8-K

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): February 4, 2016

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 February 4, 2016, 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 press release 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: 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; 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; 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; 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; the cost and effects of legal and administrative claims against the Company or activist shareholder campaigns to effect changes at the Company; uncertainty of oil and gas reserve estimates; significant differences between the Company’s projected and actual production levels for natural gas or oil; changes in demographic patterns and weather conditions; changes in the availability, price or accounting treatment of derivative financial instruments; changes in economic conditions, including global, national or regional recessions, and their effect on the demand for, and customers’ ability to pay for, the Company’s products and services; the creditworthiness or performance of the Company’s key suppliers, customers and counterparties; economic disruptions or uninsured losses resulting from major accidents, fires, severe weather, natural disasters, terrorist activities, acts of war, cyber attacks or pest infestation; significant differences between the Company’s projected and actual capital expenditures and operating expenses; changes in laws, actuarial assumptions, the interest rate environment and the return on plan/trust assets related to the Company’s pension and other post-retirement benefits, which can affect future funding obligations and costs and plan liabilities; 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 February 2016

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: February 4, 2016

EXHIBIT INDEX

Exhibit Number	Description
99	Investor Presentation dated February 2016

EX-99

National Fuel Gas Company

Investor Presentation

February 2016

Exhibit

99

Safe Harbor For Forward Looking Statements

2

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:  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; 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; 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; 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

at different geographic locations, and the effect of such changes on commodity production, revenues and demand for pipeline transportation capacity to or from such locations;

other changes in price differentials between similar quantities of natural gas or oil having different quality, heating value, hydrocarbon mix or delivery date; the cost and effects

of legal and administrative claims against the Company or activist shareholder campaigns to effect changes at the Company; uncertainty of oil and gas reserve estimates;

significant differences between the Company’s projected and actual production levels for natural gas or oil; changes in demographic patterns and weather conditions; changes in

the availability, price or accounting treatment of derivative financial instruments; changes in economic conditions, including global, national or regional recessions, and their

effect on the demand for, and customers’ ability to pay for, the Company’s products and services; the creditworthiness or performance of the Company’s key suppliers, customers

and counterparties; economic disruptions or uninsured losses resulting from major accidents, fires, severe weather, natural disasters, terrorist activities, acts of war, cyber

attacks or pest infestation; significant differences between the Company’s projected and actual capital expenditures and operating expenses; changes in laws, actuarial

assumptions, the interest rate environment and the return on plan/trust assets related to the Company’s pension and other post-retirement benefits, which can affect future

funding obligations and costs and plan liabilities; 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, 2015 and the Form 10-Q for the quarter ended December 31, 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.

Corporate

Corporate

•

2.3

Tcfe

Proved

Reserves

(1)

•

785,000 net acres in Marcellus Shale

•

3 million Bbls/year California

crude oil production

3

National Fuel Gas Company

Upstream

Downstream

Quality Assets  |  Exceptional Location  | Unique Integration

•

$252 million adjusted EBITDA

(2)

•

$1.2 billion midstream investments

since 2010

•

Coordinated infrastructure build-out  

in Appalachia with NFG Upstream

•

740,000 Utility customer accounts

•

Stable, regulated earnings & cash flows

•

Supports investment grade credit rating

Midstream

Corporate

(1)

Total proved reserves are as of September 30, 2015.

(2)

For the trailing twelve months ended December 31, 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.

Corporate

Unique Asset Mix and Integrated Model Provide Balance and Stability

The National Fuel Value Proposition

4

Fee ownership on ~715,000 net acres in WDA = limited royalties or drilling commitments

Seneca has >900,000 Dth/day of firm transportation & sales contracts by start of fiscal 2018

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 flexibility and reduces costs

Cash flow from rate-regulated businesses supports interest costs and funds the dividend

NFG is Well Positioned to Endure Current Commodity Price Environment

Investment grade credit rating and liquidity to support long-term Appalachian growth strategy

Strong hedge book helps insulate near-term earnings and cash flows from commodity volatility

Disciplined and flexible capital investment that is focused on economic returns

Corporate

Appalachia Overview

Exploration & Production  |  Gathering  |  Pipeline & Storage

5

Appalachia Overview

Exploration & Production  |  Gathering  |  Pipeline & Storage

Appalachia

200,000 “Tier 1” WDA acres in Pa.

Fee acreage economic < $2.50/MMBtu

with minimal lease expiration

Just-in-time build-out of Clermont

Gathering System  limits stranded

pipeline assets/capital

Northern Access projects to

transport 660 MDth/d of Seneca-

operated WDA production by FY18

Integrated Vision for Long-term Growth

6

Exploration & Production

Pipeline & Storage

Gathering

1

2

3

1

2

Long-term, return-

driven approach

to developing vast

acreage position

Connecting Our

Production to Our

Interstate Pipeline

System

Expanding Our

Interstate Pipeline

System to Reach

Premium Markets

3

Appalachia

Exploration & Production

Appalachia

$631

$428

$520

$500

$370-$425

$110-$150

$80

$55

$138

$118

$100-$125

$85-$95

$144

$56

$140

$230

$500-$550

$125-$175

$855

$539

$798

$848

$970-$1,100

$320-$420

$0

$250

$500

$750

$1,000

$1,250

$1,500

2012

2013

2014

2015

2016E

(March '15)

2016E

(Current)

  Pipeline & Storage

  Gathering

  E&P - Appalachia

Appalachia Capital Reductions

7

Exercising Capital Flexibility and Discipline

to Respond to Commodity Price Environment

(1)

FY2016 Appalachia Capital Budget Cut 

$665 million, or 64%, since preliminary

budget released in March 2015

(1) Executed “Drill-Co” JDA

(2) 1-rig program

(3) Northern Access delay

KEY ACTIONS

(1)

FY2016 capital expenditure guidance reflects the netting of up-front proceeds received from joint development partner for capital spent on wells drilled and/or completed prior to the execution date of the

joint development agreement. The E&P segment’s FY16 capital budget would be reduced by an additional $90-$110 million if joint development partner exercises right to participate on remaining 38 wells.

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 40 for NFG consolidated capital expenditures.

