Exhibit 99 Investor Presentation Q4 Fiscal 2023 Update November 1, 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 ~1.02 Bcf/day 53% of NFG (2) Net acres in Net total production (1) EBITDA Appalachia Expanding and modernizing pipeline Midstream infrastructure to provide outlets for Gathering Appalachian natural gas production Pipeline & Storage 4.4 MMDth $2.7 Billion 36% 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 $897 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 September 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 production for the three months ended September 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

2 Consolidated Business Expected to Generate Significant Free Cash Flow . . . With Sustainable Free Cash Flow Generation Expected In Fiscal 2024 . . . Over the Long-Term $300 ✓ Regulated businesses focused on long-term modernization programs that are expected to lead to mid-single digit rate base growth $250 ~$235 ▪ Capital program expected to generally live within cash flows in ~$200 the near-term $200 ~$170 ✓ Exploration & Production and Gathering – Consolidated development program dually-focused on maximizing returns $150 and free cash flow $100 ▪ Maintenance-to-low growth program beyond fiscal 2024, is expected to drive growing free cash flow $50 ✓ 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) ✓ 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 net cash used in investing activities, adjusted for acquisitions and divestitures. See non-GAAP financial measures information 6 at the end of this presentation. Assumes current hedges. Assumes no pricing-related curtailments. (1) Projected Free Cash Flow ($ Millions)

3 High Quality Assets Drive Consolidated Growth Significant long-term growth potential in earnings and free cash flow supported by mid-single digit regulated rate base growth and increasing natural gas price realizations 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 zero-carbon fuels supports additional growth Gathering Pipeline & Storage ü Integrated development with Seneca provides ü Ongoing investments in safety, emissions near-term growth and long-term free cash flow reduction, and modernization drive rate base visibility growth ü Significant infrastructure in place and ü Expansion Projects – Tioga Pathways Project numerous interconnections with major expected to add $15 MM in late calendar 2026 interstate pipelines provide opportunities to rd expand 3 party business ü Highly-interconnected pipeline network throughout the Appalachian Basin is positioned well for future growth opportunities 7

4 Over Half Century of Dividend Growth $1.98 3.9% 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 8 (1) As of October 30, 2023.

5 Focused on Corporate Responsibility and ESG Latest Corporate Responsibility Report provides Enhanced ESG Disclosures on Sustainability Initiatives ü Continued Progress Toward Emissions Reduction Targets ü Independent Third-party Verification of Greenhouse Gas Emissions – external assurance of reported 2020, 2021, and 2022 scope 1 and scope 2 emissions ü Emphasis on Biodiversity and Environmental Initiatives ü Focus on Energy Transition Teams ü Enhanced Waste Management Disclosures ü Evaluating our Resilience to Climate Scenarios – 2022 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 9

Emissions Reduction Targets and Initiatives Significant Methane Intensity and Greenhouse Progress 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 27.4% 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 14.3% New Facilities ü Equipment upgrades at Existing Facilities 50% Reduction in Methane Intensity by 2030 18.2% Pipeline & Storage ü Use of Best-in-Class Emissions Controls for New Facilities ü Investment in System Modernization vü Advancing RNG in Service Territory 30% Reduction in Methane Intensity by 2030 Utility 8.3% ü Hydrogen Blending Demonstration Projects (3) +1% ü ONE Future v 25% Reduction in GHG Emissions by 2030 54% production growth NFG ü EPA Methane Challenge 8% throughput growth (1) All emissions reduction targets based on 2020 baseline. (2) Measured using Calendar 2022 emissions data, as reported in Company’s 2022 Corporate Responsibility Report. 10 (3) Total GHG emissions largely flat vs. 2020 despite significant production and throughput growth. Total methane emissions decreased by ~7%.

Fourth Quarter and Fiscal 2023 Financial Highlights Fiscal 2024 Earnings Guidance 11

Fourth Quarter Fiscal 2023 Results and Drivers (1) Adjusted Operating Results ($/share) Q4 FY 2022 Q4 FY 2023 Major Drivers $1.19 $2.84 Natural Gas Prices $2.33 Exploration & $0.78 $0.95 Production $0.81 Exploration & Production Natural Gas Production / $0.38 93.7 87.9 Gathering Throughput Gathering Gathering $0.25 $0.29 Pipeline & Storage Pipeline & Storage $0.27 $0.25 $0.98 $0.94 Increased Scale Utility: ($0.12) Utility: ($0.08) Corporate/Other: ($0.02) Corporate/Other: ($0.06) Q4 FY22 Q4 FY23 (1) A Reconciliation of Adjusted Operating Results to Earnings Per Share is provided at the end of this presentation. 12 (2) Realized price after hedging. E&P Cash Operating Net Gas Production Natural Gas Pricing (2) Costs ($/Mcfe) (Bcf) ($/Mcfe)

