Exhibit 99 Investor Presentation Q4 Fiscal 2020 Update November 5, 2020Exhibit 99 Investor Presentation Q4 Fiscal 2020 Update November 5, 2020

National Fuel is committed to the safe and environmentally conscious development, transportation, storage, and distribution of natural gas and oil resources. For additional information, please review our Corporate Responsibility Report at https://responsibility.natfuel.com 2National Fuel is committed to the safe and environmentally conscious development, transportation, storage, and distribution of natural gas and oil resources. For additional information, please review our Corporate Responsibility Report at https://responsibility.natfuel.com 2

NFG: A Diversified, Integrated Natural Gas Company Developing our large, high quality Upstream acreage position in Marcellus & Utica Exploration & (1) shales Production ~1.2 Million ~1 Bcf/day 40% of NFG Net acres in Gross Appalachian (2) EBITDA (3) Appalachia natural gas production Expanding and modernizing pipeline Midstream infrastructure to provide outlets for Gathering Appalachian natural gas production Pipeline & Storage 4.4 MMDth $2.0 Billion 39% of NFG 38% of NFG Daily interstate Investments (2) (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 $341 Million 747,000 21% of NFG (1) 20EBITDA (2) Investments in safety Utility EBITDA customers since 2016 (1) This presentation includes forward-looking statements. Please review the safe harbor for forward looking statements at the end of this presentation. (2) Twelve months ending September 30, 2020. 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 (3) Gross Appalachian production as of September 30, 2020, excluding the impact of approximately 6 Bcf of production curtailments due to pricing. NFG: A Diversified, Integrated Natural Gas Company Developing our large, high quality Upstream acreage position in Marcellus & Utica Exploration & (1) shales Production ~1.2 Million ~1 Bcf/day 40% of NFG Net acres in Gross Appalachian (2) EBITDA (3) Appalachia natural gas production Expanding and modernizing pipeline Midstream infrastructure to provide outlets for Gathering Appalachian natural gas production Pipeline & Storage 4.4 MMDth $2.0 Billion 39% of NFG 38% of NFG Daily interstate Investments (2) (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 $341 Million 747,000 21% of NFG (1) 20EBITDA (2) Investments in safety Utility EBITDA customers since 2016 (1) This presentation includes forward-looking statements. Please review the safe harbor for forward looking statements at the end of this presentation. (2) Twelve months ending September 30, 2020. 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 (3) Gross Appalachian production as of September 30, 2020, excluding the impact of approximately 6 Bcf of production curtailments due to pricing.

Why National Fuel? Diversified Assets Provide Stability and Long-Term Growth Opportunities 4Why National Fuel? Diversified Assets Provide Stability and Long-Term Growth Opportunities 4

1 Integrated Model Enhances Shareholder Value . . . Geographic and Operational Benefits of National Fuel’s Upstream Integration Drives Synergies: Integrated Structure: Exploration & ü Ability to adjust to changing Production Upstream Midstream commodity 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 Rate-regulated entities share common Downstream ü More competitive pipeline resources, reducing operating expense Utility infrastructure projects ü Utility business is a large Pipeline & ü Strong balance sheet Storage customer ü Growing, stable dividend Financial Efficiencies: ü Investment grade credit ratingü Shared borrowing capacityü Consolidated income tax return 51 Integrated Model Enhances Shareholder Value . . . Geographic and Operational Benefits of National Fuel’s Upstream Integration Drives Synergies: Integrated Structure: Exploration & ü Ability to adjust to changing Production Upstream Midstream commodity 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 Rate-regulated entities share common Downstream ü More competitive pipeline resources, reducing operating expense Utility infrastructure projects ü Utility business is a large Pipeline & ü Strong balance sheet 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 Acquisition of significant flowing production and contiguous Tioga County acreage, with supporting gathering facilities, furthers focus on integrated Upstream and Midstream Appalachian development § ~1.2 million acre position in the Marcellus and Utica shales (inclusive of acquired acreage) § NFG’s gathering systems move Seneca’s natural gas production, driving consolidated returns § NFG’s interstate pipelines support Appalachian development and provide new firm takeaway capacity ü Further expansion of interstate pipeline systems to satisfy growing 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 6. . . and Continues to Drive Growth Opportunities Near Term Strategy Leverages Integration Across the Value Chain Pipeline & Exploration & Gathering Utility Storage Production ü Acquisition of significant flowing production and contiguous Tioga County acreage, with supporting gathering facilities, furthers focus on integrated Upstream and Midstream Appalachian development § ~1.2 million acre position in the Marcellus and Utica shales (inclusive of acquired acreage) § NFG’s gathering systems move Seneca’s natural gas production, driving consolidated returns § NFG’s interstate pipelines support Appalachian development and provide new firm takeaway capacity ü Further expansion of interstate pipeline systems to satisfy growing 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 6

2 Appalachian Program Expected to Generate Free Cash Flow . . . . . . In Fiscal 2021 at Natural Gas Prices . . . While Generating Strong Consolidated Well Below Current NYMEX Strip. . . Returns Across Seneca’s Acreage Footprint $175 Seneca and Gathering Consolidated Economics (Realized Price is NYMEX less applicable transport charges) $140-$150 $150 (2) (3) Realized Pricing $120-$130 15% IRR $125 $2.25 $2.00 Prospect Reservoir Realized (2) (2) $100-$110 IRR (%) IRR (%) Price $100 $80-$90 Lycoming Marcellus Marcellus 78% 64% $1.04 $75 Tioga Utica Utica 86% 69% $1.07 $50 RV/Beechwood Utica 42% 33% $1.42 $25 CRV Return Trip Marcellus 39% 29% $1.47 $0 $2.50 $2.75 $3.00 $3.25 (2) Net realized price is per MMBtu and reflects either (a) price received at the gathering system interconnect or @ NYMEX Price ($/MMBtu) (b) price received at delivery market net of firm transportation charges. (3) Consolidated Seneca and Gathering IRR is pre-tax and includes expected gathering capital expenditures, (1) The Company defines free cash flow on page 59 of this presentation. Assumes current hedges and $37.50 7 per Bbl WTI oil price. well costs under current cost structure, and non-gathering LOE. (1) Free Cash Flow ($ Millions) WDA EDA2 Appalachian Program Expected to Generate Free Cash Flow . . . . . . In Fiscal 2021 at Natural Gas Prices . . . While Generating Strong Consolidated Well Below Current NYMEX Strip. . . Returns Across Seneca’s Acreage Footprint $175 Seneca and Gathering Consolidated Economics (Realized Price is NYMEX less applicable transport charges) $140-$150 $150 (2) (3) Realized Pricing $120-$130 15% IRR $125 $2.25 $2.00 Prospect Reservoir Realized (2) (2) $100-$110 IRR (%) IRR (%) Price $100 $80-$90 Lycoming Marcellus Marcellus 78% 64% $1.04 $75 Tioga Utica Utica 86% 69% $1.07 $50 RV/Beechwood Utica 42% 33% $1.42 $25 CRV Return Trip Marcellus 39% 29% $1.47 $0 $2.50 $2.75 $3.00 $3.25 (2) Net realized price is per MMBtu and reflects either (a) price received at the gathering system interconnect or @ NYMEX Price ($/MMBtu) (b) price received at delivery market net of firm transportation charges. (3) Consolidated Seneca and Gathering IRR is pre-tax and includes expected gathering capital expenditures, (1) The Company defines free cash flow on page 59 of this presentation. Assumes current hedges and $37.50 7 per Bbl WTI oil price. well costs under current cost structure, and non-gathering LOE. (1) Free Cash Flow ($ Millions) WDA EDA

3 Significant Interstate Pipeline Growth ü Supply Corp. Rate Case Settlement: Northern Access § $35 million increase in base rates Empire North Delivery: NY & Canada (effective February 2020) Delivery: Canada & NY 490,000 Dth/d (remains under development) 205,000 Dth/d § Additional $15 million step-up (expected April 2022) ü Significant Expansion Revenues: § Line N to Monaca: $5 MM FM100 (placed into service November 2019) Delivery: Transco (Leidy) 330,000 Dth/d § Empire North: $27 MM (placed into service September 2020) Line N to Monaca § FM100: $35 MM Delivery: Shell ethane cracker facility (Beaver Co., Pa) (In-service target of late calendar 2021) 133,000 Dth/d ü Substantial Modernization Opportunities: § $150-$250 million expected over next 5 years (Supply Corp.) 83 Significant Interstate Pipeline Growth ü Supply Corp. Rate Case Settlement: Northern Access § $35 million increase in base rates Empire North Delivery: NY & Canada (effective February 2020) Delivery: Canada & NY 490,000 Dth/d (remains under development) 205,000 Dth/d § Additional $15 million step-up (expected April 2022) ü Significant Expansion Revenues: § Line N to Monaca: $5 MM FM100 (placed into service November 2019) Delivery: Transco (Leidy) 330,000 Dth/d § Empire North: $27 MM (placed into service September 2020) Line N to Monaca § FM100: $35 MM Delivery: Shell ethane cracker facility (Beaver Co., Pa) (In-service target of late calendar 2021) 133,000 Dth/d ü Substantial Modernization Opportunities: § $150-$250 million expected over next 5 years (Supply Corp.) 8

4 Half Century of Dividend Growth $1.78 4.3% 50 Years 118 Years (1) per share yield Consecutive Dividend Increases Consecutive Payments $3.2 Billion Dividend payments since 1970 $0.19 per share Annual Rate at Fiscal Year End 9 (1) As of November 3, 2020.4 Half Century of Dividend Growth $1.78 4.3% 50 Years 118 Years (1) per share yield Consecutive Dividend Increases Consecutive Payments $3.2 Billion Dividend payments since 1970 $0.19 per share Annual Rate at Fiscal Year End 9 (1) As of November 3, 2020.

Focused on Corporate Responsibility and Sustainability 5 Initial Corporate Responsibility Report Published in September 2020 ü Based on feedback from stakeholders, report was developed using the Sustainability Accounting Standards Board (SASB) framework ü Report covers relevant environmental metrics for each of the Company’s businesses: § Gas Utilities and Distributors § Oil & Gas Midstream § Oil & Gas Exploration and Production ü Report also includes significant social and governance disclosures utilizing the Global Reporting Initiative (GRI) standards ü Expected focus in years ahead on additional/supplemental disclosures in line with these frameworks 10Focused on Corporate Responsibility and Sustainability 5 Initial Corporate Responsibility Report Published in September 2020 ü Based on feedback from stakeholders, report was developed using the Sustainability Accounting Standards Board (SASB) framework ü Report covers relevant environmental metrics for each of the Company’s businesses: § Gas Utilities and Distributors § Oil & Gas Midstream § Oil & Gas Exploration and Production ü Report also includes significant social and governance disclosures utilizing the Global Reporting Initiative (GRI) standards ü Expected focus in years ahead on additional/supplemental disclosures in line with these frameworks 10

Fourth Quarter and Fiscal 2020 Financial Highlights 11Fourth Quarter and Fiscal 2020 Financial Highlights 11

Fourth Quarter Fiscal 2020 Results and Drivers (1) Adjusted Operating Results ($/share) Q4 FY 2019 Q4 FY 2020 Major Drivers Decrease Driven $0.54 Primarily by Natural Gas Prices Commodity Prices $61.00 $55.70 $2.26 $1.92 $0.40 Exploration & Oil Prices Production $0.28 Crude Oil ($/Bbl) Natural Gas ($/Mcfe) E&P $0.16 Natural Gas Production (Recent Acquisition) Gathering Gathering 64.0 55.4 $0.19 $0.19 612 556 Oil Production (Reduced Activity) Pipeline & Crude Oil (Mbbl) Natural Gas (Bcf) Pipeline & Storage Storage $0.18 $0.18 Supply Corporation Rate Case Settlement Utility -$0.08 Utility -$0.09 Utility: ($0.09) Utility: ($0.08) $32.3 Corporate/Other: ($0.02) Corporate/Other: ($0.05) $24.4 MM Empire North and Line N MM Q4 FY19 Q4 FY20 Projects Placed in Service (1) A Reconciliation of Adjusted Operating Results to Earnings Per Share is provided at the end of this presentation. 12 (2) Realized price after hedging. Pipeline & Storage Net Oil and Gas Oil and Gas (2) Operating Income Production PricingFourth Quarter Fiscal 2020 Results and Drivers (1) Adjusted Operating Results ($/share) Q4 FY 2019 Q4 FY 2020 Major Drivers Decrease Driven $0.54 Primarily by Natural Gas Prices Commodity Prices $61.00 $55.70 $2.26 $1.92 $0.40 Exploration & Oil Prices Production $0.28 Crude Oil ($/Bbl) Natural Gas ($/Mcfe) E&P $0.16 Natural Gas Production (Recent Acquisition) Gathering Gathering 64.0 55.4 $0.19 $0.19 612 556 Oil Production (Reduced Activity) Pipeline & Crude Oil (Mbbl) Natural Gas (Bcf) Pipeline & Storage Storage $0.18 $0.18 Supply Corporation Rate Case Settlement Utility -$0.08 Utility -$0.09 Utility: ($0.09) Utility: ($0.08) $32.3 Corporate/Other: ($0.02) Corporate/Other: ($0.05) $24.4 MM Empire North and Line N MM Q4 FY19 Q4 FY20 Projects Placed in Service (1) A Reconciliation of Adjusted Operating Results to Earnings Per Share is provided at the end of this presentation. 12 (2) Realized price after hedging. Pipeline & Storage Net Oil and Gas Oil and Gas (2) Operating Income Production Pricing

Fiscal 2020 Highlights (1) (1) Flat vs. FY19 despite significantly lower commodity prices Adjusted EBITDA $785 million th Grew shareholder distribution for 50 consecutive year Dividend $1.78 per share Up 14% vs. FY19; highest output in NFG history, Production 241.5 Bcfe driven by recent Appalachian acquisition Up 12% vs. FY19; replaced 248% of production Proved Reserves 3.5 Tcfe Gathering Up 13% vs FY19; highest throughput in NFG history 264.3 Bcfe Throughput Pipeline & Storage Up 7% vs. FY19; favorably resolved Supply Corporation $310 Million rate case and placed Empire North project into service Revenues Utility Safety Ongoing focus on pipeline replacement and modernization $71 Million Investments Corporate Published in September 2020 (covers all segments) Inaugural Report Responsibility 13 (1) A reconciliation of Adjusted EBITDA to GAAP earnings is included at the end of this presentation.Fiscal 2020 Highlights (1) (1) Flat vs. FY19 despite significantly lower commodity prices Adjusted EBITDA $785 million th Grew shareholder distribution for 50 consecutive year Dividend $1.78 per share Up 14% vs. FY19; highest output in NFG history, Production 241.5 Bcfe driven by recent Appalachian acquisition Up 12% vs. FY19; replaced 248% of production Proved Reserves 3.5 Tcfe Gathering Up 13% vs FY19; highest throughput in NFG history 264.3 Bcfe Throughput Pipeline & Storage Up 7% vs. FY19; favorably resolved Supply Corporation $310 Million rate case and placed Empire North project into service Revenues Utility Safety Ongoing focus on pipeline replacement and modernization $71 Million Investments Corporate Published in September 2020 (covers all segments) Inaugural Report Responsibility 13 (1) A reconciliation of Adjusted EBITDA to GAAP earnings is included at the end of this presentation.

