Exhibit 99 Investor Presentation nd Fiscal 2024 - 2 Quarter Update May 1, 2024 May 2024 Update 1

National Fuel Gas Company • Company Overview (3) • Why National Fuel? (7) • Business Updates (12) • Supplemental Information • Segment Information (19) • Rate Case Overview (43) • Guidance & Other Financial Information (45) May 2024 Update 2

History of National Fuel Industry Pioneer Born From Rockefeller’s Standard Oil Company May 2024 Update 3

NFG Today: A Diversified, Integrated Natural Gas Company (1) Adjusted EBITDA Developing our large, high-quality acreage position in Marcellus & Utica shales Upstream Exploration & ~1.2 Million ~1.1 Bcf/day 51% Production (2) Net acres in Net total production Appalachia Expanding and modernizing pipeline infrastructure to provide outlets for Appalachian natural gas production Midstream Gathering 37% 4.5 MMDth $2.7 Billion Pipeline & Storage Daily interstate Investments since 2010 pipeline capacity under contract Providing safe, reliable and affordable service to customers in WNY and NW PA Downstream 12% ~$900 Million 754,000 Utility Investments in safety Utility 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 March 31, 2024. 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. (2) Average net production for the three months ended March 31, 2024. May 2024 Update 4

Non-Regulated Business Overview Exploration & Production Segment (Upstream) • Seneca Resources Company • Total Net Acres (Pennsylvania): ~1.2 million Western Development Area – 915,000 Acres • Total Proved Reserves: 4.5 Tcfe (as of 9/30/2023) • Current Net Production: ~1.1 Bcf/d • Firm Transportation Capacity: ~1 Bcf/d to premium markets • Decades of Marcellus and Utica development inventory Eastern Development Area – 309,000 Acres Gathering Segment (Midstream) • National Fuel Gas Midstream Company • Total Throughput: 1.4 Bcf/d (including third party) • Greater than 2 Bcf/d of gathering capacity • ~400 miles of gathering pipeline • 24 compressor stations • Interconnections with 7 major pipelines May 2024 Update 5

Regulated Business Overview Pipeline & Storage Segment (Midstream) • Regulated by Federal Energy Regulatory Commission (FERC) (2) • Total Rate Base: $1.6 Billion • ~2,600 miles of pipeline/ 29 storage fields • National Fuel Gas Supply Corporation: • Firm Contracted Storage Capacity: 71 Bcf (1) • Firm Contracted Transportation Capacity: 3.4 Bcf/day • Empire Pipeline, Inc.: (1) • Firm Contracted Transportation Capacity: ~1.0 Bcf/ day • Interconnections with 8 major interstate pipelines Utility Segment (Downstream) • New York Jurisdiction • 540,000 customers • Regulated by the New York Public Service Commission (NYPSC) • Pennsylvania Jurisdiction • 214,000 customers • Regulated by the Pennsylvania Public Utilities Commission (PaPUC) (2) • Total Rate Base: $1.2 Billion • Fiscal 2023 Total Throughput: ~134 Bcf • Provides more than 90% of the space heating load in operating footprint (1) Contracted capacity disclosed annually as of September 30, 2023. May 2024 Update 6 (2) Represents the latest available information in regulatory filings. Supply and Empire rate base amounts are as of 12/31/2023. NY is as of 8/31/2023 and PA is as of 12/31/2023.

Why National Fuel? Responsibly Reducing Strong Integrated Visibility on Long-Term Long-Standing History Responsibly Reduce Emissions Returns EPS & FCF Growth of Shareholder Returns Emissions ü Optimized capital ü Targeting significant ü Continued progress ü Over 120 years of allocation rate base growth from toward emissions dividend payments system modernization reduction targets ü Lower cost of capital ü 53 years of dividend and expansion ü Enhanced GHG increases ü Operational synergies ü High-graded upstream disclosures on ü New share repurchase ü Improved profitability development increases sustainability initiatives program capital efficiencies May May 2024 U 2024 Updat pdate e 77

Integrated Model Enhances Returns NFG’s ROCE outperforms peers and broader market, on average, over a multi-year period (1) Return on Capital Employed Strong Integrated Business Model Benefits… Integrated NFG vs. S&P 500 and Industry Peers S&P O&G 20% Returns Index üOperations: Lower cost structure üFinancial: Lower cost of capital Visibility on NFG Long-Term 10% üStrategic: Optimized capital allocation EPS & FCF S&P 500 Growth üCommercial: Greater revenue/ margin UTY 0% Long History of Shareholder …Drive Strong Performance Since 2017 Returns Decrease driven by -10%üNFG vs. S&P 500: +2% non-cash impairments Responsibly üNFG vs. E&P Peers: +8% Reducing Emissions üNFG vs. Utility Peers: + 6% -20% FY17 FY18 FY19 FY20 FY21 FY22 FY23 th (1) Source: Bloomberg for the TTM ending September 30 . May 2024 Update 8

Robust Earnings & Free Cash Flow Growth Outlook Non-Regulated Business Significant Growth in Future FCF Growth Drivers § Increasing well productivity from prolific EDA Strong Integrated § Moderate production growth combined with lower capital Returns § Targeting production growth of 0% to 5% per year § Strong natural gas price outlook Visibility on Long-Term ~$150 EPS & FCF Regulated Business ~$130 ~$120 Growth Growth Drivers § Robust near-term outlook driven by rate making activity Long History § Long-term rate base growth driven by pipeline of Shareholder modernization and potential expansion opportunities Returns Predictable Cash Flow Generation $2.00 $2.40 $2.75 $3.25 Responsibly with Commodity Upside Reducing FY2024 FY2025 Emissions § Hedging protects near-term earnings and cash flows NYMEX Price ($/MMBtu – Remainder of FY) § Significant opportunity to capture higher natural gas prices § Predictable cash flows from the regulated businesses (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 at the end of this presentation. Assumes current hedges. Assumes no pricing-related curtailments. May 2024 Update 9 (1) Projected Free Cash Flow ($ Millions)

