EX-99 2 d19257dex99.htm EX-99

Investor Presentation Fiscal 2025 – 3rd Quarter Update July 30, 2025 Exhibit 99

National Fuel Gas Company Company Overview (3) Why National Fuel? (8) Financial Overview (13) Business Highlights (17) Supplemental Information Segment Information (24) Guidance & Other Financial Information (49)

Company Overview Left picture: Seneca Resources rig in Tioga County, PA. Right picture: Buffalo Bills’ New Highmark Stadium construction in Orchard Park, NY. Corporate HQ: Buffalo, NY ~2,300 employees NYSE: NFG Market Cap: ~$7.8B 123 Years of consecutive dividend payments 55 Years of consecutive dividend increases >10% Adjusted EPS Growth FY24-FY27E Investment Grade credit rating 17% reduction in methane emissions since 2020 Note: This presentation includes forward-looking statements. Please review the safe harbor for forward looking statements at the end of this presentation. Market capitalization is presented as of July 28th, 2025.

History of National Fuel Industry Pioneer Born From Rockefeller’s Standard Oil Company

NFG: A Diversified, Integrated Natural Gas Company (1) Twelve months ended June 30, 2025. 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 for the three months ended June 30, 2025. Upstream: Exploration & Production Midstream: Gathering Midstream: Pipeline & Storage Downstream: Utility Developing our large, high-quality acreage in Marcellus & Utica shales Providing safe, reliable and affordable service to customers in WNY and NW PA Expanding & modernizing pipeline infrastructure to provide outlets for Appalachian production Partnering with producers to construct pipeline systems and deliver gas to interstate pipelines ~1.2 Million Net acres in Appalachia ~1.2 Bcf/day Net total production(2) ~400 Miles of Pipe With 7 major pipelines interconnections ~1.4 Bcf/day Total throughput(2) ~$2 Billion Investments since 2010 4.6 MMDth Daily interstate pipeline capacity under contract 755,000 Utility customers >$1 Billion Investments in safety since 2010 52% $703MM Adjusted EBITDA(1) 15% $205MM Adjusted EBITDA(1) 20% $271MM Adjusted EBITDA(1) 13% $181MM Adjusted EBITDA(1) Non-Regulated Regulated

Western Development Area – ~925,000 Acres Eastern Development Area – ~320,000 Acres Non-Regulated Business Overview Exploration & Production Segment (Upstream) Gathering Segment (Midstream) Seneca Resources Company Total Net Acres (Pennsylvania): ~1.2 million Total Proved Reserves: 4.8 Tcfe(1) Current Net Production: ~1.2 Bcf/d(2) Firm Transportation Capacity: ~1 Bcf/d to premium markets Decades of Marcellus and Utica development inventory National Fuel Gas Midstream Company Total Throughput: 1.4 Bcf/d(2) (including third-party) ~400 miles of gathering pipeline 23 compressor stations with ~125k HP Interconnections with 7 major pipelines Reported annually as of September 30, 2024. Average net production and throughput for the three months ended June 30, 2025.

Regulated Business Overview Pipeline & Storage Segment (Midstream) Utility Segment (Downstream) Regulated by Federal Energy Regulatory Commission (FERC) Total Rate Base: $1.6 Billion(1) ~2,600 miles of pipeline / 28 storage fields National Fuel Gas Supply Corporation: Firm Contracted Storage Capacity: 71 Bcf(2) Firm Contracted Transportation Capacity: 3.5 Bcf / day(2) Empire Pipeline, Inc.: Firm Contracted Storage Capacity: 4 Bcf(2) Firm Contracted Transportation Capacity: 1.1 Bcf / day(2) Interconnections with 8 major interstate pipelines New York Jurisdiction 541,000 customers Regulated by the New York Public Service Commission (NYPSC) Pennsylvania Jurisdiction 214,000 customers Regulated by the Pennsylvania Public Utilities Commission (PAPUC) Total Rate Base: $1.5 Billion(1) Fiscal 2024 Total Throughput: ~128 Bcf Provides >90% of the space heating load in operating footprint Estimated rate base as of June 30, 2025. Reported annually as of September 30, 2024 and includes short-term and long-term contracted capacity.

Why National Fuel? Optimized capital allocation Lower cost of capital Operational synergies Improved profitability Targeting significant rate base growth from system modernization and expansion Increasing free cash flow driven by improving upstream capital efficiencies Responsibly Reduce Emissions Continued progress toward emissions reduction targets Enhanced GHG disclosures on sustainability initiatives 123 consecutive years of dividend payments 55 consecutive years of dividend increases Ongoing share repurchase program Long-Standing History of Shareholder Returns Responsibly Reducing Emissions Visibility on Long-Term EPS & FCF Growth Strong Integrated Returns

