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): November 2, 2017

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 2.02	Results of Operations and Financial Condition.	
On November 2, 2017, 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; 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 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; economic disruptions or uninsured losses resulting from major accidents, fires, severe weather, natural disasters, terrorist activities, acts of war, cyber attacks or pest infestation; significant differences between the Company’s projected and actual capital expenditures and operating expenses; or increasing costs of insurance, changes in coverage and the ability to obtain insurance. 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 November 2017	

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/ Paula M. Ciprich	
	 	Paula M. Ciprich	
	 	Senior Vice President, General Counsel & Secretary	
Dated: November 2, 2017

Investor Presentation Q4 Fiscal 2017 Update November 2, 2017 Exhibit 99

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

NFG: A Diversified, Integrated Natural Gas Company Providing significant base of stable, regulated earnings and cash flows 743,500 Utility customer accounts in NY & PA For the trailing twelve months ended September 30, 2017. A reconciliation of Adjusted EBITDA to Net Income as presented on the Consolidated Statement of Income and Earnings Reinvested in the Business is included at the end of this presentation. Upstream E&P Midstream Gathering Pipeline & Storage Downstream Utility Energy Marketing Developing our large, high quality acreage position in Marcellus & Utica shales with a focus on returns 785,000 Net acres in Appalachia Expanding and modernizing pipeline infrastructure to provide access to Appalachian supplies $275 million1 Annual Adjusted EBITDA

Adjusted EBITDA by Segment ($ millions)(1) Balanced Earnings and Cash Flows A reconciliation of Adjusted EBITDA to Net Income as presented on the Consolidated Statement of Income and Earnings Reinvested in the Business is included at the end of this presentation.

Disciplined, Flexible Capital Allocation (2) A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation. FY 2016 and FY 2017 reflects the netting of $157 million and $7 million, respectively, of up-front proceeds received from joint development partner for working interest in joint development wells. FY 2018 guidance also reflects the netting of anticipated proceeds received from the joint development partner. Capital Expenditures by Segment ($ millions)(1)

Maintaining Strong Balance Sheet & Liquidity Total Debt 55% $3.8 Billion Total Capitalization as of September 30, 2017 Net Debt / Adjusted EBITDA(1) Capitalization(2) Debt Maturity Profile ($MM) (2) Liquidity Committed Credit Facilities Short-term Debt Outstanding Available Short-term Credit Facilities Cash Balance at 09/30/17 (3) Total Liquidity at 09/30/17 $ 750 MM $ 0 MM $ 750 MM $ 256 MM $ 1,006 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. Total debt and capitalization excludes $300MM current portion of long-term debt due in 2018 that was refinanced with $300MM of 10-yr notes issued in September 2017 and subsequently retired in October 2017. Cash balance at 9/30/17 excludes $300MM of cash proceeds received in September 2017 from long-term debt issuance that were used in October 2017 to pay down $300MM of maturing notes.

Committed to Growing the Dividend Annual Dividend Rate ($ /share) Consecutive Payments 115 Years Consecutive Increases 47 Years Current Dividend Rate $1.66 per Share Current Dividend Yield (1) 2.9% As of November 1, 2017. NFG’s Dividend Consistency

Fiscal 2017 Highlights Earnings Per Share Free Cash Flow(2) Dividend Production Proved Reserves Gathering Segment Earnings Pipeline & Storage Expansions Utility Safety Investments $3.30 per share Up from $3.09 per share (operating results) in FY16(1) $262 million Cash provided by operations meaningfully exceeded net cash invested in the business while growing production / earnings $1.66 per share Grew shareholder distribution for 47th consecutive year 173.5 Bcfe Up 8% vs. FY16; highest output in Company history 2.15 Tcfe Up 17% vs. FY16; replaced 225% of production $40.4 million Up 32% vs. FY16 on 20% increase in throughput +0.3 Bcf/d Executed foundation shipper agreements on Empire North and NFG Supply Corp. Line N expansion projects $64 million Utility segment capital expenditures on pipeline replacement and modernization P P P P P P P P A reconciliation of operating results to GAAP earnings is included at the end of this presentation. The Company defines free cash flow as the total cash provided by operating activities that exceeds total cash used in investing activities, as presented on the Company’s consolidated statement of cash flows. 8

