Investor Presentation

Q3 Fiscal 2016 Update

August 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;

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;

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;

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

Forms

10-Q

for

the

quarters

ended

December

31,

2015,

March

31,

2016

and

June

30,

2016.

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.

•

2.3 Tcfe

Proved Reserves

(1)

•

785,000 net acres in Marcellus Shale

•

3 million Bbls/year of crude oil

production in California

3

(1)

Total proved reserves are as of September 30, 2015.

(2)

For the trailing twelve months ended June 30, 2016. 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.

National Fuel Gas Company

Quality Assets  |  Exceptional Location  | Unique Integration

•

$267 million annual 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

•

Generates operational and financial

synergies with other segments

Upstream

Midstream

Downstream

200,000 “Tier 1” fee-held acres in Pa.

1,100 locations economic < $2.00/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 in Appalachia

4

Exploration & Production

Pipeline & Storage

Gathering

1

2

3

1

2

Long-term, return-

driven approach

to developing vast

Marcellus & Utica

acreage position

Connecting Our

Production to Our

Interstate Pipeline

System

Expanding Our

Interstate Pipeline

System to Reach

Premium Markets

3

FY 2017 Capital Budget and Operating Plan

5

(1)

Upstream

Capital Expenditures by Segment ($MM)

FY2017 Operating Plan Highlights

Appalachia: 1-rig program / daylight-only frac

crew

FY17 development pace is designed to utilize

680Mdth/d of new FT available in FY18

Flexibility to accelerate D&C to grow into FT efficiently

California: $35-

$45 million capex

to keep production flat

Midstream

Downstream

Utility: Planning to accelerate pipeline replacement in NY

from 90 miles to 110 miles per year

Gathering: Just-in-time installation of gathering pipelines

and compression facilities to accommodate Seneca growth

Pipeline & Storage: Construction of Northern Access

$455 million project (~$300mm to be spent in FY17)

Remain on track to receive regulatory approvals          

for Nov. 2017 in-service

Note:

A

reconciliation

to

Capital

Expenditures

as

presented

on

the

Consolidated

Statement

of

Cash

Flows

is

included

at

the

end

of

this

presentation.

$94

$90 -

$100

$90 -

$100

$230

$125 -

$140

$400 -

$450

$118

$55 -

$65

$75 -

$85

$557

$120 -

$135

$160 -

$200

$1,001

$390 -

$440

$725 -

$835

$0

$500

$1,000

$1,500

2015

2016 

Forecast

2017

Forecast

Exploration & Production Segment

Gathering Segment

Pipeline & Storage Segment

Utility Segment

Energy Marketing & Other

(1) FY 2016 and FY 2017 capital expenditure guidance reflects the netting of up-front and recurring proceeds received from joint development partner for working interest in joint development wells.

Corporate

Unique Asset Mix and Integrated Model Provide Balance and Stability

The National Fuel Value Proposition

6

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

Appalachia Overview

Exploration & Production  |  Gathering  |  Pipeline & Storage

7

Exploration & Production

Appalachia

Significant Appalachian Acreage Position

8

•

153 wells able to produce 280 MMcf/d

•

50-60 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

Eastern Development Area (EDA)

70,000 Acres

Western Development Area (WDA)

715,000 Acres

•

125 wells able to produce 290 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

Exploration & Production

Appalachia

Marcellus Shale: Western Development Area

9

(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 well designs assume 8,000 ft. lateral.  Hemlock/Ridgway well designs assume 8,800 ft. lateral.  Other Tier 1 well designs assume 8,500 ft. lateral.  All well designs assume 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

54

8.5-9.5

22%

$1.94

Hemlock/Ridgway

636

8-9

22%

$1.97

Other Tier 1

406

7-8

21%

$1.99

Large drilling inventory of quality Marcellus dry gas

o

~1,100 locations economic < $2.00/MMBtu realized

NFG midstream infrastructure supporting growth

o

NFG Clermont Gathering System

o

660 MDth/d firm transport on NFG projects by FY18

Fee acreage provides flexibility/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

3 additional Utica tests expected in fiscal 2016/2017

Clermont/

Rich Valley

Hemlock

Ridgway

2

-

4 BCF/well

7-

9.5 BCF/well

4 -

6 BCF/well

EUR Color Key

Exploration & Production

Appalachia

Transaction

Seneca WDA Joint Development Agreement

10

Key Terms

On June 13, 2016, Seneca announced the extension of asset-level joint development agreement with IOG CRV -

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

LLC, to jointly develop Marcellus Shale natural gas assets located in the Western Development Area.

Assets: 75 current and future Marcellus development wells

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

Locations Developed Under Initial Obligation: 39 wells

Remaining Locations to be Developed: 36 wells

Partner Option: IOG has one-time option to participate in a

7-well pad to be completed before December 31, 2017

Economics:

IOG participates as an 80% working interest

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

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

Strategic Rationale

Significantly reduces near-term upstream capital spending

Initial 39 wells

-

$170 million

(1)

Remaining 36 wells -

$155 million

(1)

Validates quality of Seneca’s Tier 1 Marcellus WDA acreage

Seneca maintains activity levels to continue to drive

Marcellus drilling and completion efficiencies

Solidifies NFG’s midstream growth strategy:

Gathering

-

All production from JV wells will flow

through NFG Midstream’s Clermont Gathering System

Pipeline & Storage -

Provides production growth that

will utilize the 660 MDth/d of firm transportation

capacity on NFG’s Northern Access pipeline expansion

projects available starting Nov. 1, 2017

Strengthened balance sheet and makes Seneca cash flow

positive in near-term

Natural Gas Marketing: IOG to receive same realized price

before hedging as Seneca on production from the joint

development wells, including firm sales and the cost of firm

transportation.

