NATIONAL FUEL GAS CO false 0000070145 0000070145 2022-08-04 2022-08-04

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

FORM 8-K

 

 

CURRENT REPORT

Pursuant to Section 13 or 15(d)

of the Securities Exchange Act of 1934

Date of Report (Date of earliest event reported): August 4, 2022

 

 

NATIONAL FUEL GAS COMPANY

(Exact name of registrant as specified in its charter)

 

 

 

New Jersey   1-3880   13-1086010
(State or other jurisdiction
of incorporation)
 

(Commission

File Number)

  (IRS Employer
Identification No.)

 

  6363 Main Street, Williamsville, New York   14221
  (Address of principal executive offices)   (Zip Code)

Registrant’s telephone number, including area code: (716) 857-7000

Former name or former address, if changed since last report: Not Applicable

 

 

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions (see General Instruction A.2. below):

 

Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

 

Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

 

Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

 

Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

Securities registered pursuant to Section 12(b) of the Act:

 

Title of each class

 

Trading
Symbol

 

Name of Each Exchange

on Which Registered

Common Stock, par value $1.00 per share   NFG   New York Stock Exchange

Indicate by check mark whether the registrant is an emerging growth company as defined in Rule 405 of the Securities Act of 1933 (§230.405 of this chapter) or Rule 12b-2 of the Securities Exchange Act of 1934 (§240.12b-2 of this chapter).

Emerging growth company

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

 

 

 


Item 7.01

Regulation FD Disclosure.

On August 4, 2022, National Fuel Gas Company (the “Company”) updated its Investor Presentation. A copy of the presentation is furnished as part of this Current Report as Exhibit 99.

Neither the furnishing of the presentation as an exhibit to this Current Report nor the inclusion in such presentation of any reference to the Company’s internet address shall, under any circumstances, be deemed to incorporate the information available at such internet address into this Current Report. The information available at the Company’s internet address is not part of this Current Report or any other report filed or furnished by the Company with the Securities and Exchange Commission.

In addition to financial measures calculated in accordance with generally accepted accounting principles (“GAAP”), the presentation furnished as part of this Current Report as Exhibit 99 contains certain non-GAAP financial measures. The Company believes that such non-GAAP financial measures are useful to investors because they provide an alternative method for assessing the Company’s operating results in a manner that is focused on the performance of the Company’s ongoing operations, for measuring the Company’s cash flow and liquidity, and for comparing the Company’s financial performance to other companies. The Company’s management uses these non-GAAP financial measures for the same purpose, and for planning and forecasting purposes. The presentation of non-GAAP financial measures is not meant to be a substitute for financial measures prepared in accordance with GAAP.

Certain statements contained herein or in the press release furnished as part of this Current Report, including statements regarding estimated future earnings and statements that are identified by the use of the words “anticipates,” “estimates,” “expects,” “forecasts,” “intends,” “plans,” “predicts,” “projects,” “believes,” “seeks,” “will” and “may” and similar expressions, are “forward-looking statements” as defined by the Private Securities Litigation Reform Act of 1995. There can be no assurance that the Company’s projections will in fact be achieved nor do these projections reflect any acquisitions or divestitures that may occur in the future. While the Company’s expectations, beliefs and projections are expressed in good faith and are believed to have a reasonable basis, actual results may differ materially from those projected in forward-looking statements. Furthermore, each forward-looking statement speaks only as of the date on which it is made. In addition to other factors, the following are important factors that could cause actual results to differ materially from those discussed in the forward-looking statements: changes in laws, regulations or judicial interpretations to which the Company is subject, including those involving derivatives, taxes, safety, employment, climate change, other environmental matters, real property, and exploration and production activities such as hydraulic fracturing; governmental/regulatory actions, initiatives and proceedings, including those involving rate cases (which address, among other things, target rates of return, rate design and retained natural gas and system modernization), environmental/safety requirements, affiliate relationships, industry structure, and franchise renewal; the Company’s ability to estimate accurately the time and resources necessary to meet emissions targets; governmental/regulatory actions and/or market pressures to reduce or eliminate reliance on natural gas; changes in economic conditions, including inflationary pressures and global, national or regional recessions,

 


and their effect on the demand for, and customers’ ability to pay for, the Company’s products and services; changes in the price of natural gas; the creditworthiness or performance of the Company’s key suppliers, customers and counterparties; the length and severity of the ongoing COVID-19 pandemic, including its impacts across our businesses on demand, operations, global supply chains and liquidity; financial and economic conditions, including the availability of credit, and occurrences affecting the Company’s ability to obtain financing on acceptable terms for working capital, capital expenditures and other investments, including any downgrades in the Company’s credit ratings and changes in interest rates and other capital market conditions; impairments under the SEC’s full cost ceiling test for natural gas; increased costs or delays or changes in 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; the Company’s ability to successfully integrate acquired assets and achieve expected cost synergies; changes in price differentials between similar quantities of natural gas sold at different geographic locations, and the effect of such changes on commodity production, revenues and demand for pipeline transportation capacity to or from such locations; the impact of information technology disruptions, cybersecurity or data security breaches; factors affecting the Company’s ability to successfully identify, drill for and produce economically viable natural gas reserves, including among others geology, lease availability, title disputes, weather conditions, shortages, delays or unavailability of equipment and services required in drilling operations, insufficient gathering, processing and transportation capacity, the need to obtain governmental approvals and permits, and compliance with environmental laws and regulations; increasing health care costs and the resulting effect on health insurance premiums and on the obligation to provide other post-retirement benefits; other changes in price differentials between similar quantities of natural gas having different quality, heating value, hydrocarbon mix or delivery date; the cost and effects of legal and administrative claims against the Company or activist shareholder campaigns to effect changes at the Company; negotiations with the collective bargaining units representing the Company’s workforce, including potential work stoppages during negotiations; uncertainty of gas reserve estimates; significant differences between the Company’s projected and actual production levels for natural gas; changes in demographic patterns and weather conditions (including those related to climate change); changes in the availability, price or accounting treatment of derivative financial instruments; changes in laws, actuarial assumptions, the interest rate environment and the return on plan/trust assets related to the Company’s pension and other post-retirement benefits, which can affect future funding obligations and costs and plan liabilities; economic disruptions or uninsured losses resulting from major accidents, fires, severe weather, natural disasters, terrorist activities or acts of war; 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. The Company disclaims any obligation to update any forward-looking statements to reflect events or circumstances after the date hereof.

 


Item 9.01

Financial Statements and Exhibits.

 

  (d)

Exhibits

 

Exhibit 99    Investor Presentation dated August 2022
Exhibit 104    Cover Page Interactive Data File (embedded within the Inline XBRL document).

 


SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.

 

NATIONAL FUEL GAS COMPANY
By:  

/s/ Sarah J. Mugel

  Sarah J. Mugel
  General Counsel and Secretary

Dated: August 4, 2022


EX-99

Exhibit 99 Investor Presentation Q3 Fiscal 2022 Update August 4, 2022


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. 2


NFG: A Diversified, Integrated Natural Gas Company Developing our large, high-quality Upstream acreage position in Marcellus & Exploration & Utica shales Production ~1.2 Million ~980 MMcf/day 52% of NFG Net acres in Net Appalachian natural (1) EBITDA (2) Appalachia gas production Expanding and modernizing pipeline Midstream infrastructure to provide outlets for Gathering Appalachian natural gas production Pipeline & Storage ~4.5 MMDth $2.2 Billion 35% of NFG 38% of NFG Daily interstate Investments (1) (1) EBITDA EBITDA pipeline capacity since 2010 under contract Providing safe, reliable and Downstream affordable service to customers in Utility WNY and NW Pa. % of NFG $359 Million 753,000 13% of NFG (1) 20EBITDA (1) Investments in safety Utility EBITDA customers since 2017 Note: This presentation includes forward-looking statements. Please review the safe harbor for forward looking statements at the end of this presentation. (1) Twelve months ended June 30, 2022. A reconciliation of Adjusted EBITDA to Net Income as presented on the Consolidated Statement of Income and Earnings Reinvested in the Business is included at the end of this presentation. 3 (2) Average net Appalachian production for the three months ended June 30, 2022. Total net Seneca production for the three months ended June 30, 2022 was ~1,020 MMcf/day.