Integrated Model Drives Strong Returns Source: Bloomberg for the TTM ending September 30th. NFG adjusted excludes after-tax non-cash ceiling test impairments. Average Annual NFG Stock Outperformance Since FY17 NFG vs. S&P 500: +2% NFG vs. E&P Peers: +6% NFG vs. Utility Peers: +5% NFG’s ROCE Outperforms Peers and Broader Market, on Average, Over a Multi-Year Period Decrease driven by non-cash impairments S&P O&G Index NFG S&P 500 UTY Integrated Business Model Benefits Operations: Lower cost structure Financial: Lower cost of capital Strategic: Optimized capital allocation Commercial: Greater revenue / margin NFG Adj. (2)

(1) NYMEX based on flat price assumptions per year. Includes current hedge positions as of June 30, 2025 and excludes acquisitions. Note: 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. Strong Value Proposition Driven by Earnings & Cash Flow Outlook Increasing EPS expected to drive future dividend growth Ratemaking activity propelling FY25E adjusted EPS growth >15% Beyond FY25, expect adjusted EPS CAGR to moderate to 5-7%, similar to average annual rate base growth Regulated Businesses Significant FCF generation expected to provide flexibility in capital allocation priorities Hedging provides near-term visibility to growing FCF generation, with the ability to capture higher natural gas prices long-term Non-Regulated Businesses Non-Regulated Free Cash Flow(1) 8-10% CAGR Regulated Adjusted Operating Results ($ millions) $3.00 $4.00 $5.00 NYMEX On Track for >10% Consolidated 3-Year Adjusted EPS CAGR (FY24-27E)

Proven Track Record of Returning Capital to Shareholders 55 Years Consecutive Dividend Increases 123 Years Consecutive Payments $2.14 per share $0.19 per share Stable, Growing Dividend … …Plus Share Buyback $200 MM Share Repurchase Program approved in March 2024 Through June 30th purchased: 2.0 MM shares At an average purchase price of: ~$60 per share >$650 Million Returned to Shareholders in Last 3 Years(1) For the trailing three years as of June 30, 2025.

Considerable Progress on Emissions Reductions All emissions reduction targets based on 2020 baseline. Measured using calendar 2023 emissions data, as reported in Company’s 2023 Corporate Responsibility Report. Continued Progress On Our Methane Intensity Targets(1) 17% reduction in consolidated methane emissions since 2020 Responsible gas certifications Pneumatic device replacement Equipment upgrades at existing facilities Use of best-in-class emissions controls for new facilities NFG Consolidated GHG Target 25% absolute GHG reduction by 2030 Progress since 2020: 5.6% decrease while growing the business Latest Corporate Responsibility Report Provides Enhanced Disclosures on Sustainability Initiatives

Financial Overview

Continued Momentum Propels Higher Earnings Guidance Growth Supports Consolidated 3-Year Adj. EPS CAGR >10% (FY24-27E) Adjusted Operating Results(1) ($ per share) Excludes items impacting comparability. Consolidated Adjusted Operating Results includes Corporate & All Other. See Comparable GAAP Financial Measure Slides & Reconciliations at the end of this presentation. FY25 Adjusted EPS guidance, which excludes items impacting comparability, is shown at the midpoint of the range and assumes $3.25 NYMEX pricing, which approximates the current NYMEX forward curve. Fiscal 2026 Adjusted EPS is shown at the midpoint of guidance ranges, as detailed on slide 50, assuming NYMEX pricing of $3.00, $4.00 and $5.00. Q3 Highlights Non-Regulated – higher production/throughput combined with lower unit costs and higher realized prices compared to the prior year Regulated – higher net income compared to the prior year as a result of rate case outcomes and continued modernization investments FY25 Earnings Guidance projects 36-39% increase from FY24 FY26 Guidance Initiation Highlights Non-Regulated – ongoing improvement in capital efficiency is projected to continue (Seneca expects 4% lower capital and 6% higher production) Regulated – continued growth as a result of ongoing ratemaking efforts, driven by the three-year NY rate settlement and PA modernization tracker, or DSIC (Distribution System Improvement Charge) Quarterly Highlights & Higher FY26 Initial Outlook (2) (2) $3.00 $4.00 $5.00

Capital Allocation Priorities Drive Spending Levels (2) Capital expenditures include accrued capex. 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. FY25 and FY26 consolidated capital guidance is displayed at the midpoint of the range ($890 - $955 and $960 - $1,060 million, respectively). FY23 reflects the netting of $150 million in the E&P segment related to the acquisition of Appalachian upstream assets. FY24 E&P reflects the netting of $6.2 million related to the acquisition of assets from UGI. Capital Expenditures by Segment ($ millions)(1) $500 – $510 $95 - $110 Capital Allocation Priorities Organic Investments Responsibly Manage the Balance Sheet Return of Capital to Shareholders Highly Strategic M&A Invest in regulated growth via modernization and pipeline expansions Maintain mid-single digit production growth in upstream/gathering Maintain investment grade credit rating Target optimal rate making capital structure Uphold 55-year history of dividend increases Execute value-accretive share repurchases Non-Regulated: Integrated opportunities geographically proximate to existing operations Regulated: Growth to balance business mix Regulated Growth Non- Regulated Capital Efficiency Continue to Reduce Non-Regulated Capital Expenditures

