UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 8-K

CURRENT REPORT
Pursuant to Section 13 or 15(d)
of the Securities Exchange Act of 1934
Date of Report (Date of earliest event reported): August 2, 2018

NATIONAL FUEL GAS COMPANY
(Exact name of registrant as specified in its charter)

 
					
New Jersey	 	1-3880	 	13-1086010	
(State or other jurisdiction
of incorporation)	 	(Commission
File Number)	 	(IRS Employer
Identification No.)	
		
6363 Main Street, Williamsville, New York	 	14221	
(Address of principal executive offices)	 	(Zip Code)	
Registrant’s telephone number, including area code: (716) 857-7000
Former name or former address, if changed since last report: Not Applicable

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions ( see General Instruction A.2. below):
 
☐	Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)	
 
☐	Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)	
 
☐	Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))	
 
☐	Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))	
Indicate by check mark whether the registrant is an emerging growth company as defined in Rule 405 of the Securities Act of 1933 (§230.405 of this chapter) or Rule 12b-2 of the Securities Exchange Act of 1934 (§240.12b-2).
Emerging growth company  ☐
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.  ☐

 

Item 7.01	Regulation FD Disclosure.	
On August 2, 2018, National Fuel Gas Company (the “Company”) updated its Investor Presentation. A copy of the presentation is furnished as part of this Current Report as Exhibit 99.
Neither the furnishing of the presentation as an exhibit to this Current Report nor the inclusion in such presentation of any reference to the Company’s internet address shall, under any circumstances, be deemed to incorporate the information available at such internet address into this Current Report. The information available at the Company’s internet address is not part of this Current Report or any other report filed or furnished by the Company with the Securities and Exchange Commission.
In addition to financial measures calculated in accordance with generally accepted accounting principles (“GAAP”), the presentation furnished as part of this Current Report as Exhibit 99 contains certain non-GAAP financial measures. The Company believes that such non-GAAP financial measures are useful to investors because they provide an alternative method for assessing the Company’s operating results in a manner that is focused on the performance of the Company’s ongoing operations, for measuring the Company’s cash flow and liquidity, and for comparing the Company’s financial performance to other companies. The Company’s management uses these non-GAAP financial measures for the same purpose, and for planning and forecasting purposes. The presentation of non-GAAP financial measures is not meant to be a substitute for financial measures prepared in accordance with GAAP.
Certain statements contained herein or in the materials furnished as part of this Current Report, including statements regarding estimated future earnings and statements that are identified by the use of the words “anticipates,” “estimates,” “expects,” “forecasts,” “intends,” “plans,” “predicts,” “projects,” “believes,” “seeks,” “will” and “may” and similar expressions, are “forward-looking statements” as defined by the Private Securities Litigation Reform Act of 1995. There can be no assurance that the Company’s projections will in fact be achieved nor do these projections reflect any acquisitions or divestitures that may occur in the future. While the Company’s expectations, beliefs and projections are expressed in good faith and are believed to have a reasonable basis, actual results may differ materially from those projected in forward-looking statements. Furthermore, each forward-looking statement speaks only as of the date on which it is made. In addition to other factors, the following are important factors that could cause actual results to differ materially from those discussed in the forward-looking statements: 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; 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; changes in the price of natural gas or oil; impairments under the SEC’s full cost ceiling test for natural gas and oil reserves; 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 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; 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; the impact of potential information technology, cybersecurity or data security breaches; economic disruptions or uninsured losses resulting from major accidents, fires, severe weather, natural disasters, terrorist activities or acts of war; significant differences between the Company’s projected and actual capital expenditures and operating expenses; or increasing costs of insurance, changes in coverage and the ability to obtain insurance. The Company disclaims any obligation to update any forward-looking statements to reflect events or circumstances after the date hereof.
 
Item 9.01	Financial Statements and Exhibits.	
 
 	(d)	Exhibits	

		
Exhibit 99	  	Investor Presentation dated August 2018	

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

	 		 	NATIONAL FUEL GAS COMPANY	
				
	 		 	By:	 	/s/ Sarah J. Mugel	
	 		 		 	Sarah J. Mugel	
	 		 		 	Secretary	
Dated: August 2, 2018	 		 		 		

Investor Presentation Q3 Fiscal 2018 Update August 2, 2018 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 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; 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; changes in the price of natural gas or oil; impairments under the SEC’s full cost ceiling test for natural gas and oil reserves; 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 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; 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; the impact of potential information technology, cybersecurity or data security breaches; economic disruptions or uninsured losses resulting from major accidents, fires, severe weather, natural disasters, terrorist activities or acts of war; significant differences between the Company’s projected and actual capital expenditures and operating expenses; or increasing costs of insurance, changes in coverage and the ability to obtain insurance. Forward-looking statements include estimates of oil and gas quantities. Proved oil and gas reserves are those quantities of oil and gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible under existing economic conditions, operating methods and government regulations. Other estimates of oil and gas quantities, including estimates of probable reserves, possible reserves, and resource potential, are by their nature more speculative than estimates of proved reserves. Accordingly, estimates other than proved reserves are subject to substantially greater risk of being actually realized. Investors are urged to consider closely the disclosure in our Form 10-K available at www.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, 2017 and the Forms 10-Q for the quarter ended December 31, 2017, March 31, 2018, and June 30, 2018. 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.

