Investor Presentation Q2 Fiscal 2017 Update May 4, 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 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; 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; 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 and March 31, 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.

Quality Assets – Exceptional Location – Unique Integration 1.8 Tcfe Proved Reserves (1) 785,000 net acres in Appalachia - mostly held in fee with no royalty 3 million Bbls annual CA crude oil production $285 million annual adjusted EBITDA (2) $1.3+ billion midstream investments since 2010 Coordinated gathering infrastructure build-out with NFG Upstream 740,000 Utility customer accounts Stable, regulated earnings & cash flows Generates operational and financial synergies with other segments Total proved reserves are as of September 30, 2016. For the trailing twelve months ended March 31, 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 Midstream Downstream

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

Flexibility to Responsibly Deploy Capital (1) FY 2016 actual capital expenditures reflects the netting of $157 million of up-front proceeds received from joint development partner for working interest in joint development wells. FY 2017 guidance also reflects the netting of anticipated proceeds received from the joint development partner. Note: A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation. Capital Expenditures by Segment ($ millions) E&P Total NFG Gross CapEx $256 $523 JDA Proceeds ($157) ($157) Net CapEx $99 $366 CapEx Reconciliation for JDA Proceeds ($millions) 5

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: ~$68 million Fiscal 2017 Pipeline & Expenditure capital expenditure guidance reduced by $115 million Minimal remaining commitments National Fuel Remains Committed to Building the Northern Access Pipeline Project

The Bridge to Northern Access Exploration & Production Strategy Midstream Strategy Corporate Strategy Near-term in-basin pricing supports plans for 10%+ annual production growth over next 3 years WDA Development – Maintain 1 rig program Convert Northern Access firm sales from Dawn (95 MMcf/d) and layer-in new firm sales on TGP 300 Utica expected to provide further upside to WDA economics and returns EDA Development – Adding 2nd Seneca rig in May 2017 Prepare well inventory for Atlantic Sunrise capacity (190 Mdth/d) starting mid-2018 Commence Utica development of EDA-Tract 007 (Tioga County) in fiscal 2018 for further growth 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 Opportunities for continued investment in 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 7

Gathering: Just-in-time installation of gathering pipelines and compression facilities to accommodate Seneca’s development plans Pipeline & Storage: FY17 capex reduced by $115 million due to Northern Access delay Line D expansion and system maintenance and modernization Near-term Capital Budget and Operating Plan Reflects the netting of anticipated proceeds received from the joint development partner for working interest in joint development wells. Current E&P guidance increased $30 million to reflect changes in the timing of Seneca’s development activities. Note: A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation. (1) Upstream Capital Expenditures by Segment ($MM) FY2017 Operating Plan Appalachia: 2 rigs (1 WDA / 1 EDA) / 1 daylight only frac crew 2nd rig added in May 2017 to prepare for Atlantic Sunrise capacity 10-well Utica appraisal program concurrent with Marcellus drilling in WDA California: $35- $45 million capex to maintain production levels Midstream Downstream Utility: Pipeline replacement and system modernization spending.

Strong Balance Sheet & Liquidity Total Debt 56% $3.7 Billion Total Capitalization as of March 31, 2017 Debt/Adjusted EBITDA Capitalization Debt Maturity Profile ($MM) Liquidity Committed Credit Facilities Short-term Debt Outstanding Available Short-term Credit Facilities Cash Balance at 03/31/17 Total Liquidity at 03/31/17 $ 1,250 MM $ 0 MM $ 1,250 MM $ 231 MM $ 1,481 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 114 Years Consecutive Increases 46 Years Current Dividend Rate $1.62 per Share Current Dividend Yield (1) 3.0% As of May 3, 2017. NFG’s Dividend Consistency

Upstream Overview Exploration & Production

Significant Appalachian Acreage Position Daily gross production: ~300 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 Daily gross production: ~280 MMcf/d Large inventory of high quality Marcellus 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

