Exhibit 99 Investor Presentation Q4 Fiscal 2022 Update November 3, 2022

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

NFG: A Diversified, Integrated Natural Gas Company Developing our large, high-quality Upstream acreage position in Marcellus & Exploration & Utica shales Production ~1.2 Million ~960 MMcf/day 54% of NFG Net acres in Net Appalachian natural (1) EBITDA (2) Appalachia gas production Expanding and modernizing pipeline Midstream infrastructure to provide outlets for Gathering Appalachian natural gas production Pipeline & Storage ~4.5 MMDth $2.4 Billion 34% of NFG 38% of NFG Daily interstate Investments (1) (1) EBITDA EBITDA pipeline capacity since 2010 under contract Providing safe, reliable and Downstream affordable service to customers in Utility WNY and NW Pa. % of NFG $788 Million 753,000 12% of NFG (1) 20EBITDA (1) Investments in safety Utility EBITDA customers since 2010 Note: This presentation includes forward-looking statements. Please review the safe harbor for forward looking statements at the end of this presentation. (1) Twelve months ended September 30, 2022. A reconciliation of Adjusted EBITDA to Net Income as presented on the Consolidated Statement of Income and Earnings Reinvested in the Business is included at the end of this presentation. 3 (2) Average net Appalachian production for the three months ended September 30, 2022.

Why National Fuel? Diversified Assets Provide Stability and Long-Term Growth Opportunities Integrated Model Enhances Shareholder Value 1 Expect to Generate Significant Free Cash Flow in Fiscal 2023 and Beyond 2 Optimization of Interstate Pipeline System Drives Future Expected Opportunities 3 Long History of Returning Capital to Shareholders 4 Focused on Corporate Responsibility and ESG 5 4

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

. . . and Continues to Drive Growth Opportunities Near Term Strategy Leverages Integration Across the Value Chain Pipeline & Exploration & Gathering Utility Storage Production ü Integrated Upstream and Midstream development of high-quality Appalachian assets § ~1.2 million net acres in the Marcellus and Utica shales § NFG’s gathering systems move Seneca’s natural gas production, driving consolidated returns § NFG’s interstate pipelines support Appalachian development and provide firm takeaway capacity ü Develop further expansion of interstate pipeline systems to satisfy natural gas supply and demand § Supply push – Appalachian producers § Demand pull – regional demand-driven projects and utilities ü Ongoing investment in safety and modernization of pipeline transportation and distribution systems § $500+ million in new investments expected over the next 5 years (1) ü Expect to generate significant consolidated free cash flow in fiscal year 2023 and beyond 6 (1) The Company defines free cash flow at the end of this presentation.

Consolidated Business Expected to Generate Significant Free Cash Flow . . . 2 . . . With Sustainable, Growing Free Cash Flow Generation . . . In Fiscal 2023. . . Expected Over the Long-Term Annualized Dividend Free Cash Flow ü Consolidated capital expenditure optimization to maximize long- $450 term free cash flow growth $400 ~$375 § Exploration & Production / Gathering: focus on enhancing $350 ~$325 returns through ongoing operating efficiencies and just-in-time build-out of supporting gathering facilities $300 ~$275 § Pipeline & Storage / Utility: current plans focus on modernizing $250 our transportation, storage, and distribution infrastructure, while leveraging existing facilities to drive further potential $200 growth opportunities $150 ü Regulated businesses expected to generate stable, predictable earnings and cash flows $100 ü Mitigation of Upstream business commodity risk through $50 consistent hedging and marketing program, while maintaining $0 upside +$0.50 -$0.50 Base Case $1.00 $2.00 $3.00 @ NYMEX Price ($/MMBtu) ü Improvement of investment grade credit profile through consistent free cash flow generation (1) Consolidated free cash flow. The Company defines free cash flow at the end of this presentation. Base case assumes current hedges and NYMEX pricing of $6.00/MMBtu for winter and $4.75/MMBtu for summer fiscal 2023. 7 (2) Assumes current hedges and commodity price assumptions for the remainder of fiscal 2022. Excludes after-tax cash net proceeds related to the sale of California properties. (1) Free Cash Flow ($ Millions)

Optimization of Interstate Pipeline Drives Future Expected Opportunities 3 ü FM100: TCPL – Canada/Dawn TGP - Hopewell § Placed into service December 2021 § ~$50 MM in Total Project-Related Revenues (Expansion & Modernization) ü Ongoing Investments in Safety, Emissions Millennium Reductions, and System Modernization: § $150-$250 MM expected over the next 5 years FM100 Delivery: Transco (Leidy)ü Well Positioned to Capitalize on Future 330,000 Dth/d Growth Opportunities: Transco - Leidy TGP – Mercer § Interconnectivity of the system to other long-haul pipelines, and proximity to producers, provides on-going opportunity to transport volumes out of the basin § Ability to optimize throughput through modest expansion projects TETCO - Holbrook 8

4 Over Half Century of Dividend Growth 52 Years 120 Years $1.90 2.9% Consecutive Dividend Increases Consecutive Payments (1) per share yield $1.4 Billion 4.4% Dividend payments over last 10 years 2022 Dividend Increase $0.19 per share Annual Rate at Fiscal Year End 9 (1) As of November 2, 2022.

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

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

Fourth Quarter and Fiscal 2022 Financial Highlights Fiscal 2023 Earnings Guidance 12

Fourth Quarter Fiscal 2022 Results and Drivers (1) Adjusted Operating Results ($/share) Q4 FY 2021 Q4 FY 2022 Major Drivers $1.19 Natural Gas Prices $2.84 $2.37 $0.95 Exploration & $0.95 Production $0.81 Exploration & Production Natural Gas Production / $0.61 87.9 76.3 Gathering Throughput Gathering Gathering $0.25 $0.20 Pipeline & Storage Pipeline & Storage $0.27 $0.23 $97.7 $85.0 FM100 Project Revenue Utility: ($0.06) Utility: ($0.12) MM MM Corporate/Other: ($0.03) Corporate/Other: ($0.02) Q4 FY21 Q4 FY22 (1) A Reconciliation of Adjusted Operating Results to Earnings Per Share is provided at the end of this presentation. 13 (2) Realized price after hedging. Pipeline and Storage Net Gas Production Natural Gas Pricing (2) Revenue ($MM) (Bcf) ($/Mcfe)

Fiscal 2022 Highlights (1) (1) Up 23% vs. FY21 Adjusted EBITDA $1.2 billion nd Grew shareholder distribution for 52 consecutive year and Dividend $1.90 per share doubled rate of annual dividend increase Up 8% vs. FY21; highest output in NFG history, Production 352.5 Bcfe despite divesting California properties Proved Reserves Up 8% vs. FY21; replaced 240% of production 4.2 Tcfe Gathering Up 15% vs FY21; highest throughput in NFG history 419 Bcfe Throughput Pipeline & Storage Up 10% vs. FY21; driven by FM100 project $377.0 Million Revenues Utility Safety Ongoing focus on pipeline replacement and modernization $82.6 Million Investments Corporate Third Annual Report & Enhanced climate-related disclosures and publication of emissions reduction targets Responsibility First Climate Report 14 (1) A reconciliation of Adjusted EBITDA to GAAP earnings is included at the end of this presentation.