Developing our large, high quality acreage position in Marcellus & Utica shales NFG: A Diversified, Integrated Natural Gas Company Providing safe, reliable and affordable service to customers in WNY and NW Pa. Upstream E&P Midstream Gathering Pipeline & Storage Downstream Utility Energy Marketing Expanding and modernizing pipeline infrastructure to provide access to Appalachian supplies 785,000 Net acres in Appalachia ~445 MMcf/day Net Appalachian natural gas production $1.5 Billion Investments since 2010 4.1 MMDth Daily interstate pipeline capacity under contract 743,600 Utility Customers 133 Bcf Utility system natural gas throughput in FY17 California: Stable cash flow & oil production

Why National Fuel? Unique Integration and Diversified Asset Mix Serves as Foundation for Growth Strategy Long-term, Disciplined Approach to Capital Allocation and Returns 3 Large, contiguous footprint in Appalachia drives peer leading low-cost development Fee-ownership (no royalty) on majority of acreage is a significant competitive advantage Stacked Marcellus and Utica development / reutilization of gathering infrastructure improves drilling economics and enhances consolidated returns Positioned to expand / modernize pipeline systems to accommodate regional supply growth Long-term capital plans designed to grow earnings for each business segment, live within cash flows and achieve value-added returns on capital employed Production and gathering growth underpinned by long-term sales contracts and hedges Strong balance sheet provides financial flexibility 48-year track record of growing the dividend Geographic and operational integration lowers costs and drives financial efficiencies Significant base of stable, regulated earnings and cash flows supports dividend and helps to lower our cost of capital 100% ownership of midstream assets (no MLP structure) preserves capital flexibility and better aligns corporate strategic goals Opportunity for Considerable Upstream and Midstream Growth in Appalachia 2 1 Strategy For Creating Long-term, Sustainable Shareholder Value

Benefits of Integration Unique Geographic and Operational Integration Drives Synergies that Maximize Shareholder Value Large Appalachian footprint with considerable opportunity for growth Operational scale Lower cost of capital Lower operating costs More efficient capital investment More competitive pipeline infrastructure projects Higher returns on investment Strong balance sheet Growing, stable dividend Utility and Pipeline & Storage Operational Efficiencies Upstream and Midstream Strategic Development Commercial Relationships Financial Efficiencies Rate-regulated entities reduce operating expenses by sharing common: Management Engineering Field labor Facilities Back office Gas dispatch center Warehouse IT systems Vehicles Tools & equipment Investment grade credit rating Shared borrowing capacity Consolidated income tax return Balanced earnings and diversified cash flows support dividend Benefits of NFG Integrated Model Utility and Energy Marketing segments are significant Pipeline & Storage customers: 29% of contracted firm transport capacity 43% of contracted firm storage capacity Coordinated development in Appalachia drives long-term growth and enhances consolidated returns: Co-development of Marcellus and Utica Installing just-in-time gathering infrastructure Expanding pipeline transmission infrastructure to reach demand markets

Adjusted Operating Results ($ per share)(1) Diversified, Balanced Earnings and Cash Flows A reconciliation of Adjusted Operating Results to Earnings per Share, by segment, as presented on the Consolidated Statement of Income and Earnings Reinvested in the Business is included at the end of this presentation 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 Adjusted EBITDA ($ millions)(2) Rate Regulated 40-45% $727 Rate Regulated ~45% Decrease in EBITDA primarily due to roll off of favorable hedges

Near-Term Growth Strategy Exploration & Production Gathering Pipeline and Storage Utility 3-rig program designed to grow Marcellus and Utica production and gathering throughput at a 15-20% CAGR over next 5 years Utilize significant existing gathering infrastructure to support further WDA development and increase returns Maintain focus on living within cash flows Continue to invest in pipeline replacement and modernization: Improve system safety and reliability Seek timely recovery through tracker mechanism in New York Maintain focus on O&M spending levels Pursue and execute opportunities for system expansion: FM100 Project Empire North Project Line N Expansions Northern Access Continue to invest in modernization of Supply Corp. system, which will result in rate base growth

Disciplined, Flexible Capital Allocation (2) Capital Expenditure totals include Energy Marketing, and Corporate and All Other Segments. A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation. FY16, FY17, and FY18 guidance reflects the netting of $157 million, $7 million, and $17 million, respectively, of up-front proceeds received from joint development partner for working interest in joint development wells. Capital Expenditures by Segment ($ millions)(1)

Maintaining Strong Balance Sheet & Liquidity Total Debt 52% $4.0 Billion Total Capitalization as of June 30, 2018 Net Debt / Adjusted EBITDA(1) Capitalization Debt Maturity Profile ($MM) Liquidity Committed Credit Facilities Short-term Debt Outstanding Available Short-term Credit Facilities Cash Balance at 6/30/18 Total Liquidity at 6/30/18 $ 750 MM 0 MM 750 MM 313 MM $ 1,063 MM Net Debt is net of cash and temporary cash investments. Reconciliations of Net Debt and Adjusted EBITDA to Net Income are included at the end of this presentation.

Dividend Track Record $2.9 Billion Dividend payments since 1970 $1.70 per share 48 Years Consecutive Dividend Increases $0.19 per share 116 Years Consecutive Payments 3.2% yield(1) As of August 1, 2018.