Balance Sheet Resiliency Through the Commodity Cycle Net Debt / Adjusted EBITDA(1) Net Debt is net of cash and temporary cash investments. Reconciliations of Net Debt and Adjusted EBITDA are included at the end of this presentation. A reconciliation of Funds From Operations (FFO) to Net Cash Provided by Operating Activities can also be found at the end of this presentation. We are unable to reconcile certain forward looking non-GAAP financial measures and ratios. Please see slide entitled Comparable GAAP Financial Measure Slides & Reconciliations at the end of this presentation. $300 MM term loan was drawn in April 2024 and replaced outstanding commercial paper. Current Credit Rating Investment Grade Credit Rating S&P BBB- Moody’s Baa3 Fitch BBB Investment Grade Credit Rating Conservative Leverage Provides for Opportunistic Capital Allocation Committed to Investment Grade Credit Rating Debt Maturity Profile by Fiscal Year ($ MM) FFO / Net Debt Comfortably above Downgrade Threshold(1) Capitalization Downgrade Threshold Downgrade Threshold (2)

Business Highlights

(1) See Case 23-G-0627 on file with the NY PSC. (2) 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%). Earnings Growth from Successful Rate Case Activity & Pipeline Projects Utility Pipeline & Storage New York Pennsylvania Supply Corporation Empire Pipeline Filed a rate case in October 2023 for new rates effective October 2024 (fiscal 2025) Joint Proposal approved(1) on December 19, 2024, with no significant modifications to the 3-year rate settlement 3-year revenue requirement cumulative increase: RY1 $57.3 MM RY2 $73.1 MM RY3 $85.8 MM Rate Case Drivers Approved Authorized ROE 9.7% Equity Ratio 48% Rate Base (Yr 1) $1.04B Joint Settlement reached in 2023 on first rate case in PA since 2007 Achieved $23 million revenue requirement (~80% of filed position) New weather normalization adjustment mechanism Current rates became effective August 1, 2023 On January 1, 2025, filed to recover eligible plant costs under PA’s Distribution System Improvement Charge (DSIC)(2), a system modernization tracker Tioga Pathway and Shippingport Lateral Project combined estimated capital spend of >$150 MM contributes to rate base (earnings) growth Tioga received FERC approval in May 2025, on track for in-service date late calendar 2026 Shippingport Lateral project announced in July 2025 with an expected in-service date late calendar 2026 Amendment to 2019 Settlement approved by FERC on March 17, 2025 New rates go into effect November 1, 2025 No material impact to customer rates (keeps rates stable for at least 2 years) Modest decrease to revenue (~$500k annual decrease) Moratorium period until April 30, 2027 Comeback required by May 31, 2031 Not required to file a new rate proceeding until May 2031 DSIC allows for additional multi-year growth up to $7 MM/year 3-Year rate case settlement drives significant earnings growth Pipeline Expansion Projects Boost Rate Base Growth

Integrated Development Creates Differentiated Value EDA development plan drives higher capital efficiencies and cash flow generation EDA wells deliver >2x the well productivity versus legacy WDA program(1) Well and facility design optimization driving enhanced EDA Utica well performance Recent Utica pads are best to date Visibility to further productivity upside Well productivity is measured within the first five years that a well comes online. Development Plan Highlights Western Development Areas (WDA) Legacy Development Area Primarily Owned in Fee (No Royalty) Eastern Development Areas (EDA) Development Focus Area ~20 years of inventory in EDA + WDA at PV-10% breakeven price of less than $2.25/MMBtu NYMEX Average of 20-30 wells brought online per year Integrated gathering systems provide optimized investment timing, low-cost structure and resilient thru-cycle margins Deep Inventory of Highly Economic Locations Western Development Area – ~925,000 Acres Eastern Development Area – ~320,000 Acres

Focused on Capital Efficiency & FCF Generation FY23 and FY24 is based on actual data. FY25 and FY26 data is projected until 12 months after the last pad has been online. Well data tied to FY based on first production off of pad and includes any marketing or operational curtailments. A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation. FY23 E&P capex reflects the netting of $150 million related to acquisition of upstream assets and acreage from total capital expenditures for E&P of $738 million. FY24 E&P capex reflects the netting of $6 million related to the acquisition of assets from UGI from E&P capex of $536 million. Development Program Driving 30% Improvement in Capital Efficiency (Since FY23) % EDA TILs ~50% ~60% ~80% ~100% ~85% Strong Capital Efficiency Improvements +20% -18% Productivity Increasing Significantly Seneca Capital Expenditures ($ MM)(2) Seneca Net Production (Bcfe)

Well Design Changes Improving Tioga Utica Performance Gen 3 design primarily uses 1,800 ft. inter-well spacing, 2,200 lbs. per ft. of proppant intensity, and 150 ft. stage spacing. +80% (1) ~25% Improvement