Fiscal 2023 Highlights (1) Down 5% vs. FY22 despite natural gas prices lower by 45% Adjusted EBITDA $1.2 billion rd Dividend Grew shareholder distribution for 53 consecutive year $1.98 per share Up 6% vs. FY22; highest output in NFG history Production 372.5 Bcfe Proved Reserves Up 9% vs. FY22; replaced 198% of production 4.5 Tcfe Gathering Up 8% vs FY22; highest throughput in NFG history 453 Bcfe Throughput Pipeline & Storage Up from $377.0 Million in FY22; Filed Supply Corp. rate case $379.2 Million with FERC for new rates in effect Feb. 2024, subject to refund. Revenues Utility Safety Ongoing focus on pipeline replacement and modernization; $108.6 Million Settlement in PA rate case increasing base rates $23 Million Investments Corporate Enhanced climate-related disclosures and publication of Fourth Annual Report continued progress against emissions reduction targets Responsibility 13 (1) A reconciliation of Adjusted EBITDA to GAAP earnings is included at the end of this presentation.

FY2024 Earnings Guidance FY2023 Adjusted Operating Results FY2024 Earnings Guidance (1) $5.17/share $5.40 to $5.90/share Key Guidance Drivers § 390-410 Bcfe (up 7% vs. FY23) Net Production (2) Realized natural gas prices (after-hedge)§ ~$2.63-2.68/Mcf (vs. $2.55/Mcf in FY23) Exploration & G&A Expense § $0.17-$0.19/Mcf (vs. $0.18/Mcf in FY23) Production DD&A Expense § $0.69-$0.74/Mcf (vs. $0.65/Mcf in FY23) LOE Expense § $0.69-$0.71/Mcf (vs. $0.68/Mcf in FY23) Gathering Revenues § $240-$260 million (up 9% vs. FY23) Gathering Gathering O&M Expense § ~$0.09/Mcf of throughput Pipeline & Storage Revenues § $380-$420 million (Supply Rate Increase) Pipeline & Pipeline & Storage O&M Expense § ~5% increase 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 § ~25-25.5% (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 $2.40 - $2.45/MMBtu for fiscal 2024, 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 Focus on Capital Efficiency (1) Net Production (Bcfe) Capital Expenditures ($ MM) $600 400 300 $400 390- $525 - $588 200 $566 372.5 352.5 410 $575 $200 100 0 $0 2022 2023 2024E 2022 2023 2024E Near-Term Strategy ü Continue to moderate activity level to target maintenance-to-low production growth beyond fiscal 2024 § Commenced transition to focus majority of the development program in the EDA to maximize long-term returns and capital efficiency ü EDA Tioga: development focused primarily on Utica (modest Marcellus activity) ü EDA Lycoming: activity maintains production level that fully utilizes valuable Atlantic Sunrise capacity ü WDA: limited development focused on Utica Shale, with return trips in Clermont-Rich Valley area 16 (1) A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation. FY23 reflects the netting of $150 million related to acquisition of upstream assets and acreage in 2H FY23.

E&P and Gathering EDA Transition Driving Improved Economics ü Transition to full EDA development, with increasing capital efficiency, enhanced productivity and higher returns, provides differentiated investment opportunity to high-grade development program ü >10 years of prolific EDA inventory at expected development pace EDA Transitions Rapidly Improving Breakevens 12 Month Expected Cumulative Production $4.00 600 100% $3.50 500 80% $3.00 400 $2.50 60% $2.00 300 $1.50 40% 200 $1.00 20% $0.50 100 $0.00 0 0% FY22 FY23 FY24 FY25 Actuals Projected % EDA TILs (2) (1) NFG Estimates Enverus 2022 Actuals (1) Source: Enverus Intelligence Research. Peers include Apex Energy, AR, Arsenal, Ascent Resources, CHK, CNX, CTRA, Encino Energy, EQT, GPOR, Greylock Energy, HG Energy, NNE, Olympus Energy, PennEnergy, REP, RRC, Snyder Brothers, SWN, Tug Hill. 17 (2) Based on internal NFG development schedule and projections. 12- Mo. Cumulative Gas, MMCF/1,000' % EDA TILs PV-10 Breakeven @ 20:1 WTI: HH ($/Mcf)

