NFG 8-K
National Fuel Gas Co (NFG)
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM
CURRENT REPORT
Pursuant to Section 13 or 15(d)
of the Securities Exchange Act of 1934
Date of Report (Date of earliest event reported):
(Exact name of registrant as specified in its charter)
| (State or other jurisdiction of incorporation) |
(Commission File Number) |
(IRS Employer Identification No.) |
| (Address of principal executive offices) | (Zip Code) | |||
Registrant’s telephone number, including area code:
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 |
Name of Each 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 July 29, 2026, 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 press release 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, retained natural gas and system modernization), environmental/safety requirements, affiliate relationships, industry structure, and franchise renewal; changes in economic conditions, including the imposition of additional tariffs on U.S. imports and related retaliatory tariffs, inflationary pressures, supply chain issues, liquidity challenges, and global, national or regional recessions, and their effect on the demand for, and customers’ ability to pay for, the Company’s products and
services; the Company’s ability to complete strategic transactions, such as the planned CenterPoint Ohio acquisition, including receipt of required regulatory clearances and satisfaction of other conditions to closing, and to recognize the anticipated benefits of such transactions; governmental/regulatory actions and/or market pressures to reduce or eliminate reliance on natural gas; the Company’s ability to estimate accurately the time and resources necessary to meet emissions targets; changes in the price of natural gas; impairments under the SEC’s full cost ceiling test for natural gas 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, other investments, and acquisitions, including any downgrades in the Company’s credit ratings and changes in interest rates and other capital market conditions; negotiations with the collective bargaining units representing the Company’s workforce, including potential work stoppages during negotiations; changes in price differentials between similar quantities of natural gas sold at different geographic locations, and the effect of such changes on commodity production, revenues and demand for pipeline transportation capacity to or from such locations; the impact of information technology disruptions, cybersecurity or data security breaches, including the impact of issues that may arise from the use of artificial intelligence technologies; factors affecting the Company’s ability to successfully identify, drill for and produce economically viable natural gas reserves, including among others geology, lease availability and costs, title disputes, weather conditions, water availability and disposal or recycling opportunities of used water, shortages, delays or unavailability of equipment and services required in drilling operations, insufficient gathering, processing and transportation capacity, the need to obtain governmental approvals and permits, and compliance with environmental laws and regulations; increased costs or delays or changes in plans with respect to Company projects or related projects of other companies, as well as difficulties or delays in obtaining necessary governmental approvals, permits or orders or in obtaining the cooperation of interconnecting facility operators; increasing health care costs and the resulting effect on health insurance premiums and on the obligation to provide other post-retirement benefits; other changes in price differentials between similar quantities of natural gas having different quality, heating value, hydrocarbon mix or delivery date; the cost and effects of legal and administrative claims against the Company or activist shareholder campaigns to effect changes at the Company; uncertainty of natural gas reserve estimates; significant differences between the Company’s projected and actual production levels for natural gas; changes in demographic patterns and weather conditions (including those related to climate change); changes in the availability, price or accounting treatment of derivative financial instruments; changes in laws, actuarial assumptions, the interest rate environment and the return on plan/trust assets related to the Company’s pension and other post-retirement benefits, which can affect future funding obligations and costs and plan liabilities; economic disruptions or uninsured losses resulting from major accidents, fires, severe weather, natural disasters, terrorist activities or acts of war, as well as economic and operational disruptions due to third-party outages; significant differences between the Company’s projected and actual capital expenditures and operating expenses; or increasing costs of insurance, changes in coverage and the ability to obtain insurance. 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 July 2026 | |
| 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/ Lee E. Hartz | |
| Lee E. Hartz | ||
| General Counsel and Secretary | ||
Dated: July 29, 2026
Investor Presentation Fiscal 2026 – 3rd Quarter Update July 29, 2026 Exhibit 99
National Fuel Gas Company Company Overview (3) Recent Highlights (6) Why National Fuel? (11) Financial Overview (16) Integrated Upstream & Gathering Highlights (20) Pipeline & Storage and Utility Highlights (31) Guidance & Other Financial Information (45)
Company Overview Left picture: Seneca Resources rig in Tioga County, PA. Right picture: Buffalo Bills’ New Highmark Stadium construction in Orchard Park, NY. Corporate HQ: Buffalo, NY ~2,300 employees NYSE: NFG Market Cap: ~$7.7B 124 Years of consecutive dividend payments 56 Years of consecutive dividend increases 7-10% Adjusted EPS Growth FY26E-FY29E Investment Grade credit rating 25% reduction in methane emissions since 2020 Note: This presentation includes forward-looking statements. Please review the safe harbor for forward looking statements at the end of this presentation. Market capitalization is presented as of July 27, 2026.
