National Fuel Gas Co 8-K, filed Nov 4, 2026
National Fuel Gas Co (NFG)
About this 8-K
National Fuel Gas Co filed this 8-K on November 4, 2026.
National Fuel Gas Company said Seneca Resources’ tax-free spin-off is targeted for the second half of calendar year 2027 and issued initial FY2027 adjusted EPS guidance of $6.00 - $6.40 per share. AI summary
Items reported
- Item 7.01: Regulation FD disclosure
- Item 9.01: Financial statements and exhibits
UNITED STATES
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| Item 7.01 | Regulation FD Disclosure. |
On November 4, 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, including statements regarding estimated future earnings and statements that are identified by the use of the words “anticipates,” “believes,” “could,” “estimates,” “expects,” “forecasts,” “guidance,” “intends,” “may,” “might,” “outlook,” “plans,” “potential,” “predicts,” “projects,” “seeks,” “targets,” “will,” “would”, and variations of such words and similar future or conditional expressions, and statements which are other than statements of historical facts, are intended to identify “forward-looking statements” as defined under U.S. federal securities laws, including, but not limited to, statements, estimates, and projections relating to the potential separation of the Company into two companies (the “Separation”), including the timing and structure of the Separation, the characteristics of the separated businesses, and the expected benefits of the Separation, future operating and financial performance and long-term strategy, and the assumptions underlying such expected benefits, targets, strategies, and statements. These forward-looking statements are based on management’s beliefs, expectations, estimates, and projections at the time they are made and are not guarantees of future performance.
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 contained herein are expressed in good faith and are believed to have a reasonable basis, but there can be no assurance that such expectations, beliefs, or projections will result or be achieved or accomplished. There can be no guarantees with respect to whether the Separation will be completed. 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.
In addition to other factors, the following are among the important factors that could cause actual results to differ materially from those discussed in the forward-looking statements: the ability to effect the Separation and to meet the conditions related thereto; the ability to obtain any consents or approvals required to complete the Separation; the ability of the separated companies to each succeed as standalone publicly traded companies; negative effects of the announcement or pendency of the Separation on the market price of the Company’s securities and/or on the Company’s financial performance; the possibility that the Separation will not achieve its intended benefits; the possibility of disruption, including disputes, litigation, or unanticipated costs in connection with the Separation; the impact of the Separation on the Company’s businesses and the risk that the Separation may be more difficult, time-consuming, or costly than expected, including the impact on the Company’s resources, systems, procedures, and controls, diversion of management’s attention, and the impact and possible disruption of existing relationships with regulators, customers, suppliers, employees, and other business counterparties; the ability to achieve anticipated capital structures in connection with the Separation; the ability to achieve anticipated credit ratings in connection with the Separation; the ability to achieve anticipated tax treatments in connection with the Separation and future, if any, divestitures, mergers, acquisitions, and other portfolio changes, and the impact of changes in relevant tax and other laws and regulations; the Company’s ability to complete strategic transactions, such as the plan to separate the Company into two independent, publicly traded companies through a tax-free spin-off of the Company’s Integrated Upstream and Gathering business, including receipt of required regulatory clearances and satisfaction of other conditions to closing, and to recognize the anticipated benefits of such transactions; 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; 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, 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; increasing costs of insurance, changes in coverage, and the ability to obtain insurance; other factors described in the risk factors set forth in the Company’s filings with the U.S. Securities and Exchange Commission, including the Company’s most recently filed Annual Report on Form 10-K and subsequent Current Reports on Form 8-K and Quarterly Reports on Form 10-Q.
Forward-looking statements speak only as of the date on which they are made, and the Company undertakes no obligation, and disclaims any duty to update, revise, or withdraw any forward-looking statement, whether as a result of new information, future events, or otherwise, except as required by applicable law or regulation.
Item 9.01 Financial Statements and Exhibits.
| (d) | Exhibits |
| Exhibit 99 | Investor Presentation dated November 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: November 4, 2026
Investor Presentation Fiscal 2026 – 4th Quarter & Full Year Update November 5, 2026 Exhibit 99
National Fuel Gas Company Company Overview (3) National Fuel Today (4) Planned Separation of IUG (5) Key Investment Highlights (8) Fiscal 2026 Results (11) Integrated Upstream & Gathering Highlights (16) Regulated Business Highlights (25) Guidance & Other Financial Information (41)
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 ~2,600 employees NYSE: NFG Market Cap: ~$7.6B(1) 124 Years of consecutive dividend payments 56 Years of consecutive dividend increases Achieved FY 2026 9% adjusted EPS growth vs. FY 2025(2) 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 November 2, 2026. 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.