Decades of High-Quality Inventory at Industry Leading Breakevens Assumes an average of 20 to 30 wells brought online/year, which is equivalent to current pace. Enverus research is at $2.50 breakevens. Peers include EQT, RRC, AR, GPOR, Ascent, CNX, EXE. Enverus Analysis Validates Inventory Depth (1) EDA WDA Seneca Analysis: >10 Years of Inventory @ <$2.00 Breakevens

Power Gen Data Center Integrated assets uniquely situated to meet the needs of power and data center development NFG is a Preferred Partner for Growing Electricity Demand Capability to provide reliable and redundant gas supply Ability to build interconnects and laterals to serve end user demand Long-term Gas Supply Agreement Core Skill Set In Developing Gathering Infrastructure Pipeline Expansion, Interconnection, Storage & Firm Transport ESG Focus Land rights/ownership Extensive pipeline connectivity Proximity to electric grid / fiber networks Substantial water access Large project management expertise Investment grade balance sheet Decades of natural gas supply Sustainability track record

Shippingport Lateral Project Supports Data Center Development Pipeline & Storage Capacity: Initially 205,000 Dth/day with potential to increase significantly Estimated capital cost: $57 million Estimated annual revenue: $15 million Facilities: approximately 7.5 miles of new 24-inch pipeline Target in-service date: late calendar year 2026 Regulatory process: FERC blanket prior notice application expected fall 2025 NFG Supply Line N Lateral Shippingport, PA Texas Eastern Pipeline Recently Announced Project will Support the Repowering of a 3.6 GW Power Generation Facility and Co-located Data Center

Supplemental Information

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

Long Runway of Development Opportunities in the EDA Utica Development >10 years of inventory with an expected PV-10% breakeven price of less than $2.00/MMBbtu NYMEX Tioga County, PA Low-risk development locations: ~200 Utica, ~70 Marcellus Utica average total lateral length (TLL) of ~13k feet (~$1,250–$1,300 / ft) Marcellus average total lateral length (TTL) of ~10k feet (~$900–$1,000 / ft) Firm Transportation: Empire Tioga County Extension (NFG - Empire), Leidy South (NFG - Supply, Transco), Northeast Supply Diversification (TGP), Tioga Pathway (2026E in-service date, NFG - Supply) Lycoming County, PA Low-risk development locations: ~20 Marcellus Average total lateral length (TLL) of ~8k feet ($1,075 - $1,125 / ft) Firm transportation: Atlantic Sunrise (Transco) Upstream Development Program E&P and Gathering Tioga County delivery point capacity up to 1,220,000 Dth per day Lycoming County delivery point capacity up to 585,000 Dth per day Gathering System Capacity Marcellus Development

High Quality Acreage in WDA, Primarily Owned in Fee ~10 years of fully delineated inventory in the Utica and Marcellus plus significant additional future development potential with expected PV-10% breakeven price of less than $2.25/MMBtu NYMEX Large gathering system with multiple interconnects provides access to firm transportation portfolio that reaches premium markets Highly contiguous fee acreage (no royalty) enhances well economics in the Utica with average TLLs of 13k / ft at ~$1,050-$1,100 / ft, providing development flexibility Beechwood area results provide long-term development optionality Western Development Area (WDA) Highlights Marcellus & Utica Development Area(1) (1) The Utica Shale lies approximately 5,000 feet beneath Seneca’s WDA Marcellus acreage. Minimal gathering pipelines and compression investment required to support Seneca’s near-term development program Seneca production source, delivery point capacity up to 750K Dth/d E&P and Gathering Marcellus Development Utica Development WDA Gathering Gathering System Map

E&P and Gathering Production Supported by Long-Term Contracts ~1 Bcf/d of Firm Transportation(1) Gulf Coast Capacity 50 MDth/d (WDA) Firm Sales Portfolio Gross Volumes MDth/d FY 2025 to 2026 NE Supply Diversification (TGP) 50 MDth/d (Canada-Dawn) (EDA-Tioga) Niagara Expansion (TGP & NFG - Supply) Canada-Dawn & TGP 200 170 MDth/d (WDA) Atlantic Sunrise (Transco) Mid-Atlantic & Southeast U.S. 189 MDth/d (EDA-Lycoming) In-Basin Firm Sales(2) Will continue to layer-in firm sales deals to reduce in-basin spot exposure Leidy South (Transco & NFG - Supply) Transco Zone 6 Non-NY 330 MDth/d *Capacity can be utilized by all three producing areas (WDA, EDA-Tioga, and EDA-Lycoming) Tioga County Extension (NFG - Empire) Canada-Dawn & NY Markets 200 MDth/d (EDA Tioga) Northern Markets (43% of total) Mid-Atlantic, SE US (19% of total) NY, NJ, Northeast (33% of total) Gulf Coast (5% of total) Percentages in chart indicate % of firm transportation volumes as of April 2026 when Gulf Coast capacity comes online. 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 transportation costs.

