National Fuel Gas Company · 2015-10-17 · Analyst Day -November 2013 Corporate. National Fuel Gas Company . Safe Harbor For Forward Looking Statements . 2 . This presentation may

National Fuel Gas Company Analyst Day Presentation

November 19, 2013

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National Fuel Gas Company 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, performance and capital structure, anticipated capital expenditures and completion of construction projects, 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 contained herein are expressed in good faith and are believed to have a reasonable basis, but there can be no assurance that such expectations, beliefs or projections will result or be achieved or accomplished. In addition to other factors, the following are important factors that could cause actual results to differ materially from results referred to in the forward-looking statements: factors affecting the Company’s ability to successfully identify, drill for and produce economically viable natural gas and oil reserves, including among others geology, lease availability, title disputes, weather conditions, shortages, delays or unavailability of equipment and services required in drilling operations, insufficient gathering, processing and transportation capacity, the need to obtain governmental approvals and permits, and compliance with environmental laws and regulations; changes in laws, regulations or judicial interpretations to which the Company is subject, including those involving derivatives, taxes, safety, employment, climate change, other environmental matters, real property, and exploration and production activities such as hydraulic fracturing; changes in the price of natural gas or oil; impairments under the SEC’s full cost ceiling test for natural gas and oil reserves; 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; governmental/regulatory actions, initiatives and proceedings, including those involving rate cases (which address, among other things, allowed rates of return, rate design and retained natural gas), environmental/safety requirements, affiliate relationships, industry structure, and franchise renewal; 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; 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; 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; changes in price differential between similar quantities of natural gas at different geographic locations, and the effect of such changes on the demand for pipeline transportation capacity to or from such locations; other changes in price differentials between similar quantities of oil or natural gas having different quality, heating value, geographic location or delivery date; 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; the cost and effects of legal and administrative claims against the Company or activist shareholder campaigns to effect changes at the Company; 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, 2012 and Forms 10-Q for the periods ended December 31, 2012, March 31, 2013 and June 30, 2013. 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.

http://www.nationalfuelgas.com/

http://www.sec.gov/

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National Fuel Gas Company Analyst Day – Schedule of Speakers

3

Presenter Topic Ron Tanski President and Chief Executive Officer Corporate Overview

Matt Cabell President of Seneca Resources Corporation

Exploration & Production Overview

John McGinnis Senior VP of Seneca Resources Corporation Appraisal & Development

Barry McMahan Senior VP of Seneca Resources Corporation

California Marcellus Operational &

Environmental Ron Kraemer President of Empire Pipeline, Inc. VP of National Fuel Gas Supply Corporation

Midstream Businesses

Dave Bauer Treasurer and Principal Financial Officer

Utility Overview Hedging Strategy Financial Wrap-Up

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Corporate Overview

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National Fuel Gas Company Exceptional Assets, Focused on Execution

5

1.549 Tcfe of Proved Reserves

800,000 Net Acres in Pennsylvania

2.8 MMBbl of Crude Oil Production

$191 Million of Midstream EBITDA

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National Fuel Gas Company A History of Success & A Future of Opportunity

6

Recent Success

35% Production CAGR Since 2010

Nearly $600 Million Invested in New Pipeline Infrastructure

De-risked 2,000 Well Locations in the Marcellus

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Corporate Overview Integrated Businesses Provide Complimentary Benefits

7

$280 $327

$377 $397

$492

$0

$150

$300

$450

$600

2009 2010 2011 2012 2013

Adju

sted

EBI

TDA

($ M

illio

ns)

Fiscal Year

Upstream (E&P) Tremendous Growth (15% CAGR)

$131 $123 $121 $152

$191

$0

$50

$100

$150

$200

$250

2009 2010 2011 2012 2013

Adju

sted

EBI

TDA

($ M

illio

ns)

Fiscal Year

Midstream Businesses Growth & Predictability (10% CAGR)

$164 $167 $169 $160 $172

$0

$50

$100

$150

$200

$250

2009 2010 2011 2012 2013

Adju

sted

EBI

TDA

($ M

illio

ns)

Fiscal Year

Downstream (Utility) Stability & Financial Strength

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Corporate Overview Consistent Growth in Low Natural Gas Price Environment

8

$164 28%

$167 26%

$169 25%

$160 23%

$172 20%

$131 23%

$121 19%

$111 17%

$137 19%

$161 19%

$30 3%

$280 48%

$327 52%

$377 57%

$397 56%

$492 58%

$581 $632

$668 $704

$852

$0

$250

$500

$750

$1,000

2009 2010 2011 2012 2013

Adju

sted

EBI

TDA

($ M

illio

ns)

Fiscal Year

Energy Marketing & OtherUtility SegmentPipeline & Storage SegmentGathering SegmentExploration & Production Segment

Fiscal Year

Natural Gas(1)

($/MMBtu)

2009 $4.68

2010 $4.49

2011 $4.10

2012 $2.83

2013 $3.60

Natural gas prices dropped 23% from 2009 to 2013

(1) Average NYMEX contract settlement price for the 12-month period

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Corporate Overview Still in the Early Stages of Our Marcellus Growth Story

9

2008-2009 2010-2011 2012-2013 2014-2015 2016+

East

ern

Deve

lopm

ent A

rea

Wes

tern

De

velo

pmen

t Are

a

Initial Delineation

Full Development (200-220 Locations)

Initial Delineation

Full Development (1,700-2,000 Locations)

Optimization & Enhancement

Optimization & Enhancement

Delineation (New Areas/Depths)

Delineation (New Areas/Depths)

Production Decline

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Corporate Overview Formula to Grow Our Marcellus Development Program

10

High-Quality Reservoir

Infrastructure& Marketing

Realized Natural Gas

Price

? Increased

Capital Deployment

National Fuel is maintaining a proactive

approach to securing markets for its growing natural gas production

Operating Efficiencies

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Corporate Overview Opportunities to Move Gas Out of the Northeast