Earnings Guidance FY2020 Adjusted Operating Results FY2021 Earnings Guidance (1) $2.92/share $3.55 to $3.85/share Key Guidance Drivers § 305-335 Bcfe (up 33% vs. FY20) Net Production (2) § ~$2.25/Mcf (vs. $2.07/Mcf in FY20) Realized natural gas prices (after-hedge) Exploration & (3) Exploration § ~$47.00/Bbl (vs. $56.96/Bbl in FY20) Realized oil prices (after-hedge) Production & Production G&A Expense § $0.21-$0.23/Mcf (vs. $0.26 in FY20) DD&A Expense § $0.60-$0.65/Mcf (vs. $0.71 in FY20) Gathering Gathering Revenues§ $185-$200 million (up 35% vs. FY20) Gathering Gathering O&M Expense § ~$0.09/Mcf (acquired assets utilize leased compression) Pipeline & Storage Revenues § $330 - $340 million (Empire North / Supply rate case) Pipeline & Pipeline & Pipeline & Storage O&M Expense § Expected to increase ~4% from FY20 (Empire North / cost inflation) Storage Storage Pipeline & Storage Depreciation Expense § Expected to increase by ~$8 million from FY20 Utility § Guidance assumes return to normal weather; higher gross Utility Utility Operating Income margin expected to be offset by cost inflation Tax Rate Effective Tax Rate § ~26% (no significant change expected) (1) Excludes items impacting comparability. A reconciliation of Adjusted Operating Results is provided at the end of this presentation. (2) Assumes NYMEX natural gas pricing of $3.00/MMBtu and in-basin spot pricing of $2.50/MMBtu for winter and $2.10/MMBtu for summer fiscal 2021, respectively, and reflects the impact of existing financial hedges, firm sales and firm transportation contracts. 14 (3) Assumes NYMEX (WTI) oil pricing of $37.50/Bbl and California-MWSS pricing differentials of 94% to WTI, and reflects impact of existing financial hedge contracts. Regulated Non-RegulatedEarnings Guidance FY2020 Adjusted Operating Results FY2021 Earnings Guidance (1) $2.92/share $3.55 to $3.85/share Key Guidance Drivers § 305-335 Bcfe (up 33% vs. FY20) Net Production (2) § ~$2.25/Mcf (vs. $2.07/Mcf in FY20) Realized natural gas prices (after-hedge) Exploration & (3) Exploration § ~$47.00/Bbl (vs. $56.96/Bbl in FY20) Realized oil prices (after-hedge) Production & Production G&A Expense § $0.21-$0.23/Mcf (vs. $0.26 in FY20) DD&A Expense § $0.60-$0.65/Mcf (vs. $0.71 in FY20) Gathering Gathering Revenues§ $185-$200 million (up 35% vs. FY20) Gathering Gathering O&M Expense § ~$0.09/Mcf (acquired assets utilize leased compression) Pipeline & Storage Revenues § $330 - $340 million (Empire North / Supply rate case) Pipeline & Pipeline & Pipeline & Storage O&M Expense § Expected to increase ~4% from FY20 (Empire North / cost inflation) Storage Storage Pipeline & Storage Depreciation Expense § Expected to increase by ~$8 million from FY20 Utility § Guidance assumes return to normal weather; higher gross Utility Utility Operating Income margin expected to be offset by cost inflation Tax Rate Effective Tax Rate § ~26% (no significant change expected) (1) Excludes items impacting comparability. A reconciliation of Adjusted Operating Results is provided at the end of this presentation. (2) Assumes NYMEX natural gas pricing of $3.00/MMBtu and in-basin spot pricing of $2.50/MMBtu for winter and $2.10/MMBtu for summer fiscal 2021, respectively, and reflects the impact of existing financial hedges, firm sales and firm transportation contracts. 14 (3) Assumes NYMEX (WTI) oil pricing of $37.50/Bbl and California-MWSS pricing differentials of 94% to WTI, and reflects impact of existing financial hedge contracts. Regulated Non-Regulated

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

E&P and Gathering Growing Production within Disciplined Capital Program E&P Net Production (Bcfe) Near-Term Strategy 350 305-335 nd Appalachia ü Expect to add 2 drilling rig in early calendar 300 2021 (additional activity focused in EDA) California 241.5 250 211.8 178.1 173.5 200 § Additional production will support Leidy 290-320 150 South capacity (330 Mdth/d) 225.4 195.9 100 160.5 154.1 § Gross production growth will benefit 50 NFG’s Gathering segment 19.4 17.6 16.1 15.9 ~15 0 2017 2018 2019 2020 2021E ü WDA: development focused on Utica shale, (1) E&P Net Capital Expenditures ($ millions) with step-out into Beechwood area and return $600 trips in Clermont-Rich Valley area $492 $500 ü EDA Tioga: development focused on return $384 $350-$390 $356 $400 trip pads (Seneca and legacy Shell) $300 $246 $462ü EDA Lycoming: activity focused on fully $340- $355 $200 $330 utilizing valuable Atlantic Sunrise capacity $380 $208 $100 ü California: Limited spending expected due to $38 $10 $26 $30 $30 $0 low oil prices 2017 2018 2019 2020 2021E (1) A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation. FY17 and FY18 reflects the netting of $7 million and $17 million, respectively, of up-front proceeds received 16 from joint development partner for working interest in joint development wells. FY20 reflects the netting of $286 million related to the acquisition of Appalachian upstream assets in July 2020. E&P and Gathering Growing Production within Disciplined Capital Program E&P Net Production (Bcfe) Near-Term Strategy 350 305-335 nd Appalachia ü Expect to add 2 drilling rig in early calendar 300 2021 (additional activity focused in EDA) California 241.5 250 211.8 178.1 173.5 200 § Additional production will support Leidy 290-320 150 South capacity (330 Mdth/d) 225.4 195.9 100 160.5 154.1 § Gross production growth will benefit 50 NFG’s Gathering segment 19.4 17.6 16.1 15.9 ~15 0 2017 2018 2019 2020 2021E ü WDA: development focused on Utica shale, (1) E&P Net Capital Expenditures ($ millions) with step-out into Beechwood area and return $600 trips in Clermont-Rich Valley area $492 $500 ü EDA Tioga: development focused on return $384 $350-$390 $356 $400 trip pads (Seneca and legacy Shell) $300 $246 $462ü EDA Lycoming: activity focused on fully $340- $355 $200 $330 utilizing valuable Atlantic Sunrise capacity $380 $208 $100 ü California: Limited spending expected due to $38 $10 $26 $30 $30 $0 low oil prices 2017 2018 2019 2020 2021E (1) A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation. FY17 and FY18 reflects the netting of $7 million and $17 million, respectively, of up-front proceeds received 16 from joint development partner for working interest in joint 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 Eastern Development Area (EDA) (1) § Average Seneca gross production : ~546 MMcf/d WDA – ~915,000 Acres § ~300 potential Utica and Marcellus locations § Large, highly-contiguous acreage position, with limited near-term lease expirations (~15% royalty) § Low breakeven consolidated economics (15% IRR) § Tioga Utica: $1.07/MMBtu § Lycoming Marcellus: $1.04/MMBtu Western Development Area (WDA) EDA – ~270,000 Acres (1) § Average Seneca gross production : ~364 MMcf/d § Over 1,000 potential Marcellus and Utica locations § Breakeven (15% IRR) consolidated economics - Seneca and Gathering - of $1.47/MMBtu or less § Royalty free mineral ownership § Highly contiguous nature drives efficiencies 17 (1) Average production is for the quarter ended September 30, 2020, and includes the impact of price-related curtailments. E&P and Gathering Significant Appalachian Acreage Position Eastern Development Area (EDA) (1) § Average Seneca gross production : ~546 MMcf/d WDA – ~915,000 Acres § ~300 potential Utica and Marcellus locations § Large, highly-contiguous acreage position, with limited near-term lease expirations (~15% royalty) § Low breakeven consolidated economics (15% IRR) § Tioga Utica: $1.07/MMBtu § Lycoming Marcellus: $1.04/MMBtu Western Development Area (WDA) EDA – ~270,000 Acres (1) § Average Seneca gross production : ~364 MMcf/d § Over 1,000 potential Marcellus and Utica locations § Breakeven (15% IRR) consolidated economics - Seneca and Gathering - of $1.47/MMBtu or less § Royalty free mineral ownership § Highly contiguous nature drives efficiencies 17 (1) Average production is for the quarter ended September 30, 2020, and includes the impact of price-related curtailments.

E&P and Gathering Eastern Development Area Seneca EDA Highlights EDA – ~270,000 Acres 1 Tioga County, PA ü ~180 undeveloped Utica locations, including ~40 return trip locations ü ~90 undeveloped Marcellus locations ü Gathering infrastructure: NFG Tioga gathering systems ü Firm transportation capacity: § Empire Pipeline (NFG): 200 Mdth/d § Dominion – capacity reaches Transco Leidy line, providing optionality for future Leidy South volumes (Transco/NFG): 100 Mdth/d § Interconnections with other interstate pipelines: TGP (300 Line) and UGI 2 Lycoming County, PA ü ~30 remaining Marcellus locations ü Geneseo Shale expected to provide 100 - 120 return trip locations ü Gathering infrastructure: NFG Midstream Trout Run ü Firm transportation capacity: Atlantic Sunrise (189 MDth/d) 18E&P and Gathering Eastern Development Area Seneca EDA Highlights EDA – ~270,000 Acres 1 Tioga County, PA ü ~180 undeveloped Utica locations, including ~40 return trip locations ü ~90 undeveloped Marcellus locations ü Gathering infrastructure: NFG Tioga gathering systems ü Firm transportation capacity: § Empire Pipeline (NFG): 200 Mdth/d § Dominion – capacity reaches Transco Leidy line, providing optionality for future Leidy South volumes (Transco/NFG): 100 Mdth/d § Interconnections with other interstate pipelines: TGP (300 Line) and UGI 2 Lycoming County, PA ü ~30 remaining Marcellus locations ü Geneseo Shale expected to provide 100 - 120 return trip locations ü Gathering infrastructure: NFG Midstream Trout Run ü Firm transportation capacity: Atlantic Sunrise (189 MDth/d) 18

E&P and Gathering EDA: Tioga County Development Synergistic Acquisition Provides Highly-Economic Utica and Marcellus Inventory Tioga Development Plan Significant Tioga County Acreage Position ü Acquired assets are contiguous to NFG’s existing Tioga County production and gathering Undeveloped operations Utica ü Near-term development expected to focus on return trips to both recently acquired and DCNR Tract 007 pads Undeveloped Marcellus (1) ü Similar to WDA-CRV development, return trips allow use of existing infrastructure, enhancing consolidated drilling program returns ü Continuing to optimize development plan through incorporation of acquired assets 19E&P and Gathering EDA: Tioga County Development Synergistic Acquisition Provides Highly-Economic Utica and Marcellus Inventory Tioga Development Plan Significant Tioga County Acreage Position ü Acquired assets are contiguous to NFG’s existing Tioga County production and gathering Undeveloped operations Utica ü Near-term development expected to focus on return trips to both recently acquired and DCNR Tract 007 pads Undeveloped Marcellus (1) ü Similar to WDA-CRV development, return trips allow use of existing infrastructure, enhancing consolidated drilling program returns ü Continuing to optimize development plan through incorporation of acquired assets 19

E&P and Gathering Integrated Development – EDA Tioga Gathering NFG Tioga Gathering Systems Support Growing Seneca Production Current Systems In-Service Tioga County Gathering Systems Map ü Tioga Gathering System Empire § Capacity: up to 550,000 Dth per day (Interconnects with Empire, Dominion, and TGP 300) § Production Source: Seneca Resources (acquired Tioga acreage and future development) DTI ü Wellsboro Gathering System TGP § Total Investment (to date): ~$38 million § Capacity: up to 200,000 Dth per day (Interconnect w/ TGP 300 line) § Production Source: Seneca Resources (DCNR Tract 007) ü Covington Gathering System § Total Investment (to date): ~$48 million § Capacity: 220,000 Dth per day (Interconnect w/ TGP 300 line) § Production Source: Seneca Resources (Covington / DCNR Tract 595) 20E&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 Empire § Capacity: up to 550,000 Dth per day (Interconnects with Empire, Dominion, and TGP 300) § Production Source: Seneca Resources (acquired Tioga acreage and future development) DTI ü Wellsboro Gathering System TGP § Total Investment (to date): ~$38 million § Capacity: up to 200,000 Dth per day (Interconnect w/ TGP 300 line) § Production Source: Seneca Resources (DCNR Tract 007) ü Covington Gathering System § Total Investment (to date): ~$48 million § Capacity: 220,000 Dth per day (Interconnect w/ TGP 300 line) § Production Source: Seneca Resources (Covington / DCNR Tract 595) 20