Leveraging Our Unique Assets for Future Growth Exploration & Production Strategy Midstream Strategy Corporate Strategy Grow Marcellus and Utica production at a 10%+ CAGR over next 3 years WDA Development (1-rig program) Return to developing 100% NRI Seneca wells post-JDA in FY18 Optimize Utica D&C designs and transition to a Utica development program by end of FY18 EDA Development (1-rig program) Develop highly economic acreage in Lycoming County and prepare well inventory for Atlantic Sunrise capacity Commence Utica development in FY18 at Tract 007 (Tioga County) to add another 100 to 150 MMcf/d by FY20 Focus on earning economic returns while living within cash flows Maintain strong balance sheet to preserve financial flexibility Continue to grow our dividend Gathering: Earnings and returns will benefit from Seneca’s transition to Utica development Gathering system throughput and revenues will grow along with Seneca’s 10%+ production growth Minimal incremental investment required to accommodate Seneca’s Utica development Pipeline & Storage: Opportunities for system expansion and modernization Foundation shipper agreements in place for Empire North Project and new Line N expansion Need for system modernization will result in Pipeline & Storage rate base growth National Fuel Will Continue to Grow Integrated Businesses While We Sort Through Northern Access Delay

Upstream Overview Exploration & Production

Growing Production within Disciplined Capital Program E&P Net Production (Bcfe) E&P Net Capital Expenditures(1) ($ millions) 2-rig development program Target 10%+ production 3-year CAGR Resume development on prolific Marcellus acreage in Lycoming County, Pa. Return to developing 100% NRI wells in the WDA (last JDA pad expected on-line in 1H FY18) Transition to Utica development in WDA and EDA in FY18 Layer-in firm sales to reduce spot market risk and take advantage of attractive regional pricing Seneca’s Near-term Operational Plan Appalachia Natural Gas California Oil Flat to modest growth on minimal capital investment Development focus on new farm-in acreage in Midway Sunset Low cost structure helps generate significant FCF at $50/bbl FY16 and FY17 capital expenditures reflects the netting of $157 million and $7 million, respectively, of up-front proceeds received from joint development partner for working interest in joint development wells. FY18 guidance also reflects the netting of anticipated proceeds received from the joint development partner. Upstream

Proved Reserves 225% Reserve Replacement Rate (adjusted for revisions) Seneca Drill-bit F&D = $0.60/Mcfe(1) Appalachia Drill-bit F&D = $0.51/Mcfe(1) Seneca “Drill-bit” finding and development (“F&D”) costs exclude the impact of reserve revisions. Upstream Total Proved Reserves (Bcfe) Fiscal 2017 Proved Reserves Stats 3-Year Average F&D Cost ($/Mcfe) 12

Significant Appalachian Acreage Position Current gross production: ~250 MMcf/d Mostly leased (16-18% royalty) with no significant near-term lease expirations 100+ remaining Marcellus and Utica locations economic under $1.80/Mcf Additional Utica & Geneseo potential Near-term development tailored to fill capacity on Atlantic Sunrise in mid-2018 Eastern Development Area (EDA) EDA - 70,000 Acres Western Development Area (WDA) WDA - 715,000 Acres Current gross production: ~340 MMcf/d Large inventory of high quality Marcellus and Utica acreage economic under $2.00/Mcf Fee ownership – lack of royalty enhances economics Highly contiguous nature drives cost and operational efficiencies Fee Acreage Lease Acreage Upstream

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

WDA Utica Appraisal Results and Initial Type Curve Tested / producing from 8 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 Upstream WDA Utica Appraisal Update WDA Utica Test Well Results   "Type Curve" Well Best Well Pad D09-NF-A C09-D Well 196HU 214HU Lateral Length 6,300 5,530 Days on-line 325 days 160 days Est. EUR /1,000 ft 1.8 Bcf 2.1 Bcf Production Results (per day):   7-day IP 6.0 MMcf 8.1 MMcf 30-day IP 6.0 MMcf 7.7 MMcf 60-day IP 5.7 MMcf 7.3 MMcf 90-day IP 5.5 MMcf 7.2 MMcf Initial WDA-CRV Utica type curve based on production results and reservoir expectations from the first 5 appraisal wells in the WDA-CRV area. 15