National Fuel Today… Developing our large, high-quality acreage in Marcellus & Utica shales Providing safe, reliable and affordable service to customers in WNY, NW PA, and Western Ohio CNP Ohio Acquisition Doubled Utility 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(2) 83 Bcf of fully-contracted natural gas storage capacity ~5 MMDth Daily interstate pipeline capacity under contract ~1.1 Million Utility customers >20,000 Miles of Utility pipeline 69% 18% 13% Adjusted EBITDA(1) Non-Regulated Regulated Twelve months ended Sept 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. Does not include EBITDA contribution from Ohio gas utility acquisition which closed on October 1, 2026. Average for the three months ended Sept 30, 2026.
…National Fuel Tomorrow: Planned Separation References NYMEX Henry Hub prices to breakeven assuming a PV-10 value. Assumes an average of 25 wells brought online/year, which is equivalent to current pace. NFG expects no need to raise incremental equity capital over the next five years based on current capital plans. National Fuel Shareholders National Fuel 100% rate-regulated company with natural gas utility and interstate pipeline and storage businesses ~1.1 Million Utility Customers 83 Bcf Fully-Contracted Storage Capacity ~5 Bcf/d Contracted Firm Transportation Capacity ~1.1 Bcf/d Net Natural Gas Production Seneca Resources Highly-integrated Appalachian natural gas upstream and gathering company 25+ years Marcellus and Utica Inventory @ $2.25 NYMEX ~1.0 Bcf/d Firm Transportation Capacity ~$5 Billion Rate Base $0.58 / Mcfe Top-Tier Cash Operating Costs #1 Customer Affordability Lowest Delivery Rates in NY & PA ~5.2 Tcfe Total Proved Reserves Preserving Key Benefits of Integration that Each Business Realizes Today $0 Projected Equity Needs(2) >25% Improvement in Capital Efficiency Trends Since 2023 (1) Establishes Two Scaled, Premier Independent Natural Gas Companies
National Fuel: A Premier Fully Regulated Natural Gas Company Natural Gas Utility and Interstate Pipeline & Storage Estimated as of September 30, 2026. Reported annually as of September 30, 2026, and includes short-term and long-term contracted capacity. Includes ~6 Bcf related to the acquisition of Honeoye Storage Corporation completed in October 2026. Includes Tioga Pathway Project and Shippingport Lateral Project. 100% rate-regulated natural gas utility, interstate pipeline and storage company in cold weather climates with constructive regulatory jurisdictions Utility business serves ~1.1 million customers ~5 Bcf/d(2) of FERC-regulated contracted transportation capacity, including ~0.4 Bcf/d(3) of expansion projects placed into service on November 1, 2026 ~83 Bcf(2) of fully-contracted natural gas storage capacity Significant long-term modernization and expansion investment opportunities Ongoing focus on customer affordability, with integrated operations driving lower operating costs ~$5 B NY $1.1 PA $0.5 OH $1.6 FERC $1.7 Total Rate Base ($B)(1)
Seneca: A Premier Integrated Appalachian Natural Gas Company Reported annually as of September 30, 2026. Average net production and throughput for the three months ended September 30, 2026. References NYMEX Henry Hub prices to breakeven assuming a PV-10 value. Assumes an average of 25 wells brought online/year, which is equivalent to current pace. Total Net Acres (Pennsylvania): ~1.2 million Total Proved Reserves: 5.2 Tcfe(1) Current Net Production: ~1.1 Bcf/d(2) Current Firm Transportation: ~1 Bcf/d to premium markets 25+ years of inventory with breakeven prices below $2.25/MMBtu(3) Wholly-owned integrated gathering infrastructure provides a durable cost advantage, supporting top-tier cash operating costs of ~$0.58/Mcfe Western Development Area Eastern Development Area Eastern Development Area ~310,000 Acres Development Zones: Marcellus, Utica Western Development Area ~920,000 Acres (mostly owned in fee) Development Zones: Marcellus, Utica OTHER PIPELINES SENECA ACREAGE NFG GATHERING
Key Investment Highlights Premier asset base supported by integrated, low-cost operations, peer-leading inventory depth and long-term growth potential 25+ years of development inventory at PV-10 breakeven prices of less than $2.25/MMBtu(1) Significant free cash flow generation supports shareholder returns, balance sheet strength, and long-term value creation Firm transportation portfolio provides ~1.5 Bcf/d by 2030 to premium-priced demand markets and supports future production growth Demonstrated capital efficiency gains, with >25% improvement since 2023, with further improvement expected over time National Fuel Seneca Resources Durable earnings growth driven by supportive ratemaking backdrop all jurisdictions – Ohio, New York, Pennsylvania, and FERC Under development expansion projects and long-term visibility for system modernization investments support 5-7% rate base growth outlook Expected to have strong investment grade credit rating in line with best-in-class peers with no expected incremental equity needs over the next five years Long history of delivering industry-leading affordability resulting from focus on controlling costs and benefits of integrated regulated operations Long-term natural gas demand growth supports additional infrastructure expansion potential Two Scaled, Well-Positioned Companies Built for Long-Term Success References NYMEX Henry Hub prices to breakeven assuming a PV-10 value. Assumes an average of 25 wells brought online/year, which is equivalent to current pace.
