Investor Presentation Q3 Fiscal 2017 Update August 3, 2017 Exhibit 99

Safe Harbor For Forward Looking Statements This presentation may contain “forward-looking statements” as defined by the Private Securities Litigation Reform Act of 1995, including statements regarding future prospects, plans, objectives, goals, projections, estimates of oil and gas quantities, strategies, future events or performance and underlying assumptions, capital structure, anticipated capital expenditures, completion of construction projects, projections for pension and other post-retirement benefit obligations, impacts of the adoption of new accounting rules, and possible outcomes of litigation or regulatory proceedings, as well as statements that are identified by the use of the words “anticipates,” “estimates,” “expects,” “forecasts,” “intends,” “plans,” “predicts,” “projects,” “believes,” “seeks,” “will,” “may,” and similar expressions. Forward-looking statements involve risks and uncertainties which could cause actual results or outcomes to differ materially from those expressed in the forward-looking statements. The Company’s expectations, beliefs and projections are expressed in good faith and are believed by the Company to have a reasonable basis, but there can be no assurance that management’s expectations, beliefs or projections will result or be achieved or accomplished. In addition to other factors, the following are important factors that, in the view of the Company, could cause actual results to differ materially from those discussed in the forward-looking statements: Delays or changes in costs or plans with respect to Company projects or related projects of other companies, including difficulties or delays in obtaining necessary governmental approvals, permits or orders or in obtaining the cooperation of interconnecting facility operators; governmental/regulatory actions, initiatives and proceedings, including those involving rate cases (which address, among other things, target rates of return, rate design and retained natural gas), environmental/safety requirements, affiliate relationships, industry structure, and franchise renewal; changes in 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; impairments under the SEC’s full cost ceiling test for natural gas and oil reserves; changes in the price of natural gas or oil; financial and economic conditions, including the availability of credit, and occurrences affecting the Company’s ability to obtain financing on acceptable terms for working capital, capital expenditures and other investments, including any downgrades in the Company’s credit ratings and changes in interest rates and other capital market conditions; factors affecting the Company’s ability to successfully identify, drill for and produce economically viable natural gas and oil reserves, including among others geology, lease availability, title disputes, weather conditions, shortages, delays or unavailability of equipment and services required in drilling operations, insufficient gathering, processing and transportation capacity, the need to obtain governmental approvals and permits, and compliance with environmental laws and regulations; increasing health care costs and the resulting effect on health insurance premiums and on the obligation to provide other post-retirement benefits; changes in price differentials between similar quantities of natural gas or oil 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; other changes in price differentials between similar quantities of natural gas or oil having different quality, heating value, hydrocarbon mix or delivery date; the cost and effects of legal and administrative claims against the Company or activist shareholder campaigns to effect changes at the Company; uncertainty of oil and gas reserve estimates; Significant differences between the Company’s projected and actual production levels for natural gas or oil; changes in demographic patterns and weather conditions; changes in the availability, price or accounting treatment of derivative financial instruments; changes in laws, actuarial assumptions, the interest rate environment and the return on plan/trust assets related to the Company’s pension and other post-retirement benefits, which can affect future funding obligations and costs and plan liabilities; changes in economic conditions, including global, national or regional recessions, and their effect on the demand for, and customers’ ability to pay for, the Company’s products and services; the creditworthiness or performance of the Company’s key suppliers, customers and counterparties; economic disruptions or uninsured losses resulting from major accidents, fires, severe weather, natural disasters, terrorist activities, acts of war, cyber attacks or pest infestation; significant differences between the Company’s projected and actual capital expenditures and operating expenses; or increasing costs of insurance, changes in coverage and the ability to obtain insurance. Forward-looking statements include estimates of oil and gas quantities. Proved oil and gas reserves are those quantities of oil and gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible under existing economic conditions, operating methods and government regulations. Other estimates of oil and gas quantities, including estimates of probable reserves, possible reserves, and resource potential, are by their nature more speculative than estimates of proved reserves. Accordingly, estimates other than proved reserves are subject to substantially greater risk of being actually realized. Investors are urged to consider closely the disclosure in our Form 10-K available at www.nationalfuelgas.com. You can also obtain this form on the SEC’s website at www.sec.gov. For a discussion of the risks set forth above and other factors that could cause actual results to differ materially from results referred to in the forward-looking statements, see “Risk Factors” in the Company’s Form 10-K for the fiscal year ended September 30, 2016 and the Forms 10-Q for the quarter ended December 31, 2016, March 31, 2017 and June 30, 2017. 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.