11

31%

52%

62% 69%

76%

86% 90% 93%

0%

25%

50%

75%

100%

2013 2014 2015 2016 2017 2018 2019 2020

% of Year that Northeast will be Long Gas Supply

The oversupply of natural gas in the Northeast is creating opportunities for the midstream businesses to develop projects to deliver to higher-priced

markets such as Eastern Canada and the Southeast

Source: TPH Research

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Corporate Overview Marcellus Infrastructure Growth Still Has Room to Run

12

Capacity Added 1,819 MDth per day

Capital Deployed $422 million

2010 to 2013 Expansions

Capacity Planned 1,724 to 2,224 MDth per day

Capital Expenditures Planned ~$1.5 billion

2014+ Expansions

Plans are in place to deploy significant capital to double

the expansion capacity added since 2010

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13

10-15% Adjusted EBITDA Growth

15-25% Production Growth

$1.5 Billion of Midstream Investment Over 5 Years

Future Goals

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Strong Balance Sheet Ability to modestly increase

leverage 1.89x Debt/Adjusted EBITDA

Balanced Business Mix

58% E&P(1)

42% Midstream/Utility(1) Operational synergies

Investment Grade Credit Diversification of businesses

provide credit support Leverage is the cheapest

cost of capital today

Corporate Overview Maintaining Our View on Corporate Structure

14

Today Future (2015+) More Aggressive Growth

Requires Capital Goal is to accelerate value

creation Need stronger natural gas

prices Additional leverage is limited Result may lead to a shift in

business mix

Options to Consider Midstream MLP Upstream/Midstream JV

In today’s commodity price environment, our current structure can handle near-term growth. Look to accelerate development

when the economics of doing so are favorable. (1) Based on Adjusted EBITDA

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Exploration & Production Overview

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41 Bcfe 43 Bcfe 50 Bcfe 68 Bcfe

83 Bcfe

121 Bcfe ~155 Bcfe(1)

~200 Bcfe(1)

Tota

l Pro

duct

ion

Seneca Resources Seneca’s Evolution

16

2008 2014

Gulf of Mexico

California

Shallow Appalachia

Marcellus Shale – Eastern Development Area

Marcellus Shale – Western Development Area

Utica Shale (Delineation)

Geneseo Shale (Delineation)

~400% Production Growth (2008 to 2015)

(1) Represents the midpoint of current guidance (Fiscal 2014: 145 – 165 Bcfe; Fiscal 2015: 180 – 220 Bcfe)

2011

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Total production increased 45% to 120.7 Bcfe

Seneca Resources Fiscal 2013 Highlights

17

45%

Replaced 351% of proved reserves Finding & Development Cost: $1.31/Mcfe Marcellus Finding & Development Cost: $0.99/Mcfe

351%

Achieved major breakthrough in the Marcellus Shale Western Development Area (WDA)

De-risked 1,700 to 2,000 future drilling locations

WDA Success

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Seneca Resources Disciplined Capital Spending

18

$31 $28 $47 $63 $105 $90- $130

$90- $130

$139

$356

$596 $631

$428 $460- $520

$560- $620

$188(1)

$398

$649 $694

$533 $550-$650

$650-$750

$0

$200

$400

$600

$800

$1,000

2009 2010 2011 2012 2013 2014Forecast

2015Forecast

Capi

tal E

xpen

ditu

res

($ M

illio

ns)

Fiscal Year

Gulf of Mexico (Divested in 2011)East Division (Appalachia)West Division (California/Kansas)

(1) Does not include the $34.9 MM acquisition of Ivanhoe’s U.S.-based assets in California, as this was accounted for as an investment in subsidiaries on the Statement of Cash Flows, and was not included in Capital Expenditures

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Seneca Resources Proven Record of Growth

19

46.2 46.6 45.2 43.3 42.9 41.6

226 249 428

675

988

1,300

503 528

700

935

1,246

1,549

0

500

1000

1500

2000

2008 2009 2010 2011 2012 2013

Tota

l Pro

ved

Rese

rves

(Bcf

e)

At September 30

Natural Gas (Bcf)Crude Oil (MMbbl)

Fiscal Years

3-Year F&D Cost(1)

($/Mcfe)

2006-2008 $7.63

2007-2009 $5.35

2008-2010 $2.37

2009-2011 $2.09

2010-2012 $1.87

2011-2013 $1.67

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

2013 F&D Cost = $1.31 Marcellus F&D: $0.99

Doubled Proved Reserves Since 2010

71% Proved Developed

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Seneca Resources Best-In-Class Marcellus Shale Reserve Growth

20

33%

24% 21% 19%

7%

-10% -15%

0%

15%

30%

45%

NFG Peer 1 Peer 2 Peer 3 Peer 4 Peer 5

2009 to 2012 Proved Reserves CAGR(1)

(1) Peers consist of AR, COG, EQT, RRC, SWN

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Seneca Resources Delivering Tremendous Production Growth

21

19.8 19.2 20.5 20.0 20-22 22-24 16.5

43.2 62.9

100.7

125-143

158-196

13.3 49.6

67.6 83.4

120.7

145-165

180-220

0

75

150

225

2010 2011 2012 2013 2014Forecast

2015Forecast

Annu

al P

rodu

ctio

n (B

cfe)

Fiscal Year

Gulf of Mexico (Divested in 2011)

East Division (Appalachia)

West Division (California/Kansas)

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Seneca Resources Delivering More than Just Absolute Growth

22

0.4 0.5

0.7

0.8

1.1

-

0.5

1.0

1.5

2009 2010 2011 2012 2013

Tota

l Pro

duct

ion

per D

ebt-

Adju

sted

Sha

re (M

cfe)

Fiscal Year

Total Production per Debt-Adjusted Share(2) (Mcfe)

(1) Year-end proved reserves divided by debt-adjusted year-end diluted shares outstanding (2) Annual production per share divided by debt-adjusted year-end diluted shares outstanding

5.5

7.1

9.0

11.5

14.4

-

5

10

15

20

2009 2010 2011 2012 2013

Tota

l Pro

ved

Rese

rves

per

Deb

t-Ad

just

ed S

hare

(Mcf

e)

At September 30

Proved Reserves per Debt-Adjusted Share(1) (Mcfe)