Long-Standing History of Returning Capital to Shareholders $1.5 Billion Returned to Shareholders Over Last 10 Years Dividend Share Total Return of (2) (1) Strong Yield Buyback Yield Capital Integrated Returns ~4% ~2% ~6% Visibility on Stable, Growing Dividend … …Plus New Share Buyback $1.98 Long-Term per share EPS & FCF Growth 53 Years Consecutive Dividend Increases § $200M Share Repurchase Long History Program approved in March 2024 121 Years of Shareholder Consecutive Payments Returns § Target completion date by end of (3) fiscal 2025 Responsibly $0.19 Reducing per share Emissions 1970 1980 1990 2000 2010 2020 th (1) As of April 30 , 2024. (2) FY24 buyback yield assumes $74 MM of stock is purchased beginning in March. (3) Completion subject to a number of factors, including but not limited to stock price, market conditions, applicable securities laws, including SEC Rule 10b-18, corporate and regulatory requirements, and capital and liquidity needs. May 2024 Update 10

Continued Progress Toward Methane Intensity Targets Latest Corporate Responsibility Report Provides Enhanced GHG Disclosures on Sustainability Initiatives Target: 40% Target: 30% Strong E&P Gathering Integrated National Fuel Gas Company Targets Returns Progress Since 2020: Progress Since 2020: § 25% reduction in GHG emissions by 2030 § Progress since 2020: 1% increase in total 27% 14% Visibility on (2) GHG emissions Long-Term EPS & FCF 2030 Growth Ongoing Sustainability Initiatives Methane Intensity (1) § Responsible gas certifications Reduction Targets Long History § Pneumatic device replacement of Shareholder Returns § Equipment upgrades at existing facilities Utility P&S § Use of best-in-class emissions controls for Progress Since 2020: Progress Since 2020: new facilities Responsibly Reducing 8% Emissions 18% Target: 30% Target: 50% (1) All emissions reduction targets based on 2020 baseline. Measured using calendar 2022 emissions data, as reported in Company’s 2022 Corporate Responsibility Report. May 2024 Update 11 (2) Total GHG emissions largely flat vs. 2020 despite significant production and throughput growth. Total methane emissions decreased by ~7%.

Business Updates 12 May May 2024 U 2024 Updat pdate e 12

Regulatory Update: Significant Rate Case Activity New York: Significant ü Filed a rate case in October 2023 for new rates effective October 1, 2024 (FY 2025) Growth ‒ Settlement negotiations began mid-April ü NFG requested revenue increase of $88.8 million ($72.6 million net margin impact) ü Major areas of focus: Rate Case ‒ Capital structure: NFG proposed 52% Equity / 48% Debt Pending ‒ ROE: NFG proposed 9.8% ‒ Rate base: NFG proposed $1.03 billion (~$320 million increase from last rate case) Pennsylvania: ü Joint Settlement reached on first rate case in PA since 2007 ‒ Achieved $23 million revenue requirement (~80% of filed position) $23M ‒ New weather normalization adjustment mechanism increase in ü New rates became effective August 1, 2023 Revenue ü Eligible for Distribution System Improvement Charge (DSIC) when net plant targets are hit after (1) July 31, 2024 Supply: ü Settlement filed with FERC on 3/27/24; Awaiting Commission approval § New rates went into effect 2/1/24 on an interim basis $56M ü $56 million expected increase in revenue on annualized basis increase in ü Maintains existing depreciation rates Revenue ü No comeback or moratorium period § Ability to file a rate case at any time May 2024 Update 13 (1) DSIC tracker allows recovery on incremental system investments after July 31, 2024, subject to attaining rate year plant balance of $781.3 million and earning below a statewide ROE target (currently 10.15%). P&S – Supply Utility – PA Utility – NY

Regulated Businesses Further Propel Long-Term Growth ~5-7% Avg. Increasing Rate Base Drives Annual Rate Long-Term EPS Growth Base Growth Factors Driving Long-Term Growth ($ in billions) Beyond FY23 3000 $2,796 $2,583 § Infrastructure modernization program $2,433 2500 $2,289 $2,127 § Ongoing expansion opportunities 2000 § Emissions reductions initiatives 1500 § Timely rate recovery and supportive 1000 ratemaking constructs minimize regulatory lag 500 0 2019 2020 2021 2022 2023 P&S Utility May 2024 Update 14

EDA Transition Creates Differentiated Upstream Value Western Development Areas (WDA) Eastern Development Areas (EDA) Legacy Development Area Development Focus Area Primarily Owned in Fee (No Royalty) 10+ Years Low-Risk Inventory EDA Transition ü High-grading development plan with higher capital efficiencies and cash flow generation ü EDA wells deliver >2x the well productivity (1) versus legacy WDA program § 24 EDA wells turned in line (TIL) since transition began (May 2023) ü Access to multiple, premium out-of-basin markets through owned firm transportation (1) Well productivity is measured within the first five years well comes online. May 2024 Update 15

EDA: Best in Basin Performance & Breakevens >10 years of prolific EDA inventory at expected development pace Best-in-Class Well Performance Already Low Breakevens Continue to Improve Seneca EDA 2022/2023 NE/ SW Appalachia Peer $3.50 1,500 1,000 $3.00 500 $2.50 0 0 12 24 Months 36 48 60 Program Productivity Increasing Significantly $2.00 600 400 $1.50 200 0 $1.00 FY22 FY23 FY24 FY25 FY26 % of EDA TILs: ~30% ~50% ~60% ~80% ~100% Seneca + Gathering Estimates Enverus 2022 Actuals Seneca Estimates Enverus 2022 Actuals (1) FY22 is based on actual data. FY23 to FY26 data is projected until 12 months after the last pad has been online. (2) Source: FY22 data is based on Enverus Intelligence Research for NFG and peers. Peers include Apex Energy, AR, Arsenal, Ascent Resources, CHK, CNX, CTRA, Encino Energy, EQT, May 2024 Update 16 GPOR, Greylock Energy, HG Energy, NNE, Olympus Energy, PennEnergy, REP, RRC, Snyder Brothers, SWN, Tug Hill. FY23 to FY25 NFG data is based on estimates. MMCF/1,000' 12 M. Cumulative Gas, (1) MCF/1,000 PV-10 Breakeven @ 20:1 WTI: HH ($/Mcf)