Marcellus Shale: Western Development Area WDA Tier 1 Acreage – 200,000 Acres WDA Tier 1 Marcellus Economics(1) WDA Highlights Large drilling inventory of quality Marcellus dry gas ~1,100 locations economic < $2.00/MMBtu realized Fee acreage provides flexibility/enhances economics No royalty on most acreage No lease expirations or requirements to drill acreage Highly contiguous position drives best in class Marcellus well costs Multi-well pad drilling averaging 10 wells with 8,000 ft. laterals Water management operations lowering water costs to under $1 /Bbl NFG midstream infrastructure supporting growth Early Utica test results in CRV on trend with other Utica wells in NE Pa. Will have 8 Utica test wells on-line by end of FY 2017 Internal rate of return (IRR) is pre-tax and includes estimated well costs under the current well design and cost structure and projected firm transportation, gathering, LOE and other operating costs.     Avg Avg $3.00 15% IRR   Locations Lateral EUR NYMEX/Dawn Realized   Remaining Length (ft) (Bcf) IRR% Price CRV 22 8,000 8.5-9.5 33% $1.70 Hemlock/Ridgway 631 8,800 8-9 32% $1.76 Other Tier 1 406 8,500 7-8 28% $1.84 Clermont/ Rich Valley Hemlock Ridgway 2 - 4 BCF/well 7- 9.5 BCF/well 4 - 6 BCF/well EUR Color Key Upstream

WDA Clermont/Rich Valley Development Gross daily production: ~270 MMcf/d 1-rig/daylight only frac crew Marcellus well costs averaging ~$660 per lateral ft. 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

Best in Class Marcellus Well Costs Down 60% since 2012 Down 77% since 2012 Seneca Average Marcellus Well Cost(1) vs. Appalachian Peers (2) Seneca CRV reflects a $5.3 million “all-in” total well cost for a 8,000 ft. lateral. Total well costs include drilling, completions, allocated pad level and production equipment. Appalachian peers include AR, COG, EQT, RICE, RRC, & SWN. Data obtained or recalculated from most recent peer company presentations. Marcellus Drilling Cost per Foot Marcellus Completion Cost per Stage ($000s) Upstream 15

Marcellus Shale: 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 2 Marcellus producing wells Utica 30-day IP = 15.8 MMcf/d Utica resource potential ~1 Tcf Development expected to begin in fiscal 2018 Covington & DCNR Tract 595 (Tioga Co., Pa.) Gross daily production: ~100 MMcf/d Marcellus locations fully developed Opportunity for future Utica appraisal DCNR Tract 100 & Gamble (Lycoming Co., Pa.) Gross daily production: ~200 MMcf/d 54 remaining Marcellus locations economic < $1.60 /Mcf Atlantic Sunrise capacity (190 MDth/d) in mid-2018 Geneseo to provide 100-120 additional locations Geneseo test well 24hr IP: 14.1 MMcf/d on 4,920’ lateral 3 Added 1 Rig May 2017 FY17/18 – Lycoming Dev FY18+ – Utica Tioga Dev 16

Utica Shale Opportunities Seneca’s Utica Activity on Trend with Strong Results in Northern Pa. Upstream Pennsylvania Utica Activity Seneca’s Utica Opportunities Western Development Area First 2 Utica test wells in Clermont / Rich Valley area are exceeding Marcellus performance Executing 10 well appraisal program over next 18 months Economics enhanced by 100% net revenue interest (no royalty) and ability to use existing infrastructure Eastern Development Area 1st test well producing on DCNR 007 in Tioga County among the best in Northeastern Pa. Industry activity in Tioga and Potter Counties suggest strong Utica potential on other EDA prospects 50 MILES Wet Gas Dry Gas Permitted TD’d Completed Production SRC Planned SRC Vertical SRC Producer High Pressure Zone Ordovician Outcrop EQT CNX RRC CNX JKLM Hilcorp CHK Shell Seneca WDA Seneca EDA

WDA Utica Update Results: WDA Utica Results (1) vs Avg WDA Marcellus WDA-CRV Utica Test Wells WDA-CRV Marcellus Wells (Average) Well 113HU Well 196HU(1) 121 wells Initial Test June 2016 Nov 2016 Lateral Length 4,630 ft 6,288 ft 7,139 ft Choke Avg ( /64th) 35/64th 28/64th 64/64th 30 Day IP/1,000 ft 1.4 MMcf/d 1.0 MMcf/d 0.7 MMcf/d Est. EUR/1,000 ft 2.0 Bcf 1.8 Bcf 1.1 Bcf First Two Utica Test Wells in WDA CRV Area Continue to Exceed Marcellus Performance Managed pressure drawdown of 196HU resulted in depressed early-time metrics. Upstream Early economic indicators: 60 - 80% higher production/EUR 25 - 35% increase in Upstream capital per well Will use existing Upstream pad and water facilities and Gathering infrastructure from current Marcellus development to drive efficiencies Can utilize existing and future contracted firm transport capacity (Niagara Expansion and Northern Access)