NFG: A Diversified, Integrated Natural Gas Company Providing significant base of stable, regulated earnings & cash flows 740,000 Utility customer accounts in NY & PA For the trailing twelve months ended June 30, 2017. 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. Upstream E&P Midstream Gathering Pipeline & Storage Downstream Utility Energy Marketing Developing our large, high quality acreage position in Marcellus & Utica shales with a focus on returns 785,000 Net acres in Appalachia Expanding and modernizing pipeline infrastructure to provide access to Appalachian supplies $282 million1 Annual Adjusted EBITDA

Adjusted EBITDA by Segment ($ millions)(1) Balanced Earnings and Cash Flows 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.

Disciplined, Flexible Capital Allocation (2) A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation. FY 2016 actual capital expenditures reflects the netting of $157 million of up-front proceeds received from joint development partner for working interest in joint development wells. FY 2017 and FY 2018 guidance also reflects the netting of anticipated proceeds received from the joint development partner. Capital Expenditures by Segment ($ millions)(1) E&P Total NFG Gross CapEx $256 $523 JDA Proceeds ($157) ($157) Net CapEx $99 $366 CapEx Reconciliation for JDA Proceeds ($millions)

Near-term Growth Strategy Exploration & Production Strategy Midstream Strategy Corporate Strategy Grow Marcellus and Utica production at a 10%+ CAGR over next 3 years WDA Development (1-rig program) Return to developing 100% NRI Seneca wells post-JDA in FY18 Optimize Utica D&C designs and transition to a Utica development program by FY19 EDA Development (1-rig program) Develop highly economic acreage in Lycoming County and prepare well inventory for Atlantic Sunrise capacity Commence Utica development in FY18 at Tract 007 (Tioga County) to add another 100 to 150 MMcf/d by FY20 Near-term improvement in balance sheet/credit metrics Maintain commitment to growing the dividend Continue to leverage operational, financial and strategic benefits of the integrated model Gathering: System throughput and revenues will benefit from Seneca’s production growth Minimal incremental investment required to accommodate Seneca’s WDA Utica development Pipeline & Storage: Opportunities for system expansion and modernization Foundation shipper agreements in place for Empire North Project and new Line N expansion Need for system modernization will result in Pipeline & Storage rate base growth National Fuel Will Continue to Grow Integrated Businesses While We Sort Through Northern Access Delay 6

Strong Balance Sheet & Liquidity Total Debt 55% $3.7 Billion Total Capitalization as of June 30, 2017 Debt/Adjusted EBITDA Capitalization Debt Maturity Profile ($MM) Liquidity Committed Credit Facilities Short-term Debt Outstanding Available Short-term Credit Facilities Cash Balance at 06/30/17 Total Liquidity at 06/30/17 $ 1,250 MM $ 0 MM $ 1,250 MM $ 285 MM $ 1,535 MM Note: A reconciliation of Adjusted EBITDA to Net Income is included at the end of this presentation.

Committed to the Dividend Annual Dividend Rate ($ /share) Consecutive Payments 115 Years Consecutive Increases 47 Years Current Dividend Rate $1.66 per Share Current Dividend Yield (1) 2.8% As of August 3, 2017. NFG’s Dividend Consistency

Upstream Overview Exploration & Production

Growing Production within Disciplined Capital Program E&P Net Production (Bcfe) E&P Net Capital Expenditures(1) ($ millions) 2-rig development program Target 10%+ production 3-year CAGR Resume development on prolific Marcellus acreage in Lycoming County, Pa. Return to developing 100% NRI wells in the WDA (last JDA pad expected on-line in 1H FY18) Transition to Utica development in WDA and EDA in FY18/19 Layer-in firm sales to reduce spot market risk and take advantage of attractive regional pricing Seneca’s Near-term Operational Plan Appalachia Natural Gas California Oil Flat to modest growth on minimal capital investment Development focus on new farm-in acreage in Midway Sunset Low capital and operational costs generate FCF at $50/bbl FY 2016 actual capital expenditures reflects the netting of $157 million of up-front proceeds received from joint development partner for working interest in joint development wells. FY 2017 and FY 2018 guidance also reflects the netting of anticipated proceeds received from the joint development partner. Upstream 10

Proved Reserves (1) 117% Reserve Replacement Rate (adjusted for revisions and sales) 65% Proved Developed 35% Proved Undeveloped Includes approximately 69 Bcf of natural gas proved reserves in Appalachia that will be transferred in fiscal 2017 as interests in the joint development wells are conveyed to the partner. Reflects 246 Bcfe of natural gas reserves that were conveyed and sold to joint development partner and 16 Bcfe of Upper Devonian sales. FY 2016 net negative revisions include 227 Bcfe of proved reserves that were revised due to lower oil and gas pricing. Total Proved Reserves (Bcfe) Upstream Proved Reserves - FYE '15 2,344 FY '16 Production (161) Mineral Sales (2) (262) Net Negative Revisions (3) (262) Extensions & Discoveries 190 Proved Reserves - FYE '16 1,849 Fiscal 2016 Proved Reserves Reconciliation (Bcfe) Fiscal 2016 Proved Reserves Stats 11