Capital Allocation Priorities Drive Spending Levels (1) Capital Expenditures by Segment ($ millions) Capital Allocation Priorities (2) (2) Exploration & Production Gathering Pipeline & Storage Utility • Invest in regulated growth via modernization $973 Organic and pipeline expansions $885 - $980 Investments • Maintain 0-5% growth in upstream/gathering $829 $770 Responsibly $719 • Maintain investment grade credit rating Manage the $525 - $555 $588 Balance • Target optimal rate making capital structure Sheet $381 $566 $384 Return of • Uphold 53-year history of dividend increases Capital to $35 • Value-accretive share repurchases $120 - $140 $103 Shareholders $74 $56 $90 - $110 $252 $142 • Upstream/Gathering: Integrated $167 Highly $96 opportunities geographically proximate to Strategic existing operations $150 - $175 $140 $111 $102 $94 M&A • Regulated: Growth to balance business mix FY 2020 FY 2021 FY 2022 FY 2023 FY 2024E (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 $283 million in E&P segment and $223 million in the Gathering segment related to the acquisition of Appalachian upstream assets in July 2020. FY23 reflects the netting of $150 million in the E&P segment related to the acquisition of Appalachian upstream assets. May 2024 Update 17

Maintaining Strong Balance Sheet & Liquidity (1) Net Debt / Adjusted EBITDA Capitalization Current Credit Ratings Quickly de-levered after 2020 Shell acquisition. Debt 3.08 x Total 2.72 x S&P BBB- Equity Debt 2.27 x 2.22 x 2.14 x Moody’s Baa3 55% 45% Fitch BBB Investment Grade $6.0 Billion Total Capitalization Credit Rating 2020 2021 2022 2023 TTM 3/31/24 (2) as of March 31, 2024 Fiscal Year Debt Maturity Profile by Fiscal Year ($MM) Liquidity as of March 31, 2024 (3) $600 $ 1,300 MM Committed Credit Facilities $500 $500 $500 (279 MM) Short-term Debt Outstanding $300 1,021 MM Available Short-term Credit Facilities 51 MM Cash Balance $ 1,072 MM Total Liquidity (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. (2) Total capitalization as presented includes $279 MM of notes payable to banks and commercial paper, in addition to $5.7B of Total Capitalization as presented on the balance sheet as of March 31, 2024. May 2024 Update 18 (3) Committed credit facilities includes $300 MM which was added in February from a Term Loan due in February 2026.

Supplemental Information: Segment Overview Exploration & Production & Gathering Overview Seneca Resources Company, LLC National Fuel Gas Midstream Company, LLC 19

E&P and Gathering Focused on Capital Efficiency and FCF Generation (1) Net Production (Bcfe) Capital Expenditures ($ MM) $588 390- $566 $525- 405 372.5 $555 352.5 2022 2023 2024E 2022 2023 2024E Near-Term Strategy ü Continue to moderate activity level to target maintenance-to-low production growth beyond fiscal 2025 § 0-5% growth expected beyond FY2025 § Focus majority of the development program in the EDA to maximize returns and capital efficiency ü EDA Tioga: most active development area focused on Utica and Marcellus ü EDA Lycoming: modest development focused on Marcellus ü WDA: limited development focused on Utica (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 May 2024 Update 20 assets and acreage.

E&P and Gathering Integration Drives Industry Leading Cost Structure Seneca Cash OpEx ($/Mcfe) Seneca + Gathering Cash OpEx ($/Mcfe) Operating results excluding California operations $0.97 ~$0.95 $0.93 $0.11 $0.07 $0.07 (1) $0.18 $0.18 $0.18 (2) $0.12 $0.10 $0.11 (2) $0.58 $0.58 $0.57 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. (2) The total of the two LOE components represents the midpoint of the LOE guidance ranges for fiscal 2024. May 2024 Update 21

E&P and Gathering Long Runway of Development Opportunities in the EDA 1 Tioga County, PA EDA Exploration & Production: Utica Development ü Low-risk development locations: ~200 Utica, 80 Marcellus ü Gathering infrastructure: NFG Midstream 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 (Tioga Pathway 2026) Marcellus Development Gathering: ü Seneca and third-party production sources, system capacity up to 970,000 Dth per day 1 2 Lycoming County, PA Exploration & Production: ü Low-risk development locations: ~20 Marcellus 2 ü Gathering infrastructure: NFG Midstream Trout Run ü Firm transportation capacity: Atlantic Sunrise (Transco) Gathering: ü Seneca and third-party production sources, system capacity up to 585,000 Dth per day ü Expected to generate third-party revenues of $10 – $15 million for fiscal 2024 May 2024 Update 22

E&P and Gathering High Quality Acreage in WDA, Primarily Owned in Fee (1) Western Development Area (WDA) Highlights Marcellus & Utica Trend Fairways ü Potential for 600+ Marcellus Shale and 500+ Utica Shale well locations ü Large gathering system with multiple interconnects provides access to firm transportation portfolio that reaches premium markets ü Highly contiguous fee acreage (no royalty) enhances economics and provides development flexibility ü Beechwood area results provide long-term development optionality Gathering System Map WDA Gathering ü Total investment to date ~$400 MM ü Seneca production source, system capacity up to 750K Dth/d ü Minimal gathering pipelines and compression investment required to Utica Trend support Seneca’s near-term Marcellus Trend development program (1) The Utica Shale lies approximately 5,000 feet beneath Seneca’s WDA Marcellus acreage May 2024 Update 23