History of National Fuel Industry Pioneer Born From Rockefeller’s Standard Oil Company
NFG: A Diversified, Integrated Natural Gas Company Developing our large, high-quality acreage in Marcellus & Utica shales Providing safe, reliable and affordable service to customers in WNY and NW PA CNP Ohio Acquisition Will Double Rate Base Integrated Upstream & Gathering Regulated Midstream Pipeline & Storage Downstream Utility Expanding and modernizing pipeline infrastructure to provide outlets for Appalachian natural gas production ~1.2 Million Net acres in Appalachia ~1.1 Bcf/day Net total production(3) 77 Bcf of natural gas storage capacity 4.5 MMDth Daily interstate pipeline capacity under contract 756,000 Utility customers ~800 Miles of pipeline replaced over the last five years 69% 18% 13% Adjusted EBITDA(1) Non-Regulated Regulated (1) Twelve months ended June 30, 2026. A reconciliation of Adjusted EBITDA to Net Income as presented on the Consolidated Statement of Income and Earnings Reinvested in the Business is included at the end of this presentation. (2) Closing of the CNP Ohio acquisition is expected to occur on October 1, 2026. (3) Average for the three months ended June 30, 2026. (2) 5
Recent Highlights Strength of the Integrated Model is Evident as Each Business Contributes Meaningfully Strategic IUG(1) land expansion program extends core development runway, enhances planning optionality and supports long-term capital efficiency NY Utility System Modernization Tracker (SMT) pending petition filing would support continued modernization investments and defer future rate case needs Further supports new long-term annual adjusted EPS target of 7-10% through 2029(2) Integrated Upstream and Gathering. 7-10% adjusted earnings per share CAGR from 2026E to 2029E. Announced upsized Line N System Upgrade Project, which increases expansion capacity to ~0.5 Bcf per day in southwest Pennsylvania by 2029 Received all necessary regulatory approvals required for CNP Ohio acquisition and is on track to close on October 1, 2026 2 3 1 4 6
Announced Acquisition of CenterPoint’s Ohio Gas Utility Acquiring a High-Quality Gas Utility in a Neighboring Service Territory Entered into an agreement to acquire CenterPoint’s Ohio gas utility business for $2.62 billion, representing ~1.6x 2026E rate base of $1.6 billion Increases Scale & Balances Business Mix Attractive Regulatory & Political Environment Significantly Increases Regulated Investment Opportunity Enhances Regulated Earnings Growth & Dividend Support Strong Pro-forma Credit Profile Accretive to Long-Term Earnings per Share Note: Closing of the CNP Ohio acquisition is expected to occur on October 1, 2026. 7
Acquisition Update Regulatory Approvals Completed(1) On Track to Close on October 1, 2026 Integration Planning Progressing Well Working closely with the CenterPoint management team to ensure a smooth transition for employees and customers Financing Complete Issued $350 MM in common equity through a private placement with accredited, long-only investors; fulfills equity needs to maintain investment grade credit rating Debt issuance to raise remaining proceeds due at closing completed with proceeds received June 10, 2026 Continue to target Debt/EBITDA of 2.5 – 3.0x and FFO/Net Debt of approximately 30% by the end of the fiscal year after closing PUCO Issued Final Ruling on Ohio Rate Case On January 7, 2026 PUCO issued its final order regarding CenterPoint’s Ohio gas rate case Adopted a modestly lower ROE (Authorized 9.79% vs 9.85%) and extended the amortization period for certain riders from 15 to 25 years; outcome has a minimal impact to earnings and credit metrics and is accretive to long-term rate base growth New rates went into effect January 12, 2026 Ohio Legislative Update Passed Senate Bill 103 which modernizes ratemaking in Ohio Allows for a 3-year fully projected test period (previously used historical test period) with an authorized return true-up mechanism Enables timely recovery of costs and cash flows by requiring PUCO to issue final order within 360 days from date of filing (well in advance of previous timelines) Includes the PUCO Finding and Order and Hart-Scott-Rodino filing. 8
Western Development Area – ~920,000 Acres Eastern Development Area – ~310,000 Acres Non-Regulated Business Overview Reported annually as of September 30, 2025. Average net production and throughput for the three months ended June 30, 2026. Integrated Upstream & Gathering Segment Seneca Resources Company Total Net Acres (Pennsylvania): ~1.2 million Total Proved Reserves: 5.0 Tcfe(1) Current Net Production: ~1.1 Bcf/d(2) Current Firm Transportation: ~1 Bcf/d to premium markets 45+ years of Marcellus and Utica development inventory National Fuel Gas Midstream Company Total Throughput: ~1.2 Bcf/d(2) (including third-party) ~400 miles of gathering pipeline ~128k HP of compression Interconnections with 7 major pipelines
Regulated Business Overview Pipeline & Storage Segment Utility Segment Regulated by Federal Energy Regulatory Commission (FERC) Total Rate Base: $1.7 Billion(2) ~2,600 miles of pipeline / 28 storage fields National Fuel Gas Supply Corporation: Firm Contracted Storage Capacity: 71 Bcf(3) Firm Contracted Transportation Capacity: 3.4 Bcf / day(3) Empire Pipeline, Inc.: Firm Contracted Storage Capacity: 4 Bcf(3) Firm Contracted Transportation Capacity: 1.1 Bcf / day(3) Interconnections with 8 major interstate pipelines New York Jurisdiction 543,000 customers Regulated by the New York Public Service Commission (NYPSC) Pennsylvania Jurisdiction 213,000 customers Regulated by the Pennsylvania Public Utility Commission (PAPUC) Total Rate Base: $1.6 Billion(2) Fiscal 2025 Total Throughput: ~142 Bcf Provides >90% of the space heating load in operating footprint Closing of the CNP Ohio acquisition is expected to occur on October 1, 2026. Estimated rate base as of June 30, 2026. Reported annually as of September 30, 2025, and includes short-term and long-term contracted capacity. (1) 10
Why National Fuel? Optimized capital allocation Lower cost of capital Operational synergies Improved profitability Regulated earnings growth from modernization, expansion and Ohio utility acquisition Increasing free cash flow driven by improving upstream & gathering capital efficiencies Responsibly Reduce Emissions Continued progress toward emissions reduction targets Enhanced GHG disclosures on sustainability initiatives 124 consecutive years of dividend payments 56 consecutive years of dividend increases Long-Standing History of Shareholder Returns Responsibly Reducing Emissions Visibility on Long-Term EPS & FCF Growth Strong Integrated Returns
Integrated Model Drives Strong Returns Source: NFG actuals as reported; S&P500 and Industry Peers as reported in Bloomberg for the TTM ending September 30th. NFG adjusted excludes after-tax non-cash ceiling test impairments. Average Annual NFG Stock Outperformance Since FY17 NFG vs. S&P 500: +2% NFG vs. E&P Peers: +6% NFG vs. Utility Peers: +6% NFG’s ROCE Has Outperformed Peers and Broader Market, on Average, Over a Multi-Year Period Decrease driven by non-cash impairments S&P O&G Index NFG S&P 500 UTY Integrated Business Model Benefits Operational: Lower cost structure Financial: Lower cost of capital Strategic: Optimized capital allocation Commercial: Greater revenue / margin NFG Adj. (2)
Strong, Durable Long-Term Growth Trajectory 7-10% CAGR Adjusted Earnings Per Share Expect $1.0 to $1.5 Billion of Free Cash Flow Generation 2027E-2029E(1) Key Earnings Growth Drivers: Utility and Pipeline & Storage: Ohio gas utility acquisition and associated growth opportunities Infrastructure expansions to serve growing power generation and data center demand in Pennsylvania Continued investments in maintaining safe, reliable, and resilient infrastructure Integrated Upstream & Gathering: Best-in-class capital efficiency trend among Appalachian producers 25+ years of high-quality inventory at less than $2.25 NYMEX breakeven Production growth supported by expanding portfolio of firm transportation to high-value markets Free cash flow generation supported by long-standing hedging program Assumes future natural gas prices based upon current NYMEX and basis differential projections as of the date of this presentation.
