8-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K

CURRENT REPORT

Pursuant to Section 13 or 15(d)

of the Securities Exchange Act of 1934

Date of Report (Date of earliest event reported): April 28, 2016

NATIONAL FUEL GAS COMPANY

(Exact name of registrant as specified in its charter)

New Jersey	1-3880	13-1086010
(State or other jurisdiction of incorporation)	(Commission File Number)	(IRS Employer Identification No.)

6363 Main Street, Williamsville, New York	14221
(Address of principal executive offices)	(Zip Code)

Registrant’s telephone number, including area code: (716) 857-7000

Former name or former address, if changed since last report: Not Applicable

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions (see General Instruction A.2. below):

¨ Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

¨ Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

¨ Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

¨ Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

Item 7.01 Regulation FD Disclosure.

On April 28, 2016, National Fuel Gas Company (the “Company”) updated its Investor Presentation. A copy of the presentation is furnished as part of this Current Report as Exhibit 99.

Neither the furnishing of the presentation as an exhibit to this Current Report nor the inclusion in such presentation of any reference to the Company’s internet address shall, under any circumstances, be deemed to incorporate the information available at such internet address into this Current Report. The information available at the Company’s internet address is not part of this Current Report or any other report filed or furnished by the Company with the Securities and Exchange Commission.

In addition to financial measures calculated in accordance with generally accepted accounting principles (“GAAP”), the presentation furnished as part of this Current Report as Exhibit 99 contains certain non-GAAP financial measures. The Company believes that such non-GAAP financial measures are useful to investors because they provide an alternative method for assessing the Company’s operating results in a manner that is focused on the performance of the Company’s ongoing operations, for measuring the Company’s cash flow and liquidity, and for comparing the Company’s financial performance to other companies. The Company’s management uses these non-GAAP financial measures for the same purpose, and for planning and forecasting purposes. The presentation of non-GAAP financial measures is not meant to be a substitute for financial measures prepared in accordance with GAAP.

Certain statements contained herein or in the materials furnished as part of this Current Report, including statements regarding estimated future earnings and statements that are identified by the use of the words “anticipates,” “estimates,” “expects,” “forecasts,” “intends,” “plans,” “predicts,” “projects,” “believes,” “seeks,” “will” and “may” and similar expressions, are “forward-looking statements” as defined by the Private Securities Litigation Reform Act of 1995. There can be no assurance that the Company’s projections will in fact be achieved nor do these projections reflect any acquisitions or divestitures that may occur in the future. While the Company’s expectations, beliefs and projections are expressed in good faith and are believed to have a reasonable basis, actual results may differ materially from those projected in forward-looking statements. Furthermore, each forward-looking statement speaks only as of the date on which it is made. In addition to other factors, the following are important factors that could cause actual results to differ materially from those discussed in the forward-looking statements: impairments under the SEC’s full cost ceiling test for natural gas and oil reserves; changes in the price of natural gas or oil; financial and economic conditions, including the availability of credit, and occurrences affecting the Company’s ability to obtain financing on acceptable terms for working capital, capital expenditures and other investments, including any downgrades in the Company’s credit ratings and changes in interest rates and other capital market conditions; delays or changes in costs or plans with respect to Company projects or related projects of other companies, including difficulties or delays in obtaining necessary governmental approvals, permits or orders or in obtaining the cooperation of interconnecting facility operators; factors affecting the Company’s ability to successfully identify, drill for and produce economically viable natural gas and oil reserves, including among others geology, lease availability, title disputes, weather conditions, shortages, delays or unavailability of equipment and services

