Exhibit 99 Investor Presentation Q3 Fiscal 2023 Update August 2, 2023

National Fuel is committed to the safe and environmentally conscious development, transportation, storage, and distribution of natural gas resources. For additional information, please review our Corporate Responsibility Report. 2

NFG: A Diversified, Integrated Natural Gas Company Developing our large, high-quality acreage Upstream position in Marcellus & Utica shales Exploration & Production ~1.2 Million ~1.04 Bcf/day 54% of NFG Net acres in Net Appalachian natural (1) EBITDA (2) Appalachia gas production Expanding and modernizing pipeline Midstream infrastructure to provide outlets for Gathering Appalachian natural gas production Pipeline & Storage 4.4 MMDth $2.4 Billion 35% of NFG 38% of NFG Daily interstate Investments (1) (1) EBITDA EBITDA pipeline capacity since 2010 under contract Providing safe, reliable and affordable Downstream service to customers in WNY and NW Pa. Utility % of NFG $788 Million 754,000 11% of NFG (1) 20EBITDA (1) Investments in safety Utility EBITDA customers since 2010 Note: This presentation includes forward-looking statements. Please review the safe harbor for forward looking statements at the end of this presentation. (1) Twelve months ended June 30, 2023. 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 (2) Average net Appalachian production for the three months ended June 30, 2023.

Why National Fuel? Diversified Assets Provide Stability and Long-Term Growth Opportunities Integrated Model Enhances Shareholder Value 1 Consolidated Business Expected to Generate Significant Free Cash Flow 2 High Quality Assets Drive Consolidated Growth 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 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 year 2023 and beyond 6 (1) The Company defines free cash flow at the end of this presentation.

Consolidated Business Expected to Generate Significant Free Cash Flow 2 . . . With Sustainable Free Cash Flow Generation Expected In Fiscal 2024 . . . Over the Long-Term $300 ü Regulated businesses focused on long-term modernization programs that are expected to lead to mid-single digit rate base growth $250 § Capital program expected to generally live within cash flows in ~$200 the near-term $200 ~$165 ü Exploration & Production and Gathering – Consolidated development program dually-focused on maximizing returns $150 ~$130 and free cash flow $100 § Maintenance-to-low growth program beyond fiscal 2024, is expected to drive growing free cash flow $50 ü Mitigation of Upstream business commodity risk through consistent hedging and marketing program, while maintaining upside $0 $3.25 $3.50 $3.00 $1.00 $2.00 $3.00 @ NYMEX Price ($/MMBtu) ü Improvement of investment grade credit profile through consistent free cash flow generation (1) The Company defines free cash flow as net cash provided by operating activities less capital expenditures. See non-GAAP financial measures information at the end of this presentation. Assumes current hedges. 7 Assumes no pricing-related curtailments. (1) Projected Free Cash Flow ($ Millions)

3 High Quality Assets Drive Consolidated Growth Regulated businesses provide stable, predictable growth that underpins integrated Appalachian development program Exploration & Production Utility ü Decades of high-quality, economic Marcellus ü Multi-year modernization program, focused on and Utica Shale inventory safety and reliability, delivers consistent and predictable rate base growth ü Significant firm transportation and sales portfolio to premium markets supports growth ü Low customer rates supports continued from two-rig development program infrastructure investment ü Consistent approach to hedging supports ü Focus on emissions reductions and alternative, continued free cash flow generation low-and-no carbon fuels supports additional growth Gathering Pipeline & Storage ü Integrated development with Seneca provides ü Ongoing investments in safety, emissions long runway for growth reduction, and modernization drive rate base growth ü Significant infrastructure in place and numerous interconnections with major ü Highly-interconnected pipeline network interstate pipelines provide opportunities to throughout the Appalachian Basin is positioned rd expand 3 party business well for future growth opportunities 8

4 Over Half Century of Dividend Growth $1.98 3.7% 53 Years 121 Years (1) per share yield Consecutive Dividend Increases Consecutive Payments $1.5 Billion 4.2% Dividend payments Over Last 10 Years 2023 Dividend Increase $0.19 per share Annual Rate at Fiscal Year End 9 (1) As of July 31, 2023.

5 Focused on Corporate Responsibility and ESG Corporate Responsibility & Climate Report provides Enhanced ESG Disclosures Responsive to Key Stakeholder Priorities ü Enhanced Diversity Disclosures – continued workforce EEO-1 diversity disclosures, as well as supply chain diversity initiatives ü Greenhouse Gas Emissions – disclosure of scope 1 and scope 2 emissions ü Progress Toward Emissions Reduction Targets – disclosed ongoing progress towards our targets focused on methane intensity for each business and overall GHG reduction for consolidated company ü Published Executive Summary of ESG Report – includes highlights of Company’s ongoing efforts and initiatives, along with key ESG metrics ü Alignment with TCFD – 2022 Climate Report further aligns the Company’s climate-risk disclosures with the TCFD framework ü Evaluating our Resilience to Climate Scenarios – Climate 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 10

Emissions Reduction Targets and Initiatives Significant Methane Intensity and Greenhouse Reduction Gas Emissions Reduction Targets Across the Ongoing Sustainability Initiatives (2) Since 2020 (1) Energy Value Chain ü Responsible Gas Certifications Exploration & 40% Reduction in Methane Intensity by 2030 4.9% Productionü Pneumatic Device Replacement ü Equipment upgrades at Existing Facilities Gathering 30% Reduction in Methane Intensity by 2030 ü Use of Best-in-Class Emissions Controls for 11.4% New Facilities ü Equipment upgrades at Existing Facilities 50% Reduction in Methane Intensity by 2030 24.1% 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 Utility 6.2% ü Advancing RNG in Service Territory ü ONE Future (3) v 25% Reduction in GHG Emissions by 2030 No change NFG ü EPA Methane Challenge (1) All emissions reduction targets based on 2020 baseline. (2) Measured using Calendar 2021 emissions data, as reported in Company’s 2021 Corporate Responsibility Report. 11 (3) Decreased methane intensity offset by growth in throughput and production.