E&P and Gathering Eastern Development Area (EDA) Seneca EDA Highlights EDA – ~309,000 Acres 1 Tioga County, PA Undeveloped Utica ü ~200 Utica future development locations ü ~80 Marcellus future development locations ü Gathering infrastructure: NFG Tioga gathering systems ü Numerous marketing opportunities: Undeveloped Marcellus § 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 (Transco) 18

E&P and Gathering Integrated Development – EDA Gathering Current Systems In-Service Gathering Systems Map 1 Tioga Gathering Systems (1) ü Total Investment (to date): ~$420 million ü Capacity: up to 970,000 Dth per day ü Current Production Sources: Seneca Resources & Third Party ü Interconnects: Empire, Eastern, and TGP 300 ü Future Build-Out § Expected increased investment in gathering pipeline and compression required to support Seneca’s transition to primarily EDA development program 1 2 Trout Run Gathering System ü Total Investment (to date): ~$283 million ü Capacity: 466,000 to 585,000 Dth per day 2 ü Current Production Sources: Seneca Resources & Third-Party ü Interconnects: Transco (Leidy Line) ü Expected to generate third-party revenues of $10 – $15 million for fiscal 2024 (supported by minimum volume commitments) 19 (1) Includes Company’s acquisition of midstream gathering assets in July 2020, in the amount of ~$223 million.

E&P and Gathering Western Development Area (WDA) (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 Strong Beechwood area results provide 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. 20 (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 § Total Investment (to date): ~$394 million § Capacity: up to 750 MMcf per day § Current Production Source: Seneca Resources § Interconnects: TGP 300 and NFG Supply Future Build-Out § Minimal gathering pipeline and compression investment required to support Seneca’s near-term development program 21

E&P and Gathering Production Supported by Long-Term Contracts Natural Gas Marketing Firm Contract / Transport Volumes (gross MDth/day) 1200 (1) Firm Sales Contracts Will continue to layer-in firm sales deals to reduce in-basin spot exposure 1000 Leidy South (Transco & NFG - Supply) Transco Zone 6 Non-NY 330,000 Dth/d 800 *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 (EDA-Lycoming) 200 Niagara Expansion (TGP & NFG - Supply) Canada-Dawn & TGP 200 170,000 Dth/d (WDA) Northeast Supply Diversification (TGP) 50,000 Dth/d (Canada-Dawn) (EDA-Tioga) 0 Oct-23 Jan-24 Apr-24 Jul-24 Oct-24 22 (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. Gross Firm Volumes (MDth/d)

E&P and Gathering Near-term Firm Sales Provide Market & Price Certainty Net Contracted Firm Sales (Dth per day) (1) Contracted Index Price Differentials ($ per Dth) NYMEX Dawn Other Capped Fixed Price (2) (2) 37,300 38,600 ($0.26) $0.43 1,044,300 1,044,700 1,015,900 988,400 986,500 252,000 284,700 227,100 187,500 184,800 $2.37 $2.48 $2.44 $2.47 $2.46 (3) (3) (3) (3) (3) 66,800 66,800 60,200 65,000 (3) 66,000 (2) (2) (2) 75,200 ($0.91) 112,200 ($1.25) 112,300 ($1.25) 54,300 ($0.88) 22,400 86,200 ($0.86) 86,100 ($0.86) 22,200 ($0.98) ($0.88) 672,400 633,200 594,300 535,800 536,400 ($0.63) ($0.62) ($0.62) ($0.62) ($0.62) Q1 FY24 Q2 FY24 Q3 FY24 Q4 FY24 FY24 Avg Gross Firm Sales Volumes (Dth per day) 1,140,700 1,170,900 1,202,300 1,203,000 1,137,400 (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 are primarily TGP 200 and Transco Zone 6 Non-NY markets, with the balance to other Transco markets. 23 (3) Refer to NYMEX Capped Firm Sales Additional Detail on appendix slide 48.