Exploration & Production

Exploration & Production

Appalachia

Significant Appalachian Acreage Position

8

153

wells

able

to

produce

350

MMcf/d

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

83

wells

able

to

produce

255

MMcf/d

Large inventory of high quality Marcellus acreage

NFG midstream infrastructure supporting growth

660 MDth/d firm transportation by fiscal 2018

Mineral fee ownership enhances economics

Highly contiguous nature drives efficiencies

Seneca Lease

Seneca Fee

715,000 Acres

70,000 Acres

Western Development Area (WDA)

Eastern Development Area (EDA)

Exploration & Production

Appalachia

(1)

(1)

Exploration & Production

Appalachia

Marcellus Shale: Western Development Area

9

WDA Tier 1 Acreage –

200,000 Acres

WDA Tier 1 Marcellus Economics

(1)

WDA Highlights

Large drilling inventory of quality Marcellus dry gas

o

~1,200 locations economic < $2.50/MMBtu

NFG midstream infrastructure supporting growth

o

NFG Clermont Gathering System

o

660 MDth/d firm transport on NFG projects by FY18

Fee acreage enhances economics

o

No royalty on most acreage

o

No lease expirations or requirements to drill acreage

Highly contiguous position drives D&C efficiencies

o

Multi-well pad drilling averaging 10 wells per pad

o

Average lateral length to date = 7,800 ft.

o

Centralized water sourcing & disposal infrastructure

2 Utica tests expected in fiscal 2016/2017

SRC Fee Acreage

SRC Lease Acreage

SRC / EOG Earned

Acreage

Clermont/

Rich Valley

Hemlock

Ridgway

2

-

4 BCF/well

6 -

10 BCF/well

4 -

6 BCF/well

EUR Color Key

(1)

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.

Transaction

Seneca WDA Joint Development Agreement

10

Key Terms

On December 2, 2015, Seneca entered into an asset-level joint development agreement with IOG CRV-Marcellus

Capital, LLC, an affiliate of IOG Capital, LP, and funds managed by affiliates of Fortress Investment Group, LLC, to

jointly develop Marcellus Shale natural gas assets located in Elk, McKean and Cameron counties in north-central PA.

Assets: 80 current and future Marcellus development wells

in the Clermont/Rich Valley region of Seneca’s WDA.

Partner’s Initial Obligation: 42 wells

Partner Option: Partner has one-time option to participate

in remaining 38 wells on or before July 1, 2016.

Economics:

Partner participates as an 80% working interest

owner until the Partner achieves a 15% IRR hurdle. Seneca

retains a 7.5% royalty and remaining 20% working interest.

Strategic Rationale

Significantly reduces near-term upstream capital spending

Initial 42 wells

-

$200 million

(1)

38 well option -

$180 million

(1)

Validates quality of Seneca’s Tier 1 Marcellus WDA acreage

Seneca maintains current activity level driving additional

Marcellus drilling and completion efficiencies

Solidifies NFG’s midstream growth strategy:

Gathering

-

All production from JV wells will flow

through NFG Midstream’s Clermont Gathering System

Pipeline & Storage -

Provides production growth that

will utilize the 660 MDth/d of firm transportation

capacity on NFG’s Northern Access pipeline expansion

projects

Strengthens balance sheet and makes Seneca cash flow

positive in near-term

Marketing: Partner to receive same realized price before

hedging as Seneca on production from the joint

development wells, including firm sales and the cost of firm

transportation.

Interests on Initial 42

Wells

Seneca

Partner

Working Interest

20%

80%

Net Revenue Interest

26%

74%

(1)  Estimated reduction in capital expenditures from joint development agreement assumes current wells costs.

Exploration & Production

Appalachia

Exploration & Production

Appalachia

11

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

•

Current: 62 wells able to produce ~200 MMcf/d

•

200+ MMcf/d gross firm sales in fiscal 2016

•

Currently operating 2-rigs (down from 3 to start

year). Will drop to 1 rig in March 2016

•

Just-in-time gathering infrastructure build-out

provides significant capital flexibility based on

pace of Seneca’s development program

•

Regional focus of development minimizes capital

outlay and improve returns

Exploration & Production

Appalachia

Integrated WDA Development -

Upstream

Appalachia

Gathering

Integrated WDA Development -

Gathering

12

Current System In-Service

•

~44 miles of pipe/13,800 HP of compression

•

Current Capacity: 470 MMcf

per day    

•

Interconnects with TGP 300

•

Total CapEx

To Date: $235 million

Fiscal 2016 Build Out

•

FY16 CapEx: $60 to $75 million

•

Exit FY16 with > 52 miles of pipe installed and

>26,220 HP commissioned

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

•

Future third-party volume opportunities

Gathering System Build-Out Tailored

to Accommodate Seneca’s WDA Development

Clermont Gathering System Map

Appalachia

Pipeline & Storage

Integrated WDA Development -

Interstate Pipelines

13

(1) 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 2015

•

Customer: Seneca Resources (NFG)

•

In-Service: November 2015

(1)

•

System: NFG Supply Corp.

•

Capacity: 140,000 Dth per day

o

Leased to TGP as part of TGP’s

Niagara Expansion project

•

Interconnect

o

Niagara (TransCanada)

•

Total Cost: $67.5 Million

•

Major Facilities

o

23,000 hp Compression

Expanding Our Interstate Pipelines to Deliver Seneca’s WDA Production to Canada

Pipeline & Storage

Appalachia

14

Northern Access 2016

•

Customer: Seneca Resources (NFG)

•

In-Service: Now targeting Nov. 1, 2017

•

Capacity:  490,000 Dth/d

•

Interconnects:

o

o

TGP 200 –

East Aurora (140 MDth/d)

•

Total Cost: ~$455 Million

•

Major Facilities:

o

98.5 miles –

16/24” Pipeline

o

22,214 hp & 5,350 hp Compression

•

FERC Status

o

Pre-filing: July 2014

o

Certificate filing: March 2015

o

Certificate amendment filed Nov. 2015

Northern

Access

2016

to

Increase

Transport

Capacity

out of WDA to Canada by 490,000 Dth/d by FY18

Integrated WDA Development -

Interstate Pipelines

Chippawa

East Aurora

Pipeline

& Storage

Appalachia

TransCanada

–

Chippawa

(350

MDth/d)

Exploration & Production

Appalachia

$248

$148

$109

$91

$75

$0

$100

$200

$300

FY 2012

FY 2013

FY 2014

FY 2015

FY 2016

15

(1)

Excludes pad construction costs. FY 2016 well costs assume actual costs incurred through December 31, 2016  and projects costs for the remainder of the  fiscal year under the current cost structure.