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Marcellus Shale Significant Position & Integral Part of Seneca’s Future

23

Company Net Marcellus

Acreage(1)

Enterprise Value(2)

($ Billions) Acres per

$ Million of EV

NFG 780,000 $7.4 105.4

RRC 835,000 $15.5 53.9

EQT 560,000 $15.5 36.1

SWN 337,000 $14.6 23.0

AR 334,000 $17.2 19.4

COG 200,000 $15.2 13.1

(1) Source: ITG Investment Research, & Company Data (2) Source: Bloomberg - As of November 8, 2013

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Marcellus Shale Factors for Success

Acreage Position – Quantity & Quality

Operating Expertise Control costs Maximize production

Gathering, Transportation and Marketing

Financial Stability Ability to withstand price swings and market dislocations

24

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Marcellus Shale Prolific Pennsylvania Acreage

25

Eastern Development Area (EDA)

Mostly leased (16-18% royalty) No near-term lease expiration First large expiration: 2018

Ongoing development drilling in Tioga and Lycoming Counties

Western Development Area (WDA)

Mineral ownership: 83% No royalty; No lease expiration

Net revenue interest: 98% Highly contiguous Significant economies of scale

Seneca Lease Seneca Fee

720,000 Acres 60,000 Acres

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Seneca Acreage Huge Position – Varies in Understanding

26


Tier I ~200,000 Acres

Northeast Core ~30,000 acres in NE Core

Tier I Acres ~200,000 acres Economic less than $4/Mcf Awaiting Evaluation ~250,000 acres Requires Gas Price Above $4/Mcf ~300,000 acres

Understanding Seneca’s 780,000 Net Acres

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Seneca Acreage Fee Ownership & Contiguity are Beneficial

27

No Royalty No Lease Expiration

Contiguous Acreage Blocks

Seneca’s Tier I acreage is approaching Northeast Core economics

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Seneca Acreage Seneca’s Marcellus Acreage Provides a Unique Advantage

28 Note: Assuming a 7.8 Bcf well, with a 6,000’ lateral and 40 frac stages Note: Assumes $4/MMBtu realized natural gas pricing

Seneca Advantage #1 Fee Ownership

Position

28% IRR

Competitor Advantage #1 Advantage #2 Seneca Advantage Capital Expenditures $9,000 $9,000 $7,000 $7,000 Multiple Pads No No Yes Yes Working Interest 100% 100% 100% 100% Revenue Interest 84% 100% 84% 100% IRR 18% 28% 29% 43%

Seneca Advantage #2 Contiguous Acreage

for Multiple Pads

29% IRR

Seneca Advantage Fee Ownership +

Contiguous Acreage

43% IRR

Competitor Single Pad

Working Interest: 100% Revenue Interest: 84%

18% IRR

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Seneca’s Operations Best-In-Class Operator in Lycoming County (EDA)

29

8.2

4.2 4.0

3.3 3.1

2.2 2.1 1.5

1.0

0

20

40

60

80

100

120

140

160

180

0.0

1.0

2.0

3.0

4.0

5.0

6.0

7.0

8.0

9.0

Seneca Co. 2 Co. 3 Co. 4 Co. 5 Co. 6 Co. 7 Co. 8 Co. 9

Hor

izon

tal W

ell C

ount

Aver

age

Prod

uctio

n pe

r Wel

l (M

Mcf

per

Day

)

Average MMcf per DayHorizontal Well Count

Source: DEP Production Data (January 2013 to June 2013)

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Seneca’s Operations Top-Notch Lycoming Economics

30

12.3

6.6 6.3

4.9 3.7

$0

$2

$4

$6

0.0

5.0

10.0

15.0

NFG APC SWN RRC XCO

Brea

keve

n Pr

ice

($/M

cfe)

EUR

(Bcf

e)

Lycoming County: EURs & Breakeven Prices

EUR (Bcfe) Breakeven Price

Source: ITG IR, raw data provided by didesktop and state agencies

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Seneca’s Operations Seneca’s Lycoming Economics are in the Top 3

31

$2.4

1

$2.7

9

$2.8

0

$2.9

5

$2.9

5

$2.9

6

$3.0

3

$3.0

6

$3.0

9

$3.1

1

$3.2

1

$3.2

3

$3.2

5

$3.3

3

$3.3

5

$3.4

6

$3.5

4

$3.6

2

$3.6

5

$3.6

9

$2.00

$3.00

$4.00

$5.00

Brea

keve

n N

YMEX

($/M

cf)

Top Marcellus Breakevens by Operator & County (Source: ITG Investment Research)

Source: ITG IR, raw data provided by didesktop and state agencies

There are an additional 109 breakeven data points greater than $3.69/Mcf

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Seneca’s Operations Driving Down Well Costs

32

$10.0

$8.1 $6.7

$5.8

$0.0

$3.0

$6.0

$9.0

$12.0

2012 2013 2014 (Est.) Best YTD

Tota

l Wel

l Cos

ts ($

Mill

ions

)

Fiscal Year

DCNR Tract 100 Total Well Costs RCS Well Normalized for 5,500’ Lateral & 37 RCS Stages

Tract 100 (EDA)

In 2014, total well costs are expected to be ~35-40% lower than 2012

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Seneca’s Gathering & Marketing Seneca’s Overall Marketing Strategy

33

Develop gathering infrastructure with

NFG Midstream

Firm sales at interstate pipeline

interconnects

Firm transport (FT) to major markets

Firm sales tied to FT contracts

Financial hedges to lock in benchmark

and basis risk


and basis risk

Historical Strategy

Current/Long-Term Strategy

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National Fuel’s Financial Stability Ability to Withstand Pricing Challenges

34

Strong Balance Sheet & Liquidity Position

Cash Generation from California Oil

No Near-Term Debt Maturities

Active Hedging Program

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Marcellus Shale Factors for Success

Acreage Position – Quantity & Quality

Operating Expertise Control costs Maximize production

Gathering, Transportation and Marketing

Financial Stability Ability to withstand price swings and market dislocations

35

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California Outstanding Cash Flow(1)

