NATIONAL FUEL GAS CO - FORM 8-K - EX-99 - March 21, 2016

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Investor Presentation
Scotia Howard Weil Energy Conference
March 21 –
23, 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.

•
2.3
Tcfe
Proved
Reserves
(1)
•
785,000 net acres in Marcellus Shale
•
3 million Bbls/year California
crude oil production
3
(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.
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
•
Generates operational and financial
synergies with other segments
Midstream

200,000 “Tier 1” fee-held acres in Pa.
1,200 locations economic < $2.25/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
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
3
Exploration & Production
Expanding Our
Interstate Pipeline
System to Reach
Premium Markets

Integrated Upstream & Midstream Development
5
WDA Well Costs ($millions)
WDA Clermont / Rich Valley Economics
Normalized for a 8,800 ft. Lateral Length
Realized
Price
Required
for
15%
IRR
(1)
Normalized for a 8,800 ft. Lateral Length
(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.
While Seneca has consistently driven down its well costs and improved break-even economics …
Marcellus Drilling Cost per Foot
Marcellus Completion Cost per Stage ($000s)

1-Rig Program/Northern Access 1-year Delay
Integrated Upstream & Midstream Development
6
WDA Clermont /Rich Valley Economics vs. NYMEX Futures Strip
FT Cost
(2)
Northern Access 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)
Reflects $0.70 per Dth reservation charge, including the cost of non-affiliated downstream transportation from the Canadian border to Dawn, and assumes approximately $0.06 per Dth of variable fees
(commodity, fuel, etc.).
… near-term commodity prices prompted modification to upstream & midstream development pace
$0.76
Original Northern Access
in-service date (11/1/16)
Revised Northern Access
in-service date (11/1/17)
$2.68
$1.92
NYMEX Natural Gas Futures Strip (3/16/16)
CRV Break-even Realized Price (NYMEX/Dawn)
CRV Break-even Realized Price (well-head)

$72
$89
$94
$75-$100
$95-$105
$56
$140
$230
$500-$550
$125-$175
$55
$138
$118
$100-$125
$85-$95
$533
$603
$557
$400-$475
$150-$200
$717
$970
$1,001
$1,075-$1,250
$455-$575
$0
$500
$1,000
$1,500
2013
2014
2015
2016E
(March '15)
2016E
(Current)
Exploration & Production Segment
Gathering Segment
Pipeline & Storage Segment
Utility Segment
Energy Marketing & Other
Consolidated Capital Expenditures
7
(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
&
FY17
capital
budgets
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.
(1)
Exercising Capital Flexibility and Discipline
to Respond to Commodity Price Environment
(1)  Executed “Drill-Co” JDA
(2)  1-rig Marcellus program
(3)  Northern Access delay
(4)  Gathering build-out slow-down
(5)  Reduced spending in CA
Key Capital Budget Actions
56% cut
in FY16

National Fuel is Well Positioned
8
Flexibility to
Deploy Capital
Strong Hedge Book
and Firm Sales
Portfolio
Stable, Growing
Base of Regulated
Earnings &
Cash Flows
Strong Balance
Sheet and Liquidity
Investment grade credit rating
$1.25 billion short-term credit facilities can accommodate modest outspend           
in fiscal 2017
No near-term debt maturities to refinance
Fee ownership on Marcellus acreage limits drilling commitments (& royalties)
Just-in-time midstream development model for upstream affiliate limits risk of idle
capital
and
minimizes
contractual
commitments
to
3
rd
party
pipelines
Modest 1-rig program, curtailed volumes and DUC well inventory allow for a steady
ramp-up of productive capacity to fill Northern Access by end of fiscal 2018
78% of remaining fiscal 2016 natural gas production hedged at $3.53/MMbtu
45% of remaining fiscal 2016 crude oil production hedged at $87.70/Bbl
Allows E&P segment to live within cash flows in FY16 and FY17 at current strips
Preserves near-term well economics and protects affiliated midstream throughput
Utility segment provides stable, predictable earnings and cash flows
Pipeline & Storage EBITDA growth from 2015 projects and on-going expansions
Supports investment grade rating
Covers commitment to dividend, debt service and maintenance expenditures

Appalachia Overview
Exploration & Production  |  Gathering  |  Pipeline & Storage
9