(2)

Includes dollars spent to drill and complete development wells only. Excludes exploration and delineation wells.

$275

$208

$174

$153

$130

$0

$100

$200

$300

FY 2012

FY 2013

FY 2014

FY 2015

FY 2016

$8.7 MM

Well Cost

$4.9 MM

Well Cost

Fiscal 2012 Average Development Well

(1)

Fiscal 2016 Average Development Well

(1)

Lateral Length: 5,100 ft

Measured Depth: 13,700 ft

Completion Stages: 20

Lateral Length: 7,600 ft

Measured Depth: 14,300 ft

Completion Stages: 40

Drilling Cost per Foot

(2)

Completion Cost per Stage

(2)

(000s)

Marcellus Drilling and Completion Efficiencies

WDA Upstream & Midstream Development

16

WDA Well Costs

WDA Clermont / Rich Valley Economics

WDA Clermont / Valley Economics vs. NYMEX Futures Strip

$10.8

$9.6

$7.2

$5.8

$0

$5

$10

$15

FY 2013

FY 2014

FY 2015

FY 2016E

$2.94

$2.71

$2.22

$1.92

$0.00

$1.00

$2.00

$3.00

$4.00

FY 2013

FY 2014

FY 2015

FY 2016E

Normalized for a 8,800 ft. Lateral Length

Normalized for a 8,800 ft. Lateral Length

NA 2016 FT Cost

(2)

Northern Access 2016 In-Service (+490 Mdth/d)

(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. Assumes Dawn is on par with NYMEX.

(2)

Northern Access 2016 FT cost reflects $0.70 per Dth reservation charge and assumes approximately $0.06 per Dth of variable fees (commodity, fuel, etc.)

While Seneca has consistently driven down its well costs and break-even economics …

… near-term development pace modified to achieve value-added returns on investments 

NA 2016 1-year Delay

$0.76

Appalachia

$2.68

$1.92

$1.50

$2.00

$2.50

$3.00

$3.50

  NYMEX Futures Strip (2/2/16)

  CRV Break-even Realized Price

(1)

Realized

Price

Required

for

15%

IRR

Marcellus Shale: Eastern Development Area

17

(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

o

Tioga County, Pa. 

o

92 wells

(1)

with 110  MMcf/d productive capacity

o

75 MMcf/d firm sales/FT in FY16

o

NFG Covington Gathering System

o

Opportunity for future Geneseo & Utica dev.

DCNR Tract 100 & Gamble

o

Lycoming County, Pa. 

o

61 wells

(1)

with 240 MMcf/d productive capacity

o

130-185 MMcf/d firm sales/FT in FY16

o

Atlantic Sunrise capacity (190 MDth/d) in FY18

o

NFG Trout Run Gathering System

o

Geneseo to provide additional 100-120 locations

DCNR Tract 007

o

Tioga County, Pa. 

o

1 Utica and 1 Marcellus exploration well

o

Utica well 24 IP = 22.7 MMcf/d

o

Utica Resource potential  = ~1 Tcf

2

3

Exploration & Production

Appalachia

Integrated EDA Development -

Gathering

18

•

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): $166 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

Gathering

Appalachia

Utica/Point Pleasant: Industry Activity

19

Range

59 MMcf/d

Rice

42 MMcf/d

Shell

26.5 MMcf/d

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 FY16/17

Seneca -

DCNR 007

IP: 22.7 MMcf/d

CNX

61.9 MMcf/d

CNX

44 MMcf/d

Appalachia

Exploration & Production

Exploration & Production

Appalachia

Exploration & Production

Appalachia

Exploration & Production

20

32.8 Bcf

150 –

180 Bcfe

59.4 Bcf

29.3 Bcf

4.9 Bcf

0 -

30 Bcf

~21 Bcfe

2.5 Bcf

(3)

129 –

159 Bcf

0

50

100

150

200

250

Q1 East

Division

Production

Firm Sales +

Hedges

Fixed Price

Firm Sales

NYMEX

Firm Sales

(No Hedge)

Spot Sales

Production

Total

Appalachia

West Coast

(CA)

Total

Seneca

Production

Remaining FY16 Production

with Price Certainty

88.7 Bcf Realizing ~$3.25/Mcf

(1)

4.9 Bcf of Additional Basis Protection

(2)

Appalachia

Productive

Capacity

Seneca Total

Productive

Capacity

(1)

Average realized price reflects uplift from financial hedges less fixed differentials under firm sales contracts and firm transportation costs.

(2)

Indicates firm sales contracts with fixed index differentials to NYMEX but not backed by a matching NYMEX financial hedge.

(3)

Represents 2.5 Bcf of non-operated production from Western Development Area ..

FY 2016 Production -

Firm Sales & Spot Exposure

Exploration & Production

Appalachia

-

250

500

750

1,000

1,250

2016

2017

2018

2019

2020

2021

2022

2023

Fiscal Year Start

Significant Base of Long-Term Firm Contracts

21

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

Firm Sales

(2)

914,405 Dth per day

Total Gross Firm Contracts by FY2018

(1)

Includes capacity on both National Fuel Gas Supply Corp. and Empire Pipeline, Inc., both wholly owned subsidiaries of National Fuel Gas Company.

(2)

Includes base firm sales contracts not tied to firm transportation capacity.

Northeast Supply Diversification  50,000 Dth/d

Exploration & Production

Appalachia

28.5

29.5

20.4

11.4

14.1

12.7

19.0

22.1

30.4

32.9

8.0

5.8

92.0

97.2

30.2

17.2

4.9

0

50

100

150

FY 2016

FY 2017

FY 2018

FY 2019

FY 2020

NYMEX

Dominion

Dawn & MichCon

Fixed Price Physical Sales

Strong Hedge Book in Fiscal 2016 and 2017

22

FY 2016 = 78% hedged

(1)

at $3.53 per MMBtu

Natural Gas Swap & Fixed Physical Sales Contracts (Million MMBtu)

(3)

(2)

(2)

(1)

Assumes midpoint of natural gas production guidance, adjusted for year-to-date actual results.