36

$31.4 $27.6 $47.4

$62.9

$104.6

$171.6 $187.8 $187.6

$226.9 $215.0

$0

$50

$100

$150

$200

$250

2009 2010 2011 2012 2013

$ M

illio

ns

Fiscal Year

Capital Expenditures

Adjusted EBITDA

(1) Adjusted EBITDA and Capital Expenditures represent Seneca Resources Corporation’s West Division, which includes its activity in Kansas

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200

400

600

800

1,000

1,200

1,400

1,600

2004 2005 2006 2007 2008 2009 2010 2011 2012 2013

Gro

ss P

rodc

utio

n (B

OPD

)

Seneca South Midway Sunset Production

SRC Development Production Historical PDP (Assumes 6% Decline)

California Looking Back at the Successful Ivanhoe Acquisition

37

Purchase Price $39.2 million

Proved PV-10 at 9/30/13(1) $149.5 million

$10.3 million cumulative net cash flow

(including purchase price) since acquisition

Net Production at Acquisition 550 Bbl per Day (March 2009)

Net Production at 9/30/13 1,157 Bbl per Day

110% Increase

(1) PV-10 from 10/1/2013 SEC reserves

$2.6 $3.4 $10.9 $11.4

$25.6 $27.6

($45)

($30)

($15)

$0

$15

$30

$45

$60

7/1/2009 2009 2010 2011 2012 2013 2014 Est.

Cash

Flo

w ($

Mill

ions

)

Fiscal Year

Ivanhoe Acquisition Cash Flow

AnnualCumulative

Acqu

isiti

on D

ate

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California Looking Forward

38

1. Manage decline of base production

2. Pursue and develop opportunities for growth from current assets Sespe East Coalinga South Midway Sunset

3. Continue to pursue additional acquisition and farm-in opportunities

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Seneca Resources Key Metrics

39

Operational Strategy Metric Fiscal 2009 Strategic

Improvements Fiscal 2013

Focus on growth-oriented Marcellus Shale assets with

significant fee acreage

Maintain and grow strong cash flow

assets in California

East Division Production

East Division Proved Reserves

East Division EBITDA

Operating Costs(1)

West Division EBITDA

Cash Margin(2)

9 Bcfe (21% of Total Production)

152 Bcfe (29% of Proved Reserves)

$57 million (20% of Total EBITDA)

$2.15 per Mcfe

$172 million

$52 per Bbl

101 Bcfe (83% of Total Production)

1,240 Bcfe (80% of Proved Reserves)

$284 million (57% of Total EBITDA)

$1.09 per Mcfe One of the lowest cost producers in the region

$215 million

$66 per Bbl

12x Production Growth

7x Reserve Growth

5x EBITDA Growth

49% Decrease per Mcfe

25% EBITDA Growth

28% Margin Improvement

(1) Defined as LOE and G&A per Mcfe (2) Defined as realized price including the effects of hedging less LOE , G&A and production taxes

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Seneca Resources What Will Seneca Look Like Moving Forward?

40

Consistent Production Growth: 15-25% CAGR

Driven by a very large, high-quality Appalachian acreage position

Maintain Oil Production → Expand When Possible

Excellent operator and significant cash flow generation

Disciplined Spending Driven by Rates of Return

Pace of development adapts to changing market dynamics

A Leader in Technology, Safety & Environmental Responsibility

Maintain a leadership role in using technology and developing best practices

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41

Appraisal & Development Overview

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Marcellus Shale WDA Is the Key to Seneca’s Long-Term Growth Outlook

42

Full Development Since 2010

~225 locations remaining 70-90 wells in Lycoming County

Near-term driver of growth

Full Development Started in 2013

1,700 to 2,000 locations de-risked Long-term driver of growth


720,000 Acres 60,000 Acres

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Marcellus Shale Significantly Improved Understanding of the WDA

43

SRC Lease Acreage

SRC Fee Acreage

James City

Church Run

Owl’s Nest

Mt. Jewett W. Branch

Clermont

St. Mary’s

Kyler’s Corner

Boone Mtn

Sulger Farm

Tionesta Beechwood

Red Hill/ Leasgang

Punxy

Rich Valley

Ridgway

Key Statistics Vertical Wells: 30 Full Core: 8 Sidewall Core: 2 3D Seismic: 432 sq m

3D Seismic Outlines

EOG Earned Acreage

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Marcellus Shale Northwest PA Generalized Cross-Section

44

Transitional Outer Shelf

CaCO3

Sed. Rate

TOC

Platform Basin

Rich Valley Clermont

Beechwood

Owl’s Nest James City

Leasgang

Punxy

Ridgway

High variability, very poor rock quality in areas

High organics, great rock quality, less variability Medium rock quality, high pressures

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Marcellus Shale WDA Log Summary Cross-Section

45

TOC/PHI/BWV 0 Wt% 50

0.2 v/v 0 0.2 v/v 0

Mineralogy Volume %

Gas Resource 0 Mcf/ac-ft 1500

0 Bcf/mi 100

ɸ = 6.8 - 8.1% Total GIP = ~70/sect

ɸ = 5.6 - 6.7% Total GIP = ~75/sect


0.2 v/v 0 0.2 v/v 0

Mineralogy Volume %


0 Bcf/mi 100


0.2 v/v 0 0.2 v/v 0

Mineralogy Volume %


0 Bcf/mi 100


0.2 v/v 0 0.2 v/v 0

Mineralogy Volume %


0 Bcf/mi 100

ɸ = 5.5 - 6.6% Total GIP = ~60/sect

ɸ = 2.8 – 4.3% Total GIP = < 40/sect

Very poor rock quality. Low gas in place.