Seneca

IOG

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

Integrated

WDA

Development

-

Upstream

11

Clermont/Rich Valley Development Map

CRV Development Summary

•

Current: 103 wells able to produce ~280 MMcf/d

•

Dropped to 1 rig in March 2016 (down from 3 rigs

to start fiscal 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 improves returns

Exploration & Production

Appalachia

Best in Class Marcellus Well Costs

12

(1)

Appalachian peers include AR, COG, EQT, RICE, RRC & SWN. Data obtained or recalculated from most recent peer company presentations.

$248

$148

$109

$91

$70

$0

$100

$200

$300

FY 2012

FY 2013

FY 2014

FY 2015

FY 2016E

$275

$208

$174

$153

$120

$0

$100

$200

$300

FY 2012

FY 2013

FY 2014

FY 2015

FY 2016E

Marcellus Drilling Cost per Foot

Marcellus Completion Cost per Stage ($000s)

Average

Marcellus

Well

Costs

vs.

Appalachian

Peers

(1)

$5,300

$5,700

$5,630

$6,545

$5,700

$8,100

$7,350

8,000

7,000

6,876

7,700

6,500

9,000

7,500

Avg. Well Cost ($000s)

Avg. Lateral Length (ft)

WDA Acreage Position & Operational Efficiencies Driving Best-in-Class Well Costs in Marcellus

Peer Average

$873 per lateral ft

$663

$814

$819

$850

$877

$900

$980

$500

$600

$700

$800

$900

$1,000

Seneca

CRV

Peer 1

Peer 2

Peer 3

Peer 4

Peer 5

Peer 6

Appalachia

Gathering

Integrated

WDA

Development

-

Gathering

13

Current System In-Service

•

~67 miles of pipe/26,220 HP of compression

•

Current Capacity: 470 MMcf

per day    

•

Interconnects with TGP 300

•

Total CapEx

To Date: $254 million

Fiscal 2017 Build Out

•

Remaining FY16 CapEx: $8-12 million

•

FY17 CapEx: $75 to $85 million

•

Adjusted timing of gathering & compression

investment to match Seneca’s modified

development schedule/Northern Access

Future Build-Out

•

Ultimate capacity can exceed 1 Bcf/d

•

Over 300 miles of pipelines and five

compressor stations (+60,000 HP installed)

•

Deliverability into TGP 300 and NFG Supply

Gathering System Build-Out Tailored

to Accommodate Seneca’s WDA Development

Clermont Gathering System Map

Appalachia

Pipeline & Storage

Integrated WDA Development -

Interstate Pipelines

14

(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

•

Delivery Interconnect:

o

Niagara (TransCanada)

•

Major Facilities:

o

23,000 hp Compression

•

Total Cost: $67.1 million

•

Annual Revenues: $13.3 million

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

Niagara

Appalachia

Pipeline & Storage

15

Northern Access 2016

•

Customer: Seneca Resources (NFG)

•

In-Service: Now targeting Nov. 1, 2017

•

Capacity:  490,000 Dth/d

•

Receipt Interconnect:

o

Clermont Gathering System (McKean Pa.)

•

Delivery Interconnects:

o

TransCanada –

Chippawa

(350 MDth/d)

o

TGP 200 –

East Aurora (140 MDth/d)

•

Total Expected Cost: ~$455 Million

•

Major Facilities:

o

98.5 miles –

16” & 24” Pipeline

o

22,214 hp & 5,350 hp Compression

•

FERC/Regulatory Status:

o

FERC Environmental Assessment received

7/27/16 –

Certificate expected late 2016

o

NY DEC 401 Water Quality permit

expected March 2017

Northern Access 2016

to Increase Transport

Capacity Out of WDA by 490,000 Dth/d by FY18

Integrated WDA Development -

Interstate Pipelines

Chippawa

East Aurora

Exploration & Production

Appalachia

Marcellus Shale: Eastern Development Area

16

(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)

o

Marcellus locations fully developed

o

92 wells

(1)

with 90 MMcf/d productive capacity

o

70-80 MDth/d firm sales in FY17

o

NFG Covington Gathering System

o

Opportunity for future Geneseo & Utica dev.

DCNR Tract 100 & Gamble (Lycoming)

o

61 wells

(1)

with 190 MMcf/d productive capacity

o

115-155 MDth/d firm sales in FY17

o

Atlantic Sunrise capacity (190 MDth/d) in FY18

o

NFG Trout Run Gathering System

o

Geneseo well 24 IP test: 14.1MMcf/d on 4,920’ lat

o

Geneseo to provide 100-120 additional locations

DCNR Tract 007 (Tioga)

o

1 Utica and 1 Marcellus exploration well

o

Utica well 24 IP test: 22.7 MMcf/d

o

Expected to be placed on-line in Nov. 2016

o

Utica to provide 70 additional locations

o

Utica Resource potential  = ~1 Tcf

2

3

FY 2017 D&C Plans

Drill 9 and complete 4 Marcellus

wells in Gamble to hold acreage

and prepare for Atlantic Sunrise

capacity (190MDth/d) in FY 2018

Appalachia

Gathering

Integrated

EDA

Development

-

Gathering

17

•

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

•

In-Service Date: May 2012

•

Capital Expenditures (to date): $167 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

Interconnects

Exploration & Production

Appalachia

Utica Shale Opportunities in WDA

18

Permitted

Drilling

Completed

Production

SRC Vertical

SRC Vertical

+ Horizontal

SRC Planning

2.6 Bcf

2.4 Bcf

1.9 Bcf

1.6 Bcf

1.9 Bcf

1.6 Bcf

SRC –

CRV

June 2016 Test 

1.6 Bcf

2.2 Bcf

SRC –

Tract 007

March 2015 Test

2.4 Bcf

1

st

Clermont Rich Valley Utica Well Test On Trend with Northeast Pa. Results 

Northeast Pa. Utica Well Results

Estimated EUR/1,000 ft

(1)

CRV Utica Test Well Results

WDA vs. Tioga County

WDA

Tioga County, Pa.