Earnings Guidance FY2022 Adjusted Operating Results FY2023 Earnings Guidance (1) $5.88/share $6.40 to $6.90/share Key Guidance Drivers § 370-390 Bcfe (up 8% vs. FY22) Net Production (2) Realized natural gas prices (after-hedge)§ ~$3.05/Mcf (vs. $2.71/Mcf in FY22) Exploration & (1) G&A Expense § $0.17-$0.19/Mcf (vs. $0.20/Mcf in FY22 ) Production DD&A Expense § $0.60-$0.64/Mcf (vs. $0.59/Mcf in FY22) LOE Expense § $0.67-$0.69/Mcf (vs. $0.81/Mcf in FY22) Gathering Revenues § $230-$245 million (up 11% vs. FY22) Gathering Gathering O&M Expense § ~$0.09/Mcf of throughput Pipeline & Storage Revenues § $360-$380 million Pipeline & Storage O&M Expense § ~5% increase Pipeline & Pipeline & Storage Storage Pipeline & Storage Depreciation Expense § ~5% increase due primarily to FM100 Project Utility§ Increased operating expenses / return to normal weather Utility Utility Earnings Before Interest and Taxes § ~$3 million decrease in post retirement benefit expense Tax Rate Effective Tax Rate § ~25.5-26% (Loss of Enhanced Oil Recovery credit) (1) Excludes items impacting comparability. See Comparable GAAP Financial Measure Slides & Reconciliations at the end of this presentation. (2) Assumes NYMEX pricing of $6.00/MMBtu and in-basin spot pricing of $4.95/MMBtu for winter and $4.75/MMBtu and in-basin spot pricing of $3.55 for summer fiscal 2023, and reflects the impact of existing financial hedges, firm sales and firm transportation contracts. 15 Regulated Non-Regulated

Exploration & Production & Gathering Overview Seneca Resources Company, LLC National Fuel Gas Midstream Company, LLC 16

E&P and Gathering Growing Production within Disciplined Capital Program E&P Net Production (Bcfe) Near-Term Strategy 400 ü Continue two rig development program with focus on maximizing returns and cash flows, targeting 300 mid-to-high single digit production growth 200 370-390 352.5 327.4 § EDA share of total drilling and completion 241.5 211.8 100 178.1 activity increasing 0 2018 2019 2020 2021 2022 2023E§ Gross production growth will benefit NFG Gathering segment (1) E&P Net Capital Expenditures ($ millions) $600 ü EDA Tioga: development focused primarily on Utica (modest Marcellus activity) $500 $400 ü EDA Lycoming: activity maintains production level $525- $300 $565.8 that fully utilizes valuable Atlantic Sunrise capacity $492 $575 $200 $384 $381 $356 ü WDA: development focused on Utica Shale, with $100 return trips in Clermont-Rich Valley area $0 2018 2019 2020 2021 2022 2023E (1) A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation. FY18 reflects the netting of $17 million of up-front proceeds received from joint development partner for working interest in joint 17 development wells. FY20 reflects the netting of $286 million related to the acquisition of Appalachian upstream assets in July 2020.

E&P and Gathering Significant Appalachian Acreage Position >1,000 Economic Drilling Locations (1) at $3.50 NYMEX Prices ( ) ( ) ü Decades of highly-economic inventory (~40 wells per year at current 2-rig pace) ü Large, contiguous acreage position, driving increased capital efficiency (()) § ~50% undeveloped acreage ü Development supported by wholly-owned gathering infrastructure, enhancing returns EASTERN (1) Drilling locations with expected consolidated Exploration & Production and Gathering segments pre-tax IRR’s at 25%. 18 (2) Seneca Appalachian acreage is fee-owned, or leased from either the Pennsylvania Department of Conservation and Natural Resources or private landowners.

E&P and Gathering Eastern Development Area Seneca EDA Highlights EDA – ~270,000 Acres 1 Tioga County, PA ü ~140 Utica future development locations ü ~80 Marcellus future development locations ü Gathering infrastructure: NFG Tioga gathering systems ü Numerous marketing opportunities: § Ability to utilize Seneca’s firm transportation capacity: Empire Tioga County Extension, Leidy South and Northeast Supply Diversification 1 § Interconnections with multiple interstate pipelines: Empire, Eastern, TGP (300 Line), UGI 2 Lycoming County, PA 2 ü ~30 Marcellus future development locations ü Geneseo Shale expected to provide return trip locations ü Gathering infrastructure: NFG Midstream Trout Run ü Firm transportation capacity: Atlantic Sunrise (189 MDth/d) 19

E&P and Gathering EDA: Tioga County Development Large Contiguous Acreage Position, with Highly-Economic Utica and Marcellus Inventory Tioga Development Plan Significant Tioga County Acreage Position ü Significant additional assets acquired in mid-2020, contiguous to NFG’s existing Tioga County production and gathering operations Undeveloped Utica ü Near-term development expected to focus on acquired and DCNR Tract 007 pads Undeveloped § Utica average lateral length of 10,000-11,000’ and Marcellus consolidated well costs of $1,200-$1,300/ft (1) § Acceleration of Tioga County development increases upfront investment in upstream and gathering infrastructure § More intensive completion design results in improved performance and better expected IRRs ü Continuing to optimize consolidated upstream and gathering development plan across expanded Tioga footprint 20

E&P and Gathering Integrated Development – EDA Tioga Gathering NFG Tioga Gathering Systems Support Growing Seneca Production Current Systems In-Service Tioga County Gathering Systems Map ü Tioga Gathering System (1) § Total Investment (to date): ~$255 million § Capacity: up to 550,000 Dth per day (Interconnects with Empire, Eastern, and TGP 300) § Production Source: Seneca Resources (acquired Tioga acreage and future development) and Third-Party § NFG Covington Gathering System tie-in provides access to Eastern and Empire markets ü Covington Gathering System § Total Investment (to date): ~$50 million § Capacity: 220,000 Dth per day (Interconnect w/ TGP 300 line) § Production Source: Seneca Resources (Covington & DCNR Tract 595) ü Wellsboro Gathering System § Total Investment (to date): ~$45 million § Capacity: up to 200,000 Dth per day (Interconnect w/ TGP 300 line) § Production Source: Seneca Resources (DCNR Tract 007) 21 (1) Includes Company’s acquisition of midstream gathering assets in July 2020, in the amount of ~$223 million.

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

E&P and Gathering EDA: Lycoming County Development Marcellus Development in Lycoming County Fully Utilizes Valuable Firm Transportation ü Prolific Marcellus acreage with average EUR of 2.5-3.0 Bcf / 1,000 ft ü ~30 Marcellus future development locations § Average lateral length of 6,500-7,500’ and consolidated well costs of $1,050-$1,150/ft ü Potential for return trip Geneseo development 300 EDA - Transco Firm Contracts 250 (1) Leidy South Firm Sales 200 150 Atlantic Sunrise (Transco) FT Capacity: 189,405 Dth/d 100 Firm Sales: NYMEX/Market Indices 50 - Oct-22 Jan-23 Apr-23 Jul-23 Oct-23 23 (1) Capacity can be utilized by all three producing areas (WDA, EDA-Tioga, and EDA-Lycoming). Gross Firm Volumes (MDth/d)