Over Half Century of Dividend Growth $1.6 Billion Dividend payments Over Last 10 Years $2.22 per share 56 Years Consecutive Dividend Increases $0.19 per share 124 Years Consecutive Payments 4% 2026 Dividend Increase Acquisition of CNP Ohio Supports Long-Term Dividend Growth
Considerable Progress on Emissions Reductions All emissions reduction targets based on 2020 baseline. Measured using calendar 2024 emissions data, as reported in Company’s 2024 Corporate Responsibility Report. Continued Progress On Our Methane Intensity Targets(1) E&P and Gathering surpassed targets six years ahead of plan Prioritization of emissions reduction projects that deliver highest impact per dollar invested Continued progress on consolidated emissions reductions while growing the business: 25% consolidated methane emissions reductions since 2020 10% consolidated GHG reductions since 2020 Latest Corporate Responsibility Report Provides Disclosures on Sustainability Initiatives
Financial Overview
Continued Momentum Drives Expected Earnings Growth Adjusted Earnings Per Share(1) ($ per share) Excludes items impacting comparability. Consolidated Adjusted Earnings Per Share includes Corporate & All Other. See Comparable GAAP Financial Measure Slides & Reconciliations at the end of this presentation. The acquisition of CNP’s Ohio natural gas utility business is expected to close on October 1, 2026, and therefore, has no impact on FY26 shown above. Fiscal 2026 Adjusted EPS is shown at the midpoint of guidance range, as detailed on slide 46, assuming NYMEX pricing of $3.00. Q3 Financial Summary Integrated Upstream and Gathering – higher realized prices and lower per-unit operating costs compared to the prior year Regulated – higher utility net income compared to the prior year as a result of rate case outcomes; continued progress on Pipeline & Storage expansion projects to support future growth FY26 Guidance Highlights Integrated Upstream and Gathering – ongoing improvement in capital efficiency Regulated – continued earnings growth as a result of ongoing ratemaking efforts Quarter Highlights & FY26 Outlook (2) ~22% CAGR 17
Capital Allocation Priorities Drive Spending Levels (2) Capital expenditures includes accrued capex. Total Capital Expenditures include Corporate and All Other. A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation. FY26 consolidated capital guidance is displayed at the midpoint of the range ($1,000 - $1,075 million). FY23 reflects the netting of $150 million related to the acquisition of Appalachian upstream assets. FY24 reflects the netting of $6.2 million related to the acquisition of assets from UGI. Updated Integrated Upstream & Gathering guidance excludes $20 - $40 MM of discretionary land spending. Capital Expenditures by Segment ($ millions)(1) Capital Allocation Priorities Organic Investments Responsibly Manage the Balance Sheet Return of Capital to Shareholders Highly Strategic M&A Invest in regulated growth via modernization and pipeline expansions Maintain mid-single digit production growth in Integrated Upstream & Gathering segment Maintain investment grade credit rating Target optimal ratemaking capital structure Uphold 56-year history of dividend increases Execute value-accretive share repurchases Integrated Upstream & Gathering opportunities geographically proximate to existing operations Regulated growth to add scale and further balance business mix Regulated Growth Non- Regulated Capital Efficiency (3)
Balance Sheet Resiliency Through the Commodity Cycle Net Debt / Adjusted EBITDA(1) Net Debt is net of cash and temporary cash investments. Reconciliations of Net Debt and Adjusted EBITDA are included at the end of this presentation. A reconciliation of Funds From Operations (FFO) to Net Cash Provided by Operating Activities can also be found at the end of this presentation. We are unable to reconcile certain forward looking non-GAAP financial measures and ratios. Please see slide entitled Comparable GAAP Financial Measure Slides & Reconciliations at the end of this presentation. FY2026 figures exclude the impact of the $350 MM common equity issuance and $1.2B of Long-Term Debt Financing associated with the CNP Ohio Acquisition. Current Credit Rating Investment Grade Credit Rating S&P BBB- Moody’s Baa3 Fitch BBB Investment Grade Credit Rating Committed to Investment Grade Credit Rating Debt Maturity Profile by Fiscal Year ($ MM) FFO / Net Debt(1) Capitalization as of 6/30/26 Downgrade Threshold Downgrade Threshold $1.3B Committed Credit Facility Post Close CNP Ohio Post Close CNP Ohio (2) (2) (2) $1.5 B June 2026 Issuance
Integrated Upstream and Gathering Business Highlights
Integrated Upstream & Gathering Highlights Significant Improvement in Capital Efficiency (FY26E vs. FY23) >25% Improvement Since FY23 Driven by Production Growth and Disciplined Capital Allocation(1) Strategically Growing Core Inventory Through Discretionary Land Investment Over 45 Years of Total Remaining Inventory Upper Utica delineation increased Tioga County Utica Locations >2x >500 MDth/d Increase in Firm Transportation (FT) by FY30 ~1,500 MDth/d of total FT by FY30 Balanced Marketing Portfolio Provides Premium Market Access Re-certified with A-grades from MiQ and Equitable Origin A-grade Certifications Four Years in a Row Enhancing Capital Efficiency Expanding Inventory Depth Increasing Firm Transportation Improving Sustainability Metrics Upstream and Gathering Updated Integrated Upstream & Gathering guidance excludes $20 - $40 MM of discretionary land spending.