required in drilling operations, insufficient gathering, processing and transportation capacity, the need to obtain governmental approvals and permits, and compliance with environmental laws and regulations; changes in laws, regulations or judicial interpretations to which the Company is subject, including those involving derivatives, taxes, safety, employment, climate change, other environmental matters, real property, and exploration and production activities such as hydraulic fracturing; governmental/regulatory actions, initiatives and proceedings, including those involving rate cases (which address, among other things, target rates of return, rate design and retained natural gas), environmental/safety requirements, affiliate relationships, industry structure, and franchise renewal; changes in price differentials between similar quantities of natural gas or oil sold at different geographic locations, and the effect of such changes on commodity production, revenues and demand for pipeline transportation capacity to or from such locations; other changes in price differentials between similar quantities of natural gas or oil having different quality, heating value, hydrocarbon mix or delivery date; the cost and effects of legal and administrative claims against the Company or activist shareholder campaigns to effect changes at the Company; uncertainty of oil and gas reserve estimates; significant differences between the Company’s projected and actual production levels for natural gas or oil; changes in demographic patterns and weather conditions; changes in the availability, price or accounting treatment of derivative financial instruments; changes in economic conditions, including global, national or regional recessions, and their effect on the demand for, and customers’ ability to pay for, the Company’s products and services; the creditworthiness or performance of the Company’s key suppliers, customers and counterparties; economic disruptions or uninsured losses resulting from major accidents, fires, severe weather, natural disasters, terrorist activities, acts of war, cyber attacks or pest infestation; significant differences between the Company’s projected and actual capital expenditures and operating expenses; changes in laws, actuarial assumptions, the interest rate environment and the return on plan/trust assets related to the Company’s pension and other post-retirement benefits, which can affect future funding obligations and costs and plan liabilities; increasing health care costs and the resulting effect on health insurance premiums and on the obligation to provide other post-retirement benefits; or increasing costs of insurance, changes in coverage and the ability to obtain insurance. The Company disclaims any obligation to update any forward-looking statements to reflect events or circumstances after the date hereof.

Item 9.01 Financial Statements and Exhibits.

(d) Exhibits

Exhibit 99 Investor Presentation dated April 2016

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.

NATIONAL FUEL GAS COMPANY
By:	/s/ Paula M. Ciprich
	Paula M. Ciprich Secretary

Dated: April 28, 2016

EXHIBIT INDEX

Exhibit Number	Description
99	Investor Presentation dated April 2016

EX-99

Investor Presentation

Q2 Fiscal 2016 Update

April 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 Forms 10-Q for the quarters ended December 31, 2015 and March 31, 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 California

crude oil production

3

(1)

Total proved reserves are as of September 30, 2015.

(2)

For the trailing twelve months ended March 31, 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

Upstream

Downstream

Quality Assets  |  Exceptional Location  | Unique Integration

•

$255 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

Integrated Vision for Long-term Growth in Appalachia

4

Exploration & Production

Pipeline & Storage

Gathering

1

2

1

2

Long-term, return-

driven approach

to developing vast

acreage position

Connecting Our

Production to Our

Interstate Pipeline

System

Expanding Our

Interstate Pipeline

System to Reach

Premium Markets

3

3

Northern Access projects to

transport 660 MDth/d of Seneca-

operated WDA production by FY18

Integrated Upstream & Midstream Development

5

WDA Well Costs ($millions)

WDA Clermont / Rich Valley Economics

$10.8

$9.6

$7.2

$5.8

$0

$5

$10

$15

FY 2013

FY 2014

FY 2015

FY 2016E

$2.94

$2.71

$2.22

$1.92

$0.00

$1.00

$2.00

$3.00

$4.00

FY 2013

FY 2014

FY 2015

FY 2016E

Normalized for a 8,800 ft. Lateral Length

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 …

$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)

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)

(1)

$2.68

$1.92

$1.00

$1.50

$2.00

$2.50

$3.00

$3.50

NYMEX Natural Gas Futures Strip (2/2/16)

NYMEX Natural Gas Futures Strip (4/26/16)

CRV Break-even Realized Price at Dawn

CRV Break-even Realized Price at well-head

Consolidated Capital Expenditures

7

(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

57% cut

in FY16

$72

$89

$94

$75-$100

$90-$100

$56

$140

$230

$500-$550

$130-$160

$55

$138

$118

$100-$125

$75-$85

$533

$603

$557

$400-$475

$150-$200

$717

$970

$1,001

$1,075-$1,250

$445-$545

$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

(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.

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 FY 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

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 FY 2018

Robust hedge book in FY 2016 & FY 2017 at attractive prices

FY2016 hedges: 80% and 55% of remaining natural gas & crude oil production

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

rd

9

Appalachia Overview

Exploration & Production  |  Gathering  |  Pipeline & Storage

Significant Appalachian Acreage Position

10

•

153 wells able to produce 325 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

•

110 wells able to produce 245 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

Western Development Area (WDA)

Eastern Development Area (EDA)

715,000 Acres

70,000 Acres

Seneca Fee

Seneca Lease

Exploration & Production

Appalachia

Exploration & Production

Appalachia

Marcellus Shale: Western Development Area

11

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

60

10-11

23%

$1.92

Hemlock/Ridgway

636

8-9

16%

$2.14

Other Tier 1

406

7-8

14%

$2.21

Large drilling inventory of quality Marcellus dry gas

o

~1,100 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

(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.