E&P and Gathering Integrated Development – EDA Lycoming Gathering NFG Trout Run Gathering System Supports Seneca and Third-Party Development Current System In-Service Trout Run Gathering System Map ü Total Investment (to date): ~$275 million ü Capacity: 466,000 to 585,000 Dth per day ü Current Production Source: Seneca Resources (DCNR Tract 100 & Gamble) & Third-Party ü Interconnect: Transco (Leidy Line) Third-Party Volumes ü Gathering contracts executed, with volumes first online in November 2020 § Completed construction of new facilities, leveraging existing Trout Run system ü Expected to generate third-party revenues of $10 - $13 million for fiscal 2023 (supported by minimum volume commitments) 24

E&P and Gathering Western Development Area (1) Marcellus Core Acreage vs. Utica Trend WDA Highlights ü Large well inventory: § Marcellus Shale: 600+ well locations remaining / 200,000 acres § Utica Shale: 500+ potential locations across Utica trend (2) / evaluating extent of prospective acreage ü Fee acreage (no royalty) enhances economics and provides development flexibility ü Highly contiguous position drives best in class well costs and program efficiencies Beechwood Utica Development Area ü Long-term firm contracts provide access to premium markets and support growth Boone Mountain Utica Test Well ü Early Beechwood area results are encouraging Past Marcellus delineation tests Utica Trend (currently evaluating) ? Marcellus Core Acreage (1) The Utica Shale lies approximately 5,000 feet beneath Seneca’s WDA Marcellus acreage. 25 (2) Appraisal program currently in progress. Prior Marcellus delineation tests helped define the prospective limits of the Marcellus core acreage; planned testing in the Utica is expected to do the same.

E&P and Gathering Integrated Development – WDA Gathering System Gathering System Build-Out Tailored to Accommodate Seneca’s WDA Development Clermont Gathering System Map Current System In-Service § Capacity: 750 MMcf per day § Interconnects with TGP 300 and NFG Supply § Total Investment (to date): $370 million § 40,620 HP of compression (3 stations) Future Build-Out § Modest gathering pipeline and compression investment required to support Seneca’s Utica return-trip development § Beechwood development expected to require installation of new in-field gathering lines and incremental compression at existing centralized station. 26

E&P and Gathering WDA Firm Transportation and Sales Capacity WDA Exit Capacity Supports Production and Enhances Consolidated Returns WDA Gas Marketing Strategy WDA Contracted Firm Transport and Gross Sales Volumes (MDth/d) 500 ü Will continue to layer-in firm sales 450 deals of short and longer duration 400 on TGP 300 to reduce spot (1) WDA - TGP 300 Firm Sales exposure 350 300 ü WDA spot realizations track TGP Leidy South Firm Sales 250 Station 313 pricing, typically 15¢ - *Capacity can be utilized by all three producing areas (WDA, EDA-Tioga, and EDA-Lycoming) 20¢ better than TGP Marcellus 200 Zone 4 150 100 Niagara Expansion Project (TGP and NFG) ü Leidy South provides additional NYMEX & Dawn 50 capacity to premium markets 158,000 Dth/d (Transco Zone 6 NNY) - Oct-22 Jan-23 Apr-23 Jul-23 Oct-23 27 (1) Includes physical fixed price and NYMEX-based firm sales contracts that do not carry any additional transportation costs.

E&P and Gathering Long-term Contracts Supporting Appalachian Production Seneca Appalachia Natural Gas Marketing Firm Contract / Transport Volumes (MDth/day) 1,200 (1) Firm Sales Contracts 1,000 Leidy South (Transco & NFG - Supply) Transco Zone 6 Non-NY 800 330,000 Dth/d *Capacity can be utilized by all three producing areas (WDA, EDA-Tioga, and EDA-Lycoming) 600 Tioga County Extension (NFG - Empire) Canada-Dawn & NY Markets 185,000 - 200,000 Dth/d 400 Atlantic Sunrise (Transco) Mid-Atlantic & Southeast U.S. 189,405 Dth/d 200 Niagara Expansion (TGP & NFG - Supply) Canada-Dawn & TGP 200 158,000 Dth/d Northeast Supply Diversification (TGP) 50,000 Dth/d (Canada-Dawn) - Oct-22 Jan-23 Apr-23 Jul-23 Oct-23 28 (1) Represents base firm sales contracts not tied to firm transportation capacity. Base firm sales are either fixed priced or priced at an index (e.g., NYMEX ) +/- a fixed basis and do not carry any transportation costs.

E&P and Gathering Near-term Firm Sales Provide Market & Price Certainty Net Contracted Firm Sales / Transport Volumes (Dth per day) (1) Contracted Index Price Differentials ($ per Dth) NYMEX Dawn Other Capped Fixed Price 35,100 ($0.77) 988,600 2,800 ($0.72) 983,400 948,200 4,300 ($0.72) 915,800 905,000 179,000 178,000 200,700 $2.30 $2.30 226,900 219,100 $2.44 (3) (3) 43,500 43,200 (3) $2.53 $2.56 (3) 46,400 (2) 177,300 176,700 (3) (3) (2) (2) 42,000 118,400 56,900 ($1.23) ($1.23) (2) (2) ($0.73) 69,000 $1.28 50,500 $0.07 66,500 ($0.77) 66,700 ($0.77) 575,700 573,600 547,600 519,000 522,100 ($0.69) ($0.67) ($0.68) ($0.68) ($0.68) Q1 FY23 Q2 FY23 Q3 FY23 Q4 FY23 FY23 (Avg.) Gross Firm Sales Volumes (Dth per day) 1,133,400 1,092,100 1,047,600 1,053,900 1,133,400 (1) Values shown represent the weighted average fixed price or weighted average differential relative to NYMEX (netback price), and are net of any associated transportation costs. Transportation costs include minor variable components such as the Canadian exchange rate and fuel components. With respect to “Other”, the weighted average differential relative to NYMEX (netback price) includes net contracted firm sales at various indices, which are to subject to fluctuations in the market, such as seasonal demand swings, and is calculated using forward basis at various associated locations as specified by the underlying contract. (2) “Other” volumes included in fiscal 2023, are primarily DOM, TGP 200 and Transco Zone 6 Non-NY markets, with the balance to other Transco markets. 29 (3) Refer to NYMEX Capped Firm Sales Additional Detail on appendix slide 53.

E&P and Gathering Fiscal 2023 Production Profile 335 Bcf of Appalachian Production Protected by Firm Sales (1) § 185 Bcf locked-in realizing ~$2.31/Mcf , net of transportation (2) § 69 Bcf of no-cost collars with $3.20/Mcf floor (3) § 81 Bcf of additional firm sales 400 370-390 Bcfe ~45 Bcfe 350 Spot production 300 ~81 Bcfe assumed to be sold at ~$4.95 for winter and 250 ~$3.55 for summer FY23 ~69 Bcfe 200 150 100 ~185 Bcfe 50 0 Price Certainty Floor Protection Unhedged Firm Sales Spot Sales Total Seneca (1) Average realized price reflects uplift from financial hedges less fixed differentials under firm sales contracts and any firm transportation costs. (2) Average weighted floor price (average weighted ceiling price of $3.75/Mcf). (3) Includes ~65 Bcf of firm sales with fixed index differentials, as well as production with associated firm transport volumes, but not backed by a matching financial hedge. Also includes ~16 Bcf of firm sales with caps tied to NYMEX prices. 30 See NYMEX Capped Firm Sales Additional Detail on appendix slide 53. Production (Bcfe)

E&P and Gathering Continued Decrease in E&P Operating Costs Increased Scale and Highly-Contiguous Operations Expected to Drive Lower Cash Unit Costs Seneca Cash OpEx ($/Mcfe) Operating $1.40 $1.32 results excluding California operations $0.14 $1.22 $0.14 $1.14 $0.12 $0.34 $0.11 $0.97 $0.30ü Fees Paid to NFG’s Gathering ~$0.94 $0.26 $0.21 Segment Comprise ~90% of $0.11 $0.08 (1) Expected Gathering & $0.18 $0.18 (2) $0.38 $0.32 $0.28 Transport LOE $0.25 (2) $0.10 $0.10 (3) (2) (2) $0.58 $0.58 $0.57 $0.57 $0.56 $0.54 FY 2018 FY 2019 FY 2020 FY 2021 FY 2022 FY 2023E LOE (Gathering & Transport) LOE (Other) G&A Taxes & Other (1) G&A estimate represents the midpoint of the G&A guidance ranges for fiscal 2023. 31 (2) The total of the two LOE components represents the midpoint of the LOE guidance ranges for fiscal 2023. FY20 Seneca LOE was $0.84/Mcfe (vs. total shown of $0.85) due to rounding.