Integrated Upstream & Gathering Eastern Development Area ~310,000 Acres Development zones: Marcellus, Upper Utica, Lower Utica 25+ years of development inventory at PV-10 breakeven price of less than $2.25/MMBtu NYMEX Expect to average 25 to 27 wells brought online per year Well and facility design optimization continues to drive improved productivity Diverse and growing marketing portfolio with ~1,500 MDth/d of future firm transportation Integrated gathering systems provide optimized investment timing, low-cost structure and resilient thru-cycle margins Western Development Area ~920,000 Acres (mostly held in fee) Development zones: Marcellus, Lower Utica Development Plan Highlights Upstream and Gathering
Enhanced Capital Efficiency and Competitive Cost Structure (1) Capital Efficiency defined as Integrated Upstream and Gathering Capital Expenditures less Acquisitions, Discretionary Land Spend, and Third-Party Midstream investments, divided by Seneca net production. FY23 capex reflects the netting of $150 million related to acquisition of upstream assets and acreage from total capital expenditures. FY24 capex reflects the netting of $6 million related to the acquisition of assets from UGI from E&P capex of $536 million. FY26E excludes $20 - $40 MM of discretionary land spending. Upstream and Gathering >25% Reduction FY23 to FY26E Capital Efficiency ($/Mcfe)(1) >15% Continued Improvement Expected FY26E Integrated Operating Expense ($/Mcfe)
Lower Utica Gen 4 Testing Underway Gen 3 design primarily uses 1,800 ft. inter-well spacing, 2,200 lbs. per ft. of proppant intensity, and 150 ft. stage spacing. Gen 4 design primarily uses 2,000 ft. inter-well spacing, 3,000 lbs. per ft. of proppant intensity, and 150 ft. stage spacing. Blue shaded leasehold is where Seneca has > 25% ownership in township. Upstream and Gathering Lower Utica Zone Well Performance Gen 1 Lower Utica Gen 2 Lower Utica Gen 3 Lower Utica (1) Gen 4(2,3) Testing Underway Planned Producing 24
Addition of Upper Utica Zone More than Doubles Tioga Utica Inventory Upper Utica Adds ~8 Years Inventory on Existing Infrastructure Increased Core Inventory to ~400 Premium Locations Blue shaded leasehold is where Seneca has > 25% ownership in township. Includes wells online for at least 1 month and offset operator. Upstream and Gathering Upper Utica Type Curve Upper Utica(2) (9 wells) ~220 additional Upper Utica locations with similar productivity to Lower Utica ~300 ft resource column with strong frac barrier establishes two distinct zones ~170 premium Lower Utica locations with EURs of 2.5 Bcf / 1,000 ft. Upper Utica Lower Utica Frac Barrier ~300 ft Upper Utica Map(1) Third party operator Planned Producing 25
Decades of High-Quality Inventory at Industry Leading Breakevens Assumes an average of 25 to 30 wells brought online/year, which is equivalent to current pace. Enverus research is at $2.50 breakevens as of the most recent report published on June 29, 2026. Peers include EQT, RRC, AR, GPOR, Ascent, CNX, EXE. Enverus Analysis Validates Inventory Depth (1) EDA WDA Seneca Analysis: >15 Years of Inventory @ <$2.00 Breakevens Upper Utica Upstream and Gathering
Production Growth Supported by New Firm Transportation Marketing Portfolio Has Premium Market Access(1) New FT Enhances Long-Term Marketing Portfolio: Supports future production growth with egress from EDA Minimizes spot exposure (together with in-basin firm sales) Increases optionality and connectively to premium markets Data center developments (Western PA, Mid-Atlantic) Gulf Coast (LNG exports, industrial markets) Northern Markets ~30% of total Southeast, Gulf Coast ~20% of total Northeast ~20% of total Percentages in chart indicate firm transportation capacity as of fiscal 2030. FT increases of 100 MDth/d in FY26 (Premium PA Markets and Gulf Coast), 215 MDth/d in FY27 (Premium PA Markets and Gulf Coast), 275 MDth/d in FY28-30 (Premium PA Markets and Gulf Coast). NE Supply Divers. 50 MDth/d Niagara Expansion (TGP & NFG - Supply) 170 MDth/d Atlantic Sunrise (Transco) 189 MDth/d Tioga County Extension (NFG - Empire) 200 MDth/d Premium PA Markets ~30% of total Premium PA Markets 490 MDth/d ~1,000 MDth/d FT ~1,500 MDth/d FT Gulf Coast 100 MDth/d Leidy South (Transco & NFG - Supply) 330 MDth/d Upstream and Gathering
FY 2026 Sales Mix Provides Significant Price Certainty (1) Q4 Volumes: Fixed Price 24 Bcfe, NYMEX-Linked 69 Bcfe, Index 3 Bcfe. All prices shown in $/MMBtu. NYMEX-linked and Index prices shown as differentials to NYMEX. Expected production of 420 to 430 Bcfe Minimal spot exposure of 10 to 20 Bcfe (~15% of remaining volumes) Firm sales contracts in place for ~85% of expected remaining production ~75% of expected production paired with a NYMEX financial hedge or entered into at a fixed price Continue to utilize in-basin firm sales to reduce spot exposure Fiscal 2026 Highlights Upstream and Gathering Firm Sales & Production Cadence(1) $2.55 ($0.81) ($0.50) 109 Bcfe 102 Bcfe 104 Bcfe
Hedging Program: Disciplined with Upside Potential Methodical Approach to Layering in Hedges Over Time Supports Investment Grade Credit Rating Swaps and Fixed Price Sales Provide Price Certainty(1)… Swaps and Fixed Price Sales Provide Price Certainty(1)… ~55% ~25% ~40%- 45% ~70%- 75% ~95%- 100% ~20% FY26 estimated hedge percentage shown for the remaining 3 months and assumes midpoint of production guidance for the year with the remaining years at mid-single digit growth. Strip includes NYMEX settle for July 2026. (2) Upstream and Gathering …Collars and Unhedged Production Provide Upside Capture Opportunities Upside with Collars
Industry-Leading Focus on Sustainability Responsible Gas Certifications, Emission Reductions & Water Management Equitable Origin – EO100TM Standard for Responsible Energy Development Certification (100% of natural gas production and gathering assets certified) Certification focuses on three emissions management criteria: Methane Intensity Company Practices to Manage Methane Emissions Emissions Monitoring Technology Deployment MiQ (100% of production assets re-certified in August 2025) Encompasses the following principles: Corporate Governance, Transparency & Ethics Human Rights, Social Impacts & Community Development Indigenous People’s Rights Fair Labor & Working Conditions Climate Change, Biodiversity & Environment Emission Reductions Water Management Wholly-owner water management subsidiary, Highland Field Services, LLC, optimizes water handling, treatment and storage Partner with local townships, government agencies, and environmental groups on water quality improvement projects Operate a vast water pipeline network which reduces truck traffic, leading to decreased emissions and less wear on roads Both E&P (Seneca) and Gathering (Midstream) surpassed 2030 Methane Intensity Reduction Targets in calendar 2024 Significant reductions in methane driven by: Natural gas pneumatic device conversions Operational BMPs for well liquids unloading and flowback Increased fugitive emissions monitoring In 2024, Highland recycled more than 95% of Seneca’s produced fluids Upstream and Gathering Executed a long-term agreement with Centrica Energy to sell 250,000 MMBtu/day of MiQ-certified gas certificates over the next ten years.