E&P and Gathering Production Supported by Long-Term Contracts ~1 Bcf/d of Firm Transportation Firm Sales Portfolio 1200 (1) Incremental Firm Sales Contracts 1000 Will continue to layer-in firm sales deals to reduce in-basin spot exposure To Canada, Dawn, Leidy South (Transco & NFG - Supply) TPG-200 Transco Zone 6 Non-NY (45% of total) 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 (EDA Tioga) To NY, NJ, 400 Northeast Atlantic Sunrise (Transco) (35% of total) 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) To Mid-Atlantic, SE US (20% of total) NE Supply Diversification (TGP) 50,000 Dth/d (Canada-Dawn) (EDA-Tioga) 0 Fiscal 2024 (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. May 2024 Update 24 Gross Firm Volumes (MDth/d)

E&P and Gathering Fiscal 2024 Sales Mix Provides Near-Term Price Certainty Firm Sales & Production Cadence Price Realizations with Hedging (Net Bcfe, $ per Mmbtu) ~390 - 405 103 Bcfe 101 Bcfe $1.60 ($0.82) ($0.71) ($0.91) Differential to Floor: $2.56 NYMEX Cap: $3.13 ($0.66) ($0.66) $2.57 $2.28 $2.43 (1) (1) Q1 Q2 3Q24E 4Q24E (2) (3) Realized Fixed NYMEX-Linked Index Spot (1) Q3 Volumes: Fixed Price 22 bcf, NYMEX-Linked 67 bcf, Index 4 bcf. Q4 Volumes: Fixed Price 18 bcf, NYMEX-Linked 67 bcf, Index 5 bcf. NYMEX-Linked and Index prices are shown as differentials to NYMEX and $ per Mmbtu. (2) Price certainty defined as volumes where the price is locked in through either a fixed price firm sale or a NYMEX-linked firm sale paired with a NYMEX swap. (3) Floor protection defined as volumes where a floor price is locked in through a NYMEX-linked firm sale paired with a NYMEX collar. May 2024 Update 25

E&P and Gathering Hedging Program: Disciplined with Upside Potential Significant Opportunity to Capture Increasing Natural Gas Prices 450 400 ü Methodical approach of layering in 350 ~26% hedges over time 40- 300 45% 60- ü Protect near-term earnings and cash 65% 250 80- flows while maintaining upside 85% 90- 200 95% ü Maintain the strength of our investment 150 ~74% grade credit profile 100 50 0 FY24E FY25E FY26E FY27E FY28E Hedged volumes Estimated Unhedged Production Volumes (1) Assumes ~400 Bcf of production per year. May 2024 Update 26 (1) % Hedged/ % Unhedged

E&P and Gathering Industry-Leading Focus on Sustainability Responsible Gas Certifications, Methane Detection & Biodiversity TM Equitable Origin – EO100 Standard for Responsible Methane Detection Energy Development Certifications ü Standard pad design includes fixed gas detection systems installed near production equipment ü Seneca is participating in AMI’s 2024 ü Regular Audio-Visual-Olfactory Monitoring Plan inspections of all assets ü AMI is a proactive, basin-wide initiative ü Quarterly Leak Detection and ü 100% of natural gas production certified and designed to enhance methane ü 100% of gathering system Repair (LDAR) surveys of all assets monitoring & emission reductions re-verified in December 2023 assets certified in 2023 ü Piloting continuous emissions ü AMI includes aerial surveys of operator ü Achieved peer-leading “A” certification grade monitoring equipment assets as well as non-oil & gas assets 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 for every acre disturbed ü Methane Intensity ü Voluntary initiatives focused on ü Company Practices to Manage Methane Emissions pollinator and tree plantings, Achieved “A” certification grade streambank stabilization, and ü Emissions Monitoring Technology Deployment - the highest certification level enhancing aquatic wildlife available May 2024 Update 27

Supplemental Information: Segment Overview Pipeline & Storage Overview National Fuel Gas Supply Corporation Empire Pipeline, Inc. 28 May 2024 Update 28

Pipeline & Storage Pipeline & Storage Segment Overview National Fuel Gas Supply Corporation (1) ü Contracted Capacity : § Firm Transportation: 3,408 MDth per day § Firm Storage: 70,693 MDth (fully subscribed) (2) ü Rate Base : ~$1,244 million Empire Pipeline ü FERC Rate Proceeding Status: § New rates are in effect as of February 1, 2024 § Interim rates, subject to FERC approval Supply Corp. Empire Pipeline, Inc. (1) ü Contracted Capacity : § Firm Transportation: 1,048 MDth per day § Firm Storage: 3,753 MDth (fully subscribed) (2) ü Rate Base : ~$317 million ü FERC Rate Proceeding Status: § Rates in effect since January 2019 § Must file for new rates no later than May 1, 2025 (1) Disclosed annually as of September 30, 2023. May 2024 Update 29 (2) As of December 31, 2023, calculated from National Fuel Gas Supply Corporation’s and Empire Pipeline, Inc.’s 2023 FERC Form-2 reports, respectively.

Pipeline & Storage Pipeline & Storage Customer Mix (1) Customer Transportation by Shipper Type Affiliated Customer Mix (Contracted Capacity) Affiliated Non-Affiliated End User 22% 8% Outside Producer 52% Pipeline 28% 16% 79% Marketer 78% 12% LDC 48% 36% 21% LDCs Producers Firm Storage Firm Transport (1) Disclosed annually as of 9/30/2023. May 2024 Update 30

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) May 2024 Update 31

Pipeline & Storage Continued Expansion of the Supply Corp. Line N System Recent Expansion of Line N ü Over the past four 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 May 2024 Update 32

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 May 2024 Update 33

Supplemental Information: Segment Overview Utility Overview National Fuel Gas Distribution Corporation 34

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: 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) o Modernization Tracker (1) Disclosed annually as of September 30, 2023. (2) Applied to new plant placed in service through September 30, 2024. May 2024 Update 35

Utility NY Utility Rate Case Status Rate Case is Ongoing with New Rates Expected to Start October 1, 2024 ü Filed case on October 31, 2023; National Fuel’s base rates have not changed since the last base rate case was litigated in 2017 ü Rebuttal testimony filed March 22, 2024; Settlement discussions ongoing Proposed Base (1) Revenue Increase ü Proposed Base Rate Increase = $83.0 million ($67.1 million net margin revenues) § 28.8% increase in base delivery revenues (23.0% net margin revenues) § 12.0% increase in operating revenues ü Proposed Capital Structure and Returns: § Capital Structure = 48% debt / 52% equity Utility § Return on Equity = 9.8% ü Increasing rate base and depreciation expense associated with higher plant in-service (1) § Total Rate Base in Rate Year = ~$1.03 billion Key Drivers § Maintain leak prone pipe replacement target at 110 miles per year ü O&M expense inflation (e.g., labor and benefits) ü Implement elements of Long-Term Plan filed with NY PSC in July 2023 (e.g. Hybrid Heating, Demand Response, RNG and RSNG pilots) ü Seeking approval for uncollectible expense tracker May 2024 Update 36 (1) The Company filed rebuttal testimony and exhibits on March 22, 2024 revising the requested base rate increase from $88.6 million to $83.0 million. Refer to NY PSC case docket 23-G-0627.