Third Quarter Fiscal 2023 Financial Highlights 12

Third Quarter Fiscal 2023 Results and Drivers (1) Adjusted Operating Results ($/share) Q3 FY 2022 Q3 FY 2023 M Ma ajo jor r D Dr ri iv ver ers s $1.54 Natural Gas Prices $2.87 $2.27 Exploration & Production $1.01 $0.95 Appalachian Production / Exploration & Gathering Throughput 94.8 88.9 Production $0.48 California Production 3.5 N/A (FY 2022 Divestiture) Gathering California Appalachia Gathering $0.27 $0.26 Pipeline & Storage Pipeline & Storage $0.29 $0.26 Lower Expenses / Utility $0.05 Utility $0.00 Corporate/Other: ($0.02) California Divestiture $1.22 Corporate/Other: $0.01 $0.87 Q3 FY22 Q3 FY23 (1) A reconciliation of Adjusted Operating Results Per Share to Earnings Per Share is provided at the end of this presentation. 13 (2) Realized price after hedging. Upstream Cash Total Production Natural Gas Pricing Operating Costs (2) (Bcfe) ($/Mcfe) ($/Mcfe)

Earnings Guidance FY2023E Adjusted Operating Results FY2024 Preliminary Earnings Guidance (1) (1) $5.15 to $5.25/share $5.50 to $6.00/share Key Guidance Drivers § 390-410 Bcfe (up 7% vs. FY23E) Net Production (2) (2) Realized natural gas prices (after-hedge)§ ~$2.63-2.68/Mcf (vs. ~$2.55/Mcf in FY23E) Exploration & G&A Expense § $0.17-$0.19/Mcf (vs. ~$0.18/Mcf in FY23E) Production DD&A Expense § $0.66-$0.70/Mcf (vs. ~$0.63/Mcf in FY23E) LOE Expense § $0.69-$0.71/Mcf (vs. ~$0.675/Mcf in FY23E) Gathering Revenues § $240-$260 million (up 9% vs. FY23E) Gathering Gathering O&M Expense § ~$0.09/Mcf of throughput Pipeline & Storage Revenues § $380-$420 million (Supply Rate Increase) Pipeline & Storage O&M Expense § ~5% increase Pipeline & Pipeline & Storage Storage Pipeline & Storage Depreciation Expense § ~5% increase § ~20% increase Utility ‾ Pennsylvania rate increase / Weather normalization clause (PA) Utility Utility Operating Income ‾ System Modernization/ Improvement Tracker (NY) ‾ O&M ~5% increase Tax Rate Effective Tax Rate § ~25.5-26% (1) Excludes items impacting comparability. See Comparable GAAP Financial Measure Slides & Reconciliations at the end of this presentation. 14 (2) Assumes NYMEX pricing of $3.25/MMBtu and in-basin spot pricing of $2.45/MMBtu for fiscal 2024, and NYMEX pricing of $2.60/MMBtu and in-basin spot pricing of $1.60/MMBtu for remaining fiscal 2023 and reflects the impact of existing financial hedges, firm sales and firm transportation contracts. Regulated Non-Regulated

Exploration & Production & Gathering Overview Seneca Resources Company, LLC National Fuel Gas Midstream Company, LLC 15

E&P and Gathering Growing Production within Disciplined Capital Program E&P Net Production (Bcfe) Near-Term Strategy 400 ü Continue to moderate activity level to target maintenance-to-low production growth beyond 300 fiscal 2024 200 390-410 370-380 352.5 327.4 241.5§ Commenced transition to focus majority of 211.8 100 the development program in the EDA to 0 maximize long-term returns and capital 2019 2020 2021 2022 2023E 2024E efficiency (1) E&P Net Capital Expenditures ($ millions) ü EDA Tioga: development focused primarily on Utica $600 (modest Marcellus activity) $500 ü EDA Lycoming: activity maintains production level $400 $575 - that fully utilizes valuable Atlantic Sunrise capacity $525 - $300 $566 $600 $492 $575 $200 $384 $381 ü WDA: limited development focused on Utica Shale, $100 with return trips in Clermont-Rich Valley area $0 2019 2020 2021 2022 2023E 2024E 16 (1) A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation. FY20 reflects the netting of $286 million related to the acquisition of Appalachian upstream assets in July 2020.

E&P and Gathering EDA Transition Driving Improved Economics >10 years of prolific EDA inventory at expected development pace ü Decades of highly economic inventory across acreage position § Significant inventory expansion with acquisitions over the past three years ü Large, contiguous acreage position, driving increased capital efficiency with development supported by wholly-owned gathering infrastructure 12 Month Expected Cumulative Production 600 100% 500 80% 400 60% 300 40% 200 20% 100 0 0% FY22 FY23 FY24 FY25 Actuals Projected % EDA TILs 17 (1) Seneca Appalachian acreage is fee-owned, or leased from either the Pennsylvania Department of Conservation and Natural Resources or private landowners. 12- Mo. Cumulative Gas, MMCF/1,000' % EDA TILs

E&P and Gathering Eastern Development Area Seneca EDA Highlights EDA – ~306,000 Acres 1 Tioga County, PA ü ~200 Utica future development locations ü ~80 Marcellus future development 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 Marcellus future development 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) 18

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 Large, contiguous Tioga County development position supported by extensive gathering system Undeveloped ü Transition to primarily Tioga County development Utica results in better expected program IRRs ü Near-term development expected to focus on acquired Undeveloped acreage and DCNR Tract 007 pads Marcellus (1) ü Continuing to optimize consolidated upstream and gathering development plan across expanded Tioga County footprint 19