Pipeline & Storage and Utility Overview Business Highlights
Pipeline & Storage and Utility Highlights Tioga Pathway and Shippingport Lateral projects expected to add ~$30 MM in incremental revenue annually Supply expanded the Line N System Upgrade project to 294,000 Dth/d, executing a precedent agreement for 200,000 Dth/d of incremental firm transportation capacity NY Utility 3-Year rate case settlement(2) drives continued earnings growth PA Utility rate case filed on 1/28/2026, with rates expected to be effective 11/1/26 Supply filed a rate case with FERC on 4/30/26, requesting new rates effective 11/1/26 with an annual cost of service increase of $95 MM relative to 2024 settlement Utility rate base is expected to double upon closing, significantly increasing scale Begins to rebalance business mix by increasing share of regulated earnings and cash flows Supports long-term 5-7% regulated adjusted EPS target, while growing regulated earnings Pipeline Expansion Projects Drive Meaningful Growth Rate Case Activity Balances Modernization Spending & Affordability Continued Growth Expected from Ohio Utility Acquisition DSIC tracker allows recovery on incremental system investments after July 31, 2024, subject to attaining rate year plant balance of $781.3 million and earning below a statewide ROE target (currently 10.25%). See Case 23-G-0627 on file with the NY PSC. Long-standing modernization programs enable continued investment in the system to ensure the safety and reliability of service to customers Utility Rate base growth in PA from Distribution System Improvement Charge (DSIC)(1), or system modernization tracker, allows for additional earnings growth up to ~$7 MM/year Long-term expected rate base growth of approximately 5-7% drives earnings growth Modernization Programs Drive Rate Base Growth
Pipeline & Storage Segment Overview Firm transportation includes short-term and long-term and is disclosed annually as of September 30, 2025. Reported as of June 30, 2026. Empire Pipeline, Inc. National Fuel Gas Supply Corporation Empire Pipeline Supply Corp. Contracted Capacity(1): Firm Storage: 71 Bcf (fully subscribed) Firm Transportation: 3.4 Bcf / day Rate Base(2): ~$1.4 billion FERC Rate Proceeding Status: Filed rate case on April 30, 2026 New rates expected to go into effect on Nov. 1, 2026 Requested an annual cost of service increase of $95 MM relative to 2024 settlement Contracted Capacity(1): Firm Storage: 4 Bcf (fully subscribed) Firm Transportation: 1.1 Bcf / day Rate Base(2): ~$0.3 billion FERC Rate Proceeding Status: Settlement approved by FERC on March 17, 2025 New rates went into effect November 1, 2025 Moratorium period until April 30, 2027 Comeback required by May 31, 2031 Pipeline & Storage
Pipeline & Storage Customer Mix Customer Transportation by Shipper Type Affiliated Customer Mix (Contracted Capacity) Note: Data disclosed annually as of 9/30/2025. Pipeline & Storage Firm Transport
Pipeline Modernization & Expansion Projects Propel Growth A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation. FY26E capex is presented at mid-point of guidance. Capex Investments Support Long-Term Rate Base Growth Estimate of ~5-7% Pipeline & Storage Organic Growth Drivers Expect long-term non-expansion capex spend of ~$100-150 MM/year Expansion projects drive further growth, including the Tioga Pathway and Shippingport Lateral projects (expected in-service November 2026) Tioga Pathway & Shippingport Lateral Project Line N System Upgrade project expected in-service November 2028
Tioga Pathway Project Creates Organic Growth Capacity: 190,000 Dth/day Estimated capital cost: ~$100 million ~$82 million in expansion capital Estimated annual revenue: ~$15 million (underpinned by 15-year agreement with Seneca) Provides Seneca access to premium markets: Connectivity into TGP 313 Pool and Transco Leidy Line Pool Access to Transco Z6 Non-NY markets via downstream Leidy South FT capacity Facilities (all in Pennsylvania) include: Approximately 20 miles of new pipeline Replacement of ~4 miles of existing pipeline (with new 20” pipeline) Project Milestones: Project commenced construction in May 2026 On track for targeted in-service date of November 2026 Pipeline & Storage Long-term revenue growth for Supply, while providing an additional outlet for Seneca’s EDA production Project Pipeline
Line N System Upgrade Project Newly executed commercial agreement to support the initial phase of the coal-to-gas power plant conversion at Shippingport Industrial Park Replacement of ~7 miles of Line N Total Capex: ~$100 million (~$34 million in expansion capital) Expansion Capacity: 294,000 Dth/day with delivery to: TGP – Mercer (94,000 Dth/d) Shippingport Industrial Park (200,000 Dth/d) Target In-Service: November 2028 Executed Precedent Agreements in place Foundation Shipper Open Season closed July 2026 with project capacity awarded in full Shippingport Lateral Project Supports behind the meter data center development along the Line N corridor Total Capex: ~$57 million Target In-Service: November 2026 Capacity: 205,000 Dth/day Estimated annual revenue: ~$15 million (underpinned by 20-year agreement with an investment-grade developer) Continued Expansion Opportunities Along Supply’s Line N System Pipeline & Storage Added 200,000 Dth/day of capacity Shippingport Power Station Total gas demand could reach ~800,000 Dth/d(1) Includes ~205,000 Dth/d supporting the BTM data center and up to 600,000 Dth/d supporting the full coal-to-gas conversion. Projects represent separate facilities and shippers.