SRC -

CRV

SRC

Tract 007

Industry

Average

Gross EUR/1,000 ft

1.6 Bcf

2.4 Bcf

2.0 Bcf

Approx. NRI %

100%

82%

82%

Net EUR/1,000 ft

1.6 Bcf

2.0 Bcf

1.6 Bcf

Seneca tested 1

Utica well off 10-well Marcellus

pad in Clermont Rich Valley in June 2016:

Lateral length = 4,500 ft

30 day avg. IP /1,000 ft = 1.4 MMcf/d

Estimated EUR/1,000 ft = 1.6 Bcf

Seneca’s CRV Utica also benefits from fee acreage

Next Steps

Next CRV Utica test expected in Q1 FY17

Est. development well cost = $5.5-$6.5mm

Existing pad and gathering infrastructure from

Marcellus development provide economic

advantage

Evaluation to consider competitiveness with

Marcellus economics

(1)  Estimated by Seneca reservoir engineering.  Industry estimates are based on publicly available information (e.g., Pa DEP).

2+ Bcf

st

Appalachia

Pipeline & Storage

Recent 3

rd

Party Expansions Highly Successful

19

Expansions for 3

Parties since 2010

Line N Projects

+633 MDth/d

Northern

Access 2012

+320 MDth/d

Empire & Lamont

Expansions

+489 MDth/d

3

Party Expansion Capital Cost ($MM)

Annual Expansion Revenues Added ($MM)

$387 million

since FY 2010

1,442 MDth/d

since FY2010

$72

$132

$183

Northern Access 2012

Empire & Lamont

Line N Projects

$4

$37

$19

$4

$5

$25

~$95

$0

$25

$50

$75

$100

$125

FY11

FY12

FY13

FY14

FY15

FY16E

Cum.

rd

rd

Appalachia

Pipeline & Storage

Planned Empire System Expansion

20

Empire North Expansion Project

•

Target In-Service: Fiscal 2019

•

System: Empire

Pipeline

•

Target Market:

o

Marcellus & Utica producers in Tioga &

Potter County, Pa.

•

Open Season Capacity: 300,000 Dth/d

•

Receipt Point: Jackson (Tioga Co., Pa.)

•

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 Nov. 2015 fully

subscribed

o

Precedent agreements currently in

negotiations

Providing Optionality

for Northeast Pennsylvania Producers

Appalachia

Pipeline & Storage

2015 Pipeline Expansion Projects In-Service

21

Westside Expansion & Modernization

In-Service (October 2015)

Tuscarora Lateral

In-Service (November 2015)

2015 Completed Pipeline Expansion Projects

•

Total Cost: $64.8 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: $82.3 million

o

Expansion: $43.3 million

o

Modernization: $39 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

Appalachia

Pipeline & Storage

Pipeline & Storage Customer Mix

22

Contracted Transportation

by Shipper Type

(1)

(1)

Contracted as of 1/15/2016.

4.1 MMDth/d

68 MMDth

23%

77%

FT Capacity -

Marketers

Affiliated

Non-Affiliated

60%

40%

FT Capacity  -

LDCs

Affiliated

Non-Affiliated

Producer

36%

LDC

48%

Marketer

9%

Outside

Pipeline

6%

End User

1%

6%

94%

FT Capacity -

Producers

Affiliated

Non-Affiliated

Firm Storage Capacity

Affiliated

Non-Affiliated

46%

54%

Production and Marketing

Exploration & Production

23

Production & Marketing

Proved Reserves & Development Costs

24

•

2015 F&D Cost = $0.96

•

Marcellus F&D: $0.79

•

373% Reserve

Replacement Rate

•

65% Proved Developed

(1)

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

Natural Gas (Bcf)

Crude Oil (MMbbl)

(1)

Includes approximately 180 Bcf of natural gas proved reserves in Appalachia 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.

43.3

42.9

41.6

38.5

33.7

At September 30

2008-2010

$2.37

2009-2011

$2.09

2010-2012

$1.87

2011-2013

$1.67

2012-2014

$1.38

2013-2015

$1.12

Fiscal

Years

3-Year

F&D Cost

(2)

($/Mcfe)

Production & Marketing

Seneca Production

25

(1)

Refer to slide 31 for additional details on fiscal 2016 firm sales and local Appalachian spot market exposure. 

Seneca Resources Net Production (Bcfe)

JDA tempers net production growth in FY17

Gross production expected to grow ~10%

Growth is largely being generated from joint

development wells where Seneca has 26% NRI,

resulting in net production flat YOY

Growth will benefit Gathering segment revenues

20.5

20.0

21.2

21.2

20 -

21

20 -

22

62.9

100.7

139.3

136.6

140-144

130-153

67.6

120.7

160.5

157.8

160-165

150-175

0

50

100

150

200

250

2012

2013

2014

2015

2016E

2017E

Appalachia

West Coast (California)

(1)

Production & Marketing

Significant Base of Long-Term Firm Contracts

26

Atlantic Sunrise (Transco)

Delivery Markets: Mid-Atlantic & Southeast U.S.

189,405 Dth/d

Northern Access 2016 (NFG

(2)

, 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

(1)

Northeast Supply Diversification  50,000 Dth/d

FY 2016 to FY2017

465,000+ Dth/d

Fiscal 2018 and beyond

914,405 Dth/d

-

250

500

750

1,000

2016

2017

2018

2019

2020

2021

2022

2023

Includes base firm sales contracts not tied to firm transportation capacity.  Base firm sales are either fixed priced or priced at an index (e.g., NYMEX ) +/- a fixed basis and do not carry any

transportation costs.  See slide 28 for details on firm sales portfolio for fiscal 2016. 