Utility NY Utility Regulated Environment NY Regulatory Environment Continues to Prioritize Access to Safe, Reliable and Affordable Energy ü First utility in the state to submit a LTP (Long-Term Plan) § NY PSC implemented NFG’s LTP with modifications in December 2023 § Includes an “All-of-the-Above Pathway” for an affordable and practical way to meet the State’s climate goals § LTP includes Hybrid Heating, Demand Response, RNG and RSNG pilots ü System Modernization § NFG continues to receive support for accelerated and proactive investments in the replacement of leak prone pipe § Current modernization tracker reduces regulatory lag on rate base growth ü Supportive rate mechanisms include: § Weather normalization – Adjusts billings based on temperature variances compared to average weather § Revenue Decoupling – Separates usage from revenue for initiatives such as energy conservation § Industrial 90/10 – Symmetrical sharing for large commercial and industrial customer margin May 2024 Update 37

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) $250 $250 $200 $200 $150 $150 $100 $100 $50 $50 $0 Peer 1 Peer 2 NFGDC Peer 3 Peer 4 Peer 5 Peer 6 Peer 7 Peer 8 $0 NY NFGDC PA Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 (1) Based on 2023 average monthly residential bill data posted on company websites required by the NYPSC. May 2024 Update 38 (2) Based on analysis of 2024 PAPUC Annual Rate Comparison Report, which includes data for average monthly residential bills for 2023.

Utility Utility Continues its Significant Investments in Safety Long-Standing Focus on Distribution System Safety and Reliability (2) $150-$175 (1) Capital Expenditures for Safety Total Capital Expenditures $139.9 $111.0 $108.6 $100.8 $95.8 $94.3 $85.6 $82.6 $79.7 $74.1 $71.4 $69.9 Modernization Spending in NY Expected to Add $8 - $9 MM in Gross Margin in FY 2024 2018 2019 2020 2021 2022 2023 2024E Fiscal Year (1) A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation. May 2024 Update 39 (2) Increase from FY23 to FY24E is partially due to the estimated impact of New York State’s Roadway Excavation Quality Assurance Act (“REQAA”). Utility Capital Expenditures ($ millions)

Utility Long-Standing Pipeline Replacement & Modernization (1) (2) 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 9,817 miles Plastic 114 Wrought Iron 113 113 113 112 Coated Bare PA 4,832 miles Plastic 2019 2020 2021 2022 2023 Fiscal Year (1) All values are reported on a calendar year basis, as of December 31, 2023, as required by the DOT. May 2024 Update 40 (2) All values are reported on a fiscal year basis, as required by the NYPSC and PAPUC.

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 State 200 (2) Climate Act (CLCPA) 100 ü Reductions Primarily Driven by Ongoing Modernization of Mains and Services 0 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. (2) New York Climate Leadership and Community Protection Act, enacted in 2019. May 2024 Update 41

Utility Promoting Renewable & Certified Natural Gas RNG (Renewable Natural Gas) Progress: Through Fiscal 2020 July 2021 Currently Future Three site locations under Awarded four RNG grants First on-system project Advance RNG construction. for $1.1 million through goes online. Production By end of 2025, opportunities in the the Utility’s Area volumes ~50,000 anticipated RNG volumes Utility Long-Term Plan Development Program Mcf/year. of 386,000 Mcf/ year. Continuing to Work with Regulators and Third Parties to Certified Natural Gas Pilot Programs: (1) Advance Zero and Low Carbon Opportunities Pennsylvania • Term: Three-year pilot program ending on July 31, 2027 • Certification Providers and Levels: • Distribution Corporation received approval from NY and PA utility o MiQ Grade A or Grade B, or commissions to accept RNG into its distribution system o OGMP 2.0 Level 4 or Level 5 • Certification Cap Premium: • Final Scoping Plan adopted by New York Climate Action Council includes o Annual spend not to exceed $175,000 o Cap on certification premium not to exceed $0.07/Dth/day consideration of alternative fuels and technologies in future gas system (2) planning New York • Proposed: Three-year pilot program • Low Carbon Resources Initiative (LCRI) expected to provide • Certification Providers and Levels: o MiQ Grade A or Grade B opportunities for NFG to leverage technology acceleration within its o OGMP 2.0 Level 4 or Level 5 regional footprint • Certification Cap Premium: o Annual spend not to exceed $300,000 (1) Pennsylvania CNG pilot program was approved via 1307 (f) Settlement R-2024-3045177. May 2024 Update 42 (2) New York CNG pilot program details are as proposed in current New York Rate Case.