Utility Service Territories in New York & Pennsylvania New York Last Rate Case: Joint Proposal approved December 19, 2024 (3-year rate plan effective Oct. 1, 2024 through Sept. 30, 2027) Total Customers(1): ~543,000 Allowed ROE: 9.7% (NYPSC Case 23-G-0627) Rate Mechanisms: Revenue Decoupling Weather Normalization Low Income Customer Discount Reconciliation Merchant Function Charge (Uncollectibles Adj.) 90/10 Sharing (Large Customers) Uncollectible Expense Tracker Pennsylvania *Filed rate case with the PAPUC in January 2026, see next slide Last Rate Case: 2023 (rates effective August 1, 2023) Total Customers(1): ~213,000 Allowed ROE: Black-box settlement (2023) Rate Mechanisms: Weather Normalization (added Aug. 1, 2023), subject to 3% deadband Low Income Rates Merchant Function Charge (Uncollectibles Adj.) Distribution System Improvement Charge (DSIC) Initiated recovery of eligible costs on January 1, 2025 Disclosed annually as of September 30, 2025. Utility
Pennsylvania Rate Case Overview Base Rate Increase = $19.7 million 7.4% increase in total revenues, or ~2.5% increase per year since last rate case New rates expected to be effective November 1, 2026 Proposed Base Revenue Increase Key Drivers Capital Structure and Returns: Capital Structure = 43.6% debt / 56.4% equity Return on Equity = 11.25% Total Rate of Return = 8.78% Increasing rate base and depreciation expense associated with higher plant in-service NFGDC PA plans to accelerate pipeline replacement from 53 miles in 2025 to 57 miles in 2027 O&M expense inflation (e.g., labor and benefits) Seeking permanent status for Weather Normalization Adjustment (WNA) mechanism Proposing Residential Energy Efficiency pilot program Proposing to mitigate the rate increase by utilizing $7 MM set aside in a trust for the future benefit of rate payers (related to previous OPEB over-collections) On January 28, 2026, National Fuel Gas Distribution Corporation filed a request with the Pennsylvania Public Utility Commission (PAPUC) to amend its tariff and increase its base rates Utility
NY Utility Rate Activity Supports Growing Earnings Outlook Three-Year Rate Settlement(1) Approved on December 19, 2024 Rate activity: Constructive three-year rate settlement approved and implemented effective January 2025, providing earnings visibility through fiscal 2027 Modernization (pipeline replacement) program maintained at a minimum of 105 miles per year over rate plan Recovery of system modernization costs, including higher rate base and depreciation expense, now included in new base rates (revenue requirement) Ratemaking mechanisms: Continuation of: weather normalization; revenue decoupling; industrial 90/10 symmetrical sharing; merchant function charge New: uncollectible expense tracker; gas safety and customer service performance metrics; customer bill impact levelization See Case 23-G-0627 on the NY PSC website. Rate Case Drivers Old Rates Approved (New) Rates (in millions) FY24 FY25 FY26 FY27 Revenue Requirement Cumulative Increase (relative to FY24) n/a $57.3 $73.1 $85.8 Rate Base $858 $1,044 $1,104 $1,163 Authorized ROE 8.7% 9.7% 9.7% 9.7% Authorized Equity Ratio 43% 48% 48% 48% Utility Utility System Modernization Tracker (SMT) on file: Potentially providing further earnings stability through continued recovery of capital investments and minimizing near-term general rate case filing need
Customer Affordability New York Pennsylvania Based on 2025 average monthly residential bill data posted on company websites (required by the NYPSC). Based on analysis of 2026 PAPUC Annual Rate Comparison Report, which includes data for average monthly residential bills for January 2026. Utility #1 Out of 9 Gas Utilities(1) #1 Out of 6 Gas Utilities(2) Expect to be among the lowest in calendar 2026 as well, including rate increase Expect to be among the lowest in calendar 2027 as well, including proposed rate increase
Utility Continues its Significant Investments in Safety (1) A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation. Increase from FY23 to FY24 is partially due to the impact of New York State’s Roadway Excavation Quality Assurance Act (“REQAA”) which will continue to increase investment costs in future years. Long-Standing Focus on Distribution System Safety and Reliability Utility (2)
Long-Standing Pipeline Replacement & Modernization NY ~10,000 miles PA ~5,000 miles Miles of Utility Main Pipeline Replaced(2) Utility Mains by Material(1) (1) All values are reported on a calendar year basis, as of December 31, 2025, as required by the DOT. (2) All values are reported on a fiscal year basis, as required by the NYPSC and PAPUC. Utility
Baseline emissions & emissions reduction targets are calculated pursuant to the reporting methodology under the EPA GHG Reporting Program (current Subpart W, and using AR5), primarily Distribution pipeline mains & services. Revisions of Subpart W emissions factors, effective for 2025 reporting, will change the reported baseline, 2025 emissions profile, and progress against these targets. New York Climate Leadership and Community Protection Act, enacted in 2019. Targets Exceed Those Included in New York State Climate Act (CLCPA)(2) Reductions Primarily Driven by Ongoing Modernization of Mains and Services Utility Targeting Substantial Emissions Reductions 2030 75% Significant Reductions in Utility GHG Emissions to Date, Driven by System Modernization Efforts GHG Reduction Targets, Continuing Focus on Lowering Carbon Footprint ~70% Reduction Since 1990 (510,000 Metric Tons CO2e) Utility GHG Emissions Reduction Targets(1) (Based on 1990 EPA Subpart W Emissions) 90% 2050 Utility
Guidance & Other Financial Information Contact Information: Ryan Vossler, Director of Investor Relations (716) 857-7158 [email protected]
Updated FY26 Adjusted EPS Guidance & Assumptions Note: The acquisition of CenterPoint Energy’s Ohio natural gas utility business is expected to close on October 1, 2026, and therefore, has no impact on FY26 shown above, including financing and acquisition related costs. Excludes items impacting comparability. See Comparable GAAP Financial Measure Slides & Reconciliations at the end of this presentation. Guidance assumes NYMEX pricing of $3.00/MMBtu and in-basin spot pricing of $2.15/MMBtu for the remaining 3 months in Fiscal 2026, and reflects the impact of existing financial hedges, firm sales and firm transportation contracts. Updated Integrated Upstream & Gathering guidance excludes $20 - $40 MM of discretionary land spending. Customer Margin is defined as Operating Revenues less Purchased Gas Expense. Consolidated Effective Tax Rate ~25.5% ~25.5% Integrated Upstream & Gathering Previous Guidance Updated Guidance NYMEX natural gas price (per MMBtu) $3.00 Remaining 6 months $3.00 Remaining 3 months Spot Price (per MMBtu) $2.20 Remaining 6 months $2.15 Remaining 3 months Production (Bcf) 425 – 440 420 – 430 Integrated Operating Costs ($/Mcf) Upstream G&A ~$0.18 ~$0.18 LOE $0.16 - $0.17 $0.15 - $0.16 Gathering O&M ~$0.12 ~$0.12 DD&A $0.76 - $0.81 $0.77 - $0.80 Pipeline & Storage Previous Guidance Updated Guidance Revenues ($MM) $420 – $435 $420 – $435 O&M Expense 4 – 5% increase 4 – 5% increase Utility ($MM) Previous Guidance Updated Guidance Customer Margin(4) $470 – $490 $470 – $490 O&M Expense $250 - $260 $250 - $260 Non-Service Pension / OPEB Income $23 - $27 $23 - $27 Capital Expenditures ($MM) Previous Guidance Updated Guidance Integrated Upstream & Gathering $560 – $610 $580 – $605(3) P&S $210 – $250 $235 – $265 Utility $185 – $205 $185 – $205 Total Company $955 – $1,065 $1,000 – $1,075 (1) Assuming $3.00 NYMEX, FY26 Adjusted EPS(2) of $7.40 - $7.60 ($7.50 at midpoint) represents 9% increase from FY25 46