Transitioning to Utica Development in CRV WDA-CRV Marcellus (Depth ~7,000 feet) Existing Line Leased Seneca Fee Producing FY18 Producer Development WDA-CRV Utica (Depth ~12,000 feet) Upstream 148 wells producing 315 Mcf/d Avg. EUR ~1.15 Bcf / 1,000 lateral ft. FY17 Avg. Well Costs = $660/lat ft. 125+ locations on existing Marcellus pads Est. EURs ~1.7 Bcf / 1,000 lateral ft. Est. Development Well Costs = ~$800/lat ft FY 18 WDA Utica Transition Plan Finish Marcellus Pads in Development Drill 8 / complete 17 Marcellus wells (100% Seneca) Complete and bring final 12 joint development online by end of 1H FY18 (63 of 75 JDA wells now producing) Optimize Utica D&C design Drill 11 Utica wells and test 2 more Utica test wells off Marcellus pads Optimize landing zone targets, well-bore spacing, sand concentration and completion stage spacing Transition to Utica development by fiscal 2019 Tailor development plan to reuse existing pad, water and gathering infrastructure Expect development costs to average $5.5 to $6.5mm per well Utica generating EURs that are 50% better than Marcellus locations for only 20% higher well costs

Eastern Development Area EDA Acreage – 70,000 Acres EDA Highlights 3 1 2 1 2 Upstream DCNR Tract 007 (Tioga Co., Pa) 1 Utica and 1 Marcellus producing well Utica 30-day IP = 15.8 MMcf/d Utica development expected to begin in fiscal 2018 ~50 remaining Utica locations economic under $2.00 /Mcf Covington & DCNR Tract 595 (Tioga Co., Pa.) Gross daily production: ~85 MMcf/d Marcellus locations fully developed Opportunity for future Utica appraisal DCNR Tract 100 & Gamble (Lycoming Co., Pa.) Gross daily production: ~155 MMcf/d 58 remaining Marcellus locations economic < $1.70 /Mcf Atlantic Sunrise capacity (190 MDth/d) in mid-2018 Geneseo shale to provide 100-120 additional locations 3

EDA Marcellus: Lycoming County Development Upstream Prolific Marcellus acreage with peer leading well results 60 Marcellus wells producing w/ average IP rate of 17.0 MMcf/d 58 remaining Marcellus locations economic under $1.70 /Mcf Near-term development focused on filling Atlantic Sunrise capacity forecasted to be available in July 2018 Transco Firm Sales(1) 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.

EDA Utica: Tioga County Development Upstream Utica Development in Tioga County – Tract 007 Expected to Begin in FY18 Northeast Supply Diversification Project FT Capacity: 50,000 Dth/d @ $0.50/Dth Firm Sales: NYMEX and DAWN EDA - TGP 300 Firm Sales(1) 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: 50 locations economic under $2.00 /Mcf Targeting to grow production by 100 to 150 MDth/d by FY20 Expected Development Costs: $5.5 to $6.5 million per well Gathering Infrastructure: NFG Midstream Wellsboro Modest build-out required to connect to TGP 300 Sales/Takeaway Strategy: 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

Marcellus: Drilling & Completions Efficiencies Normalized to adjust for daylight only frac operations that began in 2016. Marcellus Drilling Marcellus Completions Upstream Down 40% since 2014 Operational Efficiencies and Investment in Water Infrastructure Have Resulted in Peer Leading Well Costs Down 41% since 2014

Appalachia Drilling Program Economics Net realized price reflects either (a) price received at the gathering system inteconnect or (b) price received at delivery market net of firm transportation charges. Internal Rate of Return (IRR) is pre-tax and includes estimated well costs under current cost structure, LOE, and Gathering tariffs anticipated for each prospect. 1,300 to 1,700 Locations Economic Below $2.00/MMBtu(1) Upstream Prospect Reservoir Locations Remainingto Be Drilled Completed Lateral Length (ft) Average EUR (Bcf) Internal Rate of Return % (2) Realized Price(1) Required for 15% IRR Anticipated DeliveryMarkets $2.50Realized $2.25Realized $2.00Realized EDA DCNR 100Lycoming Marcellus 11 5600 13 - 15 0.88 0.67 0.48 $1.52 Transco Leidy &Atlantic Sunrise Southeast US(NYMEX+) GambleLycoming Marcellus 47 4700 10 - 11 0.63 0.48 0.33 $1.67 DCNR 007Tioga Utica 50 7500 13 - 14 0.4 0.27 0.16 $1.98 TGP 300 WDA CRV Utica 125 - 500+ 7500 12 - 14 0.36 0.27 0.2 $1.83 TGP 300 &Niagara Expansion Canada (Dawn) CRV Marcellus 10 8000 8 - 10 0.34 0.26 0.18 $1.87 Hemlock/ Ridgway Marcellus 631 8800 8-9 0.28999999999999998 0.23 0.16 $1.97 Remaining Tier 1 Marcellus 402 8500 7-8 0.34 0.25 0.17 $1.94 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)