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

Fiscal Year Start

(1)

(2)

Production & Marketing

Firm Transportation Commitments

27

(1) WMB is now targeting second half of calendar 2017 following the change in the timing of the environmental review from FERC.

Volume

(Dth/d)

Production

Source

Delivery

Market

Demand Charges

($/Dth)

Gas Marketing Strategy

Northeast Supply

Diversification

Project

Tennessee Gas Pipeline

Atlantic Sunrise

WMB -

Transco

In-service: Late 2017

(1)

Niagara Expansion

TGP & NFG

Northern Access

NFG –

Supply & Empire

In-Service: Nov. 1 2017

50,000

189,405

158,000

350,000

EDA -Tioga

County

Covington &

Tract 595

EDA -

Lycoming

County

Tract 100 &

Gamble

WDA –

Clermont

/Rich Valley

WDA –

Clermont

/Rich Valley

12,000

140,000

Canada

(Dawn)

Mid-Atlantic/

Southeast

Canada

(Dawn)

TETCO (SE Pa.)

Canada

(Dawn)

TGP 200

(NY)

$0.50

(3

party)

$0.73

(3

party)

3

party

=

$0.43

NFG pipelines = $0.12

NFG pipelines = $0.38

3

party

=

$0.21

Firm Sales Contracts

50,000 Dth/d

Dawn/NYMEX+

10 years

Firm Sales Contracts

158,000 Dth/d

Dawn/NYMEX+

8 to 15 years

Firm Sales Contracts

189,405 Dth/d

NYMEX+

First 5 years

Firm Sales Contracts

145,000 Dth/d

Dawn/Fixed Price

First 3 years

Weighted Average Transportation Charge on Volumes Transported

$0.64/Dth

Annualized Gross FT Demand Charges –

3rd Parties

Annualized Gross FT Charges –

NFG Affiliates

$111 MM

$97 MM

FY16/FY17

FY18+

$14 MM

$34 MM

$0.63/Dth

rd

rd

rd

rd

NFG pipelines = $0.24

NFG pipelines = $0.50

Production & Marketing

148,800

Less $0.01

116,100

Plus $0.03

100,700

Less $0.01

173,400

Less $0.01

189,500

Less $0.01

41,700 Less $0.33 

41,600 Less $0.38

42,600 Less $0.40

12,600 Less $0.57

12,500 Less $0.57

53,300 Less $0.01

63,600 Less $0.01

65,400 Less $0.02

21,400 Less $0.40

24,000 Less $0.40

151,700

$2.41

174,700

$2.37

170,700

$2.46

154,900

$2.45

158,000

$2.44

395,500

396,000

379,500

362,300

384,000

Q4 FY16

Q1 FY17

Q2 FY17

Q3 FY17

Q4 FY17

Fixed Price

Dawn

DOM SP / TGPL

NYMEX

Firm Sales Provide Market for Appalachian Production

28

(1)

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

(2)

Reflects adjustment to gross sales volumes to reflect impact of lease royalties  in EDA and  net revenue interests assigned to  joint development partner  on certain contracts in WDA.

Gross vs.

Net Firm Sales Volumes

Gross

493,100/d

493,000/d

483,000/d

483,000/d

483,000/d

NRI Owners

(2)

97,500/d

97,000/d

103,500/d

120,700/d

99,000/d

Net

395,600/d

396,000/d

379,500/d

362,300/d

384,000/d

FY 2016 and FY 2017 Net Firm Sales by Fiscal Quarter

Pricing Index Key:

Net Contracted Volumes (Dth per day)

Contracted

Index

Price

Differentials

($

per

Dth)

(1)

Production & Marketing

9.9

35.7

26.1

25.6

16.9

4.3

6.6

7.1

22.1

8.4

7.2

7.2

14.2

59.9

14.2

5.9

35.5

124.3

48.7

38.7

27.1

-

50.0

100.0

150.0

Q4 - FY16

FY 2017

FY 2018

FY 2019

FY 2020

NYMEX

Dominion

Dawn & MichCon

Fixed Price Physical Sales

Strong Hedge Book in Fiscal 2016 and 2017

29

(1)

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

(2)

Fixed

price

physical

sales

exclude

joint

development

partner’s

share

of

fixed

price

contract

WDA

volumes

as

specified

under

the

joint

development

agreement.

Remaining FY 2016 Natural Gas Production

90% hedged

(1)

at $3.31 per MMBtu

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

(2)

Fiscal 2017 Natural Gas Production

83% hedged

(1)

at $3.27 per MMBtu

Production & Marketing

Fiscal 2017 Production and Price Certainty

30

(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)

Includes non-operated production from Western Development Area (legacy EOG JV wells).

150-175

Bcfe

120 Bcf

12.5 Bcf

(2)

0-18 Bcf

(3)

20-22 Bcfe

Firms

Sales +

Hedges

Firm Sales

(Unhedged)

Spot

Exposure

California

Total

Seneca

160-165

Bcfe

121.3 Bcfe

34 Bcf

0-5 Bcf

(3)

~5 Bcfe

YTD

Actuals

Firm Sales +

Hedges

Spot

Exposure

California

Total

Seneca

Remaining Fiscal 2016 Production

Fiscal 2017 Production

FY17 Natural Gas Price Certainty

120 Bcf realizing net ~$3.05/Mcf

(1)

12.5 Bcf of Additional Basis Protection

Remaining FY16 Natural Gas Price Certainty

34 Bcf realizing net ~$3.10/Mcf

(1)

Production & Marketing

$0.56

$0.59

$0.61

$0.25

$0.14

$0.11

$0.81

$0.73

$0.72

FY 2015

FY 2016E

FY 2017E

LOE (Affiliated Gathering)