Q4 Volumes: Fixed Price 22 Bcfe, NYMEX-Linked 69 Bcfe, Index 3 Bcfe. Floor protection defined as volumes where a floor price is locked in through a NYMEX-linked firm sale paired with a NYMEX collar. The average realized price, which includes differentials of ~($0.76) is a $2.60 floor and $3.65 cap. 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. Fiscal 2025 Sales Mix Provides Near-Term Price Certainty E&P and Gathering ($0.95) ($0.76) $2.53 Firm Sales & Production Cadence(1) 98 Bcfe 106 Bcfe 420 to 425 Bcfe Price Certainty(3) 64 Bcfe $2.64 Realized Floor Protection(2) 19 Bcfe $3.36 Floor Spot 14 Bcfe $(0.75) Diff Price Realizations with Hedging (Net Bcfe, $ per MMBtu) Unhedged Firm Sales 12 Bcfe $(0.81) Diff 112 Bcfe 315 Bcfe $2.73 Realized

Price Realizations with Hedging (Net Bcfe, $ per MMBtu) Fiscal 2026 Sales Mix Provides Near-Term Price Certainty E&P and Gathering ($0.86) ($0.86) ($0.82) ($0.82) $2.48 $2.48 Firm Sales & Production Cadence(1) 440 to 455 Bcfe Price Certainty(3) 188 Bcfe $2.86 Realized Floor Protection(2) 96 Bcfe $3.57 Floor Spot 77 Bcfe $(0.90) Diff Unhedged Firm Sales 87 Bcfe $(0.83) Diff ($0.78) ($0.76) ($0.81) ($0.83) $2.46 $2.42 Q1 Volumes: Fixed Price 20 Bcfe, NYMEX-Linked 67 Bcfe, Index 7 Bcfe. Q2 Volumes: Fixed Price 19 Bcfe, NYMEX-Linked 61 Bcfe, Index 10 Bcfe. Q3 Volumes: Fixed Price 19 Bcfe, NYMEX-Linked 49 Bcfe, Index 25 Bcfe. Q4 Volumes: Fixed Price 20 Bcfe, NYMEX-Linked 50 Bcfe, Index 25 Bcfe. NYMEX-Linked and Index prices are shown as differentials to NYMEX and $ per MMBtu. Floor protection defined as volumes where a floor price is locked in through a NYMEX-linked firm sale paired with a NYMEX collar. The average realized price, which includes differentials of ~($0.82) is a $2.76 floor and $4.00 cap. 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.

…Collars and Unhedged Production Provide Upside Capture Opportunities Hedging Program: Disciplined with Upside Potential E&P and Gathering FY25 estimated hedge percentage shown for the remaining 3 months and assumes ~423 Bcf of production for the year with the remaining years at mid-single digit growth. Methodical Approach to Layering in Hedges Over Time Supports Investment Grade Credit Rating Swaps and Fixed Price Sales Provide Price Certainty(1)… Upside with Collars Swaps and Fixed Price Sales Provide Price Certainty(1)… ~25% ~35% ~55%- 60% ~80%- 85% ~95%- 100% ~20% ~60% ~15% ~45%

Integration Drives Industry Leading Cost Structure Seneca Cash OpEx ($/Mcfe) G&A estimate represents the midpoint of the G&A guidance ranges for fiscal 2025 and 2026. The total of the two LOE components represents the midpoint of the LOE guidance ranges for fiscal 2025 and 2026. (2) E&P and Gathering (2) Seneca + Gathering Cash OpEx ($/Mcfe) $0.45 Reduction (1) (2) (2) (1)

Industry-Leading Focus on Sustainability E&P and Gathering Responsible Gas Certifications, Emissions Reductions & Biodiversity Equitable Origin – EO100TM Standard for Responsible Energy Development Certification (100% of natural gas production recertified in December 2024) Certification focuses on three emissions management criteria: Methane Intensity Company Practices to Manage Methane Emissions Emissions Monitoring Technology Deployment MiQ (100% of Appalachian Assets, re-certified August 2024) Encompasses the following principles: Corporate Governance, Transparency & Ethics Human Rights, Social Impacts & Community Development Indigenous People’s Rights Fair Labor & Working Conditions Climate Change, Biodiversity & Environment Emissions Reductions Achieved grade certification, the highest certification level available Biodiversity Surface Footprint Neutral Program focuses on restoring, enhancing, or protecting biodiversity by returning one acre of land to the environment for every acre disturbed Voluntary initiatives focused on pollinator and tree plantings, streambank stabilization, and enhancing aquatic wildlife Surpassed 2030 Methane Intensity Reduction Target Significant reductions in methane driven by: Natural gas pneumatic device conversions Operational best management practices for well liquids unloading and flowback Increased LDAR frequency and aerial monitoring to reduce fugitive emissions Achieved peer-leading certification: Seneca Midstream