Planned Separation Details and Expected Timing Transaction Structure IUG will be named Seneca Resources and is expected to trade on the NYSE Separation expected to be effected through a tax-free distribution of Seneca shares to National Fuel shareholders National Fuel shareholders will retain National Fuel shares and receive Seneca shares on a pro rata basis Retained Ownership National Fuel expects to retain up to a 19.9% ownership interest in Seneca and intends to dispose of in a tax-efficient manner Monetization proceeds expected to further strengthen National Fuel’s investment grade balance sheet Leadership & Governance Each company to have a dedicated management team and board of directors National Fuel: David P. Bauer to remain President and Chief Executive Officer; Timothy J. Silverstein to remain Treasurer and Chief Financial Officer Seneca Resources: Justin Loweth to become Chief Executive Officer Closing Conditions Final approval by National Fuel’s Board of Directors Form 10 effectiveness Completion of financing arrangements Favorable tax treatment and other customary conditions Expected Timing Targeted for completion in the second half of calendar year 2027
Financial Overview
Achieved 9% Annual Adjusted EPS Growth in Fiscal 2026 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. Management defines free cash flow as net cash provided by operating activities, less net cash used in investing, adjusted for acquisitions and divestitures. See Comparable GAAP Financial Measure Slides & Reconciliations at the end of this presentation. Represents Integrated Upstream & Gathering segment. FY26 Results 9% year-over-year adjusted earnings per share growth(1) ~$200 million of free cash flow generated(2) 56th consecutive annual dividend increase Recent Strategic Highlights Completed acquisition of Ohio natural gas utility Announced plan to spin-off Seneca Resources(3) Approval of $10.4 million Utility rate increase in Pennsylvania and System Modernization Tracker in New York Tioga Pathway and Shippingport Lateral projects placed into service 1 2 3 4 1 2 3
Capital Investment Supports Growth Across Each Business (2,3) Capital expenditures includes accrued capital expenditures. 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. FY2027 consolidated capital guidance is displayed at the midpoint of the range ($1,090 - $1,220 million). FY24 reflects the netting of $6.2 million related to the acquisition of assets from UGI. FY 2026 capital expenditures exclude $38 MM of IUG discretionary land capital. FY 2027E IUG guidance excludes $50 - $100 MM of discretionary land capital. Capital Expenditures by Segment ($ millions)(1) FY 2027 Capital Drivers Integrated Upstream & Gathering Underlying activity level largely unchanged year-over-year Higher capital related to third-party gathering and non-op investments Pipeline & Storage Utility Regulated Growth Ongoing system modernization investments Tioga Pathway and Shippingport Lateral projects placed in service November 1, 2026 Continued pipeline replacement and system modernization Full-year investment in recently acquired Ohio utility $140 - $180
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 9/30/26 Downgrade Threshold Downgrade Threshold $1.3B Committed Credit Facility (2) (2) (2) Temporary impact of Ohio acquisition financing $1.2B Seller Note due 9/30/2027 Temporary impact of Ohio acquisition financing 13
Enhanced Financial Profile Post-Separation High-quality resource base, efficiently capitalized for disciplined growth and long-term shareholder returns Compelling rate-regulated return proposition, driven by stable cash flows, predictable growth, and a strong credit profile Expect strong balance sheet and improved investment grade credit metrics, in line with some of the strongest peers in the utility sector Strong leverage profile and hedge book designed to provide the flexibility to navigate volatile market cycles National Fuel Seneca Resources Credit Profile Return of Capital Financing Needs Dividend policy expected to be consistent with utility peers, with visibility towards above-average dividend per share growth No expected need to raise incremental equity capital over the next five years based on current capital plans Significant free cash flow generation expected through commodity cycles, supporting balance sheet strength, share repurchases, and disciplined growth Disciplined use of free cash flow, balancing leverage reduction with growth and share repurchases
Integrated Upstream and Gathering Business Highlights