Integrated WDA Development -

Upstream

13

Clermont/Rich Valley Development Map

Clermont/Rich

Valley Area

Pittsburgh

Legend

Drilled Wells

Planned Wells

Clermont Gathering System (in-service)

Clermont Gathering System (future)

CRV Development Summary

•

Current: 88 wells able to produce ~225 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

Exploration & Production

Appalachia

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: $247 million

Fiscal 2016 Build Out

•

FY16 CapEx

(1)

: $30 to $40 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 six 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

•

Delivery 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

Niagara

Appalachia

Pipeline & Storage

16

Northern Access 2016

•

Customer: Seneca Resources (NFG)

•

In-Service: Now targeting Nov. 1, 2017

•

Capacity:  490,000 Dth/d

•

Delivery 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

401 Water Quality Joint Application to

NYDEC & USACE:  March 2016

o

FERC Environmental Assessment:

Expected July 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

2

3

Covington & DCNR Tract 595

o

Tioga County, Pa. 

o

92 wells

(1)

with 100 MMcf/d productive capacity

o

75 MMcf/d firm sales/FT for remainder of 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 225 MMcf/d productive capacity

o

130 MMcf/d firm sales/FT for remainder of 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

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

Exploration & Production

Appalachia

Utica Shale Opportunities in EDA & WDA

19

Range

59 MMcf/d

Rice

42 MMcf/d

Shell

26.5 MMcf/d

PGE

Permitted

Drilling

Completed

Production

Seneca Vert.

Seneca Horiz.

EQT

73 MMcf/d

Color-filled contours are Trenton TVDSS; CI = 1000’

Seneca –

Mt. Jewett

IP: 8.9 MMcf/d

CNX

61 MMcf/d

MHR

46 MMcf/d

Seneca –

WDA

2 Utica Test Wells

Planned for FY16/17

Seneca -

DCNR 007

IP: 22.7 MMcf/d

CNX

61.9 MMcf/d

CNX

44 MMcf/d

Appalachia

Pipeline & Storage

Recent 3

rd

Party Expansions Highly Successful

20

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

21

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

Precedent agreements tendered in

February 2016

Appalachia

Pipeline & Storage

2015 Pipeline Expansion Projects In-Service

22

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

Pipeline & Storage Customer Mix

23

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

6%

94%

FT Capacity -

Producers

Affiliated

Non-Affiliated

46%

54%

Firm Storage Capacity

Affiliated

Non-Affiliated

60%

40%

FT Capacity  -

LDCs

Affiliated

Non-Affiliated

Producer

36%

LDC

48%

Marketer

9%

Outside

Pipeline

6%

End User

1%

6%

Production and Marketing

Exploration & Production

24

Production & Marketing

Proved Reserves & Development Costs

25

43.3

42.9

41.6

38.5

33.7

675

988

1,300

1,683

2,142

935

1,246

1,549

1,914

2,344

0

500

1,000

1,500

2,000

2,500

3,000

2011

2012

2013

2014

2015

At September 30

Natural Gas (Bcf)

Crude Oil (MMbbl)

Fiscal

Years

3-Year

F&D Cost

(2)

($/Mcfe)

2008-2010

$2.37

2009-2011

$2.09

2010-2012

$1.87

2011-2013

$1.67

2012-2014

$1.38

2013-2015

$1.12

•

2015 F&D Cost = $0.96

•

Marcellus F&D: $0.79

•

373% Reserve

Replacement Rate

•

65% Proved Developed

(1)

(1)

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

(2)

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

Production & Marketing

Seneca Production

26

(1)

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

20.5

20.0

21.2

21.2

20 -

21

62.9

100.7

139.3

136.6

138

Appalachia

Spot Sales

67.6

120.7

160.5

157.8

158-175 Bcfe

0

50

100

150

200

2012

2013

2014

2015

2016E

Appalachia - Spot Exposure

Appalachia - Firm Commitments

West Coast (California)

(1)

(1)

Production & Marketing

Significant Base of Long-Term Firm Contracts

27

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

-

250

500

750

1,000

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 29 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.