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) 450 ü Acquired production supported by firm transportation capacity to premium 400 markets: Dominion Dominion to Leidy South FT Capacity: 100,000 Dth/d 350 § 200 MDth/d (Empire-NFG) provides access to Dawn/TGP 200 markets 300 250 § 100 MDth/d to Dominion markets, Tioga County Extension (NFG - Empire) which reaches Leidy Hub and FT Capacity: 170,000 - 200,000 Dth/d 200 provide access to Leidy South expansion project 150 ü Seneca’s existing firm transportation 100 (1) EDA - TGP 300 Firm Sales and firm sales support DCNR Tract 007, 50 DCNR Tract 595, and Covington area Northeast Supply Diversification Project production FT Capacity: 50,000 Dth/d - Oct-20 Jan-21 Apr-21 Jul-21 Oct-21 Jan-22 Apr-22 Jul-22 21 (1) Includes physical fixed price and NYMEX-based firm sales contracts that do not carry any additional transportation costs. 100 MDth/d of Dominion capacity provides optionality to fill Leidy South.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) 450 ü Acquired production supported by firm transportation capacity to premium 400 markets: Dominion Dominion to Leidy South FT Capacity: 100,000 Dth/d 350 § 200 MDth/d (Empire-NFG) provides access to Dawn/TGP 200 markets 300 250 § 100 MDth/d to Dominion markets, Tioga County Extension (NFG - Empire) which reaches Leidy Hub and FT Capacity: 170,000 - 200,000 Dth/d 200 provide access to Leidy South expansion project 150 ü Seneca’s existing firm transportation 100 (1) EDA - TGP 300 Firm Sales and firm sales support DCNR Tract 007, 50 DCNR Tract 595, and Covington area Northeast Supply Diversification Project production FT Capacity: 50,000 Dth/d - Oct-20 Jan-21 Apr-21 Jul-21 Oct-21 Jan-22 Apr-22 Jul-22 21 (1) Includes physical fixed price and NYMEX-based firm sales contracts that do not carry any additional transportation costs. 100 MDth/d of Dominion capacity provides optionality to fill Leidy South.

E&P and Gathering EDA: Lycoming County Development Marcellus Development in Lycoming County Fully Utilizes Firm Transportation ü Prolific Marcellus acreage with peer-leading well results ü ~30 remaining Marcellus locations – breakeven (15% IRR) consolidated economics of ~$1.04/MMBtu ü Near-term development focused on Atlantic Sunrise capacity EDA – Transco Firm Contracts 250 (1) 200 Transco Firm Sales 150 Atlantic Sunrise (Transco) FT Capacity: 189,405 Dth/d 100 Firm Sales: NYMEX+ 50 0 22 (1) Includes physical fixed price and NYMEX-based firm sales contracts that do not carry any additional transportation costs. Gross Firm Volumes (MDth/d)E&P and Gathering EDA: Lycoming County Development Marcellus Development in Lycoming County Fully Utilizes Firm Transportation ü Prolific Marcellus acreage with peer-leading well results ü ~30 remaining Marcellus locations – breakeven (15% IRR) consolidated economics of ~$1.04/MMBtu ü Near-term development focused on Atlantic Sunrise capacity EDA – Transco Firm Contracts 250 (1) 200 Transco Firm Sales 150 Atlantic Sunrise (Transco) FT Capacity: 189,405 Dth/d 100 Firm Sales: NYMEX+ 50 0 22 (1) Includes physical fixed price and NYMEX-based firm sales contracts that do not carry any additional transportation costs. Gross Firm Volumes (MDth/d)

E&P and Gathering Integrated Development – EDA Lycoming Gathering NFG Trout Run Gathering System Supports Seneca and Future Third-Party Development Current System In-Service Trout Run Gathering System Map ü Total Investment (to date): ~$270 million ü Capacity: 466,000 to 585,000 Dth per day ü Current Production Source: Seneca Resources (DCNR Tract 100 & Gamble) ü Interconnect: Transco (Leidy Line) Opportunities for Third-Party Volumes ü Third-party volumes under contract and expected to come online in early fiscal 2021 § Completed construction of new facilities, leveraging existing Trout Run system ü Once in service, expected to generate $4 million - $10 million per year in additional gathering revenues (supported by minimum volume commitments) 23E&P and Gathering Integrated Development – EDA Lycoming Gathering NFG Trout Run Gathering System Supports Seneca and Future Third-Party Development Current System In-Service Trout Run Gathering System Map ü Total Investment (to date): ~$270 million ü Capacity: 466,000 to 585,000 Dth per day ü Current Production Source: Seneca Resources (DCNR Tract 100 & Gamble) ü Interconnect: Transco (Leidy Line) Opportunities for Third-Party Volumes ü Third-party volumes under contract and expected to come online in early fiscal 2021 § Completed construction of new facilities, leveraging existing Trout Run system ü Once in service, expected to generate $4 million - $10 million per year in additional gathering revenues (supported by minimum volume commitments) 23

E&P and Gathering Western Development Area (1) WDA Highlights Marcellus Core Acreage vs. Utica Trend ü Large well inventory: § Marcellus Shale: 600+ well locations remaining / 200,000 acres § Utica Shale: 500+ potential locations across Utica (2) trend / 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 Past Marcellus delineation testsü Additional appraisal tests planned to delineate Rich Utica Trend (currently evaluating) Valley to Boone Mountain corridor ? Marcellus Core Acreage (1) The Utica Shale lies approximately 5,000 feet beneath Seneca’s WDA Marcellus acreage. 24 (2) Appraisal program currently in progress. Additional tests are planned. 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 Western Development Area (1) WDA Highlights Marcellus Core Acreage vs. Utica Trend ü Large well inventory: § Marcellus Shale: 600+ well locations remaining / 200,000 acres § Utica Shale: 500+ potential locations across Utica (2) trend / 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 Past Marcellus delineation testsü Additional appraisal tests planned to delineate Rich Utica Trend (currently evaluating) Valley to Boone Mountain corridor ? Marcellus Core Acreage (1) The Utica Shale lies approximately 5,000 feet beneath Seneca’s WDA Marcellus acreage. 24 (2) Appraisal program currently in progress. Additional tests are planned. 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 WDA Development Plan Beechwood Development Area Provides ~100 Potential Utica Locations with Strong Economics WDA Development Update WDA – Potential RV-Beechwood Development Area ü WDA-CRV Area: producing from both Utica and Marcellus wells, with recent development focused on return trips to existing pads § Avg. CRV Utica Production: ~160 MMcf/d § Avg. CRV Marcellus Production: ~182 MMcf/d ü WDA RV-Beechwood Area: ~100 potential Utica locations, with economics equal to or greater than prior CRV-Utica development program Consolidated WDA Economics EUR IRR% 15% IRR (1) (Bcf/1000’) $2.25 ($/MMBtu) Utica (RV-Beechwood) 1.5 - 1.8 42% $1.42 Marcellus (CRV Return Trip) 1.1 - 1.2 39% $1.47 (1) Internal Rate of Return is for consolidated Seneca and Gathering, is pre-tax, and includes expected gathering 25 capital expenditures, well costs under current cost structure, and non-gathering LOE. E&P and Gathering WDA Development Plan Beechwood Development Area Provides ~100 Potential Utica Locations with Strong Economics WDA Development Update WDA – Potential RV-Beechwood Development Area ü WDA-CRV Area: producing from both Utica and Marcellus wells, with recent development focused on return trips to existing pads § Avg. CRV Utica Production: ~160 MMcf/d § Avg. CRV Marcellus Production: ~182 MMcf/d ü WDA RV-Beechwood Area: ~100 potential Utica locations, with economics equal to or greater than prior CRV-Utica development program Consolidated WDA Economics EUR IRR% 15% IRR (1) (Bcf/1000’) $2.25 ($/MMBtu) Utica (RV-Beechwood) 1.5 - 1.8 42% $1.42 Marcellus (CRV Return Trip) 1.1 - 1.2 39% $1.47 (1) Internal Rate of Return is for consolidated Seneca and Gathering, is pre-tax, and includes expected gathering 25 capital expenditures, well costs under current cost structure, and non-gathering LOE.

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: 470 MMcf per day § Interconnects with TGP 300 and NFG Supply § Total Investment to Date: $326 million § 38,120 HP of compression (3 stations) Future Build-Out § Modest gathering pipeline and compression investment required to support Seneca’s Utica return-trip development § Seneca’s RV-Beechwood development area expected to require extension of existing trunkline and incremental compression 26E&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: 470 MMcf per day § Interconnects with TGP 300 and NFG Supply § Total Investment to Date: $326 million § 38,120 HP of compression (3 stations) Future Build-Out § Modest gathering pipeline and compression investment required to support Seneca’s Utica return-trip development § Seneca’s RV-Beechwood development area expected to require extension of existing trunkline and incremental compression 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) 600 ü Will continue to layer-in firm sales deals of short and longer 500 duration on TGP 300 to reduce Leidy South* Transco Zone 6 NNY spot exposure 400 330,000 Dth/d *Capacity can be utilized by all three producing areas (WDA, EDA-Tioga, and EDA-Lycoming) ü WDA spot realizations track 300 TGP Station 313 pricing, WDA - TGP 300 typically 10¢ - 20¢ better than 200 Firm Sales TGP Marcellus Zone 4 Niagara Expansion Project (TGP and NFG) 100 NYMEX & Dawn ü Leidy South will provide 158,000 Dth/d 0 additional capacity to premium markets (Transco Zone 6 NNY) 27E&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) 600 ü Will continue to layer-in firm sales deals of short and longer 500 duration on TGP 300 to reduce Leidy South* Transco Zone 6 NNY spot exposure 400 330,000 Dth/d *Capacity can be utilized by all three producing areas (WDA, EDA-Tioga, and EDA-Lycoming) ü WDA spot realizations track 300 TGP Station 313 pricing, WDA - TGP 300 typically 10¢ - 20¢ better than 200 Firm Sales TGP Marcellus Zone 4 Niagara Expansion Project (TGP and NFG) 100 NYMEX & Dawn ü Leidy South will provide 158,000 Dth/d 0 additional capacity to premium markets (Transco Zone 6 NNY) 27

E&P and Gathering Long-term Contracts Supporting Appalachian Production Seneca Appalachia Natural Gas Marketing Firm Contract Volumes (MDth/day) 1,200 Leidy South (Transco & NFG - Supply) 1,000 (1) Transco Zone 6 NNY Dominion 100,000 Dth/d 330,000 Dth/d Dominion to Leidy South 800 Tioga County Extension (NFG - Empire) Canada-Dawn & NY Markets 170,000 - 200,000 Dth/d 600 In-Basin (2) Firm Sales Contracts 400 Atlantic Sunrise (Transco) Mid-Atlantic & Southeast U.S. 189,405 Dth/d 200 Niagara Expansion (TGP & NFG - Supply) Canada-Dawn & TETCO 158,000 Dth/d Northeast Supply Diversification (TGP) 50,000 Dth/d (Canada-Dawn) - Oct-20 Jan-21 Apr-21 Jul-21 Oct-21 Jan-22 Apr-22 Jul-22 Oct-22 (1) 100,000 Dth/day on Dominion provides optionality to fill Leidy South. 28 (2) 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. Gross Frim Volumes (MDth/d) E&P and Gathering Long-term Contracts Supporting Appalachian Production Seneca Appalachia Natural Gas Marketing Firm Contract Volumes (MDth/day) 1,200 Leidy South (Transco & NFG - Supply) 1,000 (1) Transco Zone 6 NNY Dominion 100,000 Dth/d 330,000 Dth/d Dominion to Leidy South 800 Tioga County Extension (NFG - Empire) Canada-Dawn & NY Markets 170,000 - 200,000 Dth/d 600 In-Basin (2) Firm Sales Contracts 400 Atlantic Sunrise (Transco) Mid-Atlantic & Southeast U.S. 189,405 Dth/d 200 Niagara Expansion (TGP & NFG - Supply) Canada-Dawn & TETCO 158,000 Dth/d Northeast Supply Diversification (TGP) 50,000 Dth/d (Canada-Dawn) - Oct-20 Jan-21 Apr-21 Jul-21 Oct-21 Jan-22 Apr-22 Jul-22 Oct-22 (1) 100,000 Dth/day on Dominion provides optionality to fill Leidy South. 28 (2) 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. Gross Frim Volumes (MDth/d)

E&P and Gathering Near-term Firm Sales Provide Market & Price Certainty Net Contracted Firm Sales Volumes (Dth per day) (1) Contracted Index Price Differentials ($ per Dth) NYMEX Dawn Other Fixed Price 932,600 16,800 ($0.84) 22,100 ($0.70) 21,900 ($0.70) 121,200 17,600 ($0.88) 805,600 $2.24 786,400 781,500 773,400 141,200 ~691,000 140,900 140,100 $2.29 $2.22 $2.22 293,100 80.700 ($0.24) $2.10 462,500 140,000 138,600 ($0.54) ($0.61) ($0.68) Actual 27,600 ($0.50) Daily Net Production 566,900 84,000 ($0.68) 478,500 472,800 ($0.54) 448,100 ($0.58) ($0.58) ($0.52) 264,900 ($0.63) Q4 FY20 Q1 FY21 Q2 FY21 Q3 FY21 Q4 FY21 FY 2022 Avg Gross Firm Sales 932,500 952,000 906,500 896,600 1,067,200 Volumes (Dth/d) (1) Values shown include acquired contracts, and represent the weighted average fixed price or weighted average differential relative to NYMEX (netback price) less any associated transportation costs. Transportation costs include minor variable components such as the Canadian exchange rate and fuel components. With respect to “Other”, the weighted average differential relative to NYMEX (netback price) includes net contracted firm sales at various indices, which are to subject to fluctuations 29 in the market, such as seasonal demand swings, and is calculated using forward basis at various associated locations as specified by the underlying contract. E&P and Gathering Near-term Firm Sales Provide Market & Price Certainty Net Contracted Firm Sales Volumes (Dth per day) (1) Contracted Index Price Differentials ($ per Dth) NYMEX Dawn Other Fixed Price 932,600 16,800 ($0.84) 22,100 ($0.70) 21,900 ($0.70) 121,200 17,600 ($0.88) 805,600 $2.24 786,400 781,500 773,400 141,200 ~691,000 140,900 140,100 $2.29 $2.22 $2.22 293,100 80.700 ($0.24) $2.10 462,500 140,000 138,600 ($0.54) ($0.61) ($0.68) Actual 27,600 ($0.50) Daily Net Production 566,900 84,000 ($0.68) 478,500 472,800 ($0.54) 448,100 ($0.58) ($0.58) ($0.52) 264,900 ($0.63) Q4 FY20 Q1 FY21 Q2 FY21 Q3 FY21 Q4 FY21 FY 2022 Avg Gross Firm Sales 932,500 952,000 906,500 896,600 1,067,200 Volumes (Dth/d) (1) Values shown include acquired contracts, and represent the weighted average fixed price or weighted average differential relative to NYMEX (netback price) less 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 29 in the market, such as seasonal demand swings, and is calculated using forward basis at various associated locations as specified by the underlying contract.