Significant Appalachian Acreage Position Current gross production: ~255 MMcf/d Mostly leased (16-18% royalty) with no significant near-term lease expirations > 100 remaining Marcellus and Utica locations economic under $1.80/Mcf Additional Utica & Geneseo potential Near-term development tailored to fill capacity on Atlantic Sunrise in mid-2018 Eastern Development Area (EDA) EDA - 70,000 Acres Western Development Area (WDA) WDA - 715,000 Acres Current gross production: ~340 MMcf/d Large inventory of high quality Marcellus and Utica acreage economic under $2.00/Mcf Fee ownership – lack of royalty enhances economics Highly contiguous nature drives cost and operational efficiencies Fee Acreage Lease Acreage Upstream

Western Development Area WDA Marcellus Tier 1 Acreage – 200,000 Acres Significant multi-zone drilling inventory economic under $2.00 /Mcf Marcellus Shale : 1,000+ well locations Utica Shale: 125 to 500+ well locations (2) Fee acreage / stacked pay provides flexibility & enhances economics No royalty or lease expirations on most acreage Expected Utica development will re-use existing upstream and midstream infrastructure to maximize ROI Highly contiguous position drives best in class well costs Multi-well pad drilling with laterals approaching 8,000 ft. Water management operations lowering water costs to under $1 /Bbl Long-term firm sales and firm transport contracts support growth Recently added fixed price deals through FY24 at $2.30 to $2.40 /MMBtu Marcellus EURs only. The Utica Shale lies approx. 5,000 feet beneath Seneca’s WDA Marcellus acreage. Appraisal program currently in progress to determine extent of economic Utica inventory on acreage. Clermont/ Rich Valley Hemlock Ridgway 2 - 4 BCF/well 7- 9.5 BCF/well 4 - 6 BCF/well EUR Color Key(1) Upstream Niagara Expansion Project (TGP and NFG) FT Capacity: 158,000 Dth/d @ $0.67/Dth Firm Sales: NYMEX & DAWN WDA - TGP 300 Firm Sales 13

WDA Marcellus: Clermont/Rich Valley Development Gross daily production: ~315 MMcf/d 1-rig / daylight only frac crew Developing 75 Marcellus wells with joint development partner (IOG) 75 wells drilled 63 wells online/producing Just-in-time gathering infrastructure build-out provides significant capital flexibility to adjust scheduling and pace of Seneca’s development program Regional focus of development minimizes capital outlay and improves returns CRV Development Summary Upstream 14

WDA Utica: Early Results and Economic Impact 15/16 WDA Marcellus WDA Utica WDA Utica vs Marcellus Utica Early Test Results: Drawdown management is important Restricted drawdown improves well EURs Higher pressure significantly enhances well productivity (Utica ~5,000’ deeper than Marcellus) Completion design Successful results without high strength proppant indicate completion costs will be on par with the Marcellus Utica Economic Impact: Utica generates lower F&D costs and higher returns than WDA Marcellus 60-80% higher EUR for ~35% higher capital cost Leverage existing upstream and midstream infrastructure Over 125 well locations with established midstream and upstream infrastructure Enhances IRRs on consolidated upstream / midstream investment Upstream

WDA Utica: Transition to Development WDA Marcellus (Depth ~7,000 feet) Existing Line Leased Seneca Fee Producing FY18 Producer Development WDA Utica (Depth ~12,000 feet) Seneca and NFG Midstream can leverage existing upstream and midstream infrastructure to drive capital, operational, and marketing efficiencies NEXT STEPS: FY 2018: Optimize D&C design Continue Marcellus development Test 5 more Utica wells off Marcellus pads Optimize stage spacing, landing zone targets, and well spacing FY 2019+: Transition to Utica development 125+ Utica well locations in WDA-CRV with ability to reuse existing pad, water and gathering infrastructure Expect Utica WDA development costs to be $5.0 to $6.0 million per well Upstream 16

Eastern Development Area EDA Acreage – 70,000 Acres EDA Highlights 3 1 2 1 2 Upstream DCNR Tract 007 (Tioga Co., Pa) 1 Utica and 1 Marcellus producing well Utica 30-day IP = 15.8 MMcf/d Utica development expected to begin in fiscal 2018 59 remaining Utica locations economic under $1.95 /Mcf Covington & DCNR Tract 595 (Tioga Co., Pa.) Gross daily production: ~85 MMcf/d Marcellus locations fully developed Opportunity for future Utica appraisal DCNR Tract 100 & Gamble (Lycoming Co., Pa.) Gross daily production: ~160 MMcf/d 63 remaining Marcellus locations economic < $1.65 /Mcf Atlantic Sunrise capacity (190 MDth/d) in mid-2018 Geneseo shale to provide 100-120 additional locations 3