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): ~$278 million § Capacity: up to 550,000 Dth per day (Interconnects with Empire, Eastern, and TGP 300) § Production Source: Seneca Resources and Third-Party § NFG Covington Gathering System tie-in provides access to Eastern and Empire markets ü Covington Gathering System § Total Investment (to date): ~$52 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): ~$52 million § Capacity: up to 200,000 Dth per day (Interconnect w/ TGP 300 line) § Production Source: Seneca Resources (DCNR Tract 007) 20 (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) 600 ü Production supported by firm transportation capacity to premium markets: 500 (1) EDA - TGP 300/EGT Firm Sales § 250 MDth/d (Empire-NFG & Northeast 400 Supply Diversification Project) provides access to Dawn/TGP 200 markets Leidy South Firm Sales 300 *Capacity can be utilized by all three producing areas § Tioga production can be utilized to fill a (WDA, EDA-Tioga, and EDA-Lycoming) portion of Leidy South capacity 200 ü Seneca’s firm transportation and firm sales Tioga County Extension (NFG - Empire) FT Capacity: 200,000 Dth/d support Tioga County production 100 Northeast Supply Diversification Project FT Capacity: 50,000 Dth/d - Jul-23 Oct-23 Jan-24 Apr-24 Jul-24 Oct-24 21 (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 Marcellus future development locations § Currently developing 13-well pad with expected TIL fiscal 2024 ü Potential for return trip Geneseo development EDA - Transco Firm Contracts 250 (1) Leidy South Firm Sales (1) Leidy South Firm Sales 200 150 Atlantic Sunrise (Transco) Atlantic Sunrise (Transco) FT Capacity: 189,405 Dth/d 100 FT Capacity: 189,405 Dth/d Firm Sales: NYMEX/Market Indices Firm Sales: NYMEX/Market Indices 50 - Jul-23 Oct-23 Jan-24 Apr-24 Jul-24 Oct-24 22 (1) Capacity can be utilized by all three producing areas (WDA, EDA-Tioga, and EDA-Lycoming). 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): ~$279 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 ü Expected to generate third-party revenues of $10 – $13 million for fiscal 2023 and $10 – $15 million for fiscal 2024 (supported by minimum volume commitments) 23

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 Highly contiguous fee acreage (no royalty) enhances economics and provides development flexibility ü Early Beechwood area results are encouraging providing long-term development optionality Beechwood Utica Development Area ü Large gathering system with multiple interconnects provides access to firm transportation portfolio that reaches premium markets Boone Mountain Utica Test Well Past Marcellus delineation tests Utica Trend (currently evaluating) ? Marcellus Core Acreage (1) The Utica Shale lies approximately 5,000 feet beneath Seneca’s WDA Marcellus acreage. 24 (2) Appraisal program currently in progress. 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 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): ~$387 million § 40,620 HP of compression (3 stations) Future Build-Out § Minimal gathering pipeline and compression investment required to support Seneca’s near-term development program 25

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 450 deals of short and longer duration on TGP 300 to reduce spot 400 (1) WDA - TGP 300 Firm Sales exposure 350 300 ü WDA spot realizations track TGP Leidy South Firm Sales 250 Station 313 pricing, typically 15¢ *Capacity can be utilized by all three producing areas (WDA, EDA-Tioga, and EDA-Lycoming) 200 – 20¢ better than TGP Marcellus Zone 4 150 100 Niagara Expansion Project (TGP and NFG) ü Leidy South provides capacity to NYMEX & Dawn 50 premium markets (Transco Zone 6 158,000 Dth/d - NNY) Jul-23 Oct-23 Jan-24 Apr-24 Jul-24 Oct-24 26 (1) Includes physical fixed price and NYMEX-based firm sales contracts that do not carry any additional transportation costs.

E&P and Gathering Long-term Contracts Supporting Appalachian Production Seneca Appalachia Natural Gas Marketing Firm Contract / Transport Volumes (MDth/day) 1200 (1) Firm Sales Contracts 1000 Leidy South (Transco & NFG - Supply) Transco Zone 6 Non-NY 800 330,000 Dth/d *Capacity can be utilized by all three producing areas (WDA, EDA-Tioga, and EDA-Lycoming) 600 Tioga County Extension (NFG - Empire) Canada-Dawn & NY Markets 200,000 Dth/d 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) 0 Jul-23 Oct-23 Jan-24 Apr-24 Jul-24 Oct-24 27 (1) Represents approximate 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 (2) (2) (2) 47,000 32,200 53,300 ($0.19) ($1.54) $0.66 1,029,400 1,030,800 1,026,900 989,700 950,900 950,900 241,800 249,500 269,500 206,300 157,200 157,100 $2.38 $2.20 $2.44 $2.44 $2.50 $2.50 (3) (3) (3) (3) (3) 60,700 67,000 67,100 43,500 65,300 (3) 66,500 (2) (2) (2) 152,400 152,400 101,400 ($0.87) ($1.23) ($1.24) 53,700 ($0.88) 22,400 22,100 85,000 ($0.87) 85,000 ($0.87) 22,300 ($0.95) ($0.89) ($0.93) 681,900 658,900 615,500 563,000 ($0.65) ($0.63) 489,300 489,300 ($0.62) ($0.62) ($0.61) ($0.61) Q4 FY23 Q1 FY24 Q2 FY24 Q3 FY24 Q4 FY24 FY24 Avg Gross Firm Sales Volumes (Dth per day) 1,181,100 1,178,400 1,185,200 1,107,400 1,144,600 1,107,400 (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 2023 and fiscal 2024, are primarily TGP 200 and Transco Zone 6 Non-NY markets, with the balance to other Transco markets. 28 (3) Refer to NYMEX Capped Firm Sales Additional Detail on appendix slide 53.

E&P and Gathering Fiscal 2023 Production Profile 91 Bcf of Appalachian Production Protected by Firm Sales (1) § 54 Bcf locked-in realizing ~$2.28/Mcf , net of transportation (2) § 23 Bcf of no-cost collars with $3.54/Mcf floor (3) § 14 Bcf of additional firm sales 400 ~5 Bcf 370-380 Bcfe ~14 Bcfe 350 ~23 Bcfe Spot production ~54 Bcfe 300 assumed to be sold at 250 $1.60 200 150 ~279 Bcfe 100 50 0 YTD FY23 Price Certainty Floor Protection Unhedged Firm Sales Spot Sales Total Actuals Seneca (1) Average realized price reflects uplift from financial hedges less fixed differentials under firm sales contracts and any firm transportation costs. (2) Average weighted floor price (average weighted ceiling price of $4.25/Mcf). (3) Includes ~9 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 ~5 Bcf of firm sales with caps tied to NYMEX prices. 29 See NYMEX Capped Firm Sales Additional Detail on appendix slide 53. Production (Bcfe)