Transitional Outer Shelf Platform Basin

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SRC Lease Acreage

SRC Fee Acreage

EOG Earned JV Acreage

Marcellus Shale 2013 & 2014 WDA Delineation Program

46

Owl’s Nest – Delineating 2 High Btu Wells Completed

Rich Valley – Full Development 2 Wells Completed

7-Day IP of 7.8 MMcf/d & EUR of 7.4 Bcf 2nd Well 7-Day IP: 4.5 MMcf/d

Tionesta – Delineating 1 Well Completed

Ridgway – Delineating 1 Well Completed

2013 Drill Program

Seneca Operated

Heath – Delineating 1 Well Planned

Sulger Farms – Delineating 1 Well Planned

Hemlock – Delineating 1 Well Planned

2014 Drill Program

Church Run – Delineating 1 Well Completed

Clermont – Full Development 2 Wells Completed

9H: 7-Day IP of 10 MMcf/d & EUR of 8.6 Bcf 10H: 7-Day IP of 7.4 MMcf/d & EUR of 6.6 Bcf

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Marcellus Shale Rich Valley/Clermont is in Full Development Mode

47

Clermont

Rich Valley

Rich Valley 2nd Well 7-day IP: 4.5 MMcf/d Lateral Length: 4,492’

Marcellus Faults Marcellus & Basement Faults

200-250 Horizontal Locations

Pad N: Spacing Test

JV Wells Pad H

Pad D Pad E

Pad O

SRC Lease Acreage SRC Fee Acreage

Clermont RCS: 9H 7-day IP: 10.0 MMcf/d (EUR: 8.6 Bcf)

Non-RCS: 10H 7-day IP: 7.4 MMcf/d Rich Valley

7-day IP: 7.8 MMcf/d EUR: 7.4 BCF

Lateral Length: 6,372’

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Marcellus Shale Clermont Wells Improved from Early Non-Op JV Wells

48

Clermont 5H & 6H (Non-op wells) Avg. lateral length: 3,344’ Small casing: 4.5” Restricted pump rates

Wide stage spacing: 350’ No soaking, low Sw’s

Clermont 9H & 10H (Seneca wells) Avg. lateral length: >5,500’ Large casing: 5.5” Increased pump rates

9H (RCS): 150’ spacing 10H (Standard): 240’ spacing Soaked both wells: 30 Days

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

10,000

0 5 10 15 20 25 30

Mcf

per

Day

Days On

9H 10H COP 2316 5H COP 2316 6H

SRC Clermont vs. Non-Op JV Clermont

9H: RCS Completion (150’ stage spacing)

10H: Standard Completion (240’ stage spacing)

Non-Op JV Wells (5H, 6H)

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Marcellus Shale Moving All Completions to Reduced Cluster Spacing (RCS)

49

300’

Wellbore Formation Fracture

RCS Design ~1000’

300’

Formation

~1000’

Conventional Design

Wellbore Fracture

Twice the number of stages/perforations Increases stimulated reservoir volume

Increased proppant near the wellbore improves fracture conductivity

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0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

0 100 200 300 400 500 600 700

Flow

back

Gas

Rat

e (M

cfd)

Elapsed Time

Ridgway Church Run ON1H-Sales ON3H-Sales ON54H

Church Run

Owl’s Nest

Ridgway

Marcellus Shale Consistently Improved Results in the Owl’s Nest Area

50

Owl’s Nest Area

2013 Appraisal Program

Lateral length >4,400’ to 6,200’

RCS completions 150’ spacing

Soaked wells 30 – 60 days

Target interval Union Springs: 100% in

target

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Marcellus Shale Strong Wells Across WDA Acreage

51

Well Name Completion

Design

Treatable Lateral Length Stages

Peak 24-Hour

Rate (MMcfd)

Peak 7-Day Rate

(MMcfd) EUR (Bcf) Status

Rich Valley 27H RCS1 6,372’ 42 8.1 7.8 7.4 Producing

Clermont 9H RCS 5,500’ 37 11.4 10.0 8.6 Producing

Clermont 10H Non-RCS 5,565’ 23 8.1 7.3 6.6 Producing

Ridgway 19H RCS 5,537’ 37 7.1 6.4 5-8 Flowback Test

Church Run 2H RCS 4,435’ 29 4.8 4.5 4-6 Flowback Test

Owl’s Nest 54H RCS 6,139’ 41 6.1 5.8 4-7 Flowback Test

Owl’s Nest 59H RCS; Gel2 5,371’ 36 3.4 3.1 2-4 Flowback Test

(1) RCS – Reduced Cluster Spacing (2) Completed using linear gel to place larger proppant near the wellbore

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Marcellus Shale Key Areas of Improvement in Recent Delineation Program

52

Areas of Improvement 2012-2013 Delineation Program

Target Selection (Landing Depth) Identification of specific target interval is key

Target Execution Percent of wellbore in target interval increased from prior years

Completion Design Reduced Cluster Spacing (RCS)

Shorter stages: From 240-350’ down to 150’ Increased volume of sand per foot

Lateral Length Drilled laterals 15-45% longer than in prior years

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23% 33%

83%

0%

25%

50%

75%

100%

2009 2010 2011 2012 2013 2014

Perc

ent I

n Cu

rren

t Tar

get (

% o

f CLL

)

Well Year

Percentage of Wellbore in Current Target Interval

WellsAverages

Marcellus Shale Selection of Target Interval is Critical

53

Previous programs spent a significant portion ( > 60% ) of the wellbore outside of the current target interval, identified to have improved productivity

260% Improvement

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Marcellus Shale Optimized Landing Depth

54

EDA Lycoming Type Log

160 140 120 100 80 40 20 60 ROP (ft/hr)

ROP vs Height Above Onondaga

Improved Target Zone Drivers

Best rock quality in terms of organic content, brittleness, and porosity

Highest rate of penetration (ROP)

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71% 69%

83%

0%

25%

50%

75%

100%

2009 2010 2011 2012 2013 2014

Perc

ent I

n Ta

rget

(% o

f CLL

)

Well Year

Percent of Wellbore In Target Zone (15-20’ Interval)

WellsAverages

Marcellus Shale Continued Improvement Staying within Targeted Interval

55

17% Improvement

Reasons for Improvement

3D seismic acquisition Improved communication between Geology, Drilling and Completion teams Geosteering technology (azimuthal GR)

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Marcellus Shale RCS & Increased Sand Volume Generating Better Results

56

1,275

1,448 1,479

1,200

1,300

1,400

1,500

1,600

1,700

2009 2010 2011 2012 2013 2014

Poun

ds o

f Sa

nd p

er F

oot

Well Year

Pounds of Sand per Foot

Wells Averages

349

266

162

0

10

20

30

40

50

60

100

150

200

250

300

350

400

2009 2010 2011 2012 2013 2014

Stag

e Co

unt

Avg.