EDA Marcellus: Lycoming County Development Upstream Prolific Marcellus acreage with peer leading well results 60 Marcellus wells producing w/ average IP rate of 17.0 MMcf/d 63 remaining Marcellus locations economic under $1.65 /Mcf Near-term development focused on filling Atlantic Sunrise capacity forecasted to be available in July 2018 Transco Firm Sales Marcellus Development in Lycoming County has Resumed in Anticipation of Atlantic Sunrise 18

EDA Utica: Tioga County Development Upstream Utica Development in Tioga County – Tract 007 Expected to Begin in FY18 Northeast Supply Diversification Project FT Capacity: 50,000 Dth/d @ $0.50/Dth Firm Sales: NYMEX and DAWN EDA - TGP 300 Firm Sales SRC EDA – Tract 007 Utica Test Well Gathering Line In-Service November 2016 Lateral Length 4,640 ft 30 Day IP /1,000 ft 3.4 MMcf/d Est. EUR /1,000 ft 2.4 Bcf Inventory: 59 locations economic under $1.95 /Mcf Targeting to grow production by 100 to 150 MDth/d by FY20 Expected Development Costs: $5.5 to $6.5 million per well Gathering Infrastructure: NFG Midstream Wellsboro Modest build-out required to connect to TGP 300 Sales/Takeaway Strategy: TGP 300 (Marcellus Zone 4) Recently executed firm sales at fixed prices $2.00 to $2.15 per Dth extending from 2019 to 2024

Marcellus: Drilling & Completions Efficiencies Normalized to adjust for daylight only frac operations that began in 2016. Marcellus Drilling Marcellus Completions Upstream Down 42% since 2014 Operational Efficiencies and Investment in Water Infrastructure Have Resulted in Peer Leading Well Costs Down 40% since 2014

Appalachia Drilling Program Economics Net realized price reflects either (a) price received at the gathering system inteconnect or (b) price received at delivery market net of firm transportation charges. Internal Rate of Return (IRR) is pre-tax and includes estimated well costs under current cost structure, LOE, and Gathering tariffs anticipated for each prospect. ~1,300 Locations Economic Below $2.00/MMBtu(1) Upstream Prospect Reservoir Locations Remainingto Be Drilled Completed Lateral Length (ft) Average EUR (Bcf) Internal Rate of Return % (2) Realized Price(1) Required for 15% IRR Anticipated DeliveryMarkets $2.50Realized $2.25Realized $2.00Realized EDA DCNR 100Lycoming Marcellus 11 5600 13.5-14.5 0.88 0.67 0.48 $1.52 Transco Leidy &Atlantic Sunrise Southeast US(NYMEX+) GambleLycoming Marcellus 52 4700 10.5-11.5 0.66 0.5 0.36 $1.64 DCNR 007Tioga Utica 59 7000 12.5-13.5 0.42 0.28000000000000003 0.17 $1.94 TGP 300 WDA CRV Utica 125 - 500+ 7500 13-14 0.4 0.3 0.22 $1.77 TGP 300 &Niagara Expansion Canada (Dawn) CRV Marcellus 14 8000 8.5-9.5 0.35 0.26 0.19 $1.86 Hemlock/ Ridgway Marcellus 631 8800 8-9 0.32 0.25 0.17 $1.92 Remaining Tier 1 Marcellus 406 8500 7-8 0.33 0.25 0.17 $1.95 Major Changes FY15Q4: 1. WDA - CRV --> TLL increased to 8,800, remaining locations reduced to 79 2. WDA - Hemlock --> TLL increased to 8,800 3. WDA - Ridgway --> TLL increasd to 8,800, merged with Hemlock (using Hemlock CAPEX, BTU, etc) 4. WDA - CRV/Hemlock/Ridgway --> updated LOE, shrink, and BTU 5. WDA- Tier 1 Locations --> TLL increased to 8,500 ft. (G&G guidance) FY15Q3: 1. EDA- DCNR 100 --> Updated Type Curve (Higher IP) and Lower Capital Structure (190 ft. Stages) 2. EDA- Gamble --> Updated Type Curve (based on DCNR 100) and Lower Capital Structure (190 ft. Stages) 3. WDA- CRV --> Updated Type Curve and Lower Capital Structure (Optimization Mode $5.4 MM/Well) 4. WDA- Hemlock/Ridgway/Tier 1/Future Resources --> Updated Capital Structure (Optimization Mode $5.4 MM/Well)