E&P and Gathering Sustainability Initiatives – Independently Certified Gas Responsible Gas Certifications Equitable Origin MiQ (100% of Appalachian Assets - Certified December 2021) (100% of Appalachian Assets - Certified August 2022) Certification focuses on three emissions management criteria: Certification focuses on five key principles: ü Methane Intensity ü Social Impacts ü Company Practices to Manage Methane Emissions ü Human Rights/Community Engagement ü Emissions Monitoring Technology Deployment ü Indigenous Peoples’ Rights ü Occupational Health & Safety/Fair Labor Standards ü Environmental Impacts/Biodiversity/Climate Change TrustWell by Project Canary (~300 MMcf/d - Certified March 2022) ü Certification focuses on four key areas: Seneca § Air § Water § Land § Community ü Continuous Emissions Monitoring Technology installed November 2021 32

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

Pipeline & Storage Pipeline & Storage Segment Overview National Fuel Gas Supply Corporation (1) ü Contracted Capacity : § Firm Transportation: 3,284 MDth per day § Firm Storage: 70,693 MDth (fully subscribed) (2) ü Rate Base : ~$1,173 million Empire Pipeline ü FERC Rate Proceeding Status: § 2020 settlement rates effective February 2020 § Period 2 rates went into effect April 2022 Supply Corp. (3) § Permitted to file for new rates as soon as July 31, 2023 Empire Pipeline, Inc. (1) ü Contracted Capacity : § Firm Transportation: 964 MDth per day § Firm Storage: 3,753 MDth (fully subscribed) (2) ü Rate Base : ~$341 million ü FERC Rate Proceeding Status: § 2019 settlement rates effective January 2019 (4) § No moratorium on filing for new rates (1) As of September 30, 2021 as disclosed in the Company’s fiscal 2021 Form 10-K. (2) As of December 31, 2021 calculated from National Fuel Gas Supply Corporation’s and Empire Pipeline, Inc.’s 2021 FERC Form-2 reports, respectively. (3) Supply Corporation must file for new rates no later than July 31, 2024. 34 (4) Empire must file for new rates no later than May 31, 2025.

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

Pipeline & Storage Continued Expansion of the Supply Corp. Line N System Recent Expansion of Line N ü Over the past three years, the company has successfully placed TGP 219 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 Commenced open season to expand ability to move gas from Holbrook to several markets, including Rover and Tennessee system at Mercer Omnis Bailey Interconnect § Precedent agreements in negotiations Holbrook 36

Pipeline & Storage Northern Access Project Delivery points: ü 350,000 Dth/d to Chippawa (TCPL interconnect) ü 140,000 Dth/d to East Aurora (TGP 200 line) Regulatory/legal status: To Dawn ü Feb. 2017 – FERC 7(c) certificate issued ü Aug. 2018 – FERC issued Order finding that NY DEC waived water quality certification (WQC) ü April 2019 – FERC denied rehearing of WQC waiver order (upholding waiver finding) ü March 2021 – U.S. Second Circuit Court of Appeals dismissed appeal of FERC waiver orders ü June 2022 – FERC granted extension of certificate until December 31, 2024 37

Pipeline & Storage Pipeline & Storage Customer Mix (1) Customer Transportation by Shipper Type Affiliated Customer Mix (Contracted Capacity) Outside Affiliated Non-Affiliated Pipeline 9% End User 8% 26% 52% Producer Marketer 7% 36% 84% 74% LDC 48% 40% 16% LDCs Producers Firm Storage Firm Transport 38 (1) Contracted as of 9/30/2021.

Utility Overview National Fuel Gas Distribution Corporation 39

Utility New York & Pennsylvania Service Territories New York (1) Total Customers : 539,000 (2) ROE: 8.7% (NY PSC Rate Case Order, April 2017) Rate Mechanisms: o Revenue Decoupling o Weather Normalization o Low Income Rates o Merchant Function Charge (Uncollectibles Adj.) o 90/10 Sharing (Large Customers) (3) o System Modernization Tracker Pennsylvania (1) Total Customers : 214,000 ROE: Black Box Settlement (2007) Rate Mechanisms: o Low Income Rates o Merchant Function Charge Filed a request on October 28, 2022 for a new rate case (1) As of September 30, 2021. (2) Earnings sharing under Rate Case Order started April 1, 2018 (50/50 sharing starts at ROE in excess of 9.2%). 40 (3) Applied to new plant placed in service through March 31, 2023.

Utility Pennsylvania Rate Case On October 28, 2022, National Fuel Gas Distribution Corporation filed a request with the Pennsylvania Public Utility Commission (PA PUC) to amend its tariff and increase its base rates. National Fuel’s base rates have not changed since the last base rate case reached settlement in 2007. ü Base Rate Increase = $28.1 million (excluding EE pilot program Rider) § 9.2% increase in total revenues Proposed Base § 24.4% increase in base delivery revenues Revenue Increase ü New rates expected to be effective August 1, 2023 ü Capital Structure and Returns: § Capital Structure = 45.1% debt / 54.9% equity § Return on Equity = 11.2% (10.95% + 0.25% management performance adj.) § Total Rate of Return = 8.53% ü Increasing rate base and depreciation expense associated with higher plant in-service Key Drivers § NFGDC PA plans to accelerate pipeline replacement from ~40 miles in 2022 to 52 miles in 2024 ü O&M expense inflation (e.g., labor and benefits) ü Seeking Weather Normalization Adjustment (WNA) mechanism ü Proposed Residential Energy Efficiency pilot program (+$1.2 million per year) 41

Utility Utility Continues its Significant Investments in Safety Long-Standing Focus on Distribution System Safety and Reliability $140.0 (1) Capital Expenditures for Safety Total Capital Expenditures $110-$130 $111.0 $120.0 $100.8 $95.8 $94.3 $100.0 $85.6 $82.6 $80.9 $79.7 $74.1 $71.4 $80.0 $69.9 $63.6 $60.0 $40.0 Modernization Spending in NY Expected to Add $3 MM - $4 MM in Gross Margin in FY 2023 $20.0 $0.0 2017 2018 2019 2020 2021 2022 2023E Fiscal Year 42 (1) A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation. Utility Capital Expenditures ($ millions)

Utility Long-Standing Pipeline Replacement & Modernization (1) Utility Mains by Material Miles of Utility Main Pipeline Replaced Wrought Iron 159 158 156 154 Coated Bare 144 Cast Iron NY 9,782 miles Plastic Wrought Iron Bare Coated PA* 4,850 miles Plastic 2017 2018 2019 2020 2021 Calendar Year * No Cast Iron Mains in Pa.* 43 (1) All values are reported on a calendar year basis as of December 31, 2021.