WDA Utica Appraisal Program Plan to drill 10 total Utica appraisal wells off Marcellus development pads Two wells on pad EO9-S producing under 30 days Testing target zone and D&C design Can leverage existing upstream and midstream infrastructure to drive capital, operational, and marketing efficiencies Expect Utica CRV WDA development costs to range from $5.0 to $6.0 million per well WDA UTICA TESTING TIMELINE   Pad # Wells Status Test Timing (FY) 1 E09-M 1 Producing Initial On-line 2 NF-A 1 Producing Sand On-line 3 E09-S 2 Producing Target On-line 4 C09-D 1 Completed Step-out Q3 '17 5 D08-U 3 Planned Target Q4 '17 6 E08-T 2 Planned Step-out Q4 '18 Short Term Plan Forward Upstream 1 Mile Built Planning Field-Verified Proposed Pad Status Producing Completed TD’d Planned Possible Well Status 1 2 3 4 5 6

EDA Utica Update Northeast PA Utica Well Performance – Tioga and Potter County 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 Seneca DCNR 007 Utica Well Among the Best in Northeastern PA Upstream Source: PA DEP. Includes production from 19 Potter and Tioga County wells Utica DCNR 007 development expected in 2018 Up to 68 development locations delivering 1 Tcf recoverable resource Expect development costs to range from $5.5 to $6.5 million per well Midstream infrastructure: NFG Midstream Wellsboro Gathering System Interconnect with Tennessee Gas Pipeline 300 Evaluating long-term takeaway options

California Oil Stable Oil Production | Minimal Capital Investment | Free Cash Flow Positive 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) 2013 2014 2015 2016 2017 Forecast 2013 2014 2015 2016 2017 Forecast

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 $55/Bbl(1) Reflects pre-tax IRRs at a $55/Bbl WTI. Upstream

Proved Reserves & Development Costs (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

Seneca Production Upstream 10%+ CAGR Target Significant base of long-term firm contracts and relatively strong near-term regional pricing outlook supports Appalachian development program that will drive 10%+ annual Appalachian production growth while NFG works through Northern Access delay Near-term Growth Strategy 2 rig development program Atlantic Sunrise capacity starting mid-2018 New Utica development in EDA with production starting in FY19 Layer-in firm sales to take advantage of attractive regional pricing Gross production growth will benefit NFG’s Gathering segment 25

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 MMdth/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 26

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 Gross vs. Net Firm Sales Volumes (Dth per Day) Q3 FY17 Q4 FY17 Gross 503,000/d 478,000/d NRI Owners(2) 143,800/d 122,200/d Net 359,200/d 355,800/d FY 17 Net Contracted 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. Reflects adjustment to gross sales volumes to reflect impact of lease royalties in EDA and net revenue interests assigned to joint development partner on certain contracts in WDA. Upstream Q3 FY17 Q4 FY17

Strong Hedge Book Natural Gas Swap & Fixed Physical Sales Contracts (Millions MMBtu) Remaining Fiscal 2017 Natural Gas Production ~80% hedged (1) at $3.30 per MMBtu (2) Assumes midpoint of natural gas production guidance, adjusted for year-to-date actual results. Fixed price physical sales exclude joint development partner’s share of fixed price contract WDA volumes as specified under the joint development agreement. Upstream

Fiscal 2017 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. Includes non-operated production from Western Development Area (legacy EOG JV wells) of ~2 Bcf. 57 Bcf realizing net ~$3.09/Mcf (1) 5 Bcf of Additional Basis Protection Upstream 58% of remaining oil production hedged at $60.21 /Bbl Remaining spot production assumed to be sold at $2.00/Mcf

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 to $1.00 per Mcfe for fiscal 2017. Upstream