Long-term Contracts Supporting Appalachian Production Atlantic Sunrise (Transco) Delivery Markets: Mid-Atlantic & Southeast U.S. 189,405 Dth/d In-Basin Firm Sales Contracts(1) Niagara Expansion (TGP & NFG) Delivery Markets: Canada-Dawn & TETCO 158,000 Dth/d Northeast Supply Diversification 50,000 Dth/d Represents base firm sales contracts not tied to firm transportation capacity. Base firm sales are either fixed priced or priced at an index (e.g., NYMEX ) +/- a fixed basis and do not carry any transportation costs. Firm Transportation Long-term firm sales contracts in place at physical delivery points realizing NYMEX / Dawn less transport cost Upstream Regional Firm Sales Converting 95 Mdth/d of Northern Access sales from Dawn back to basin Recent deals providing attractive realizations Further regional basis improvement expected as pipeline projects are placed in-service 10% Production CAGR FYTD 2017 Avg. Spot Production FY 2018 FY 2019 FY 2020 Seneca will continue to layer-in firm sales contracts with attractive realizations at regional pricing points to lock-in drilling economics and minimize spot exposure as it waits for Northern Access FY 2017 Fixed Price Firm Sales Contracts Added Since NA16 Delay

Firm Transportation Commitments Volume (Dth/d) Production Source Delivery Market Demand Charges ($/Dth) Gas Marketing Strategy Northeast Supply Diversification Project Tennessee Gas Pipeline Atlantic Sunrise WMB - Transco In-service: Mid-2018 Niagara Expansion TGP & NFG Northern Access NFG – Supply & Empire Delayed 50,000 189,405 158,000 350,000 EDA -Tioga County Covington & Tract 595 EDA - Lycoming County Tract 100 & Gamble WDA – Clermont/ Rich Valley WDA – Clermont/ Rich Valley 12,000 140,000 Canada (Dawn) Mid-Atlantic/ Southeast Canada (Dawn) TETCO (SE Pa.) Canada (Dawn) TGP 200 (NY) $0.50 (3rd party) $0.73 (3rd party) NFG pipelines = $0.24 3rd party = $0.43 NFG pipelines = $0.12 NFG pipelines = $0.38 NFG pipelines = $0.50 3rd party = $0.21 Firm Sales Contracts 50,000 Dth/d Dawn/NYMEX+ 10 years Currently In-Service Future Capacity Firm Sales Contracts 158,000 Dth/d Dawn/NYMEX+ 8 to 15 years Firm Sales Contracts 189,405 Dth/d NYMEX+ First 5 years Firm Sales Contracts At Dawn When Project Goes In-Service Upstream

Firm Sales Provide Market for Appalachian Production Net Contracted Firm Sales Volumes (Dth per day) Contracted Index Price Differentials ($ per Dth)(1) Values shown represent the price or differential to a reference price (netback price) at the point of sale less any associated transportation costs.. Upstream $2.51 $2.39 $2.40 $2.40 $2.40 Less: $0.69 Less: $0.74 Less: $0.77 Less: $0.65 Less: $0.64 480,100 Dth/d gross 487,300 Dth/d gross 500,000 Dth/d gross 459,300 Dth/d gross 592,500 Dth/d gross

California Oil Stable Oil Production | Minimal Capital Investment | Steady Free Cash Flow 1 2 3 4 5 6 Location Formation Production Method FY16 Gross Daily Production (Boe/d) 1 East Coalinga Temblor Primary 770 2 North Lost Hills Tulare & Etchegoin Primary/ Steam flood 1,000 3 South Lost Hills Monterey Shale Primary 1,680 4 North Midway Sunset Tulare & Potter Steam flood 3,640 5 South Midway Sunset Antelope Steam flood 1,760 6 Sespe Sespe Primary 1,350 Upstream

California Average Daily Net Production Less than $40 Million Annual Capital Spending Needed to Keep CA Production Flat Upstream California Average Net Daily Production (BOE/D) California Annual Capital Expenditures ($MM) Guidance Guidance

Future Development Focused on Midway Sunset Modest near-term capital program focused on locations that earn attractive returns in current oil price environment A&D will focus on low cost, bolt-on opportunities Sec. 17 and Pioneer farm-ins to provide future growth F&D (est.) = $6.50/Boe Midway-Sunset Midway-Sunset Pioneer South MWSS Acreage North MWSS Acreage Sec. 17N North South South North Midway Sunset Economics MWSS Project IRRs at $50/Bbl(1) Reflects pre-tax IRRs at a $50/Bbl WTI. Upstream

Seneca Production Upstream Net Production (Bcfe)

Strong Hedge Book in FY 2018 Natural Gas Swap & Fixed Physical Sales Contracts (Millions MMBtu) Fixed price physical sales exclude joint development partner’s share of fixed price contract WDA volumes as specified under the joint development agreement. Upstream Crude Oil Swap Contracts (Thousands Bbls) (1)