Utility Utility Targeting Substantial Emissions Reductions Significant Reductions in Utility GHG Emissions to Date, GHG Reduction Targets, Continuing Focus on Lowering Driven by System Modernization Efforts Carbon Footprint (1) (1) Utility GHG Emissions Reduction Targets Utility Mains & Services Emissions (Based on 1990 EPA Subpart W Emissions) (Thousand Metric Tons, CO e) 2 800 2030 2050 700 600 500 75% 90% 400 300 ü Targets Exceed Those Included in New York 200 (2) State Climate Act (CLCPA) 100 ü Reductions Primarily Driven by Ongoing 0 Modernization of Mains and Services 1990 1995 2000 2005 2010 2015 2020 (1) Baseline emissions & emissions reduction targets are calculated pursuant to the reporting methodology under the EPA GHG Reporting Program (current Subpart W, and using AR5), primarily Distribution pipeline mains & services. 44 (2) New York Climate Leadership and Community Protection Act, enacted in 2019.

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

Consolidated Financial Overview Upstream I Midstream I Downstream 46

Diversified, Balanced Earnings and Cash Flows (1) (2) Adjusted Operating Results ($ per share) Adjusted EBITDA ($ millions) $1,400 $8.00 $1,226 $6.40 to $6.90 $1,200 $7.00 $1,000 $5.88 $6.00 $1,000 $656 $5.00 $4.29 $800 E&P $465 $3.21 $4.00 $600 $1.83 $3.00 $177 $159 $400 $1.01 $0.88 Gathering $2.00 $241 $219 Pipeline & $1.11 $1.01 $200 $1.00 Storage $171 $163 $0.59 $0.59 Utility $0.00 $0 FY 2021 FY 2022 FY 2023 FY 2021 FY 2022 Guidance (1) Excludes items impacting comparability. See Comparable GAAP Financial Measure Slides & Reconciliations at the end of this presentation. 47 (2) Consolidated Adjusted EBITDA includes Corporate & All Other. A reconciliation of Adjusted EBITDA to Net Income, by segment, as presented on the Consolidated Statement of Income and Earnings Reinvested in the Business is included at the end of this presentation.

Disciplined, Flexible Capital Allocation (1) Capital Expenditures by Segment ($ millions) (2) (3) $1,000 Exploration & Production Gathering Pipeline & Storage Utility $830-$940 $829 $781 $770 $719 $750 $583 $525-$575 $381 $566 $492 $384 $500 $356 $35 $74 $85-$105 $50 $250 $56 $252 $48 $110-$130 $167 $143 $96 $93 $110-$130 $111 $101 $96 $94 $86 $0 2018 2019 2020 2021 2022 2023E Fiscal Year (1) Total Capital Expenditures include Corporate and All Other. A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation. (2) FY18 reflects the netting of $17 million of up-front proceeds received from joint development partner for working interest in joint development wells, and $21 million in intercompany asset transfers. FY20 reflects the netting of $286 million related to the acquisition of Appalachian upstream assets in July 2020. 48 (3) FY20 reflects the netting of $224 million related to the acquisition of Appalachian gathering assets in July 2020.

Maintaining Strong Balance Sheet & Liquidity (1) Net Debt / Adjusted EBITDA Capitalization Expect Excluding AOCI, 3.08 x further Equity as percentage 2.72 x 2.61 x reduction in of Total 2.45 x 2.47 x Equity Total FY23 2.22 x Capitalization would (2) 44% Debt be 50% 56% 2017 2018 2019 2020 2021 2022 2023E $4.8 Billion Total Capitalization Fiscal Year (3) as of September 30, 2022 Debt Maturity Profile by Fiscal Year ($MM) Liquidity Expect to repay maturities with cash and short-term borrowings $ 1,000 MM Committed Credit Facilities $600 $549 $500 $500 $500 364-Day Delayed Draw Term Loan 250 MM $400 $300 $300 (60 MM) Short-term Debt Outstanding 1,190 MM Available Short-term Credit Facilities $200 46 MM Cash Balance at 9/30/22 $0 $ 1,236 MM Total Liquidity at 9/30/22 (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) Includes impact of Accumulated Other Comprehensive Loss of $626 MM as of September 30, 2022. 49 (3) Total capitalization as presented here includes $609 MM of notes payable to banks and commercial paper and current portion of long-term debt, in addition to $4.2 B of Total Capitalization as presented on the balance sheet as of September 30, 2022.