LOE (non-Gathering)

G&A

Taxes & Other

Operating Costs

31

$0.49

$0.55

$0.60

$0.57

$0.43

$0.40

$0.42

$0.38

$0.38

$0.22

$0.20

$0.20

$1.70

$1.55

$1.58

FY 2015

FY 2016E

FY 2017E

$16.17

$15.06

$17.88

$16.17

$15.06

$17.88

FY 2015

FY 2016E

FY 2017E

Appalachia LOE & Gathering

$/Mcfe

California LOE

$/Boe

Seneca Resources Consolidated

$/Mcfe

Competitive, low cost structure in Appalachia

and California supports strong cash margins

Gathering fee generates significant revenue

stream for affiliated gathering company

DD&A decrease due to improving Marcellus

F&D costs and reduction in net plant resulting

from ceiling test impairments

DD&A

$/Mcfe

$1.85

$1.52

$0.85 -

$0.90

$0.65 -

$0.75

FY 2014

FY 2015

FY 2016E

FY 2017E

(1)

Excludes $7.9 million

of professional fees relating to the joint development agreement announced in December 2015.

(2)

The

total

of

the

two

LOE

components

represents

the

midpoint

of

LOE

guidance

of

$0.95

to

$1.00

per

Mcfe

for

fiscal

2016

and

$0.95

to

$1.05

per

Mcfe

for

fiscal

2017.

(1)

(2)

(2)

(2)

(2)

(1)

California Overview

Exploration & Production

32

Upstream

California

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

Stable Oil Production   |   Minimal Capital Investment   |  Free Cash Flow Positive

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

FY16 Budgeted D&C Portfolio

Modest near-term capital program focused on

locations that earn attractive returns in current  oil

price environment

A&D will focus on low cost, bolt-on opportunities

Sec. 17 and Hoyt farm-ins to provide future growth

•

F&D (est.) = $6.50/Boe

Economic Development Focused on Midway Sunset

34

(1) Reflects pre-tax IRRs at a $50/Bbl WTI.

Hoyt

South

MWSS

Acreage

North

MWSS

Acreage

Sec. 17N

North

South

South

North

37%

49%

~30%

NMWSS

SMWSS

Farm-in Projects

Midway Sunset Economics

MWSS Project IRRs at $50/Bbl

(1)

Upstream

California Average Daily Net Production

35

$35-$45 Million Annual Capital Spending Expected to Keep CA Production Flat

9,322

9,078

9,699

9,674

9,400

9,600

0

2,500

5,000

7,500

10,000

2012

2013

2014

2015

2016     

Forecast

2017     

Forecast

Fiscal Year

Upstream

$11.79

$3.19

$4.91

$2.62

$1.86

$30.44

Non-Steam Fuel LOE

Steam Fuel

G&A

Production & Other

Taxes

Other Operating Costs

Adjusted EBITDA

West Division Adjusted EBITDA per BOE

Trailing 12-months Ended 6/30/16

Strong Margins Support Significant Free Cash Flow

36

(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 of this presentation.

EBITDA per BOE includes Seneca corporate results and eliminations.

Average Revenue

Less: Cash Costs

= Adjusted EBITDA

$ 24.37

$ 54.81

$ 30.44

California Margins (per BOE)

(1)

37

Downstream

New York & Pennsylvania Service Territories

38

(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)

Filed Rate Case with NY PSC on 4/28/16

Total Customers

(1)

: 213,652

ROE: Black Box Settlement (2007)

Rate Mechanisms:

o

Low Income Rates

o

Merchant Function Charge

Downstream

New York Rate Case

39

Background

On April 28, 2016, National Fuel Gas Distribution Corporation filed a request with the New York

Public Service Commission (NY PSC) to amend its tariff and increase its base rates.  National Fuel’s

base rates have not changed since the last base rate case was litigated in 2007. 

Key Drivers

Timeline

•

Requesting rate relief that would increase annual revenues by $41.7 million

•

Key drivers of revenue requirement:

Significant

increase

in

net

plant

-

$127.5

million

-

and

related

depreciation

expense

since

9/30/2006, the test year associated with the 2007 rate proceeding

Continued investment in pipeline replacement and system modernization to enhance and

ensure safe, reliable service

•

Accelerated removal of vintage pipe from current annual target of 95 miles to 110 miles

•

Replacement

of

aging

information

technology

infrastructure

completed

in

2

nd

half

of

FY16

Commitment to low income customer, conservation and gas expansion initiatives

April 28, 2016

Request filed with NY PSC

for $41.7mm in rate relief

May 11, 2016

NY PSC issued a Notice suspending

the effective date of proposed rate

increase from May 31, 2016 to

September 27, 2016.

April 1, 2017

Approximate date that revised rates may

become effective

(assuming standard procedure)

June 28-29, 2016

NY PSC held Public

Statement Hearings

October 5, 2016

Commencement of

Evidentiary Hearings in

Albany, NY

40

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

Residential Usage

Industrial Usage

80

90

100

110

120

12-Months Ended June 30

20

25

30

35

40

12-Months Ended June 30

Utility: Shifting Trends in Customer Usage

Downstream

$152

$152

$152

$151

$163

$164

$16

$16

$20

$33

$28

$24

$11

$9

$6

$10

$9

$7

$179

$177

$178

$193

$200

$195

$0

$50

$100

$150

$200

$250

2011

2012

2013

2014

2015

12 Months

ended

06/30/16

Fiscal Year

  All Other O&M Expenses

  O&M Pension Expense

  O&M Uncollectible Expense

A Proven History of Controlling Costs

41

(1)

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

(1)