Type Curves Demonstrate Outstanding Well Results *All TILs except for 1 in FY26 are Tioga Utica Estimated wells Fiscal 2026 Drills 25 - 27 TILs* 25 - 27 Avg. TLL 12,500 – 13,000’ Drilling rigs 1.5 Estimated Tioga Utica Lower Tioga Utica Upper Tioga Marcellus Lycoming Marcellus WDA Utica Location Count 170 220 56 20 250 Avg. TLL (ft) 13,000’ 13,000’ 10,000’ 8,000’ 13,000’ D&C ($000s/ft) $1,250- $1,300 $1,250- $1,300 $900- $1,000 $1,075- $1,125 $1,050- $1,100 Avg. Royalty 15% 15% 15% 16% 2% EUR (Bcfe/ft) 2.5 2.0 – 2.4 2.0 2.7 1.7 Operational Data
Regulated Businesses: Rate Case Overview Supply Empire NY(2) PA Regulatory Agency (Governed by) FERC FERC NYPSC PAPUC Timing / Status Filed rate case on April 30, 2026 Requesting new rates effective November 1, 2026 Requested an annual cost of service increase of $95 MM relative to 2024 settlement Amendment to 2019 Settlement approved by FERC on March 17, 2025 New rates went into effect November 1, 2025 Moratorium period until April 30, 2027 Comeback required by May 31, 2031 Joint Proposal approved(2) December 2024 with no significant modifications in the settlement 3-year rate plan effective October 1, 2024, with make-whole provision Filed rate case on January 28, 2026 requesting new rates effective Nov. 2026 with a $19M increase in base rates Last settlement approved in June 2023 Rates in effect since August 1, 2023 Rate Base(1) (in billions) $1.4 $0.3 $1.1 $0.5 Equity Ratio Not stated – Black box settlement Not stated – Black box settlement Authorized 48% Not stated – Black box settlement Authorized ROE Not Stated – Black box settlement Not Stated – Black box settlement Authorized 9.7% Not Stated – Black box settlement Pipeline & Storage Utility Estimated as of June 30, 2026. See Case 23-G-0627 on file with the NY PSC.
Detailed Hedging Information for Modeling Calculated as the weighted average NYMEX forward price for each time period shown based on the Fixed Price Physical firm sale execution date, plus basis differentials and transportation costs. (All volumes in MMBtu; Prices in $ / MMBtu) 4Q 26 1Q 27 2Q 27 3Q 27 4Q27 FY 27 FY 28 FY 29 Hedged Volumes 86,105 83,464 72,347 57,805 58,050 271,666 131,385 34,629 Swaps Volume 36,810 35,530 29,640 28,440 28,440 122,050 57,730 4,350 Wtd. Avg. Price $4.04 $4.02 $3.94 $3.92 $3.92 $3.95 $3.82 $3.73 Collars Volume 25,200 23,800 19,620 7,440 7,440 58,300 17,680 -- Wtd. Avg. Ceiling $4.58 $4.70 $4.79 $4.25 $4.25 $4.62 $4.67 -- Wtd. Avg. Floor $3.54 $3.65 $3.71 $3.34 $3.34 $3.59 $3.64 -- Fixed Price Physical Volume 24,095 24,134 23,087 21,925 22,170 91,316 55,975 30,279 Wtd. Avg. Price $2.55 $2.63 $2.69 $2.64 $2.64 $2.65 $2.80 $2.83 NYMEX Equiv. Price(1) $2.74 $3.39 $3.81 $3.64 $3.45 $3.57 $3.73 $3.71 Capped Firm Sales Volume 1,503 1,492 1,462 1,481 1,500 5,919 506 -- NYMEX Cap $4.95 $4.95 $4.95 $4.95 $4.95 $4.95 $4.95 -- Volume -- 1,343 1,976 1,993 2,011 7,274 7,926 7,873 NYMEX Cap $5.00 $5.00 $5.00 $5.00 $5.00 $5.00 $5.00 $5.00 Volume 4,017 3,990 3,893 3,986 4,022 15,891 15,852 15,746 NYMEX Cap $5.65 $5.65 $5.65 $5.65 $5.65 $5.65 $5.65 $5.65 Volume 1,832 1,809 1,775 1,808 1,831 7,222 7,296 7,354 NYMEX Cap $7.00 $7.00 $7.00 $7.00 $7.00 $7.00 $7.00 $7.00
Comparable GAAP Financial Measure Slides & Reconciliations This presentation contains certain non-GAAP financial measures. For pages that contain non-GAAP financial measures, pages containing the most directly comparable GAAP financial measures and reconciliations are provided in the slides that follow. The Company believes that its non-GAAP financial measures are useful to investors because they provide an alternative method for assessing the Company’s ongoing operating results or liquidity and for comparing the Company’s financial performance to other companies. The Company’s management uses these non-GAAP financial measures for the same purpose, and for planning and forecasting purposes. The presentation of non-GAAP financial measures is not meant to be a substitute for financial measures prepared in accordance with GAAP. Management defines adjusted earnings and adjusted earnings per share as reported GAAP earnings before items impacting comparability. Management defines adjusted EBITDA as reported GAAP earnings before the following items: interest expense, income taxes, depreciation, depletion and amortization, other income and deductions, impairments, and other items reflected in operating income that impact comparability. The revised adjusted earnings per share guidance range also excludes certain items that impacted the comparability of adjusted operating results during the six months ended March 31, 2026, including after-tax unrealized losses on other investments, which reduced earnings by $0.01 per share. While the Company expects to record certain adjustments to unrealized gain or loss on investments during the remaining six months ending September 30, 2026, the amounts of these and other potential adjustments are not reasonably determinable at this time. As such, the Company is unable to provide earnings guidance other than on a non-GAAP basis. Management defines free cash flow as net cash provided by operating activities, less net cash used in investing activities, adjusted for acquisitions and divestitures. The Company is unable to provide a reconciliation of projected free cash flow as described in this presentation to its respective comparable financial measure calculated in accordance with GAAP without unreasonable efforts. This is due to our inability to reliably predict the comparable GAAP projected metrics, including operating income and total production costs, given the unknown effect, timing, and potential significance of certain income statement items. Reconciliations of forward-looking non-GAAP financial measures and non-GAAP ratios to comparable GAAP measures are not available due to the challenges and impracticability of estimating certain items, particularly depreciation and depletion expense, interest expense, income tax expense (benefit), other potential adjustments and charges, including ceiling test impairments, and non-cash unrealized derivative fair value gains and losses that are subject to market variability. Because of those challenges, a reconciliation of forward-looking non-GAAP financial measures and non-GAAP ratios is not available without unreasonable effort.