California Oil Stable Oil Production | Minimal Capital Investment | Steady Free Cash Flow 1 2 3 4 5 6 Location Formation Production Method FY17 Gross Daily Production (Boe/d) 1 East Coalinga Temblor Primary 711 2 North Lost Hills Tulare & Etchegoin Primary/ Steam flood 951 3 South Lost Hills Monterey Shale Primary 1,578 4 North Midway Sunset Tulare & Potter Steam flood 3,183 5 South Midway Sunset Antelope Steam flood 1,968 6 Sespe Sespe Primary 1,335 TOTAL CALIFORNIA GROSS PRODUCTION 9,726 Boe/d Upstream

California Capital Expenditures vs. Production Upstream 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.

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 Midway Sunset Economics MWSS Project IRRs at $50/Bbl(1) Reflects pre-tax IRRs at a $50/Bbl WTI. Upstream 24

Seneca Production Upstream Net Production (Bcfe) +11% at midpoint

Long-term Contracts Supporting Appalachian Production Atlantic Sunrise (Transco) Delivery Markets: Mid-Atlantic & Southeast U.S. 189,405 Dth/d In-Basin Firm Sales Contracts(1) Niagara Expansion (TGP & NFG) Delivery Markets: Canada-Dawn & TETCO 158,000 Dth/d Northeast Supply Diversification 50,000 Dth/d Represents base firm sales contracts not tied to firm transportation capacity. Base firm sales are either fixed priced or priced at an index (e.g., NYMEX ) +/- a fixed basis and do not carry any transportation costs. Firm Transportation Long-term firm sales contracts in place at physical delivery points realizing NYMEX / Dawn less transport cost Upstream Regional Firm Sales Converting 95 Mdth/d of Northern Access sales from Dawn back to basin Recent deals providing attractive realizations Further regional basis improvement expected as pipeline projects are placed in-service 10% Production CAGR FY 2019 FY 2020 FY 2021 Seneca will continue to layer-in firm sales contracts with attractive realizations at regional pricing points to lock-in drilling economics and minimize spot exposure as it waits for Northern Access FY 2018 Firm Sales Contracts Added Since NA16 Delay

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

Firm Sales Provide Market for Appalachian Production Net Contracted Firm Sales Volumes (Dth per day) Contracted Index Price Differentials ($ per Dth)(1) Values shown represent the weighted average fixed price or contracted fixed differential relative to NYMEX (netback price) less any associated transportation costs. Upstream 492,400 Dth/d gross 525,300 Dth/d gross 494,500 Dth/d gross 597,600 Dth/d gross

Strong Hedge Book in FY 2018 Natural Gas Swap & Fixed Physical Sales Contracts (Millions MMBtu) Fixed price physical sales exclude joint development partner’s share of fixed price contract WDA volumes as specified under the joint development agreement. Reflects percentage of projected production hedged at the midpoint of the FY18 production range. Seneca’s total FY18 production range is 185 to 200 Bcfe, or 192.5 Bcfe at the midpoint. Natural gas is assumed to be 175 MMcf or ~181 million MMBtus (conversion factor of ~1.03) at midpoint. Oil assumed to be approx. 2.9 million Bbls at midpoint. Upstream Crude Oil Swap Contracts (Thousands Bbls) (1) FY 18 Nat Gas 55% Hedged(2) FY 2018 Production Guidance(3) FY 2018 Production Guidance(3)