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

Pipeline & Storage Segment Overview Firm transportation includes short-term and long-term and is disclosed annually as of September 30, 2024. Reported as of June 30, 2025. Empire Pipeline, Inc. National Fuel Gas Supply Corporation Empire Pipeline Supply Corp. Contracted Capacity(1): Firm Storage: 71 Bcf (fully subscribed) Firm Transportation: 3.5 Bcf / day Rate Base(2): ~$1.3 billion FERC Rate Proceeding Status: Rate case settled in Q2 FY24 and approved by FERC June 11, 2024 New rates went into effect February 1, 2024 Contracted Capacity(1): Firm Storage: 4 Bcf (fully subscribed) Firm Transportation: 1.1 Bcf / day Rate Base(2): ~$0.3 billion FERC Rate Proceeding Status: Settlement approved by FERC on March 17, 2025 New rates go into effect November 1, 2025 Moratorium period until April 30, 2027 Comeback required by May 31, 2031 Pipeline & Storage

Pipeline & Storage Customer Mix Customer Transportation by Shipper Type(1) Affiliated Customer Mix (Contracted Capacity) Disclosed annually as of 9/30/2024. Pipeline & Storage Firm Transport

Pipeline Modernization & Expansion Projects Propel Growth A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation. FY25E & FY26E capex is presented at mid-point of guidance. Capex Investments Support Long-Term Rate Base Growth Estimate of ~5-7% Pipeline & Storage Organic Growth Drivers Expect long-term non-expansion capex spend of ~$100-150 MM/year Expansion projects drive further growth potential, such as the Tioga Pathway and Shippingport Lateral projects (late calendar 2026) Tioga Pathway & Shippingport Lateral Project

Tioga Pathway Project Creates Organic Growth Capacity: 190,000 Dth/day Estimated capital cost: ~$100 million A portion of the capital to be allocated to modernization facilities Estimated annual revenue: ~$15 million (underpinned by 15-year agreement with Seneca) Modernization component of capital investment is expected to drive additional revenue growth in future rate case Facilities (all in Pennsylvania) include: Approximately 20 miles of new pipeline Replacement of ~4 miles of existing pipeline (with new 20” pipeline) Project Milestones: FERC Order issued May 2025 approving the project Construction expected to commence in Q1 calendar 2026 with a targeted in-service date late calendar 2026 Pipeline & Storage Long-term revenue growth for Supply, while providing an additional outlet for Seneca’s EDA development

Continued Expansion Opportunities for Supply Corp. Line N System Pipeline & Storage Additional Line N Expansion Opportunities Line N corridor is well positioned to serve growing power demand from AI and data centers Significant data centers exist today, plus more expected in the future Proximate to fiber corridor Ability to serve power generation requirements (greenfield, underutilized, or previously decommissioned power assets) Access to significant gas supply in SW PA/WV Interconnectivity of the system to other long-haul pipelines and on-system load provides on-going opportunity to transport additional volumes 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 Line N

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

New York & Pennsylvania Service Territories New York Last Rate Case: Joint Proposal approved December 19, 2024 (3-year rate plan effective Oct. 1, 2024 through Sept. 30, 2027) Total Customers(1): ~541,000 Allowed ROE: 9.7% (NYPSC Case 23-G-0627) Rate Mechanisms: Revenue Decoupling Weather Normalization Low Income Customer Discount Reconciliation Merchant Function Charge (Uncollectibles Adj.) 90/10 Sharing (Large Customers) Uncollectible Expense Tracker Pennsylvania Last Rate Case: 2023 (rates effective August 1, 2023) Total Customers(1): ~214,000 Allowed ROE: Black-box settlement (2023) - $23 MM rate increase Rate Mechanisms: Weather Normalization (added Aug. 1, 2023), subject to 3% deadband Low Income Rates Merchant Function Charge (Uncollectibles Adj.) Distribution System Improvement Charge (DSIC) Initiated recovery of eligible costs on January 1, 2025 Disclosed annually as of September 30, 2024. Utility

NY Utility Rate Case Supports Growing Earnings Outlook Three-Year Rate Settlement Approved on December 19th, 2024 Joint Proposal approved(1) on December 19, 2024: 3-year rate settlement (fiscal 2025 – 2027) with no significant modifications to the Joint Proposal filed in September New rates implemented on Jan. 1, 2025 with make-whole provision allowing full recovery over calendar 2025 of incremental revenue requirement not billed to customers between Oct. 1, 2024, and Dec. 31, 2024 Maintains modernization (pipeline replacement) program at a minimum of 105 miles per year over rate plan Recovery of system modernization costs, including higher rate base and depreciation expense, now included in new base rates (revenue requirement) Ratemaking mechanisms: Continuation of: weather normalization; revenue decoupling; industrial 90/10 symmetrical sharing; merchant function charge New: uncollectible expense tracker; gas safety and customer service performance metrics; customer bill impact levelization See Case 23-G-0627 on the NY PSC website. Rate Case Drivers Old Rates Approved (New) Rates (in millions) FY24 FY25 FY26 FY27 Revenue Requirement Cumulative Increase (relative to FY24) n/a $57.3 $73.1 $85.8 Rate Base $858 $1,044 $1,104 $1,163 Authorized ROE 8.7% 9.7% 9.7% 9.7% Authorized Equity Ratio 43% 48% 48% 48% Utility Utility

