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 5, 2015

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))	

 

Item 7.01	Regulation FD Disclosure.	
On November 5, 2015, 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: 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; impairments under the SEC’s full cost ceiling test for natural gas and oil reserves; changes in the price of natural gas or oil; changes in laws, regulations or judicial interpretations to which the Company is subject, including those involving derivatives, taxes, safety, employment, climate change, other environmental matters, real property, and exploration and production activities such as hydraulic fracturing; governmental/regulatory actions, initiatives and proceedings, including those involving rate

cases (which address, among other things, target rates of return, rate design and retained natural gas), environmental/safety requirements, affiliate relationships, industry structure, and franchise renewal; 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; 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; 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; 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; changes in demographic patterns and weather conditions; changes in the availability, price or accounting treatment of derivative financial instruments; changes in economic conditions, including global, national or regional recessions, and their effect on the demand for, and customers’ ability to pay for, the Company’s products and services; the creditworthiness or performance of the Company’s key suppliers, customers and counterparties; economic disruptions or uninsured losses resulting from major accidents, fires, severe weather, natural disasters, terrorist activities, acts of war, cyber attacks or pest infestation; significant differences between the Company’s projected and actual capital expenditures and operating expenses; changes in laws, actuarial assumptions, the interest rate environment and the return on plan/trust assets related to the Company’s pension and other post-retirement benefits, which can affect future funding obligations and costs and plan liabilities; increasing health care costs and the resulting effect on health insurance premiums and on the obligation to provide other post-retirement benefits; 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 2015	

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/ James R. Peterson	
	 	James R. Peterson	
	 	Assistant Secretary	
Dated: November 5, 2015

EXHIBIT INDEX

Exhibit
Number	  	Description	
		
99	  	Investor Presentation dated November 2015	

National Fuel Gas Company Investor Presentation November 2015 Exhibit 99

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: 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; impairments under the SEC’s full cost ceiling test for natural gas and oil reserves; changes in the price of natural gas or oil; changes in laws, regulations or judicial interpretations to which the Company is subject, including those involving derivatives, taxes, safety, employment, climate change, other environmental matters, real property, and exploration and production activities such as hydraulic fracturing; governmental/regulatory actions, initiatives and proceedings, including those involving rate cases (which address, among other things, target rates of return, rate design and retained natural gas), environmental/safety requirements, affiliate relationships, industry structure, and franchise renewal; 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; 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; 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; 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; changes in demographic patterns and weather conditions; changes in the availability, price or accounting treatment of derivative financial instruments; changes in economic conditions, including global, national or regional recessions, and their effect on the demand for, and customers’ ability to pay for, the Company’s products and services; the creditworthiness or performance of the Company’s key suppliers, customers and counterparties; economic disruptions or uninsured losses resulting from major accidents, fires, severe weather, natural disasters, terrorist activities, acts of war, cyber attacks or pest infestation; significant differences between the Company’s projected and actual capital expenditures and operating expenses; changes in laws, actuarial assumptions, the interest rate environment and the return on plan/trust assets related to the Company’s pension and other post-retirement benefits, which can affect future funding obligations and costs and plan liabilities; increasing health care costs and the resulting effect on health insurance premiums and on the obligation to provide other post-retirement benefits; 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, 2014 and the Forms 10-Q for the quarters ended December 31, 2014, March 31, 2015 and June 30, 2015. 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. Safe Harbor For Forward Looking Statements

$257 Million of Midstream Adjusted EBITDA(2) $1.2 Billion Midstream Investments since 2010 790,000 Net Acres in Marcellus Shale 2.3 Tcfe of Proved Reserves(1) Quality Assets, Exceptional Location, Unique Integration Total proved reserves are as of September 30, 2015. For the fiscal year ended September 30, 2015. 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.