Fiscal 2018 Production and Price Certainty FINANCIAL HEDGE + FIRM SALE = PRICE CERTAINTY Average realized price reflects uplift from financial hedges less fixed differentials under firm sales contracts and any firm transportation costs. Indicates firm sales contracts with fixed index differentials but not backed by a matching financial hedge. 96 Bcf locked-in realizing net ~$2.59/Mcf (1) 45 Bcf of additional basis protection Upstream Spot production assumed to be sold at ~$2.40/MMbtu 140.5 Bcf Protected by Firm Sales Next Year 60% of oil production hedged at $54.30 /Bbl

Seneca Operating Costs Competitive, low cost structure in Appalachia and California supports strong cash margins Gathering fee generates significant revenue stream for affiliated gathering company DD&A decrease due to improving Marcellus & Utica F&D costs Seneca DD&A Rate $/Mcfe Appalachia LOE & Gathering $/Mcfe California LOE $/Boe Total Seneca Cash OpEx $/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 $0.90 to $1.00 for fiscal 2018. Upstream

Midstream Businesses

Midstream Businesses Midstream Midstream Midstream Businesses Adjusted EBITDA ($MM)(1) A reconciliation of Adjusted EBITDA to Net Income as presented on the Consolidated Statement of Income and Earnings Reinvested in the Business is included at the end of this presentation. Midstream Businesses System Map NFG Supply Corp. FERC-Regulated Pipeline & Storage Empire Pipeline, Inc. FERC-Regulated Pipeline & Storage NFG Midstream Corp Marcellus & Utica Gathering & Compression

Integrated Development – WDA Gathering System Current System In-Service ~70 miles of pipe / 31,220 HP of compression Current Capacity: 470 MMcf per day Interconnects with TGP 300 Total Investment to Date: $281 million Future Build-Out FY 2018 CapEx: $10 MM - $15MM Modest gathering pipeline and compression investment required to support Seneca’s transition to Utica development Ultimate capacity can exceed 1 Bcf/d Over 300 miles of pipelines and five compressor stations (+60,000 HP installed) Deliverability into TGP 300 and NFG Supply Gathering System Build-Out Tailored to Accommodate Seneca’s WDA Development Midstream Clermont Gathering System Map

Integrated Development – EDA Gathering Systems Total Investment (to date): $33 million Capacity: 220,000 Dth per day (Interconnect w/ TGP 300) Production Source: Seneca Resources – Tioga Co. (Covington and DCNR Tract 595) Total Investment (to date): $177 million FY 2018 Capital Expenditures: $35 MM - $50 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 Midstream Interconnects Wellsboro Gathering System Total Investment (to date): $7 million FY 2018 Capital Expenditures: $10 MM - $20 MM Capacity: 200,000 Dth per day (Interconnect w/ TGP 300) Production Source: Seneca Resources – Tioga Co. (DCNR Tract 007)

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

Northern Access Project Status Project in-service not expected before 2019 due to regulatory delays February 3, 2017 – NFG received FERC 7(c) certificate March 3, 2017 – NFG filed petition for rehearing with FERC seeking waiver of NYS DEC Clean Water Act Section 401 Water Quality Certification (WQC) and preemption on state level permits April 7, 2017 – NY DEC issued notice of denial of WQC and other state stream and wetland permits for NY portion of project (PA DEP WQC received in January 2017) April 21, 2017 – NFG filed appeal of NY DEC WQC notice of denial with US Court of Appeals for the 2nd Circuit Project Spending Update: Total project spending to-date: ~$76 million Minimal remaining commitments National Fuel Remains Committed to Building the Northern Access Pipeline Project Midstream

Empire System Expansion Target In-Service: November 2019 System: Empire Pipeline Estimated Cost: $135 million Receipt Point: Jackson (Tioga Co., Pa. production) Design Capacity and Delivery Points: 175,000 Dth/d to Chippawa (TCPL interconnect) 30,000 Dth/d to Hopewell (TGP 200 interconnect) Customers: Precedent agreements in-place for 190,000 Mdth/d Negotiating commitments on remaining capacity Major Facilities: 2 new compressor stations in NY (1) & Pa. (1) No new pipeline construction Foundation Shipper Agreement Provides Major Commitment Needed for the Empire North Project Midstream