Why National Fuel? Diversified Assets Provide Stability and Long-Term Growth Opportunities Integrated Model Enhances Shareholder Value 1 Expect to Generate Significant Free Cash Flow in Fiscal 2022 and Beyond 2 Optimization of Interstate Pipeline System Drives Future Expected Opportunities 3 Long History of Returning Capital to Shareholders 4 Focused on Corporate Responsibility and ESG 5 4


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


. . . and Continues to Drive Growth Opportunities Near Term Strategy Leverages Integration Across the Value Chain Pipeline & Exploration & Gathering Utility Storage Production ü Integrated Upstream and Midstream development of high-quality Appalachian assets § ~1.2 million net acres in the Marcellus and Utica shales § NFG’s gathering systems move Seneca’s natural gas production, driving consolidated returns § NFG’s interstate pipelines support Appalachian development and provide firm takeaway capacity ü Develop further expansion of interstate pipeline systems to satisfy natural gas supply and demand § Supply push – Appalachian producers § Demand pull – regional demand-driven projects and utilities ü Ongoing investment in safety and modernization of pipeline transportation and distribution systems § $500+ million in new investments expected over the next 5 years (1) ü Expect to generate significant consolidated free cash flow in fiscal year 2022 and beyond 6 (1) The Company defines free cash flow at the end of this presentation.


Consolidated Business Expected to Generate Significant Free Cash Flow . . .. 2 . . . With Sustainable, Growing Free Cash Flow Generation . . . In Fiscal 2022 and Fiscal 2023. . . Expected Over the Long-Term Annualized Dividend Free Cash Flow ü Consolidated capital expenditure optimization to maximize long- $500 term free cash flow growth $450 ~$425 § Exploration & Production / Gathering: focus on enhancing ~$375 $400 returns through ongoing operating efficiencies and just-in-time build-out of supporting gathering facilities $350 ~$325 ~$300 § Pipeline & Storage / Utility: current plans focus on modernizing $300 our transportation, storage, and distribution infrastructure, $250 while leveraging existing facilities to drive further potential growth opportunities $200 ü Regulated businesses expected to generate stable, predictable $150 earnings and cash flows $100 ü Mitigation of Upstream business commodity risk through $50 consistent hedging and marketing program, while maintaining $0 upside to rising commodity prices (2) $5.75 $6.25 $6.75 FY 2022E $1.00 $2.00 $3.00 $4.00 ü Improvement of investment grade credit profile through FY 2023 @ NYMEX Price ($/MMBtu) consistent free cash flow generation (1) Consolidated free cash flow. The Company defines free cash flow at the end of this presentation. Assumes current hedges. 7 (2) Assumes current hedges and commodity price assumptions for the remainder of fiscal 2022. Excludes after-tax cash net proceeds related to the sale of California properties. (1) Free Cash Flow ($ Millions)


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


4 Over Half Century of Dividend Growth 52 Years 120 Years $1.90 2.7% Consecutive Dividend Increases Consecutive Payments (1) per share yield $1.4 Billion 4.4% Dividend payments over last 10 years 2022 Dividend Increase $0.19 per share Annual Rate at Fiscal Year End 9 (1) As of August 2, 2022.


5 Focused on Corporate Responsibility and ESG Recently Published Inaugural Climate Report Provides Enhanced Climate-Risk Disclosures, Responsive to Key Stakeholder Priorities ü Alignment with TCFD – report further aligns the Company’s climate-risk disclosures with the TCFD framework ü Evaluating our Resilience to Climate Scenarios – report evaluated the resilience of our operations to potential transitional and physical risks associated with climate change, including a less than 2-degree Celsius scenario § Transitional Risk – “analysis showed that National Fuel can continue to operate profitably and generate free cash flow through 2050 even using the IEA’s long-term natural gas price of $2.00 per dekatherm and dramatically reduced demand” § Physical Risk – “comprehensive review of future physical risks across our businesses indicated that there is relatively low financial risk from climate hazards in 2030 and 2050 to our facilities and operations” ü Identifying Climate Related Opportunities – “significant pipeline assets provide the Company with potential long-term opportunities to transport and store low and zero-carbon fuels” 10


Emissions Reduction Targets and Initiatives Significant Methane Intensity and Greenhouse Gas Emissions Reduction Ongoing Sustainability Initiatives (1) Targets Across the Energy Value Chain ü ONE Future NFG 25% Reduction in GHG Emissions by 2030 ü EPA Methane Challenge ü Responsible Gas Certifications Exploration & 40% Reduction in Methane Intensity by 2030 ü Pneumatic Device Replacement Production ü Use of Best-in-Class Emissions Controls for Gathering 30% Reduction in Methane Intensity by 2030 New Facilities ü Equipment upgrades at Existing Facilities v 50% Reduction in Methane Intensity by 2030 Pipeline & Storage ü Use of Best-in-Class Emissions Controls for New Facilities ü Investment in System Modernization v 30% Reduction in Methane Intensity by 2030 ü Low Carbon Resources Initiative v 75% Reduction in delivery system GHG emissions by 2030 Utility ü Advancing RNG in Service Territory ü Evaluation of Hydrogen v 90% Reduction in delivery system GHG emissions by 2050 11 (1) All emissions reduction targets based on 2020 baseline, except Utility reduction in delivery system targets (1990 baseline).


Third Quarter Fiscal 2022 Financial Highlights 12


Third Quarter Fiscal 2022 Results and Drivers (1) Adjusted Operating Results ($/share) Q3 FY 2021 Q3 FY 2022 Major Drivers $1.54 $2.87 Natural Gas Prices $2.20 Exploration & Production $0.93 $0.95 Exploration & Natural Gas Production / 92.4 Production 83.1 Gathering Throughput $0.43 Gathering Gathering $0.27 $0.22 Pipeline & Storage Pipeline & Storage $0.29 $0.24 $95.5 $84.1 Utility $0.05 Utility $0.05 FM100 Project Revenue MM Corporate/Other: ($0.01) Corporate/Other: ($0.02) MM Q3 FY21 Q3 FY22 (1) A Reconciliation of Adjusted Operating Results to Earnings Per Share is provided at the end of this presentation. 13 (2) Realized price after hedging. Pipeline and Storage Net Gas Production Natural Gas Pricing (2) Revenue ($MM) (Bcf) ($/Mcfe)


Earnings Guidance FY2022 Adjusted Operating Results FY2023 Preliminary Earnings Guidance (1) $5.85 to $5.95/share $7.25 to $7.75/share Key Guidance Drivers § 370-390 Bcfe (up 8% vs. FY22E) Net Production (2) Realized natural gas prices (after-hedge)§ ~$3.34/Mcf (vs. ~$2.72/Mcf in FY22E) Exploration & (1) G&A Expense § $0.17-$0.19/Mcf (vs. $0.20/Mcf in FY22E) Production DD&A Expense § $0.60-$0.64/Mcf (vs. $0.58/Mcf in FY22E) LOE Expense § $0.67-$0.69/Mcf (vs. $0.80/Mcf in FY22E) Gathering Revenues § $235-$250 million (up 13% vs. FY22E) Gathering Gathering O&M Expense § ~$0.09/Mcf of throughput Pipeline & Storage Revenues § $360-$380 million Pipeline & Storage O&M Expense § ~5% increase Pipeline & Pipeline & Storage Storage Pipeline & Storage Depreciation Expense § ~5% increase due primarily to FM100 Project Utility Operating Income Utility§ Return to normal weather / increased operating expenses Utility Utility Other Income § ~$1-3 million decrease in post retirement benefit income Tax Rate Effective Tax Rate § ~25.5-26% (Loss of Enhanced Oil Recovery credit) (1) Excludes items impacting comparability. See Comparable GAAP Financial Measure Slides & Reconciliations at the end of this presentation. (2) Assumes NYMEX pricing of $7.50/MMBtu and in-basin spot pricing of $6.50/MMBtu for winter and $5.00/MMBtu and in-basin spot pricing of $3.90 for summer fiscal 2023, and reflects the impact of existing financial hedges, firm sales and firm transportation contracts. 14 Regulated Non-Regulated


Exploration & Production & 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 400 ü Continue two rig development program with focus on maximizing returns and cash flows, targeting 300 mid-to-high single digit production growth 200 370-390 350-355 327.4 § EDA share of total drilling and completion 241.5 211.8 100 178.1 activity increasing 0 2018 2019 2020 2021 2022E 2023E§ Gross production growth will benefit NFG Gathering segment (1) E&P Net Capital Expenditures ($ millions) $600 ü EDA Tioga: development focused primarily on Utica (modest Marcellus activity) $500 $400 ü EDA Lycoming: activity maintains production level $525- $300 $525- that fully utilizes valuable Atlantic Sunrise capacity $492 $575 $550 $200 $384 $381 $356 ü WDA: development focused on Utica Shale, with $100 return trips in Clermont-Rich Valley area $0 2018 2019 2020 2021 2022E 2023E (1) A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation. FY18 reflects the netting of $17 million of up-front proceeds received from joint development partner for working interest in joint 16 development wells. FY20 reflects the netting of $286 million related to the acquisition of Appalachian upstream assets in July 2020.