Exploration & Production
Appalachia
Significant Appalachian Acreage Position
10
•
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
Marcellus Shale: Western Development Area
11
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 < $2.25/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
2 Utica tests expected in fiscal 2016/2017
SRC Lease Acreage
SRC Fee Acreage
SRC / EOG Earned
Acreage
Clermont/
Rich Valley
Hemlock
Ridgway
2
-
4 BCF/well
7-11 BCF/well
4 -
6 BCF/well
EUR Color Key
Avg
$3.00
15% IRR
Locations
EUR
NYMEX/Dawn
Realized
Remaining
(Bcf)
IRR%
Price
CRV
72
10-11
23%
$1.92
Hemlock/Ridgway
662
8-9
16%
$2.14
Other Tier 1
423
7-8
14%
$2.21
(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.

Exploration & Production
Appalachia
Transaction
Seneca WDA Joint Development Agreement
12
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 reduced near-term upstream capital spending
Initial 42 wells
-
$200 million
(1)
38 well option -
$180 million
(1)
Validated quality of Seneca’s Tier 1 Marcellus WDA acreage
Seneca maintained activity levels driving additional
Marcellus drilling and completion efficiencies
Solidified 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
Strengthened 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
Integrated
WDA
Development
-
Upstream
13
Clermont/Rich Valley Development Map
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
•
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
Pittsburgh

Appalachia
Gathering
Integrated WDA Development -
Gathering
14
Current System In-Service
•
~60 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
(1)
: $60 to $75 million
•
Adjusted timing of gathering & compression
investment to match Seneca’s modified
development schedule/Northern Access
•
Will exit FY16 with > 72 miles of pipe installed
and >26,220 HP commissioned
Future Build-Out (FY17+)
•
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
(1)  For the remaining 9-months of fiscal 2016.

Appalachia
Pipeline & Storage
Integrated WDA Development -
Interstate Pipelines
15
(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)
•
Major Facilities
o
23,000 hp Compression
•
Total Cost: $67.5 million
•
Annual Revenues: $13.3 million
Expanding Our Interstate Pipelines to Deliver Seneca’s WDA Production to Canada

Appalachia
Pipeline & Storage
16
Northern Access 2016
•
Customer: Seneca Resources (NFG)
•
In-Service: Now targeting Nov. 1, 2017
•
Capacity:  490,000 Dth/d
•
Interconnects:
o
TransCanada –
Chippawa
(350 MDth/d)
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/Regulatory Status
o
FERC Certificate filing: March 2015
o
Certificate amendment filed Nov. 2015
o
401 Water Quality Joint Application to
NYDEC & USACE: February 2016
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

Exploration & Production
Appalachia
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

Appalachia
Gathering
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
•
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
Interconnects

Exploration & Production
Appalachia
Utica Shale Opportunities in EDA & WDA
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

Pipeline & Storage: Premier Appalachian Position
20
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
21
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)
$72
$132
$183
Northern Access 2012
Empire & Lamont
Line N Projects
$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.

Appalachia
Pipeline & Storage
Planned Empire System Expansion
22
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
Pipeline & Storage
2015 Pipeline Expansion Projects In-Service
23
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

Appalachia
Pipeline & Storage
Producer
36%
LDC
48%
Marketer
9%
Outside
Pipeline
6%
End User
1%
Pipeline & Storage Customer Mix
24
60%
40%
FT Capacity  -
LDCs
Affiliated
Non-Affiliated
6%
94%
FT Capacity -
Producers
Affiliated
Non-Affiliated
23%
77%
FT Capacity -
Marketers
Affiliated
Non-Affiliated
46%
54%
Firm Storage Capacity
Affiliated
Non-Affiliated
Contracted Transportation
by Shipper Type
(1)
(1)
Contracted as of 1/15/2016.
4.1 MMDth/d
68 MMDth

Production and Marketing
Exploration & Production
25

Production & Marketing
Proved Reserves & Development Costs
26
(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.
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)

Production & Marketing
Seneca Production
27
20.5
20.0
21.2
21.2
~21
62.9
100.7
139.3
136.6
129
Appalachia
Spot Sales
67.6
120.7
160.5
157.8
150-180 Bcfe
0
50
100
150
200
2012
2013
2014
2015
2016E
Appalachia - Spot Exposure
Appalachia - Firm Commitments
West Coast (California)
(1)
Joint
Development
Partner
Production
(2)
+ 21Bcf
(1)
(1)
Refer to slide 32 for additional details on fiscal 2016 firm sales and local Appalachian spot market exposure.  
(2)
Represents joint development partner’s share of production from Seneca operated wells, which is incremental to the 150 – 180 Bcf net production range.  The joint development
partner’s production will utilize gathering and transportation capacity on NFG-affiliated pipelines.