Continued Expansion of the NFG Supply System Line N Expansion Opportunities Line D Expansion Project Midstream Project Status: In-service on November 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) Line D Expansion Project Line N Expansion Opportunities Line N Expansion Opportunity #1 (Supply OS #220) Project: Firm transportation service to a new ethylene cracker facility being built by Shell Chemical Appalachia, LLC. Target In-Service: July 2019 Contracted Capacity: 133,000 Dth/d with foundation shipper Line N Expansion Opportunity #2 (Supply OS #221) Project: New firm transportation service for on-system demand Target In-Service: July 2020 Open Season Capacity: Awarded 165,000 to foundation shipper. Precedent agreement in negotiations. Future NFG Supply System Expansions

Pipeline & Storage Customer Mix 4.0 MMDth/d Contracted as of 11/1/2017. 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): 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) Pennsylvania Total Customers(1): 213,200 ROE: Black Box Settlement (2007) Rate Mechanisms: Low Income Rates Merchant Function Charge As of September 30, 2017. Downstream

New York Rate Case Outcome 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 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 Earnings sharing would start 4/1/18 if NFG Distribution Corp. does not file for new rates to become effective on or before 10/1/18 (50/50 sharing starts at earnings in excess of 9.1%) Article 78 appeal filed on 7/28/17 On April 20, 2017, the New York Public Service Commission issued a Rate Order relating to NFG Distribution’s rate case (No. 16-G-0257) filed in April 2016. Case 13-G-0136 rate year ended September 30, 2015. Downstream 43

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 September 30 Downstream

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

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

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

Appendix

Earnings Guidance Fiscal 2017 EPS Non-regulated Businesses Exploration & Production Gathering $3.30 /share $2.75 to $3.05 /share Fiscal 2018 EPS Guidance Seneca Net Production: 185 to 200 Bcfe (up 17.5 Bcf or 11% vs FY 17) Gathering Revenues: $115 to $125 million (up $12 million or 11% vs FY17) Natural Gas : ~$2.55 /Mcf(1) (down $0.40 /Mcf vs. $2.95 /Mcf in FY17) Crude Oil: ~$51.85 /Bbl(2) (down $2.02 /Bbl vs. $53.87 /Bbl FY17) Key Guidance Drivers Assumes NYMEX natural gas pricing of $3.00 /MMBtu and basin spot pricing of $2.40 /MMbtu and reflects the impact of existing financial hedge, firm sales and firm transportation contracts. Assumes NYMEX (WTI) oil pricing of $50.00 /Bbl and California-MWSS pricing differentials of 95% to WTI, and reflects impact of existing financial hedge contracts. Production Realized natural gas & oil prices (after-hedge) Utility Normal Weather Regulated Businesses Pipeline & Storage Utility Guidance assumes normal weather Warmer than normal weather impacted FY17 earnings by ~$0.06/sh ~$295 million in revenues (flat vs. FY17) Pipeline & Storage Revenues Appendix Decline in FY18 Earnings Guidance Predominantly Due to Lower Commodity Price Realizations

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. Appendix (1) Natural Gas Volumes in thousand MMBtu; Prices in $/MMBtu Fiscal 2018 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 42570 $3.34 27060 $3.17 16880 $3.07 4840 $3.01 - - Dominion Swaps 180 $3.82 - - - - - - - - Dawn Swaps 8400 $3.08 7200 $3 7200 $3 600 $3 - - Fixed Price Physical 47992 $2.4300000000000002 34438 $2.4900000000000002 38428 $2.2799999999999998 41260 $2.21 39844 $2.23 Total 99142 $2.88 68698 $2.81 62508 $2.58 46700 $2.31 39844 $2.23 Crude Oil Volumes & Prices in Bbl Fiscal 2018 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 24000 $91 - - - - - - - - NYMEX Swaps 1731000 $53.79 1068000 $53.42 324000 $50.52 156000 $51 156000 $51 Total 1755000 $54.3 1068000 $53.42 324000 $50.52 156000 $51 156000 $51

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 Operating Results as reported GAAP earnings before items impacting comparability. 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 – Operating Results Appendix

Non-GAAP Reconciliations – Adjusted EBITDA Appendix

Non-GAAP Reconciliations – Capital Expenditures Appendix

Non-GAAP Reconciliations – E&P Operating Expenses Appendix