Appendix 50

Appendix Safe Harbor For Forward Looking Statements This presentation may contain “forward-looking statements” as defined by the Private Securities Litigation Reform Act of 1995, including statements regarding future prospects, plans, objectives, goals, projections, estimates of gas quantities, strategies, future events or performance and underlying assumptions, capital structure, anticipated capital expenditures, completion of construction projects, projections for pension and other post-retirement benefit obligations, impacts of the adoption of new accounting rules, and possible outcomes of litigation or regulatory proceedings, as well as statements that are identified by the use of the words “anticipates,” “estimates,” “expects,” “forecasts,” “intends,” “plans,” “predicts,” “projects,” “believes,” “seeks,” “will,” “may,” and similar expressions. Forward-looking statements involve risks and uncertainties which could cause actual results or outcomes to differ materially from those expressed in the forward-looking statements. The Company’s expectations, beliefs and projections are expressed in good faith and are believed by the Company to have a reasonable basis, but there can be no assurance that management’s expectations, beliefs or projections will result or be achieved or accomplished. In addition to other factors, the following are important factors that could cause actual results to differ materially from those discussed in the forward-looking statements: changes in laws, regulations or judicial interpretations to which the Company is subject, including those involving derivatives, taxes, safety, employment, climate change, other environmental matters, real property, and exploration and production activities such as hydraulic fracturing; governmental/regulatory actions, initiatives and proceedings, including those involving rate cases (which address, among other things, target rates of return, rate design and retained natural gas and system modernization), environmental/safety requirements, affiliate relationships, industry structure, and franchise renewal; the Company’s ability to estimate accurately the time and resources necessary to meet emissions targets; governmental/regulatory actions and/or market pressures to reduce or eliminate reliance on natural gas; changes in economic conditions, including inflationary pressures, supply chain issues, liquidity challenges, and global, national or regional recessions, and their effect on the demand for, and customers’ ability to pay for, the Company’s products and services; changes in the price of natural gas; the creditworthiness or performance of the Company’s key suppliers, customers and counterparties; financial and economic conditions, including the availability of credit, and occurrences affecting the Company’s ability to obtain financing on acceptable terms for working capital, capital expenditures and other investments, including any downgrades in the Company’s credit ratings and changes in interest rates and other capital market conditions; impairments under the SEC’s full cost ceiling test for natural gas reserves; increased costs or delays or changes in plans with respect to Company projects or related projects of other companies, as well as difficulties or delays in obtaining necessary governmental approvals, permits or orders or in obtaining the cooperation of interconnecting facility operators; the Company’s ability to complete planned strategic transactions; the Company’s ability to successfully integrate acquired assets and achieve expected cost synergies; changes in price differentials between similar quantities of natural gas sold at different geographic locations, and the effect of such changes on commodity production, revenues and demand for pipeline transportation capacity to or from such locations; the impact of information technology disruptions, cybersecurity or data security breaches; factors affecting the Company’s ability to successfully identify, drill for and produce economically viable natural gas reserves, including among others geology, lease availability and costs, title disputes, weather conditions, shortages, delays or unavailability of equipment and services required in drilling operations, insufficient gathering, processing and transportation capacity, the need to obtain governmental approvals and permits, and compliance with environmental laws and regulations; increasing health care costs and the resulting effect on health insurance premiums and on the obligation to provide other post-retirement benefits; other changes in price differentials between similar quantities of natural gas having different quality, heating value, hydrocarbon mix or delivery date; the cost and effects of legal and administrative claims against the Company or activist shareholder campaigns to effect changes at the Company; negotiations with the collective bargaining units representing the Company's workforce, including potential work stoppages during negotiations; uncertainty of gas reserve estimates; significant differences between the Company’s projected and actual production levels for natural gas; changes in demographic patterns and weather conditions (including those related to climate change); changes in the availability, price or accounting treatment of derivative financial instruments; changes in laws, actuarial assumptions, the interest rate environment and the return on plan/trust assets related to the Company’s pension and other post-retirement benefits, which can affect future funding obligations and costs and plan liabilities; economic disruptions or uninsured losses resulting from major accidents, fires, severe weather, natural disasters, terrorist activities or acts of war, as well as economic and operational disruptions due to third-party outages; significant differences between the Company’s projected and actual capital expenditures and operating expenses; or increasing costs of insurance, changes in coverage and the ability to obtain insurance. Forward-looking statements include estimates of gas quantities. Proved gas reserves are those quantities of gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible under existing economic conditions, operating methods and government regulations. Other estimates of gas quantities, including estimates of probable reserves, possible reserves, and resource potential, are by their nature more speculative than estimates of proved reserves. Accordingly, estimates other than proved reserves are subject to substantially greater risk of being actually realized. Investors are urged to consider closely the disclosure in our Form 10-K available at www.nationalfuel.com. You can also obtain this form on the SEC’s website at www.sec.gov. For a discussion of the risks set forth above and other factors that could cause actual results to differ materially from results referred to in the forward-looking statements, see “Risk Factors” in the Company’s Form 10-K for the fiscal year ended September 30, 2021 and the Forms 10-Q for the quarter ended December 31, 2021, March 31, 2022 and June 30, 2022. The Company disclaims any obligation to update any forward- looking statements to reflect events or circumstances after the date thereof or to reflect the occurrence of unanticipated events. 51

Appendix Hedge Positions and Prices 52 (1) Fixed price physical sales exclude joint development partner’s share of fixed price contract WDA volumes as specified under the joint development agreement.

Appendix NYMEX Capped Firm Sales Additional Detail Capped Firm Sales - Net Contracted Volumes (Dth/d) NYMEX Cap Q1 FY23 Q2 FY23 Q3 FY23 Q4 FY23 FY23 Avg $2.92 25,200 25,200 25,900 26,100 25,600 $3.00 14,900 0 0 0 3,700 $3.00 capped firm sales expired 10/31/22 $4.95 16,800 16,800 17,300 17,400 17,100 Total 56,900 42,000 43,200 43,500 46,400 (1) Capped Firm Sales - Weighted Average Index Price Differentials ($/Dth) Q1 FY23 Q2 FY23 Q3 FY23 Q4 FY23 FY23 Avg NYMEX Price (56,900) (42,000) (43,200) (43,500) (46,400) $3.00 ($0.65) ($0.59) ($0.59) ($0.59) ($0.61) $3.50 ($1.00) ($0.89) ($0.89) ($0.89) ($0.93) $4.00 ($1.35) ($1.19) ($1.19) ($1.19) ($1.24) $4.50 ($1.70) ($1.49) ($1.49) ($1.49) ($1.56) $5.00 ($2.07) ($1.81) ($1.81) ($1.81) ($1.89) $5.50 ($2.57) ($2.31) ($2.31) ($2.31) ($2.39) $6.00 ($3.07) ($2.81) ($2.81) ($2.81) ($2.89) $6.50 ($3.57) ($3.31) ($3.31) ($3.31) ($3.39) $7.00 ($4.07) ($3.81) ($3.81) ($3.81) ($3.89) $7.50 ($4.57) ($4.31) ($4.31) ($4.31) ($4.39) $8.00 ($5.07) ($4.81) ($4.81) ($4.81) ($4.89) $8.50 ($5.57) ($5.31) ($5.31) ($5.31) ($5.39) (1) Values shown represent the weighted average differential relative to NYMEX (netback price) and are net of any associated transportation costs. Transportation costs include minor variable components such as the Canadian exchange rate and fuel 53 components.

Appendix Firm Transportation Commitments Volume Delivery Demand Charges Production Source Gas Marketing Strategy (Dth/d) Market ($/Dth) Northeast Supply Canada Firm Sales Contracts rd EDA – Tioga 50,000 $0.46 (3 party) Diversification (Dawn) Dawn/NYMEX Tennessee Gas Pipeline NFG pipelines - $0.24 158,000 Canada (Dawn) rd Niagara Expansion 3 party - $0.40 Firm Sales Contracts WDA – CRV TGP & NFG - Supply Dawn/NYMEX 12,000 TGP 200 (PA) $0.14 (NFG pipelines) Atlantic Sunrise Mid-Atlantic/ Firm Sales Contracts rd EDA - Lycoming 189,405 $0.73 (3 party) WMB - Transco Southeast NYMEX/Market Indices TGP 200 (NY) / Tioga County Extension Firm Sales Contracts 200,000 $0.23 (NFG pipelines) EDA – Tioga Canada (Dawn) NFG - Empire TGP 200 (PA)/NYMEX rd (1) Eastern EDA – Tioga 100,000 In-Basin $0.23 (3 Party) Capacity release WDA – CRV Transco Zone Firm Sales Contracts Leidy South / FM100 rd 330,000 $0.66 (3 Party) WMB – Transco; NFG - Supply EDA - Lycoming 6 NNY Transco Zone 6 NNY/NYMEX NFG pipelines - $0.50 Canada (Dawn) Seneca to pursue firm sales 350,000 rd 3 party - $0.19 Northern Access WDA – CRV contracts as project development NFG – Supply and Empire TGP 200 (NY) 140,000 $0.38 (NFG pipelines) progresses 54 (1) Expected reduction in rates upon approved settlement of recent FERC Rate Proceeding. Currently In-Service

Appendix Comparable GAAP Financial Measure Slides & Reconciliations This presentation contains certain non-GAAP financial measures. For pages that contain non-GAAP financial measures, pages containing the most directly comparable GAAP financial measures and reconciliations are provided in the slides that follow. The Company believes that its non-GAAP financial measures are useful to investors because they provide an alternative method for assessing the Company’s ongoing operating results and for comparing the Company’s financial performance to other companies. The Company’s management uses these non-GAAP financial measures for the same purpose, and for planning and forecasting purposes. The presentation of non-GAAP financial measures is not meant to be a substitute for financial measures prepared in accordance with GAAP. Management defines Adjusted Operating Results as reported GAAP earnings before items impacting comparability. Management defines Adjusted EBITDA as reported GAAP earnings before the following items: interest expense, income taxes, depreciation, depletion and amortization, other income and deductions, impairments, and other items reflected in operating income that impact comparability. Management defines Free Cash Flow as Funds from Operations (Net Cash Provided by Operating Activities less changes in working capital) less Capital Expenditures. The Company is unable to provide a reconciliation of projected Free Cash Flow as described in this presentation to its respective comparable financial measure calculated in accordance with GAAP without unreasonable efforts. This is due to our inability to calculate the comparable GAAP projected metrics, including operating income and total production costs, given the unknown effect, timing, and potential significance of certain income statement items. 55