Sta

ge S

paci

ng p

er F

oot

Well Year

Stage Spacing & Count

Wells Averages Stage Count

Improved near wellbore fracture conductivity

Increases near wellbore fracturing & stimulated reservoir volume

Reducing stage length, increasing the number of stages, and increasing proppant volume have been integral in improving well productivity

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Marcellus Shale Longer Laterals Drive Improved Economics

57

3,709

4,838

5,586

2,000

3,000

4,000

5,000

6,000

7,000

2009 2010 2011 2012 2013 2014

Com

plet

ed La

tera

l Len

gth

(ft)

Well Year

Completed Lateral Length (ft) WellsAverages

50% Increase

Lateral lengths have increased even as target selection and execution have improved

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Marcellus Shale 2013 Appraisal Program was a Success

58

50-hr Flowback Rate (Mcf/d/1000') P10 P50 P90 Mean StDev

FY13 Program 1,427 1,128 893 1,147 211

Previous Programs 1,002 519 270 589 329

95% improvement

-2.400

-1.900

-1.400

-0.900

-0.400

0.100

0.600

1.100

1.600

2.100

100 1000

Avg Rate, Peak 50 hr/1000'

P50

P60

P70

P80

P90

P99

P1

P10

P20

P30

P40

Rich Valley Flowback EUR: 7.4 BCF

2010-2011 Program

2013 Program

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Marcellus Shale 200,000 Acres With 6-8 Bcfe EUR Wells

59

SRC Lease Acreage

SRC Fee Acreage

EOG Earned JV Acreage

Vertical well data base

2014 Hz Appraisal Program 2015+ Locations

4 - 6 BCF/well

4 - 6 BCF/well

6 - 8 BCF/well

2-4 BCF/well

2-4 BCF/well

Note: Assumes 6,000’ treated lateral length

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Marcellus Shale 1,700 To 2,000 Economic WDA Locations Below $4/Mcfe

60

Prospect County Product

Approx. Remaining Locations

EUR (Bcfe) BTU

IRR(1) @ $4/MMBtu

15% IRR(1) Breakeven Price

($/Mcf)

Tract 100 Lycoming Dry Gas 40 11.5 1,030 90% $2.20

Gamble Lycoming Dry Gas 29 10-11 1,030 77% $2.33

Tract 595 Tioga Dry Gas 20 8.4 1,030 45% $2.63

Clermont/Rich Valley Elk/Cameron Dry Gas 228 6-8 1,050 38% $2.80

Ridgway Elk Dry Gas 450-570 6-8 1,111 26% $3.30

Hemlock Elk Dry Gas 130-170 6-8 1,070 23% $3.40

Church Run Elk Dry Gas 60-70 6-8 1,125 22% $3.45

(W) West Branch McKean Dry Gas 47 6-8 1,050 22% $3.48

Covington Tioga Dry Gas Developed 5.7 1,030 22% $3.49

Heath Jefferson Dry Gas 260-330 5-8 1,060 19% $3.65

Sulger Farms Jefferson Dry Gas 170-210 5-8 1,020 19% $3.66

Owl’s Nest/James City Elk/Forest Dry Gas 120-160 5-8 1,125 18% $3.69

Boone Mt. Elk Dry Gas 230-290 4-6 1,020 18% $3.76

Church Run Elk Wet Gas 40-50 2-4 1,140 13% $4.32

Tionesta Forest/Venango Wet Gas/ Liquids 300-340 4-6 1,325 12% $4.50

Owl’s Nest/James City Elk/Forest Wet Gas 150-180 4-6 1,140 11% $4.51

Mt. Jewett McKean Wet Gas 90-110 2-4 1,140 6% $5.50

Beechwood Cameron Dry Gas 210-280 2-4 1,030 2% $7.14

Red Hill Cameron Dry Gas 150-200 2-4 1,030 2% $7.14

2013 Appraisal prospects 2014 Appraisal prospects

(1) Internal Rate of Return (IRR) includes estimated well costs, LOE, and Gathering tariffs anticipated for each prospect

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Marcellus Shale Marketing Intercompany Gathering Ensures Timely Gas Sales

61

Develop gathering infrastructure with

NFG Midstream

Firm transport (FT) to major markets

Firm sales tied to FT contracts


and basis risk


and basis risk

Historical Strategy

Current/Long-Term Strategy

Firm sales at interstate pipeline

interconnects

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Marcellus Shale Marketing Securing Firm Transportation to Major Markets

62

Current Seneca Development Areas

Firm transport to Canada, Northeast and Southeast U.S.

markets

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Marcellus Shale Marketing TGP 300 Production & Firm Sales Aligned Thru 2014

63

0

20

40

60

80

100

120

140

160

180

200

Gro

ss M

MBt

u pe

r Day

Dawn NYMEX Dominion Production (Forecast)

Dawn Index Less $0.44

Dominion Index Less $0.37

NYMEX Index Less $0.24

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Marcellus Shale Marketing Targeting Future Firm Sales on Transco

64

0

50

100

150

200

250

300

350

400

Gro

ss M

MBt

u pe

r Day

Transco Z6 NY/NNY NYMEX Dominion Production (Forecast)

Transco Zone 6 Index Less $0.57

Dominion Index Less $0.14

NYMEX Index Less $0.29

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Point Pleasant & Utica Shale Continuing to Delineate