E&P and Gathering California Oil Stable Oil Production | Minimal Capital Investment | Steady Free Cash Flow 1 Avg. Daily Production Location Formation Production Method (net Boe/d) East Coalinga/ 1 Temblor Primary 614 Other 2 North Lost Tulare & Primary/ 2 775 Hills Etchegoin Steam flood 3 South Lost Monterey 3 Primary 1,112 Hills Shale North Midway Tulare & 4 4 Steam flood 2,434 Sunset Potter 5 South Midway 5 Antelope Steam flood 1,921 Sunset (1) TOTAL WEST DIVISION AVG. NET PRODUCTION 6,856 Boe/d 30 (1) Average daily net production (oil and natural gas) for West division for quarter ended September 30, 2020. E&P and Gathering California Oil Stable Oil Production | Minimal Capital Investment | Steady Free Cash Flow 1 Avg. Daily Production Location Formation Production Method (net Boe/d) East Coalinga/ 1 Temblor Primary 614 Other 2 North Lost Tulare & Primary/ 2 775 Hills Etchegoin Steam flood 3 South Lost Monterey 3 Primary 1,112 Hills Shale North Midway Tulare & 4 4 Steam flood 2,434 Sunset Potter 5 South Midway 5 Antelope Steam flood 1,921 Sunset (1) TOTAL WEST DIVISION AVG. NET PRODUCTION 6,856 Boe/d 30 (1) Average daily net production (oil and natural gas) for West division for quarter ended September 30, 2020.

E&P and Gathering Fiscal 2021 Production and Price Certainty 275 Bcf of Appalachian Production Protected by Firm Sales (1) § 209 Bcf locked-in realizing net ~$2.19/Mcf (2) § 25 Bcf of no-cost collars with $2.89/Mcf ceiling § 41 Bcf of additional basis protection 350 305-335 Bcfe ~15 Bcfe 300 50% of oil ~30 Bcf production (3) ~41 Bcf Spot production hedged at 250 assumed to be sold $58.24 /Bbl ~25 Bcf at ~$2.10 for 200 summer and ~$2.50 for winter of FY21 150 100 ~209 Bcfe 50 0 Fixed Price + Firm No Cost Collars Firm Sales Spot Sales California Total Sales w/ Hedge (Unhedged) 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 ceiling price (average weighted floor price of $2.37/Mcf). 31 (3) Indicates firm sales contracts with fixed index differentials, as well as production with associated firm transport volumes, but not backed by a matching financial hedge. Production (Bcfe)E&P and Gathering Fiscal 2021 Production and Price Certainty 275 Bcf of Appalachian Production Protected by Firm Sales (1) § 209 Bcf locked-in realizing net ~$2.19/Mcf (2) § 25 Bcf of no-cost collars with $2.89/Mcf ceiling § 41 Bcf of additional basis protection 350 305-335 Bcfe ~15 Bcfe 300 50% of oil ~30 Bcf production (3) ~41 Bcf Spot production hedged at 250 assumed to be sold $58.24 /Bbl ~25 Bcf at ~$2.10 for 200 summer and ~$2.50 for winter of FY21 150 100 ~209 Bcfe 50 0 Fixed Price + Firm No Cost Collars Firm Sales Spot Sales California Total Sales w/ Hedge (Unhedged) 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 ceiling price (average weighted floor price of $2.37/Mcf). 31 (3) Indicates firm sales contracts with fixed index differentials, as well as production with associated firm transport volumes, but not backed by a matching financial hedge. Production (Bcfe)

E&P and Gathering Hedge Positions and Prices Production Supported by Strong Hedge Positions in Fiscal 2021 and 2022 (1) Reflects percentage of remaining projected production for FY21 hedged at the midpoint of the production guidance range. (2) Average weighted floor and ceiling prices. 32 (3) Fixed price physical sales exclude joint development partner’s share of fixed price contract WDA volumes as specified under the joint development agreement. Swaps and no cost collar prices do not include cost of transport. E&P and Gathering Hedge Positions and Prices Production Supported by Strong Hedge Positions in Fiscal 2021 and 2022 (1) Reflects percentage of remaining projected production for FY21 hedged at the midpoint of the production guidance range. (2) Average weighted floor and ceiling prices. 32 (3) Fixed price physical sales exclude joint development partner’s share of fixed price contract WDA volumes as specified under the joint development agreement. Swaps and no cost collar prices do not include cost of transport.

E&P and Gathering Acquisition Drives Expected Decrease in E&P Operating Costs Increased Scale and Highly-Synergistic Operations Expected to Drive Lower Cash Unit Costs (3) Seneca Cash OpEx ($/Mcfe) Appalachia LOE ($/Mcfe) Approximately $0.07/Mcfe Reduction in Expected Expected FY21 Increase Driven by One-Time Costs to Cash Unit Costs vs. Pre-Acquisition Levels Bring Acquired Assets In Line with Seneca Standards $1.32 ~$0.71 ~$1.26 $0.68 $1.22 $0.67 ~$1.19 $0.14 $0.11 ~$0.09 $0.07 $0.12 $0.07 $0.12 $0.30 (1) $0.28 $0.26 $0.22 (2) (2) $0.32 $0.30 $0.27 $0.28 (4) ~$0.62 $0.61 $0.60 (2) (2) $0.58 $0.57 $0.56 $0.57 FY 2019 FY 2020 FY 2021E FY 2019 FY20E (April) FY 2020 FY 2021E LOE (Gathering & Transport) LOE (Other) G&A Taxes & Other (1) G&A estimate represents the midpoint of the G&A guidance ranges for fiscal 2021. (2) The total of the two LOE components represents the midpoint of the LOE guidance ranges for fiscal 2021. FY20 Seneca LOE was $0.84/Mcfe (vs. total shown of $0.85) due to rounding. (3) See Non-GAAP Reconciliation at the end of this presentation for additional detail on Appalachian LOE & Gathering and Seneca LOE. 33 (4) Gathering fees paid by Seneca to Gathering segment comprise approximately 90% of expected Appalachian Gathering and TransportLOE. E&P and Gathering Acquisition Drives Expected Decrease in E&P Operating Costs Increased Scale and Highly-Synergistic Operations Expected to Drive Lower Cash Unit Costs (3) Seneca Cash OpEx ($/Mcfe) Appalachia LOE ($/Mcfe) Approximately $0.07/Mcfe Reduction in Expected Expected FY21 Increase Driven by One-Time Costs to Cash Unit Costs vs. Pre-Acquisition Levels Bring Acquired Assets In Line with Seneca Standards $1.32 ~$0.71 ~$1.26 $0.68 $1.22 $0.67 ~$1.19 $0.14 $0.11 ~$0.09 $0.07 $0.12 $0.07 $0.12 $0.30 (1) $0.28 $0.26 $0.22 (2) (2) $0.32 $0.30 $0.27 $0.28 (4) ~$0.62 $0.61 $0.60 (2) (2) $0.58 $0.57 $0.56 $0.57 FY 2019 FY 2020 FY 2021E FY 2019 FY20E (April) FY 2020 FY 2021E LOE (Gathering & Transport) LOE (Other) G&A Taxes & Other (1) G&A estimate represents the midpoint of the G&A guidance ranges for fiscal 2021. (2) The total of the two LOE components represents the midpoint of the LOE guidance ranges for fiscal 2021. FY20 Seneca LOE was $0.84/Mcfe (vs. total shown of $0.85) due to rounding. (3) See Non-GAAP Reconciliation at the end of this presentation for additional detail on Appalachian LOE & Gathering and Seneca LOE. 33 (4) Gathering fees paid by Seneca to Gathering segment comprise approximately 90% of expected Appalachian Gathering and TransportLOE.

Pipeline and Storage Overview National Fuel Gas Supply Corporation ~ Empire Pipeline, Inc. 34Pipeline and Storage Overview National Fuel Gas Supply Corporation ~ Empire Pipeline, Inc. 34

Pipeline & Storage Pipeline & Storage Segment Overview National Fuel Gas Supply Corporation (1) ü Contracted Capacity : § Firm Transportation: 3,443 MDth per day § Firm Storage: 70,693 Mdth (fully subscribed) (2) ü Rate Base : ~$944 million Empire Pipeline ü FERC Rate Proceeding Status: § New rates went into effect February 2020 Supply Corp. § Rate case settlement approved June 2020 Empire Pipeline, Inc. (1) ü Contracted Capacity : § Firm Transportation: 984 MDth per day § Firm Storage: 3,753 Mdth (fully subscribed) (2) ü Rate Base : ~$247 million ü FERC Rate Proceeding Status: § New rates went into effect January 2019 § Rate case settlement approved May 2019 (1) As of September 30, 2020. 35 (2) As of December 31, 2019 calculated from National Fuel Gas Supply Corporation’s and Empire Pipeline, Inc.’s 2019 FERC Form-2 reports, respectively.Pipeline & Storage Pipeline & Storage Segment Overview National Fuel Gas Supply Corporation (1) ü Contracted Capacity : § Firm Transportation: 3,443 MDth per day § Firm Storage: 70,693 Mdth (fully subscribed) (2) ü Rate Base : ~$944 million Empire Pipeline ü FERC Rate Proceeding Status: § New rates went into effect February 2020 Supply Corp. § Rate case settlement approved June 2020 Empire Pipeline, Inc. (1) ü Contracted Capacity : § Firm Transportation: 984 MDth per day § Firm Storage: 3,753 Mdth (fully subscribed) (2) ü Rate Base : ~$247 million ü FERC Rate Proceeding Status: § New rates went into effect January 2019 § Rate case settlement approved May 2019 (1) As of September 30, 2020. 35 (2) As of December 31, 2019 calculated from National Fuel Gas Supply Corporation’s and Empire Pipeline, Inc.’s 2019 FERC Form-2 reports, respectively.

Pipeline & Storage Empire North Project Fully Subscribed Project Provides 205,000 Dth/day of Incremental Firm Transportation § In-service date: September 15, 2020 § Est. capital cost: $129 million § Annual revenues: ~$27 million § Receipt point: Jackson (Tioga Co., Pa. production) § Design capacity and delivery points: ü 175,000 Dth/d to Chippawa (TCPL interconnect) ü 30,000 Dth/d to Hopewell (TGP 200 interconnect) § Major facilities: ü 2 new compressor stations in NY (1) & Pa. (1) ü No new pipeline construction 36Pipeline & Storage Empire North Project Fully Subscribed Project Provides 205,000 Dth/day of Incremental Firm Transportation § In-service date: September 15, 2020 § Est. capital cost: $129 million § Annual revenues: ~$27 million § Receipt point: Jackson (Tioga Co., Pa. production) § Design capacity and delivery points: ü 175,000 Dth/d to Chippawa (TCPL interconnect) ü 30,000 Dth/d to Hopewell (TGP 200 interconnect) § Major facilities: ü 2 new compressor stations in NY (1) & Pa. (1) ü No new pipeline construction 36

Pipeline & Storage FM100 Project - Consolidated Benefit for NFG Project expected to provide long-term earnings 330,000 Dth/d of new transportation capacity from uplift to Seneca, Supply Corp. and Gathering WDA and EDA acreage positions to premium markets Supply Corp. ü Lease to Transco of new capacity: 330,000 Dth/day ü Target in-service: late calendar year 2021 ü Estimated annual revenues: ~$50 million § In-service: ~$35 million (lease revenues) (2) § April 2022: ~$15 million (negotiated revenue step-up) Seneca ü New Transco capacity (Leidy South): 330,000 Dth/day (1) ü Rate : competitive with other expansion project rates in Seneca’s current transportation portfolio ü Delivery point(s): Transco Zone 6 interconnections Gathering ü All Seneca volumes will flow through wholly-owned NFG gathering facilities (1) Includes lease of new capacity from Supply Corp. to Transco. 37 (2) Based on Period 2 rates described in recently approved settlement of Supply Corporation rate proceeding. Period 2 rates go into effect the later of the in-service date of FM100 project, or April 2022. Pipeline & Storage FM100 Project - Consolidated Benefit for NFG Project expected to provide long-term earnings 330,000 Dth/d of new transportation capacity from uplift to Seneca, Supply Corp. and Gathering WDA and EDA acreage positions to premium markets Supply Corp. ü Lease to Transco of new capacity: 330,000 Dth/day ü Target in-service: late calendar year 2021 ü Estimated annual revenues: ~$50 million § In-service: ~$35 million (lease revenues) (2) § April 2022: ~$15 million (negotiated revenue step-up) Seneca ü New Transco capacity (Leidy South): 330,000 Dth/day (1) ü Rate : competitive with other expansion project rates in Seneca’s current transportation portfolio ü Delivery point(s): Transco Zone 6 interconnections Gathering ü All Seneca volumes will flow through wholly-owned NFG gathering facilities (1) Includes lease of new capacity from Supply Corp. to Transco. 37 (2) Based on Period 2 rates described in recently approved settlement of Supply Corporation rate proceeding. Period 2 rates go into effect the later of the in-service date of FM100 project, or April 2022.