Financial Highlights Q3 Fiscal 2018

Net Oil and Gas Production Third Quarter Fiscal 2018 Results and Drivers Operating Results ($/share)(1) Operating results of $0.69 for Q3 Fiscal 2017 and $0.73 for Q3 Fiscal 2018 includes operating results of Energy Marketing and Corporate & All Other segments. Realized price after hedging. Oil and Gas Pricing(2) Natural Gas ($/Mcfe) Crude Oil ($/Bbl) Oil Prices Natural Gas Prices Gathering Volume (Bcf) Seneca Gross Production Drivers Natural Gas Production Oil Production Crude Oil (Mbbl) Natural Gas (Bcf)

Impact of Federal Tax Reform Non-Rate Regulated Segments Rate Regulated Segments Exploration & Production and Gathering Positive ongoing earnings impact expected from reduction in federal income tax rate from 35% to 21% (blended 24.5% in FY 2018) Remeasurement of deferred income taxes resulted in $111.0 million earnings benefit recorded as of the close of Q3 FY 2018 Pipeline & Storage Supply Corp – FERC final rule concerning Federal tax reform issued on 7/18/18; Supply expected to file form 501-G in December 2018; any adjustment to rates expected to be prospective – no refund provision recorded Empire – Filed Section 4 Rate Case on 6/29/18; new transportation rates expected to be effective 1/1/19 Both pipelines recorded remeasurement of deferred income tax balance sheet amounts as a regulatory liability Utility NY – Distribution filed petition on 6/4/18 seeking authorization to implement customer refund program on 10/1/18 (remains pending); refund estimated at $7.8 million in connection with FY18 PA – PUC issued Temporary Rates Order on 5/17/18 requiring 2.2% refund of customer rates as of 7/1/18 Recorded refund provision of approximately $11.8 million (~$8.7M after-tax) as of the close of Q3 FY18 Recorded remeasurement of deferred income tax balance sheet amounts as regulatory liability NFG Consolidated Higher earnings / Lower effective tax rate: ~25% in FY18 and FY19+ Impact on cash flow is expected to be positive over long-term

Earnings Guidance FY2018 Earnings Guidance(1) Non-regulated Businesses Exploration & Production Gathering $3.30 to $3.40 /share $3.30 to $3.60 /share FY2019 Earnings Guidance Seneca Net Production: 210 to 230 Bcfe Gathering Revenues: $130-140 million Natural Gas: ~$2.35 /Mcf(2) (vs. $2.55 /Mcf FYTD 2018) Crude Oil: ~$60 /Bbl(3) (vs. $58.96/ Bbl FYTD 2018) Key Guidance Drivers Excludes the $107.0 million, or $1.24 per share, reduction in tax expense due to the remeasurement of deferred taxes resulting from the 2017 Tax Reform Act. See non-GAAP disclosure on slide 59 of this presentation. Assumes NYMEX natural gas pricing of $2.75/MMBtu and basin spot pricing of $2.40/MMBtu (winter) and $2.00 /MMBtu (summer) for FY19, and reflects the impact of existing financial hedge, firm sales and firm transportation contracts. Assumes NYMEX (WTI) oil pricing of $65.00/Bbl and California-MWSS pricing differentials of 100% to WTI for FY19, and reflects impact of existing financial hedge contracts. Production & Gathering Throughput Realized natural gas prices (after-hedge) Utility Operating Income Regulated Businesses Pipeline & Storage Utility Guidance assumes normal weather; modestly higher gross margin expected to be offset by cost inflation ~$285 million in revenues (expected decrease primarily due to expiration of contract on Empire system) Pipeline & Storage Revenues Tax Reform Realized oil prices (after-hedge) Lower effective tax rate Effective tax rate ~25% (federal rate 21%)

Exploration & Production and Gathering Overview Seneca Resources Company, LLC ~ National Fuel Gas Midstream Company, LLC

Proved Reserves 225% Reserve Replacement Rate (adjusted for revisions) Seneca Drill-bit F&D = $0.60/Mcfe(1) Appalachia Drill-bit F&D = $0.51/Mcfe(1) Seneca “Drill-bit” finding and development (“F&D”) costs exclude the impact of reserve revisions. Total Proved Reserves (Bcfe) Fiscal 2017 Proved Reserves Stats 3-Year Average F&D Cost ($/Mcfe) E&P and Gathering

Growing Production within Disciplined Capital Program E&P Net Production (Bcfe) E&P Net Capital Expenditures(1) ($ millions) 3-rig drilling program, with new rig in the WDA focused on redevelopment of Clermont-Rich Valley acreage for Utica Target 15-20%+ production CAGR over next 5 years Resumed development on prolific Marcellus acreage in Lycoming County, Pa. (new pad brought to sales in Q2 2018) Returned to developing 100% NRI wells in the WDA (last JDA pad brought on-line in Q2 FY18) Continue Utica development in WDA and EDA in FY18 Continue to 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 Minimal capital investment to generate flat to modest growth over next 3 years (excluding sale of Sespe assets) Development focus on new farm-in acreage in Midway Sunset Low cost structure helps generate significant positive cash flows at $65+ /bbl A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation. FY16, FY17, and FY18 guidance reflects the netting of $157 million, $7 million and $17 million, respectively, of up-front proceeds received from joint development partner for working interest in joint development wells. E&P and Gathering