Unique Integrated Business Model Provides Competitive Advantage The National Fuel Value Proposition 4 Mineral ownership on ~720,000 acres in WDA = limited royalties or drilling commitments Seneca has >900,000 Dth/day of firm transportation & sales contracts by end of fiscal 2017 Stacked pay potential in Utica and Geneseo shales across Marcellus acreage Coordinated gathering & interstate pipeline infrastructure build-out with NFG midstream Opportunity for further pipeline expansion to accommodate Appalachian supply growth Creating long-term sustainable value remains our #1 shareholder priority Considerable Upstream and Midstream Growth Opportunities in Appalachia Geographical and operational integration drives capital efficiency and reduces costs Diversified cash flows provide stability in challenging commodity price environment Strong Balance Sheet and History of Disciplined Financial Management Investment grade credit rating and liquidity to support Appalachian growth strategy Strong hedge book helps insulate earnings and cash flows from commodity volatility Disciplined capital investment focused on economic returns 113-year commitment to the dividend

200,000 “Tier 1” WDA Acres in Pa. Fee Acreage Economic < $3/MMbtu Clermont Gathering System Capacity to Approach 1Bcf/d Northern Access Projects to Transport 660 MDth/d of Seneca production by FY17 NFG Appalachia – Integrated Vision for Growth Exploration & Production Pipeline & Storage Gathering WDA “Tier 1” Acreage 1 2 3 1 2 Developing Our High Quality Marcellus & Utica Acreage Connecting Our Production to Our Interstate Pipeline System Expanding Our Interstate Pipeline System to Reach Premium Markets 3

Appalachia Upstream & Midstream CapEx 7 Note: A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation. Refer to slide 39 for NFG consolidated capital expenditures. Exercising Capital Flexibility & Efficiency to Respond to Commodity Environment and Capitalize on Midstream Opportunities

Significant Appalachian Acreage Position 8 153 wells able to produce 415 MMcf/d(1) 40-50 remaining Marcellus locations Additional strong Utica & Geneseo potential Limited development drilling until firm transportation on Atlantic Sunrise (190 MDth/d) is available in late 2017 Mostly leased (16-18% royalty) No near-term lease expirations 48 wells able to produce 185 MMcf/d(1) Large inventory of high quality Marcellus acreage NFG midstream infrastructure supporting growth 660 MDth/d firm transportation by fiscal 2017 Mineral fee ownership enhances economics Highly contiguous nature drives efficiencies Seneca Lease Seneca Fee 720,000 Acres 70,000 Acres Western Development Area (WDA) Eastern Development Area (EDA) (1) Productive capacity includes 50 MMcf and 200 MMcf/d, respectively, of WDA and EDA daily production being voluntarily curtailed for price-related reasons.

Marcellus Shale: Western Development Area 9 Internal rate of return (IRR) is pre-tax and includes estimated well costs under the current well design and cost structure and projected firm transportation, gathering, LOE and other operating costs. CRV and Hemlock/Ridgway well designs assume 8,800 ft. lateral and 190 ft. frac stage spacing. Other Tier 1 well designs assume 8,500 ft. lateral and 190 ft. frac stage spacing. WDA Tier 1 Acreage – 200,000 Acres WDA Tier 1 Marcellus Economics(1) WDA Highlights     Avg $3.00 15% IRR   Locations EUR NYMEX/Dawn Realized   Remaining (Bcf) IRR% Price CRV 79 10-11 19% $2.03 Hemlock/Ridgeway 668 8-9 11% $2.35 Other Tier 1 423 7.5-8.5 10% $2.44 Large drilling inventory of quality Marcellus dry gas ~1,200 locations economic < $2.50/MMBtu NFG midstream infrastructure supporting growth NFG Clermont Gathering System – ~1Bcf/d 660 MDth/d firm transport on NFG projects by FY17 Fee acreage enhances economics No royalty on most acreage (98% avg. NRI) No lease expirations or requirements to drill acreage Highly contiguous position drives D&C efficiencies Multi-well pad drilling averaging 10 wells per pad Average lateral length = 7,800 ft. Centralized water sourcing & disposal infrastructure 2 Utica tests expected in fiscal 2016 SRC Lease Acreage SRC Fee Acreage EOG Earned JV Acreage Clermont/ Rich Valley Hemlock Ridgway 2 - 4 BCF/well 6 - 10 BCF/well 4 - 6 BCF/well EUR Color Key