Fiscal 2017 Production and Price Certainty Average realized price reflects uplift from financial hedges less fixed differentials under firm sales contracts and any firm transportation costs. Indicates firm sales contracts with fixed index differentials but not backed by a matching NYMEX financial hedge. 28 Bcf realizing net ~$3.04/Mcf (1) 4.2 Bcf of additional basis protection Upstream 55% of remaining oil production hedged at $60.21 /Bbl Remaining spot production assumed to be sold at $2.00/Mcf Price Certainty on Q4 Production

Fiscal 2018 Production and Price Certainty FINANCIAL HEDGE + FIRM SALE = PRICE CERTAINTY Average realized price reflects uplift from financial hedges less fixed differentials under firm sales contracts and any firm transportation costs. Indicates firm sales contracts with fixed index differentials but not backed by a matching NYMEX financial hedge. 90 Bcf locked-in realizing net ~$2.61/Mcf (1) 46.5 Bcf of additional basis protection Upstream 43% of oil production hedged at $55.46 /Bbl Spot production assumed to be sold at ~$2.40/Mcf 136.5 Bcf Protected by Firm Sales Next Year

Seneca Operating Costs Competitive, low cost structure in Appalachia and California supports strong cash margins Gathering fee generates significant revenue stream for affiliated gathering company DD&A decrease due to improving Marcellus F&D costs and reduction in net plant resulting from ceiling test impairments DD&A $/Mcfe Appalachia LOE & Gathering $/Mcfe California LOE $/Boe Seneca Resources Consolidated $/Mcfe (1) (2) (2) (1) Excludes $7.9 million , or $0.05 per Mcfe, of professional fees relating to the joint development agreement announced in December 2015. The total of the two LOE components represents the midpoint of the LOE guidance range of ~$0.95 for fiscal 2017 and $0.90 to $1.00 for fiscal 2018. Upstream (2) (2)

Midstream Businesses

Midstream Businesses Midstream Midstream Midstream Businesses Adjusted EBITDA ($MM) Note: 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. Midstream Businesses System Map NFG Supply Corp. FERC-Regulated Pipeline & Storage Empire Pipeline, Inc. FERC-Regulated Pipeline & Storage NFG Midstream Corp Marcellus & Utica Gathering & Compression

Integrated Development – WDA Gathering System Current System In-Service ~70 miles of pipe / 31,220 HP of compression Current Capacity: 470 MMcf per day Interconnects with TGP 300 Total Investment to Date: $277 million FY 2018 CapEx: ~$10 million Modest Midstream compression and pipeline investment required to support Utica development Timing and extent of gathering and compression investments are flexible to match Seneca’s modified development schedule and maximize returns Future Build-Out Ultimate capacity can exceed 1 Bcf/d Over 300 miles of pipelines and five compressor stations (+60,000 HP installed) Deliverability into TGP 300 and NFG Supply Gathering System Build-Out Tailored to Accommodate Seneca’s WDA Development Midstream Clermont Gathering System Map

Integrated Development – EDA Gathering Systems Total Investment (to date): $33 million Capacity: 220,000 Dth per day (Interconnect w/ TGP 300) Production Source: Seneca Resources – Tioga Co. (Covington and DCNR Tract 595) Total Investment (to date): $173 million FY 2018 Capital Expenditures: ~$45 million Capacity: 466,000 to 585,000 Dth per day (Interconnect w/ Transco) Production Source: Seneca Resources – Lycoming Co. (DCNR Tract 100 and Gamble) Future third-party volume opportunities Covington Gathering System Trout Run Gathering System Gathering Segment Supporting Seneca’s EDA Production & Future Development Midstream Interconnects Wellsboro Gathering System Total Investment (to date): $7 million FY 2018 Capital Expenditures: ~$15 million Capacity: 200,000 Dth per day (Interconnect w/ TGP 300) Production Source: Seneca Resources – Tioga Co. (DCNR Tract 007)

Infrastructure Expansions Bolster Supply Diversity Northern Access 2015 (In-Service(1)) System: NFG Supply Corp. Capacity: 140,000 Dth per day Leased to TGP as part of TGP’s Niagara Expansion project Delivery Interconnect: Niagara (TransCanada) Total Cost: $67.1 million Annual Revenues: $13.3 million Expanding Our Pipelines to Assure Supply Security for New York Markets Integration of Seneca’s WDA Production Into Broader Interstate System Midstream 40,000 Dth per day went in-service on November 1, 2015. The remaining 100,000 Dth per day was placed in-service on December 1, 2015. Northern Access 2016 (Delayed) In-Service: TBD Systems: NFG Supply Corp. & Empire Pipeline Capacity: 490,000 Dth per day Total Expected Cost: ~$500 million Project Status: Delayed pending appeal of NYS DEC WQC notice of denial 401 Chippewa To Dawn Niagara East Aurora NE US (TGP 200)