First utility in the state to submit a LTP (Long-Term Plan) NYPSC 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, and RNG pilot proposals System modernization NFG continues to receive support for accelerated and proactive investments in the replacement of leak prone pipe System modernization costs included in base rates in most recent rate case 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 NY Regulatory Environment Continues to Prioritize Access to Safe, Reliable and Affordable Energy NY Utility Regulatory Environment Utility

Customer Affordability New York Pennsylvania Based on 2024 average monthly residential bill data posted on company websites required by the NYPSC. Based on analysis of 2025 PAPUC Annual Rate Comparison Report, which includes data for average monthly residential bills for 2024. Utility #1 Out of 9 Gas Utilities(1) #1 Out of 6 Gas Utilities(2) Expect to be among the lowest in calendar 2025 as well, including rate increase

Utility Continues its Significant Investments in Safety (1) A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation. Increase from FY23 to FY24 is partially due to the impact of New York State’s Roadway Excavation Quality Assurance Act (“REQAA”) which will continue to increase investment costs in future years. Long-Standing Focus on Distribution System Safety and Reliability Utility (2)

Long-Standing Pipeline Replacement & Modernization NY 9,834 miles PA 4,852 miles Miles of Utility Main Pipeline Replaced(2) Utility Mains by Material(1) (1) All values are reported on a calendar year basis, as of December 31, 2024, as required by the DOT. (2) All values are reported on a fiscal year basis, as required by the NYPSC and PAPUC. Utility

Baseline emissions & emissions reduction targets are calculated pursuant to the reporting methodology under the EPA GHG Reporting Program (current Subpart W, and using AR5), primarily Distribution pipeline mains & services. Revisions of Subpart W emissions factors, effective for 2025 reporting, will change the reported baseline, 2025 emissions profile, and progress against these targets. New York Climate Leadership and Community Protection Act, enacted in 2019. Targets Exceed Those Included in New York State Climate Act (CLCPA)(2) Reductions Primarily Driven by Ongoing Modernization of Mains and Services Utility Targeting Substantial Emissions Reductions 2030 75% Significant Reductions in Utility GHG Emissions to Date, Driven by System Modernization Efforts GHG Reduction Targets, Continuing Focus on Lowering Carbon Footprint ~70% Reduction Since 1990 (510,000 Metric Tons CO2e) Utility GHG Emissions Reduction Targets(1) (Based on 1990 EPA Subpart W Emissions) 90% 2050 Utility

Guidance & Other Financial Information Supplemental Information

Fiscal 2026 Adjusted EPS Guidance Updated FY25 Adj. EPS Guidance $6.80 to $6.95/share(1) Preliminary FY2026 Adj. EPS Guidance 440 - 455 Bcfe Key Guidance Drivers Net Production Pipeline & Storage Utility $250 – $260 million $415 - $430 million Pipeline & Storage Revenues Tax Rate Effective Tax Rate ~25.5% LOE Expense $0.67 - $0.68/Mcf G&A Expense ~$0.18 /Mcf ~4 - 5% increase Pipeline & Storage O&M Expense Non-Regulated Regulated $245 - $255 million Gathering Revenues Gathering O&M Expense ~$0.10/ Mcf of throughput Exploration & Production Gathering Pipeline & Storage Utility DD&A Expense $0.65 - $0.69/Mcf Utility O&M Expenses Excludes items impacting comparability. See Comparable GAAP Financial Measure Slides & Reconciliations at the end of this presentation. Assumes NYMEX pricing of $3.25/MMBtu and in-basin spot pricing of $2.50/MMBtu for remaining three months of Fiscal 2025, and reflects the impact of existing financial hedges, firm sales and firm transportation contracts. Customer Margin is defined as Operating Revenues less Purchased Gas Expense. $470 - $490 million Utility Customer Margin(3) $23 – $27 million Utility Non-Service Pension / OPEB Income NYMEX Assumption EPS Sensitivities Assumed Spot Price $3.00 $6.35 - $6.85 $2.30 $4.00 $8.00 - $8.50 $3.10 $5.00 $9.75 - $10.25 $3.90

Regulated: Rate Case Overview Supply Empire NY(2) PA Regulatory Agency (Governed by) FERC FERC NYPSC PAPUC Timing / Status Settlement approved by FERC June 11, 2024 New rates went into effect February 1, 2024 No moratorium or comeback period Amendment to 2019 Settlement approved by FERC on March 17, 2025 New rates go into effect November 1, 2025 Moratorium period until April 30, 2027 Comeback required by May 31, 2031 Joint Proposal approved(2) December 2024 with no significant modifications in the settlement 3-year rate plan effective October 1, 2024, with make-whole provision Settlement approved in June 2023 Rates in effect since August 1, 2023 Rate Base(1) (in millions) $1,300 $300 $1,000 $450 Equity Ratio Not stated – Black box settlement Not stated – Black box settlement Authorized 48% Not stated – Black box settlement Authorized ROE Not Stated – Black box settlement Not Stated – Black box settlement Authorized 9.7% Not Stated – Black box settlement Pipeline & Storage Utility Estimated as of June 30, 2025. See Case 23-G-0627 on file with the NY PSC.