Significant Appalachian Acreage Position Current gross production: ~267 MMcf/d Mostly leased (16-18% royalty) with no significant near-term lease expirations ~100 remaining Marcellus & Utica locations economic under $1.80/Mcf Additional Utica & Geneseo potential across position Eastern Development Area (EDA) EDA - 70,000 Acres Western Development Area (WDA) WDA - 715,000 Acres Current gross production: ~322 MMcf/d Large inventory of high quality Marcellus & Utica acreage economic at ~$2.00/Mcf Royalty free mineral ownership enhances well economics Highly contiguous nature drives cost and operational efficiencies Fee Acreage Lease Acreage E&P and Gathering

Western Development Area Marcellus Core Acreage vs. Utica Appraisal Trend(1) The Utica Shale lies approximately 5,000 feet beneath Seneca’s WDA Marcellus acreage. Appraisal program currently in progress. Additional tests are planned. Prior Marcellus delineation tests helped define the prospective limits of the Marcellus core acreage; planned testing in the Utica expected to do the same. Internal Rate of Return (IRR) is pre-tax and includes estimated well costs under current cost structure, LOE, and anticipated Gathering tariffs. Area of Planned Re-Development 125 Utica Locations on Existing Marcellus Pads ? Key Utica tests Past Marcellus delineation tests Utica Trend (currently evaluating) Marcellus Core Acreage Significant multi-zone drilling inventory economic at ~$2.00 /Mcf Marcellus Shale: 600+ well locations remaining / 200,000 acres Utica Shale: 500+ well locations / evaluating extent of prospective acreage (2) Fee acreage / existing infrastructure enhances economics No royalty or lease expirations on most acreage Expected Utica development will utilize existing upstream and midstream infrastructure to maximize ROI Highly contiguous position drives best in class well costs Multi-well pad drilling with laterals approaching 10,000 ft. Water management operations keep water costs low Long-term firm contracts support growth and returns Boone Mountain Utica Test Well 2.3 Bcf /1,000ft Rich Valley Utica Test Well 2.3 Bcf /1,000ft E&P and Gathering Utica “Type-Curve” Well 1.8 Bcf /1,000ft EUR Well Cost IRR(3) % Break-even Bcf/1000' $M/1000' $2.25 15% IRR WDA - Utica 1.7 $916 0.23 $1.95 WDA - Marcellus 1.1000000000000001 $627 0.21 $2.0099999999999998

WDA Utica Appraisal Results and Initial Type Curve Tested / producing from 10 Utica wells in WDA-CRV Higher pressure significantly enhances well productivity (Utica ~5,000’ deeper than Marcellus) Drawdown management is critical: restricted drawdown improves well EURs Early production declines much shallower vs. Marcellus WDA Utica Appraisal Update WDA Utica Test Well Results   "Type Curve" Well Rich Valley Well Boone Mtn. Well Pad D09-NF-A C09-D G15-A Well 196HU 214HU 101HU Lateral Length 6,300 5,530 4,420 Est. EUR /1,000 ft 1.8 Bcf 2.3 Bcf 2.3 Bcf Production Results (MMcf/1,000ft per day): 7-day IP 1.0 1.5 1.5 30-day IP 1.0 1.4 1.5 60-day IP 0.9 1.3 1.4 90-day IP 0.9 1.3 1.3 Initial WDA Utica type curve based on production results and reservoir expectations from the first 5 appraisal wells in the WDA-CRV area. E&P and Gathering

Transitioning to Utica Development in CRV WDA-CRV Marcellus (Depth ~7,000 feet) WDA-CRV Utica (Depth ~12,000 feet) Average CRV Marcellus Production: 267 Mcf/d Rem. Avg. EUR 1.0-1.1 Bcf / 1,000 lat ft. Rem. Avg. Well Costs = $627/lat ft. 125+ locations on existing Marcellus pads Est. EURs 1.7 Bcf / 1,000 lat ft. Est. Development Well Costs = $916/lat ft. WDA Utica Transition Plan Finish Marcellus Pads in Development Drill 20 / complete 28 Marcellus wells (100% Seneca) Completed and producing all 75 joint development wells Optimize Utica D&C design Drill additional Utica optimization wells off Marcellus pads (currently 10 producing wells) Optimization to include: Well spacing Completion design / stage spacing Landing zone targets Transition to full Utica development in FY19 Continue shift toward multi-well Utica pads Tailor development plan to reuse existing pad, water and gathering infrastructure WDA Utica Development Will Utilize Existing Pad, Water, and Gathering Infrastructure to Drive Economics E&P and Gathering Rich Valley Utica Test Utica “Type-Curve” UPDATE Existing Line Leased Seneca Fee Producing FY18 Producer Development

Integrated Development – WDA Gathering System Current System In-Service ~70 miles of pipe / 36,220 HP of compression Current Capacity: 470 MMcf per day Interconnects with TGP 300 Total Investment to Date: $292 million Future Build-Out FY 2018 CapEx: $15MM - $20MM Modest gathering pipeline and compression investment required to support Seneca’s transition to Utica development and increased rig count 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 Clermont Gathering System Map E&P and Gathering