E&P and Gathering Significant Appalachian Acreage Position ~1,000 Economic Drilling Locations (1) at $2.50 NYMEX Prices ( ) ü Decades of highly-economic inventory ( ) (~40 wells per year at current 2-rig pace) ü Large, contiguous acreage position, driving increased capital efficiency ü Development supported by wholly-owned gathering infrastructure, enhancing returns Development Locations at 20% IRR (()) 2,000 Utica Marcellus 1,500 1,000 500 EASTERN 0 $2.00 $2.25 $2.50 $2.75 $3.00 NYMEX Price ($/MMBtu) (1) Drilling locations with expected consolidated Exploration & Production and Gathering segments pre-tax IRR’s at 20%. 17 (2) Seneca Appalachian acreage is fee-owned, or leased from either the Pennsylvania Department of Conservation and Natural Resources or private landowners.


E&P and Gathering Eastern Development Area Seneca EDA Highlights EDA – ~270,000 Acres 1 Tioga County, PA ü ~150 undeveloped Utica locations ü ~90 undeveloped Marcellus locations ü Gathering infrastructure: NFG Tioga gathering systems ü Numerous marketing opportunities: § Ability to utilize Seneca’s firm transportation capacity: Empire Tioga County Extension, Leidy South and Northeast Supply Diversification 1 § Interconnections with multiple interstate pipelines: Empire, Eastern, TGP (300 Line), UGI 2 Lycoming County, PA 2 ü ~30 remaining Marcellus locations ü Geneseo Shale expected to provide return trip locations ü Gathering infrastructure: NFG Midstream Trout Run ü Firm transportation capacity: Atlantic Sunrise (189 MDth/d) 18


E&P and Gathering EDA: Tioga County Development Large Contiguous Acreage Position, with Highly-Economic Utica and Marcellus Inventory Tioga Development Plan Significant Tioga County Acreage Position ü Significant additional assets acquired in mid-2020, contiguous to NFG’s existing Tioga County production and gathering operations Undeveloped Utica ü Near-term development expected to focus on acquired and DCNR Tract 007 pads Undeveloped § Utica average lateral length of 10,000-11,000’ and Marcellus consolidated well costs of $1,200-$1,300/ft (1) § Acceleration of Tioga County development increases upfront investment in upstream and gathering infrastructure § More intensive completion design results in improved performance and better expected IRRs ü Continuing to optimize consolidated upstream and gathering development plan across expanded Tioga footprint 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 (1) § Total Investment (to date): ~$240 million § Capacity: up to 550,000 Dth per day (Interconnects with Empire, Eastern, and TGP 300) § Production Source: Seneca Resources (acquired Tioga acreage and future development) and Third-Party § NFG Covington Gathering System tie-in provides access to Eastern and Empire markets ü Covington Gathering System § Total Investment (to date): ~$50 million § Capacity: 220,000 Dth per day (Interconnect w/ TGP 300 line) § Production Source: Seneca Resources (Covington & DCNR Tract 595) ü Wellsboro Gathering System § Total Investment (to date): ~$42 million § Capacity: up to 200,000 Dth per day (Interconnect w/ TGP 300 line) § Production Source: Seneca Resources (DCNR Tract 007) 20 (1) Includes Company’s acquisition of midstream gathering assets in July 2020, in the amount of ~$223 million.


E&P and Gathering EDA: Tioga County Development Production Underpinned by Firm Sales and Firm Transportation Contracts Tioga County Gas Marketing Strategy Tioga County Gross Firm Contract Volumes (MDth/d) 500 ü Production supported by firm transportation capacity to premium markets: 450 400 Leidy South Firm Sales § 250 MDth/d (Empire-NFG & Northeast Supply Diversification Project) provides *Capacity can be utilized by all three producing areas 350 (WDA, EDA-Tioga, and EDA-Lycoming) access to Dawn/TGP 200 markets 300 § Tioga production can be utilized to fill a 250 portion of Leidy South expansion Tioga County Extension (NFG - Empire) capacity 200 FT Capacity: 185,000 - 200,000 Dth/d 150 ü Seneca’s firm transportation and firm sales support DCNR Tract 007, DCNR Tract 595, 100 and Covington area production (1) EDA - TGP 300 Firm Sales 50 Northeast Supply Diversification Project FT Capacity: 50,000 Dth/d - Jul-22 Oct-22 Jan-23 Apr-23 Jul-23 Oct-23 21 (1) Includes physical fixed price and NYMEX-based firm sales contracts that do not carry any additional transportation costs.


E&P and Gathering EDA: Lycoming County Development Marcellus Development in Lycoming County Fully Utilizes Valuable Firm Transportation ü Prolific Marcellus acreage with average EUR of 2.5-3.0 Bcf / 1,000 ft ü ~30 remaining Marcellus locations § Average lateral length of 6,500-7,500’ and consolidated well costs of $1,050-$1,150/ft ü Potential for return trip Geneseo development EDA - Transco Firm Contracts 300 250 (1) Leidy South Firm Sales (2) 200 Transco Firm Sales 150 Atlantic Sunrise (Transco) FT Capacity: 189,405 Dth/d 100 Firm Sales: NYMEX/Market Indices 50 - Jul-22 Oct-22 Jan-23 Apr-23 Jul-23 Oct-23 (1) Capacity can be utilized by all three producing areas (WDA, EDA-Tioga, and EDA-Lycoming). 22 (2) 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 Third-Party Development Current System In-Service Trout Run Gathering System Map ü Total Investment (to date): ~$273 million ü Capacity: 466,000 to 585,000 Dth per day ü Current Production Source: Seneca Resources (DCNR Tract 100 & Gamble) & Third-Party ü Interconnect: Transco (Leidy Line) Third-Party Volumes ü Gathering contracts executed, with volumes first online in November 2020 § Completed construction of new facilities, leveraging existing Trout Run system ü Expected to generate third-party revenues of $10 - $12 million in fiscal 2022 and $15 - $18 million for fiscal 2023 (supported by minimum volume commitments) 23


E&P and Gathering Western Development Area (1) Marcellus Core Acreage vs. Utica Trend WDA Highlights ü Large well inventory: § Marcellus Shale: 600+ well locations remaining / 200,000 acres § Utica Shale: 500+ potential locations across Utica trend (2) / evaluating extent of prospective acreage ü Fee acreage (no royalty) enhances economics and provides development flexibility ü Highly contiguous position drives best in class well costs and program efficiencies Beechwood Utica Development Area ü Long-term firm contracts provide access to premium markets and support growth Boone Mountain Utica Test Well ü Early Beechwood area results are encouraging Past Marcellus delineation tests Utica Trend (currently evaluating) ? Marcellus Core Acreage (1) The Utica Shale lies approximately 5,000 feet beneath Seneca’s WDA Marcellus acreage. 24 (2) Appraisal program currently in progress. Prior Marcellus delineation tests helped define the prospective limits of the Marcellus core acreage; planned testing in the Utica is expected to do the same.


E&P and Gathering Integrated Development – WDA Gathering System Gathering System Build-Out Tailored to Accommodate Seneca’s WDA Development Clermont Gathering System Map Current System In-Service § Capacity: 750 MMcf per day § Interconnects with TGP 300 and NFG Supply § Total Investment (to date): $363 million § 40,620 HP of compression (3 stations) Future Build-Out § Modest gathering pipeline and compression investment required to support Seneca’s Utica return-trip development § Beechwood development expected to require installation of new in-field gathering lines and incremental compression at existing centralized station. 25


E&P and Gathering WDA Firm Transportation and Sales Capacity WDA Exit Capacity Supports Production and Enhances Consolidated Returns WDA Gas Marketing Strategy WDA Contracted Firm Transport and Gross Sales Volumes (MDth/d) 500 ü Will continue to layer-in firm sales deals of short and longer duration on TGP 300 to reduce spot 400 Leidy South Firm Sales exposure *Capacity can be utilized by all three producing areas (WDA, EDA-Tioga, and EDA-Lycoming) 300 ü WDA spot realizations track TGP Station 313 pricing, typically 15¢ - WDA - TGP 300 Firm Sales 200 20¢ better than TGP Marcellus Zone 4 100 Niagara Expansion Project (TGP and NFG) NYMEX & Dawn ü Leidy South provides additional 158,000 Dth/d capacity to premium markets - (Transco Zone 6 NNY) 26


E&P and Gathering Long-term Contracts Supporting Appalachian Production Seneca Appalachia Natural Gas Marketing Firm Contract / Transport Volumes (MDth/day) 1,200 Leidy South (Transco & NFG - Supply) Transco Zone 6 Non-NY 1,000 330,000 Dth/d *Capacity can be utilized by all three producing areas (WDA, EDA-Tioga, and EDA-Lycoming) 800 Tioga County Extension (NFG - Empire) Canada-Dawn & NY Markets 185,000 - 200,000 Dth/d 600 (1) In-Basin Firm Sales Contracts 400 Atlantic Sunrise (Transco) Mid-Atlantic & Southeast U.S. 189,405 Dth/d 200 Niagara Expansion (TGP & NFG - Supply) Canada-Dawn & TGP 200 158,000 Dth/d Northeast Supply Diversification (TGP) 50,000 Dth/d (Canada-Dawn) - Jul-22 Oct-22 Jan-23 Apr-23 Jul-23 Oct-23 27 (1) Represents base firm sales contracts not tied to firm transportation capacity. Base firm sales are either fixed priced or priced at an index (e.g., NYMEX ) +/- a fixed basis and do not carry any transportation costs.