E&P and Gathering Fiscal 2024 Net Production Profile 357 Bcf of Appalachian Production Protected by Firm Sales (1) § 211 Bcf locked-in realizing ~$2.69/Mcf , net of transportation (2) § 64 Bcf of no-cost collars with $3.43/Mcf floor (3) § 82 Bcf of additional firm sales 390-410 Bcfe 400 ~43 Bcfe 350 ~82 Bcfe Spot production 300 assumed to be sold at ~$2.40 – $2.45 250 ~64 Bcfe 200 150 ~211 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 ~52 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. 24 See NYMEX Capped Firm Sales Additional Detail on appendix slide 48. Net 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 $0.30ü Fees Paid to NFG’s Gathering ~$0.95 $0.93 $0.26 $0.21 Segment Comprise >98% of $0.11 $0.07 $0.20 $0.07 (1) Expected Gathering & $0.18 (2) $0.18 $0.18 $0.32 $0.28 Transport LOE $0.25 $0.24 (2) $0.12 $0.10 $0.11 (3) (2) (2) $0.58 $0.58 $0.57 $0.57 $0.57 $0.56 $0.56 FY 2019 FY 2020 FY 2021 FY 2022E FY 2022 FY 2023 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 2024. 25 (2) The total of the two LOE components represents the midpoint of the LOE guidance ranges for fiscal 2024. 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, Methane Detection & Biodiversity TM Equitable Origin – EO100 Standard for Responsible Methane Detection Energy Development Certifications ü For the past decade, standard pad design has included fixed gas detection systems installed near production equipment to shut-in the pad if methane 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 100% of natural gas ü 100% of gathering system production certified and re- assets certified in ü Piloting continuous emissions monitoring equipment verified in December 2022 September 2023 MiQ Biodiversity (100% of Appalachian Assets – Re-Certified August 2023) ü Surface Footprint Neutral Program focuses on restoring, enhancing, or Certification focuses on three emissions protecting biodiversity by returning management criteria: one acre of land to the environment ü Methane Intensity for every acre disturbed ü Company Practices to Manage Methane Emissionsü Voluntary initiatives focused on pollinator and tree plantings, ü Emissions Monitoring Technology Deployment Achieved “A” certification grade - streambank stabilization, and the highest certification level enhancing aquatic wildlife available 26

Pipeline & Storage Overview National Fuel Gas Supply Corporation Empire Pipeline, Inc. 27

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. 28 (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 Tioga Pathway Project – Organic Growth Project provides long-term revenue growth for Supply, while providing an additional outlet for Seneca’s EDA development ü Capacity: 190,000 Dth/day ü Estimated annual revenue: ~$15 million (underpinned by 15-year agreement with Seneca) ü Estimated capital cost: ~$90 million § A portion of the capital to be allocated to modernization facilities ü Facilities (all in Pennsylvania) include: § Approximately 20 miles of new pipeline § Approximately 4 miles of replacement/modernization of 20” pipeline ü Target In-Service Date: late calendar year 2026 ü Regulatory process: § FERC 7(c) Application (expected late summer 2024) 29

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 30

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 31

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 32 (1) Contracted as of 9/30/2022.

Utility Overview National Fuel Gas Distribution Corporation 33

Utility New York & Pennsylvania Service Territories New York (1) Total Customers : 540,000 Allowed 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) (2) o System Modernization / Improvement Trackers Pennsylvania (1) Total Customers : 214,000 Allowed 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 (3) August 1, 2024 (1) As of September 30, 2022. (2) Applied to new plant placed in service through September 30, 2024. 34 (3) Eligible to recover costs on incremental system investments after August 1, 2024, subject to attaining rate year plant balance of $781.3 million.

Utility New York Rate Case On October 31, 2023, National Fuel Gas Distribution Corporation filed a request with the New York Public Service Commission (NY PSC) to amend its tariff and increase its base rates. National Fuel’s base rates have not changed since the last base rate case was litigated in 2017. ✓ Base Rate Increase = $88.8 million ($72.6 million net margin revenues) ▪ 30.8% increase in base delivery revenues (24.9% net margin revenues) Proposed Base ▪ 13.0% increase in operating revenues Revenue Increase ✓ New rates expected to be effective October 1, 2024 ✓ Proposed Capital Structure and Returns: ▪ Capital Structure = 48% debt / 52% equity ▪ Return on Equity = 9.8% ✓ Increasing rate base and depreciation expense associated with higher plant in-service ▪ Total Rate Base in Rate Year = $1.1 billion Key Drivers ▪ Maintain pipeline replacement target at 110 miles per year ✓ O&M expense inflation (e.g., labor and benefits) ✓ Implement elements of Long-term Plan filed with NY PSC in July 2023 (e.g. Hybrid Heating, Demand Response, RNG and RSNG pilots) ✓ Seeking approval for uncollectible expense tracker 35