Downstream

Utility: Strong Commitment to Safety

42

The Utility

remains focused on maintaining the

ongoing safety and reliability of its system

Recent increase due to ~$60MM upgrade

of the Utility’s Customer Information

System

and anticipated acceleration of

pipeline replacement program

$43.8

$48.1

$49.8

$54.4

$58.3

$72.0

$88.8

$94.4

$90-$100

$90-$100

$0.0

$30.0

$60.0

$90.0

$120.0

$150.0

2012

2013

2014

2015

2016E

2017E

Capital Expenditures for Safety

Total Capital Expenditures

Downstream

Consolidated Financial Overview

Upstream  |  Midstream  | Downstream

43

Corporate

$58

$72

$89

$94

$90-$100

$90-$100

$144

$56

$140

$230

$125-$140

$400-$450

$80

$55

$138

$118

$55-$65

$75-$85

$694

533

$603

$557

$120-$135

$160-$200

$977

$717

$970

$1,001

$390-$440

$725-$835

$0

$500

$1,000

$1,500

2012

2013

2014

2015

2016E

2017E

Fiscal Year

Exploration & Production Segment

Gathering Segment

Pipeline & Storage Segment

Utility Segment

Energy Marketing & Other

Capital Expenditures by Segment

44

(1)

(1) FY 2016 and FY 2017 capital expenditure guidance reflects the netting of up-front and recurring proceeds received from joint development partner for working interest in joint development 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

EBITDA Contribution by Segment

45

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

$160

$172

$165

$164

$142

$137

$161

$186

$188

$193

$64

$69

$74

$397

$492

$539

$422

$366

$704

$852

$953

$843

$772

$0

$250

$500

$750

$1,000

$1,250

2012

2013

2014

2015

TTM

6/30/16

Fiscal Year

Exploration & Production Segment

Gathering Segment

Pipeline & Storage Segment

Utility Segment

Energy Marketing & Other

Corporate

Financial Position & Liquidity

46

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

Total

Equity

42%

Total

Debt

58%

$3.6 Billion Total Capitalization

as of June 30, 2016

1.89 x

1.89 x

1.77 x

2.27 x

2.72 x

2012

2013

2014

2015

TTM

06-30-16

Fiscal Year

Debt/Adjusted EBITDA

Capitalization

Debt Maturity Profile ($MM)

Liquidity

Committed Credit Facilities

Short-term Debt Outstanding

Available Short-term Credit Facilities

Cash Balance at 06/30/16

Total Liquidity at 06/30/16

$ 1,250 MM

$         0 MM

$ 1,250 MM

$    106 MM

$ 1,356 MM

$300

$250

$500

$549

$500

$0

$200

$400

$600

Dividend Track Record

47

(1)

As of August 3, 2016.

Current

Dividend Yield

(1)

2.9%

Dividend Consistency

Consecutive Dividend Payments

114 Years

Consecutive Dividend Increases

46 Years

Current

Annualized Dividend Rate

$1.62

per Share

$0.00

$0.50

$1.00

$1.50

$2.00

Appendix

48

Appendix

Total Seneca Capital Spending by Division

49

$63

$105

$83

$57

~$35

$35-$45

$631

$428

$520

$500

$85-$100

$125-$155

$694

$533

$603

$557

$120-$135

$160-$200

$0

$200

$400

$600

$800

2012

2013

2014

2015

2016E

2017E

Fiscal Year

Appalachia

West Coast (California)

(2)

(1)

(1)

FY2016 and FY 2017 capital expenditure guidance reflects the netting of up-front and recurring proceeds received from joint development partner for working interest in joint development wells.

(2)

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

Appendix

Marcellus Operated Well Results

50

EDA Development Wells:

Area

Producing

Well

Count

Average IP Rate

(MMcfd)

Average

30-Day (MMcf/d)

Average Treatable

Lateral Length (ft)

Covington

Tioga

County

47

5.2

4.1

4,023’

Tract 595

Tioga

County

44

(2)

7.4

4.9

4,754’

Tract 100

Lycoming

County

60

(2)

17.0

12.6

5,221’

Area

Producing

Well

Count

Average IP Rate

(MMcfd)

Average

30-Day (MMcf/d)

Average Treatable

Lateral Length (ft)

Clermont/Rich Valley

(CRV) & Hemlock

Elk, Cameron &

McKean

counties

100

(1)

6.9

5.2

(1)

7,045’

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 14 wells that have not been on line 30 days.

(2)

Excludes 1 well each drilled into and producing from the Geneseo Shale inTract 595 and Tract 100.

Appendix

Marcellus Shale Program Economics

~1,100 WDA Locations Economic Below $2.00/MMBtu

$3.00

IRR %

(1)

$2.75

IRR %

(1)

$2.50

IRR %

(1)

DCNR 100

Dry Gas

(1033 BTU)

12

5,400

13-14

58%

42%

24%

$1.59

Gamble

Dry Gas

(1033 BTU)

44

4,600

11-12

43%

28%

15%

$1.73

CRV

Dry Gas

(1045 BTU)

54

8,000

8.5-9.5

22%

15%

9%

$1.94

Hemlock /

Ridgway

Dry Gas

(1045 BTU)

636

8,800

8-9

22%

14%

8%

$1.97

Remaining

Tier 1

Dry Gas

(1045 BTU)

406

8,500

7-8

21%

13%

7%

$1.99

Net Realized

Price

(2)

Required for

15% IRR

NYMEX / DAWN Pricing

Prospect

Product

Locations

Remaining

to Be Drilled

Completed

Lateral

Length (ft)

Average

EUR (Bcf)

Anticipated

Delivery

Market

Niagara Expansion

Northern Access

Canada (Dawn) /

TGP200

Atlantic Sunrise

Southeast US

(NYMEX+)

(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.

(2)

Net realized price reflects either (a) price received at the well-head or (b) price received at delivery market net of firm transportation charges.