Supplemental Information Rate Case Overview 43 May May 2024 U 2024 Updat pdate e 43

Rate Case Overview: Timing and Status Recent updates in orange Pipeline & Storge Utility Supply Empire NY PA Regulatory Agency FERC FERC NY PSC PaPUC (Governed by) • Settlement filed • Rates in effect since • Filed rate case • Settlement approved March 27, 2024 January 1, 2019 October 31, 2023 in June 2023 • New rates in effect • Must file for new rates • Anticipant new rates • Rates in effect since Timing/ Status February 1, 2024 by May 1, 2025 effective October 1, August 1, 2023 • No moratorium or 2024 comeback period • Rate case is ongoing (1) Rate base $823 $1,244 $317 $412 (in millions) Requested à $1,030 NY PSC Rate Case Not stated – Not stated – Not stated – April 2017 à 43% Equity Ratio Black box settlement Black box settlement Black box settlement Requested à 52% NY PSC Rate Case Not stated – Not Stated – Not Stated – April 2017 à 8.7% Authorized ROE Black box settlement Black box settlement Black box settlement Requested à 9.8% (1) Represents the latest available information in regulatory filings. Supply and Empire rate base amounts are as of 12/31/2023. NY is as of 8/31/2023 and PA is as of 12/31/2023. May 2024 Update 44

Supplemental Information Guidance & Other Financial Information 45 May May 2024 U 2024 Updat pdate e 45

Fiscal 2024 Earnings Guidance Previous FY2024 Earnings Guidance Updated FY2024 Earnings Guidance (1) (1) $4.90 to $5.20/share $4.75 to $5.05/share Key Guidance Drivers 390 - 405 Bcfe Net Production (2) Realized natural gas prices (after-hedge) ~$2.40 - $2.45/Mcf Exploration & G&A Expense $0.17 - $0.19/Mcf Production DD&A Expense $0.69 - $0.74/Mcf LOE Expense $0.69 - $0.70/Mcf Gathering Revenues $240 - $255 million Gathering Gathering O&M Expense ~$0.09/ Mcf of throughput Pipeline & Storage Revenues $400 - $420 million (Supply Rate Increase) Pipeline & Pipeline & Storage O&M Expense ~5% increase Pipeline & Storage Storage Pipeline & Storage Depreciation Expense ~5% increase ~7% - 10% increase Utility Utility Operating Income Utility ‾ YTD warmer than normal weather ‾ O&M ~5% increase Tax Rate Effective Tax Rate ~25% (1) Excludes items impacting comparability. See Comparable GAAP Financial Measure Slides & Reconciliations at the end of this presentation. May 2024 Update 46 (2) Assumes NYMEX pricing of $2.00/MMBtu and in-basin spot pricing of $1.60/MMBtu for fiscal 2024, and reflects the impact of existing financial hedges, firm sales and firm transportation contracts. Regulated Non-Regulated

Financial Results and Major Drivers (1) (2) Adjusted Operating Results Adjusted EBITDA ($ millions) FY24 Major Drivers ($ per share) $1,226 $1,184 $1,165 $5.88 E&P and Gathering: § Natural Gas Prices $5.17 $4.75 - $5.05 § Natural Gas Production $656 $599 $612 & Gathering Throughput $3.21 $2.52 E&P P&S: § Impact of Supply Rate $199 $177 $186 Case Increase Gathering $1.01 $1.08 $241 $243 Pipeline $237 Utility: $1.11 $1.09 & Storage § Impact of Pennsylvania $163 $159 $145 Utility $0.59 $0.52 Rate Increase FY 2022 FY 2023 FY 2024 Guidance FY 2022 FY 2023 TTM 3/31/24 (1) Excludes items impacting comparability. See Comparable GAAP Financial Measure Slides & Reconciliations at the end of this presentation. (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. May 2024 Update 47

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: Impairments under the SEC's full cost ceiling test for natural gas reserves; changes in the price of natural gas; 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, 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; 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; 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; 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, water availability and disposal or recycling opportunities of used water, 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; the Company's ability to complete strategic transactions; 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. Forward-looking and other statements in this presentation regarding methane and greenhouse gas reduction plans and goals are not an indication that these statements are necessarily material to investor or required to be disclosed in our filings with the SEC. In addition, historical, current and forward-looking statements regarding methane and greenhouse gas emissions may be based on standards for measuring progress that are still developing, internal controls, and processes that continue to evolve and assumptions that are subject to change in the future. 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, 2023, and the Forms 10-Q for the quarter ended December 31, 2023, and March 31, 2024. 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. May 2024 Update 48

Hedge Portfolio & Capped Firm Sales 3Q 2024 4Q 2024 FY 2025 FY 2026 FY 2027 FY 2028 Swaps Units Volume Mmbtu 38,670 38,670 101,080 40,060 21,750 1,750 Wtd. Avg. Floor $ / Mmbtu $3.35 $3.35 $3.50 $3.96 $4.16 $4.16 Collars Volume Mmbtu 14,400 14,400 43,960 42,720 3,560 -- Wtd. Avg. Ceiling $ / Mmbtu $3.79 $3.79 $4.65 $4.76 $4.76 -- Wtd. Avg. Floor $ / Mmbtu $3.22 $3.22 $3.49 $3.53 $3.53 -- Fixed Price Physical Volume Mmbtu 22,468 18,389 76,440 71,640 53,921 17,152 Wtd. Avg. Floor $ / Mmbtu $2.28 $2.43 $2.47 $2.42 $2.46 $2.61 Capped Firm Sales Volume Mmbtu 2,693 2,729 10,793 914 -- -- NYMEX Cap $ / Mmbtu $2.92 $2.92 $2.92 $2.92 $2.92 $2.92 Volume Mmbtu 1,539 1,560 6,167 6,161 6,132 519 NYMEX Cap $ / Mmbtu $4.95 $4.95 $4.95 $4.95 $4.95 $4.95 Volume Mmbtu 1,878 1,903 7,526 7,517 7,483 7,462 NYMEX Cap $ / Mmbtu $7.00 $7.00 $7.00 $7.00 $7.00 $7.00 May 2024 Update 49

Firm Transportation Commitments Volume Delivery Demand Charges Production Source Gas Marketing Strategy (Dth/d) Market ($/Dth) Northeast Supply Canada Firm Sales Contracts rd Diversification EDA – Tioga 50,000 $0.46 (3 party) (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 158,000 TGP 200 (NY) 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 In-Basin Eastern EDA – Tioga 100,000 $0.19 (3 Party) Capacity release WDA – CRV Leidy South / FM100 Transco Zone Firm Sales Contracts rd 330,000 $0.66 (3 Party) WMB – Transco; NFG - Supply EDA - Lycoming 6 NNY Transco Zone 6 NNY/NYMEX May 2024 Update 50 Currently In-Service