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/26,220 HP of compression Current Capacity: 470 MMcf per day Interconnects with TGP 300 Total CapEx To Date: $272 million FY 2017 CapEx: ~$30 million Timing and extent of gathering & 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 Capital Expenditures (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 acreage) Capital Expenditures (to date): $168 Million Capacity: 466,000 to 585,000 Dth per day (Interconnect w/ Transco) Production Source: Seneca Resources – Lycoming Co. (DCNR Tract 100 and Gamble acreage) 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 Capital Expenditures (to date): $7 Million Capacity: 200,000 Dth per day (Interconnect w/ TGP 300) Production Source: Seneca Resources – 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) 36

Empire System Expansion Target In-Service: as early as Nov. 1, 2019 System: Empire Pipeline Estimated Cost: $150 to $200 million (scalable) Receipt Point: Jackson (Tioga Co., Pa.) Available Capacity / Delivery Points: 180,000 Dth/d to Chippawa (TCPL) 120,000 Dth/d to Hopewell (TGP) Major Facilities: 70,000 hp at 3 new compressor stations in NY & Pa. No new pipeline construction in NY Project Status: Open Season fully subscribed Foundation shipper agreement in place for substantial portion of expansion capacity Negotiating commitments on remaining capacity Foundation Shipper Agreement Provides Major Commitment Needed for the Empire North Project Midstream

Continued Expansion of the NFG Supply System Line N Expansion Opportunities Line D Expansion Project Midstream Target In-Service: Nov. 1, 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 - expected conclusion 5/4/17) Project: Provide nat gas transportation service to a new ethylene cracker facility being built by Shell Chemical Appalachia, LLC. Open Season Capacity: 100,000 Dth/d from Hollbrook interconnect (TETCO) 73,000 Dth/d on a new 4-mile pipeline extension to facility Project Status: Foundation Shipper Agreement signed Line N Expansion Opportunity #2 (Supply OS #221) New open season expected to launch 5/4/17 in response to market interest Future NFG Supply System Expansions 38

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: Earnings Sharing 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%) 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. 42

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 March 31 Downstream

Utility: Strong Commitment to Safety Recent increase due to ~$60MM upgrade of the Utility’s Customer Information System and anticipated acceleration of pipeline replacement program The Utility remains focused on maintaining the ongoing safety and reliability of its system Capital Expenditures ($ millions) Downstream

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

Appendix

Marcellus Operated Well Results EDA Development Wells: Area Producing Well Count Average IP Rate (MMcfd) Average 30-Day (MMcf/d) Average Treatable Lateral Length (ft) Covington Tioga County 47 5.2 4.1 4,023’ Tract 595 Tioga County 44(2) 7.4 4.9 4,754’ Tract 100 Lycoming County 60(2) 17.0 12.6 5,221’ Area Producing Well Count Average IP Rate (MMcfd) Average 30-Day (MMcf/d) Average Treatable Lateral Length (ft) Clermont/Rich Valley (CRV) & Hemlock Elk, Cameron & McKean counties 121(1) 6.9 5.3 7,139’ WDA Development Wells: Excludes 2 wells now operated by Seneca that were drilled by another operator as part of a joint-venture. Excludes 4 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

Marcellus Shale Program Economics 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. Net realized price reflects either (a) price received at the well-head or (b) price received at delivery market net of firm transportation charges. ~1,150 Locations Economic Below $2.00/MMBtu Appendix Prospect Product Locations Remainingto Be Drilled Completed Lateral Length (ft) Average EUR (Bcf) NYMEX / DAWN Pricing Net Realized Price(2) Required for 15% IRR Anticipated DeliveryMarkets $3.00IRR % (1) $2.75IRR % (1) $2.50IRR % (1) EDA DCNR 100 Dry Gas(1033 BTU) 12 5700 13.5-14.5 0.8 0.59 0.4 $1.45 Transco Leidy &Atlantic Sunrise Southeast US(NYMEX+) Gamble Dry Gas(1033 BTU) 42 4250 10-11 0.57999999999999996 0.43 0.26 $1.59 WDA CRV Dry Gas(1045 BTU) 22 8000 8.5-9.5 0.33 0.24 0.16 $1.7 TGP 300 &Niagara Expansion Canada (Dawn) Hemlock/ Ridgway Dry Gas(1045 BTU) 631 8800 8-9 0.32 0.23 0.14000000000000001 $1.76 Remaining Tier 1 Dry Gas(1045 BTU) 406 8500 7-8 0.28000000000000003 0.19 0.12 $1.84 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)