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. 36 (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) $160.0 Capital Expenditures for Safety Total Capital Expenditures $130-$150 $139.9 $140.0 $111.0 $120.0 $108.6 $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 $8 - $9 MM in Gross Margin in FY 2024 $20.0 $0.0 2018 2019 2020 2021 2022 2023 2024E Fiscal Year 37 (1) A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation. Utility Capital Expenditures ($ millions)

Utility Long-Standing Pipeline Replacement & Modernization (1) Utility Mains by Material Miles of Utility Main Pipeline Replaced Wrought Iron 161 158 156 154 154 Coated Bare 49 NY 45 43 40 41 9,798 miles Plastic 114 113 113 113 Wrought Iron 112 Bare Coated PA 4,845 miles Plastic 2019 2020 2021 2022 2023 Calendar Year 38 (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. 39 (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 Animal Manure 6 9 12 20 NFG to leverage technology acceleration within its regional footprint Food Waste 2 3 4 6 ü Final Scoping Plan adopted by New York Climate Action Council includes consideration of alternative fuels and technologies in future gas system Wastewater 2 2 3 7 planning Other 23 56 102 188 All Sources 47 90 147 272 40 (1) NYSERDA– Potential of Renewable Natural Gas in New York State (April 2022).

Consolidated Financial Overview Upstream I Midstream I Downstream 41

Diversified, Balanced Earnings and Cash Flows (1) (2) Adjusted Operating Results ($ per share) Adjusted EBITDA ($ millions) $1,400 $7.00 $1,226 $1,165 $5.88 $1,200 $6.00 $5.40 - $5.90 $5.17 $1,000 $5.00 $656 $612 E&P $3.21 $800 $4.00 $2.52 $600 $3.00 $177 Gathering $186 $1.01 $1.08 $2.00 $400 Pipeline & $241 $237 $1.11 $1.09 Storage $1.00 $200 Utility $163 $0.59 $0.52 $145 $0.00 $0 FY 2022 FY 2023 FY 2024 FY 2022 FY 2023 Guidance (1) Excludes items impacting comparability. See Comparable GAAP Financial Measure Slides & Reconciliations at the end of this presentation. 42 (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 $974 $1,000 $865-$975 $829 $781 $770 $800 $719 $588 $525-$575 $600 $381 $566 $492 $384 $400 $35 $103 $90-$110 $74 $50 $56 $252 $142 $120-$140 $200 $167 $143 $96 $140 $130-$150 $111 $101 $96 $94 $0 2019 2020 2021 2022 2023 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 $150 million related to the acquisition of Appalachian upstream assets in 2H 2023. 43 (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 3.08 x 2.72 x 2.61 x 2.47 x Total 2.27 x 2.22 x Equity Debt 53% 47% 2018 2019 2020 2021 2022 2023 $5.6 Billion Total Capitalization Fiscal Year (2) as of September 30, 2023 Debt Maturity Profile by Fiscal Year ($MM) Liquidity $ 1,000 MM Committed Credit Facilities $600 $600 (288 MM) $500 $500 $500 Short-term Debt Outstanding 712 MM Available Short-term Credit Facilities $400 $300 55 MM Cash Balance at 9/30/23 $200 $ 767 MM Total Liquidity at 9/30/23 $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. 44 (2) Total capitalization as presented here includes $288 MM of notes payable to banks and commercial paper, in addition to $5.4 B of Total Capitalization as presented on the balance sheet as of September 30, 2023.