(2)

For the remaining nine months ended September 30, 2016.

(3)

Fixed price physical sales exclude  joint development partner’s share of fixed price contract WDA volumes as specified under the joint development agreement.

Pipeline & Storage: Premier Appalachian Position

23

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 3

rd

party producers and shippers in Appalachia

Canada &

Michigan

New England

& Northeast

Midwest &

Southeast

Mid-Atlantic

Appalachia

Pipeline

& Storage

Appalachia

Pipeline & Storage

Recent 3

rd

Party Expansions Highly Successful

24

Expansions for 3

rd

Parties since 2010

Line N Projects

+633 MDth/d

Northern

Access 2012

+320 MDth/d

Empire & Lamont

Expansions

+489 MDth/d

3

rd

Party Expansion Capital Cost ($MM)

Annual Expansion Revenues Added ($MM)

$387 million

since FY 2010

1,442 MDth/d

since FY2010

$4

$37

$19

$4

$5

$25

~$95

$0

$25

$50

$75

$100

$125

FY11

FY12

FY13

FY14

FY15

FY16E

Cum.

$72

$132

$183

Northern Access 2012

Empire & Lamont

Line N Projects

Appalachia

Pipeline & Storage

Planned Empire System Expansion

25

Empire North Expansion Project

•

Target In-Service: Late 2018

•

System: Empire Pipeline

•

Target Market:

o

Marcellus & Utica producers in Tioga &

Potter County, Pa.

•

Open Season Capacity: 300,000 Dth/d

•

Delivery Points:

o

180,000 Dth/d to Chippawa

(TCPL)

o

Up to 158,000 Dth/d to Hopewell (TGP)

•

Estimated Cost: $185 million

•

Major Facilities:

o

3 new compressor stations

•

FERC Status:

o

Open Season concluded in Nov. 2015

o

Preparing precedent agreements

Appalachia

$111

$137

$161

$186

$188

$190

$10

$15

$30

$64

$69

$62

$121

$152

$191

$250

$257

$252

$0

$100

$200

$300

2011

2012

2013

2014

2015

TTM

12-31-2015

Fiscal Year

  Gathering

  Pipeline & Storage

Midstream Businesses EBITDA

26

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.

Downstream Overview

Utility  |  Energy Marketing

27

Downstream

New York & Pennsylvania Service Territories

28

(1)  As of September 30, 2015.

New York

Pennsylvania

Total Customers

(1)

: 526,323

ROE: 9.1% (NY PSC Rate Case Settlement, May 2014)

Rate Mechanisms:

o

Earnings Sharing

o

Revenue Decoupling

o

Weather Normalization

o

Low Income Rates

o

Merchant Function Charge (Uncollectibles

Adj.)

o

90/10 Sharing (Large Customers)

Total Customers

(1)

: 213,652

ROE: Black Box Settlement (2007)

Rate Mechanisms:

o

Low Income Rates

o

Merchant Function Charge

Downstream

Utility: Shifting Trends in Customer Usage

29

(1)  Weighted Average of New York and Pennsylvania service territories (assumes normal weather).

80

90

100

110

120

12-Months Ended December 31

20

25

30

35

40

12-Months Ended December 31

Residential Usage

Industrial Usage

Downstream

$152

$152

$152

$151

$163

$160

$16

$16

$20

$33

$28

$28

$11

$9

$6

$10

$9

$10

$179

$177

$178

$193

$200

$198

$0

$50

$100

$150

$200

$250

2011

2012

2013

2014

2015

12 Months

ended

12/31/15

Fiscal Year

  All Other O&M Expenses

  O&M Pension Expense

  O&M Uncollectible Expense

A Proven History of Controlling Costs

30

(1)

$10 million of increase in pension costs from fiscal 2013 primarily due to  the NY PSC rate case settlement in May 2014.

(1)

Downstream

The Utility

remains focused on maintaining the

ongoing safety and reliability of its system

Utility: Strong Commitment to Safety

31

Near-term increase due to

~$60MM upgrade of the Utility’s

Customer Information System

and anticipated acceleration of

pipeline replacement program

$44.3

$43.8

$48.1

$49.8

$54.4

$58.4

$58.3

$72.0

$88.8

$94.4

$95 -

$105

0

30

60

90

120

150

2011

2012

2013

2014

2015

2016E

Fiscal Year

Capital Expenditures for Safety

Total Capital Expenditures

32

32

California

Exploration & Production

California: Stable Production; Modest Growth

33

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

0

1,500

3,000

4,500

6,000

North

Midway

Sunset

South

Midway

Sunset

South Lost

Hills

North Lost

Hills

Sespe

East

Coalinga

FY 2010

FY 2015

Upstream

Upstream

8,773

9,322

9,078

9,699

9,674

9,560

0

2,500

5,000

7,500

10,000

2011

2012

2013

2014

2015

2016

Forecast

Fiscal Year

California Average Daily Net Production

34

$40-$50 Million Annual Capital Spending to Keep Production Flat

Upstream

Strong Margins Support Significant Free Cash Flow

35

$12.74

$3.37

$5.56

$2.90

$2.44

$33.83

Non-Steam Fuel LOE

Steam Fuel

G&A

Production & Other

Taxes

Other Operating Costs

Adjusted EBITDA

West Division Adjusted EBITDA per BOE

(1)

Trailing 12-months Ended 12/31/15

DD&A

Average Revenue

for TTM 12/31/15

(1)

$60.84 per BOE

(1)

Average revenue per BOE  includes impact of hedging and other revenues. 

Note: 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 ofthis presentation.

EBITDA per BOE includes Seneca corporate results and eliminations.

Consolidated Financial Overview

Upstream  |  Midstream  | Downstream

36

Corporate

Appalachia Driving Proved Reserve Growth

37

43.3

42.9

41.6

38.5

33.7

675

988

1,300

1,683

2,142

935

1,246

1,549

1,914

2,344

0

500

1,000

1,500

2,000

2,500

3,000

2011

2012

2013

2014

2015

At September 30

Natural Gas (Bcf)

Crude Oil (MMbbl)

Fiscal

Years

3-Year

F&D Cost

(2)

($/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

(1)

(1)

Includes approximately 150 Bcf of natural gas PUD reserves in Clermont/Rich Valley that will be transferred in fiscal 2016 as interests in the joint development wells are conveyed to the partner.