Leveraging Existing Gathering Infrastructure Enhances Consolidated Returns WDA Development Consolidated Economics WDA Well Costs(1) WDA Consolidated Economics The addition of a 3rd rig will be incremental to returns, while also providing economies of scale and significant operational flexibility E&P and Gathering WDA Marcellus well costs reflect drilling, completion and gathering costs for the 166 wells drilled and completed to date. WDA Utica well costs reflect expected drilling, completion and gathering costs for the 125 well locations in area of redevelopment. Internal Rate of Return for Seneca WDA includes estimated well costs under current cost structure, and anticipated LOE and Gathering costs. Internal Rate of Return for Seneca WDA and Gathering includes expected gathering capital expenditures through FY 2022, well costs under current cost structure, and non-gathering LOE. Total cost per well expected to marginally increase WDA EURs At a $2.25 netback price, consolidated Seneca WDA and Gathering IRR is approximately 32%, an uplift of ~11% over standalone Seneca WDA economics(2) 10% + IRR Uplift Expected

WDA Firm Transportation and Sales Capacity Seneca’s net production will utilize more of its gross capacity through time as JDA production declines Will continue to layer-in firm sales deals of short and longer duration on TGP 300 to reduce spot exposure WDA spot realizations track TGP Station 313 pricing, typically 10¢ - 30¢ better than TGP Marcellus Zone 4 Favorable resolution to Northern Access would provide additional capacity WDA Exit Capacity Supports Long-term Production Growth and Protects Consolidated Returns WDA Gas Marketing Strategy WDA Contracted Firm Transport and Sales Volumes (gross) Seneca net production trend E&P and Gathering Niagara Expansion Project (TGP and NFG) FT Capacity: 158,000 Dth/d @ $0.67/Dth Firm Sales: NYMEX & DAWN WDA - TGP 300 Firm Sales Seneca net production to utilize more firm capacity as JDA volumes decline Transco Project Transco Zone 6 Markets 300,000 Dth/d(1) Will layer-in firm sales to minimize spot exposure WDA Contracted Firm Transport and Sales Volumes (gross) Seneca net production trend (1) Portion of Transco Project capacity will likely be utilized by EDA Lycoming County production.

Eastern Development Area EDA Acreage – 70,000 Acres EDA Highlights 3 1 2 DCNR Tract 007 (Tioga Co., Pa) 1 Utica and 1 Marcellus producing well Utica 30-day IP = 15.8 MMcf/d Utica development resumed in third quarter fiscal 2018 47 remaining Utica locations economic at ~$1.75 /Mcf Covington & DCNR Tract 595 (Tioga Co., Pa.) Gross daily production: ~97 MMcf/d Marcellus locations fully developed Opportunity for future Utica appraisal DCNR Tract 100 & Gamble (Lycoming Co., Pa.) Gross daily production: ~170 MMcf/d(1) 49 remaining Marcellus locations economic at ~$1.50 /Mcf Atlantic Sunrise capacity (189 MDth/d) by close of fiscal 2018 Geneseo shale expected to provide 100-120 additional locations 3 E&P and Gathering (1) Production from two additional Gamble pads (~80-100 MMcf/d) is expected to come online concurrent with Atlantic Sunrise capacity.

EDA Marcellus: Lycoming County Development Prolific Marcellus acreage with peer leading well results Average Marcellus IP rate of 17.0 MMcf/d 49 remaining Marcellus locations economic at ~$1.50 /Mcf Near-term development focused on filling Atlantic Sunrise capacity now forecasted to be available by end of fiscal 2018 Marcellus Development in Lycoming County has Resumed in Anticipation of Atlantic Sunrise Includes physical fixed price and NYMEX-based firm sales contracts that do not carry any additional transportation costs. E&P and Gathering Transco Firm Sales(1) Atlantic Sunrise Delay Existing Line Leased Seneca Fee Producing FY18 Producer Development

EDA Utica: Tioga County Development Utica Development in Tioga County – Tract 007 Development Resumed in Q3 FY18 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: 47 locations economic at ~$1.75 /Mcf Targeting to grow production by 100 to 150 MDth/d by FY20 Expected Development Costs: $967 per lateral ft. Gathering Infrastructure: NFG Midstream Wellsboro Modest build-out required to connect to TGP 300 Sales/Takeaway Strategy: Layer-in firm sales with shippers holding capacity on TGP 300 Includes physical fixed price and NYMEX-based firm sales contracts that do not carry any additional transportation costs. Tract 007 Utica Appraisal Well Results vs. Industry E&P and Gathering Northeast Supply Diversification Project FT Capacity: 50,000 Dth/d @ $0.50/Dth Firm Sales: NYMEX and DAWN EDA - TGP 300 Firm Sales(1)

Integrated Development – EDA Gathering Systems Total Investment (to date): $45 million FY 2018 Capital Expenditures: $13MM - $15MM 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): $195 million FY 2018 Capital Expenditures: $20 MM - $30 MM 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 Wellsboro Gathering System Total Investment (to date): $7 million FY 2018 Capital Expenditures: $3MM - $8MM Capacity: 200,000 Dth per day (Interconnect w/ TGP 300) Production Source: Seneca Resources – Tioga Co. (DCNR Tract 007) E&P and Gathering

Long-term Contracts Supporting Appalachian Growth 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. Seneca continues 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 new capacity out of the basin E&P and Gathering FY 2019 FY 2020 15% - 20% Production CAGR FY 2021 FY 2022 Northeast Supply Diversification 50,000 Dth/d Niagara Expansion (TGP & NFG) Delivery Markets: Canada-Dawn & TETCO 158,000 Dth/d Atlantic Sunrise (Transco) Delivery Markets: Mid-Atlantic & Southeast U.S. 189,405 Dth/d In-Basin Firm Sales Contracts(1) Transco Project Transco Zone 6 Markets ~300,000 Dth/d Seneca Appalachia Natural Gas Marketing Gross Firm Contract Volumes (Mdth/day)