Pipeline & Storage FM100 Project – Significant Investment by Supply Corp. § Estimated capital cost: $279 million § Expansion facilities: ~$159 million § Modernization facilities: ~$120 million § Facilities (all in Pennsylvania) include: § Approximately 30 miles of new pipeline § 2 new compressor stations (totaling approximately 37,000 HP) § New interconnection station and modification of existing interconnection station § Abandonment of approximately 45 miles of existing pipeline and compressor station § Regulatory process: § FERC certificate application filed July 2019 § FERC certificate issued 7/17/20 38Pipeline & Storage FM100 Project – Significant Investment by Supply Corp. § Estimated capital cost: $279 million § Expansion facilities: ~$159 million § Modernization facilities: ~$120 million § Facilities (all in Pennsylvania) include: § Approximately 30 miles of new pipeline § 2 new compressor stations (totaling approximately 37,000 HP) § New interconnection station and modification of existing interconnection station § Abandonment of approximately 45 miles of existing pipeline and compressor station § Regulatory process: § FERC certificate application filed July 2019 § FERC certificate issued 7/17/20 38

Pipeline & Storage Continued Expansion of the NFG Supply System Line N to Monaca Project § Project: Firm transportation service to a new ethane cracker facility being built by Shell Chemical Appalachia, LLC § In-service date: November 1, 2019 § Capital cost: ~$24.5 million § Contracted capacity: 133,000 Dth/day Additional Line N Expansion Potential § Several expansions of Line N pipeline since 2010 § Continuing to discuss opportunities for further expansion with third parties: ü On-system demand ü Producers 39Pipeline & Storage Continued Expansion of the NFG Supply System Line N to Monaca Project § Project: Firm transportation service to a new ethane cracker facility being built by Shell Chemical Appalachia, LLC § In-service date: November 1, 2019 § Capital cost: ~$24.5 million § Contracted capacity: 133,000 Dth/day Additional Line N Expansion Potential § Several expansions of Line N pipeline since 2010 § Continuing to discuss opportunities for further expansion with third parties: ü On-system demand ü Producers 39

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 Feb. 2019 – U.S. Second Circuit Court of Appeals vacated and remanded NY DEC denial of WQC ü April 2019 – FERC denied rehearing of WQC waiver order (upholding waiver finding) ü Supply and Empire currently working to finalize remaining federal authorizations 40Pipeline & 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 Feb. 2019 – U.S. Second Circuit Court of Appeals vacated and remanded NY DEC denial of WQC ü April 2019 – FERC denied rehearing of WQC waiver order (upholding waiver finding) ü Supply and Empire currently working to finalize remaining federal authorizations 40

Pipeline & Storage Pipeline & Storage Customer Mix (1) Customer Transportation by Shipper Type Affiliated Customer Mix (Contracted Capacity) (2) 4.4 MMDth/d Affiliated Non-Affiliated End User 8% Outside Pipeline 26% 9% 52% Producer 82% 34% Marketer 10% 74% 48% LDC 39% 18% LDCs Producers Firm Storage Firm Transport (1) Contracted as of 9/30/2020. 41 (2) Affiliated includes Seneca’s acquired capacity on Empire Pipeline. Pipeline & Storage Pipeline & Storage Customer Mix (1) Customer Transportation by Shipper Type Affiliated Customer Mix (Contracted Capacity) (2) 4.4 MMDth/d Affiliated Non-Affiliated End User 8% Outside Pipeline 26% 9% 52% Producer 82% 34% Marketer 10% 74% 48% LDC 39% 18% LDCs Producers Firm Storage Firm Transport (1) Contracted as of 9/30/2020. 41 (2) Affiliated includes Seneca’s acquired capacity on Empire Pipeline.

Utility Overview National Fuel Gas Distribution Corporation 42Utility Overview National Fuel Gas Distribution Corporation 42

Utility New York & Pennsylvania Service Territories New York (1) Total Customers : 534,000 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) o System Modernization Tracker Pennsylvania (1) Total Customers : 213,000 ROE: Black Box Settlement (2007) Rate Mechanisms: o Low Income Rates o Merchant Function Charge 43 (1) As of September 30, 2020.Utility New York & Pennsylvania Service Territories New York (1) Total Customers : 534,000 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) o System Modernization Tracker Pennsylvania (1) Total Customers : 213,000 ROE: Black Box Settlement (2007) Rate Mechanisms: o Low Income Rates o Merchant Function Charge 43 (1) As of September 30, 2020.

Utility New York Rate Case Outcome On April 20, 2017, the New York Public Service Commission issued a Rate Order relating to NFG Distribution’s rate case (No. 16-G-0257) filed in April 2016. Rate Order Summary: § Revenue Requirement: $5.9 million § Rate Base: $704 million § Allowed Return on Equity (ROE): 8.7% § Capital Structure: 42.9% equity § Other notable items: § New rates became effective 5/1/17 § Retains rate mechanisms in place under prior order (revenue decoupling, weather normalization, merchant function charge, 90/10 large customer sharing) (1) § System modernization tracker for Leak Prone Pipe (LPP) § Earnings sharing started 4/1/18 (50/50 sharing starts at ROE in excess of 9.2%) 44 (1) Applies to new plant placed in service through March 31, 2021. Utility New York Rate Case Outcome On April 20, 2017, the New York Public Service Commission issued a Rate Order relating to NFG Distribution’s rate case (No. 16-G-0257) filed in April 2016. Rate Order Summary: § Revenue Requirement: $5.9 million § Rate Base: $704 million § Allowed Return on Equity (ROE): 8.7% § Capital Structure: 42.9% equity § Other notable items: § New rates became effective 5/1/17 § Retains rate mechanisms in place under prior order (revenue decoupling, weather normalization, merchant function charge, 90/10 large customer sharing) (1) § System modernization tracker for Leak Prone Pipe (LPP) § Earnings sharing started 4/1/18 (50/50 sharing starts at ROE in excess of 9.2%) 44 (1) Applies to new plant placed in service through March 31, 2021.

Utility Utility Continues its Significant Investments in Safety Ongoing system modernization program drives increased rate base, with tracker in NY allowing recovery of pipeline replacement costs (1) $125.0 Capital Expenditures for Safety Total Capital Expenditures $98.0 $95.8 $90-$100 $94.3 $100.0 $85.6 $80.9 $74.1 $71.4 $69.9 $75.0 $63.6 $61.8 $50.0 Modernization Spending in NY Expected to Grow Gross Margin By $3 MM - $4 MM in FY 2021 $25.0 $0.0 2016 2017 2018 2019 2020 2021E Fiscal Year 45 (1) A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation. Capital Expenditures ($ millions)Utility Utility Continues its Significant Investments in Safety Ongoing system modernization program drives increased rate base, with tracker in NY allowing recovery of pipeline replacement costs (1) $125.0 Capital Expenditures for Safety Total Capital Expenditures $98.0 $95.8 $90-$100 $94.3 $100.0 $85.6 $80.9 $74.1 $71.4 $69.9 $75.0 $63.6 $61.8 $50.0 Modernization Spending in NY Expected to Grow Gross Margin By $3 MM - $4 MM in FY 2021 $25.0 $0.0 2016 2017 2018 2019 2020 2021E Fiscal Year 45 (1) A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation. Capital Expenditures ($ millions)

Utility Ongoing Pipeline Replacement & Modernization (1) Utility Mains by Material Miles of Utility Main Pipeline Replaced 159 158 Wrought Iron 146 144 Coated Bare 130 Cast Iron NY 9,738 miles Plastic Wrought Bare Iron Coated PA* 4,843 miles Plastic 2015 2016 2017 2018 2019 Calendar Year * No Cast Iron Mains in Pa.* 46 (1) All values are reported on a calendar year basis as of December 31, 2019.Utility Ongoing Pipeline Replacement & Modernization (1) Utility Mains by Material Miles of Utility Main Pipeline Replaced 159 158 Wrought Iron 146 144 Coated Bare 130 Cast Iron NY 9,738 miles Plastic Wrought Bare Iron Coated PA* 4,843 miles Plastic 2015 2016 2017 2018 2019 Calendar Year * No Cast Iron Mains in Pa.* 46 (1) All values are reported on a calendar year basis as of December 31, 2019.

Utility A Proven History of Controlling Costs (1) Utility O&M Expense and Non-Service Pension Costs ($ millions) $250 O&M Expense (GAAP) Non-Service Pension Costs $200 $206 $195 $197 $196 $189 $200 $27 $28 $31 $179 $169 $150 $166 $100 $50 $0 2015 2016 2017 2018 2019 2020 Fiscal Year 47 (1) As of October 1, 2018, Operation and Maintenance Expense does not include non-service pension costs, which were re-classified as Other Income (Deductions) on the Company’s Income Statement. Utility A Proven History of Controlling Costs (1) Utility O&M Expense and Non-Service Pension Costs ($ millions) $250 O&M Expense (GAAP) Non-Service Pension Costs $200 $206 $195 $197 $196 $189 $200 $27 $28 $31 $179 $169 $150 $166 $100 $50 $0 2015 2016 2017 2018 2019 2020 Fiscal Year 47 (1) As of October 1, 2018, Operation and Maintenance Expense does not include non-service pension costs, which were re-classified as Other Income (Deductions) on the Company’s Income Statement.

Consolidated Financial Overview Upstream I Midstream I Downstream 48Consolidated Financial Overview Upstream I Midstream I Downstream 48

Diversified, Balanced Earnings and Cash Flows (1) (2) Adjusted Operating Results ($ per share) Adjusted EBITDA ($ millions) $785 $785 $3.55 to $3.85 $4.00 $800 $2.92 $312 E&P $351 $3.00 $600 $0.68 $120 Gathering $2.00 $400 $108 $0.73 $190 $162 Pipeline & $0.89 Rate Rate $1.00 $200 Storage Regulated Regulated ~40-45% ~45% $176 $171 $0.65 Utility $- $0 FY 2020 FY 2021 Guidance FY 2019 FY 2020 (1) A reconciliation of Adjusted Operating Results to Earnings per Share, by segment, as presented on the Consolidated Statement of Income and Earnings Reinvested in the Business is included at the end of this presentation. (2) Consolidated Adjusted EBITDA includes Corporate & All Other Segments. A reconciliation of Adjusted EBITDA to Net Income, by segment, as presented on the Consolidated Statement of Income and Earnings Reinvested in the Business is included 49 at the end of this presentation.Diversified, Balanced Earnings and Cash Flows (1) (2) Adjusted Operating Results ($ per share) Adjusted EBITDA ($ millions) $785 $785 $3.55 to $3.85 $4.00 $800 $2.92 $312 E&P $351 $3.00 $600 $0.68 $120 Gathering $2.00 $400 $108 $0.73 $190 $162 Pipeline & $0.89 Rate Rate $1.00 $200 Storage Regulated Regulated ~40-45% ~45% $176 $171 $0.65 Utility $- $0 FY 2020 FY 2021 Guidance FY 2019 FY 2020 (1) A reconciliation of Adjusted Operating Results to Earnings per Share, by segment, as presented on the Consolidated Statement of Income and Earnings Reinvested in the Business is included at the end of this presentation. (2) Consolidated Adjusted EBITDA includes Corporate & All Other Segments. 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 49 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 $781 $720-$830 $719 $750 $583 $350-$390 $492 $384 $500 $455 $366 $356 $30-$40 $246 $99 $74 $50 $250 $54 $250-$300 $48 $33 $167 $143 $114 $93 $95 $98 $96 $94 $90-$100 $86 $81 $0 2016 2017 2018 2019 2020 2021E 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) FY16, FY17, and FY18 reflects the netting of $157 million, $7 million, and $17 million, respectively, of up-front proceeds received from joint development partner for working interest in joint development wells, and $21M in intercompany asset transfers in FY18. FY20 reflects the netting of $286 million related to the acquisition of Appalachian upstream assets in July 2020. 50 (3) FY20 reflects the netting of $224 million related to the acquisition of Appalachian gathering assets in July 2020. Disciplined, Flexible Capital Allocation (1) Capital Expenditures by Segment ($ millions) (2) (3) $1,000 Exploration & Production Gathering Pipeline & Storage Utility $781 $720-$830 $719 $750 $583 $350-$390 $492 $384 $500 $455 $366 $356 $30-$40 $246 $99 $74 $50 $250 $54 $250-$300 $48 $33 $167 $143 $114 $93 $95 $98 $96 $94 $90-$100 $86 $81 $0 2016 2017 2018 2019 2020 2021E 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) FY16, FY17, and FY18 reflects the netting of $157 million, $7 million, and $17 million, respectively, of up-front proceeds received from joint development partner for working interest in joint development wells, and $21M in intercompany asset transfers in FY18. FY20 reflects the netting of $286 million related to the acquisition of Appalachian upstream assets in July 2020. 50 (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 Includes only 2 months of EBITDA from acquisition Total 3.08 x Total Equity 2.61 x 2.51 x 2.45 x 2.47 x Debt 43% 57% Expect reduction to ~2.75x in FY21 $4.6 Billion Total Capitalization 2016 2017 2018 2019 2020 2021E as of September 30, 2020 Fiscal Year End Debt Maturity Profile by Fiscal Year ($MM) Liquidity $600 $549 $500 $500 $500 $ 750 MM Multi-Year Committed Credit Facility 200 MM 364-Day Committed Credit Facility $400 $300 $300 (30 MM) Short-term Debt Outstanding $200 920 MM Available Short-term Credit Facilities 21 MM Cash Balance at 9/30/20 $0 $ 941 MM Total Liquidity at 9/30/20 51 (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.Maintaining Strong Balance Sheet & Liquidity (1) Net Debt / Adjusted EBITDA Capitalization Includes only 2 months of EBITDA from acquisition Total 3.08 x Total Equity 2.61 x 2.51 x 2.45 x 2.47 x Debt 43% 57% Expect reduction to ~2.75x in FY21 $4.6 Billion Total Capitalization 2016 2017 2018 2019 2020 2021E as of September 30, 2020 Fiscal Year End Debt Maturity Profile by Fiscal Year ($MM) Liquidity $600 $549 $500 $500 $500 $ 750 MM Multi-Year Committed Credit Facility 200 MM 364-Day Committed Credit Facility $400 $300 $300 (30 MM) Short-term Debt Outstanding $200 920 MM Available Short-term Credit Facilities 21 MM Cash Balance at 9/30/20 $0 $ 941 MM Total Liquidity at 9/30/20 51 (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.