Integrated Upstream & Gathering Highlights Significant Improvement in Capital Efficiency (FY23 to FY26) ~25% Improvement Since FY23 Shift to EDA Development(1) Peer-Leading Inventory Depth with Strategic Optionality Over 25 Years of Inventory at <$2.25/MMBtu NYMEX Breakeven PV-10(2) Balanced Marketing Portfolio With Premium Market Access ~1,500 MDth/d of total FT by FY30 (+ ~500 MDth/d vs. YE25) Peer-Leading Certified Gas Designations Seneca (MiQ and Equitable Origin) and Midstream (Equitable Origin) are certified at A Grades. Enhancing Capital Efficiency Expanding Inventory Depth Increasing Firm Transportation Improving Sustainability Metrics Upstream and Gathering FY26 Integrated Upstream & Gathering capital excludes discretionary land spending. Assumes an average of 25 wells brought online/year, which is equivalent to current pace. 16
Top-Tier Cost Structure and Long-Term Capital Efficiency Trends (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. FY26 excludes $38 million of discretionary land spending. (2) LOE, Gathering O&M, and G&A ranges shown represent FY 2027 guidance ranges. Capital Efficiency ($/Mcfe)(1) FY27E Integrated Operating Expense ($/Mcfe)(2) ~25% Reduction FY23 to FY26E 15% Continued Improvement Expected Upstream and Gathering FY 2026 17
FY26 Appraisals / FY27 Plan Strengthen Long-term Development FY 2026 | Appraisal Learnings Appraisal results reduced near-term production Upper Utica well results confirm low-breakevens, though Lower Utica provides superior economics Frac interactions in Lower Utica were more evident in more intensive completion designs (including Gen 4) FY 2027 | Transition and Optimization Complete in-progress Upper Utica infill and step-out tests Focus on Gen 3 design and optimization of development sequencing Further delineate core inventory and play extension FY 2028+ | Growth and Capital Efficiency Resume expected production growth with a Lower Utica first program Apply a more repeatable, optimized development approach Target long-term 15% improvement in capital efficiency Upstream and Gathering Seneca / IUG Acreage 18
Peer-Leading Inventory Depth at Low Breakeven Prices Assumes an average of 25 wells brought online per year. Enverus research is at $2.75 breakevens as of the most recent report published on September 24, 2026. Peers include AR, Ascent, CNX, EQT, EXE, GPOR, RRC. Eastern Development Area Predominantly Western Development Area IUG Analysis: >25 Years of Inventory @ <$2.25 Breakevens Enverus Analysis Validates Industry-Leading Inventory Depth Enverus Peers(2) PV10% Breakeven at Various NYMEX prices ($/MMBtu) Upstream and Gathering
Production Growth Supported by Expanding FT Portfolio Marketing Portfolio Has Premium Market Access(1) New FT Enhances Long-Term Marketing Portfolio: Supports future production growth with egress from Tioga County Minimizes spot exposure (together with in-basin firm sales) Increases optionality and connectivity to premium markets Data center developments (Western PA, Mid-Atlantic) Gulf Coast (LNG exports, industrial markets) 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 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 Northern Markets ~30% of total Southeast, Gulf Coast ~20% of total Northeast ~20% of total Premium PA Markets ~30% of total Percentages in chart indicate firm transportation capacity as of fiscal 2030. FT increases of 215 MDth/d in FY27 (Premium PA Markets and Gulf Coast), 275 MDth/d in FY28-30 (Premium PA Markets and Gulf Coast).
FY 2027 Sales Mix Provides Significant Price Certainty (1) Q1 Volumes: Fixed Price 24 Bcfe, NYMEX-Linked 68 Bcfe, Index 5 Bcfe. Q2 Volumes: Fixed Price 22 Bcfe, NYMEX-Linked 66 Bcfe, Index 6 Bcfe. Q3 Volumes: Fixed Price 21 Bcfe, NYMEX-Linked 66 Bcfe, Index 9 Bcfe. Q4 Volumes: Fixed Price 21 Bcfe, NYMEX-Linked 67 Bcfe, Index 9 Bcfe. All prices shown in $/MMBtu. NYMEX-linked and Index prices shown as differentials to NYMEX. Fiscal 2027 Highlights Upstream and Gathering Firm Sales & Production Cadence(1) $2.64 ($0.78) $2.57 ($0.80) $2.64 ($0.79) $2.64 ($0.78) Expected production of 400 to 435 Bcfe Minimal spot exposure of 15 to 45 Bcfe (~5-10% of remaining volumes) Firm sales contracts in place for ~90-95% of expected remaining production ~65% 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 Firm Sales & Production Cadence(1) $2.64 ($0.78) ($0.44) $2.57 ($0.80) ($0.46) $2.64 ($0.79) ($0.37) $2.64 ($0.78) ($0.46)
Disciplined Hedging Program 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) ~50% ~35% ~65%- 70% ~90%- 95% ~15% FY27 estimated hedge percentage assumes midpoint of production guidance for the year. Strip includes NYMEX settles for October and November 2026. ~95%- 100% (2) …Collars and Unhedged Production Provide Upside Capture Opportunities Upstream and Gathering 22
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 2026) 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-owned 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 2025 Significant reductions in methane driven by: Natural gas pneumatic device conversions Operational BMPs for well liquids unloading and flowback Increased fugitive emissions monitoring In 2025, Highland recycled more than 99% 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.