E&P and Gathering Near-term Firm Sales Provide Market & Price Certainty Net Contracted Firm Sales / Transport Volumes (Dth per day) (1) Contracted Index Price Differentials ($ per Dth) NYMEX Dawn Other Capped Fixed Price 26,000 ($0.88) 2,800 ($0.56) 966,100 957,600 4,300 ($0.56) 936,400 926,700 895,500 885,200 178,500 177,300 200,300 $2.30 228,500 $2.30 216,900 204,600 $2.44 $2.54 (3) (3) 43,500 42,700 $2.56 $2.62 (3) 46,500 (3) (2) 44,000 (2) (3) (2) (3) (3) 234,500 56,100 232,100 146,600 85,600 (2) 69,800 $0.94 (2) 50,000 $0.49 ($1.20) ($1.20) ($0.81) (2) 30,700 ($1.22) 48,700 ($0.90) 48,400 ($0.90) 580,100 569,700 564,300 517,000 460,900 ($0.67) 457,100 ($0.69) ($0.71) ($0.67) ($0.66) ($0.66) Q4 FY22 Q1 FY23 Q2 FY23 Q3 FY23 Q4 FY23 FY23 (Avg.) Gross Firm Sales Volumes (Dth per day) 1,026,700 1,039,100 1,068,500 1,111,500 1,099,400 1,079,600 (1) Values shown represent the weighted average fixed price or weighted average differential relative to NYMEX (netback price), and are net of any associated transportation costs. Transportation costs include minor variable components such as the Canadian exchange rate and fuel components. With respect to “Other”, the weighted average differential relative to NYMEX (netback price) includes net contracted firm sales at various indices, which are to subject to fluctuations in the market, such as seasonal demand swings, and is calculated using forward basis at various associated locations as specified by the underlying contract. (2) “Other” volumes included in fiscal 2022 and fiscal 2023, are primarily TGP 200 and Transco Zone 6 Non-NY markets, with the balance to other Transco markets. 28 (3) Refer to NYMEX Capped Firm Sales Additional Detail on appendix slide 52.


E&P and Gathering Fiscal 2022 Production Profile 79 Bcf of Appalachian Production Protected by Firm Sales (1) § 68 Bcf locked-in realizing net ~$2.27/Mcf (2) § 11 Bcf of additional firm sales 400 350-355 Bcfe ~9 Bcfe (3) ~9 Bcfe ~2 Bcfe 350 Spot 300 production ~68 Bcfe assumed to be 250 sold at ~$7.20 200 150 ~265 Bcfe 100 50 0 YTD FY22 Price Certainty Hedged Firm Sales Unhedged Firm Sales Spot Sales Total Actuals Seneca (1) Average realized price reflects uplift from financial hedges less fixed differentials under firm sales contracts and any firm transportation costs. (2) Includes ~8 Bcf of firm sales with fixed index differentials, as well as production with associated firm transport volumes, but not backed by a matching financial hedge. Also includes ~2 Bcf of non-NYMEX indexed firm sales with existing NYMEX hedge. 29 (3) Includes ~8 Bcf of firm sales with caps tied to NYMEX prices. See NYMEX Capped Firm Sales Additional Detail on appendix slide 52. Production (Bcfe)


E&P and Gathering Fiscal 2023 Production Profile 332 Bcf of Appalachian Production Protected by Firm Sales (1) § 184 Bcf locked-in realizing ~$2.31/Mcf , net of transportation (2) § 69 Bcf of no-cost collars with $3.20/Mcf floor (3) § 79 Bcf of additional firm sales 400 370-390 Bcfe ~48 Bcfe 350 Spot production 300 ~79 Bcfe assumed to be sold at ~$6.50 for winter and 250 ~$3.90 for summer FY23 ~69 Bcfe 200 150 100 ~184 Bcfe 50 0 Price Certainty Floor Protection Unhedged Firm Sales Spot Sales Total Seneca (1) Average realized price reflects uplift from financial hedges less fixed differentials under firm sales contracts and any firm transportation costs. (2) Average weighted floor price (average weighted ceiling price of $3.75/Mcf). (3) Includes ~63 Bcf of firm sales with fixed index differentials, as well as production with associated firm transport volumes, but not backed by a matching financial hedge. Also includes ~16 Bcf of firm sales with caps tied to NYMEX prices. 30 See NYMEX Capped Firm Sales Additional Detail on appendix slide 52. Production (Bcfe)


E&P and Gathering Continued Decrease in E&P Operating Costs Increased Scale and Highly-Contiguous Operations Expected to Drive Lower Cash Unit Costs Seneca Cash OpEx ($/Mcfe) Expected operating $1.40 $1.32 results post sale of California operations $0.14 $1.22 $0.14ü Approximately $0.20/Mcfe $1.14 $0.12 Reduction in Expected Cash $0.34 $0.11 ~$0.97 $0.30 Unit Costs 2023E vs. 2021 ~$0.94 $0.26 $0.21 $0.08 Levels $0.08 (1) (1) $0.18 $0.18 (2) $0.38 $0.32 $0.28 $0.25 (2) (2) $0.12 $0.10 ü Fees Paid to NFG’s Gathering Segment Comprise ~90% of Expected Gathering & (2) (3) (2) (2) $0.59 $0.58 $0.57 $0.57 $0.56 $0.54 Transport LOE FY 2018 FY 2019 FY 2020 FY 2021 Q4 2022E FY 2023E LOE (Gathering & Transport) LOE (Other) G&A Taxes & Other (1) G&A estimate represents the midpoint of the G&A guidance ranges for Q4 fiscal 2022 and fiscal 2023. 31 (2) The total of the two LOE components represents the midpoint of the LOE guidance ranges for fiscal 2022 and fiscal 2023. FY20 Seneca LOE was $0.84/Mcfe (vs. total shown of $0.85) due to rounding.


E&P and Gathering Sustainability Initiatives – RSG and Pneumatic Devices Responsible Gas Certification Pneumatic Devices Emissions Reduction Initiative Continue to systematically transition natural gas actuated pneumatic devices to Equitable Origin compressed air, electric, or solar powered compressed air to eliminate vented (100% of Appalachian Assets - Certified December 2021) methane emissions from pneumatic devices Certification focuses on five key principles: ü Committed to using compressed air, electric, or solar powered compressed air ü Social Impacts pneumatic devices on all new well pads ü Human Rights/Community Engagement ü Natural gas pneumatics on existing well pads will be converted to compressed air, ü Indigenous Peoples’ Rights electric, or solar powered compressed air ü Occupational Health & Safety/Fair Labor Standards ü Environmental Impacts/Biodiversity/Climate Change TrustWell by Project Canary (~300 MMcf/d - Certified March 2022) ü Certification focuses on four key areas: § Air § Water § Land § Community ü Continuous Emissions Monitoring Technology installed November 2021 32


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


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


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


Pipeline & Storage Continued Expansion of the Supply Corp. Line N System Line N to Monaca Project ü Shell Chemical Appalachia, LLC - On-system Delivery Point § In-service date: November 2019 TGP 219 § Contracted firm transport: 133,000 Dth/d § Capital cost: $24.5 million § Annual revenue: $5.6 million 2021 Line N Market Pull Projects ü Omnis Bailey Plant - On-system Delivery Point § In-service date: May 2021 § Contracted firm transport: 21,000 Dth/d Columbia Interconnect § Capital cost: $2.9 million Rover § Annual revenue: $1.2 million ü Columbia Gas of PA Interconnect – On-system Delivery Point § In-service date: October 2021 § Contracted firm transport/storage: 4,000 Dth/d / 267,000 Dth Omnis Bailey Interconnect § Capital cost: $0.8 million Holbrook § Annual revenue: $0.5 million 36