Appendix Non-GAAP Reconciliations – Adjusted EBITDA (1) Reconciliation of Adjusted EBITDA to Consolidated Net Income ($ Thousands) FY 2017 FY 2018 FY 2019 FY 2020 FY 2021 FY 2022 Total Adjusted EBITDA Exploration & Production Adjusted EBITDA $ 361,079 $ 317,707 $ 351,159 $ 312,166 464,529 656,310 Pipeline & Storage Adjusted EBITDA 180,328 183,972 162,181 189,520 218,921 240,904 Gathering Adjusted EBITDA 94,380 91,937 108,292 119,879 159,005 176,572 Utility Adjusted EBITDA 151,078 175,554 176,134 171,418 171,379 162,871 Corporate & All Other Adjusted EBITDA (9,725) (7,704) (12,393) (7,529) (13,521) (10,762) Total Adjusted EBITDA $ 777,140 $ 761,466 $ 785,373 $ 785,454 $ 1,000,313 $ 1,225,895 Total Adjusted EBITDA $ 777,140 $ 761,466 $ 785,373 $ 785,454 $ 1,000,313 $ 1,225,895 Minus: Interest Expense (119,837) (114,522) (106,756) (117,077) (146,357) (130,357) Plus: Other Income (Deductions) 11,156 (21,174) (15,542) (17,814) (15,238) (1,509) Minus: Income Tax Expense (160,682) 7,494 (85,221) (18,739) (114,682) (116,629) Minus: Depreciation, Depletion & Amortization (224,195) (240,961) (275,660) (306,158) (335,303) (369,790) Minus: Impairment of Oil and Gas Properties (E&P) - - - (449,438) (76,152) - Minus: Gain on Sale of Timber Properties - - - - 51,066 - Minus: Gain on Sale of California Properties - - - - - 12,736 Minus: Loss from discontinuance of oil cash flow hedges (E&P) - - - - - (44,632) Minus: Transaction and severance costs related to West Coast asset sale (E&P) - - - - - (9,693) Minus: Unrealized Gain (Loss) on Hedge Ineffectiveness (100) (782) 2,096 - - - Rounding - - - - - - Consolidated Net Income $ 283,482 $ 391,521 $ 304,290 $ ( 123,772) $ 363,647 $ 566,021 Consolidated Debt to Total Adjusted EBITDA Long-Term Debt, Net of Current Portion (End of Period) $ 2,099,000 $ 2,149,000 $ 2,149,000 $ 2,649,000 $ 2,649,000 $ 2,100,000 Current Portion of Long-Term Debt (End of Period) 300,000 - - - - 549,000 Notes Payable to Banks and Commercial Paper (End of Period) - - 55,200 30,000 158,500 60,000 Less: Cash and Temporary Cash Investments (End of Period) (555,530) (229,606) (20,428) (20,541) (31,528) (46,048) Total Net Debt (End of Period) $ 1,843,470 $ 1,919,394 $ 2,183,772 $ 2,658,459 $ 2,775,972 $ 2,662,952 Long-Term Debt, Net of Current Portion (Start of Period) 2,099,000 2,099,000 2,149,000 2,149,000 2,649,000 2,649,000 Current Portion of Long-Term Debt (Start of Period) - 300,000 - - - - Notes Payable to Banks and Commercial Paper (Start of Period) - - - 55,200 30,000 158,500 Less: Cash and Temporary Cash Investments (Start of Period) (129,972) (555,530) (229,606) (20,428) (20,541) (31,528) Total Net Debt (Start of Period) $ 1,969,028 $ 1,843,470 $ 1,919,394 $ 2,183,772 $ 2,658,459 $ 2,775,972 Average Total Net Debt $ 1,906,249 $ 1,881,432 $ 2,051,583 $ 2,421,116 $ 2,717,216 $ 2,719,462 Average Total Net Debt to Total Adjusted EBITDA 2.45 x 2.47 x 2.61 x 3.08 x 2.72 x 2.22 x (1) Total Adjusted EBITDA for FY 2018, FY 2019, FY 2020, FY 2021 and FY 2022, include the reclassification of non-service pension costs from Operating and Maintenance Expense to Other Income (Deductions) as of October 1, 2018 on the Company’s Income Statement. 56 This reclassification is not reflected in Total Adjusted EBITDA for FY 2017.

Appendix Non-GAAP Reconciliations – Adjusted EBITDA, by Segment Reconciliation of Adjusted EBITDA to Net Income, by Segment ($ Thousands) FY 2017 FY 2018 FY 2019 FY 2020 FY 2021 FY 2022 Exploration and Production Segment Reported GAAP Earnings $ 129,326 $ 180,632 $ 111,807 $ (326,904) $ 101,916 $ 306,064 Depreciation, Depletion and Amortization 112,565 124,274 154,784 172,124 182,492 208,148 Other (Income) Deductions (707) (307) (1,091) 882 937 3,210 Interest Expense 53,702 54,288 54,777 58,098 69,662 53,401 Income Taxes 66,093 (41,962) 32,978 (41,472) 33,370 43,898 Mark-to-Market Adjustment due to Hedge Ineffectiveness 100 782 (2,096) - - - Impairment of Oil and Gas Properties - - - 449, 438 76,152 - Gain on Sale of West Coast assets - - - - - (12,736) Loss from discontinuance of crude oil cash flow hedges - - - - - 44,632 Transaction and severance costs related to West Coast asset sale - - - - - 9,693 Adjusted EBITDA $ 361,079 $ 317,707 $ 351,159 $ 312,166 $ 464,529 $ 656,310 Pipeline and Storage Segment Reported GAAP Earnings $ 68,446 $ 97,246 $ 74,011 $ 78,860 $ 92,542 $ 102,557 Depreciation, Depletion and Amortization 41,196 43,463 44,947 53,951 62,431 67,701 Other (Income) Deductions (3,978) (5,926) (9,157) (4,635) (5,840) (6,889) Interest Expense 33,717 31,383 29,142 32,731 40,976 42,492 Income Taxes 40,947 17,806 23,238 28,613 28,812 35,043 Adjusted EBITDA $ 180,328 $ 183,972 $ 162,181 $ 189,520 $ 218,921 $ 240,904 Gathering Segment Reported GAAP Earnings $ 40,377 $ 83,519 $ 58,413 $ 68,631 $ 80,274 $ 101,111 Depreciation, Depletion and Amortization 16,162 17,313 20,038 22,440 32,350 33,998 Other (Income) Deductions (995) (778) (460) (260) 12 26 Interest Expense 9,142 9,560 9,406 10,877 17,493 16,488 Income Taxes 29,694 (17,677) 20,895 18,191 28,876 24,949 Adjusted EBITDA $ 94,380 $ 91,937 $ 108,292 $ 119,879 $ 159,005 $ 176,572 Utility Segment Reported GAAP Earnings $ 46,935 $ 51,217 $ 60,871 $ 57,366 $ 54,335 $ 68,948 Depreciation, Depletion and Amortization 52,582 53,253 53,832 55,248 57,457 59,760 Other (Income) Deductions (1,825) 29,073 24,021 23,380 23,785 (7,117) Interest Expense 28,492 26,753 23,443 22,150 21,795 24,115 Income Taxes 24,894 15,258 13,967 13,274 14,007 17,165 Adjusted EBITDA $ 151,078 $ 175,554 $ 176,134 $ 171,418 $ 171,379 $ 162,871 Corporate and All Other Reported GAAP Earnings $ (1,602) $ (21,093) $ (812) $ (1,725) $ 34,580 $ (12,659) Depreciation, Depletion and Amortization 1,690 2,658 2,059 2,395 573 183 Gain on Sale of Timber Properties - - - - (51,066) - Other (Income) Deductions (3,651) (888) 2,229 (1,553) (3,656) 12,279 Interest Expense (5,216) (7,462) (10,012) (6,779) (3,569) (6,139) Income Taxes (946) 19,081 (5,857) 133 9,617 (4,426) Adjusted EBITDA $ (9,725) $ (7,704) $ (12,393) $ (7,529) $ (13,521) $ (10,762) 57