Integrated WDA Development – Upstream Clermont/Rich Valley Development Map Pittsburgh Clermont/Rich Valley Area Legend Drilled Wells Planned Wells Clermont Gathering System (in-service) Clermont Gathering System (future) CRV Development Summary 48 wells currently producing 185 MMcf/d >200 MMcf/d firm sales starting 12/1/15 Currently operating 3-rigs. Will drop to 2 rigs during Q2 FY16 Development focused on building productive capacity to fill firm transport on NFG’s Northern Access projects (total 660 MDth/d by late 2016)

Integrated WDA Development - Gathering 11 Current System In-Service ~44 miles of pipe/13,800 HP of compression Current Capacity: 470 MMcf per day Interconnect with TGP 300 Total CapEx To Date: $216 MM Fiscal 2016 Build Out FY16 CapEx: $100 MM to $140 MM Exit FY16 with > 60 miles of pipe installed and >31,000 HP commissioned Anticipate >200% throughput increase, compared to FY15 Future Build-Out (FY17+) Ultimate capacity can exceed 1 Bcf/d Over 100 miles of pipelines and five compressor stations (+60,000 HP installed) Deliverability into TGP 300 and NFG Supply (Northern Access 2016) Future third-party volume opportunities Gathering System Build-Out Tailored to Accommodate Seneca’s WDA Production Growth Clermont Gathering System Map

Integrated WDA Development - Interstate Pipelines 12 (1) 40,000 Dth per day went in-service on November 1, 2015. The remaining 100,000 Dth per day is expected to be placed in-service by December 1, 2015. Northern Access 2015 Customer: Seneca Resources (NFG) In-Service: November 2015(1) System: NFG Supply Corp. Capacity: 140,000 Dth per day Leased to TGP as part of TGP’s Niagara Expansion project Interconnect Niagara (TransCanada) Total Cost: $67.5 Million Major Facilities 23,000 hp Compression FERC Status Certificate received Feb. 2015 Expanding Our Interstate Pipelines to Deliver Seneca’s WDA Production to Canada

13 Northern Access 2016 Customer: Seneca Resources (NFG) In-Service: Targeting Late 2016 Capacity: 490,000 Dth/d Interconnects: TransCanada – Chippawa (350 MDth/d) TGP 200 – East Aurora (140 MDth/d) Total Cost: ~$455 Million Major Facilities: 98.5 miles – 16/24” Pipeline 22,214 hp & 5,350 hp Compression FERC Status Pre-filing: July 2014 Certificate filing: March 2015 Certificate amendment filed Nov. 2015 Northern Access 2016 to Increase Transport Capacity out of WDA to Canada by 490,000 Dth/d by FY17 Integrated WDA Development - Interstate Pipelines

Marcellus Shale: Eastern Development Area (1) One well included in the total for both Tract 595 and Tract 100 is drilled into and producing from the Geneseo Shale. EDA Acreage – 70,000 Acres 1 2 3 EDA Highlights 1 Covington & DCNR Tract 595 Tioga County, Pa. 92 wells(1) with 125 MMcf/d productive capacity 75MM/d firm sales/FT in FY16 NFG Covington Gathering System Opportunity for future Geneseo & Utica dev. DCNR Tract 100 & Gamble Lycoming County, Pa. 59 wells(1) with 290 MMcf/d productive capacity 110-165 MMcf/d firm sales/FT in FY16 Atlantic Sunrise capacity (190 Mth/d) in FY18 NFG Trout Run Gathering System Geneseo to provide additional 100-120 locations DCNR Tract 007 Tioga County, Pa. 1 Utica and 1 Marcellus exploration well Utica well 24 IP = 22.7 MMcf/d Utica Resource potential = ~1 Tcf 2 3

Integrated EDA Development - Gathering 15 In-Service Date: November 2009 Capital Expenditures (to date): $33 Million Capacity: 220,000 Dth per day Production Source: Seneca Resources – Tioga Co. (Covington and DCNR Tract 595 acreage) Interconnect: TGP 300 Facilities: Pipelines and dehydration Future third-party volume opportunities Interconnects In-Service Date: May 2012 Capital Expenditures (to date): $163 Million Capacity: 466,000 to 585,000 Dth per day Production Source: Seneca Resources – Lycoming Co. (DCNR Tract 100 and Gamble acreage) Interconnect: Transco – Leidy Lateral Facilities: Pipelines, compression, and dehydration Future third-party volume opportunities Covington Gathering System Trout Run Gathering System Gathering Segment Supporting Seneca’s EDA Production & Future Development