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 6 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 19980 $4.3499999999999996 42570 $3.34 27060 $3.17 16880 $3.07 4840 $3.01 Dominion Swaps 900 $3.82 180 $3.82 - - - - - - Dawn Swaps 6660 $3.71 8400 $3.08 7200 $3 7200 $3 600 $3 Fixed Price Physical 31360 $2.54 35260 $2.39 15807 $2.83 11277 $2.42 7665 $2.0299999999999998 Total 58900 $3.3 86410 $2.93 50067 $3.04 35357 $2.85 13105 $2.44 Crude Oil Volumes & Prices in Bbl Fiscal 2017 (last 6 mos.) Fiscal 2018 Fiscal 2019 Volume Avg. Volume Avg. Volume Avg. Price Price Price Brent Swaps 48000 $91 24000 $91 - - NYMEX Swaps 792000 $58.34 1275000 $54.79 912000 $53.84 Total 840000 $60.21 1299000 $55.46 912000 $53.84

Assets: 75 current and future Marcellus development wells in the Clermont/Rich Valley region of Seneca’s WDA. Locations Developed Under Initial Obligation: 39 wells Remaining Locations to be Developed: 36 wells Partner Option: IOG has one-time option to participate in a 7-well pad to be completed before December 31, 2017 Economics: IOG participates as an 80% working interest owner until the IOG achieves a 15% IRR hurdle. Seneca retains a 7.5% royalty and remaining 20% working interest. Natural Gas Marketing: IOG to receive same realized price before hedging as Seneca on production from the joint development wells, including firm sales and the cost of firm transportation. Seneca WDA Joint Development Agreement Estimated reduction in capital expenditures from joint development agreement assumes current wells costs. Transaction Key Terms of the Agreement On June 13, 2016, Seneca announced the extension of asset-level joint development agreement with IOG CRV – Marcellus Capital, LLC, an affiliate of IOG Capital, LP, and funds managed by affiliates of Fortress Investment Group LLC, to jointly develop Marcellus Shale natural gas assets located in the Western Development Area. Strategic Rationale Significantly reduces near-term upstream capital spending Initial 39 wells - $170 million(1) Remaining 36 wells - $155 million(1) Validates quality of Seneca’s Tier 1 Marcellus WDA acreage Seneca maintains activity levels to continue to drive Marcellus drilling and completion efficiencies Solidifies NFG’s midstream growth strategy: Gathering - All production from JV wells will flow through NFG Midstream’s Clermont Gathering System Pipeline & Storage - Provides production growth that will utilize the 660 MDth/d of firm transportation capacity on NFG’s Northern Access pipeline expansion projects available starting Nov. 1, 2017 Strengthened balance sheet and makes Seneca cash flow positive in near-term   Seneca IOG Working Interest 20% 80% Net Revenue Interest 26% 74% Appendix