Appendix 45

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. 46

Appendix Hedge Positions and Prices Natural Gas Volumes in thousand MMBtu; Prices in $/MMBtu Fiscal 2024 Q1 Q2 Q3 Q4 Avg. Avg. Avg. Avg. Volume Price Volume Price Volume Price Volume Price NYMEX Swaps 30,620 $3.16 34,770 $3.39 34,770 $3.39 34,770 $3.39 No Cost Collars 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 22,936 $2.37 26,198 $2.48 17,063 $2.47 17,001 $2.46 Total 72,936 78,068 66,233 66,171 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 88,810 $3.53 38,020 $3.98 13,500 $4.25 No Cost Collars 43,960 $3.49 / $4.65 42,720 $3.53 / $4.76 3,560 $3.53/ $4.76 Fixed Price Physical 75,047 $2.49 66,821 $2.39 46,129 $2.39 Total 207,817 147,561 63,189 47 (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 Q1 FY24 Q2 FY24 Q3 FY24 Q4 FY24 FY24 Avg $2.92 28,900 29,100 29,500 29,500 29,300 $4.95 17,300 16,600 16,800 16,800 16,900 $7.00 14,000 20,300 20,500 20,500 18,800 Total 60,200 66,000 66,800 66,800 65,000 (1) Capped Firm Sales - Weighted Average Index Price Differentials ($/Dth) Q1 FY24 Q2 FY24 Q3 FY24 Q4 FY24 FY24 Avg NYMEX Price (60,200) (66,000) (66,800) (66,800) (65,000) $2.00 ($0.52) ($0.51) ($0.51) ($0.51) ($0.51) $2.50 ($0.52) ($0.51) ($0.51) ($0.51) ($0.51) $3.00 ($0.56) ($0.55) ($0.55) ($0.55) ($0.55) $3.50 ($0.80) ($0.77) ($0.77) ($0.77) ($0.78) $4.00 ($1.04) ($0.99) ($0.99) ($0.99) ($1.00) $4.50 ($1.28) ($1.18) ($1.18) ($1.18) ($1.20) $5.00 ($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 48 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 49 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 Net Cash Used in Investing Activities, adjusted for acquisitions and divestitures. 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. 50

Appendix Non-GAAP Reconciliations – Adjusted EBITDA Reconciliation of Adjusted EBITDA to Consolidated Net Income ($ Thousands) FY 2018 FY 2019 FY 2020 FY 2021 FY 2022 FY 2023 Total Adjusted EBITDA Exploration & Production Adjusted EBITDA $ 317,707 $ 351,159 $ 312,166 464,529 656,310 611,782 Pipeline & Storage Adjusted EBITDA 183,972 162,181 189,520 218,921 240,904 237,327 Gathering Adjusted EBITDA 91,937 108,292 119,879 159,005 176,572 185,882 Utility Adjusted EBITDA 175,554 176,134 171,418 171,379 162,871 145,002 Corporate & All Other Adjusted EBITDA (7,704) (12,393) (7,529) (13,521) (10,762) (15,273) Total Adjusted EBITDA $ 761,466 $ 785,373 $ 785,454 $ 1,000,313 $ 1,225,895 $ 1,164,720 Consolidated Net Income $ 391,521 $ 304,290 $ (123,772) $ 363,647 $ 566,021 $ 476,866 Plus: Interest Expense 114,522 106,756 117,077 146,357 130,357 131,886 Minus: Other Income (Deductions) 21,174 15,542 17,814 15,238 1,509 (18,138) Plus: Income Tax Expense (7,494) 85,221 18,739 114,682 116,629 164,533 Plus: Depreciation, Depletion & Amortization 240,961 275,660 306,158 335,303 369,790 409,573 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 $ 1,164,720 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 60,000 287,500 Less: Cash and Temporary Cash Investments (End of Period) (229,606) (20,428) (20,541) (31,528) (46,048) (55,447) Total Net Debt (End of Period) $ 1,919,394 $ 2,183,772 $ 2,658,459 $ 2,775,972 $ 2,662,952 $ 2,632,053 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 60,000 Less: Cash and Temporary Cash Investments (Start of Period) (555,530) (229,606) (20,428) (20,541) (31,528) (46,048) Total Net Debt (Start of Period) $ 1,843,470 $ 1,919,394 $ 2,183,772 $ 2,658,459 $ 2,775,972 $ 2,662,952 Average Total Net Debt $ 1,881,432 $ 2,051,583 $ 2,421,116 $ 2,717,216 $ 2,719,462 $ 2,647,503 Average Total Net Debt to Total Adjusted EBITDA 2.47 x 2.61 x 3.08 x 2.72 x 2.22 x 2.27 x 51