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


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


Utility Overview National Fuel Gas Distribution Corporation 39


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


Utility Utility Continues its Significant Investments in Safety Long-Standing Focus on Distribution System Safety and Reliability $140.0 (1) Capital Expenditures for Safety Total Capital Expenditures $110-$130 $120.0 $100-$110 $100.8 $95.8 $94.3 $100.0 $85.6 $80.9 $79.7 $74.1 $71.4 $80.0 $69.9 $63.6 $60.0 $40.0 Modernization Spending in NY Expected to Add $3 MM - $4 MM in Gross Margin in FY 2022 & 2023 $20.0 $0.0 2017 2018 2019 2020 2021 2022E 2023E Fiscal Year 41 (1) A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation. Utility Capital Expenditures ($ millions)


Utility Long-Standing Pipeline Replacement & Modernization (1) Utility Mains by Material Miles of Utility Main Pipeline Replaced Wrought Iron 159 158 156 154 Coated Bare 144 Cast Iron NY 9,782 miles Plastic Wrought Iron Bare Coated PA* 4,850 miles Plastic 2017 2018 2019 2020 2021 Calendar Year * No Cast Iron Mains in Pa.* 42 (1) All values are reported on a calendar year basis as of December 31, 2021.


Utility Utility Targeting Substantial Emissions Reductions Significant Reductions in Utility GHG Emissions to Date, GHG Reduction Targets, Continuing Focus on Lowering Driven by System Modernization Efforts Carbon Footprint (1) Utility GHG Emissions Reduction Targets Utility EPA Subpart W Emissions (Based on 1990 EPA Subpart W Emissions) (Thousand Metric Tons, CO e) 2 800 2030 2050 700 600 500 75% 90% 400 300 ü Targets Exceed Those Included in New York 200 (2) State Climate Act (CLCPA) 100 ü Reductions Primarily Driven by Ongoing 0 Modernization of Mains and Services 1990 1995 2000 2005 2010 2015 2020 (1) Baseline emissions & emissions reduction targets are calculated pursuant to the reporting methodology under the EPA GHG Reporting Program (current Subpart W, and using AR5), primarily Distribution pipeline mains & services. 43 (2) New York Climate Leadership and Community Protection Act, enacted in 2019.


Utility Promoting Renewable Natural Gas and Hydrogen July 2021 Through Fiscal 2020 October 2020 Ongoing Accepted first RNG deliveries Petitioned NY PSC to include Awarded three RNG grants Continue to advance RNG into NY system from RNG in the supply mix and for $1.2 million through the anaerobic digester project and evaluate investment recover purchased RNG Utility’s Area Development (receipts estimated to be ~50 opportunities costs through gas supply Program MMcf/year) rates Substantial RNG Potential in New York Continuing to Work with Regulators and Third Parties to Advance Zero and Low Carbon Opportunities (1) RNG Potential in New York State (Bcf/Year) ü Distribution Corporation received approval from NY and PA utility Low Resource High Resource Technical commissions to accept RNG into its distribution system Scenario Scenario Potential Landfill 20 33 50 ü Low Carbon Resources Initiative (LCRI) expected to provide opportunities for NFG to leverage technology acceleration within Animal/Food Waste 7 13 37 its regional footprint Wastewater 2 3 7 ü Focused on the development of potential hydrogen projects Other 24 56 177 through membership in the Clean Hydrogen Economy consortium led by Guidehouse and NYSERDA-led Regional Clean Hydrogen All Sources 53 105 271 Hub consortium 44 (1) American Gas Foundation – Renewable Sources of Natural Gas: Supply and Emissions Reduction Assessment (December 2019).


Consolidated Financial Overview Upstream I Midstream I Downstream 45


Diversified, Balanced Earnings and Cash Flows (1) (2) Adjusted Operating Results ($ per share) Adjusted EBITDA ($ millions) $8.00 $1,170 $7.25 to $7.75 $1,200 $7.00 $1,000 $1,000 $5.85 to $5.95 $6.00 $611 E&P $800 $5.00 $465 $4.29 E&P $4.00 $600 $1.83 $3.00 $171 $159 $400 Gathering Gathering $0.88 $2.00 $219 $230 Pipeline & Pipeline & $200 $1.01 $1.00 Storage Storage $171 $168 $0.59 Utility Utility $0.00 $0 FY 2021 FY 2022 FY 2023 FY 2021 TTM 6/30/22 Guidance Guidance (1) Excludes items impacting comparability. See Comparable GAAP Financial Measure Slides & Reconciliations at the end of this presentation. 46 (2) Consolidated Adjusted EBITDA includes Corporate & All Other. A reconciliation of Adjusted EBITDA to Net Income, by segment, as presented on the Consolidated Statement of Income and Earnings Reinvested in the Business is included at the end of this presentation.


Disciplined, Flexible Capital Allocation (1) Capital Expenditures by Segment ($ millions) (2) (3) $1,000 Exploration & Production Gathering Pipeline & Storage Utility $830-$940 $775-$840 $781 $770 $719 $750 $583 $525-$575 $381 $525-$550 $492 $384 $500 $356 $35 $74 $85-$105 $50 $250 $50-$60 $252 $48 $110-$130 $167 $143 $100-$120 $93 $110-$130 $101 $100-$110 $96 $94 $86 $0 2018 2019 2020 2021 2022E 2023E Fiscal Year (1) Total Capital Expenditures include Corporate and All Other. A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation. (2) FY18 reflects the netting of $17 million of up-front proceeds received from joint development partner for working interest in joint development wells, and $21 million in intercompany asset transfers. FY20 reflects the netting of $286 million related to the acquisition of Appalachian upstream assets in July 2020. 47 (3) FY20 reflects the netting of $224 million related to the acquisition of Appalachian gathering assets in July 2020.


Maintaining Strong Balance Sheet & Liquidity (1) Net Debt / Adjusted EBITDA Capitalization Expect Excluding AOCI, 3.08 x further Equity as percentage 2.72 x 2.61 x reduction in of Total 2.45 x 2.47 x Equity Total FY23 2.20 x Capitalization would (2) 40% Debt be 46% 60% 2017 2018 2019 2020 2021 TTM 2023E $5.0 Billion Total Capitalization 6/30/2022 Fiscal Year (3) as of June 30, 2022 Debt Maturity Profile by Fiscal Year ($MM) Liquidity Expect to fund maturity with cash and short-term liquidity $ 1,000 MM Committed Credit Facilities $600 $549 $500 $500 $500 364-Day Delayed Draw Term Loan 250 MM $400 $300 $300 (400 MM) Short-term Debt Outstanding 850 MM Available Short-term Credit Facilities $200 433 MM Cash Balance at 6/30/22 $0 $ 1,283 MM Total Liquidity at 6/30/22 (1) Net Debt is net of cash and temporary cash investments. Reconciliations of Net Debt and Adjusted EBITDA to Net Income are included at the end of this presentation. (2) Includes impact of Accumulated Other Comprehensive Loss of $583 MM as of June 30, 2022. 48 (3) Total capitalization as presented here includes $949 MM of notes payable to banks and commercial paper and current portion of long-term debt, in addition to $4.1 B of Total Capitalization as presented on the balance sheet as of June 30, 2022.