Production & Marketing
Significant Base of Long-Term Firm Contracts
28
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
FY2016 to FY2017
~450,000 Dth/d
Fiscal 2018 and beyond
914,405 Dth/d
2016
2017
2018
2019
2020
2021
2022
2023
Fiscal Year Start
(1)
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 32 for details on firm sales portfolio for fiscal 2016.
(2)
Includes capacity on both National Fuel Gas Supply Corp. and Empire Pipeline, Inc., both wholly owned subsidiaries of National Fuel Gas Company.
-
250
500
750
1,000

Production & Marketing
Firm Transportation Commitments
29
(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)
$0.49
$0.73
NFG pipelines = $0.29
3
rd
party = $0.38
NFG pipelines = $0.12
NFG pipelines = $0.38
NFG pipelines = $0.50
3
rd
party = $0.20
Firm Sales Contracts
50,000 Dth/d
Dawn/NYMEX+
10 years
Firm Sales Contracts
140,000 Dth/d
Dawn/NYMEX+
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
$0.63/Dth
Annualized Gross FT Demand Charges –
3rd Parties
Annualized Gross FT Charges –
NFG Affiliates
$107 MM
$88 MM
FY16/FY17
FY18+
$17 MM
$31 MM
$0.60/Dth

Production & Marketing
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
$2.61
469,698
468,098
468,098
0
200,000
400,000
600,000
Q2
Q3
Q4
Fixed Price
Dawn
Dominion SP
NYMEX
Firm Sales Provide Market for Appalachian Production
30
(1)
Reflects gross firm sales volumes before impact of lease royalties  in EDA or  net revenue interests assigned to  joint development partner  on certain contracts in WDA.
(2)
Values shown represent the price or differential to a reference price (netback price) at the point of sale.
WDA
(1)
209,600/d
263,000/d
263,000/d
EDA
(1)
260,098/d
205,098/d
205,098/d
Fiscal 2016 Firm Sales by Fiscal Quarter
Pricing Index Key:
EDA/WDA Split:
Gross
Contracted
Volumes
(Dth
per
day)
(1)
Contracted
Index
Price
Differentials
($
per
Dth)
(2)

Production & Marketing
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
31
(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.
FY 2016 = 78% hedged
(1)
at $3.53 per MMBtu
Natural Gas Swap & Fixed Physical Sales Contracts (Million MMBtu)
(3)
(2)
(2)

Production & Marketing
FY 2016 Production –
Firm Sales & Spot Exposure
32
(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 45% of remaining projected oil production at the midpoint of guidance.
(4)
Represents 2.5 Bcf of non-operated production from Western Development Area .
Fiscal 2016 Price Certainty
88.7 Bcf realizing net ~$3.25/Mcf
(1)
4.9 Bcf of Additional Basis Protection
(2)
1 million Bbls
crude oil hedged at $87.70/Bbl
(3)
32.8 Bcf
150-180 Bcfe
59.4 Bcf
29.3 Bcf
0-30 Bcf
~21 Bcfe
4.9 Bcf
(2)
2.5 Bcf
(4)
0
50
100
150
200
Q1 FY16
Appalachia
Production
Firms
Sales +
Hedges
Fixed
Price
Sales
Spot
Sales
California
Total
Seneca

Production & Marketing
$0.50
$0.56
$0.24
$0.25
$0.33
$0.35
$0.12
$0.11
$1.19
$1.27
FY 2014
FY 2015
LOE (Affiliated Gathering)
LOE (non-Gathering)
G&A
Taxes & Other
Operating Costs
33
$0.44
$0.49
$0.50
$0.59
$0.57
$0.55
$0.40
$0.42
$0.38
$0.22
$0.22
$0.20
$1.65
$1.70
$1.63
FY 2014
FY 2015
FY 2016E
$17.74
$16.17
$5.03
$5.29
$5.20
$5.70
$27.97
$27.16
FY 2014
FY 2015
Appalachia Division
$/Mcfe
West Division (California)
$/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 ($0.79 /Mcf in FY15) and reduction in
net plant resulting from ceiling test impairments
DD&A
$/Mcfe
$1.85
$1.52
$0.90 -
$1.00
FY 2014
FY 2015
FY 2016E
(1)
Excludes impact
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
$1.00
to
$1.10
per
Mcfe
for
fiscal
2016.
(1)
(2)
(2)