Hedge Portfolio & Capped Firm Sales Calculated as the weighted average NYMEX forward price for each time period shown based on the Fixed Price Physical firm sale execution date, plus basis differentials and transportation costs. 4Q 2025 1Q 2026 2Q 2026 3Q 2026 4Q 2026 FY 2027 FY 2028 Swaps Units Volume Bbtu 42,725 28,795 25,140 29,640 29,640 86,860 28,780 Wtd. Avg. Price $ / MMBtu $3.46 $3.68 $4.04 $4.05 $4.05 $3.95 $3.82 Collars Volume Bbtu 19,080 24,440 30,975 21,600 21,600 40,000 6,680 Wtd. Avg. Ceiling $ / MMBtu $4.41 $4.93 $5.04 $4.60 $4.60 $4.43 $4.28 Wtd. Avg. Floor $ / MMBtu $3.36 $3.58 $3.65 $3.51 $3.51 $3.45 $3.36 Fixed Price Physical Volume Bbtu 22,869 20,481 19,177 20,050 20,262 82,435 46,885 Wtd. Avg. Price $ / MMBtu $2.53 $2.46 $2.42 $2.48 $2.48 $2.59 $2.74 NYMEX Equiv. Price(1) $ / MMBtu $3.37 $3.47 $3.65 $3.13 $3.27 $3.58 $3.72 Capped Firm Sales Volume Bbtu 2,520 854 0 0 0 0 0 NYMEX Cap $ / MMBtu $2.92 $2.92 $2.92 $2.92 $2.92 $2.92 $2.92 Volume Bbtu 1,440 1,451 1,426 1,447 1,461 5,870 501 NYMEX Cap $ / MMBtu $4.95 $4.95 $4.95 $4.95 $4.95 $4.95 $4.95 Volume Bbtu 1,757 1,771 1,741 1,765 1,782 7,163 7,242 NYMEX Cap $ / MMBtu $7.00 $7.00 $7.00 $7.00 $7.00 $7.00 $7.00

Type Curves Demonstrate Outstanding Well Results Estimated wells Fiscal 2026 Drills 25 - 27 TILs* 25 - 27 Avg. TLL 12,500 – 13,000’ Drilling rigs 1.5 Estimated Tioga Utica Tioga Marcellus Lycoming Marcellus WDA Utica Location Count 200 70 20 250 Avg. TLL (ft) 13,000’ 10,000’ 8,000’ 13,000’ Cost / ft $1,250 - $1,300 $900 - $1,000 $1,075 - $1,125 $1,050 - $1,100 Avg. Royalty Burden 15% 15% 16% 2% *All TILs in FY26 are Tioga Utica Operational Data

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, retained natural gas and system modernization), environmental/safety requirements, affiliate relationships, industry structure, and franchise renewal; changes in economic conditions, including the imposition of additional tariffs on U.S. imports and related retaliatory tariffs, 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 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; impairments under the SEC’s full cost ceiling test for natural gas reserves; 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; the Company’s ability to complete 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, including the impact of issues that may arise from the use of artificial intelligence technologies; 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; 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; 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, 2024, and the Forms 10-Q for the quarters ended December 31, 2024, March 31, 2025, and June 30, 2025. 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.

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 or liquidity 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 and adjusted earnings per share 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 adjusted earnings per share guidance range excludes certain items that impacted the comparability of adjusted operating results during the nine months ended June 30, 2025, including: (1) the after tax impairment of assets, which reduced earnings by $1.14 per share; (2) after-tax premiums paid on early redemptions of debt, which reduced earnings by $0.02 per share; (3) after-tax unrealized losses on a derivative asset, which reduced earnings by $0.01 per share; and (4) after-tax unrealized losses on other investments, which reduced earnings by $0.02 per share. While the Company expects to record certain adjustments to unrealized gain or loss on investments during the remaining three months ending September 30, 2025, the amounts of these and other potential adjustments are not reasonably determinable at this time. As such, the Company is unable to provide earnings guidance other than on a non-GAAP basis. Management defines 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. Reconciliations of forward-looking non-GAAP financial measures and non-GAAP ratios to comparable GAAP measures are not available due to the challenges and impracticability of estimating certain items, particularly depreciation and depletion expense, interest expense, income tax expense (benefit), other potential adjustments and charges, including ceiling test impairments, and non-cash unrealized derivative fair value gains and losses that are subject to market variability. Because of those challenges, a reconciliation of forward-looking non-GAAP financial measures and non-GAAP ratios is not available without unreasonable effort.

Non-GAAP Reconciliations – Adjusted EBITDA & Net Debt

Non-GAAP Reconciliations – Adjusted EBITDA, by Segment

Non-GAAP Reconciliations – Adjusted Operating Results

Non-GAAP Reconciliations – Funds From Operations

Reconciliation – Capital Expenditures