(2)

Represents a three-year average U.S. finding and development cost.

Corporate

Seneca Production

38

(1)

Refer to slide 20 for additional details on fiscal 2016 firm sales and local Appalachian spot market exposure.  

19.2

20.5

20.0

21.2

21.2

~21

43.2

62.9

100.7

139.3

136.6

129.0

Appalachia

Spot Sales

67.6

83.4

120.7

160.5

157.8

150 –

180 Bcfe

0

50

100

150

200

2011

2012

2013

2014

2015

2016E

Fiscal Year

Gulf of Mexico (Divested in 2011)

Appalachia Division

West Coast Division

(1)

Corporate

$169

$160

$172

$165

$164

$157

$111

$137

$161

$186

$188

$190

$64

$69

$62

$377

$397

$492

$539

$422

$378

$668

$704

$852

$953

$843

$785

$0

$250

$500

$750

$1,000

$1,250

2011

2012

2013

2014

2015

TTM

12/31/15

Fiscal Year

Exploration & Production Segment

Gathering Segment

Pipeline & Storage Segment

Utility Segment

Energy Marketing & Other

EBITDA Contribution by Segment

39

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.

Corporate

$58

$58

$72

$89

$94

$95-$105

$129

$144

$56

$140

$230

$125-$175

$80

$55

$138

$118

$85-$95

$649

$694

533

$603

$557

$150-$200

$854

$977

$717

$970

$1,001

$455-

$575

$0

$500

$1,000

$1,500

2011

2012

2013

2014

2015

2016E

Fiscal Year

Exploration & Production Segment

Gathering Segment

Pipeline & Storage Segment

Utility Segment

Energy Marketing & Other

Capital Expenditures by Segment

40

(1)

(1)

FY2016 capital expenditure guidance reflects the netting of up-front proceeds received from joint development partner for capital spent on wells drilled and/or completed prior to the execution date of the 

joint development agreement. The E&P segment’s FY16 capital budget would be reduced by an additional $90-$110 million if joint development partner exercises right to participate in remaining 38 wells.

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

Corporate

Financial Position & Liquidity

41

Note:  A reconciliation of Adjusted EBITDA to Net Income is included at the end of this presentation.

Total

Debt

54%

$3.9 Billion Total Capitalization

as of December 31, 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 12/31/15

Total Liquidity at 12/31/15

$ 1,250 MM

$ 31 MM

$ 1,219 MM

$ 36 MM

$ 1,255 MM

Total

Equity

46%

1.75 x

1.89 x

1.89 x

1.77 x

2.27 x

2.52 x

2011

2012

2013

2014

2015

TTM            

12-31-15

Fiscal Year

$300

$250

$500

$549

$500

$0

$200

$400

$600

Corporate

Dividend Track Record

42

(1) As of February 3, 2016.

Current

Dividend Yield

(1)

3.4%

Dividend Consistency

Consecutive Dividend Payments

113 Years

Consecutive Dividend Increases

45 Years

Current

Annualized Dividend Rate

$1.58

per Share

$0.00

$0.50

$1.00

$1.50

$2.00

Annual Rate at Fiscal Year End

Appendix

43

43

Appendix

2015 Pipeline Expansion Projects In-Service

44

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

million on 49,000 Dth per day capacity

•

Preserves $16.1 million in annual revenues

on existing FT (192,500 Dth/d) and retained

storage (3.3 Bcf) services

•

Total Cost: $86 million

o

Expansion: $45 million

o

Modernization: $41 million

•

Incremental Annual Revenues: $8.8 million

•

Capacity: 175,000 Dth per day

o

Range Resources (145,000 Dth/d)

o

Seneca Resources (30,000 Dth/d)

Tuscarora

Lateral

Westside

Expansion &

Modernization

Appendix

Total Seneca Capital Spending by Division

45

$47

$63

$105

$83

$57

$40-$50

$596

$631

$428

$520

$500

$110-

$150

$649

$694

$533

$603

$557

$150 -

$200

$0

$200

$400

$600

$800

$1,000

2011

2012

2013

2014

2015

2016E

Fiscal Year

Gulf of Mexico (Divested in 2011)

Appalachia

West Coast (California)

(2)

(1)

(1)

FY2016 capital expenditure guidance reflects the netting of up-front proceeds received from joint development partner for capital spent on wells drilled and/or completed prior to the execution date of the joint

development agreement. The FY16 capital budget would be reduced by an additional $90-$110 million if joint development partner exercises right to participate in remaining 38 wells.

(2)

Seneca’s West Coast division includes Seneca corporate and eliminations.

Exploration & Production

Appalachia

Marcellus Operated Well Results

46

EDA Development Wells:

Area

Producing

Well

Count

Average IP Rate

(MMcfd)

Average

30-Day (MMcf/d)

Average Treatable

Lateral Length (ft)

Covington

Tioga

County

47

5.2

4.1

4,023’

Tract 595

Tioga

County

44

(2)

7.4

4.9

4,754’

Tract 100

Lycoming

County

57

(2)

16.8

12.6

5,270’

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

56

(1)

7.5

5.7

(1)

6,823’

WDA Development Wells:

(1)

Excludes 2 wells now operated by Seneca that were drilled by another operator as part of a joint-venture.  30-day average excludes 2 wells that have not been on line 30 days.

(2)

Does not include 1 well drilled into and producing from the Geneseo Shale.

Appendix

$0.91

$0.76

$0.65

$0.57

$0.57

$0.55

$0.17

$0.24

$0.34

$0.46

$0.49

$0.50

$0.73

$0.65

$0.52

$0.40

$0.42

$0.43

$0.18

$0.28

$0.14

$0.13

$0.13

$0.13

$2.09

$2.01

$1.74

$1.65

$1.70

~$1.68

$0.00

$1.00

$2.00

$3.00

2011

2012

2013

2014

2015

2016E

Fiscal Year

Property, Franchise & Other Taxes

Other O&M Expense

General & Administrative Expense

Lease Operating & Transportation Expense (Gathering Only)

Lease Operating & Transportation Expense (Excl. Gathering)

Highly Competitive Cost Structure

47

(1)

(2)

(2)

(3)

(1)

(2)

(2)

(1)

Represents the midpoint of General & Administrative Expense guidance of $0.40 to $0.45 per Mcfe for fiscal 2016.