Northern Access Project Status Project in-service not expected before 2019 due to regulatory delays February 3, 2017 – NFG received FERC 7(c) certificate March 3, 2017 – NFG filed petition for rehearing with FERC seeking waiver of NYS DEC Clean Water Act Section 401 Water Quality Certification (WQC) and preemption on state level permits April 7, 2017 – NY DEC issued notice of denial of WQC and other state stream and wetland permits for NY portion of project (PA DEP WQC received in January 2017) April 21, 2017 – NFG filed appeal of NY DEC WQC notice of denial with US Court of Appeals for the 2nd Circuit Project Spending Update: Total project spending to-date: ~$74 million Minimal remaining commitments National Fuel Remains Committed to Building the Northern Access Pipeline Project Midstream

Empire System Expansion Target In-Service: November 2019 System: Empire Pipeline Estimated Cost: $135 million Receipt Point: Jackson (Tioga Co., Pa. production) Design Capacity and Delivery Points: 175,000 Dth/d to Chippawa (TCPL interconnect) 30,000 Dth/d to Hopewell (TGP 200 interconnect) Customers: Precedent agreements in-place for 185,000 Mdth/d Negotiating commitments on remaining capacity Major Facilities: 2 new compressor stations in NY (1) & Pa. (1) No new pipeline construction Foundation Shipper Agreement Provides Major Commitment Needed for the Empire North Project Midstream 39

Continued Expansion of the NFG Supply System Line N Expansion Opportunities Line D Expansion Project Midstream Target In-Service: November 2017 Contracted Capacity: 77,500 Dth/d from an interconnect with TGP 300 at Lamont, Pa. into Erie, Pa. market Estimated Cost: $28 million ($8 million modernization) Project Status: In-construction Line D Expansion Project Line N Expansion Opportunities Line N Expansion Opportunity #1 (Supply OS #220) Project: Firm transportation service to a new ethylene cracker facility being built by Shell Chemical Appalachia, LLC. Target In-Service: July 2019 Contracted Capacity: 133,000 Dth/d with foundation shipper Line N Expansion Opportunity #2 (Supply OS #221) Project: New firm transportation service for on-system demand Target In-Service: July 2020 Open Season Capacity: Awarded 165,000 to foundation shipper. Precedent agreement in negotiations. Future NFG Supply System Expansions

Pipeline & Storage Customer Mix 4.1 MMDth/d Contracted as of 10/20/2016. Customer Transportation by Shipper Type(1) Affiliated Customer Mix (Contracted Capacity) Firm Transport Midstream

Downstream Overview Utility ~ Energy Marketing

New York & Pennsylvania Service Territories New York Total Customers(1): 528,312 ROE: 8.7% (NY PSC Rate Case Order, April 2017) Rate Mechanisms: Revenue Decoupling Weather Normalization Low Income Rates Merchant Function Charge (Uncollectibles Adj.) 90/10 Sharing (Large Customers) Pennsylvania Total Customers(1): 213,924 ROE: Black Box Settlement (2007) Rate Mechanisms: Low Income Rates Merchant Function Charge As of September 30, 2016. Downstream

New York Rate Case Outcome Downstream Rate Order Summary: Revenue Requirement:$5.9 million Rate Base:$704 million (prior case $632 million1) Allowed Return on Equity (ROE):8.7% (prior case allowed 9.1%1) Capital Structure:42.9% equity Other notable items: New rates effective 5/1/17 Retains rate mechanisms in place under prior order (revenue decoupling, weather normalization, merchant function charge, 90/10 large customer sharing) No stay-out clause Earnings sharing would start 4/1/18 if NFG Distribution Corp. does not file for new rates to become effective on or before 10/1/18 (50/50 sharing starts at earnings in excess of 9.1%) Article 78 appeal filed on 7/28/17 On April 20, 2017, the New York Public Service Commission issued a Rate Order relating to NFG Distribution’s rate case (No. 16-G-0257) filed in April 2016. Case 13-G-0136 rate year ended September 30, 2015.

Utility: Shifting Trends in Customer Usage Weighted Average of New York and Pennsylvania service territories (assumes normal weather). Usage Per Account (1) 12-Months Ended June 30 Downstream

Utility: Strong Commitment to Safety The Utility remains focused on maintaining the ongoing safety and reliability of its system Capital Expenditures ($ millions)(1) Downstream A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation.