Regulated Companies Overview Business Highlights
NY Utility 3-Year rate case settlement (2025-2027) drives continued earnings growth PA Utility rate case completed based on PAPUC order on October 22, 2026 Ohio Utility rate case completed in January 2026, no-near term rate case filing expected Supply filed a rate case on 4/30/2026 with new rates effective 11/1/2026 subject to refund, settlement discussions remain ongoing Regulated Business Highlights Tioga Pathway and Shippingport Lateral projects placed into service November 1, 2026, adding ~$30 MM in incremental revenue annually Line N System Upgrade Project will add 294,000 Dth per day of incremental capacity, with ~$20 MM per year in annual revenues, expected in-service November 2028 Increased Utility business scale with the closing of Ohio acquisition Long-term expected rate base growth of approximately 5-7% drives earnings growth with no incremental expected equity needs over the next five years Pipeline Expansion Projects Drive Meaningful Growth Rate Case Activity Balances Modernization Spending & Affordability Continued Growth Expected from Ohio Utility Acquisition Longstanding modernization programs enable continued investment in the system to ensure the safety and reliability of service to customers Utility rate base growth from system modernization tracker including SMT in New York, DSIC in Pennsylvania, and CEP and DRR riders in Ohio Modernization Programs Drive Rate Base Growth Pipeline & Storage
Pipeline & Storage Overview Pipeline & Storage Firm transportation includes short-term and long-term and is disclosed annually as of September 30, 2026. Reported as of September 30, 2026. National Fuel Gas Supply Corporation Empire Pipeline Supply Corp. $5 million acquisition closed on October 30, 2026 ~6 Bcf firm storage capacity (fully subscribed) 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 Empire Pipeline, Inc. Contracted Capacity(1): Firm Storage: 71 Bcf (fully subscribed) Firm Transportation: ~3.8 Bcf / day Rate Base(2): ~$1.4 billion FERC Rate Proceeding Status: Filed rate case on 4/30/2026, settlement negotiations remain ongoing New rates went into effect on 11/1/2026, subject to refund Honeoye Storage
Pipeline & Storage Customer Mix Customer Transportation by Shipper Type Affiliated Customer Mix (Contracted Capacity) Note: As of 9/30/2026, adjusted to include Tioga Pathway and Shippingport Lateral projects placed into service November 1, 2026. 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. FY27E capex is presented at mid-point of guidance. Represents expansion-related capital for Tioga Pathway Project. ~$18 MM of modernization capital shown in Modernization / Maintenance Capital. 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, Line N System Upgrade Project target in-service date of November 2028 Tioga Pathway & Shippingport Lateral Project(2)
Line N System Upgrade Project Fully subscribed project will support growing in-basin production and the initial phase of the coal-to-gas conversion at Shippingport Industrial Park Replacement of ~7 miles of Line N Total Capex: ~$100 million (~$34 million in expansion capital) Estimated annual revenue: ~$20 million (underpinned by agreements of at least 15 years) 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 Further Expansion Potential Strategically positioned for growing PJM power demand, supported by data centers, fiber connectivity, existing transmission infrastructure, and low-cost gas supply Multiple expansion options enable Line N to scale with evolving customer needs Broader connectivity could expand market access, including potential Rover and TGP connections at Mercer Continued Expansion Opportunities Along Supply’s Line N System Pipeline & Storage Shippingport Power Station Total gas demand could reach ~800,000 Dth/d(1) Includes ~205,000 Dth/d supporting the behind-the-meter data center and up to 600,000 Dth/d supporting the full coal-to-gas conversion. Projects represent separate facilities and shippers.