Appendix 52Appendix 52

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 oil and 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: the Company’s ability to successfully integrate acquired assets, including Shell’s upstream assets and midstream gathering assets in Pennsylvania, and achieve expected cost synergies; the length and severity of the COVID-19 pandemic, including its impacts across our businesses on demand, operations, global supply chains and liquidity; changes in economic conditions, including 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 or oil; impairments under the SEC’s full cost ceiling test for natural gas and oil reserves; 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; 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; delays or changes in costs or plans with respect to Company projects or related projects of other companies, including disruptions due to the COVID-19 pandemic, 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; 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), environmental/safety requirements, affiliate relationships, industry structure, and franchise renewal; changes in price differentials between similar quantities of natural gas or oil 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 and oil reserves, including among others geology, lease availability, 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 or oil 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; uncertainty of oil and gas reserve estimates; significant differences between the Company’s projected and actual production levels for natural gas or oil; changes in demographic patterns and weather conditions; 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; 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 oil and gas quantities. Proved oil and gas reserves are those quantities of oil and 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 oil and 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, 2019 and the Forms 10-Q for the quarters ended December 31, 2019, March 31, 2020, June 30, 2020. 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. 53Appendix 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 oil and 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: the Company’s ability to successfully integrate acquired assets, including Shell’s upstream assets and midstream gathering assets in Pennsylvania, and achieve expected cost synergies; the length and severity of the COVID-19 pandemic, including its impacts across our businesses on demand, operations, global supply chains and liquidity; changes in economic conditions, including 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 or oil; impairments under the SEC’s full cost ceiling test for natural gas and oil reserves; 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; 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; delays or changes in costs or plans with respect to Company projects or related projects of other companies, including disruptions due to the COVID-19 pandemic, 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; 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), environmental/safety requirements, affiliate relationships, industry structure, and franchise renewal; changes in price differentials between similar quantities of natural gas or oil 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 and oil reserves, including among others geology, lease availability, 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 or oil 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; uncertainty of oil and gas reserve estimates; significant differences between the Company’s projected and actual production levels for natural gas or oil; changes in demographic patterns and weather conditions; 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; 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 oil and gas quantities. Proved oil and gas reserves are those quantities of oil and 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 oil and 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, 2019 and the Forms 10-Q for the quarters ended December 31, 2019, March 31, 2020, June 30, 2020. 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. 53

Appendix Consolidated Seneca and Gathering Economics (2) Realized Pricing Average (3) Locations Average 15% IRR Completed EUR $2.50 $2.25 $2.00 Prospect Reservoir Remaining CAPEX Realized Lateral (Bcf/1000') (3) (3) (3) to Be Drilled ($M/1000') IRR (%) IRR (%) IRR (%) Price Length (ft) 5,500 - Lycoming Marcellus Marcellus ~30 2.5-2.9 $950-$1,000 94% 78% 64% $1.04 6,000 9,500 - Tioga Utica Utica ~180 2.0-2.3 $950-$1,050 100% 86% 69% $1.07 10,500 9,500- RV/Beechwood Utica ~100 1.5-1.8 $900-$950 49% 42% 33% $1.42 10,500 CRV Return Trip Marcellus ~25 8,500-9,500 1.1-1.2 $575-$625 46% 39% 29% $1.47 Over 1,000 Potential Additional Marcellus and Utica Locations (1) Economic on a Stand-Alone Basis at ~$2.00/MMBtu (1) Stand-alone Seneca breakeven economics (15% pre-tax IRR) by prospect are as follows: Lycoming Marcellus: $1.51; Tioga County: $1.48; WDA-RV/Beechwood Utica: $1.88; WDA-CRV Return Trip Marcellus: $1.86. Approximately 50 remaining WDA-CRV Utica return-trips remaining with breakeven economics of ~$1.75/MMBtu. Internal Rate of Return (IRR) for stand-alone Seneca is pre-tax and includes estimated well costs under current cost structure, LOE, and Gathering tariffs anticipated for each prospect. (2) Net realized price reflects either (a) price received at the gathering system interconnect or (b) price received at delivery market net of firm transportation charges. 54 (3) Consolidated Seneca and Gathering IRR is pre-tax and includes expected gathering capital expenditures, well costs under current cost structure, and non-gathering LOE. WDA EDAAppendix Consolidated Seneca and Gathering Economics (2) Realized Pricing Average (3) Locations Average 15% IRR Completed EUR $2.50 $2.25 $2.00 Prospect Reservoir Remaining CAPEX Realized Lateral (Bcf/1000') (3) (3) (3) to Be Drilled ($M/1000') IRR (%) IRR (%) IRR (%) Price Length (ft) 5,500 - Lycoming Marcellus Marcellus ~30 2.5-2.9 $950-$1,000 94% 78% 64% $1.04 6,000 9,500 - Tioga Utica Utica ~180 2.0-2.3 $950-$1,050 100% 86% 69% $1.07 10,500 9,500- RV/Beechwood Utica ~100 1.5-1.8 $900-$950 49% 42% 33% $1.42 10,500 CRV Return Trip Marcellus ~25 8,500-9,500 1.1-1.2 $575-$625 46% 39% 29% $1.47 Over 1,000 Potential Additional Marcellus and Utica Locations (1) Economic on a Stand-Alone Basis at ~$2.00/MMBtu (1) Stand-alone Seneca breakeven economics (15% pre-tax IRR) by prospect are as follows: Lycoming Marcellus: $1.51; Tioga County: $1.48; WDA-RV/Beechwood Utica: $1.88; WDA-CRV Return Trip Marcellus: $1.86. Approximately 50 remaining WDA-CRV Utica return-trips remaining with breakeven economics of ~$1.75/MMBtu. Internal Rate of Return (IRR) for stand-alone Seneca is pre-tax and includes estimated well costs under current cost structure, LOE, and Gathering tariffs anticipated for each prospect. (2) Net realized price reflects either (a) price received at the gathering system interconnect or (b) price received at delivery market net of firm transportation charges. 54 (3) Consolidated Seneca and Gathering IRR is pre-tax and includes expected gathering capital expenditures, well costs under current cost structure, and non-gathering LOE. WDA EDA

Appendix Hedge Positions and Prices Natural Gas Volumes in thousand MMBtu; Prices in $/MMBtu Fiscal 2021 Fiscal 2022 Fiscal 2023 Avg. Avg. Avg. Volume Price Volume Price Volume Price NYMEX Swaps 149,160 $2.63 128,530 $2.65 23,240 $2.54 Dawn Swaps 600 $3.00 - - - - 2-Way Collars 25,850 $2.28 / $2.77 2,350 $2.28 / $2.77 - - (1) Fixed Price Physical 65,422 $2.20 43,815 $2.30 38,509 $2.29 Total 241,032 174,695 61,749 Crude Oil Volumes & Prices in Bbl Fiscal 2021 Fiscal 2022 Avg. Avg. Price Price Volume Volume Brent Swaps 936,000 $59.45 300,000 $60.07 NYMEX Swaps 156,000 $51.00 156,000 $51.00 Total 1,092,000 $58.24 456,000 $56.97 55 (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 Hedge Positions and Prices Natural Gas Volumes in thousand MMBtu; Prices in $/MMBtu Fiscal 2021 Fiscal 2022 Fiscal 2023 Avg. Avg. Avg. Volume Price Volume Price Volume Price NYMEX Swaps 149,160 $2.63 128,530 $2.65 23,240 $2.54 Dawn Swaps 600 $3.00 - - - - 2-Way Collars 25,850 $2.28 / $2.77 2,350 $2.28 / $2.77 - - (1) Fixed Price Physical 65,422 $2.20 43,815 $2.30 38,509 $2.29 Total 241,032 174,695 61,749 Crude Oil Volumes & Prices in Bbl Fiscal 2021 Fiscal 2022 Avg. Avg. Price Price Volume Volume Brent Swaps 936,000 $59.45 300,000 $60.07 NYMEX Swaps 156,000 $51.00 156,000 $51.00 Total 1,092,000 $58.24 456,000 $56.97 55 (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 Firm Transportation Commitments Volume Delivery Demand Charges Production Source Gas Marketing Strategy (Dth/d) Market ($/Dth) Firm Sales Contracts Northeast Supply Canada $0.50 EDA – Tioga 50,000 Diversification Dawn/NYMEX+ rd (Dawn) (3 party) Tennessee Gas Pipeline 10 years NFG pipelines = $0.24 Firm Sales Contracts 158,000 Canada (Dawn) rd Niagara Expansion 3 party = $0.43 WDA – CRV Dawn/NYMEX+ TGP & NFG - Supply 12,000 TETCO (SE Pa.) $0.12 (NFG pipelines) 8 to 15 years Firm Sales Contracts Atlantic Sunrise Mid-Atlantic/ $0.73 EDA - Lycoming 189,405 NYMEX+ rd WMB - Transco Southeast (3 party) First 5 years Utilize acquired firm sales and TGP 200 (NY) / Tioga County Extension $0.23 (NFG pipelines) 200,000 EDA – Tioga pursue additional firm sales as Canada (Dawn) NFG - Empire needed Capacity release (near-term); rd (1) In-Basin 100,000 $0.14 (3 Party) Dominion EDA – Tioga access to Leidy South project (long-term) Seneca to pursue firm sales Competitive with other Leidy South / FM100 WDA – CRV Transco WMB – Transco; NFG - Supply 330,000 expansion project rates in contracts as project EDA - Lycoming Zone 6 Target in-service: late 2021 Seneca’s portfolio development progresses NFG pipelines = $0.50 350,000 Canada (Dawn) Seneca to pursue firm sales rd 3 party = $0.21 Northern Access WDA – CRV contracts as project NFG – Supply and Empire TGP 200 (NY) 140,000 $0.38 (NFG pipelines) development progresses 56 (1) 100,000 Dth/day on Dominion provides optionality to fill Leidy South. (1) Future Capacity Currently In-ServiceAppendix Firm Transportation Commitments Volume Delivery Demand Charges Production Source Gas Marketing Strategy (Dth/d) Market ($/Dth) Firm Sales Contracts Northeast Supply Canada $0.50 EDA – Tioga 50,000 Diversification Dawn/NYMEX+ rd (Dawn) (3 party) Tennessee Gas Pipeline 10 years NFG pipelines = $0.24 Firm Sales Contracts 158,000 Canada (Dawn) rd Niagara Expansion 3 party = $0.43 WDA – CRV Dawn/NYMEX+ TGP & NFG - Supply 12,000 TETCO (SE Pa.) $0.12 (NFG pipelines) 8 to 15 years Firm Sales Contracts Atlantic Sunrise Mid-Atlantic/ $0.73 EDA - Lycoming 189,405 NYMEX+ rd WMB - Transco Southeast (3 party) First 5 years Utilize acquired firm sales and TGP 200 (NY) / Tioga County Extension $0.23 (NFG pipelines) 200,000 EDA – Tioga pursue additional firm sales as Canada (Dawn) NFG - Empire needed Capacity release (near-term); rd (1) In-Basin 100,000 $0.14 (3 Party) Dominion EDA – Tioga access to Leidy South project (long-term) Seneca to pursue firm sales Competitive with other Leidy South / FM100 WDA – CRV Transco WMB – Transco; NFG - Supply 330,000 expansion project rates in contracts as project EDA - Lycoming Zone 6 Target in-service: late 2021 Seneca’s portfolio development progresses NFG pipelines = $0.50 350,000 Canada (Dawn) Seneca to pursue firm sales rd 3 party = $0.21 Northern Access WDA – CRV contracts as project NFG – Supply and Empire TGP 200 (NY) 140,000 $0.38 (NFG pipelines) development progresses 56 (1) 100,000 Dth/day on Dominion provides optionality to fill Leidy South. (1) Future Capacity Currently In-Service