Comparable GAAP Financial Measure Slides & Reconciliations This presentation contains certain non-GAAP financial measures. For pages that contain non-GAAP financial measures, pages containing the most directly comparable GAAP financial measures and reconciliations are provided in the slides that follow. The Company believes that its non-GAAP financial measures are useful to investors because they provide an alternative method for assessing the Company’s ongoing operating results and for comparing the Company’s financial performance to other companies. The Company’s management uses these non-GAAP financial measures for the same purpose, and for planning and forecasting purposes. The presentation of non-GAAP financial measures is not meant to be a substitute for financial measures prepared in accordance with GAAP. The Company 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 Reconciliation of Adjusted EBITDA to Consolidated Net Income ($ Thousands) Total Adjusted EBITDA Exploration & Production Adjusted EBITDA 492,383 $ 539,472 $ 422,289 $ 363,830 $ 389,528 Pipeline & Storage Adjusted EBITDA 161,226 186,022 188,042 199,446 192,147 Gathering Adjusted EBITDA 29,777 64,060 68,881 78,685 92,668 Utility Adjusted EBITDA 171,669 164,643 164,037 148,683 147,210 Energy Marketing Adjusted EBITDA 6,963 10,335 12,237 6,655 3,385 Corporate & All Other Adjusted EBITDA (9,920) (11,078) (11,900) (8,238) (9,736) Total Adjusted EBITDA 852,098 $ 953,454 $ 843,586 $ 789,061 $ 815,202 $ Total Adjusted EBITDA 852,098 $ 953,454 $ 843,586 $ 789,061 $ 815,202 $ Minus: Interest Expense (94,111) (94,277) (99,471) (121,044) (118,911) Plus: Interest and Other Income 9,032 13,631 11,961 14,055 11,671 Minus: Income Tax Expense (172,758) (189,614) 319,136 232,549 (137,234) Minus: Depreciation, Depletion & Amortization (326,760) (383,781) (336,158) (249,417) (228,113) Minus: Impairment of Oil and Gas Properties (E&P) - - (1,126,257) (948,307) (115,413) Plus: Reversal of Stock-Based Compensation - - 7,776 - - Plus: Elimination of Other Post-Retirement Regulatory Liability (P&S) - - - - - Minus: Pennsylvania Impact Fee Related to Prior Fiscal Years (E&P) - - - - - Minus: New York Regulatory Adjustment (Utility) (7,500) - - - - Minus: Joint Development Agreement Professional Fees - - - (7,855) (3,173) Rounding - - - - - Consolidated Net Income 260,001 $ 299,413 $ (379,427) $ (290,958) $ 224,029 $ Consolidated Debt to Total Adjusted EBITDA Long-Term Debt, Net of Current Portion (End of Period) 1,649,000 $ 1,649,000 $ 2,099,000 $ 2,099,000 $ 2,099,000 $ Current Portion of Long-Term Debt (End of Period) - - - - - Notes Payable to Banks and Commercial Paper (End of Period) - 85,600 - - - Total Debt (End of Period) 1,649,000 $ 1,734,600 $ 2,099,000 $ 2,099,000 $ 2,099,000 $ Long-Term Debt, Net of Current Portion (Start of Period) 1,149,000 1,649,000 1,649,000 2,099,000 2,099,000 Current Portion of Long-Term Debt (Start of Period) 250,000 - - - - Notes Payable to Banks and Commercial Paper (Start of Period) 171,000 - 85,600 - - Total Debt (Start of Period) 1,570,000 $ 1,649,000 $ 1,734,600 $ 2,099,000 $ 2,099,000 $ Average Total Debt 1,609,500 $ 1,691,800 $ 1,916,800 $ 2,099,000 $ 2,099,000 $ Average Total Debt to Total Adjusted EBITDA 1.89 x 1.77 x 2.27 x 2.66 x 2.57 x FY 2013 12-Months Ended 03/31/17 FY 2014 FY 2015 FY 2016

