229 (1,553) (3,656) 3,373 (2,954) 2,671 Interest Expense (5,216) (7,462) (10,012) (6,779) (3,569) (1,446) (2,546) (2,469) Income Taxes (946) 19,081 (5,857) 133 9,617 (1,974) 11,974 (4,331) 59 Adjusted EBITDA $ (9,725) $ (7,704) $ (12,393) $ (7,529) $ (13,521) $ (4,767) $ (6,536) $ (11,752)

Appendix Non-GAAP Reconciliations – Adjusted Operating Results 60

Appendix Non-GAAP Reconciliations – Capital Expenditures Reconciliation of Segment Capital Expenditures to Consolidated Capital Expenditures ($ Thousands) FY 2022 FY 2017 FY 2018 FY 2019 FY 2020 FY 2021 Guidance Capital Expenditures Exploration & Production Capital Expenditures $ 253,057 $ 380,677 $ 491,889 $ 670, 455 $ 381, 408 $475,000 - $550,000 Pipeline & Storage Capital Expenditures $ 95,336 $ 92,832 $ 143,003 $ 166, 652 $ 252, 316 $100,000 - $150,000 Gathering Segment Capital Expenditures $ 32,645 $ 61,728 $ 49,650 $ 297, 806 $ 34, 669 $50,000 - $60,000 Utility Capital Expenditures $ 80,867 $ 85,648 $ 95,847 $ 94, 273 $ 100, 845 $100,000 - $110,000 Corporate & All Other Capital Expenditures $ 212 $ 222 $ 855 $ 561 $ 450 Eliminations $ - $ (20,505) $ ( 1,130) $ 223 Total Capital Expenditures from Continuing Operations $ 462,117 $ 600,602 $ 781,246 $ 1,228,617 $ 769,911 $725,000 - $870,000 Plus (Minus) Acquisition of Upstream Assets and Midstream Gathering Assets $ ( 506,258) Plus (Minus) Accrued Capital Expenditures $ ( 47,887) (1) Exploration & Production FY 2020 Accrued Capital Expenditures $ ( 45,788) $ 42,983 Exploration & Production FY 2019 Accrued Capital Expenditures $ (38,063) $ 38,063 Exploration & Production FY 2018 Accrued Capital Expenditures $ (51,343) $ 51,343 Exploration & Production FY 2017 Accrued Capital Expenditures $ (36,465) $ 36,465 Exploration & Production FY 2016 Accrued Capital Expenditures $ 25,215 - $ ( 39,436) Pipeline & Storage FY 2020 Accrued Capital Expenditures $ ( 17,264) $ 17,264 Pipeline & Storage FY 2019 Accrued Capital Expenditures $ (23,771) $ 23,771 Pipeline & Storage FY 2018 Accrued Capital Expenditures $ (21,861) $ 21,861 Pipeline & Storage FY 2017 Accrued Capital Expenditures $ (25,077) $ 25,077 Pipeline & Storage FY 2016 Accrued Capital Expenditures $ 18,661 - $ ( 4,743) Gathering FY 2020 Accrued Capital Expenditures $ ( 13,524) $ 13,524 Gathering FY 2019 Accrued Capital Expenditures $ (6,595) $ 6,595 Gathering FY 2018 Accrued Capital Expenditures $ (6,084) $ 6,084 Gathering FY 2017 Accrued Capital Expenditures $ (3,925) $ 3,925 Gathering FY 2016 Accrued Capital Expenditures $ 5,355 - $ ( 10,634) Utility FY 2020 Accrued Capital Expenditures $ ( 10,751) $ 10,751 Utility FY 2019 Accrued Capital Expenditures $ (12,692) $ 12,692 Utility FY 2018 Accrued Capital Expenditures $ (9,525) $ 9,525 Utility FY 2017 Accrued Capital Expenditures $ (6,748) $ 6,748 Utility FY 2016 Accrued Capital Expenditures $ 11,203 Total Accrued Capital Expenditures $ (11,782) $ (16,597) $ 7,692 $ ( 6,206) $ ( 18,177) Total Capital Expenditures per Statement of Cash Flows $ 450, 335 $ 584, 004 $ 788, 938 $ 716, 153 $ 751, 734 $725,000 - $870,000 61 (1) Amount is $2,805 lower than the accrued capital expenditures reported in the prior year, representing certain liabilities assumed in connection with the 2020 acquisition of assets from Shell, capitalized as part of the asset acquisition cost, and subsequently paid by the Company. As the liabilities were owed and paid to third parties, they are not classified as capital expenditures in 2021.

Appendix Non-GAAP Reconciliations – E&P Operating Expenses Reconciliation of Exploration & Production Segment Operating Expenses by Division ($000s unless noted otherwise) Twelve Months Ended Twelve Months Ended September 30, 2021 September 30, 2020 (2) (2) (2) (2) Appalachia West Coast Total E&P Appalachia West Coast Total E&P Appalachia West Coast Total E&P Appalachia West Coast Total E&P $/ Mcfe $ / Boe $ / Mcfe $/ Mcfe $ / Boe $ / Mcfe Operating Expenses: (1) Gathering & Transportation Expense $185,151 $0 $185,151 $0.59 $0.00 $0.57 $136,994 $0 $136,994 $0.61 $0.00 $0.57 Other Lease Operating Expense $25,578 $56,587 $82,165 $0.08 $22.46 $0.25 $16,527 $50,149 $66,676 $0.07 $18.85 $0.28 Lease Operating and Transportation Expense $210,729 $56,587 $267,316 $0.67 $22.46 $0.82 $153,521 $50,149 $203,670 $0.68 $18.85 $0.84 General & Administrative Expense $67,973 $0.21 $63,429 $0.26 All Other Operating and Maintenance Expense $14,659 $0.04 $12,542 $0.05 Property, Franchise and Other Taxes $22,220 $0.07 $15,646 $0.06 Total Taxes & Other $36,879 $0.11 $28,188 $0.12 Depreciation, Depletion & Amortization $182,492 $0.56 $172,123 $0.71 Production: Gas Production (MMcf) 312,300 1,720 314,020 225,513 1,889 227,402 Oil Production (MBbl) 2 2,233 2,235 3 2,345 2,348 Total Production (Mmcfe) 312,313 15,117 327,430 225,529 15,958 241,487 Total Production (Mboe) 52,052 2,519 54,572 37,588 2,660 40,248 (1) Gathering and Transportation expense is net of any payments received from JDA partner for the partner's share of gathering cost. (2) Seneca West Coast division includes Seneca corporate and eliminations. 62

Appendix Non-GAAP Reconciliations – Free Cash Flow Reconciliation of Free Cash Flow ($ Thousands) FY 2021 Operating Cash Flow $ 791,553 Less: Change in Working Capital: Receivables and Unbilled Revenue $ (61,413) Gas Stored Underground and Materials, Supplies and Emission Allowances $ (2,014) Unrecovered Purchased Gas Costs $ (33,128) Other Current Assets $ (11,972) Accounts Payable $ 31,352 Amounts Payable to Customers $ (10,767) Customer Advances $ 1,904 Customer Security Deposits $ 2,093 Other Accruals and Current Liabilities $ 34,314 Other Assets $ 1,250 Other Liabilities $ (33,771) $ (82,152) Funds from Operations $ 873,705 Less: Capital Expenditures $ 751,734 Free Cash Flow $ 121,971 63