Appendix EDA Type Curves Lycoming Marcellus Tioga Utica 18 16 14 12 10 8 Estimated Cumulative Volumes (Bcf) Lycoming Tioga 6 Year Marcellus Utica (5,800') (10,000') 1 3.1 6.0 4 5 8.3 14.3 10 10.8 17.6 2 EUR (Bcf) 14.5-16.8 20.0-23.0 NRI 84% 82-87% 0 0 12 24 36 48 60 72 84 96 108 120 57 Months On Cumulative Production (Bcf)Appendix EDA Type Curves Lycoming Marcellus Tioga Utica 18 16 14 12 10 8 Estimated Cumulative Volumes (Bcf) Lycoming Tioga 6 Year Marcellus Utica (5,800') (10,000') 1 3.1 6.0 4 5 8.3 14.3 10 10.8 17.6 2 EUR (Bcf) 14.5-16.8 20.0-23.0 NRI 84% 82-87% 0 0 12 24 36 48 60 72 84 96 108 120 57 Months On Cumulative Production (Bcf)

Appendix WDA Type Curves (1) RV/Beechwood Utica CRV Marcellus 12 Estimated Cumulative Volumes (Bcf) Utica Marcellus Year (10,000') (9,000') 10 1 2.7 1.6 5 7.8 4.2 10 10.5 5.9 EUR (Bcf) 15.0-18.0 9.0-10.8 8 NRI 100% 100% 6 4 2 0 0 12 24 36 48 60 72 84 96 108 120 (1) Type Curve based on the first 19 wells brought online. Months On 58 Cumulative Production (Bcf)Appendix WDA Type Curves (1) RV/Beechwood Utica CRV Marcellus 12 Estimated Cumulative Volumes (Bcf) Utica Marcellus Year (10,000') (9,000') 10 1 2.7 1.6 5 7.8 4.2 10 10.5 5.9 EUR (Bcf) 15.0-18.0 9.0-10.8 8 NRI 100% 100% 6 4 2 0 0 12 24 36 48 60 72 84 96 108 120 (1) Type Curve based on the first 19 wells brought online. Months On 58 Cumulative Production (Bcf)

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 interest and other income, impairments, and other items reflected in operating income that impact comparability. Management defines Free Cash Flow as Funds from Operations less Capital Expenditures. The Company is unable to provide a reconciliation of projected Free Cash Flow as described in this presentation to their 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. While the Company could potentially record non-cash impairments in subsequent quarters depending on the commodity price environment, the amount of these charges is not reasonably determinable at this time. The amount of any ceiling test charge is determined at the end of the applicable quarter and will depend on many factors, including additions to or subtractions from proved reserves, fluctuations in oil and gas prices, and income tax effects related to the differences between the book and tax basis of the Company’s oil and gas properties. Some or all of these factors could be significant. Because any potential ceiling test impairment charges and other potential items impacting comparability are not reasonably determinable at this time, the Company is unable to provide earnings guidance in fiscal 2021 other than on a non-GAAP basis that excludes these items. 59Appendix 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 interest and other income, impairments, and other items reflected in operating income that impact comparability. Management defines Free Cash Flow as Funds from Operations less Capital Expenditures. The Company is unable to provide a reconciliation of projected Free Cash Flow as described in this presentation to their 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. While the Company could potentially record non-cash impairments in subsequent quarters depending on the commodity price environment, the amount of these charges is not reasonably determinable at this time. The amount of any ceiling test charge is determined at the end of the applicable quarter and will depend on many factors, including additions to or subtractions from proved reserves, fluctuations in oil and gas prices, and income tax effects related to the differences between the book and tax basis of the Company’s oil and gas properties. Some or all of these factors could be significant. Because any potential ceiling test impairment charges and other potential items impacting comparability are not reasonably determinable at this time, the Company is unable to provide earnings guidance in fiscal 2021 other than on a non-GAAP basis that excludes these items. 59

Appendix Non-GAAP Reconciliations – Adjusted EBITDA Reconciliation of Adjusted EBITDA to Consolidated Net Income ($ Thousands) (1) (1) FY 2016 FY 2017 FY 2018 FY 2019 FY 2020 Total Adjusted EBITDA Exploration & Production Adjusted EBITDA $ 363, 830 $ 360, 979 $ 317,707 $ 351,159 312,166 Pipeline & Storage Adjusted EBITDA 199,446 180,328 183,972 162,181 189,520 Gathering Adjusted EBITDA 78,685 94,380 91,937 108,292 119,879 Utility Adjusted EBITDA 148,683 151,078 175,554 176,134 171,418 Corporate & All Other Adjusted EBITDA (1,583) (9,725) (7,704) (12,393) (7,529) Total Adjusted EBITDA $ 789, 061 $ 777, 040 $ 761, 466 $ 785, 373 $ 785, 454 Total Adjusted EBITDA $ 789,061 $ 777, 040 $ 761, 466 $ 785, 373 $ 785, 454 Minus: Interest Expense ( 121,044) ( 119,837) ( 114,522) ( 106,756) (117,077) Plus: Other Income (Deductions) 14,055 11,156 (21,174) (15,542) (17,814) Minus: Income Tax Expense 232,549 ( 160,682) 7, 494 (85,221) (18,739) Minus: Depreciation, Depletion & Amortization ( 249,417) ( 224,195) ( 240,961) ( 275,660) ( 306,158) Minus: Impairment of Oil and Gas Properties (E&P) ( 948,307) - - - (449,438) Plus: Reversal of Stock-Based Compensation (all segments) - - - - - Minus: Unrealized Gain (Loss) on Hedge Ineffectiveness 392 ( 100) ( 782) 2, 096 - Minus: Joint Development Agreement Professional Fees (E&P) (7,855) - - - - Rounding - - - - - Consolidated Net Income $ (290,566) $ 283,382 $ 391, 521 $ 304, 290 $ (123,772) Consolidated Debt to Total Adjusted EBITDA Long-Term Debt, Net of Current Portion (End of Period) $ 2,099,000 $ 2,099,000 $ 2,149,000 $ 2,149,000 $ 2,649,000 Current Portion of Long-Term Debt (End of Period) - 300,000 - - - Notes Payable to Banks and Commercial Paper (End of Period) - - - 55,200 30,000 Less: Cash and Temporary Cash Investments (End of Period) ( 129,972) ( 555,530) ( 229,606) (20,428) (20,541) Total Net Debt (End of Period) $ 1,969,028 $ 1,843,470 $ 1,919,394 $ 2,183,772 $ 2,658,459 Long-Term Debt, Net of Current Portion (Start of Period) 2, 099,000 2, 099,000 2, 099,000 2, 149,000 2, 149,000 Current Portion of Long-Term Debt (Start of Period) - - 300,000 - - Notes Payable to Banks and Commercial Paper (Start of Period) - - - - 55,200 Less: Cash and Temporary Cash Investments (Start of Period) ( 113,596) ( 129,972) ( 555,530) ( 229,606) (20,428) Total Net Debt (Start of Period) $ 1,985,404 $ 1,969,028 $ 1,843,470 $ 1,919,394 $ 2,183,772 Average Total Net Debt $ 1,977,216 $ 1,906,249 $ 1,881,432 $ 2,051,583 $ 2,421,116 Average Total Net Debt to Total Adjusted EBITDA 2.51 x 2.45 x 2.47 x 2.61 x 3.08 x (1) Total Adjusted EBITDA for FY 2018, FY 2019, 12 months ended September 30, 2020, include the reclassification of non-service pension costs from Operating and Maintenance Expense to Other Income (Deductions) as of October 1, 2018 on the 60 Company’s Income Statement. This reclassification is not reflected in Total Adjusted EBITDA for FY 2016 or FY 2017.Appendix Non-GAAP Reconciliations – Adjusted EBITDA Reconciliation of Adjusted EBITDA to Consolidated Net Income ($ Thousands) (1) (1) FY 2016 FY 2017 FY 2018 FY 2019 FY 2020 Total Adjusted EBITDA Exploration & Production Adjusted EBITDA $ 363, 830 $ 360, 979 $ 317,707 $ 351,159 312,166 Pipeline & Storage Adjusted EBITDA 199,446 180,328 183,972 162,181 189,520 Gathering Adjusted EBITDA 78,685 94,380 91,937 108,292 119,879 Utility Adjusted EBITDA 148,683 151,078 175,554 176,134 171,418 Corporate & All Other Adjusted EBITDA (1,583) (9,725) (7,704) (12,393) (7,529) Total Adjusted EBITDA $ 789, 061 $ 777, 040 $ 761, 466 $ 785, 373 $ 785, 454 Total Adjusted EBITDA $ 789,061 $ 777, 040 $ 761, 466 $ 785, 373 $ 785, 454 Minus: Interest Expense ( 121,044) ( 119,837) ( 114,522) ( 106,756) (117,077) Plus: Other Income (Deductions) 14,055 11,156 (21,174) (15,542) (17,814) Minus: Income Tax Expense 232,549 ( 160,682) 7, 494 (85,221) (18,739) Minus: Depreciation, Depletion & Amortization ( 249,417) ( 224,195) ( 240,961) ( 275,660) ( 306,158) Minus: Impairment of Oil and Gas Properties (E&P) ( 948,307) - - - (449,438) Plus: Reversal of Stock-Based Compensation (all segments) - - - - - Minus: Unrealized Gain (Loss) on Hedge Ineffectiveness 392 ( 100) ( 782) 2, 096 - Minus: Joint Development Agreement Professional Fees (E&P) (7,855) - - - - Rounding - - - - - Consolidated Net Income $ (290,566) $ 283,382 $ 391, 521 $ 304, 290 $ (123,772) Consolidated Debt to Total Adjusted EBITDA Long-Term Debt, Net of Current Portion (End of Period) $ 2,099,000 $ 2,099,000 $ 2,149,000 $ 2,149,000 $ 2,649,000 Current Portion of Long-Term Debt (End of Period) - 300,000 - - - Notes Payable to Banks and Commercial Paper (End of Period) - - - 55,200 30,000 Less: Cash and Temporary Cash Investments (End of Period) ( 129,972) ( 555,530) ( 229,606) (20,428) (20,541) Total Net Debt (End of Period) $ 1,969,028 $ 1,843,470 $ 1,919,394 $ 2,183,772 $ 2,658,459 Long-Term Debt, Net of Current Portion (Start of Period) 2, 099,000 2, 099,000 2, 099,000 2, 149,000 2, 149,000 Current Portion of Long-Term Debt (Start of Period) - - 300,000 - - Notes Payable to Banks and Commercial Paper (Start of Period) - - - - 55,200 Less: Cash and Temporary Cash Investments (Start of Period) ( 113,596) ( 129,972) ( 555,530) ( 229,606) (20,428) Total Net Debt (Start of Period) $ 1,985,404 $ 1,969,028 $ 1,843,470 $ 1,919,394 $ 2,183,772 Average Total Net Debt $ 1,977,216 $ 1,906,249 $ 1,881,432 $ 2,051,583 $ 2,421,116 Average Total Net Debt to Total Adjusted EBITDA 2.51 x 2.45 x 2.47 x 2.61 x 3.08 x (1) Total Adjusted EBITDA for FY 2018, FY 2019, 12 months ended September 30, 2020, include the reclassification of non-service pension costs from Operating and Maintenance Expense to Other Income (Deductions) as of October 1, 2018 on the 60 Company’s Income Statement. This reclassification is not reflected in Total Adjusted EBITDA for FY 2016 or FY 2017.