E&P and Gathering Fiscal 2024 Production Profile 352 Bcf of Appalachian Production Protected by Firm Sales (1) § 205 Bcf locked-in realizing ~$2.70/Mcf , net of transportation (2) § 64 Bcf of no-cost collars with $3.43/Mcf floor (3) § 83 Bcf of additional firm sales 390-410 Bcfe 400 ~48 Bcfe 350 ~83 Bcfe Spot production 300 assumed to be sold at ~$2.45 250 ~64 Bcfe 200 150 ~205 Bcfe 100 50 0 Price Certainty Floor Protection Unhedged Firm Sales Spot Sales Total Seneca (1) Average realized price reflects uplift from financial hedges less fixed differentials under firm sales contracts and any firm transportation costs. (2) Average weighted floor price (average weighted ceiling price of $4.29/Mcf). (3) Includes ~53 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 ~30 Bcf of firm sales with caps tied to NYMEX prices. 30 See NYMEX Capped Firm Sales Additional Detail on appendix slide 53. Production (Bcfe)

E&P and Gathering Competitive, Low-Cost Profile Operations Increased Scale and Highly-Contiguous Operations Drive Low Cash Unit Costs Seneca Cash OpEx ($/Mcfe) Operating results excluding $1.32 California operations $1.22 $0.14 $1.14 $1.13 $0.12 $0.12 $0.13 $0.97 ~$0.96 $0.30ü Fees Paid to NFG’s Gathering ~0.94 $0.26 $0.21 Segment Comprise >98% of $0.08 $0.11 $0.08 $0.20 (1) Expected Gathering & (1) $0.18 (2) $0.18 $0.18 $0.32 $0.28 Transport LOE $0.25 $0.24 (2) (2) $0.12 $0.10 $0.10 (3) (2) (2) (2) $0.58 $0.58 $0.58 $0.57 $0.57 $0.56 $0.56 FY 2019 FY 2020 FY 2021 FY 2022E FY 2022 FY 2023E FY2024E LOE (Gathering & Transport) LOE (Other) G&A Taxes & Other (1) G&A estimate represents the midpoint of the G&A guidance ranges for fiscal 2023 and fiscal 2024. 31 (2) The total of the two LOE components represents the midpoint of the LOE guidance ranges for fiscal 2023. FY20 Seneca LOE was $0.84/Mcfe (vs. total shown of $0.85) due to rounding.

E&P and Gathering Sustainability Initiatives Responsible Gas Certifications and Methane Detection Equitable Origin Methane Detection (100% of Appalachian Assets - Certified December 2021) ü For the past decade, standard pad design has included fixed gas detection ü 2022 Re-Verification assessment displays commitment to systems installed near production equipment to shut-in the pad if methane continuous improvement: is detected ü Regular Audio-Visual-Olfactory inspections of all assets ü Quarterly Leak Detection and Repair (LDAR) surveys of all assets ü Quarterly Aerial Facility-Scale Monitoring surveys of all assets ü Piloting continuous emissions monitoring equipment MiQ (100% of Appalachian Assets - Certified August 2022) Certification focuses on three emissions management criteria: ü Methane Intensity ü Company Practices to Manage Methane Emissions ü Emissions Monitoring Technology Deployment Achieved “A” certification grade - the highest certification level available 32

Pipeline & Storage Overview National Fuel Gas Supply Corporation Empire Pipeline, Inc. 33

Pipeline & Storage Pipeline & Storage Segment Overview National Fuel Gas Supply Corporation (1) ü Contracted Capacity : § Firm Transportation: 3,461 MDth per day § Firm Storage: 70,693 MDth (fully subscribed) (2) ü Rate Base : ~$1,179 million Empire Pipeline ü FERC Rate Proceeding Status: § Filed rate case on July 31, 2023 § New rates expected to go into effect (subject to refund) on Supply Corp. February 1, 2024 Empire Pipeline, Inc. (1) ü Contracted Capacity : § Firm Transportation: 964 MDth per day § Firm Storage: 3,753 MDth (fully subscribed) (2) ü Rate Base : ~$328 million ü FERC Rate Proceeding Status: § Rates in effect since January 2019 § Must file for new rates no later than May 31, 2025 (1) As of September 30, 2022 as disclosed in the Company’s fiscal 2022 Form 10-K. 34 (2) As of December 31, 2022 calculated from National Fuel Gas Supply Corporation’s and Empire Pipeline, Inc.’s 2022 FERC Form-2 reports, respectively.

Pipeline & Storage FM100 Project – Significant Investment by Supply Corp. (1) ü In-service date: December 1, 2021 ü Capital cost: ~$230 million (2) ü Annual revenue: ~$50 million 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 compressed 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. 35 (2) Includes impact of 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 Recent Expansion of Line N ü Over the past three years, the company has successfully placed Mercer into service several projects which have added: § Contracted firm transport: 158,000 Dth/d § Contracted firm storage: 267,000 Dth § Combined annual revenue: ~$7 million Additional Line N Expansion Opportunities Columbia Interconnect ü Interconnectivity of the system to other long-haul pipelines and Rover on-system load provides on-going opportunity to transport additional volumes ü Evaluating potential projects for end users, as well as projects for producers and marketers that could reach various markets, including to Rover and TGP Pipeline at Mercer Holbrook 36

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 Apr. 2019 – FERC denied rehearing of WQC waiver order (upholding waiver finding) ü Mar. 2021 – U.S. Second Circuit Court of Appeals dismissed appeal of FERC waiver orders ü Jun. 2022 – FERC granted extension of certificate until December 31, 2024 37

Pipeline & Storage Pipeline & Storage Customer Mix (1) Customer Transportation by Shipper Type Affiliated Customer Mix (Contracted Capacity) Affiliated Non-Affiliated End User 8% 23% Outside 52% Pipeline Producer 16% 34% 84% Marketer 5% 77% LDC 48% 37% 16% LDCs Producers Firm Storage Firm Transport 38 (1) Contracted as of 9/30/2022.