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. The revised earnings guidance range does not include the impact of certain items that impacted the comparability of earnings during the six months ended March 31, 2024, including: (1) after-tax unrealized losses on a derivative asset, which reduced earnings by $0.03 per share; and (2) after-tax unrealized gains on other investments, which increased earnings by $0.02 per share. While the Company expects to record certain adjustments to unrealized gain or loss on a derivative asset and unrealized gain or loss on investments during the six months ending September 30, 2024, the amounts of these and other potential adjustments and charges, including ceiling test impairments, are not reasonably determinable at this time. As such, the Company is unable to provide earnings guidance other than on a non-GAAP basis. Management defines 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. May 2024 Update 51

Non-GAAP Reconciliations – Adjusted EBITDA Reconciliation of Adjusted EBITDA to Consolidated Net Income ($ Thousands) 12-Months Ended FY 2019 FY 2020 FY 2021 FY 2022 FY 2023 3/31/2024 Total Adjusted EBITDA Exploration & Production Adjusted EBITDA $ 351,159 $ 312,166 464, 529 656, 310 611,782 598,915 Pipeline & Storage Adjusted EBITDA 162, 181 189,520 218, 921 240, 904 237,327 243,046 Gathering Adjusted EBITDA 108, 292 119, 879 159, 005 176, 572 185,882 199,069 Utility Adjusted EBITDA 176, 134 171,418 171, 379 162,871 145,002 159, 300 Corporate & All Other Adjusted EBITDA (12,393) (7,529) ( 13,521) (10,762) (15,273) (16,462) Total Adjusted EBITDA $ 785,373 $ 785,454 $ 1,000,313 $ 1,225,895 $ 1,164,720 $ 1,183,868 Consolidated Net Income $ 304,290 $ (123,772) $ 363,647 $ 566,021 $ 476,866 $ 465,588 Plus: Interest Expense 106,756 117,077 146, 357 130,357 131,886 169, 047 Minus: Other Income (Deductions) 15,542 17,814 15,238 1,509 ( 18,138) (18,736) Plus: Income Tax Expense 85,221 18,739 114,682 116, 629 164, 533 167,466 Plus: Depreciation, Depletion & Amortization 275, 660 306, 158 335,303 369,790 409, 573 400,503 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 (2,096) - - - - - Rounding - - - - - - Total Adjusted EBITDA $ 785,373 $ 785,454 $ 1,000,313 $ 1,225,895 $ 1, 164,720 $ 1,183,868 Consolidated Debt to Total Adjusted EBITDA Long-Term Debt, Net of Current Portion (End of Period) $ 2,149,000 $ 2,649,000 $ 2,649,000 $ 2,100,000 $ 2,400,000 $ 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, 500 278,900 Less: Cash and Temporary Cash Investments (End of Period) (20,428) (20,541) (31,528) (46,048) (55,447) ( 50,769) Total Net Debt (End of Period) $ 2,183,772 $ 2,658,459 $ 2,775,972 $ 2,662,952 $ 2,632,053 $ 2,628,131 Long-Term Debt, Net of Current Portion (Start of Period) 2,149,000 2,149,000 2,649,000 2,649,000 2,100,000 2,100,000 Current Portion of Long-Term Debt (Start of Period) - - - - 549,000 - Notes Payable to Banks and Commercial Paper (Start of Period) - 55,200 30,000 158, 500 60,000 410, 000 Less: Cash and Temporary Cash Investments (Start of Period) (229,606) ( 20,428) (20,541) ( 31,528) ( 46,048) ( 71,533) Total Net Debt (Start of Period) $ 1,919,394 $ 2,183,772 $ 2,658,459 $ 2,775,972 $ 2,662,952 $ 2,438,467 Average Total Net Debt $ 2,051,583 $ 2,421,116 $ 2,717,216 $ 2,719,462 $ 2,647,503 $ 2,533,299 Average Total Net Debt to Total Adjusted EBITDA 2.61 x 3.08 x 2.72 x 2.22 x 2.27 x 2.14 x May 2024 Update 52