Utica/Point Pleasant: Industry Activity Range 59 MMcf/d Rice 42 MMcf/d Shell 26.5 MMcf/d PGE Permitted Drilling Completed Production Seneca Vert. Seneca Horiz. EQT 73 MMcf/d Color-filled contours are Trenton TVDSS; CI = 1000’ Seneca – Mt. Jewett IP: 8.9 MMcf/d CNX 61 MMcf/d MHR 46 MMcf/d Seneca – WDA 2 Utica Test Wells Planned for 2016 Seneca - DCNR 007 IP: 22.7 MMcf/d

Marcellus Drilling and Completion Efficiencies Includes dollars spent to drill and complete development wells only. Excludes exploration and delineation wells. Down 44% since 2012 Down 63% since 2012 $8.7 MM Well Cost $5.7 MM Well Cost Fiscal 2012 Average Development Well Fiscal 2015 Average Development Well Lateral Length: 5,100 ft Measured Depth: 13,700 ft Completion Stages: 20 Lateral Length: 7,300 ft Measured Depth: 14,300 ft Completion Stages: 37 Drilling Cost per Foot(1) Completion Cost per Stage(1) (000s)

FY 2016 Production - Firm Sales & Spot Exposure 18 Fiscal 2016 Firm Sales with Price Certainty 119.9 Bcf Realizing ~$3.45/Mcf (1) 15.0 Bcf of Additional Basis Protection (2) 6.3 Bcf(3) Appalachia Productive Capacity Seneca Total Productive Capacity Realized price is net of firm transportation costs. Indicates firm sales contracts with fixed index differentials but not backed by a matching financial hedge. Refer to slide 50 for the average firm sales differentials by quarter for fiscal 2016. Represents 6.3 Bcf of non-operated production from Western Development Area that typically realizes pricing similar to DOM SP. EPS guidance assumes production sold into spot market realizes an average price of $1.75 per MMBtu.

Significant Base of Long-Term Firm Contracts Atlantic Sunrise (Transco) Delivery Markets: Mid-Atlantic & Southeast U.S. 189,405 Dth/d Northern Access 2016 (NFG(1), TransCanada & Union) Delivery Markets: Canada-Dawn & NY-TGP200 490,000 Dth/d Niagara Expansion (TGP & NFG) Delivery Markets: Canada-Dawn & TETCO 170,000 Dth/d Current Firm Sales(2) & FT 914,405 Dth per day Total Firm Contracts by FY2018 Includes capacity on both National Fuel Gas Supply Corp. and Empire Pipeline, Inc., both wholly owned subsidiaries of National Fuel Gas Company. Includes base firm sales contracts not tied to firm transportation capacity.

Natural Gas Hedge Position (1) Assumes production at midpoint of East Division Productive Capacity and 3 Bcf of natural gas production in California. FY 2016 = 67% hedged(1) at $3.66 per MMbtu Natural Gas Swap & Fixed Physical Sales Contracts (Million MMBtu)

Appalachian Price Realizations & Margins 21 Appalachian peer group includes AR, COG, CNX, EQT, GPOR, RICE, & RRC . Peer group information obtained or estimated by National Fuel Gas Company from peer company quarterly public filings (press release & Form 10-Q) for the quarter-ended September 30, 2015. Where necessary, peer company realizations and margins were adjusted to reflect cash settled hedges and results of exploration and production operations only. Note: A reconciliation of Adjusted EBITDA per Mcfe 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. Q4 FY15 Average Natural Gas Realizations per Mcf vs. Appalachian Peer Group(1) Q4 FY15 Adjusted EBITDA per Mcfe(2) vs. Appalachian Peer Group(1) Strong hedge book, firm sales portfolio, and cost discipline generating impressive natural gas price realizations and margins in challenging commodity environment Peer Average $2.84/Mcf Appalachia Appalachia

Pipeline & Storage: Premier Appalachian Position 22 In addition to serving our own upstream and downstream subsidiaries, NFG is uniquely positioned to expand our regional pipeline systems and provide valuable outlets for 3rd party producers and shippers in Appalachia Canada & Michigan New England & Northeast Midwest & Southeast Mid-Atlantic