Production & Marketing

Firm Transportation Commitments

28

(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

rd

party)

$0.73

(3

rd

party)

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

159,500

Less: $0.02

157,000

Less: $0.02

42,000  Less: $0.33

42,000  Less: $0.33

57,500  Less: $0.01

56,500  Less: $0.01

133,100

$2.54

131,800

$2.55

392,100

387,300

Q3 FY16

Q4 FY16

Fixed Price

Dawn

Dominion SP

NYMEX

Firm Sales Provide Market for Appalachian Production

29

(1)

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

(2)

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

Gross

Net

(2)

Gross

Net

(2)

WDA

263,000/d

208,500/d

263,000/d

203,700/d

EDA

205,100/d

183,600/d

205,100/d

183,600/d

Total

468,100/d

392,100/d

468,100/d

387,300/d

Fiscal 2016 Firm Sales by Fiscal Quarter

Pricing Index Key:

WDA/EDA Split (Dth/d):

Net Contracted Volumes (Dth per day)

Contracted

Index

Price

Differentials

($

per

Dth)

(1)

Production & Marketing

19.0

29.5

26.0

25.6

16.9

9.4

12.7

14.2

22.1

8.4

7.2

7.2

24.2

50.7

13.4

6.9

66.8

115.0

47.8

39.7

27.5

-

50.0

100.0

150.0

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

30

Remaining FY 2016

80% hedged

(1)

at $3.41 per MMBtu

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

(3)

(2)

(1)

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

(2)

For the remaining six 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 Production –

Firm Sales & Spot Exposure

31

(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 55% 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

64.3

Bcf

realizing

net

~$3.20/Mcf

(1)

4.2

Bcf

of

Additional

Basis

Protection

(2)

821,000

Bbls

crude

oil

hedged

at

$81.10/Bbl

(3)

67.0 Bcf

158-175 Bcfe

41.0 Bcf

23.3 Bcf

0-16 Bcf

20-21 Bcfe

4.2 Bcf

(2)

2.5 Bcf

(4)

0

50

100

150

200

1H FY16

Appalachia

Production

Firms

Sales +

Hedges

Fixed

Price

Sales

Spot

Sales

California

Total

Seneca

Production &

Marketing

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

32

$0.44

$0.49

$0.50

$0.59

$0.57

$0.50

$0.40

$0.42

$0.38

$0.22

$0.22

$0.20

$1.65

$1.70

$1.58

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

$0.85 -

$0.95

FY 2014

FY 2015

FY 2016E

(1)

Excludes $4.7 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

$1.05

per

Mcfe

for

fiscal

2016.

(1)

(2)

(2)

California Overview

Exploration & Production

33

Upstream

California

34

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

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

35

(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)

Upstream

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

36

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

Upstream

$12.46

$3.24

$5.55

$2.70

$1.89

$31.78

Non-Steam Fuel LOE

Steam Fuel

G&A

Production & Other

Taxes

Other Operating Costs

Adjusted EBITDA

DD&A

Strong Margins Support Significant Free Cash Flow

37

(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

$ 25.84

$ 57.62

$ 31.78

California Margins (per BOE)

West

Division

Adjusted

EBITDA

per

BOE

(1)

Trailing 12-months Ended 3/31/16

Downstream Overview

Utility  |  Energy Marketing

38

Downstream

New York & Pennsylvania Service Territories

39

(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

40

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

Anticipated

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

•

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 31, 2016

Proposed date that revised

rates may become effective

April 1, 2017

Approximate date that revised rates may

become effective

(assuming standard procedure)

Replacement of aging information technology infrastructure expected in 2     half of FY16

nd

Downstream

Utility: Shifting Trends in Customer Usage

41

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

Residential Usage

Industrial Usage

12-Months Ended March 31

12-Months Ended March 31

Downstream

A Proven History of Controlling Costs

42

(1)

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

(1)

$152

$152

$152

$151

$163

$159

$16

$16

$20

$33

$28

$26

$11

$9

$6

$9

$7

$179

$177

$178

$193

$200

$192

$0

$50

$100

$150

$200

$250

2011

2012

2013

2014

2015

12 Months

ended

03/31/16

Fiscal Year

All Other O&M Expenses

O&M Pension Expense

O&M Uncollectible Expense

$10

Downstream

Utility: Strong Commitment to Safety

43

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

$90 -

$100

0

30

60

90

120

150

2011

2012

2013

2014

2015

2016E

Fiscal Year

Capital Expenditures for Safety

Total Capital Expenditures

44

Consolidated Financial Overview

Upstream  |  Midstream  | Downstream

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.