(2)

The total of the two LOE components represents the midpoint of LOE guidance of $1.00  to $1.10 per Mcfe for fiscal 2016.

(3)

The cost of firm transportation is reflected in price realizations (a deduction to gross revenues). As such, it is not included in LOE.

Appendix

Marcellus Shale Program Economics

~1,200 WDA Locations Economic Below $2.50/MMBtu

$3.25

IRR %

(1)

$3.00

IRR %

(1)

$2.75

IRR %

(1)

DCNR 100

Dry Gas

12

5,400

13-14

1033

78%

59%

43%

$1.57

Gamble

Dry Gas

44

4,600

11-12

1033

47%

35%

22%

$1.83

CRV

Dry Gas

72

8,800

10-11

1045

32%

23%

17%

$1.92

Hemlock /

Ridgway

Dry Gas

662

8,800

8-9

1045 - 1110

23%

16%

11%

$2.14

Remaining

Tier 1

Dry Gas

423

8,500

7-8

1030 - 1110

21%

14%

10%

$2.31

15% IRR

(1)

Realized Price

NYMEX / DAWN Pricing

Prospect

Product

Locations

Remaining

to Be Drilled

Completed

Lateral

Length (ft)

Average

EUR (Bcf)

BTU

(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.

48

Appendix

Firm Transportation Portfolio

49

(1)

A large majority of the  executed firm sales agreements continue for the remainder of the firm transportation contract term.

(2)

Excludes throughput-based commodity charges, fuel charges and other surcharges.

Project

(Counterparty)

In-

Service

Date

Contract

Term

Delivery

Market

Demand

Charge

($/Dth)

Gross 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

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)

Northern Access

2016 (NFG/

TransCanada/

Union)

Nov.

2017

15 years

Canada

$0.70

---

---

350,000

Executed Contracts

145,000 Dth/d

For first 3 years

TGP 200

(NY)

$0.38

---

---

140,000

Total Firm Transportation Capacity

220,000

220,000

899,405

Weighted Average

Transportation Charge per Dth

(2)

$0.59

$0.60

$0.63

Appendix

219,698

Plus $0.07

178,098

Less: $0.01

178,098

Less:  $0.01

65,000  Less: $0.55

50,000  Less: $0.33

50,000  Less: $0.33

25,000  Less: $0.02

65,000  Less: $0.01

65,000  Less: $0.01

160,000

$2.78

175,000

$2.61

175,000

$2.61

469,698

468,098

468,098

0

200,000

400,000

600,000

Q2

Q3

Q4

Fixed Price

Dawn

Dominion SP

NYMEX

Firm Sales Provide Market for Appalachian Production

50

(1)

Reflects gross firm sales volumes before impact of lease royalties  in EDA or  net revenue interests assigned to  joint development partner  on certain contracts in WDA.

(2)

Values shown represent the price or differential to a reference price (netback price) at the point of sale.

WDA

(1)

209,600/d

263,000/d

263,000/d

EDA

(1)

260,098/d

205,098/d

205,098/d

Fiscal 2016 Firm Sales by Fiscal Quarter

Pricing Index Key:

EDA/WDA Split:

Gross

Contracted

Volumes

(Dth

per

day)

(1)

Contracted

Index

Price

Differentials

($

per

Dth)

(2)

Exploration & Production

Appalachia

$3.35

$3.99

$3.18

$2.83

$2.77

$2.62

$2.46

$2.02

NFG

P1

P2

P3

P4

P5

P6

P7

Before Hedging

Hedging Uplift

$2.06

$2.06

$1.85

$1.58

$1.57

$1.18

$0.86

$0.77

NFG

P1

P2

P5

P4

P7

P6

P3

Peer Average

$1.41/Mcfe

Appalachian Price Realizations & Margins

51

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

(1)

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.

(2)

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.

Appendix

Volume

Avg.

Price

Volume

Avg.

Price

Volume

Avg.

Price

Volume

Avg.

Price

Volume

Avg.

Price

NYMEX Swaps

28,440

$3.92

29,530

$4.20

20,350

$3.62

11,400

$3.39

2,000

$3.49

Dominion

Swaps

14,130

$3.78

12,720

$3.87

-

-

-

-

-

-

MichCon Swaps

9,000

$4.10

3,000

$4.10

-

-

-

-

-

-

Dawn Swaps

9,990

$3.92

19,100

$3.70

1,800

$3.40

-

-

-

-

Fixed Price

Physical Sales

30,426

$2.75

32,893

$3.03

8,010

$3.21

5,840

$3.25

2,928

$3.25

Total

91,986

$3.53

97,243

$3.66

30,160

$3.50

17,240

$3.34

4,928

$3.35

Fiscal 2019

Fiscal 2020

Fiscal 2016

Fiscal 2017

Fiscal 2018

Natural Gas Hedge Positions

52

(Volumes in thousands MMBtu; Prices in $/MMBtu)

(1)

For the remaining nine months of Fiscal 2016.

(2)

Fixed price physical sales exclude joint development partner’s share of fixed price contract WDA volumes as specified under the joint development agreement.

(1)

(2)

Appendix

Crude Oil Hedge Positions

53

Fiscal 2016

Fiscal 2017

Fiscal 2018

Volume

Avg.

Price

Volume

Avg.

Price

Volume

Avg.

Price

Brent Swaps

404,000

$94.63

231,000

$92.14

51,000

$91.00

NYMEX Swaps

640,000

$83.33

465,000

$66.77

24,000

$90.52

Total

1,044,000

$87.70

696,000

$75.19

75,000

$90.85

(Volumes & Prices in Bbl)

(1)

For the remaining nine months of Fiscal 2016.

(1)

Utica/Point Pleasant: EDA Opportunities

54

Shell: Gee

11.2 MMcf/d

PGE

Vertical Tests

Permitted

Drilling

Completed

Producing

Seneca

Horizontal

Planned

or Potential

Shell: Neal

26.5 MMcf/d

Other Operators

DCNR Tract 001

Potential Future Location

DCNR 595

Potential Future Location

JKLM

Pt Pleasant Test

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.) 