Recent 3rd Party Expansions Highly Successful Expansions for 3rd Parties since 2010 Line N Projects +633 MDth/d Northern Access 2012 +320 MDth/d Empire & Lamont Expansions +489 MDth/d 3rd Party Expansion Capital Cost ($MM) Expansion Revenues ($MM) $387 million since FY 2010 1,442 MDth/d since FY2010

Planned Empire System Expansion Empire North Expansion Project Target In-Service: Late 2018 System: Empire Pipeline Target Market: Marcellus & Utica producers in Tioga & Potter County, Pa. Open Season Capacity: 300,000 Dth/d Delivery Points: 180,000 Dth/d to Chippawa (TCPL) 120,000 Dth/d to Hopewell (TGP) Total Cost: $150 - $400 million Major Facilities: 33,000 hp compression Potential 25+ miles 24” pipe FERC Status: Open Season 10/6/15 – 11/18/15

Midstream EBITDA Growth Note: A reconciliation of Adjusted EBITDA to Net Income as presented on the Consolidated Statement of Income and Earnings Reinvested in the Business is included at the end of this presentation.

New York & Pennsylvania Service Territories New York Pennsylvania Total Customers: 526,323 ROE: 9.1% (NY PSC Rate Case Settlement, May 2014) Rate Mechanisms: Earnings Sharing Revenue Decoupling Weather Normalization Low Income Rates Merchant Function Charge (Uncollectibles Adj.) 90/10 Sharing (Large Customers) Total Customers: 213,652 ROE: Black Box Settlement (2007) Rate Mechanisms: Low Income Rates Merchant Function Charge

Utility: Shifting Trends in Customer Usage (1) Weighted Average of New York and Pennsylvania service territories (assumes normal weather). Residential Usage Industrial Usage

A Proven History of Controlling Costs $10 million of increase in pension costs from fiscal 2013 primarily due to the NY PSC rate case settlement in May 2014. (1) (1)

Utility: Strong Commitment to Safety The Utility remains focused on maintaining the ongoing safety and reliability of its system Near-term increase due to ~$60MM upgrade of the Utility’s Customer Information System

California: Stable Production; Modest Growth East Coalinga Temblor Formation Primary North Lost Hills Tulare & Etchegoin Formation Primary/Steamflood South Lost Hills Monterey Shale Primary North Midway Sunset Tulare & Potter Formation Steamflood South Midway Sunset Antelope Formation Steamflood Sespe Sespe Formation Primary

California Average Daily Net Production 33 $40-$50 million Annual CapEx to Keep California Oil Production Flat

Strong Margins Support Significant Free Cash Flow Average revenue per BOE includes impact of hedging and other revenues. A reconciliation of Adjusted EBITDA margin 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. EBITDA per BOE includes Seneca corporate results and eliminations. Average Revenue for FYTD 2015(1) $65.72 per BOE

Appalachia Driving Proved Reserve Growth (1) Represents a three-year average U.S. finding and development cost. 4 Year CAGR: 26% Fiscal Years 3-Year F&D Cost(1) ($/Mcfe) 2008-2010 $2.37 2009-2011 $2.09 2010-2012 $1.87 2011-2013 $1.67 2012-2014 $1.38 2013-2015 $1.12 2015 F&D Cost = $0.96 Marcellus F&D: $0.79 373% Reserve Replacement Rate 65% Proved Developed

Seneca Production 37 Refer to slide 18 for additional details on fiscal 2016 firm sales and local Appalachian spot market exposure. (1)

EBITDA Contribution by Segment Note: A reconciliation of Adjusted EBITDA to Net Income as presented on the Consolidated Statement of Income and Earnings Reinvested in the Business is included at the end of this presentation.

Capital Expenditures by Segment Note: A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation.