Utility Overview National Fuel Gas Distribution Corporation 39

Utility New York & Pennsylvania Service Territories New York (1) Total Customers : 540,000 (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 / Improvement Trackers Pennsylvania (1) Total Customers : 214,000 ROE: Black Box Settlement (2023) - $23 MM rate increase Rate Mechanisms: o Weather Normalization (added August 1, 2023) o Low Income Rates o Merchant Function Charge o Distribution System Improvement Charge (DSIC) – eligible (4) August 1, 2024 (1) As of September 30, 2022. (2) Earnings sharing under Rate Case Order started April 1, 2018 (50/50 sharing starts at ROE in excess of 9.2%). (3) Applied to new plant placed in service through September 30, 2024. 40 (4) Eligible to recover costs on incremental system investments after August 1, 2024, subject to attaining rate year plant balance of $781.3 million.

Utility Customer Affordability New York Pennsylvania #1 #3 (2) (1) Out of 6 Gas Utilities Out of 9 Gas Utilities New York Large Gas Utilities Monthly Bill Pennsylvania Large Gas Utilities Monthly Bill Residential Heating (based on 100 MCF annually) Residential Heating (based on 15 MCF monthly) $200 $350 $180 $300 $160 $140 $250 $120 $200 $100 $150 $80 $60 $100 $40 $50 $20 $0 $0 NFGDC Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Peer 1 Peer 2 NFGDC Peer 3 Peer 4 Peer 5 Peer 6 Peer 7 Peer 8 PA NY (1) Based on 2022 average monthly residential bill data posted on company websites required by the NYSPSC. 41 (2) Based on analysis of 2023 PAPUC Annual Rate Comparison Report, which includes data for average monthly residential bills for 2022.

Utility Utility Continues its Significant Investments in Safety Long-Standing Focus on Distribution System Safety and Reliability (1) Capital Expenditures for Safety Total Capital Expenditures $130-$150 $140.0 $125-$135 $111.0 $120.0 $100.8 $95.8 $94.3 $100.0 $85.6 $82.6 $79.7 $80.0 $74.1 $71.4 $69.9 $60.0 $40.0 Modernization Spending in NY Expected to Add $4 MM - $5 MM in Gross Margin in FY 2023 & $8-$9 MM in FY 2024 $20.0 $0.0 2018 2019 2020 2021 2022 2023E 2024E Fiscal Year 42 (1) A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation. Utility Capital Expenditures ($ millions)

Utility Long-Standing Pipeline Replacement & Modernization (1) Utility Mains by Material Miles of Utility Main Pipeline Replaced Wrought Iron 159 158 156 154 154 Coated Bare NY 9,798 miles Plastic Wrought Iron Bare Coated PA 4,845 miles Plastic 2018 2019 2020 2021 2022 Calendar Year 43 (1) All values are reported on a calendar year basis as of December 31, 2022.

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) (1) Utility GHG Emissions Reduction Targets Utility Mains & Services 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. 44 (2) New York Climate Leadership and Community Protection Act, enacted in 2019.

Utility Promoting Renewable Natural Gas and Hydrogen July 2021 Through Fiscal 2020 Ongoing Advance RNG, Hydrogen, and Accepted first RNG deliveries into Awarded three RNG grants for other CLCPA related NY system from anaerobic $1.2 million through the Utility’s digester project (receipts opportunities in the pending Area Development Program estimated to be ~50 MMcf/year) Utility Long-Term Plan Substantial RNG Potential in New York Continuing to Work with Regulators and Third Parties to (1) RNG Potential in New York State (Bcf/Year) Advance Zero and Low Carbon Opportunities Limited Achievable Optimistic Maximum ü Distribution Corporation received approval from NY and PA utility Adoption Deployment Growth Potential commissions to accept RNG into its distribution system Landfill 14 19 25 51 ü Low Carbon Resources Initiative (LCRI) expected to provide opportunities for NFG to leverage technology acceleration within its regional footprint Animal Manure 6 9 12 20 Food Waste 2 3 4 6ü Focused on the development of potential hydrogen projects through membership in the Clean Hydrogen Economy consortium led by Guidehouse Wastewater 2 2 3 7 and NYSERDA-led Regional Clean Hydrogen Hub consortium Other 23 56 102 188 ü Final Scoping Plan adopted by New York Climate Action Council includes consideration of alternative fuels and technologies in future gas system All Sources 47 90 147 272 planning 45 (1) NYSERDA– Potential of Renewable Natural Gas in New York State (April 2022).

Consolidated Financial Overview Upstream I Midstream I Downstream 46

Diversified, Balanced Earnings and Cash Flows (1) (2) Adjusted Operating Results ($ per share) Adjusted EBITDA ($ millions) $1,400 $7.00 $1,226 $1,202 $5.88 $1,200 $5.50 - $6.00 $6.00 $5.15 to $5.25 $1,000 $1,000 $5.00 $656 $645 E&P $3.21 $800 $4.00 $465 E&P $600 $3.00 $177 Gathering $182 $159 $1.01 Gathering $2.00 $400 Pipeline & $241 $219 $241 Pipeline & $1.11 $1.00 Storage $200 Storage $171 $163 $0.59 Utility $145 Utility $0.00 $0 FY 2022 FY 2023 FY 2024 FY 2021 FY 2022 TTM 6/30/23 Guidance Guidance (1) Excludes items impacting comparability. See Comparable GAAP Financial Measure Slides & Reconciliations at the end of this presentation. 47 (2) Consolidated Adjusted EBITDA includes Corporate & All Other. 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.