51

Appendix

Volume

Avg.

Price

Volume

Avg.

Price

Volume

Avg.

Price

Volume

Avg.

Price

Volume

Avg.

Price

NYMEX Swaps

9,930

$3.96

35,710

$4.29

26,070

$3.49

25,560

$3.18

16,880

$3.07

Dominion

Swaps

4,260

$3.77

6,540

$3.86

-

-

-

-

-

-

MichCon Swaps

3,000

$4.10

3,000

$4.10

-

-

-

-

-

-

Dawn Swaps

4,080

$3.82

19,100

$3.70

8,400

$3.08

7,200

$3.00

7,200

$3.00

Fixed Price

Physical Sales

14,224

$2.40

59,926

$2.43

14,197

$2.56

5,955

$3.18

3,005

$3.25

Total

35,494

$3.31

124,276

$3.27

48,667

$3.15

38,715

$3.14

27,085

$3.07

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 three 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

51,000

$94.06

123,000

$92.27

24,000

$91.00

NYMEX Swaps

432,000

$73.82

885,000

$64.17

207,000

$62.27

Total

483,000

$75.96

1,008,000

$67.60

231,000

$65.25

(Volumes & Prices in Bbl)

(1)

For the remaining three months of Fiscal 2016.

(1)

Appendix

Comparable GAAP Financial Measure Slides & Reconciliations

54

This

presentation

contains

certain

non-GAAP

financial

measures.

For

pages

that

contain

non-GAAP

financial

measures,

pages

containing

the

most

directly

comparable

GAAP

financial

measures

and

reconciliations

are

provided

in

the

slides

that

follow.

The

Company

believes

that

its

non-GAAP

financial

measures

are

useful

to

investors

because

they

provide

an

alternative

method

for

assessing

the

Company’s

ongoing

operating

results

and

for

comparing

the

Company’s

financial

performance

to

other

companies.

The

Company’s

management

uses

these

non-

GAAP

financial

measures

for

the

same

purpose,

and

for

planning

and

forecasting

purposes.

The

presentation

of

non-GAAP

financial

measures

is

not

meant

to

be

a

substitute

for

financial

measures

prepared

in

accordance

with

GAAP.

The

Company

defines

Adjusted

EBITDA

as

reported

GAAP

earnings

before

the

following

items:

interest

expense,

depreciation,

depletion

and

amortization,

interest

and

other

income,

impairments,

items

impacting

comparability

and

income

taxes.

Appendix

National Fuel Gas Company

55

Reconciliation of Adjusted EBITDA to Consolidated Net Income

($ Thousands)

FY 2012

Total Adjusted EBITDA

Exploration & Production Adjusted EBITDA

397,129

$           

492,383

$              

539,472

$              

422,289

$              

366,255

Pipeline & Storage Adjusted EBITDA

136,914

161,226

186,022

188,042

193,226

Gathering Adjusted EBITDA

14,814

29,777

64,060

68,783

74,050

Utility Adjusted EBITDA

159,986

171,669

164,643

164,037

141,598

Energy Marketing Adjusted EBITDA

5,945

6,963

10,335

12,150

6,306

Corporate & All Other Adjusted EBITDA

(10,674)

(9,920)

(11,078)

(11,900)

(9,127)

Total Adjusted EBITDA

704,114

$           

852,098

$              

953,454

$              

843,401

$              

772,308

$        

Total Adjusted EBITDA

704,114

$           

852,098

$              

953,454

$              

843,401

$              

772,308

$        

Minus: Interest Expense

(86,240)

(94,111)

(94,277)

(99,471)

(121,390)

Plus:  Interest and Other Income

8,822

9,032

13,631

11,961

15,505

Minus: Income Tax Expense

(150,554)

(172,758)

(189,614)

319,136

414,167

Minus: Depreciation, Depletion & Amortization

(271,530)

(326,760)

(383,781)

(336,158)

(264,160)

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

-

-

-

(1,126,257)

(1,332,749)

Plus: Reversal of Stock-Based Compensation

-

-

-

7,961

7,961

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)

-

-

-

Minus: Joint Development Agreement Professional Fees

-

-

-

-

(7,855)

Rounding

(1)

-

-

-

-

Consolidated Net Income

220,077

$           

260,001

$              

299,413

$              

(379,427)

$            

(516,213)

$       

Consolidated Debt to Total Adjusted EBITDA

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

1,149,000

$        

1,649,000

$          

1,649,000

$          

2,099,000

$          

2,099,000

$     

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

250,000

-

-

-

-

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

171,000

-

85,600

-

-

Total Debt (End of Period)

1,570,000

$        

1,649,000

$          

1,734,600

$          

2,099,000

$          

2,099,000

$     

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

899,000

1,149,000

1,649,000

1,649,000

2,099,000

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

150,000

250,000

-

-

-

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

40,000

171,000

-

85,600

-

Total Debt (Start of Period)

1,089,000

$        

1,570,000

$          

1,649,000

$          

1,734,600

$          

2,099,000

$     

Average Total Debt

1,329,500

$        

1,609,500

$          

1,691,800

$          

1,916,800

$          

2,099,000

$     

Average Total Debt to Total Adjusted EBITDA

1.89 x

1.89 x

1.77 x

2.27 x

2.72 x

FY 2013

12-Months

Ended 6/30/16

FY 2014

FY 2015

Appendix

National Fuel Gas Company

56

(1) FY 2016 and FY 2017 capital expenditure guidance reflects the netting of up-front and recurring proceeds received from joint development partner for working interest in joint development wells. 