Non-GAAP Reconciliations - Adjusted Operating Results
Non-GAAP Reconciliations - Adjusted EBITDA, by Segment
Non-GAAP Reconciliations - Adjusted EBITDA & Net Debt
Non-GAAP Reconciliations - Funds From Operations
Reconciliation – Capital Expenditures
Reconciliation – Free Cash Flow
Safe Harbor For Forward Looking Statements This presentation may contain “forward-looking statements” as defined by the Private Securities Litigation Reform Act of 1995, including statements regarding future prospects, plans, objectives, goals, projections, estimates of gas quantities, strategies, future events or performance and underlying assumptions, capital structure, anticipated capital expenditures, completion of construction projects, projections for pension and other post-retirement benefit obligations, impacts of the adoption of new accounting rules, and possible outcomes of litigation or regulatory proceedings, as well as statements that are identified by the use of the words “anticipates,” “estimates,” “expects,” “forecasts,” “intends,” “plans,” “predicts,” “projects,” “believes,” “seeks,” “will,” “may,” and similar expressions. Forward-looking statements involve risks and uncertainties which could cause actual results or outcomes to differ materially from those expressed in the forward-looking statements. The Company’s expectations, beliefs and projections are expressed in good faith and are believed by the Company to have a reasonable basis, but there can be no assurance that management’s expectations, beliefs or projections will result or be achieved or accomplished. In addition to other factors, the following are important factors that could cause actual results to differ materially from those discussed in the forward-looking statements: changes in laws, regulations or judicial interpretations to which the Company is subject, including those involving derivatives, taxes, safety, employment, climate change, other environmental matters, real property, and exploration and production activities such as hydraulic fracturing; governmental/regulatory actions, initiatives and proceedings, including those involving rate cases (which address, among other things, target rates of return, rate design, retained natural gas and system modernization), environmental/safety requirements, affiliate relationships, industry structure, and franchise renewal; changes in economic conditions, including the imposition of additional tariffs on U.S. imports and related retaliatory tariffs, inflationary pressures, supply chain issues, liquidity challenges, and global, national or regional recessions, and their effect on the demand for, and customers’ ability to pay for, the Company’s products and services; the Company’s ability to complete strategic transactions, such as the planned CenterPoint Ohio acquisition, including receipt of required regulatory clearances and satisfaction of other conditions to closing, and to recognize the anticipated benefits of such transactions; governmental/regulatory actions and/or market pressures to reduce or eliminate reliance on natural gas; the Company’s ability to estimate accurately the time and resources necessary to meet emissions targets; changes in the price of natural gas; impairments under the SEC’s full cost ceiling test for natural gas 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, other investments, and acquisitions, including any downgrades in the Company’s credit ratings and changes in interest rates and other capital market conditions; negotiations with the collective bargaining units representing the Company’s workforce, including potential work stoppages during negotiations; changes in price differentials between similar quantities of natural gas sold at different geographic locations, and the effect of such changes on commodity production, revenues and demand for pipeline transportation capacity to or from such locations; the impact of information technology disruptions, cybersecurity or data security breaches, including the impact of issues that may arise from the use of artificial intelligence technologies; factors affecting the Company’s ability to successfully identify, drill for and produce economically viable natural gas reserves, including among others geology, lease availability and costs, title disputes, weather conditions, water availability and disposal or recycling opportunities of used water, shortages, delays or unavailability of equipment and services required in drilling operations, insufficient gathering, processing and transportation capacity, the need to obtain governmental approvals and permits, and compliance with environmental laws and regulations; increased costs or delays or changes in plans with respect to Company projects or related projects of other companies, as well as difficulties or delays in obtaining necessary governmental approvals, permits or orders or in obtaining the cooperation of interconnecting facility operators; increasing health care costs and the resulting effect on health insurance premiums and on the obligation to provide other post-retirement benefits; other changes in price differentials between similar quantities of natural gas having different quality, heating value, hydrocarbon mix or delivery date; the cost and effects of legal and administrative claims against the Company or activist shareholder campaigns to effect changes at the Company; uncertainty of natural gas reserve estimates; significant differences between the Company’s projected and actual production levels for natural gas; changes in demographic patterns and weather conditions (including those related to climate change); changes in the availability, price or accounting treatment of derivative financial instruments; changes in laws, actuarial assumptions, the interest rate environment and the return on plan/trust assets related to the Company’s pension and other post-retirement benefits, which can affect future funding obligations and costs and plan liabilities; economic disruptions or uninsured losses resulting from major accidents, fires, severe weather, natural disasters, terrorist activities or acts of war, as well as economic and operational disruptions due to third-party outages; significant differences between the Company’s projected and actual capital expenditures and operating expenses; or increasing costs of insurance, changes in coverage and the ability to obtain insurance. The Company disclaims any obligation to update any forward-looking statements to reflect events or circumstances after the date thereof. Forward-looking statements include estimates of gas quantities. Proved gas reserves are those quantities of gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible under existing economic conditions, operating methods and government regulations. Other estimates of gas quantities, including estimates of probable reserves, possible reserves, and resource potential, are by their nature more speculative than estimates of proved reserves. Accordingly, estimates other than proved reserves are subject to substantially greater risk of being actually realized. Investors are urged to consider closely the disclosure in our Form 10-K available at www.nationalfuel.com. You can also obtain this form on the SEC’s website at www.sec.gov. Forward-looking and other statements in this presentation regarding methane and greenhouse gas reduction plans and goals are not an indication that these statements are necessarily material to investor or required to be disclosed in our filings with the SEC. In addition, historical, current and forward-looking statements regarding methane and greenhouse gas emissions may be based on standards for measuring progress that are still developing, internal controls, and processes that continue to evolve and assumptions that are subject to change in the future. For a discussion of the risks set forth above and other factors that could cause actual results to differ materially from results referred to in the forward-looking statements, see “Risk Factors” in the Company’s Form 10-K for the fiscal year ended September 30, 2025, and the Form 10-Q for the quarters ended December 31, 2025 and March 31, 2026. 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.