Disciplined, Flexible Capital Allocation (1) Capital Expenditures by Segment ($ millions) (2) (3) Exploration & Production Gathering Pipeline & Storage Utility $1,000 $905-$970 $865-$975 $829 $781 $770 $719 $750 $525-$575 $575-$600 $381 $566 $492 $384 $500 $35 $90-$110 $74 $95-$105 $50 $250 $56 $252 $120-$140 $110-$130 $167 $143 $96 $130-$150 $125-$135 $111 $101 $96 $94 $0 2019 2020 2021 2022 2023E 2024E 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) FY20 reflects the netting of $286 million related to the acquisition of Appalachian upstream assets in July 2020. FY23 reflects the netting of $139 million related to the acquisition of Appalachian upstream assets in June 2023. (3) FY20 reflects the netting of $224 million related to the acquisition of Appalachian gathering assets in July 2020. 48

Maintaining Strong Balance Sheet & Liquidity (1) Net Debt / Adjusted EBITDA Capitalization 3.08 x 2.72 x 2.61 x 2.47 x Total 2.22 x 2.12 x Equity Debt 54% 46% 2018 2019 2020 2021 2022 TTM $5.5 Billion Total Capitalization 6/30/2023 Fiscal Year (2) as of June 30, 2023 Debt Maturity Profile by Fiscal Year ($MM) Liquidity $ 1,000 MM Committed Credit Facilities $600 $600 (139 MM) $500 $500 $500 Short-term Debt Outstanding 862 MM Available Short-term Credit Facilities $400 $300 53 MM Cash Balance at 6/30/23 $200 $ 915 MM Total Liquidity at 6/30/23 $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. 49 (2) Total capitalization as presented here includes $139 MM of notes payable to banks and commercial paper, in addition to $5.3 B of Total Capitalization as presented on the balance sheet as of June 30, 2023.

Appendix 50

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 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 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; changes in economic conditions, including inflationary pressures, supply chain issues, liquidity challenges, 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; 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 reserves; increased costs or delays or changes in plans with respect to Company projects or related projects of other companies, 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; changes in price differentials between similar quantities of natural gas 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 reserves, including among others geology, lease availability and costs, 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 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 natural gas reserve estimates; significant differences between the Company’s projected and actual production levels for natural gas; changes in demographic patterns and weather conditions (including those related to climate change); 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, as well as economic and operational disruptions due to third-party outages; 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 gas quantities. Proved gas reserves are those quantities of 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 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, 2022 and the Forms 10-Q for the quarter ended December 31, 2022, March 31, 2023, and June 30, 2023. 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. 51

Appendix Hedge Positions and Prices Natural Gas Volumes in thousand MMBtu; Prices in $/MMBtu Remaining Fiscal 2023 Fiscal 2024 Q4 Q1 Q2 Q3 Q4 Avg. Avg. Avg. Avg. Avg. Volume Price Volume Price Volume Price Volume Price Volume Price NYMEX Swaps 32,820 $2.88 30,620 $3.16 34,770 $3.39 34,770 $3.39 34,770 $3.39 No Cost Collars 23,940 $3.43 / $4.13 19,380 $3.43 / $4.38 17,100 $3.42 / $4.56 14,400 $3.22 / $3.79 14,400 $3.22 / $3.79 Fixed Price Physical 23,006 $2.20 22,002 $2.38 24,795 $2.44 14,304 $2.50 14,454 $2.50 Total 79,766 72,002 76,665 63,474 63,624 Natural Gas Volumes in thousand MMBtu; Prices in $/MMBtu Fiscal 2025 Fiscal 2026 Fiscal 2027 Avg. Avg. Avg. Volume Price Volume Price Volume Price NYMEX Swaps 80,560 $3.49 29,020 $3.98 12,750 $4.27 No Cost Collars 43,960 $3.49 / $4.65 42,720 $3.53 / $4.76 3,560 $3.53/ $4.76 Fixed Price Physical 73,371 $2.49 65,847 $2.39 45,656 $2.39 Total 197,891 137,587 61,966 52 (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 Capped Firm Sales - Net Contracted Volumes (Dth/d) NYMEX Cap Q4 FY23 Q1 FY24 Q2 FY24 Q3 FY24 Q4 FY24 FY24 Avg $2.92 26,100 29,100 29,300 29,500 29,600 29,400 $4.95 17,400 17,500 16,800 16,900 16,900 17,000 $7.00 0 14,100 20,400 20,600 20,600 18,900 Total 43,500 60,700 66,500 67,000 67,100 65,300 (1) Capped Firm Sales - Weighted Average Index Price Differentials ($/Dth) Q4 FY23 Q1 FY24 Q2 FY24 Q3 FY24 Q4 FY24 FY24 Avg NYMEX Price (43,500) (60,700) (66,500) (67,000) (67,100) (65,300) $2.00 ($0.57) ($0.52) ($0.51) ($0.51) ($0.51) ($0.51) $2.50 ($0.57) ($0.52) ($0.51) ($0.51) ($0.51) ($0.51) $3.00 ($0.59) ($0.56) ($0.55) ($0.55) ($0.55) ($0.55) $3.50 ($0.89) ($0.80) ($0.77) ($0.77) ($0.77) ($0.78) $4.00 ($1.19) ($1.04) ($0.99) ($0.99) ($0.99) ($1.00) $4.50 ($1.49) ($1.28) ($1.18) ($1.18) ($1.18) ($1.20) $5.00 ($1.81) ($1.53) ($1.44) ($1.44) ($1.44) ($1.46) (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 53 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 3 party - $0.40 Niagara Expansion Firm Sales Contracts WDA – CRV TGP & NFG - Supply Dawn/NYMEX TGP 200 (PA) $0.18 (NFG pipelines) 12,000 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) 158,000 NFG pipelines - $0.23 Tioga County Extension Firm Sales Contracts EDA – Tioga NFG pipelines - $0.23 NFG – Empire TGP 200 (NY)/NYMEX/Dawn Canada (Dawn) 42,000 rd 3 party - $0.15 rd Eastern EDA – Tioga 100,000 In-Basin $0.19 (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 54 Currently In-Service

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. 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 in operating income that impact comparability. Management defines Free Cash Flow as Net Cash Provided by Operating Activities less Capital Expenditures. In prior presentations, Management defined 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 its respective comparable financial measure calculated in accordance with GAAP without unreasonable efforts. This is due to our inability to reliably predict 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. 55