Appendix Non-GAAP Reconciliations – Adjusted EBITDA, by Segment Reconciliation of Adjusted EBITDA to Net Income, by Segment ($ Thousands) FY 2018 FY 2019 FY 2020 FY 2021 FY 2022 FY 2023 Exploration and Production Segment Reported GAAP Earnings $ 180,632 $ 111,807 $ (326,904) $ 101,916 $ 306,064 $ 232,275 Depreciation, Depletion and Amortization 124,274 154,784 172,124 182,492 208,148 241,142 Other (Income) Deductions (307) (1,091) 882 937 3,210 (3,748) Interest Expense 54,288 54,777 58,098 69,662 53,401 54,317 Income Taxes (41,962) 32,978 (41,472) 33,370 43,898 87,796 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) - Loss from discontinuance of crude oil cash flow hedges - - - - 44,632 - Transaction and severance costs related to West Coast asset sale - - - - 9,693 - Adjusted EBITDA $ 317,707 $ 351,159 $ 312,166 $ 464,529 $ 656,310 $ 611,782 Pipeline and Storage Segment Reported GAAP Earnings $ 97,246 $ 74,011 $ 78,860 $ 92,542 $ 102,557 $ 100,501 Depreciation, Depletion and Amortization 43,463 44,947 53,951 62,431 67,701 70,827 Other (Income) Deductions (5,926) (9,157) (4,635) (5,840) (6,889) (11,989) Interest Expense 31,383 29,142 32,731 40,976 42,492 43,499 Income Taxes 17,806 23,238 28,613 28,812 35,043 34,489 Adjusted EBITDA $ 183,972 $ 162,181 $ 189,520 $ 218,921 $ 240,904 $ 237,327 Gathering Segment Reported GAAP Earnings $ 83,519 $ 58,413 $ 68,631 $ 80,274 $ 101,111 $ 99,724 Depreciation, Depletion and Amortization 17,313 20,038 22,440 32,350 33,998 35,725 Other (Income) Deductions (778) (460) (260) 12 26 (684) Interest Expense 9,560 9,406 10,877 17,493 16,488 14,989 Income Taxes (17,677) 20,895 18,191 28,876 24,949 36,128 Adjusted EBITDA $ 91,937 $ 108,292 $ 119,879 $ 159,005 $ 176,572 $ 185,882 Utility Segment Reported GAAP Earnings $ 51,217 $ 60,871 $ 57,366 $ 54,335 $ 68,948 $ 48,395 Depreciation, Depletion and Amortization 53,253 53,832 55,248 57,457 59,760 61,450 Other (Income) Deductions 29,073 24,021 23,380 23,785 (7,117) (6,343) Interest Expense 26,753 23,443 22,150 21,795 24,115 34,233 Income Taxes 15,258 13,967 13,274 14,007 17,165 7,267 Adjusted EBITDA $ 175,554 $ 176,134 $ 171,418 $ 171,379 $ 162,871 $ 145,002 Corporate and All Other Reported GAAP Earnings $ (21,093) $ (812) $ (1,725) $ 34,580 $ (12,659) $ (4,029) Depreciation, Depletion and Amortization 2,658 2,059 2,395 573 183 429 Gain on Sale of Timber Properties - - - (51,066) - - Other (Income) Deductions (888) 2,229 (1,553) (3,656) 12,279 4,626 Interest Expense (7,462) (10,012) (6,779) (3,569) (6,139) (15,152) Income Taxes 19,081 (5,857) 133 9,617 (4,426) (1,147) Adjusted EBITDA $ (7,704) $ (12,393) $ (7,529) $ (13,521) $ (10,762) $ (15,273) 52

Appendix Non-GAAP Reconciliations – Adjusted Operating Results 53

Appendix Non-GAAP Reconciliations – Free Cash Flow Reconciliation of Free Cash Flow ($ Thousands) Twelve Twelve Months Ended Months Ended September 30, September 30, 2023 2022 Net Cash Provided by Operating Activities $ 1,237,075 $ 812,521 Less: Net Cash Used in Investing Activities $ 1,112,347 $ 518,704 Proceeds from Divestitures $ - $ 254,439 $ 124,728 $ 39,378 Plus: Acquisitions $ 124,758 $ - (1) Upstream Acquisitions Included in Capital Expenditures $ 25,057 $ - (2) Free Cash Flow $ 274,543 $ 39,378 (1) $25.0 million related to the acquisition of assets from EXCO and UGI included in Capital Expenditures on Consolidated Statement of Cash Flows. (2) Management defines free cash flow as net cash provided by operating activities, less net cash used in investing activities, adjusted for acquisitions and divestitures. 54