Appendix Non-GAAP Reconciliations – Adjusted EBITDA, by Segment Reconciliation of Segment Capital Expenditures to Consolidated Capital Expenditures ($ Thousands) FY 2021 FY 2016 FY 2017 FY 2018 FY 2019 FY 2020 Guidance Capital Expenditures Exploration & Production Capital Expenditures $ 256, 104 $ 253,057 $ 380, 677 $ 491,889 $ 670,455 $350,000 - $390,000 Pipeline & Storage Capital Expenditures $ 114, 250 $ 95,336 $ 92,832 $ 143, 003 $ 166,652 $250,000 - $300,000 Gathering Segment Capital Expenditures $ 54,293 $ 32,645 $ 61,728 $ 49,650 $ 297,806 $30,000 - $40,000 Utility Capital Expenditures $ 98,007 $ 80,867 $ 85,648 $ 95,847 $ 94,273 $90,000 - $100,000 Corporate & All Other Capital Expenditures $ 397 $ 212 $ 222 $ 855 $ 561 Eliminations $ - $ - $ (20,505) $ (1,130) Total Capital Expenditures from Continuing Operations $ 523, 051 $ 462,117 $ 600,602 $ 781,246 $ 1,228,617 $720,000 - $830,000 Plus (Minus) Acquisition of Upstream and Midstream Gathering Assets $ (506,258) Plus (Minus) Accrued Capital Expenditures $ (45,788) 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) $ 36,465 Exploration & Production FY 2016 Accrued Capital Expenditures $ (25,215) $ 25,215 Exploration & Production FY 2015 Accrued Capital Expenditures $ 46,173 $ (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) $ 25,077 Pipeline & Storage FY 2016 Accrued Capital Expenditures $ (18,661) $ 18,661 Pipeline & Storage FY 2015 Accrued Capital Expenditures $ 33,925 $ (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) $ 3,925 Gathering FY 2016 Accrued Capital Expenditures $ (5,355) $ 5,355 Gathering FY 2015 Accrued Capital Expenditures $ 22,416 $ ( 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) $ 6,748 Utility FY 2016 Accrued Capital Expenditures $ (11,203) $ 11,203 Utility FY 2015 Accrued Capital Expenditures $ 16,445 Total Accrued Capital Expenditures $ 58,525 $ ( 11,782) $ (16,597) $ 7,692 $ (6,207) Total Capital Expenditures per Statement of Cash Flows $ 581,576 $ 450, 335 $ 584,004 $ 788, 938 $ 716, 153 $720,000 - $830,000 61Appendix Non-GAAP Reconciliations – Adjusted EBITDA, by Segment Reconciliation of Segment Capital Expenditures to Consolidated Capital Expenditures ($ Thousands) FY 2021 FY 2016 FY 2017 FY 2018 FY 2019 FY 2020 Guidance Capital Expenditures Exploration & Production Capital Expenditures $ 256, 104 $ 253,057 $ 380, 677 $ 491,889 $ 670,455 $350,000 - $390,000 Pipeline & Storage Capital Expenditures $ 114, 250 $ 95,336 $ 92,832 $ 143, 003 $ 166,652 $250,000 - $300,000 Gathering Segment Capital Expenditures $ 54,293 $ 32,645 $ 61,728 $ 49,650 $ 297,806 $30,000 - $40,000 Utility Capital Expenditures $ 98,007 $ 80,867 $ 85,648 $ 95,847 $ 94,273 $90,000 - $100,000 Corporate & All Other Capital Expenditures $ 397 $ 212 $ 222 $ 855 $ 561 Eliminations $ - $ - $ (20,505) $ (1,130) Total Capital Expenditures from Continuing Operations $ 523, 051 $ 462,117 $ 600,602 $ 781,246 $ 1,228,617 $720,000 - $830,000 Plus (Minus) Acquisition of Upstream and Midstream Gathering Assets $ (506,258) Plus (Minus) Accrued Capital Expenditures $ (45,788) 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) $ 36,465 Exploration & Production FY 2016 Accrued Capital Expenditures $ (25,215) $ 25,215 Exploration & Production FY 2015 Accrued Capital Expenditures $ 46,173 $ (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) $ 25,077 Pipeline & Storage FY 2016 Accrued Capital Expenditures $ (18,661) $ 18,661 Pipeline & Storage FY 2015 Accrued Capital Expenditures $ 33,925 $ (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) $ 3,925 Gathering FY 2016 Accrued Capital Expenditures $ (5,355) $ 5,355 Gathering FY 2015 Accrued Capital Expenditures $ 22,416 $ ( 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) $ 6,748 Utility FY 2016 Accrued Capital Expenditures $ (11,203) $ 11,203 Utility FY 2015 Accrued Capital Expenditures $ 16,445 Total Accrued Capital Expenditures $ 58,525 $ ( 11,782) $ (16,597) $ 7,692 $ (6,207) Total Capital Expenditures per Statement of Cash Flows $ 581,576 $ 450, 335 $ 584,004 $ 788, 938 $ 716, 153 $720,000 - $830,000 61

Appendix Non-GAAP Reconciliations – Adjusted Operating Results Three Months Ended Fiscal Year Ended September 30, September 30, 2020 2019 2020 2019 (in thousands except per share amounts) $ (145,545) $ 47,281 $ (123,772) $ 304,290 Reported GAAP Earnings Items impacting comparability: Impairment of oil and gas properties (E&P) 253,441 — 449,438 — Tax impact of impairment of oil and gas properties (69,698) — (123,187) — Deferred tax valuation allowance as of March 31, 2020 — — 56,770 — Remeasurement of deferred income taxes under 2017 Tax Reform — — — (5,000) Mark-to-market adjustments due to hedge ineffectiveness (E&P) — (1,313) — (2,096) Tax impact of mark-to-market adjustments due to hedge ineffectiveness — 276 — 440 Unrealized (gain) loss on other investments (Corporate / All Other) (2,439) 949 (1,645) 2,045 Tax impact of unrealized (gain) loss on other investments 512 (199) 345 (429) $ 36,271 $ 46,994 $ 257,949 $ 299,250 Adjusted Operating Results Reported GAAP Earnings Per Share $ (1.60) $ 0.54 $ (1.41) $ 3.51 Items impacting comparability: Impairment of oil and gas properties, net of tax (E&P) 2.02 — 3.71 — Deferred tax valuation allowance as of March 31, 2020 — — 0.65 — Remeasurement of deferred income taxes under 2017 Tax Reform — — — (0.06) Mark-to-market adjustments due to hedge ineffectiveness, net of tax (E&P) — (0.01) — (0.02) Unrealized (gain) loss on other investments, net of tax (Corporate / All Other) (0.02) 0.01 (0.01) 0.02 Earnings per share impact of diluted shares — — (0.02) — $ 0.40 $ 0.54 $ 2.92 $ 3.45 Adjusted Operating Results Per Share 62Appendix Non-GAAP Reconciliations – Adjusted Operating Results Three Months Ended Fiscal Year Ended September 30, September 30, 2020 2019 2020 2019 (in thousands except per share amounts) $ (145,545) $ 47,281 $ (123,772) $ 304,290 Reported GAAP Earnings Items impacting comparability: Impairment of oil and gas properties (E&P) 253,441 — 449,438 — Tax impact of impairment of oil and gas properties (69,698) — (123,187) — Deferred tax valuation allowance as of March 31, 2020 — — 56,770 — Remeasurement of deferred income taxes under 2017 Tax Reform — — — (5,000) Mark-to-market adjustments due to hedge ineffectiveness (E&P) — (1,313) — (2,096) Tax impact of mark-to-market adjustments due to hedge ineffectiveness — 276 — 440 Unrealized (gain) loss on other investments (Corporate / All Other) (2,439) 949 (1,645) 2,045 Tax impact of unrealized (gain) loss on other investments 512 (199) 345 (429) $ 36,271 $ 46,994 $ 257,949 $ 299,250 Adjusted Operating Results Reported GAAP Earnings Per Share $ (1.60) $ 0.54 $ (1.41) $ 3.51 Items impacting comparability: Impairment of oil and gas properties, net of tax (E&P) 2.02 — 3.71 — Deferred tax valuation allowance as of March 31, 2020 — — 0.65 — Remeasurement of deferred income taxes under 2017 Tax Reform — — — (0.06) Mark-to-market adjustments due to hedge ineffectiveness, net of tax (E&P) — (0.01) — (0.02) Unrealized (gain) loss on other investments, net of tax (Corporate / All Other) (0.02) 0.01 (0.01) 0.02 Earnings per share impact of diluted shares — — (0.02) — $ 0.40 $ 0.54 $ 2.92 $ 3.45 Adjusted Operating Results Per Share 62

Appendix Non-GAAP Reconciliations – Capital Expenditures Reconciliation of Segment Capital Expenditures to Consolidated Capital Expenditures ($ Thousands) FY 2021 FY 2016 FY 2017 FY 2018 FY 2019 FY 2020 Guidance Capital Expenditures Exploration & Production Capital Expenditures $ 256,104 $ 253,057 $ 380,677 $ 491,889 $ 670, 455 $350,000 - $390,000 Pipeline & Storage Capital Expenditures $ 114,250 $ 95,336 $ 92,832 $ 143,003 $ 166, 652 $250,000 - $300,000 Gathering Segment Capital Expenditures $ 54,293 $ 32,645 $ 61,728 $ 49,650 $ 297,806 $30,000 - $40,000 Utility Capital Expenditures $ 98,007 $ 80,867 $ 85,648 $ 95,847 $ 94,273 $90,000 - $100,000 Corporate & All Other Capital Expenditures $ 397 $ 212 $ 222 $ 855 $ 561 Eliminations $ - $ - $ ( 20,505) $ (1,130) Total Capital Expenditures from Continuing Operations $ 523, 051 $ 462, 117 $ 600,602 $ 781,246 $ 1,228,617 $720,000 - $830,000 Plus (Minus) Acquisition of Upstream Assets and Midstream Gathering Assets $ (506,258) Plus (Minus) Accrued Capital Expenditures $ (45,788) 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) $ 36,465 Exploration & Production FY 2016 Accrued Capital Expenditures $ (25,215) $ 25,215 Exploration & Production FY 2015 Accrued Capital Expenditures $ 46,173 $ (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) $ 25,077 Pipeline & Storage FY 2016 Accrued Capital Expenditures $ ( 18,661) $ 18,661 Pipeline & Storage FY 2015 Accrued Capital Expenditures $ 33,925 $ (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) $ 3,925 Gathering FY 2016 Accrued Capital Expenditures $ (5,355) $ 5,355 Gathering FY 2015 Accrued Capital Expenditures $ 22,416 $ (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) $ 6,748 Utility FY 2016 Accrued Capital Expenditures $ (11,203) $ 11,203 Utility FY 2015 Accrued Capital Expenditures $ 16,445 Total Accrued Capital Expenditures $ 58,525 $ (11,782) $ (16,597) $ 7,692 $ (6,206) Total Capital Expenditures per Statement of Cash Flows $ 581,576 $ 450, 335 $ 584,004 $ 788, 938 $ 716, 153 $720,000 - $830,000 63Appendix Non-GAAP Reconciliations – Capital Expenditures Reconciliation of Segment Capital Expenditures to Consolidated Capital Expenditures ($ Thousands) FY 2021 FY 2016 FY 2017 FY 2018 FY 2019 FY 2020 Guidance Capital Expenditures Exploration & Production Capital Expenditures $ 256,104 $ 253,057 $ 380,677 $ 491,889 $ 670, 455 $350,000 - $390,000 Pipeline & Storage Capital Expenditures $ 114,250 $ 95,336 $ 92,832 $ 143,003 $ 166, 652 $250,000 - $300,000 Gathering Segment Capital Expenditures $ 54,293 $ 32,645 $ 61,728 $ 49,650 $ 297,806 $30,000 - $40,000 Utility Capital Expenditures $ 98,007 $ 80,867 $ 85,648 $ 95,847 $ 94,273 $90,000 - $100,000 Corporate & All Other Capital Expenditures $ 397 $ 212 $ 222 $ 855 $ 561 Eliminations $ - $ - $ ( 20,505) $ (1,130) Total Capital Expenditures from Continuing Operations $ 523, 051 $ 462, 117 $ 600,602 $ 781,246 $ 1,228,617 $720,000 - $830,000 Plus (Minus) Acquisition of Upstream Assets and Midstream Gathering Assets $ (506,258) Plus (Minus) Accrued Capital Expenditures $ (45,788) 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) $ 36,465 Exploration & Production FY 2016 Accrued Capital Expenditures $ (25,215) $ 25,215 Exploration & Production FY 2015 Accrued Capital Expenditures $ 46,173 $ (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) $ 25,077 Pipeline & Storage FY 2016 Accrued Capital Expenditures $ ( 18,661) $ 18,661 Pipeline & Storage FY 2015 Accrued Capital Expenditures $ 33,925 $ (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) $ 3,925 Gathering FY 2016 Accrued Capital Expenditures $ (5,355) $ 5,355 Gathering FY 2015 Accrued Capital Expenditures $ 22,416 $ (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) $ 6,748 Utility FY 2016 Accrued Capital Expenditures $ (11,203) $ 11,203 Utility FY 2015 Accrued Capital Expenditures $ 16,445 Total Accrued Capital Expenditures $ 58,525 $ (11,782) $ (16,597) $ 7,692 $ (6,206) Total Capital Expenditures per Statement of Cash Flows $ 581,576 $ 450, 335 $ 584,004 $ 788, 938 $ 716, 153 $720,000 - $830,000 63

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, 2020 September 30, 2019 (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 $136,994 $0 $136,994 $0.61 $0.00 $0.57 $118,023 $0 $118,023 $0.60 $0.00 $0.56 Other Lease Operating Expense $16,527 $50,149 $66,676 $0.07 $18.85 $0.28 $13,474 $55,129 $68,604 $0.07 $20.81 $0.32 Lease Operating and Transportation Expense $153,521 $50,149 $203,670 $0.68 $18.85 $0.84 $131,497 $55,129 $186,626 $0.67 $20.81 $0.88 General & Administrative Expense $63,429 $0.26 $64,003 $0.30 All Other Operating and Maintenance Expense $12,542 $0.05 $11,130 $0.05 Property, Franchise and Other Taxes $15,646 $0.06 $17,725 $0.08 Total Taxes & Other $28,188 $0.12 $28,855 $0.14 Depreciation, Depletion & Amortization $172,123 $0.71 $154,784 $0.73 Production: Gas Production (MMcf) 225,513 1,889 227,402 195,906 1,974 197,880 Oil Production (MBbl) 3 2,345 2,348 3 2,320 2,323 Total Production (Mmcfe) 225,529 15, 958 241,487 195,926 15, 893 211,819 Total Production (Mboe) 37,588 2,660 40,248 32,654 2,649 35, 303 (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. 64Appendix 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, 2020 September 30, 2019 (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 $136,994 $0 $136,994 $0.61 $0.00 $0.57 $118,023 $0 $118,023 $0.60 $0.00 $0.56 Other Lease Operating Expense $16,527 $50,149 $66,676 $0.07 $18.85 $0.28 $13,474 $55,129 $68,604 $0.07 $20.81 $0.32 Lease Operating and Transportation Expense $153,521 $50,149 $203,670 $0.68 $18.85 $0.84 $131,497 $55,129 $186,626 $0.67 $20.81 $0.88 General & Administrative Expense $63,429 $0.26 $64,003 $0.30 All Other Operating and Maintenance Expense $12,542 $0.05 $11,130 $0.05 Property, Franchise and Other Taxes $15,646 $0.06 $17,725 $0.08 Total Taxes & Other $28,188 $0.12 $28,855 $0.14 Depreciation, Depletion & Amortization $172,123 $0.71 $154,784 $0.73 Production: Gas Production (MMcf) 225,513 1,889 227,402 195,906 1,974 197,880 Oil Production (MBbl) 3 2,345 2,348 3 2,320 2,323 Total Production (Mmcfe) 225,529 15, 958 241,487 195,926 15, 893 211,819 Total Production (Mboe) 37,588 2,660 40,248 32,654 2,649 35, 303 (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. 64