Production & Marketing
$3.15
$0.00
$1.00
$2.00
$3.00
$4.00
$5.00
NFG
P1
P2
P3
P4
P5
P6
P7
P8
Before Hedging
Hedging Uplift
$1.95
$0.00
$1.00
$2.00
$3.00
$4.00
$5.00
NFG
P1
P2
P4
P6
P5
P3
P8
P7
Peer Average
$1.52/Mcfe
Appalachian Price Realizations & Margins
34
(1)
Appalachian peer group includes AR, CNX, COG, EQT,  GPOR, RICE, RRC & SWN. Peer group information obtained or estimated by National Fuel Gas Company from peer company
quarterly public filings (press release & Form 10-K) for the quarter-ended December 31, 2015.  Where applicable and when information was available, peer company realizations and
margins were adjusted to reflect cash settled hedges and results of  exploration and production operations only.  Accounting methodology for transportation expense (included in
price realizations vs. operating expense) varies between companies. NFG deducts transportation costs from revenues to calculate its price realizations.
Q1 FY16 Average Natural Gas Realizations per Mcf 
vs. Appalachian Peer Group
(1)
Q1 FY16 Adjusted EBITDA per Mcfe
vs. Appalachian Peer Group
(1)
Peer Average
$2.92/Mcf
Appalachia
Appalachia
Strong hedge book,
firm sales portfolio, and cost
discipline generating impressive
natural gas price realizations and margins in challenging commodity environment 

California Overview
Exploration & Production
35

Upstream
California: Stable Production; Modest Growth
36
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
North
Midway
Sunset
South
Midway
Sunset
South Lost
Hills
North Lost
Hills
Sespe
East
Coalinga

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
37
(1) Reflects
pre-tax
IRRs
at
a
$40/Bbl
realized
price.
Hoyt
South
MWSS
Acreage
North
MWSS
Acreage
Sec. 17N
North
South
South
North
Midway Sunset Economics
MWSS Project IRRs at $40/Bbl
(1)
25%
36%
NMWSS
SMWSS

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
38
$35-$40 Million Annual Capital Spending Will Keep Production Flat

Upstream
Strong Margins Support Significant Free Cash Flow
39
(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.
$12.74
$3.37
$5.56
$2.90
$2.58
$33.69
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

Downstream Overview
Utility  |  Energy Marketing
40

Downstream
New York & Pennsylvania Service Territories
41
(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
42
(1)  Weighted Average of New York and Pennsylvania service territories (assumes normal weather).
Residential Usage
Industrial Usage
12-Months Ended December 31
12-Months Ended December 31

Downstream
A Proven History of Controlling Costs
43
(1)
$10 million of increase in pension costs from fiscal 2013 primarily due to  the NY PSC rate case settlement in May 2014.
(1)
$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

Downstream
Utility: Strong Commitment to Safety
44
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
$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

45
Consolidated Financial Overview
Upstream  |  Midstream  | Downstream

Corporate
EBITDA Contribution by Segment
46
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.
$160
$172
$165
$164
$157
$137
$161
$186
$188
$190
$64
$69
$62
$397
$492
$539
$422
$378
$704
$852
$953
$843
$785
$0
$250
$500
$750
$1,000
$1,250
2012
2013
2014
2015
TTM  12/31/15
Fiscal Year
Exploration & Production Segment
Gathering Segment
Pipeline & Storage Segment
Utility Segment
Energy Marketing & Other

Corporate
Capital Expenditures by Segment
47
(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.
(1)
$58
$72
$89
$94
$95-$105
$144
$56
$140
$230
$125-$175
$80
$55
$138
$118
$85-$95
$694
533
$603
$557
$150-$200
$977
$717
$970
$1,001
$0
$500
$1,000
$1,500
2012
2013
2014
2015
2016E
Fiscal Year
Exploration & Production Segment
Gathering Segment
Pipeline & Storage Segment
Utility Segment
Energy Marketing & Other
$455-$575

Corporate
Financial Position & Liquidity
48
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
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
Total
Equity
46%