Appendix 49


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: changes in laws, regulations or judicial interpretations to which the Company is subject, including those involving derivatives, taxes, safety, employment, climate change, other environmental matters, real property, and exploration and production activities such as hydraulic fracturing; governmental/regulatory actions, initiatives and proceedings, including those involving rate cases (which address, among other things, target rates of return, rate design and retained natural gas and system modernization), environmental/safety requirements, affiliate relationships, industry structure, and franchise renewal; the Company’s ability to estimate accurately the time and resources necessary to meet emissions targets; governmental/regulatory actions and/or market pressures to reduce or eliminate reliance on natural gas; changes in economic conditions, including inflationary pressures and global, national or regional recessions, and their effect on the demand for, and customers’ ability to pay for, the Company’s products and services; changes in the price of natural gas; the creditworthiness or performance of the Company’s key suppliers, customers and counterparties; the length and severity of the ongoing COVID-19 pandemic, including its impacts across our businesses on demand, operations, global supply chains and liquidity; financial and economic conditions, including the availability of credit, and occurrences affecting the Company’s ability to obtain financing on acceptable terms for working capital, capital expenditures and other investments, including any downgrades in the Company’s credit ratings and changes in interest rates and other capital market conditions; impairments under the SEC’s full cost ceiling test for natural gas reserves; increased costs or delays or changes in plans with respect to Company projects or related projects of other companies, 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; the Company’s ability to successfully integrate acquired assets and achieve expected cost synergies; changes in price differentials between similar quantities of natural gas sold at different geographic locations, and the effect of such changes on commodity production, revenues and demand for pipeline transportation capacity to or from such locations; the impact of information technology disruptions, cybersecurity or data security breaches; factors affecting the Company’s ability to successfully identify, drill for and produce economically viable natural gas reserves, including among others geology, lease availability, title disputes, weather conditions, shortages, delays or unavailability of equipment and services required in drilling operations, insufficient gathering, processing and transportation capacity, the need to obtain governmental approvals and permits, and compliance with environmental laws and regulations; increasing health care costs and the resulting effect on health insurance premiums and on the obligation to provide other post-retirement benefits; other changes in price differentials between similar quantities of natural gas having different quality, heating value, hydrocarbon mix or delivery date; the cost and effects of legal and administrative claims against the Company or activist shareholder campaigns to effect changes at the Company; negotiations with the collective bargaining units representing the Company's workforce, including potential work stoppages during negotiations; uncertainty of gas reserve estimates; significant differences between the Company’s projected and actual production levels for natural gas; changes in demographic patterns and weather conditions (including those related to climate change); changes in the availability, price or accounting treatment of derivative financial instruments; changes in laws, actuarial assumptions, the interest rate environment and the return on plan/trust assets related to the Company’s pension and other post-retirement benefits, which can affect future funding obligations and costs and plan liabilities; economic disruptions or uninsured losses resulting from major accidents, fires, severe weather, natural disasters, terrorist activities or acts of war; 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, 2021 and the Forms 10-Q for the quarter ended December 31, 2021, March 31, 2022 and June 30, 2022. The Company disclaims any obligation to update any forward- looking statements to reflect events or circumstances after the date thereof or to reflect the occurrence of unanticipated events. 50


Appendix Hedge Positions and Prices Natural Gas Volumes in thousand MMBtu; Prices in $/MMBtu Fiscal 2022 (Remain.) Fiscal 2023 Fiscal 2024 Avg. Avg. Avg. Volume Price Volume Price Volume Price NYMEX Swaps 53,580 $2.76 116,200 $2.79 61,080 $2.72 No Cost Collars - - 70,400 $3.11 / $3.64 59,200 $3.20 / $3.78 (1) Fixed Price Physical 18,940 $2.62 73,108 $2.44 60,224 $2.22 Total 72,520 259,708 180,504 51 (1) Fixed price physical sales exclude joint development partner’s share of fixed price contract WDA volumes as specified under the joint development agreement.


Appendix NYMEX Capped Firm Sales Additional Detail Capped Firm Sales - Net Contracted Volumes (Dth/d) NYMEX Cap Q4 FY22 Q1 FY23 Q2 FY23 Q3 FY23 Q4 FY23 FY23 Avg $2.92 25,000 24,900 26,400 26,100 25,600 25,700 $3.00 44,000 14,600 0 0 0 3,600 $3.00 capped firm sales expire 10/31/22 $4.95 16,600 16,600 17,600 17,400 17,100 17,200 Total 85,600 56,100 44,000 43,500 42,700 46,500 (1) Capped Firm Sales - Weighted Average Index Price Differentials ($/Dth) Q4 FY22 Q1 FY23 Q2 FY23 Q3 FY23 Q4 FY23 FY23 Avg NYMEX Price (85,600) (56,100) (44,000) (43,500) (42,700) (46,500) $3.00 ($0.70) ($0.65) ($0.59) ($0.59) ($0.59) ($0.61) $3.50 ($1.11) ($1.00) ($0.89) ($0.89) ($0.89) ($0.93) $4.00 ($1.51) ($1.35) ($1.19) ($1.19) ($1.19) ($1.24) $4.50 ($1.91) ($1.70) ($1.49) ($1.49) ($1.49) ($1.56) $5.00 ($2.32) ($2.07) ($1.81) ($1.81) ($1.81) ($1.89) $5.50 ($2.82) ($2.57) ($2.31) ($2.31) ($2.31) ($2.39) $6.00 ($3.32) ($3.07) ($2.81) ($2.81) ($2.81) ($2.89) $6.50 ($3.82) ($3.57) ($3.31) ($3.31) ($3.31) ($3.39) $7.00 ($4.32) ($4.07) ($3.81) ($3.81) ($3.81) ($3.89) $7.50 ($4.82) ($4.57) ($4.31) ($4.31) ($4.31) ($4.39) $8.00 ($5.32) ($5.07) ($4.81) ($4.81) ($4.81) ($4.89) $8.50 ($5.82) ($5.57) ($5.31) ($5.31) ($5.31) ($5.39) (1) Values shown represent the weighted average differential relative to NYMEX (netback price) and are net of any associated transportation costs. Transportation costs include minor variable components such as the Canadian exchange rate and fuel 52 components.


Appendix Firm Transportation Commitments Volume Delivery Demand Charges Production Source Gas Marketing Strategy (Dth/d) Market ($/Dth) Northeast Supply Canada Firm Sales Contracts rd EDA – Tioga 50,000 $0.46 (3 party) Diversification (Dawn) Dawn/NYMEX Tennessee Gas Pipeline NFG pipelines - $0.24 158,000 Canada (Dawn) rd Niagara Expansion 3 party - $0.40 Firm Sales Contracts WDA – CRV TGP & NFG - Supply Dawn/NYMEX 12,000 TGP 200 (PA) $0.14 (NFG pipelines) Atlantic Sunrise Mid-Atlantic/ Firm Sales Contracts rd EDA - Lycoming 189,405 $0.73 (3 party) WMB - Transco Southeast NYMEX/Market Indices TGP 200 (NY) / Tioga County Extension Firm Sales Contracts 200,000 $0.23 (NFG pipelines) EDA – Tioga Canada (Dawn) NFG - Empire TGP 200 (PA)/NYMEX rd (1) Eastern EDA – Tioga 100,000 In-Basin $0.23 (3 Party) Capacity release WDA – CRV Transco Zone Firm Sales Contracts Leidy South / FM100 rd 330,000 $0.66 (3 Party) WMB – Transco; NFG - Supply EDA - Lycoming 6 NNY Transco Zone 6 NNY/NYMEX NFG pipelines - $0.50 Canada (Dawn) Seneca to pursue firm sales 350,000 rd 3 party - $0.19 Northern Access WDA – CRV contracts as project development NFG – Supply and Empire TGP 200 (NY) 140,000 $0.38 (NFG pipelines) progresses 53 (1) Expected reduction in rates upon approved settlement of recent FERC Rate Proceeding. Currently In-Service


Appendix Primary Development Area Type Curves Lycoming Marcellus Tioga Utica WDA Utica 20 18 16 14 12 10 8 Estimated Cumulative Volumes (Bcf) Lycoming Tioga Utica WDA Utica 6 Year Marcellus (10,000 - (10,000- (5,500-6,000') 11,000') 11,000’) 4 1 3.5 5.9 2.7 5 9.5 14.1 8.0 10 12.2 17.3 10.8 2 EUR (Bcf) 14.5-16.8 19.0-24.0 15.8-18.9 NRI 84% 82-87% 100% 0 0 12 24 36 48 60 72 84 96 108 120 Months On 54 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. The Company’s fiscal 2022 earnings guidance range does not include the impact of certain items that impacted the comparability of earnings during the nine months ended June 30, 2022, including: (1) the gain on sale of West Coast assets; (2) the loss from discontinuance of crude oil cash flow hedges; (3) transaction and severance costs (E&P); (4) the unrealized loss on other investments; and (5) the reduction of other post-retirement regulatory liability. While the Company expects to record additional adjustments to unrealized gain or loss on other investments during the three months ending September 30, 2022, the amounts of these and other potential adjustments are not reasonably determinable at this time. As such, the Company is unable to provide earnings guidance other than on a non-GAAP basis. Management defines Adjusted Operating Results as reported GAAP earnings before items impacting comparability. Management defines Adjusted EBITDA as reported GAAP earnings before the following items: interest expense, income taxes, depreciation, depletion and amortization, other income and deductions, impairments, and other items reflected in operating income that impact comparability. Management defines Free Cash Flow as Funds from Operations (Net Cash Provided by Operating Activities less changes in working capital) less Capital Expenditures. The Company is unable to provide a reconciliation of projected Free Cash Flow as described in this presentation to its respective comparable financial measure calculated in accordance with GAAP without unreasonable efforts. This is due to our inability to calculate the comparable GAAP projected metrics, including operating income and total production costs, given the unknown effect, timing, and potential significance of certain income statement items. 55