Appendix Non-GAAP Reconciliations – Adjusted EBITDA Reconciliation of Adjusted EBITDA to Consolidated Net Income ($ Thousands) 12-Months FY 2018 FY 2019 FY 2020 FY 2021 FY 2022 Ended 6/30/2023 Total Adjusted EBITDA Exploration & Production Adjusted EBITDA $ 317,707 $ 351,159 $ 312,166 464,529 656,310 645,377 Pipeline & Storage Adjusted EBITDA 183,972 162,181 189,520 218,921 240,904 240,910 Gathering Adjusted EBITDA 91,937 108,292 119,879 159,005 176,572 182,343 Utility Adjusted EBITDA 175,554 176,134 171,418 171,379 162,871 144,581 Corporate & All Other Adjusted EBITDA (7,704) (12,393) (7,529) (13,521) (10,762) (11,490) Total Adjusted EBITDA $ 761,466 $ 785,373 $ 785,454 $ 1,000,313 $ 1,225,895 $ 1,201,721 Consolidated Net Income $ 391,521 $ 304,290 $ (123,772) $ 363,647 $ 566,021 $ 561,331 Plus: Interest Expense 114,522 106,756 117,077 146,357 130,357 132,480 Minus: Other Income (Deductions) 21,174 15,542 17,814 15,238 1,509 (7,954) Plus: Income Tax Expense (7,494) 85,221 18,739 114,682 116,629 121,782 Plus: Depreciation, Depletion & Amortization 240,961 275,660 306,158 335,303 369,790 394,082 Plus: Impairment of Oil and Gas Properties (E&P) - - 449,438 76,152 - - Plus: Gain on Sale of Timber Properties - - - (51,066) - - Plus: Gain on Sale of California Properties - - - - (12,736) - Plus: Loss from discontinuance of oil cash flow hedges (E&P) - - - - 44,632 - Plus: Transaction and severance costs related to West Coast asset sale (E&P) - - - - 9,693 - Plus: Unrealized Gain (Loss) on Hedge Ineffectiveness 782 (2,096) - - - - Rounding - - - - - - Total Adjusted EBITDA $ 761,466 $ 785,373 $ 785,454 $ 1,000,313 $ 1,225,895 $ 1,201,721 Consolidated Debt to Total Adjusted EBITDA Long-Term Debt, Net of Current Portion (End of Period) $ 2,149,000 $ 2,149,000 $ 2,649,000 $ 2,649,000 $ 2,100,000 $ 2,400,000 Current Portion of Long-Term Debt (End of Period) - - - - 549,000 - Notes Payable to Banks and Commercial Paper (End of Period) - 55,200 30,000 158,500 60,000 138,500 Less: Cash and Temporary Cash Investments (End of Period) (229,606) (20,428) (20,541) (31,528) (46,048) (53,415) Total Net Debt (End of Period) $ 1,919,394 $ 2,183,772 $ 2,658,459 $ 2,775,972 $ 2,662,952 $ 2,485,085 Long-Term Debt, Net of Current Portion (Start 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 (Start of Period) 300,000 - - - - 549,000 Notes Payable to Banks and Commercial Paper (Start of Period) - - 55,200 30,000 158,500 400,000 Less: Cash and Temporary Cash Investments (Start of Period) (555,530) (229,606) (20,428) (20,541) (31,528) (432,576) Total Net Debt (Start of Period) $ 1,843,470 $ 1,919,394 $ 2,183,772 $ 2,658,459 $ 2,775,972 $ 2,616,424 Average Total Net Debt $ 1,881,432 $ 2,051,583 $ 2,421,116 $ 2,717,216 $ 2,719,462 $ 2,550,755 Average Total Net Debt to Total Adjusted EBITDA 2.47 x 2.61 x 3.08 x 2.72 x 2.22 x 2.12 x 56

Appendix Non-GAAP Reconciliations – Adjusted EBITDA, by Segment Reconciliation of Adjusted EBITDA to Net Income, by Segment ($ Thousands) FY23 FY22 12-Months FYTD FY 2018 FY 2019 FY 2020 FY 2021 FY 2022 FYTD Ended 6/30/23 Exploration and Production Segment Reported GAAP Earnings $ 180,632 $ 111,807 $ (326,904) $ 101,916 $ 306,064 $ 195,503 $ 189,987 $ 311,580 Depreciation, Depletion and Amortization 124,274 154,784 172,124 182,492 208,148 174,747 155,190 227,705 Other (Income) Deductions (307) (1,091) 882 937 3,210 56 (55) 3,321 Interest Expense 54,288 54,777 58,098 69,662 53,401 39,049 38,927 53,523 Income Taxes (41,962) 32,978 (41,472) 33,370 43,898 69,785 64,435 49,248 Mark-to-Market Adjustment due to Hedge Ineffectiveness 782 (2,096) - - - - - - Impairment of Oil and Gas Properties - - 449, 438 76,152 - - - - Gain on Sale of West Coast assets - - - - (12,736) - (12,736) 0 Loss from discontinuance of crude oil cash flow hedges - - - - 44,632 - 44, 632 0 Transaction and severance costs related to West Coast asset sale - - - - 9,693 - 9,693 0 Adjusted EBITDA $ 317,707 $ 351,159 $ 312,166 $ 464,529 $ 656,310 $ 479,140 $ 490,073 $ 645,377 Pipeline and Storage Segment Reported GAAP Earnings $ 97,246 $ 74,011 $ 78,860 $ 92,542 $ 102,557 $ 77,147 $ 77,236 $ 102,468 Depreciation, Depletion and Amortization 43,463 44,947 53,951 62,431 67,701 52,874 50,417 70,158 Other (Income) Deductions (5,926) (9,157) (4,635) (5,840) (6,889) (8,643) (4,632) (10,900) Interest Expense 31,383 29,142 32,731 40,976 42,492 32,702 31,564 43,630 Income Taxes 17,806 23,238 28,613 28,812 35,043 27,010 26,499 35,554 Adjusted EBITDA $ 183,972 $ 162,181 $ 189,520 $ 218,921 $ 240,904 $ 181,090 $ 181,084 $ 240,910 Gathering Segment Reported GAAP Earnings $ 83,519 $ 58,413 $ 68,631 $ 80,274 $ 101,111 $ 73,207 $ 69,887 $ 104,431 Depreciation, Depletion and Amortization 17,313 20,038 22,440 32,350 33,998 26,613 25,343 35,268 Other (Income) Deductions (778) (460) (260) 12 26 (570) 87 (631) Interest Expense 9,560 9,406 10,877 17,493 16,488 11,556 12,383 15,661 Income Taxes (17,677) 20,895 18,191 28,876 24,949 28,203 25,538 27,614 Adjusted EBITDA $ 91,937 $ 108,292 $ 119,879 $ 159,005 $ 176,572 $ 139,009 $ 133,238 $ 182,343 Utility Segment Reported GAAP Earnings $ 51,217 $ 60,871 $ 57,366 $ 54,335 $ 68,948 $ 55,574 $ 79,800 $ 44,722 Depreciation, Depletion and Amortization 53,253 53,832 55,248 57,457 59,760 45,425 44,592 60,593 Other (Income) Deductions 29,073 24,021 23,380 23,785 (7,117) (4,898) (7,180) (4,835) Interest Expense 26,753 23,443 22,150 21,795 24,115 26,193 17,115 33,193 Income Taxes 15,258 13,967 13,274 14,007 17,165 16,016 22,273 10,908 Adjusted EBITDA $ 175,554 $ 176,134 $ 171,418 $ 171,379 $ 162,871 $ 138,310 $ 156,600 $ 144,581 Corporate and All Other Reported GAAP Earnings $ (21,093) $ (812) $ (1,725) $ 34,580 $ (12,659) $ 1,758 $ (9,031) $ (1,870) Depreciation, Depletion and Amortization 2,658 2,059 2,395 573 183 314 139 358 Gain on Sale of Timber Properties - - - (51,066) - - - - Other (Income) Deductions (888) 2,229 (1,553) (3,656) 12,279 1,301 8,489 5,091 Interest Expense (7,462) (10,012) (6,779) (3,569) (6,139) (10,516) (3,128) (13,527) Income Taxes 19,081 (5,857) 133 9,617 (4,426) (589) (3,473) (1,542) 57 Adjusted EBITDA $ (7,704) $ (12,393) $ (7,529) $ (13,521) $ (10,762) $ (7,732) $ (7,004) $ (11,490)