Near-term Firm Sales Provide Market & Price Certainty Net Contracted Firm Sales Volumes (Dth per day) Contracted Index Price Differentials ($ per Dth)(1) Values shown represent the weighted average fixed price or contracted fixed differential relative to NYMEX (netback price) less any associated transportation costs. Actual Daily Net Production 562,100 597,200 601,800 630,400 623,600 Gross Firm Sales Volumes (Dth/d) Actual Daily Net Production E&P and Gathering

California Oil Stable Oil Production | Minimal Capital Investment | Steady Free Cash Flow 1 2 3 4 5 Location Formation Production Method FY17 Daily Production (net Boe/d) 1 East Coalinga Temblor Primary 570 2 North Lost Hills Tulare & Etchegoin Primary/ Steam flood 933 3 South Lost Hills Monterey Shale Primary 1,468 4 North Midway Sunset Tulare & Potter Steam flood 3,026 5 South Midway Sunset Antelope Steam flood 1,811 TOTAL CALIFORNIA NET PRODUCTION(1) 7,808 Boe/d E&P and Gathering (1) California net production excludes production from Sespe field, which was divested on May 1, 2018 and totaled 1,055 Boe/d in Fiscal 2017.

California Capital Expenditures vs. Production West Division Average Net Daily Production (BOE/D) West Division Annual Capital Expenditures ($MM)(1) Guidance Guidance Seneca West Division capital expenditures includes Seneca corporate and eliminations. Sale closed on 5/1/18. The impact for the remaining 3 months of fiscal 2018 is approximately 83 mboe, or 0.5 Bcfe. E&P and Gathering

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 Midway-Sunset Midway-Sunset Pioneer South MWSS Acreage North MWSS Acreage Sec. 17N North South South North MWSS Project IRRs at $65 /Bbl(1) Reflects pre-tax IRRs at a $65/Bbl WTI. E&P and Gathering Midway Sunset Economics

Fiscal 2018 Production 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 financial hedge. 34 Bcf locked-in realizing net ~$2.40/Mcf (1) 5 Bcf of additional basis protection Spot production assumed to be sold at ~$2.00/Mmbtu for remainder of year 39 Bcf Protected by Firm Sales for Remainder of Year 87% of oil production hedged at $54.99 /Bbl E&P and Gathering

Fiscal 2019 Production 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 financial hedge. 140 Bcf locked-in realizing net ~$2.44/Mcf (1) 36 Bcf of additional basis protection Spot production assumed to be sold at ~$2.40/Mmbtu (winter) and ~$2.00 (summer) 176 Bcf of Appalachian Production Protected by Firm Sales 72% of oil production hedged at $57.57 /Bbl E&P and Gathering

Strong Hedge Book 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. Reflects percentage of projected production for the remaining 3 months of FY18 hedged at Seneca’s production guidance of 175-180 Bcfe. Reflects percentage of projected production for FY19 hedged at the midpoint of the production guidance range. Seneca’s remaining FY18 production reflects guidance of 175-180 Bcfe less actual production for Q1, Q2 and Q3 FY 2018. Crude Oil Swap Contracts (Thousands Bbls) (1) FY 18 Nat Gas 78% Hedged(2) FY 2018 Remaining Production(4) FY 2018 Remaining Production(4) E&P and Gathering FY 19 Nat Gas 68% Hedged(3)

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 Seneca DD&A Rate $/Mcfe Appalachia LOE & Gathering $/Mcfe California LOE $/Boe Total Seneca Cash OpEx $/Mcfe (1) (2) (2) The total of the two LOE components represents the midpoint of the LOE guidance range of $0.90 to $0.95 for fiscal 2018. The total of the two LOE components represents the midpoint of the LOE guidance range of $0.85 to $0.90 for fiscal 2019. E&P and Gathering

Pipeline and Storage Overview National Fuel Gas Supply Corporation ~ Empire Pipeline, Inc.

Pipeline & Storage Segment Overview As of September 30, 2017 as disclosed in the Company’s fiscal 2017 form 10-K. As of December 31, 2017 calculated from National Fuel Gas Supply Corporation’s and Empire Pipeline, Inc.’s 2017 FERC Form-2 reports, respectively. Empire Pipeline, Inc. National Fuel Gas Supply Corporation Empire Pipeline Supply Corp. Contracted Capacity(1): Firm Transportation: 3,157 MDth per day Firm Storage: 68,042 Mdth (fully subscribed) Rate Base(2): ~$820 million FERC Rate Proceeding Status: Rate case settlement extension approved Nov. ‘15 Required to file a rate case by 12/31/19 Contracted Capacity(1): Firm Transportation: 954 MDth per day Firm Storage: 3,753 Mdth (fully subscribed) Rate Base(2): ~$249 million FERC Rate Proceeding Status: Section 4 Rate Proceeding commenced 6/29/18 New transportation rates expected to go into effect on 1/1/19 (subject to refund) Pipeline & Storage