Travis Peak:

Currently Drilling

Appendix

Comparable GAAP Financial Measure Slides & Reconciliations

55

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.

Appendix

National Fuel Gas Company

56

Reconciliation of Adjusted EBITDA to Consolidated Net Income

($ Thousands)

FY 2011

FY 2012

Total Adjusted EBITDA

Exploration & Production Adjusted EBITDA

377,457

$           

397,129

$           

492,383

$              

539,472

$              

422,289

$              

377,998

Pipeline & Storage Adjusted EBITDA

111,474

136,914

161,226

186,022

188,042

189,890

Gathering Adjusted EBITDA

9,386

14,814

29,777

64,060

68,783

62,478

Utility Adjusted EBITDA

168,540

159,986

171,669

164,643

164,037

156,524

Energy Marketing Adjusted EBITDA

13,178

5,945

6,963

10,335

12,150

9,355

Corporate & All Other Adjusted EBITDA

(12,346)

(10,674)

(9,920)

(11,078)

(11,900)

(11,391)

Total Adjusted EBITDA

667,689

$           

704,114

$           

852,098

$              

953,454

$              

843,401

$              

784,854

$        

Total Adjusted EBITDA

667,689

$           

704,114

$           

852,098

$              

953,454

$              

843,401

$              

784,854

$        

Minus: Interest Expense

(78,121)

(86,240)

(94,111)

(94,277)

(99,471)

(108,122)

Plus:  Interest and Other Income

8,863

8,822

9,032

13,631

11,961

13,737

Minus: Income Tax Expense

(164,381)

(150,554)

(172,758)

(189,614)

319,136

518,646

Minus: Depreciation, Depletion & Amortization

(226,527)

(271,530)

(326,760)

(383,781)

(336,158)

(303,962)

Minus: Impairment of Oil and Gas Properties (E&P)

-

-

-

-

(1,126,257)

(1,561,708)

Plus: Reversal of Stock-Based Compensation

-

-

-

-

7,961

7,961

Plus: Gain on Sale of Unconsolidated Subsidiaries (Corp. & All Other)

50,879

-

-

-

-

-

Plus: Elimination of Other Post-Retirement Regulatory Liability (P&S)

-

21,672

-

-

-

-

Minus: Pennsylvania Impact Fee Related to Prior Fiscal Years (E&P)

-

(6,206)

-

-

-

-

Minus: New York Regulatory Adjustment (Utility)

-

-

(7,500)

-

-

-

Rounding

-

(1)

-

-

-

-

Minus: Joint Development Agreement Professional Fees

-

-

-

-

-

(4,682)

Consolidated Net Income

258,402

$           

220,077

$           

260,001

$              

299,413

$              

(379,427)

$            

(653,276)

$       

Consolidated Debt to Total Adjusted EBITDA

Long-Term Debt, Net of Current Portion (End of Period)

899,000

$           

1,149,000

$        

1,649,000

$          

1,649,000

$          

2,099,000

$          

2,099,000

$     

Current Portion of Long-Term Debt (End of Period)

150,000

250,000

-

-

-

-

Notes Payable to Banks and Commercial Paper (End of Period)

40,000

171,000

-

85,600

-

31,400

Total Debt (End of Period)

1,089,000

$        

1,570,000

$        

1,649,000

$          

1,734,600

$          

2,099,000

$          

2,130,400

$     

Long-Term Debt, Net of Current Portion (Start of Period)

1,049,000

$        

899,000

1,149,000

1,649,000

1,649,000

1,649,000

Current Portion of Long-Term Debt (Start of Period)

200,000

150,000

250,000

-

-

-

Notes Payable to Banks and Commercial Paper (Start of Period)

-

40,000

171,000

-

85,600

172,900

Total Debt (Start of Period)

1,249,000

$        

1,089,000

$        

1,570,000

$          

1,649,000

$          

1,734,600

$          

1,821,900

$     

Average Total Debt

1,169,000

$        

1,329,500

$        

1,609,500

$          

1,691,800

$          

1,916,800

$          

1,976,150

$     

Average Total Debt to Total Adjusted EBITDA

1.75 x

1.89 x

1.89 x

1.77 x

2.27 x

2.52 x

FY 2013

12-Months

Ended 12/31/15

FY 2014

FY 2015

Appendix

National Fuel Gas Company

57

Reconciliation of Exploration & Production - West Coast division Adjusted EBITDA per Mboe of Production

($ Thousands)

12-Months

Ended 12/31/15

Appalachia Division Adjusted EBITDA

259,134

$        

West Coast Division Adjusted EBITDA

118,864

Total Exploration & Production Adjusted EBITDA

377,998

$        

West Coast Division Adjusted EBITDA

118,864

$        

West Coast Production (Mboe)

3,514

West Coast Division Adjusted EBITDA per Mboe

33.83

$           

Note: Seneca West Coast division includes Seneca corporate and eliminations.

Appendix

National Fuel Gas Company

58

(1)

FY2016  Exploration and Production capital expenditure guidance reflects the netting of up-front proceeds received from joint development partner for capital spent on wells drilled and/or

completed prior to the execution date of the joint development agreement.

Reconciliation of Segment Capital Expenditures to

Consolidated Capital Expenditures

($ Thousands)

FY 2016

FY 2011

FY 2012

FY 2013

FY 2014

FY 2015

Forecast

Capital Expenditures from Continuing Operations

Exploration & Production Capital Expenditures

648,815

$        

693,810

$        

533,129

$        

602,705

$        

557,313

$        

$150,000-200,000

Pipeline & Storage Capital Expenditures

129,206

144,167

56,144

$          

139,821

$        

230,192

$        

$125,000-175,000

Gathering Segment Capital Expenditures

17,021

80,012

54,792

$          

137,799

$        

118,166

$        

$85,000-95,000

Utility Capital Expenditures

58,398

58,284

71,970

$          

88,810

$          

94,371

$          

$95,000-105,000

Energy Marketing, Corporate & All Other Capital Expenditures

746

1,121

1,062

$            

772

$                

467

$                

-

Total Capital Expenditures from Continuing Operations

854,186

$        

977,394

$        

717,097

$        

969,907

$        

1,000,509

$    

$455,000-575,000

Capital Expenditures from Discountinued Operations

All Other Capital Expenditures

-

$                 

-

$                 

-

$                 

-

$                 

-

$                 

-

$                               

Plus (Minus) Accrued Capital Expenditures

Exploration & Production FY 2015 Accrued Capital Expenditures

-

$                  

-

$                  

-

$                  

-

$                  

(46,173)