Non-GAAP Reconciliations – Adjusted EBITDA, by Segment Reconciliation of Adjusted EBITDA to Net Income, by Segment ($ Thousands) 12-Months FY 2018 FY 2019 FY 2020 FY 2021 FY 2022 FY 2023 Ended 3/31/24 Exploration and Production Segment Reported GAAP Earnings $ 180,632 $ 111,807 $ (326,904) $ 101,916 $ 306,064 $ 232,275 $ 194,649 Depreciation, Depletion and Amortization 124,274 154,784 172,124 182,492 208,148 241,142 272,391 Other (Income) Deductions (307) (1,091) 882 937 3,210 (3,748) (3,205) Interest Expense 54,288 54,777 58,098 69,662 53,401 54,317 59,274 Income Taxes (41,962) 32,978 (41,472) 33,370 43,898 87,796 75,806 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) - 0 Loss from discontinuance of crude oil cash flow hedges - - - - 44,632 - 0 Transaction and severance costs related to West Coast asset sale - - - - 9,693 - 0 Adjusted EBITDA $ 317,707 $ 351,159 $ 312,166 $ 464,529 $ 656,310 $ 611,782 $ 598,915 Pipeline and Storage Segment Reported GAAP Earnings $ 97,246 $ 74,011 $ 78,860 $ 92,542 $ 102,557 $ 100,501 $ 101,958 Depreciation, Depletion and Amortization 43,463 44,947 53,951 62,431 67,701 70,827 73,389 Other (Income) Deductions (5,926) (9,157) (4,635) (5,840) (6,889) (11,989) (13,000) Interest Expense 31,383 29,142 32,731 40,976 42,492 43,499 45,513 Income Taxes 17,806 23,238 28,613 28,812 35,043 34,489 35,186 Adjusted EBITDA $ 183,972 $ 162,181 $ 189,520 $ 218,921 $ 240,904 $ 237,327 $ 243,046 Gathering Segment Reported GAAP Earnings $ 83,519 $ 58,413 $ 68,631 $ 80,274 $ 101,111 $ 99,724 $ 108,183 Depreciation, Depletion and Amortization 17,313 20,038 22,440 32,350 33,998 35,725 37,167 Other (Income) Deductions (778) (460) (260) 12 26 (684) (376) Interest Expense 9,560 9,406 10,877 17,493 16,488 14,989 14,477 Income Taxes (17,677) 20,895 18,191 28,876 24,949 36,128 39,618 Adjusted EBITDA $ 91,937 $ 108,292 $ 119,879 $ 159,005 $ 176,572 $ 185,882 $ 199,069 Utility Segment Reported GAAP Earnings $ 51,217 $ 60,871 $ 57,366 $ 54,335 $ 68,948 $ 48,395 $ 64,147 Depreciation, Depletion and Amortization 53,253 53,832 55,248 57,457 59,760 61,450 63,327 Other (Income) Deductions 29,073 24,021 23,380 23,785 (7,117) (6,343) (7,722) Interest Expense 26,753 23,443 22,150 21,795 24,115 34,233 33,467 Income Taxes 15,258 13,967 13,274 14,007 17,165 7,267 6,081 Adjusted EBITDA $ 175,554 $ 176,134 $ 171,418 $ 171,379 $ 162,871 $ 145,002 $ 159,300 Corporate and All Other Reported GAAP Earnings $ (21,093) $ (812) $ (1,725) $ 34,580 $ (12,659) $ (4,029) $ (3,349) Depreciation, Depletion and Amortization 2,658 2,059 2,395 573 183 429 460 Gain on Sale of Timber Properties - - - (51,066) - - - Other (Income) Deductions (888) 2,229 (1,553) (3,656) 12,279 4,626 5,567 Interest Expense (7,462) (10,012) (6,779) (3,569) (6,139) (15,152) (17,912) Income Taxes 19,081 (5,857) 133 9,617 (4,426) (1,147) (1,228) Adjusted EBITDA $ (7,704) $ (12,393) $ (7,529) $ (13,521) $ (10,762) $ (15,273) $ (16,462) May 2024 Update 53

Non-GAAP Reconciliations – Adjusted Operating Results Three Months Ended March 31, (in thousands except per share amounts) 2024 2023 Reported GAAP Earnings $166,272 $140,880 Items impacting comparability: Unrealized (gain) loss on derivative asset (E&P) -536 2,471 Tax impact of unrealized (gain) loss on derivative asset 147 -677 Unrealized (gain) loss on other investments (Corporate / All Other) -769 -1,068 Tax impact of unrealized (gain) loss on other investments 162 224 Adjusted Operating Results $165,276 $141,830 Reported GAAP Earnings Per Share $1.80 $1.53 Items impacting comparability: Unrealized (gain) loss on derivative asset, net of tax (E&P) — 0.02 Unrealized (gain) loss on other investments, net of tax (Corporate / -0.01 -0.01 All Other) Rounding — — Adjusted Operating Results Per Share $1.79 $1.54 May 2024 Update 54

Reconciliation – Capital Expenditures Reconciliation of Segment Capital Expenditures to Consolidated Capital Expenditures ($ Thousands) FY 2024 FY 2020 FY 2021 FY 2022 FY 2023 Guidance Capital Expenditures Exploration & Production Capital Expenditures $ 670,455 $ 381,408 $ 565, 791 $ 737,725 $525,000 - $555,000 Pipeline & Storage Capital Expenditures $ 166,652 $ 252,316 $ 95,806 $ 141, 877 $120,000 - $140,000 Gathering Segment Capital Expenditures $ 297, 806 $ 34,669 $ 55,546 $ 103, 295 $90,000 - $110,000 Utility Capital Expenditures $ 94,273 $ 100,845 $ 111,033 $ 139, 922 $150,000 - $175,000 Corporate & All Other Capital Expenditures $ 561 $ 450 $ 1,212 $ 754 Eliminations $ (1,130) $ 223 Total Capital Expenditures from Continuing Operations $ 1,228,617 $ 769,911 $ 829,388 $ 1,123,573 $885,000 - $980,000 Plus (Minus) Acquisition of Upstream Assets and Midstream Gathering Assets $ (506,258) $ (124,758) Subtotal $ 722,359 $ 769, 911 $ 829,388 $ 998,815 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 $ (45,788) $ 42,983 Exploration & Production FY 2019 Accrued Capital Expenditures $ 38,063 Exploration & Production FY 2018 Accrued Capital Expenditures $ ( 31,813) Pipeline & Storage FY 2022 Accrued Capital Expenditures $ (15,188) $ 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 Pipeline & Storage FY 2018 Accrued Capital Expenditures $ ( 20,587) Gathering FY 2022 Accrued Capital Expenditures $ ( 10,724) $ 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 Gathering FY 2018 Accrued Capital Expenditures $ ( 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 $ ( 10,751) $ 10,751 Utility FY 2019 Accrued Capital Expenditures $ 12,692 Utility FY 2018 Accrued Capital Expenditures Total Accrued Capital Expenditures $ (6,206) $ ( 18,177) $ (17,562) $ 11,053 Total Capital Expenditures per Statement of Cash Flows $ 716, 153 $ 751,734 $ 811,826 $ 1,009,868 $885,000 - $980,000 (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 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 (2) The year ended September 30, 2023 includes $124.8 million related to the acquisition of upstream assets acquired from SWN, as well as $25.0 million related to the acquisition of assets from EXCO and UGI. The acquisition cost for the assets acquired from SWN is reported as a component of Acquisition of Upstream Assets on the Consolidated Statement of Cash Flows. May 2024 Update 55

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) 3 72,271 372,271 341,699 1,211 3 42,911 Oil Production (MBbl) 3 0 30 16 1,588 1 ,604 Total Production (Mmcfe) 3 72,451 - 372,451 341,796 10,741 3 52,536 Total Production (Mboe) 6 2,075 - 62,075 56,966 1,790 5 8,756 (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. May 2024 Update 56