FM100 Project Provides Consolidated Benefit 300,000 Dth/d of new transportation capacity from WDA and EDA acreage positions to premium markets New Transco pipeline capacity: ~300,000 Dth/day Rate: expected to be competitive with other expansion project rates in Seneca’s current transportation portfolio Delivery Point(s): Transco Zone 6 interconnections Seneca Lease to Transco of new capacity: ~300,000 Dth/day Est. Annual Revenues: ~$32 million Est. capital cost: $280 million(1) Supply Corp. Project expected to provide long term earnings uplift to Seneca, Supply Corp. and Gathering Gathering (1) Includes expansion and modernization portions of the project. All incremental Seneca volumes will flow through NFG gathering facilities Pipeline & Storage

FM100 Project Target In-Service: late calendar year 2021 Facilities (all in Pennsylvania): Approximately 30 miles of new pipeline 2 new compressor Stations (totaling approximately 34,000 HP) 2 new interconnection stations and modification of existing meter and regulation station Abandonment of approximately 45 miles of existing pipeline and compressor station Regulatory Process: Pre-filing application submitted to FERC in 2017 for original modernization project FERC 7(b) / 7(c) filing expected summer 2019 Expansion component of pending FM100 Project will provide significant incremental revenues for Supply Pipeline & Storage

Empire North Project Target In-Service: Second half of fiscal 2020 Est. Capital Cost: $145 million Est. Annual Revenues: $25 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: Fully subscribed (205,000 Dth/day) Major Facilities: 2 new compressor stations in NY (1) & Pa. (1) No new pipeline construction Regulatory Process: FERC 7(c) application filed on 2/16/18 Pipeline & Storage Fully Subscribed Project will Provide 205,000 Dth/day of Incremental Firm Transportation

Northern Access Project Status Capacity: 490,000 Dth/day Total Expected Cost: ~$500MM ($75.5MM spent to date, with minimal remaining commitments) Regulatory Status: FERC issued 7(c) certificate on February 3, 2017 Legal Actions Remain Pending: US Court of Appeals for the 2nd Circuit: On April 21, 2017, NFG filed appeal of NY DEC notice of denial of the Clean Water Act Section 401 Water Quality Certification (WQC) Decision from the Court is pending Federal Energy Regulatory Commission: On March 3, 2017, NFG filed petition for rehearing with FERC seeking waiver of NY DEC Clean Water Act Section 401 WQC and preemption on state level permits Decision from FERC is pending National Fuel Remains Committed to Building the Northern Access Project Pipeline & Storage To Dawn East Aurora NE US (TGP 200)

Continued Expansion of the NFG Supply System Line N Expansion Opportunities Line N to Monaca Project Project: Firm transportation service to a new ethylene cracker facility being built by Shell Chemical Appalachia, LLC Target In-Service: as early as June 2019 Est. Capital Cost: $20 million Contracted Capacity: 133,000 Dth/day Additional Line N Expansion Opportunity (Supply OS #221) Project: New firm transportation service for on-system demand Open Season Capacity: Awarded 165,000 to foundation shipper. Precedent agreement in negotiations. Pipeline & Storage

Pipeline & Storage Customer Mix 4.1 MMDth/d Contracted as of 11/1/2017. Customer Transportation by Shipper Type(1) Affiliated Customer Mix (Contracted Capacity) Firm Transport Pipeline & Storage

Utility Overview National Fuel Gas Distribution Corporation

New York & Pennsylvania Service Territories New York Total Customers(1): 530,400 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) System Modernization Tracker Pennsylvania Total Customers(1): 213,200 ROE: Black Box Settlement (2007) Rate Mechanisms: Low Income Rates Merchant Function Charge As of September 30, 2017. Utility

New York Rate Case Outcome Rate Order Summary: Revenue Requirement:$5.9 million Rate Base:$704 million Allowed Return on Equity (ROE):8.7% Capital Structure:42.9% equity Other notable items: New rates became 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 System modernization tracker for Leak Prone Pipe (LPP) Earnings sharing starting 4/1/18 (50/50 sharing starts at earnings in excess of 9.2%) 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. Utility

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

Accelerating Pipeline Replacement & Modernization NY 9,723 miles PA* 4,832 miles * No Cast Iron Mains in Pa.* Miles of Utility Main Pipeline Replaced(1) Utility Mains by Material Utility (1) As reported to the Department of Transportation on calendar year basis.

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

Appendix

Hedge Positions and Prices Fixed price physical sales exclude joint development partner’s share of fixed price contract WDA volumes as specified under the joint development agreement. (1) Appendix Natural Gas Volumes in thousand MMBtu; Prices in $/MMBtu Fiscal 2018 (last 3 mos.) Fiscal 2019 Fiscal 2020 Fiscal 2021 Fiscal 2022 Volume Avg.Price Volume Avg.Price Volume Avg.Price Volume Avg.Price Volume Avg.Price NYMEX Swaps 12260 $3.11 80980 $2.94 18640 $3.04 4840 $3.01 - - Dawn Swaps 1800 $3 7200 $3 7200 $3 600 $3 - - Fixed Price Physical 21037.88 $2.62 56149.146000000001 $2.64 41833.351999999999 $2.2999999999999998 41608.372000000003 $2.2200000000000002 40589.264999999999 $2.23 Total 35097.880000000005 $2.62 144329.14600000001 $2.82 67673.351999999999 $2.58 47048.372000000003 $2.31 40589.264999999999 $2.23 Crude Oil Volumes & Prices in Bbl Fiscal 2018 (last 3 mos.) Fiscal 2019 Fiscal 2020 Fiscal 2021 Fiscal 2022 Volume Avg. Volume Avg. Volume Avg. Volume Avg. Volume Avg. Price Price Price Price Price Brent Swaps 114000 $63.55 744000 $63.52 732000 $61.48 444000 $62.59 300000 $60.07 NYMEX Swaps 420000 $52.67 1068000 $53.42 324000 $50.52 156000 $51 156000 $51 Total 534000 $54.99 1812000 $57.57 1056000 $58.12 600000 $59.58 456000 $56.97