Appendix Non-GAAP Reconciliations – Adjusted EBITDA (1) Reconciliation of Adjusted EBITDA to Consolidated Net Income ($ Thousands) 12-Months FY 2017 FY 2018 FY 2019 FY 2020 FY 2021 Ended 6/30/22 Total Adjusted EBITDA Exploration & Production Adjusted EBITDA $ 361,079 $ 317,707 $ 351,159 $ 312,166 464,529 610,661 Pipeline & Storage Adjusted EBITDA 180,328 183,972 162,181 189,520 218,921 230,214 Gathering Adjusted EBITDA 94,380 91,937 108,292 119,879 159,005 171,096 Utility Adjusted EBITDA 151,078 175,554 176,134 171,418 171,379 167,694 Corporate & All Other Adjusted EBITDA (9,725) (7,704) (12,393) (7,529) (13,521) (9,730) Total Adjusted EBITDA $ 777,140 $ 761,466 $ 785,373 $ 785,454 $ 1,000,313 $ 1,169,935 Total Adjusted EBITDA $ 777,140 $ 761,466 $ 785,373 $ 785,454 $ 1,000,313 $ 1,169,935 Minus: Interest Expense (119,837) (114,522) (106,756) (117,077) (146,357) (127,292) Plus: Other Income (Deductions) 11,156 (21,174) (15,542) (17,814) (15,238) 3,131 Minus: Income Tax Expense (160,682) 7,494 (85,221) (18,739) (114,682) (149,992) Minus: Depreciation, Depletion & Amortization (224,195) (240,961) (275,660) (306,158) (335,303) (359,352) Minus: Impairment of Oil and Gas Properties (E&P) - - - (449,438) (76,152) - Minus: Gain on Sale of Timber Properties - - - - 51,066 - Minus: Gain on Sale of California Properties - - - - - 12,736 Minus: Loss from discontinuance of oil cash flow hedges (E&P) - - - - - (44,632) Minus: Transaction and severance costs related to West Coast asset sale (E&P) - - - - - (9,693) Minus: Unrealized Gain (Loss) on Hedge Ineffectiveness (100) (782) 2,096 - - - Rounding - - - - - - Consolidated Net Income $ 283,482 $ 391,521 $ 304,290 $ ( 123,772) $ 363,647 $ 494,841 Consolidated Debt to Total Adjusted EBITDA Long-Term Debt, Net of Current Portion (End of Period) $ 2,099,000 $ 2,149,000 $ 2,149,000 $ 2,649,000 $ 2,649,000 $ 2,100,000 Current Portion of Long-Term Debt (End of Period) 300,000 - - - - 549,000 Notes Payable to Banks and Commercial Paper (End of Period) - - 55,200 30,000 158,500 400,000 Less: Cash and Temporary Cash Investments (End of Period) (555,530) (229,606) (20,428) (20,541) (31,528) (432,576) Total Net Debt (End of Period) $ 1,843,470 $ 1,919,394 $ 2,183,772 $ 2,658,459 $ 2,775,972 $ 2,616,424 Long-Term Debt, Net of Current Portion (Start of Period) 2,099,000 2,099,000 2,149,000 2,149,000 2,649,000 2,649,000 Current Portion of Long-Term Debt (Start of Period) - 300,000 - - - - Notes Payable to Banks and Commercial Paper (Start of Period) - - - 55,200 30,000 - Less: Cash and Temporary Cash Investments (Start of Period) (129,972) (555,530) (229,606) (20,428) (20,541) (118,012) Total Net Debt (Start of Period) $ 1,969,028 $ 1,843,470 $ 1,919,394 $ 2,183,772 $ 2,658,459 $ 2,530,988 Average Total Net Debt $ 1,906,249 $ 1,881,432 $ 2,051,583 $ 2,421,116 $ 2,717,216 $ 2,573,706 Average Total Net Debt to Total Adjusted EBITDA 2.45 x 2.47 x 2.61 x 3.08 x 2.72 x 2.20 x (1) Total Adjusted EBITDA for FY 2018, FY 2019, FY 2020, and FY 2021, include the reclassification of non-service pension costs from Operating and Maintenance Expense to Other Income (Deductions) as of October 1, 2018 on the Company’s Income Statement. This 56 reclassification is not reflected in Total Adjusted EBITDA for FY 2017.


Appendix Non-GAAP Reconciliations – Adjusted EBITDA, by Segment Reconciliation of Adjusted EBITDA to Net Income, by Segment ($ Thousands) FY22 FY21 12-Months FY 2017 FY 2018 FY 2019 FY 2020 FY 2021 FYTD FYTD Ended 6/30/22 Exploration and Production Segment Reported GAAP Earnings $ 129,326 $ 180,632 $ 111,807 $ (326,904) $ 101,916 $ 189,987 $ 46,213 $ 245,690 Depreciation, Depletion and Amortization 112,565 124,274 154,784 172,124 182,492 155,190 137,356 200,326 Other (Income) Deductions (707) (307) (1,091) 882 937 (55) 684 198 Interest Expense 53,702 54,288 54,777 58,098 69,662 38,927 57,720 50,869 Income Taxes 66,093 (41,962) 32,978 (41,472) 33,370 64,435 25,816 71,989 Mark-to-Market Adjustment due to Hedge Ineffectiveness 100 782 (2,096) - - - - - Impairment of Oil and Gas Properties - - - 449, 438 76,152 - 76,152 - Gain on Sale of West Coast assets - - - - - (12,736) - (12,736) Loss from discontinuance of crude oil cash flow hedges - - - - - 44,632 - 44,632 Transaction and severance costs related to West Coast asset sale - - - - - 9,693 - 9,693 Adjusted EBITDA $ 361,079 $ 317,707 $ 351,159 $ 312,166 $ 464,529 $ 490,073 $ 343,941 $ 610,661 Pipeline and Storage Segment Reported GAAP Earnings $ 68,446 $ 97,246 $ 74,011 $ 78,860 $ 92,542 $ 77,236 $ 71,060 $ 98,718 Depreciation, Depletion and Amortization 41,196 43,463 44,947 53,951 62,431 50,417 46,806 66,042 Other (Income) Deductions (3,978) (5,926) (9,157) (4,635) (5,840) (4,632) (3,535) (6,937) Interest Expense 33,717 31,383 29,142 32,731 40,976 31,564 31,353 41,187 Income Taxes 40,947 17,806 23,238 28,613 28,812 26,499 24,107 31,204 Adjusted EBITDA $ 180,328 $ 183,972 $ 162,181 $ 189,520 $ 218,921 $ 181,084 $ 169,791 $ 230,214 Gathering Segment Reported GAAP Earnings $ 40,377 $ 83,519 $ 58,413 $ 68,631 $ 80,274 $ 69,887 $ 61,677 $ 88,484 Depreciation, Depletion and Amortization 16,162 17,313 20,038 22,440 32,350 25,343 24,132 33,561 Other (Income) Deductions (995) (778) (460) (260) 12 87 (50) 149 Interest Expense 9,142 9,560 9,406 10,877 17,493 12,383 13,400 16,476 Income Taxes 29,694 (17,677) 20,895 18,191 28,876 25,538 21,988 32,426 Adjusted EBITDA $ 94,380 $ 91,937 $ 108,292 $ 119,879 $ 159,005 $ 133,238 $ 121,147 $ 171,096 Utility Segment Reported GAAP Earnings $ 46,935 $ 51,217 $ 60,871 $ 57,366 $ 54,335 $ 79,800 $ 59,922 $ 74,213 Depreciation, Depletion and Amortization 52,582 53,253 53,832 55,248 57,457 44,592 42,811 59,238 Other (Income) Deductions (1,825) 29,073 24,021 23,380 23,785 (7,180) 22,532 (5,927) Interest Expense 28,492 26,753 23,443 22,150 21,795 17,115 16,457 22,453 Income Taxes 24,894 15,258 13,967 13,274 14,007 22,273 18,563 17,717 Adjusted EBITDA $ 151,078 $ 175,554 $ 176,134 $ 171,418 $ 171,379 $ 156,600 $ 160,285 $ 167,694 Corporate and All Other Reported GAAP Earnings $ (1,602) $ (21,093) $ (812) $ (1,725) $ 34,580 $ (9,031) $ 37,813 $ (12,264) Depreciation, Depletion and Amortization 1,690 2,658 2,059 2,395 573 139 527 185 Gain on Sale of Timber Properties - - - - (51,066) - ( 51,066) - Other (Income) Deductions (3,651) (888) 2,229 (1,553) (3,656) 8,489 (4,553) 9,386 Interest Expense (5,216) (7,462) (10,012) (6,779) (3,569) (3,128) (3,004) (3,693) Income Taxes (946) 19,081 (5,857) 133 9,617 (3,473) 9,488 (3,344) 57 Adjusted EBITDA $ (9,725) $ (7,704) $ (12,393) $ (7,529) $ (13,521) $ (7,004) $ (10,795) $ (9,730)