$160

$172

$165

$164

$146

$137

$161

$186

$188

$189

$64

$69

$66

$397

$492

$539

$422

$362

$704

$852

$953

$843

$762

$0

$250

$500

$750

$1,000

$1,250

2012

2013

2014

2015

TTM 

Exploration & Production Segment

Gathering Segment

Pipeline & Storage Segment

Utility Segment

Energy Marketing & Other

Fiscal Year

3/31/16

Corporate

Capital Expenditures by Segment

46

(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

$90-$100

$144

$56

$140

$230

$130-$160

$80

$55

$138

$118

$75-$85

$694

533

$603

$557

$150-$200

$977

$717

$970

$1,001

$445-$545

$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

Corporate

Financial Position & Liquidity

47

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

Total

Debt

56%

$3.7 Billion Total Capitalization

as of March 31, 2016

Debt/Adjusted EBITDA

Capitalization

Debt Maturity Profile ($MM)

Liquidity

Committed Credit Facilities

Short-term Debt Outstanding

Available Short-term Credit Facilities

Cash Balance at 03/31/16

Total Liquidity at 3/31/16

$ 1,250 MM

$   0 MM

$ 1,250 MM

$ 94 MM

$ 1,344 MM

TotalEquity

44%

1.89 x

1.89 x

1.77 x

2.27 x

2.56 x

2012

2013

2014

2015

TTM            

3-31-16

Fiscal Year

$300

$250

$500

$549

$500

$0

$200

$400

$600

Corporate

Dividend Track Record

48

(1)

As of April 27, 2016.

Current

Dividend Yield

(1)

2.9%

Dividend Consistency

Consecutive Dividend Payments

113 Years

Consecutive Dividend Increases

45 Years

Current

Annualized Dividend Rate

$1.58

per Share

$0.00

$0.50

$1.00

$1.50

$2.00

Annual Rate at Fiscal Year End

Corporate

Unique Asset Mix and Integrated Model Provide Balance and Stability

The National Fuel Value Proposition

49

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

50

Appendix

Appendix

Total Seneca Capital Spending by Division

51

$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

52

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

86

(1)

6.9

5.2

(1)

6,970’

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)

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

Appendix

Marcellus Shale Program Economics

~1,100 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

60

8,800

10-11

1045

23%

17%

10%

$1.92

Hemlock /

Ridgway

Dry Gas

636

8,800

8-9

1045 - 1110

16%

11%

6%

$2.14

Remaining

Tier 1

Dry Gas

406

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.

53

Appendix

$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

54

(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 

Appendix

Volume

Avg.

Price

Volume

Avg.

Price

Volume

Avg.

Price

Volume

Avg.

Price

Volume

Avg.

Price

NYMEX Swaps

18,960

$3.92

29,530

$4.20

26,070

$3.49

25,560

$3.18

16,880

$3.07

Dominion

Swaps

9,420

$3.78

12,720

$3.87

-

-

-

-

-

-

MichCon Swaps

6,000

$4.10

3,000

$4.10

-

-

-

-

-

-

Dawn Swaps

8,160

$3.82

19,100

$3.70

8,400

$3.08

7,200

$3.00

7,200

$3.00

Fixed Price

Physical Sales

24,222

$2.55

50,660

$2.52

13,366

$2.69

6,931

$3.19

3,378

$3.25

Total

66,762

$3.41

115,010

$3.34

47,836

$3.19

39,691

$3.15

27,458

$3.07

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 six 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

102,000

$94.06

123,000

$92.27

24,000

$91.00

NYMEX Swaps

719,000

$79.27

573,000

$71.47

51,000

$90.62

Total

821,000

$81.10

696,000

$75.14

75,000

$90.74

(Volumes & Prices in Bbl)

(1)

For the remaining six months of Fiscal 2016.

(1)

Appendix

Utica/Point Pleasant: EDA Opportunities

57

Shell: Gee

11.2 MMcf/d

PGE

Vertical Tests

Permitted

Drilling

Completed

Producing

Seneca

Horizontal

Planned

or Potential

Shell: Neal

26.5 MMcf/d

Other Operators

DCNR Tract 001

Potential Future Location

DCNR 595

Potential Future Location

JKLM

Pt Pleasant Test

Seneca DCNR Tract 007

IP: 22.7 MMcf/d

Lateral Length: 4,640’

Potential locations: ~ 70

Anticipated Development Well

Cost: $7-$10 Million (5,500’ Lat.) 