Appalachia Drilling Program Economics Net realized price reflects either (a) price received at the gathering system interconnect 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. Large Inventory of Marcellus and Utica Location Economic Below $2.00/MMBtu(1) Appendix Prospect Reservoir Locations Remainingto Be Drilled Completed Lateral Length (ft) EUR / 1000' (Bcf) Well Cost$M/1,000 ft Internal Rate of Return % (2) Realized Price(1) Required for 15% IRR Anticipated DeliveryMarkets EUR / 1000' (Bcf) $2.50Realized $2.25Realized $2.00Realized EDA Tract 100 & GambleLycoming Co. Marcellus 49 4900 2.5 $1,002 0.82 0.64 0.47 $1.5 Transco Leidy &Atlantic Sunrise Southeast US(NYMEX+) DCNR 007Tioga Co. Utica 47 8300 2 $967 0.59 0.44 0.28000000000000003 $1.75 TGP 300 WDA Clermont Rich Valley Utica 125 - 500+ 8000 1.7 $916 0.28999999999999998 0.23 0.16 $1.95 TGP 300 &Niagara Expansion Canada (Dawn) Core Areas Marcellus 600+ 8500 1.0 to 1.1 $627 0.28000000000000003 0.21 0.15 $2.0099999999999998 FY15Q3:

Firm Transportation Commitments Volume (Dth/d) Production Source Delivery Market Demand Charges ($/Dth) Gas Marketing Strategy Northeast Supply Diversification Project Tennessee Gas Pipeline Niagara Expansion TGP & NFG Northern Access NFG – Supply & Empire Delayed 50,000 158,000 350,000 EDA -Tioga County Covington & Tract 595 WDA – Clermont/ Rich Valley WDA – Clermont/ Rich Valley 12,000 140,000 Canada (Dawn) Canada (Dawn) TETCO (SE Pa.) Canada (Dawn) TGP 200 (NY) $0.50 (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 Atlantic Sunrise WMB - Transco In-service: end of FY18 189,405 EDA - Lycoming County Tract 100 & Gamble Mid-Atlantic/ Southeast $0.73 (3rd party) Firm Sales Contracts 189,405 Dth/d NYMEX+ First 5 years Firm Sales Contracts At Dawn When Project Goes In-Service Transco Expansion / FM100 Project WMB – Transco; NFG - Supply In-service: ~ late 2021 ~300,000 WDA – Clermont/ Rich Valley and EDA - Lycoming County Transco Zone 6 Expected to be competitive with other expansion project rates in Seneca’s transportation portfolio(1) Seneca to pursue Firm Sales Contracts as project development progresses (1) Significant portion of transportation rate paid by Seneca to Transco is expected to flow back to NFG via a lease between Transco and Supply Corp. 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. Management defines Adjusted Operating Results as reported GAAP earnings before items impacting comparability. The Company’s fiscal 2018 earnings guidance does not include the impact of the remeasurement of deferred income taxes resulting from the 2017 Tax Reform Act, which reduced the Company’s consolidated income tax expense and benefited earnings for the nine months ended June 30, 2018 by $107.0 million, or $1.24 per share. While the Company expects to record additional adjustments to its deferred income taxes as a result of the 2017 Tax Reform Act during the remaining three months of fiscal 2018, the amounts of these and other potential adjustments are not reasonably determinable at this time. The final determination of the impact of the income tax effects of certain items will require additional analysis and further interpretation of the 2017 Tax Reform Act from yet to be issued U.S. Treasury regulations, state income tax guidance, federal and state regulatory guidance, technical corrections, and the filing of the Company’s fiscal 2017 federal consolidated tax return. Some or all of these factors may be significant. Because the amounts of final adjustments are not reasonably determinable at this time, the Company is unable to provide earnings guidance other than on a non-GAAP basis that excludes the impact of the remeasurement of deferred income taxes and other potential adjustments. Management defines Adjusted EBITDA as reported GAAP earnings before the following items: interest expense, income taxes, depreciation, depletion and amortization, interest and other income, impairments, and other items reflected in operating income that impact comparability. Appendix

Non-GAAP Reconciliations – Adjusted EBITDA Appendix

Non-GAAP Reconciliations – Adjusted EBITDA, by Segment Appendix

Non-GAAP Reconciliations – Adjusted Operating Results AppendixThree Months EndedNine Months EndedJune 30,June 30,(in thousands except per share amounts)2018201720182017Reported GAAP Earnings$63,025$59,714$353,527$237,906Items impacting comparabilityRemeasurement of deferred income taxesunder 2017 Tax Reform——(107,000)—Adjusted Operating Results$95,847$59,714$183,501$237,906Reported GAAP Earnings per share$0.73$0.69$4.09$2.77Items impacting comparabilityRemeasurement of deferred income taxesunder 2017 Tax Reform——(1.24)—Adjusted Operating Results per share$0.73$0.69$2.85$2.77

Non-GAAP Reconciliations – Capital Expenditures Appendix

Non-GAAP Reconciliations – E&P Operating Expenses Appendix