Utility Operations in Constructive Regulatory Jurisdictions 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) Capital Cost Recovery Mechanisms: System Modernization Tracker (approved August 2026) Pennsylvania Last Rate Case: 2026 (rates effective November 2026) Total Customers(1): ~214,000 Allowed ROE: 9.86% (PaPUC R-2025-3059428) Capital Cost Recovery Mechanisms: Distribution System Improvement Charge (DSIC) Disclosed annually as of September 30, 2026. Utility Ohio Last Rate Case: 2024 (rates effective Jan. 12, 2026) Total Customers(1): ~335,000 Allowed ROE: 9.79% (PUCO Case 24-0832-GA-AIR) Capital Cost Recovery Mechanisms: Capital Expenditure Program (CEP) Distribution Recovery Rider (DRR)
Long History of Delivering Industry-Leading Affordability Based on 2025 average monthly residential bill data posted on company websites required by the NYPSC. Chart reflects NY Large Gas Utilities Monthly Bill Residential Heating (based on 100 Mcf annually). Based on analysis of 2025 PAPUC Annual Rate Comparison Report, which includes data for average monthly residential bills for January 2025. Chart reflects PA Large Gas Utilities Monthly Bill Residential Heating (based on 15 Mcf annually). Based on PUCO Utility Rate Survey Dashboard data pulled on 7/6/2026. Chart reflects OH Large Gas Utilities Monthly Bill Residential Heating (based on 15 Mcf annually). New York Pennsylvania #1 out of 9 Gas Utilities(1) #1 out of 6 Gas Utilities(2) Ohio #2 out of 4 Gas Utilities(3) Long History of Operating Efficiency and Focus on Strategic Infrastructure Modernization Have Led to Peer-Leading Utility Affordability Following the transaction close in October 2026, focus will be on enhancing future affordability Utility
SMT Rider Approved in August 2026 Enables cost recovery (return of/on) related to incremental LPP investments in FY28 and FY29 No customer bill increase required – SMT revenues to be funded through dollars currently in base rates for regulatory amortizations NY Utility Rate Case & Regulatory Overview Docket # Case 23-G-0627 ROE | Equity Layer 9.7% | 48% Authorized increase ($ millions) FY25 $57.3 FY26 $73.1 FY27 $85.8 Rate Base ($ millions) $1,044 $1,104 $1,163 Rate Mechanisms Revenue Decoupling Weather Normalization Low Income Customer Discount Rec. Uncollectible Expense Tracker 2024 General Rate Case Highlights New York Public Service Commission NYPSC regulates investor-owned utilities including natural gas, electric, steam, water and telecommunications and cable Consists of 7 commissioners that are selected by gubernatorial appointment, confirmed by senate to serve 5-year terms Commissioners are not formally identified by political party and there is no statutory partisan balance requirement Utility Three-Year, Multi-Year Rate Plan Settlement Approved in December 2024 Other Key Rate Mechanisms Provides recovery of capital investment between rate cases reducing regulatory lag Supports customer bill and affordability management Infrastructure Programs Modernization (pipeline replacement) program: maintained at a minimum of 105 miles per year over rate plan Recovery of system modernization costs, including higher rate base and depreciation expense, now included in new base rates
DSIC Rider Existing DSIC revenues and eligible rate base rolled into new base rates Able to accrue additional DSIC revenues on incremental rate base investments after 10/31/2027 Pennsylvania Utility Rate Case Overview Docket # R-2025-3059428 ROE | Equity Layer 9.86% | 55% Authorized increase ($ millions) $10.4 New Rates Become Effective November 2026 Key General Rate Case Highlights Pennsylvania Public Utility Commission PaPUC regulates investor-owned utilities including natural gas, electric, water and telephone Governed by a five-member commission whose members are appointed by the governor and confirmed by the state Senate Utility On October 22, 2026, the PaPUC issued Final Opinion and Order on NFG’s January ‘26 GRC(1) Key Rate Mechanisms Approved in General Rate Case Weather Normalization Adjustment (WNA) pilot to continue Deadband increased from 3% to 5% WNA Provides recovery of capital investment between rate cases reducing regulatory lag Supports customer bill and affordability management Residential Energy Efficiency (EE) pilot approved $700k per year to be recovered in separate rider EE General rate case.