Travis Peak:

Currently Drilling

Appendix

Comparable GAAP Financial Measure Slides & Reconciliations

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 2012

Total Adjusted EBITDA

Exploration & Production Adjusted EBITDA

397,129

$           

492,383

$              

539,472

$              

422,289

$              

361,994

Pipeline & Storage Adjusted EBITDA

136,914

161,226

186,022

188,042

189,148

Gathering Adjusted EBITDA

14,814

29,777

64,060

68,783

66,145

Utility Adjusted EBITDA

159,986

171,669

164,643

164,037

145,754

Energy Marketing Adjusted EBITDA

5,945

6,963

10,335

12,150

9,565

Corporate & All Other Adjusted EBITDA

(10,674)

(9,920)

(11,078)

(11,900)

(10,729)

Total Adjusted EBITDA

704,114

$           

852,098

$              

953,454

$              

843,401

$              

761,877

$        

Total Adjusted EBITDA

704,114

$           

852,098

$              

953,454

$              

843,401

$              

761,877

$        

Minus: Interest Expense

(86,240)

(94,111)

(94,277)

(99,471)

(114,392)

Plus:  Interest and Other Income

8,822

9,032

13,631

11,961

15,818

Minus: Income Tax Expense

(150,554)

(172,758)

(189,614)

319,136

639,812

Minus: Depreciation, Depletion & Amortization

(271,530)

(326,760)

(383,781)

(336,158)

(285,223)

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

-

-

-

(1,126,257)

(1,838,803)

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

-

-

-

-

(4,682)

Rounding

(1)

-

-

-

-

Consolidated Net Income

220,077

$           

260,001

$              

299,413

$              

(379,427)

$            

(817,632)

$       

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

1,649,000

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

157,500

Total Debt (Start of Period)

1,089,000

$        

1,570,000

$          

1,649,000

$          

1,734,600

$          

1,806,500

$     

Average Total Debt

1,329,500

$        

1,609,500

$          

1,691,800

$          

1,916,800

$          

1,952,750

$     

Average Total Debt to Total Adjusted EBITDA

1.89 x

1.89 x

1.77 x

2.27 x

2.56 x

FY 2013

12-Months

Ended 3/31/16

FY 2014

FY 2015

Appendix

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

$        

$130,000-160,000

Gathering Segment Capital Expenditures

17,021

80,012

54,792

$          

137,799

$        

118,166

$        

$75,000-85,000

Utility Capital Expenditures

58,398

58,284

71,970

$          

88,810

$          

94,371

$          

$90,000-100,000

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

$    

$445,000-545,000

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

$    

$445,000-545,000

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.

(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

Appalachia

West Coast

Total E&P

Reported GAAP Earnings

(189,742)

$    

(23,593)

$      

(213,335)

$    

(759,150)

$    

(221,403)

$    

(980,553)

$    

(215,558)

$    

(21,528)

$      

(237,086)

$    

Depreciation, Depletion and Amortization

30,775

6,499

37,274

147,030

36,592

183,622

36,565

7,468

44,033

Interest and Other Income

(14)

(13)

(27)

(14)

(2,060)

(2,074)

-

(667)

(667)

Interest Expense

13,183

363

13,546

51,269

2,225

53,494

13,772

810

14,582

Income Taxes

(138,318)

(16,975)

(155,293)

(569,570)

(163,643)

(733,213)

(154,357)

(15,498)

(169,855)

Impairment of Oil and Gas Producing Properties

344,185

53,258

397,443

1,377,186

461,617

1,838,803

378,887

56,564

435,451

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

60,069

$        

19,539

$        

79,608

$        

250,608

$     

111,386

$     

361,994

$     

63,991

$        

27,149

$        

91,140

$        

Appalachia

West Coast

Total E&P

Appalachia

West Coast

Total E&P

Appalachia

West Coast

Total E&P

Production:

Gas Production (MMcf)

34,113

764

34,877

129,913

3,139

133,052

32,788

783

33,571

Oil Production (MBbl)

5

718

723

26

2,982

3,008

6

742

748

Total Production (Mmcfe)

34,143

5,072

39,215

130,069

21,031

151,100

32,824

5,235

38,059

Adjusted EBITDA Margin per Mcfe

1.76

$            

3.85

$            

2.03

$            

1.93

$            

5.30

$            

2.40

$            

1.95

$            

5.19

$            

2.39

$            

Total Production (Mboe)

NM

845

NM

NM

3,505

NM

NM

873

NM

Adjusted EBITDA Margin per Boe

NM

23.12

$          

NM

NM

31.78

$          

NM

NM

31.10

$          

NM

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

Three Months Ended

March 31, 2016

Twelve Months Ended

March 31, 2016

Three Months Ended

December 31, 2015

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