Maintaining a Strong Balance Sheet Note: A reconciliation of Adjusted EBITDA to Net Income is included at the end of this presentation. Total Debt 51% $4.1 Billion Total Capitalization as of September 30, 2015 Debt/Adjusted EBITDA Capitalization Debt Maturity Profile ($MM) Liquidity Committed Credit Facilities Short-term Debt Outstanding Available Short-term Credit Facilities Cash Balance at 9/30/15 Total Liquidity at 9/30/15 $ 1,250 MM $ 0 MM $ 1,250 MM $ 114 MM $1,364 MM

Dividend Track Record (1) As of November 4, 2015. Current Dividend Yield(1) 3.0% Dividend Consistency Consecutive Dividend Payments 113 Years Consecutive Dividend Increases 45 Years Current Annualized Dividend Rate $1.58 per Share

2015 Pipeline Expansion Projects In-Service Westside Expansion & Modernization In-Service (October 2015) Tuscarora Lateral In-Service (November 2015) 2015 Completed Pipeline Expansion Projects Total Cost: $60.0 Million Incremental annual revenues of $10.9 MM on 49,000 Dth per day capacity Preserves $16.1MM in annual revenues on existing FT (192,500 Dth/d) and retained storage (3.3 Bcf) services Total Cost: $86 MM Expansion: $45 MM Modernization: $41 MM Incremental Annual Revenues: $8.8 MM Capacity: 175,000 Dth per day Range Resources (145,000 Dth/d) Seneca Resources (30,000 Dth/d) Tuscarora Lateral Westside Expansion & Modernization

Total Seneca Capital Spending by Division (1) Seneca’s West Coast division includes Seneca corporate and eliminations. (1)

Marcellus Operated Well Results Excludes 5 wells drilled and completed without sufficient production data for inclusion in table. Also excludes 2 wells now operated by Seneca that were drilled by another operator as part of a joint-venture. 30-day average excludes 1 well that has not been on line 30 days. Area Producing Well Count Average IP Rate (MMcfd) Average 30-Day (MMcf/d) Average Treatable Lateral Length (ft) Clermont/Rich Valley (CRV) & Hemlock Elk, Cameron & McKean counties 33(1) 7.7 5.8(2) 6,132’ WDA Development Wells: EDA Development Wells: Area Producing Well Count Average IP Rate (MMcfd) Average 30-Day (MMcf/d) Average Treatable Lateral Length (ft) Covington Tioga County 47 5.2 4.1 4,023’ Tract 595 Tioga County 44 7.4 4.9 4,754’ Tract 100 Lycoming County 57 16.8 12.6 5,270’

Highly Competitive Cost Structure Represents the midpoint of General & Administrative Expense guidance of $0.35 to $0.40 per Mcfe for fiscal 2016. The total of the two LOE components represents the midpoint of LOE guidance of $0.95 to $1.05 per Mcfe for fiscal 2016. The cost of firm transportation is reflected in price realizations (a deduction to gross revenues). As such, it is not included in LOE. (1) (2) (2) (3) (1) (2) (2)