Ohio Utility Rate Case Overview Docket # 24-0832-GA-AIR ROE | Equity Layer 9.79% | 52.9% Authorized increase ($ millions) $51.3 Depreciable Life 25 Years Key General Rate Case Highlights Ohio Public Utility Commission PUCO regulates investor-owned utilities including natural gas, electric, water and telephone Consists of 5 commissioners that are selected by gubernatorial appointment, confirmed by the state senate and serve 5-year terms Recent legislation – SB103 allows for ratemaking to be based on forward test years with annual true up reconciliation to authorized ROE Ohio utility must statutorily file its next GRC(1) by December 31, 2029 Utility On January 7, 2026, the PUCO approved a modified stipulation to increase base rates for Ohio utility customers Key Rate Mechanisms Approved in General Rate Case Recovers eligible capital investment outside the DRR Identical recovery and timing parameters as DRR CEP Rider DRR Rider Recovers investment associated with accelerated replacement of aging distribution infrastructure Includes return on net plant, depreciation and eligible deferred costs Annual filing by March 1 for prior year investment, with rates effective September 1 Provide annual recovery of infrastructure investment between rate cases reducing regulatory lag Riders authorized through 2029 investment year, subject to established rate caps General rate case. 34
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. Represents midpoint of 2027E Guidance. Long-Standing Focus on Distribution System Safety and Reliability Utility (2) $350 - $400 Ohio acquisition more than doubles Utility investment opportunity (3)
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 OH ~5,700 miles
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. Targets and reductions represented are pre-Ohio gas utility acquisition. New York Climate Leadership and Community Protection Act, enacted in 2019. Targets and reductions represented are pre-Ohio gas utility acquisition. 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 vosslerr@natfuel.com
Initial FY 2027 Adjusted EPS Guidance & Assumptions Excludes items impacting comparability. See Comparable GAAP Financial Measure Slides & Reconciliations at the end of this presentation. Guidance assumes NYMEX pricing of $2.85/MMBtu and in-basin spot pricing of $2.15/MMBtu for Fiscal 2027, and reflects the impact of existing financial hedges, firm sales and firm transportation contracts. 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. FY 2026 actuals exclude ~$38 MM of discretionary land spending at Integrated Upstream and Gathering. Integrated Upstream & Gathering guidance excludes $50 - $100 MM of discretionary land spending. Consolidated Effective Tax Rate 24.7% ~24.0% Integrated Upstream & Gathering FY2026 Actual FY2027 Guidance NYMEX natural gas price (per MMBtu) $3.61 $2.85 Spot Price (per MMBtu) $2.80 $2.15 Production (Bcf) 419 400 - 435 Integrated Operating Costs ($/Mcf) Upstream G&A $0.18 $0.19 - $0.20 LOE $0.16 $0.16 - $0.17 Gathering O&M $0.13 $0.13 - $0.14 DD&A $0.79 $0.84 - $0.86 Pipeline & Storage FY2026 - Actual FY2027 Guidance Revenues ($MM) $432 $475 - $500 O&M Expense $126 3 – 4% increase Utility ($MM) FY2026 - Actual FY2027 Guidance Operating Income $123 $235 - $255 Non-Service Pension / OPEB Income $25 $23 - $27 Capital Expenditures ($MM) FY2026 Actual(3) FY2027 Guidance Integrated Upstream & Gathering $591(4) $600 – $640(5) Pipeline & Storage $272 $140 – $180 Utility $179 $350 – $400 Total Company $1,079 $1,090 – $1,220 (1) Assuming $2.85 NYMEX, FY27 Adjusted EPS(2) of $6.00 - $6.40 ($6.20 at midpoint) NYMEX Assumption Adj. EPS Sensitivities (per share) $2.50 $5.60 - $6.00 $3.00 $6.20 - $6.60 $3.50 $6.85 - $7.25 39
Type Curves Eastern Development Area (EDA) WDA Tioga Lycoming Estimated Lower Utica Upper Utica Marcellus Marcellus Upper Utica Location Count 150 210 60 10 240 Avg. TLL (ft) 13,000 13,000 10,000 8,000 13,000 D&C ($000s/ft) $1,250 to $1,300 $1,200 to $1,250 $900 to $1,000 $1,075 to $1,125 $1,000 to $1,050 Avg. Royalty 15% 15% 15% 16% 2% EUR (Bcfe/ft) 2.5 2.0 2.0 2.8 1.7 Estimated wells Fiscal 2027 Drills 30-35 (incl. 6-10 non-op) TILs 20-26 Drilling rigs 1.5 (operated)
Regulated Businesses: Rate Case Overview Supply Empire NY(2) PA(2) OH(2) Regulatory Agency (Governed by) FERC FERC NYPSC PAPUC PUCO Timing / Status Filed rate case on April 30, 2026 New rates went into effect on 11/1, subject to refund Settlement discussions remain ongoing 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 PAPUC order approved on October 22, 2026 Increase of $10.4 million in base rates New rates to be in effect November 2026 Modified Stipulation approved on January 6, 2026 with a $51 million increase in base rates and reset of CEP and DRR rider rate caps New rates went into effect January 12, 2026 Rate Base(1) (in billions) $1.4 $0.3 $1.1 $0.5 $1.6 Equity Ratio Not stated – Black box settlement Not stated – Black box settlement Authorized 48% Authorized 55% Authorized 52.9% Authorized ROE Not Stated – Black box settlement Not Stated – Black box settlement Authorized 9.7% Authorized 9.86% Authorized 9.79% Pipeline & Storage Utility Estimated as of September 30, 2026. See Case 23-G-0627 on file with the NY PSC, Case R-2025-3059428 with the PAPUC, and Case 24-0832-GA-AIR with the PUCO.