65

Permitted Drilled/Drilling Completed Producing Mt. Jewett

Horizontal: completed September 2013 Peak 24-Hour Rate: 8.5 MMcf/d

Tionesta Horizontal: Completed Fall 2012 Peak 24-Hour Rate: 3.9 MMcf/d

Rex

9.2 MMcf/d

Chesapeake

6.4 MMcf/d

Range Resources

4.4 MMcf/d

Range Resources

1.4 MMcf/d “Not Effectively Stimulated”

Halcon

6.6 MMcf/d, 750 Bbls/d

Halcon


Halcon


Eastern Ohio Point Pleasant Core

Point Pleasant Northern Boundary

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Mississippian Lime Commencing Evaluation Program in Fiscal 2014

66

Total Net Acres: 13,615 100% working interest in 4,400

gross acres

55% net working interest in 17,365 gross acres Negotiated an increase in Seneca’s

working interest and have taken over as operator

Currently drilling first well Will drill up to 5 evaluation wells in

2014

The initial entry into the Mississippian Lime play furthers the Company’s goal of maintaining a significant contribution from oil-producing properties

Unit

30-day IP: 352 BOED

(92% Oil/NGLs)

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67

California Update

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California Stable Production Fields; Modest Growth Potential

68

4,50

0

500

1,70

0

1,20

0

800

4,00

0

1,20

0

1,50

0

1,10

0

1,10

0

500

0

1,500

3,000

4,500

6,000

NorthMidwaySunset

SouthMidwaySunset

SouthLost Hills

NorthLost Hills

Sespe EastCoalinga

Gro

ss O

pera

ted

Daily

Pr

oduc

tion

(Boe

/d)

20102013East 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

Key Areas of Focus in 2014 1. East Coalinga Evaluation 2. South Midway Sunset Extensions 3. Sespe Coldwater Evaluation

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California South Midway Sunset Has Delivered Significant Growth

69

0

500

1,000

1,500

2,000

Daily

Pro

duct

ion

(Boe

per

day

)

Monthly Production at South Midway Sunset

Seneca Acquired in June 2009

Highlights Since Acquisition

Increased daily production by 130% Drilled 80 new producers Added 3.3 MMBO of proven reserves Increased steam capacity by 280% Identified opportunities for additional

pool development

252 Pool

97X Pool

SE Pool 251 Pool

B Pool A Pool

Extended Pool Boundary

Original Pool Boundary

Existing Wells

1000’

16X Pool

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California South MWSS Growth Opportunities Continue into 2014

70

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California Early Success in Farm-In with Chevron at East Coalinga

71

1-Acre Test 48 BOPD

5-Acre Test 54 BOPD

2-Acre Test 18 BOPD

2000’

Returned to Production

1-acre (~30 locations) 2-acre (~40 locations)

5-acre (~120 locations)

Downspacing Potential

2013 Evaluation Wells

Seneca Lease

Existing Wells

0

250

500

750

Daily

Pro

duct

ion

(Boe

per

Day

)

Monthly Production @ East Coalinga

Seneca Acquired in January 2013

Highlights Since Acquisition

Achieved highest field production in 10 years

Production increased 130% since 1/2013 Drilled 12 evaluation wells that

confirmed downspacing potential Returned 40 idle wells back to production

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California Ramping Up the Coalinga Drill Program in Fiscal 2014

72

2014 Development Program (Tentative)

Location Selection Criteria

2014 Locations (30) 2013 Locations (12)

• 2013 new well production • Reservoir pressure mapping • Historical production • Past EOR attempts

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California Ongoing Evaluation of Long-Term Sespe Potential

73

TC 524-28 IP: 100 BOEPD 1st Oil 10/13

“X” SANDS ISOCHORE (Thickness)

1 Mile

2011 Wells (5)

2012 Wells (6)

2013 Wells (6)

2014 Wells (4) TC 525-28

IP: 160 BOEPD 1st Oil 10/13

WS 525-33 1st Oil in 11/13

WS 535-33 1st Oil in 11/13

Year Target # of

Wells Average IP (BOEPD)

2011 Sespe (5-Acre Infill) 2 75

2011 Sespe (10-Acre) 3 90

2012 Sespe (5-Acre Infill) 2 70

2012 Coldwater 2 125

2012 Sespe (10 Acre) 2 110

2013 Sespe (5-Acre Infill) 2 NA

2013 Coldwater 2 130

2013 Sespe (10 Acre) 2 85

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California Evaluating the Monterey Shale at South Lost Hills

74

Citrus 11

Upper Antelope A

Upper Antelope B

McDonald

Truman 1H 2013 190 BOEPD

Citrus 2H Planned FY14

Truman 2H Planned FY14

GR SP ResD

Brittleness Gas Oil

18 potential locations in each of the three horizons (concept)

Seneca Lease 1000’

Lower Reef Ridge

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California Limited Growth Opportunities, But Strong Economics

75

Field Average

Well Cost

Average EUR

(MBO)

Estimated IRR

@$100/Bbl Fiscal 2014 Locations

South Midway Sunset $250,000 30 75% 23

East Coalinga $400,000 40 50% 30

Sespe – 5 Acre Infill $2,800,000 150 25% 0

Sespe - Coldwater $2,800,000 180 35% 4

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9,056 8,773

9,322 9,078

6,000

7,000

8,000

9,000

10,000

2010 2011 2012 2013 2014 (Est.) 2015 (Est.)

Aver

age

Daily

Net

Pro

duct

ion

(BO

E pe

r Day

)

Fiscal Year

California Modest Growth Anticipated in 2014 and 2015

76

Forecast

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Marcellus Operational & Environmental Overview

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Marcellus Shale Our Development Approach Drives Major Efficiencies

78

Multi-Well Pads

Focused Development

Areas

Faster Spud-to-Sales Timing Economies of Scale Reduces Costs

Minimal Infrastructure Constraints & Well Backlog

Technical & Operational

Expertise

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Marcellus Shale EDA Delivering Significant Growth

79

Covington – Fully Developed Gross Production: ~60 MMcf per Day 47 Wells Drilled and Producing

DCNR Tract 595 Gross Production: ~100 MMcf per Day 34 Wells Drilled (52 Total Locations) 26 Wells Producing

DCNR Tract 100 Gross Production: ~220 MMcf per Day 40 Wells Drilled (70 Total Locations) 30 Wells Producing