Appendix Non-GAAP Reconciliations – Adjusted Operating Results Three Months Ended June 30, (in thousands except per share amounts) 2022 2021 Reported GAAP Earnings $ 108,158 $ 86,475 Items impacting comparability: Items related to West Coast asset sale: Gain on sale of West Coast assets (E&P) (12,736) — Tax impact of gain on sale of West Coast assets 3,225 — Loss from discontinuance of crude oil cash flow hedges (E&P) 44,632 — Tax impact of loss from discontinuance of crude oil cash flow hedges (11,303) — Transaction and severance costs (E&P) 9,693 — Tax impact of transaction and severance costs (2,455) — Total items impacting comparability related to West Coast asset sale 31,056 — Reduction of other post-retirement regulatory liability (Utility) — — Tax impact of reduction of other post-retirement regulatory liability — — Unrealized (gain) loss on other investments (Corporate / All Other) 3,434 (1,025) Tax impact of unrealized (gain) loss on other investments (721) 215 Impairment of oil and gas properties (E&P) — — Tax impact of impairment of oil and gas properties — — Gain on sale of timber properties (Corporate / All Other) — — Tax impact of gain on sale of timber properties — — Premium paid on early redemption of debt — — Tax impact of premium paid on early redemption of debt — — Adjusted Operating Results $ 141,927 $ 85,665 Reported GAAP Earnings Per Share $ 1.17 $ 0.94 Items impacting comparability: Items related to West Coast asset sale: Gain on sale of West Coast assets, net of tax (E&P) (0.10) — Loss from discontinuance of crude oil cash flow hedges, net of tax (E&P) 0.36 — Transaction and severance costs, net of tax (E&P) 0.08 — Total items impacting comparability related to West Coast asset sale 0.34 — Reduction of other post-retirement regulatory liability, net of tax (Utility) — — Unrealized (gain) loss on other investments, net of tax (Corporate / All Other) 0.03 (0.01) Impairment of oil and gas properties, net of tax (E&P) — — Gain on sale of timber properties, net of tax (Corporate / All Other) — — Premium paid on early redemption of debt, net of tax — — Adjusted Operating Results Per Share $ 1.54 $ 0.93 58


Appendix Non-GAAP Reconciliations – Capital Expenditures Reconciliation of Segment Capital Expenditures to Consolidated Capital Expenditures ($ Thousands) FY 2022 FY 2023 FY 2018 FY 2019 FY 2020 FY 2021 Guidance Guidance Capital Expenditures Exploration & Production Capital Expenditures $ 380,677 $ 491,889 $ 670, 455 $ 381, 408 $525,000 - $550,000 $525,000 - $575,000 Pipeline & Storage Capital Expenditures $ 92,832 $ 143,003 $ 166, 652 $ 252, 316 $100,000 - $120,000 $110,000 - $130,000 Gathering Segment Capital Expenditures $ 61,728 $ 49,650 $ 297, 806 $ 34, 669 $50,000 - $60,000 $85,000 - $105,000 Utility Capital Expenditures $ 85,648 $ 95,847 $ 94, 273 $ 100, 845 $100,000 - $110,000 $110,000 - $130,000 Corporate & All Other Capital Expenditures $ 222 $ 855 $ 561 $ 450 Eliminations $ (20,505) $ ( 1,130) $ 223 Total Capital Expenditures from Continuing Operations $ 600,602 $ 781,246 $ 1,228,617 $ 769,911 $775,000 - $840,000 $830,000 - $940,000 Plus (Minus) Acquisition of Upstream Assets and Midstream Gathering Assets $ ( 506,258) Plus (Minus) Accrued Capital Expenditures $ ( 47,887) (1) Exploration & Production FY 2020 Accrued Capital Expenditures $ ( 45,788) $ 42,983 Exploration & Production FY 2019 Accrued Capital Expenditures $ (38,063) $ 38,063 Exploration & Production FY 2018 Accrued Capital Expenditures $ (51,343) $ 51,343 Exploration & Production FY 2017 Accrued Capital Expenditures $ 36,465 Exploration & Production FY 2016 Accrued Capital Expenditures $ ( 39,436) Pipeline & Storage FY 2020 Accrued Capital Expenditures $ ( 17,264) $ 17,264 Pipeline & Storage FY 2019 Accrued Capital Expenditures $ (23,771) $ 23,771 Pipeline & Storage FY 2018 Accrued Capital Expenditures $ (21,861) $ 21,861 Pipeline & Storage FY 2017 Accrued Capital Expenditures $ 25,077 Pipeline & Storage FY 2016 Accrued Capital Expenditures $ ( 4,743) Gathering FY 2020 Accrued Capital Expenditures $ ( 13,524) $ 13,524 Gathering FY 2019 Accrued Capital Expenditures $ (6,595) $ 6,595 Gathering FY 2018 Accrued Capital Expenditures $ (6,084) $ 6,084 Gathering FY 2017 Accrued Capital Expenditures $ 3,925 Gathering FY 2016 Accrued Capital Expenditures $ ( 10,634) Utility FY 2020 Accrued Capital Expenditures $ ( 10,751) $ 10,751 Utility FY 2019 Accrued Capital Expenditures $ (12,692) $ 12,692 Utility FY 2018 Accrued Capital Expenditures $ (9,525) $ 9,525 Utility FY 2017 Accrued Capital Expenditures $ 6,748 Utility FY 2016 Accrued Capital Expenditures Total Accrued Capital Expenditures $ (16,597) $ 7,692 $ ( 6,206) $ ( 18,177) Total Capital Expenditures per Statement of Cash Flows $ 584, 004 $ 788, 938 $ 716, 153 $ 751, 734 $775,000 - $840,000 $830,000 - $940,000 59 (1) Amount is $2,805 lower than the accrued capital expenditures reported in the prior year, representing certain liabilities assumed in connection with the 2020 acquisition of assets from Shell, capitalized as part of the asset acquisition cost, and subsequently paid by the Company. As the liabilities were owed and paid to third parties, they are not classified as capital expenditures in 2021.


Appendix Non-GAAP Reconciliations – E&P Operating Expenses Reconciliation of Exploration & Production Segment Operating Expenses by Division ($000s unless noted otherwise) Twelve Months Ended Twelve Months Ended September 30, 2021 September 30, 2020 (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 $185,151 $0 $185,151 $0.59 $0.00 $0.57 $136,994 $0 $136,994 $0.61 $0.00 $0.57 Other Lease Operating Expense $25,578 $56,587 $82,165 $0.08 $22.46 $0.25 $16,527 $50,149 $66,676 $0.07 $18.85 $0.28 Lease Operating and Transportation Expense $210,729 $56,587 $267,316 $0.67 $22.46 $0.82 $153,521 $50,149 $203,670 $0.68 $18.85 $0.84 General & Administrative Expense $67,973 $0.21 $63,429 $0.26 All Other Operating and Maintenance Expense $14,659 $0.04 $12,542 $0.05 Property, Franchise and Other Taxes $22,220 $0.07 $15,646 $0.06 Total Taxes & Other $36,879 $0.11 $28,188 $0.12 Depreciation, Depletion & Amortization $182,492 $0.56 $172,123 $0.71 Production: Gas Production (MMcf) 312,300 1,720 314,020 225,513 1,889 227,402 Oil Production (MBbl) 2 2,233 2,235 3 2,345 2,348 Total Production (Mmcfe) 312,313 15,117 327,430 225,529 15,958 241,487 Total Production (Mboe) 52,052 2,519 54,572 37,588 2,660 40,248 (1) Gathering and Transportation expense is net of any payments received from JDA partner for the partner's share of gathering cost. (2) Seneca West Coast division includes Seneca corporate and eliminations. 60


nfg-20220804.xsd
Attachment: XBRL TAXONOMY EXTENSION SCHEMA


nfg-20220804_lab.xml
Attachment: XBRL TAXONOMY EXTENSION LABEL LINKBASE


nfg-20220804_pre.xml
Attachment: XBRL TAXONOMY EXTENSION PRESENTATION LINKBASE