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) 1Q 27 2Q 27 3Q 27 4Q 27 FY 27 FY 28 FY 29 FY 30 Hedged Volumes 84,350 72,281 62,468 62,699 281,798 150,409 44,180 7,873 Swaps Volume 35,530 29,640 30,840 30,840 126,850 67,330 9,150 -- Wtd. Avg. Price $4.02 $3.94 $3.89 $3.89 $3.94 $3.78 $3.63 -- Collars Volume 23,800 19,620 9,750 9,750 62,920 26,920 4,620 -- Wtd. Avg. Ceiling $4.70 $4.79 $4.19 $4.19 $4.57 $4.44 $4.00 -- Wtd. Avg. Floor $3.65 $3.71 $3.33 $3.33 $3.57 $3.53 $3.31 -- Fixed Price Physical Volume 25,020 23,021 21,878 22,109 92,028 56,159 30,410 7,873 Wtd. Avg. Price $2.57 $2.64 $2.64 $2.64 $2.62 $2.80 $2.83 $2.89 NYMEX Equiv. Price(1) $3.52 $3.75 $3.28 $3.44 $3.50 $3.76 $3.71 $3.65 Capped Firm Sales Volume 1,500 1,468 1,488 1,507 5,963 508 -- -- NYMEX Cap $4.95 $4.95 $4.95 $4.95 $4.95 $4.95 $4.95 $4.95 Volume 1,234 1,873 1,893 1,909 6,908 7,473 7,415 7,598 NYMEX Cap $5.00 $5.00 $5.00 $5.00 $5.00 $5.00 $5.00 $5.00 Volume 3,701 3,746 3,785 3,818 15,050 14,946 14,831 15,196 NYMEX Cap $5.65 $5.65 $5.65 $5.65 $5.65 $5.65 $5.65 $5.65 Volume 1,831 1,791 1,816 1,839 7,276 7,328 7,391 7,443 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 48
Reconciliation – Free Cash Flow
Safe Harbor For Forward Looking Statements Certain statements contained herein, including statements identified by the use of the words “anticipates,” “believes,” “could,” “estimates,” “expects,” “forecasts,” “guidance,” “intends,” “may,” “might,” “outlook,” “plans,” “potential,” “predicts,” “projects,” “seeks,” “targets,” “will,” “would”, and variations of such words and similar future or conditional expressions, and statements which are other than statements of historical facts, are intended to identify “forward-looking statements” as defined under U.S. federal securities laws, including, but not limited to, statements, estimates, and projections relating to the potential separation of the Company into two companies (the “Separation”), including the timing and structure of the Separation, the characteristics of the separated businesses, and the expected benefits of the Separation, future operating and financial performance and long-term strategy, and the assumptions underlying such expected benefits, targets, strategies, and statements. These forward-looking statements are based on management’s beliefs, expectations, estimates, and projections at the time they are made and are not guarantees of future performance. 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 contained herein are expressed in good faith and are believed to have a reasonable basis, but there can be no assurance that such expectations, beliefs, or projections will result or be achieved or accomplished. There can be no guarantees with respect to whether the Separation will be completed. In addition to other factors, the following are among the important factors that could cause actual results to differ materially from those discussed in the forward-looking statements: the ability to effect the Separation and to meet the conditions related thereto; the ability to obtain any consents or approvals required to complete the Separation; the ability of the separated companies to each succeed as standalone publicly traded companies; negative effects of the announcement or pendency of the Separation on the market price of the Company’s securities and/or on the Company’s financial performance; the possibility that the Separation will not achieve its intended benefits; the possibility of disruption, including disputes, litigation, or unanticipated costs in connection with the Separation; the impact of the Separation on the Company’s businesses and the risk that the Separation may be more difficult, time-consuming, or costly than expected, including the impact on the Company’s resources, systems, procedures, and controls, diversion of management’s attention, and the impact and possible disruption of existing relationships with regulators, customers, suppliers, employees, and other business counterparties; the ability to achieve anticipated capital structures in connection with the Separation; the ability to achieve anticipated credit ratings in connection with the Separation; the ability to achieve anticipated tax treatments in connection with the Separation and future, if any, divestitures, mergers, acquisitions, and other portfolio changes, and the impact of changes in relevant tax and other laws and regulations; the Company's ability to complete strategic transactions, such as the plan to separate the Company into two independent, publicly traded companies through a tax-free spin-off of the Company’s Integrated Upstream and Gathering business, including receipt of required regulatory clearances and satisfaction of other conditions to closing, and to recognize the anticipated benefits of such transactions; 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; 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, 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; increasing costs of insurance, changes in coverage, and the ability to obtain insurance; other factors described in the risk factors set forth in the Company’s filings with the U.S. Securities and Exchange Commission, including the Company’s most recently filed Annual Report on Form 10-K and subsequent Current Reports on Form 8-K and Quarterly Reports on Form 10-Q. Forward-looking statements speak only as of the date on which they are made, and the Company undertakes no obligation, and disclaims any duty to update, revise, or withdraw any forward-looking statement, whether as a result of new information, future events, or otherwise, except as required by applicable law or regulation.