Appendix Non-GAAP Reconciliations – Adjusted Operating Results 58

Appendix Reconciliation – Capital Expenditures Reconciliation of Segment Capital Expenditures to Consolidated Capital Expenditures ($ Thousands) FY 2023 FY 2024 FY 2019 FY 2020 FY 2021 FY 2022 Guidance Guidance Capital Expenditures Exploration & Production Capital Expenditures $ 4 91,889 $ 6 70,455 $ 3 81,408 $ 5 65,791 $575,000 - $600,000 $525,000 - $575,000 Pipeline & Storage Capital Expenditures $ 1 43,003 $ 1 66,652 $ 2 52,316 $ 9 5,806 $110,000 - $130,000 $120,000 - $140,000 Gathering Segment Capital Expenditures $ 4 9,650 $ 2 97,806 $ 3 4,669 $ 5 5,546 $95,000 - $105,000 $90,000 - $110,000 Utility Capital Expenditures $ 9 5,847 $ 9 4,273 $ 1 00,845 $ 1 11,033 $125,000 - $135,000 $130,000 - $150,000 Corporate & All Other Capital Expenditures $ 8 55 $ 561 $ 450 $ 1 ,212 Eliminations $ ( 1,130) $ 223 Total Capital Expenditures from Continuing Operations $ 7 81,246 $ 1,228,617 $ 769,911 $ 829,388 $905,000 - $970,000 $865,000 - $975,000 Plus (Minus) Acquisition of Upstream Assets and Midstream Gathering Assets $ ( 506,258) Plus (Minus) Accrued Capital Expenditures $ ( 82,943) Exploration & Production FY 2021 Accrued Capital Expenditures $ ( 47,887) $ 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 $ 5 1,343 Exploration & Production FY 2017 Accrued Capital Expenditures $ ( 15,188) Pipeline & Storage FY 2021 Accrued Capital Expenditures $ ( 39,436) $ 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 $ 2 1,861 Pipeline & Storage FY 2017 Accrued Capital Expenditures $ ( 10,724) Gathering FY 2021 Accrued Capital Expenditures $ ( 4,743) $ 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 Gathering FY 2017 Accrued Capital Expenditures $ ( 11,407) Utility FY 2021 Accrued Capital Expenditures $ ( 10,634) $ 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 Utility FY 2017 Accrued Capital Expenditures Total Accrued Capital Expenditures $ 7 ,692 $ ( 6,206) $ ( 18,177) $ ( 17,562) Total Capital Expenditures per Statement of Cash Flows $ 7 88,938 $ 7 16,153 $ 7 51,734 $ 8 11,826 $905,000 - $970,000 $865,000 - $975,000 59 (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 Reconciliation – 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, 2022 September 30, 2021 (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 $199,405 $0 $199,405 $0.58 $0.00 $0.57 $185,151 $0 $185,151 $0.59 $0.00 $0.57 Other Lease Operating Expense $32,604 $51,905 $84,509 $0.10 $28.99 $0.24 $25,578 $56,587 $82,165 $0.08 $22.46 $0.25 Lease Operating and Transportation Expense $232,009 $51,905 $283,914 $0.68 $28.99 $0.81 $210,729 $56,587 $267,316 $0.67 $22.46 $0.82 General & Administrative Expense $79,061 $0.22 $67,973 $0.21 All Other Operating and Maintenance Expense $20,140 $0.06 $14,659 $0.04 Property, Franchise and Other Taxes $25,364 $0.07 $22,220 $0.07 Total Taxes & Other $45,504 $0.13 $36,879 $0.11 Depreciation, Depletion & Amortization $208,148 $0.59 $182,492 $0.56 Production: Gas Production (MMcf) 341,699 1,211 342,911 312,300 1,720 314,020 Oil Production (MBbl) 16 1,588 1,604 2 2,233 2,235 Total Production (Mmcfe) 341,796 10,741 352,536 312,313 15,117 327,430 Total Production (Mboe) 56,966 1,790 58,756 52,052 2,519 54,572 (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. 60