$         

Exploration & Production FY 2014 Accrued Capital Expenditures

-

-

-

(80,108)

80,108

Exploration & Production FY 2013 Accrued Capital Expenditures

-

-

(58,478)

58,478

-

-

Exploration & Production FY 2012 Accrued Capital Expenditures

-

(38,861)

38,861

-

-

-

Exploration & Production FY 2011 Accrued Capital Expenditures

(103,287)

103,287

-

-

-

-

Exploration & Production FY 2010 Accrued Capital Expenditures

78,633

-

-

-

-

-

Pipeline & Storage FY 2015 Accrued Capital Expenditures

-

-

-

-

(33,925)

Pipeline & Storage FY 2014 Accrued Capital Expenditures

-

-

-

(28,122)

28,122

Pipeline & Storage FY 2013 Accrued Capital Expenditures

-

-

(5,633)

5,633

-

-

Pipeline & Storage FY 2012 Accrued Capital Expenditures

-

(12,699)

12,699

-

-

-

Pipeline & Storage FY 2011 Accrued Capital Expenditures

(16,431)

16,431

-

-

-

-

Pipeline & Storage FY 2010 Accrued Capital Expenditures

3,681

-

-

-

-

-

Gathering FY 2015 Accrued Capital Expenditures

-

-

-

-

(22,416)

Gathering FY 2014 Accrued Capital Expenditures

-

-

-

(20,084)

20,084

Gathering FY 2013 Accrued Capital Expenditures

-

-

(6,700)

6,700

-

-

Gathering FY 2012 Accrued Capital Expenditures

-

(12,690)

12,690

-

-

-

Gathering FY 2011 Accrued Capital Expenditures

(3,079)

3,079

-

-

-

-

Utility FY 2015 Accrued Capital Expenditures

-

-

-

-

(16,445)

Utility FY 2014 Accrued Capital Expenditures

-

-

-

(8,315)

8,315

Utility FY 2013 Accrued Capital Expenditures

-

-

(10,328)

10,328

-

-

Utility FY 2012 Accrued Capital Expenditures

-

(3,253)

3,253

-

-

-

Utility FY 2011 Accrued Capital Expenditures

(2,319)

2,319

-

-

-

-

Utility FY 2010 Accrued Capital Expenditures

2,894

-

-

-

-

-

Total Accrued Capital Expenditures

(39,908)

$         

57,613

$          

(13,636)

$         

(55,490)

$         

17,670

$          

-

$                               

Eliminations

-

$                 

-

$                 

-

$                 

-

$                 

-

$                 

-

$                               

Total Capital Expenditures per Statement of Cash Flows

814,278

$        

1,035,007

$    

703,461

$        

914,417

$        

1,018,179

$    

$455,000-575,000

(1)

Appendix

National Fuel Gas Company

59

Reconciliation of Exploration & Production Adjusted EBITDA for Appalachia and West Coast divisions

to Exploration & Production Segment Net Income

($ Thousands)

Appalachia

West Coast

Total E&P

Appalachia

West Coast

Total E&P

Appalachia

West Coast

Total E&P

Appalachia

West Coast

Total E&P

Reported GAAP Earnings

(144,511)

$    

(62,508)

$      

(207,019)

$    

12,104

$        

21,557

$        

33,661

$        

(378,594)

$    

(178,380)

$    

(556,974)

$    

47,962

$        

73,607

$        

121,569

$     

Depreciation, Depletion and Amortization

36,837

9,440

46,277

65,422

15,609

81,031

188,489

51,329

239,818

238,541

57,669

296,210

Interest and Other Income

-

(661)

(661)

-

(604)

(604)

-

(2,554)

(2,554)

-

(1,909)

(1,909)

Interest Expense

13,613

563

14,176

9,977

607

10,584

44,798

1,928

46,726

40,015

2,217

42,232

Income Taxes

(123,825)

(45,796)

(169,621)

(4,190)

18,336

14,146

(295,912)

(132,305)

(428,217)

18,179

63,191

81,370

Impairment of Oil and Gas Producing Properties

285,038

132,159

417,197

-

-

-

730,115

396,142

1,126,257

-

-

-

Reversal of Stock Based Compensation

(825)

(1,942)

(2,767)

-

-

-

(825)

(1,942)

(2,767)

-

-

-

Adjusted EBITDA

66,327

$        

31,255

$        

97,582

$        

83,313

$        

55,505

$        

138,818

$     

288,071

$     

134,218

$     

422,289

$     

344,697

$     

194,775

$     

539,472

$     

Appalachia

West Coast

Total E&P

Appalachia

West Coast

Total E&P

Appalachia

West Coast

Total E&P

Appalachia

West Coast

Total E&P

Production:

Gas Production (MMcf)

32,183

785

32,968

40,456

808

41,264

136,404

3,159

139,563

139,097

3,210

142,307

Oil Production (MBbl)

8

770

778

8

774

782

30

3,004

3,034

31

3,005

3,036

Total Production (Mmcfe)

32,231

5,405

37,636

40,504

5,452

45,956

136,584

21,183

157,767

139,283

21,240

160,523

Adjusted EBITDA Margin per Mcfe

2.06

$            

5.78

$            

2.59

$            

2.06

$            

10.18

$          

3.02

$            

2.11

$            

6.34

$            

2.68

$            

2.47

$            

9.17

$            

3.36

$            

Total Production (Mboe)

5,372

901

6,273

6,751

909

7,660

22,764

3,531

26,295

23,214

3,540

26,754

Adjusted EBITDA Margin per Boe

12.35

$          

34.69

$          

15.56

$          

12.34

$          

61.06

$          

18.12

$          

12.65

$          

38.01

$          

16.06

$          

14.85

$          

55.02

$          

20.16

$          

Note: Seneca West Coast division includes Seneca corporate and eliminations.

Three Months Ended

September 30, 2015

Three Months Ended

September 30, 2014

Twelve Months Ended

September 30, 2015

Twelve Months Ended

September 30, 2014