Marcellus Shale Program Economics (1) 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. ~1,200 WDA Locations Economic Below $2.50/MMbtu Q3 Prospect Locations Remainingto Be Drilled Completed Lateral Length (ft) Average EUR (Bcf) EUR / 1000' (Bcf) BTU $3.50IRR (%) (1) $3.25IRR (%) (1) 15% IRR (1) Realized Price DCNR 100 13 5400 13-14 2.75 1033 0.78200000000000003 0.59250000000000003 $1.68 Gamble 28 4600 11-12 2.5 1033 0.4995 0.38250000000000001 $1.91 CRV 79 8750 10-11 1.2 1045 0.2727 0.20699999999999999 $2.19 Hemlock 137 8850 8.5-9.5 1 1045 0.22600000000000001 0.16589999999999999 $2.36 Ridgway 358 8800 7.5-8.5 0.9 1112 0.19869999999999999 0.14710000000000001 $2.4500000000000002 Remaining Tier 1 1020 7000 5.5-6.5 0.8571428571428571 1030 - 1100 0.15690000000000001 0.1115 $2.65 Future Resource 1620 7000 5.5-6.5 0.7857142857142857 1030 - 1350 0.107 7.4499999999999997E-2 $3 Q4 EDA: DCNR 100 13 5218 12.5-13.5 1033 1 0.86709999999999998 $1.6 Gamble 28 4766 11.5-12.5 1033 0.62150000000000005 0.48670000000000002 $1.81 Q4 WDA OPT MODE: CRV 79 8800 10-11 1045 0.37409999999999999 0.27639999999999998 $2.0299999999999998 Hemlock / Ridgway 647 8800 8-9 1045 0.21809999999999999 0.15609999999999999 $2.41 Remaining Tier 1 8800 7.5-8.5 1030-1100 0.19370000000000001 0.13980000000000001 $2.48 Q4 WDA DEV MODE: CRV 79 8800 10-11 1045 0.40770000000000001 0.29670000000000002 $1.97 Hemlock / Ridgway 647 8800 8-9 1045 0.3125 0.23680000000000001 $2.15 Remaining Tier 1 8800 7.5-8.5 1030-1100 0.28499999999999998 0.21099999999999999 $2.21 Prospect Product Locations Remainingto Be Drilled Completed Lateral Length (ft) Average EUR (Bcf) BTU NYMEX / DAWN Pricing 15% IRR (1) Realized Price EUR / 1000' (Bcf) $3.50IRR % (1) $3.25IRR % (1) $3.00IRR % (1) EDA DCNR 100 Dry Gas 12 5400 12.5-13.5 2.75 1033 >100% 0.86899999999999999 0.62690000000000001 $1.595 Gamble Dry Gas 44 4600 11.5-12.5 2.5 1033 0.6119 0.48110000000000003 0.35830000000000001 $1.8149999999999999 WDA CRV Dry Gas 79 8800 10-11 1.2 1045 0.37409999999999999 0.27639999999999998 0.19370000000000001 $2.0299999999999998 Hemlock / Ridgway Dry Gas 668 8800 8-9 1 1045 - 1110 0.23649999999999999 0.16950000000000001 0.1135 $2.35 Remaining Tier 1 Dry Gas 423 8500 7.5-8.5 0.8571428571428571 1030 - 1110 0.20780000000000001 0.14929999999999999 9.7900000000000001E-2 $2.44 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)

WDA Mineral Interests Significantly Enhance Returns For illustration purposes only. Reflects a hypothetical $0.55 per MMBtu of gathering and compression costs and $0.15 of variable LOE and taxes. Internal Rate of Return (IRR) includes estimated well costs under current cost structure, LOE, and Gathering tariffs anticipated for each prospect. ($/Mcf) The Seneca Advantage 0% Royalty Realized Price $ 2.03 Less: Royalty Payment (0.00) Less: Cash Operating Expenses(1) (0.70) Cash Margin $ 1.33 Before Tax IRR (2) 15% A producer burdened by a 15% royalty would require a $0.30 higher realized price to achieve same level of economics as Seneca Resources Producer Paying 15% Royalty $ 2.03 (0.30) (0.70) $ 1.03 8% Clermont/Rich Valley Example

Adding Long-Term Firm Transport to the Portfolio A large majority of the executed firm sales agreements continue for the remainder of the firm transportation contract term. Excludes throughput-based commodity charges, fuel charges and other surcharges. Project (Counterparty) In-Service Date Contract Term Delivery Market Demand Charge ($/Dth) FT Capacity (Dth/day) Matched Firm Sales Contracts Fiscal 2016 Fiscal 2017 Fiscal 2018 Northeast Supply Diversification Project (TGP) Nov. 2012 15 years Canada $0.49 50,000 50,000 50,000 Executed Contracts 50,000 Dth/d for 10 years Niagara Expansion (TGP & NFG) Nov. 2015 15 years Canada $0.67 158,000 158,000 158,000 Executed Contracts 140,000 Dth/d for 15 years TETCO $0.12 12,000 12,000 12,000 Northern Access 2016 (NFG/ TransCanada/ Union) Late 2016 15 years Canada $0.70 --- 350,000 350,000 Executed Contracts 95,000 Dth/d Evaluating Further Opportunities TGP 200 (NY) $0.38 --- 140,000 140,000 Atlantic Sunrise (Transco) Sept. 2017 15 years Mid-Atlantic/ Southeast $0.73 --- --- 189,405 Executed Contracts 189,405 Dth/d for first 5 years(1) Total Firm Transportation Capacity 220,000 710,000 899,405 Weighted Average Transportation Charge per Dth (2) $0.59 $0.60 $0.63