Corporate
Dividend Track Record
49
(1) As of March 16, 2016.
Current
Dividend Yield
(1)
3.1%
Dividend Consistency
Consecutive Dividend Payments
113 Years
Consecutive Dividend Increases
45 Years
Current
Annualized Dividend Rate
$1.58
per Share
$0.00
$1.00
$1.50
$2.00
$0.50
Annual Rate at Fiscal Year End

Corporate
Unique Asset Mix and Integrated Model Provide Balance and Stability
The National Fuel Value Proposition
50
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

Appendix
51

Appendix
Total Seneca Capital Spending by Division
52
$63
$105
$83
$57
$40-$50
$631
$428
$520
$500
$110-$150
$694
$533
$603
$557
$150 -
$200
$0
$200
$400
$600
$800
$1,000
2012
2013
2014
2015
2016E
Fiscal Year
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.

Appendix
Marcellus Operated Well Results
53
(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.
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:

Appendix
Marcellus Shale Program Economics
~1,200 WDA Locations Economic Below $2.25/MMBtu
$3.00
IRR %
(1)
$2.75
IRR %
(1)
$2.50
IRR %
(1)
DCNR 100
Dry Gas
12
5,400
13-14
1033
59%
43%
25%
$1.57
Gamble
Dry Gas
44
4,600
11-12
1033
35%
22%
11%
$1.83
CRV
Dry Gas
72
8,800
10-11
1045
23%
17%
10%
$1.92
Hemlock /
Ridgway
Dry Gas
662
8,800
8-9
1045 - 1110
16%
11%
6%
$2.14
Remaining
Tier 1
Dry Gas
423
8,500
7-8
1030 - 1110
14%
10%
5%
$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.
54

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
55
(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
56
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)

Appendix
Utica/Point Pleasant: EDA Opportunities
57
PGE
Vertical Tests
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.) 
JKLM
Pt Pleasant Test
DCNR 595
Potential Future Location
Shell: Gee
11.2 MMcf/d
Shell: Neal
26.5 MMcf/d
Travis Peak:
Currently Drilling
57
DCNR Tract 001
Potential Future Location

Appendix
Comparable GAAP Financial Measure Slides & Reconciliations
58
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
59
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
60
(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
61
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
(215,558)
$    
(21,528)
$      
(237,086)
$    
(604,945)
$    
(215,835)
$    
(820,780)
$    
Depreciation, Depletion and Amortization
36,565
          
7,468
            
44,033
          
160,431
        
43,353
          
203,784
        
Interest and Other Income
-
                 
(667)
              
(667)
              
-
                 
(2,711)
           
(2,711)
           
Interest Expense
13,772
          
810
                
14,582
          
48,585
          
2,415
            
51,000
          
Income Taxes
(154,357)
      
(15,498)
         
(169,855)
      
(457,237)
      
(159,681)
      
(616,918)
      
Impairment of Oil and Gas Producing Properties
378,887
        
56,564
          
435,451
        
1,109,002
    
452,706
        
1,561,708
    
Joint Development Agreement Professional Fees
4,682
            
-
                 
4,682
            
4,682
            
-
                 
4,682
            
Reversal of Stock Based Compensation
-
                 
-
                 
-
                 
(825)
              
(1,942)
           
(2,767)
           
Adjusted EBITDA
63,991
$        
27,149
$        
91,140
$        
259,693
$     
118,305
$     
377,998
$     
Appalachia
West Coast
Total E&P
Appalachia
West Coast
Total E&P
Production:
Gas Production (MMcf)
32,788
          
783
                
33,571
          
126,394
        
3,169
            
129,563
        
Oil Production (MBbl)
6
                    
742
                
748
                
27
                  
2,984
            
3,011
            
Total Production (Mmcfe)
32,824
          
5,235
            
38,059
          
126,556
        
21,073
          
147,629
        
Adjusted EBITDA Margin per Mcfe
1.95
$            
5.19
$            
2.39
$            
2.05
$            
5.61
$            
2.56
$            
Total Production (Mboe)
NM
873
                
NM
NM
3,512
            
NM
Adjusted EBITDA Margin per Boe
NM
31.10
$          
NM
NM
33.69
$          
NM
Note: Seneca West Coast division includes Seneca corporate and eliminations.
Three Months Ended
December 31, 2015
Twelve Months Ended
December 31, 2014

Appendix
National Fuel Gas Company
62
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

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