Appendix Non-GAAP Reconciliations – Adjusted Operating Results 58

Appendix Non-GAAP Reconciliations – Capital Expenditures Reconciliation of Segment Capital Expenditures to Consolidated Capital Expenditures ($ Thousands) FY 2023 FY 2018 FY 2019 FY 2020 FY 2021 FY 2022 Guidance Capital Expenditures Exploration & Production Capital Expenditures $ 380,677 $ 491,889 $ 670, 455 $ 381, 408 $ 565, 791 $525,000 - $575,000 Pipeline & Storage Capital Expenditures $ 92,832 $ 143,003 $ 166, 652 $ 252, 316 $ 95, 806 $110,000 - $130,000 Gathering Segment Capital Expenditures $ 61,728 $ 49,650 $ 297, 806 $ 34, 669 $ 55, 546 $85,000 - $105,000 Utility Capital Expenditures $ 85,648 $ 95,847 $ 94, 273 $ 100, 845 $ 111, 033 $110,000 - $130,000 Corporate & All Other Capital Expenditures $ 222 $ 855 $ 561 $ 450 $ 1, 212 Eliminations $ (20,505) $ ( 1,130) $ 223 Total Capital Expenditures from Continuing Operations $ 600,602 $ 781,246 $ 1,228,617 $ 769,911 $ 829,388 $830,000 - $940,000 Plus (Minus) Acquisition of Upstream Assets and Midstream Gathering Assets $ ( 506,258) Plus (Minus) Accrued Capital Expenditures $ ( 82,943) Exploration & Production FY 2021 Accrued Capital Expenditures $ ( 47,887) $ 47,887 (1) Exploration & Production FY 2020 Accrued Capital Expenditures $ ( 45,788) $ 42,983 Exploration & Production FY 2019 Accrued Capital Expenditures $ (38,063) $ 38,063 Exploration & Production FY 2018 Accrued Capital Expenditures $ (51,343) $ 51,343 Exploration & Production FY 2017 Accrued Capital Expenditures $ 36,465 $ ( 15,188) Pipeline & Storage FY 2021 Accrued Capital Expenditures $ ( 39,436) $ 39,436 Pipeline & Storage FY 2020 Accrued Capital Expenditures $ ( 17,264) $ 17,264 Pipeline & Storage FY 2019 Accrued Capital Expenditures $ (23,771) $ 23,771 Pipeline & Storage FY 2018 Accrued Capital Expenditures $ (21,861) $ 21,861 Pipeline & Storage FY 2017 Accrued Capital Expenditures $ 25,077 $ ( 10,724) Gathering FY 2021 Accrued Capital Expenditures $ ( 4,743) $ 4,743 Gathering FY 2020 Accrued Capital Expenditures $ ( 13,524) $ 13,524 Gathering FY 2019 Accrued Capital Expenditures $ (6,595) $ 6,595 Gathering FY 2018 Accrued Capital Expenditures $ (6,084) $ 6,084 Gathering FY 2017 Accrued Capital Expenditures $ 3,925 $ ( 11,407) Utility FY 2021 Accrued Capital Expenditures $ ( 10,634) $ 10,634 Utility FY 2020 Accrued Capital Expenditures $ ( 10,751) $ 10,751 Utility FY 2019 Accrued Capital Expenditures $ (12,692) $ 12,692 Utility FY 2018 Accrued Capital Expenditures $ (9,525) $ 9,525 Utility FY 2017 Accrued Capital Expenditures $ 6,748 Total Accrued Capital Expenditures $ (16,597) $ 7,692 $ ( 6,206) $ ( 18,177) $ ( 17,562) Total Capital Expenditures per Statement of Cash Flows $ 584, 004 $ 788, 938 $ 716, 153 $ 751, 734 $ 811, 826 $830,000 - $940,000 59 (1) Amount is $2,805 lower than the accrued capital expenditures reported in the prior year, representing certain liabilities assumed in connection with the 2020 acquisition of assets from Shell, capitalized as part of the asset acquisition cost, and subsequently paid by the Company. As the liabilities were owed and paid to third parties, they are not classified as capital expenditures in 2021.

Appendix Non-GAAP Reconciliations – E&P Operating Expenses Reconciliation of Exploration & Production Segment Operating Expenses by Division ($000s unless noted otherwise) Twelve Months Ended Twelve Months Ended September 30, 2022 September 30, 2021 (2) (2) (2) (2) Appalachia West Coast Total E&P Appalachia West Coast Total E&P Appalachia West Coast Total E&P Appalachia West Coast Total E&P $/ Mcfe $ / Boe $ / Mcfe $/ Mcfe $ / Boe $ / Mcfe Operating Expenses: (1) Gathering & Transportation Expense $199,405 $0 $199,405 $0.58 $0.00 $0.57 $185,151 $0 $185,151 $0.59 $0.00 $0.57 Other Lease Operating Expense $32,604 $51,905 $84,509 $0.10 $28.99 $0.24 $25,578 $56,587 $82,165 $0.08 $22.46 $0.25 Lease Operating and Transportation Expense $232,009 $51,905 $283,914 $0.68 $28.99 $0.81 $210,729 $56,587 $267,316 $0.67 $22.46 $0.82 General & Administrative Expense $79,061 $0.22 $67,973 $0.21 All Other Operating and Maintenance Expense $20,140 $0.06 $14,659 $0.04 Property, Franchise and Other Taxes $25,364 $0.07 $22,220 $0.07 Total Taxes & Other $45,504 $0.13 $36,879 $0.11 Depreciation, Depletion & Amortization $208,148 $0.59 $182,492 $0.56 Production: Gas Production (MMcf) 341,699 1,211 342,911 312,300 1,720 314,020 Oil Production (MBbl) 16 1,588 1,604 2 2,233 2,235 Total Production (Mmcfe) 341,796 10,741 352,536 312,313 15,117 327,430 Total Production (Mboe) 56,966 1,790 58,756 52,052 2,519 54,572 (1) Gathering and Transportation expense is net of any payments received from JDA partner for the partner's share of gathering cost. (2) Seneca West Coast division includes Seneca corporate and eliminations. 60