Firm Sales Provide Market for Appalachian Production EDA and WDA carry an average net revenue interest (NRI) of 82% - 84% and 98%, respectively. Note: Values shown represent the price or differential to a reference price (netback price) at the point of sale. WDA (1) 176,629 /d 209,600 /d 208,000 /d 208,000 /d EDA (1) 253,526 /d 240,048 /d 185,048 /d 185,048/d Fiscal 2016 Firm Sales by Fiscal Quarter Pricing Index Key: EDA/WDA Split: Gross Contracted Volumes (Dth per day) Contracted Index Price Differentials ($ per Dth)

Natural Gas Hedge Positions (Volumes in thousands Mmbtu; Prices in $/Mmbtu) Fiscal 2016 Fiscal 2017 Fiscal 2018 Fiscal 2019 Fiscal 2020 Volume Avg.Price Volume Avg.Price Volume Avg.Price Volume Avg.Price Volume Avg.Price NYMEX Swaps 44350 $3.94 29530 $4.2 20350 $3.62 11400 $3.39 2000 $3.49 Dominion Swaps 18840 $3.78 12720 $3.87 - - - - - - SoCal Swaps - - - - - - - - - - MichCon Swaps 9000 $4.0999999999999996 3000 $4.0999999999999996 - - - - - - Dawn Swaps 9990 $3.92 19100 $3.7 1800 $3.4 - - - - Fixed Price Physical Sales 42680 $3.17 31010 $3.48 8850 $3.34 7300 $3.25 3660 $3.25 Total 124860 $3.66 95360 $3.82 31000 $3.53 18700 $3.33 5660 $3.33 Fiscal 2016 Fiscal 2017 Fiscal 2018 Fiscal 2019 Fiscal 2020 Volume Avg.Price Volume Avg.Price Volume Avg.Price Volume Avg.Price Volume Avg.Price NYMEX Swaps 44350 $3.94 29530 $4.2 20350 $3.62 11400 $3.39 2000 $3.49 Dominion Swaps 18840 $3.78 12720 $3.87 - - - - - - SoCal Swaps - - - - - - - - - - MichCon Swaps 9000 $4.0999999999999996 3000 $4.0999999999999996 - - - - - - Dawn Swaps 9990 $3.92 19100 $3.7 1800 $3.4 - - - - Fixed Price Physical Sales 42680 $3.17 31010 $3.48 8850 $3.34 7300 $3.25 3660 $3.25 Total 124860 $3.66 95360 $3.82 31000 $3.53 18700 $3.33 5660 $3.33

Crude Oil Hedge Positions Fiscal 2016 Fiscal 2017 Fiscal 2018 Volume Avg. Price Volume Avg. Price Volume Avg. Price Midway Sunset (MWSS) Swaps 36,000 $92.10 - - - - Brent Swaps 933,000 $95.18 384,000 $92.30 75,000 $91.00 NYMEX Swaps 456,000 $73.74 312,000 $54.20 - - Total 1,425,000 $88.24 696,000 $75.22 75,000 $91.00 (Volumes & Prices in Bbl)

Utica/Point Pleasant: EDA Opportunities Shell: Gee 11.2 MMcf/d PGE Currently Drilling Permitted Drilling Completed Producing Seneca Horizontal Shell: Neal 26.5 MMcf/d Other Operators DCNR Tract 001 Potential Future Location Covington Potential Future Location JKLM Currently Drilling PGE Seneca DCNR Tract 007 IP: 22.7 MMcf/d Lateral Length: 4,640’ Potential locations: ~ 70 Anticipated Development Well Cost: $7-$10 Million (5,500’ Lat.)

Estimated Cumulative Volumes YEAR CUM (MMCF) 1 1,466 2 2,334 3 2,989 4 3,510 5 3,933 6 4,289 7 4,596 8 4,866 9 5,108 10 5,325 EUR 8,400 Marcellus Type Curves: WDA

Estimated Cumulative Volumes YEAR CUM (MMCF) 1 3,226 2 5,451 3 6,815 4 7,762 5 8,470 6 9,029 7 9,483 8 9,862 9 10,185 10 10,466 EUR 13,495 Marcellus Type Curves: EDA

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, 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. 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.

National Fuel Gas Company

National Fuel Gas Company

National Fuel Gas Company