Reconciliation of Segment Capital Expenditures to

Consolidated Capital Expenditures

($ Thousands)

FY 2016

FY 2017

FY 2012

FY 2013

FY 2014

FY 2015

Forecast

Forecast

Capital Expenditures from Continuing Operations

Exploration

&

Production

Capital

Expenditures

(1)

693,810

$       

533,129

$       

602,705

$       

557,313

$       

$120,000 -

$135,000

$160,000 -

$200,000

Pipeline & Storage Capital Expenditures

144,167

56,144

$         

139,821

$       

230,192

$       

$125,000 -

$140,000

$400,000 -

$450,000

Gathering Segment Capital Expenditures

80,012

54,792

$         

137,799

$       

118,166

$       

$55,000 -

$65,000

$75,000 -

$85,000

Utility Capital Expenditures

58,284

71,970

$         

88,810

$         

94,371

$         

$90,000 -

$100,000

$90,000 -

$100,000

Energy Marketing, Corporate & All Other Capital Expenditures

1,121

1,062

$           

772

$               

467

$               

Total Capital Expenditures from Continuing Operations

977,394

$       

717,097

$       

969,907

$       

1,000,509

$   

$390,000 -

$440,000

$725,000 -

$835,000

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

-

-

-

Exploration & Production FY 2010 Accrued Capital Expenditures

-

-

-

-

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

-

-

-

Pipeline & Storage FY 2010 Accrued Capital Expenditures

-

-

-

-

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

-

-

-

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

-

-

-

Utility FY 2010 Accrued Capital Expenditures

-

-

-

-

Total Accrued Capital Expenditures

57,613

$         

(13,636)

$        

(55,490)

$        

17,670

$         

Eliminations

-

$                

-

$                

-

$                

-

$                

Total Capital Expenditures per Statement of Cash Flows

1,035,007

$   

703,461

$       

914,417

$       

1,018,179

$   

$390,000 -

$440,000

$725,000 -

$835,000

Appendix

National Fuel Gas Company

57

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

Reported GAAP Earnings

(24,192)

$      

5,027

$          

(19,165)

$      

(574,002)

$    

(102,603)

$    

(676,605)

$    

Depreciation, Depletion and Amortization

25,464

5,815

31,279

129,641

29,223

158,864

Interest and Other Income

(88)

-

(88)

(102)

(1,340)

(1,442)

Interest Expense

13,190

563

13,753

53,759

2,298

56,057

Income Taxes

(17,820)

4,134

(13,686)

(434,320)

(74,136)

(508,456)

Impairment of Oil and Gas Producing Properties

70,559

12,099

82,658

1,078,670

254,079

1,332,749

Joint Development Agreement Professional Fees

3,173

-

3,173

7,855

-

7,855

Reversal of Stock Based Compensation

-

-

-

(825)

(1,942)

(2,767)

Adjusted EBITDA

70,286

$        

27,638

$        

97,924

$        

260,676

$     

105,579

$     

366,255

$     

Appalachia

West Coast

Total E&P

Appalachia

West Coast

Total E&P

Production:

Gas Production (MMcf)

38,846

763

39,609

137,930

3,094

141,024

Oil Production (MBbl)

6

722

728

24

2,953

2,977

Total Production (Mmcfe)

38,882

5,095

43,977

138,074

20,812

158,886

Adjusted EBITDA Margin per Mcfe

1.81

$            

5.42

$            

2.23

$            

1.89

$            

5.07

$            

2.31

$            

Total Production (Mboe)

NM

849

NM

NM

3,469

NM

Adjusted EBITDA Margin per Boe

NM

32.55

$          

NM

NM

30.44

$          

NM

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

Three Months Ended

June 30, 2016

Twelve Months Ended

June 30, 2016

Appendix

National Fuel Gas Company

58

Reconciliation of Exploration & Production Segment Operating Expenses by Division

($000s unless noted otherwise)

Appalachia

West Coast

Total E&P

Appalachia

West Coast

Total E&P

Appalachia

West Coast

Total E&P

Appalachia

West Coast

Total E&P

$/ Mcfe

$ / Boe

$ / Mcfe

$/ Mcfe

$ / Boe

$ / Mcfe

Operating Expenses:

Lease Operating & Transportation Expense - Gathering

$76,709

$0

$76,709

$0.56

$0.00

$0.49

$69,937

$0

$69,937

$0.50

$0.00

$0.44

Lease Operating Expense - Other

$34,013

$57,078

$91,091

$0.25

$16.17

$0.57

$32,811

$62,786

$95,597

$0.24

$17.74

$0.59

Total Lease Operating Expense

$110,722

$57,078

$167,800

$0.81

$16.17

$1.06

$102,748

$62,786

$165,534

$0.74

$17.74

$1.03

General & Administrative Expense

$47,445

$18,669

$66,114

$0.35

$5.29

$0.42

$45,987

$17,817

$63,804

$0.33

$5.03

$0.40

All Other Operating and Maintenance Expense

$5,296

$9,008

$14,304

$0.04

$2.55

$0.09

$6,779

$7,742

$14,521

$0.05

$2.19

$0.09

Property, Franchise and Other Taxes

$9,046

$11,121

$20,167

$0.07

$3.15

$0.13

$10,114

$10,651

$20,765

$0.07

$3.01

$0.13

Total Taxes & Other

$14,342

$20,129

$34,471

$0.11

$5.70

$0.22

$16,893

$18,393

$35,286

$0.12

$5.20

$0.22

Depreciation, Depletaion & Amortization

$239,818

$1.52

$296,210

$1.85

Production:

Gas Production (MMcf)

136,404

3,159

139,563

139,097

3,210

142,307

Oil Production (MBbl)

30

3,004

3,034

31

3,005

3,036

Total Production (Mmcfe)

136,584

21,183

157,767

139,283

21,240

160,523

Total Production (Mboe)

22,764

3,531

26,295

23,214

3,540

26,754

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

Twelve Months Ended

September 30, 2015

Twelve Months Ended

September 30, 2014