Accelerating Pipeline Replacement & Modernization NY 9,700 miles PA* 4,830 miles * No Cast Iron Mains in Pa.* Miles of Utility Main Pipeline Replaced(1) Utility Mains by Material Downstream As reported to the Department of Transportation on calendar year basis. Coated

A Proven History of Controlling Costs O&M Expense ($ millions) Downstream

Appendix

Earnings Guidance Fiscal 2017 EPS Guidance Non-regulated Businesses Exploration & Production Gathering $3.25/sh to $3.35/sh $2.70/sh to $3.05/sh Fiscal 2018 EPS Guidance Seneca Net Production: 185 to 200 Bcfe (up 17.5 Bcf or 10% vs FY 17) Gathering Revenues: $115 to $125 million (up $10 million or 9% vs FY17) Natural Gas : ~$2.55 /Mcf(1) (down $0.41 /Mcf vs. $2.96 /Mcf FYTD 2017) Crude Oil: ~$49.50 /Bbl(2) (down $4.08 /Bbl vs. $53.58 /Bbl FYTD 2017) Key Guidance Drivers Assumes NYMEX natural gas pricing of $3.00 /MMBtu and basin spot pricing of $2.40 /MMbtu and reflects the impact of existing financial hedge, firm sales and firm transportation contracts. Assumes NYMEX (WTI) oil pricing of $50.00 /Bbl and California-MWSS pricing differentials of 92% to WTI, and reflects impact of existing financial hedge contracts. Production Realized natural gas & oil prices (after-hedge) Utility Normal Weather Regulated Businesses Pipeline & Storage Utility Guidance assumes normal weather Warmer than normal weather impacted FY17 earnings by ~$0.06/sh ~$295 million in revenues (flat vs. FY17) Pipeline & Storage Revenues Appendix Decline in FY18 Earnings Guidance Predominantly Due to Lower Commodity Price Realizations 50

Marcellus Operated Well Results EDA Development Wells: Area Producing Well Count Average IP Rate (MMcfd) Average 30-Day (MMcf/d) Average Treatable Lateral Length Covington Tioga County 47 5.2 4.1 4,023 ft Tract 595 Tioga County 44(2) 7.4 4.9 4,754 ft Tract 100 Lycoming County 60(2) 17.0 12.6 5,221 ft Area Producing Well Count Average IP Rate (MMcfd) Average 30-Day (MMcf/d) Average Treatable Lateral Length Clermont/Rich Valley (CRV) & Hemlock Elk, Cameron & McKean counties 135(1) 6.7 5.1 7,131 ft WDA Development Wells: Excludes 2 wells now operated by Seneca that were drilled by another operator as part of a joint-venture. Excludes 5 wells producing from the Utica shale. Excludes 1 well each drilled into and producing from the Geneseo Shale in Tract 595 and Tract 100. Appendix

Hedge Positions Fixed price physical sales exclude joint development partner’s share of fixed price contract WDA volumes as specified under the joint development agreement. Appendix Natural Gas Volumes in thousand MMBtu; Prices in $/MMBtu Fiscal 2017 (last 3 mos.) Fiscal 2018 Fiscal 2019 Fiscal 2020 Fiscal 2021 Volume Avg.Price Volume Avg.Price Volume Avg.Price Volume Avg.Price Volume Avg.Price NYMEX Swaps 9990 $4.3499999999999996 42570 $3.34 27060 $3.17 16880 $3.07 4840 $3.01 Dominion Swaps 450 $3.82 180 $3.82 - - - - - - Dawn Swaps 3330 $3.71 8400 $3.08 7200 $3 7200 $3 600 $3 Fixed Price Physical 17382 $2.4500000000000002 42903 $2.42 32328 $2.5099999999999998 38233 $2.2999999999999998 38561 $2.2200000000000002 Total 31152 $3.21 94053 $2.9 66588 $2.83 62313 $2.59 44001 $2.31 Crude Oil Volumes & Prices in Bbl Fiscal 2017 (last 3 mos.) Fiscal 2018 Fiscal 2019 Fiscal 2020 Volume Avg. Volume Avg. Volume Avg. Volume Avg. Price Price Price Price Brent Swaps 24000 $91 24000 $91 - - - - NYMEX Swaps 396000 $58.34 1275000 $54.79 912000 $53.84 168000 $50.08 Total 420000 $60.21 1299000 $55.46 912000 $53.84 168000 $50.08

Comparable GAAP Financial Measure Slides & Reconciliations This presentation contains certain non-GAAP financial measures. For pages that contain non-GAAP financial measures, pages containing the most directly comparable GAAP financial measures and reconciliations are provided in the slides that follow. The Company believes that its non-GAAP financial measures are useful to investors because they provide an alternative method for assessing the Company’s ongoing operating results and for comparing the Company’s financial performance to other companies. The Company’s management uses these non-GAAP financial measures for the same purpose, and for planning and forecasting purposes. The presentation of non-GAAP financial measures is not meant to be a substitute for financial measures prepared in accordance with GAAP. The Company defines Adjusted EBITDA as reported GAAP earnings before the following items: interest expense, depreciation, depletion and amortization, interest and other income, impairments, items impacting comparability and income taxes. Appendix

Non-GAAP Reconciliations – Adjusted EBITDA Appendix

Non-GAAP Reconciliations – Capital Expenditures Appendix

Non-GAAP Reconciliations – E&P Operating Expenses Appendix