Non-GAAP Reconciliations – Capital Expenditures Appendix Reconciliation of Segment Capital Expenditures to Consolidated Capital Expenditures ($ Thousands) FY 2017 FY 2013 FY 2014 FY 2015 FY 2016 Forecast Capital Expenditures from Continuing Operations Exploration & Production Capital Expenditures 533,129 $ 602,705 $ 557,313 $ 256,104 $ $210,000 - $250,000 Pipeline & Storage Capital Expenditures 56,144 $ 139,821 $ 230,192 $ 114,250 $ $100,000 - $120,000 Gathering Segment Capital Expenditures 54,792 $ 137,799 $ 118,166 $ 54,293 $ $50,000 - $60,000 Utility Capital Expenditures 71,970 $ 88,810 $ 94,371 $ 98,007 $ $90,000 - $100,000 Energy Marketing, Corporate & All Other Capital Expenditures 1,062 $ 772 $ 467 $ 397 $ Total Capital Expenditures from Continuing Operations 717,097 $ 969,907 $ 1,000,509 $ 523,051 $ $450,000 - $530,000 Plus (Minus) Accrued Capital Expenditures Exploration & Production FY 2016 Accrued Capital Expenditures - $ - $ - $ (25,215) $ Exploration & Production FY 2015 Accrued Capital Expenditures - - (46,173) 46,173 Exploration & Production FY 2014 Accrued Capital Expenditures - (80,108) 80,108 - Exploration & Production FY 2013 Accrued Capital Expenditures (58,478) 58,478 - - Exploration & Production FY 2012 Accrued Capital Expenditures 38,861 - - - Exploration & Production FY 2011 Accrued Capital Expenditures - - - - Pipeline & Storage FY 2016 Accrued Capital Expenditures - - - (18,661) Pipeline & Storage FY 2015 Accrued Capital Expenditures - - (33,925) 33,925 Pipeline & Storage FY 2014 Accrued Capital Expenditures - (28,122) 28,122 - Pipeline & Storage FY 2013 Accrued Capital Expenditures (5,633) 5,633 - - Pipeline & Storage FY 2012 Accrued Capital Expenditures 12,699 - - - Pipeline & Storage FY 2011 Accrued Capital Expenditures - - - - Gathering FY 2016 Accrued Capital Expenditures - - - (5,355) Gathering FY 2015 Accrued Capital Expenditures - - (22,416) 22,416 Gathering FY 2014 Accrued Capital Expenditures - (20,084) 20,084 - Gathering FY 2013 Accrued Capital Expenditures (6,700) 6,700 - - Gathering FY 2012 Accrued Capital Expenditures 12,690 - - - Gathering FY 2011 Accrued Capital Expenditures - - - - Utility FY 2016 Accrued Capital Expenditures - - - (11,203) Utility FY 2015 Accrued Capital Expenditures - - (16,445) 16,445 Utility FY 2014 Accrued Capital Expenditures - (8,315) 8,315 - Utility FY 2013 Accrued Capital Expenditures (10,328) 10,328 - - Utility FY 2012 Accrued Capital Expenditures 3,253 - - - Utility FY 2011 Accrued Capital Expenditures - - - - Total Accrued Capital Expenditures (13,636) $ (55,490) $ 17,670 $ 58,525 $ Total Capital Expenditures per Statement of Cash Flows 703,461 $ 914,417 $ 1,018,179 $ 581,576 $ $450,000 - $530,000

Non-GAAP Reconciliations – E&P Operating Expenses Appendix Reconciliation of Exploration & Production Segment Operating Expenses by Division ($000s unless noted otherwise) Appalachia West Coast (2) Total E&P Appalachia West Coast (2) Total E&P Appalachia West Coast (2) Total E&P Appalachia West Coast (2) Total E&P $/ Mcfe $ / Boe $ / Mcfe $/ Mcfe $ / Boe $ / Mcfe Operating Expenses: Gathering & Transportation Expense (1) $82,949 $309 $83,258 $0.59 $0.09 $0.52 $81,212 $435 $81,647 $0.59 $0.12 $0.52 Lease Operating Expense $20,402 $50,254 $70,656 $0.14 $14.74 $0.44 $29,510 $56,643 $86,153 $0.22 $16.04 $0.54 Lease Operating and Transportation Expense $103,351 $50,563 $153,914 $0.73 $14.83 $0.96 $110,722 $57,078 $167,800 $0.81 $16.17 $1.06 General & Administrative Expense $55,293 $15,305 $70,598 $0.39 $4.49 $0.44 $47,445 $18,669 $66,114 $0.35 $5.29 $0.42 All Other Operating and Maintenance Expense $6,228 $6,604 $12,832 $0.04 $1.94 $0.08 $5,296 $9,008 $14,304 $0.04 $2.55 $0.09 Property, Franchise and Other Taxes $5,403 $8,391 $13,794 $0.04 $2.46 $0.09 $9,046 $11,121 $20,167 $0.07 $3.15 $0.13 Total Taxes & Other $11,631 $14,995 $26,626 $0.08 $4.40 $0.17 $14,342 $20,129 $34,471 $0.11 $5.70 $0.22 Depreciation, Depletaion & Amortization $139,963 $0.87 $239,818 $1.52 Production: Gas Production (MMcf) 140,457 3,090 143,547 136,404 3,159 139,563 Oil Production (MBbl) 28 2,895 2,923 30 3,004 3,034 Total Production (Mmcfe) 140,625 20,460 161,085 136,584 21,183 157,767 Total Production (Mboe) 23,438 3,410 26,848 22,764 3,531 26,295 (1) Gathering and Transportation expense is net of any payments received from JDA partner for the partner's share of gathering cost (2) Seneca West Coast division includes Seneca corporate and eliminations. Twelve Months Ended September 30, 2016 Twelve Months Ended September 30, 2015