Appendix Reconciliation – Capital Expenditures Reconciliation of Segment Capital Expenditures to Consolidated Capital Expenditures ($ Thousands) FY 2024 FY 2019 FY 2020 FY 2021 FY 2022 FY 2023 Guidance Capital Expenditures Exploration & Production Capital Expenditures $ 491,889 $ 670,455 $ 381,408 $ 565,791 $ 737,725 $525,000 - $575,000 Pipeline & Storage Capital Expenditures $ 143,003 $ 166,652 $ 252,316 $ 95,806 $ 141,877 $120,000 - $140,000 Gathering Segment Capital Expenditures $ 49,650 $ 297,806 $ 34,669 $ 55,546 $ 103,295 $90,000 - $110,000 Utility Capital Expenditures $ 95,847 $ 94,273 $ 100,845 $ 111,033 $ 139,922 $130,000 - $150,000 Corporate & All Other Capital Expenditures $ 855 $ 561 $ 450 $ 1,212 $ 754 Eliminations $ (1,130) $ 223 Total Capital Expenditures from Continuing Operations $ 781,246 $ 1,228,617 $ 769,911 $ 829,388 $ 1,123,573 $865,000 - $975,000 Plus (Minus) Acquisition of Upstream Assets and Midstream Gathering Assets $ (506,2 58) $ (124,758) Plus (Minus) Accrued Capital Expenditures $ (43,198) Exploration & Production FY 2022 Accrued Capital Expenditures $ (82,943) $ 82,943 Exploration & Production FY 2021 Accrued Capital Expenditures $ (47,887) $ 47,887 (1) Exploration & Production FY 2020 Accrued Capital Expenditures $ (45,78 8) $ 42,983 Exploration & Production FY 2019 Accrued Capital Expenditures $ (38,063) $ 38,063 Exploration & Production FY 2018 Accrued Capital Expenditures $ (36,465) $ (31,813) Pipeline & Storage FY 2022 Accrued Capital Expenditures $ (15,18 8) $ 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 $ (25,077) $ (20,587) Gathering FY 2022 Accrued Capital Expenditures $ (10,72 4) $ 10,724 Gathering FY 2021 Accrued Capital Expenditures $ (4,743) $ 4,743 Gathering FY 2020 Accrued Capital Expenditures $ (13,52 4) $ 13,524 Gathering FY 2019 Accrued Capital Expenditures $ (6,595) $ 6,595 Gathering FY 2018 Accrued Capital Expenditures $ (3,925) $ (13,610) Utility FY 2022 Accrued Capital Expenditures $ (11,407) $ 11,407 Utility FY 2021 Accrued Capital Expenditures $ (10,634) $ 10,634 Utility FY 2020 Accrued Capital Expenditures $ (10,75 1) $ 10,751 Utility FY 2019 Accrued Capital Expenditures $ (12,692) $ 12,692 Utility FY 2018 Accrued Capital Expenditures $ (6,748) Total Accrued Capital Expenditures $ (153,337) $ (6,206 ) $ (18,177) $ (17,56 2) $ 11,053 Total Capital Expenditures per Statement of Cash Flows $ 627,909 $ 716,153 $ 751,734 $ 811,826 $ 1,009,868 $865,000 - $975,000 (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 55 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, 2023 September 30, 2022 (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 $210,880 $0 $210,880 $0.57 $0.00 $0.57 $199,405 $0 $199,405 $0.58 $0.00 $0.57 Other Lease Operating Expense $42,676 $0 $42,676 $0.11 $0.00 $0.11 $32,604 $51,905 $84,509 $0.10 $28.99 $0.24 Lease Operating and Transportation Expense $253,555 $0 $253,555 $0.68 $0.00 $0.68 $232,009 $51,905 $283,914 $0.68 $28.99 $0.81 General & Administrative Expense $66,074 $0.18 $79,061 $0.22 All Other Operating and Maintenance Expense $9,327 $0.03 $20,140 $0.06 Property, Franchise and Other Taxes $17,717 $0.05 $25,364 $0.07 Total Taxes & Other $27,044 $0.07 $45,504 $0.13 Depreciation, Depletion & Amortization $241,142 $0.65 $208,148 $0.59 Production: Gas Production (MMcf) 372,271 372,271 341,699 1,211 342,911 Oil Production (MBbl) 30 30 16 1,588 1,604 Total Production (Mmcfe) 372,451 - 372,451 341,796 10,741 352,536 Total Production (Mboe) 62,075 - 62,075 56,966 1,790 58,756 (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. 56