Gamble Recently, 30 to 50 future locations were added in Lycoming County

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Marcellus Shale EDA – Historical Well Results Are Exceptional

80

Development Area Producing Well Count

Average IP Rate

(MMcf/d)

Average 7-Day

(MMcf/d)

Average 30-Day

(MMcf/d)

Average EUR

per Well (Bcf)

Average Lateral Length

EUR per 1,000’ of Lateral (Bcfe)

Covington Tioga

County 47 5.2 4.7 4.1 5.7 4,023’ 1.42

Tract 595

Tioga County

26 7.1 6.0 5.1 8.4 4,639’ 1.81

Tract 100 Lycoming

County 30 16.1 14.2 11.9 11.5 5,210’ 2.21

Seneca’s acreage in Lycoming County has consistently delivered some of the most prolific wells in the Marcellus Shale

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Marcellus Shale Faster Spud-to-Sales: Drilling Efficiencies

81

642 624

829

1,050

1,200

1,320

0

500

1,000

1,500

2011 2012 2013 2013Q4

2014(Est.)

BestFYTD

Daily

Foo

tage

Fiscal Year

DCNR Tract 100 (Lycoming) Average Daily Drilling Footage

How has this been accomplished?

Directional Plan Optimization Minimize drilling path corrections

Bit Selection Increases drilling rate and durability

Drill Top-hole Sections Deeper with Water More efficient and cost effective

Optimize Landing Depth Improves production and rate of

penetration

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Marcellus Shale Faster Spud-to-Sales: Multi-Well Pads Are Key

82

Limiting the movement of rigs between pads allows for more drilling

Using LEAN practices has eliminated four days from each rig move

Staying in smaller regional areas further limits move time

18.2

10.1

5.4 3.7

2.8

18.2

20.2

21.4 21.9 22.1

16

18

20

22

24

0

4

8

12

16

20

24

1 2 4 6 8W

ells

per

Yea

r

Rig

Mov

es

Wells per Pad

Average Number of Yearly Rig Moves

Average Rig Moves (per Rig) Average Wells per Year (per Rig)

$390

$225

$143 $115 $103

$2.6

$4.0

$4.6 $4.8

$0.0

$1.0

$2.0

$3.0

$4.0

$5.0

$6.0

$0

$100

$200

$300

$400

$500

1 2 4 6 8

Cum

ulat

ive

Annu

al C

ost S

avin

gs ($

Mill

ions

)

Aver

age

per W

ell M

ove

Cost

($ T

hous

ands

)

Wells per Pad

Average Rig Move Cost per Well

Average per Well Move Cost Average Savings per Year (per Rig)

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Marcellus Shale Drilling Efficiencies Allow for More Wells per Year

83

12.0 11.6 11.3

14.5

18.7 3,929

4,614 4,650 5,021

5,500

0

2,000

4,000

6,000

0

10

20

30

2010 2011 2012 2013 2014 (Est.)

Aver

age

Late

ral L

engt

h (F

eet)

Wel

ls p

er R

ig p

er Y

ear

Fiscal Year

Drilling Efficiency vs. Lateral Length All Marcellus Wells

In spite of increasing the average lateral length, each rig is drilling more wells per year

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Marcellus Shale Faster Spud-to-Sales: Completing More Stages per Day

84

3

7

10

12

0

5

10

15

2012 2013 2014Q1

2014(Est.)

RCS

Stag

es p

er D

ay

Fiscal Year

DCNR Tract 100 (Lycoming) RCS Stages per Day

How has this been accomplished?

Completion Efficiency Technologies Hydraulic toe sleeves, frac sleeves,

Lean fundamentals (NPT tracking)

24-Hour Operations Double the stages per day

Water Pipelines More efficient than trucking water

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Marcellus Shale Faster Spud-to-Sales: The Overall Picture

85

164

161

158

131

89

89

72

101

95

60

253 Days

233 Days

259 Days

226 Days

149 Days

2010

2011

2012

2013

2014 (Est.)

Average Spud-to-Sales for a 6-Well Pad (Normalized for 5,500’ Laterals per Well)

Drilling Completion

(1)

(1) 2010 completion time based on a 5-well pad normalized to a 6-well pad

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Marcellus Shale Faster Spud-to-Sales: More Lateral Feet Completed Yearly

86

270 591 491

246

120

1,052

1,888

7

270

591 611

1,298

1,888

0

200

400

0

500

1,000

1,500

2,000

2009 2010 2011 2012 2013 2014(Est.)

Late

ral F

eet C

ompl

eted

(Tho

usan

ds)

Stag

es C

ompl

eted

Fiscal Year

Total Lateral Feet & Stages Completed

Stages per Year (RCS)Stages per Year (Non-RCS)Lateral Feet Completed

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Marcellus Shale Drilling Cost Reductions: Several Contributing Factors

87

22.0 24.0

18.0 14.8

12.0 11.1

0

10

20

30

2011 2012 2013 2013Q4

2014(Est.)

BestFYTD

Dril

ling

Day

s

Fiscal Year

DCNR Tract 100 (Lycoming) Average Drilling Days to TD

(Normalized for a 5,500’ Treatable Lateral) $4.4

$3.8 $3.3

$2.5 $2.3 $2.0

$0.0

$1.0

$2.0

$3.0

$4.0

$5.0

2011 2012 2013 2013Q4

2014(Est.)

BestFYTD

Drill

ing

Cost

($ M

illio

ns)

Fiscal Year

DCNR Tract 100 (Lycoming) Average Drilling Cost

(Normalized for a 5,500’ Treatable Lateral)

Improvements From 2012 to 2013 ($525,000 per well) Shorter drilling days to TD: $300,000 Faster rig moves (2012: 8.5 Days → 2013: 4.5 Days): $20,000 (6-well pad) Procurement and supply chain initiatives: $120,000 Directional plan optimization: $60,000 Natural gas-powered rigs: $25,000

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Marcellus Shale Completion Cost Reductions: Ongoing Optimization

88

$160

$131 $120

$113

$0

$50

$100

$150

$200

2012 2013 2014(Est.)

Best FYTD

Com

plet

ion

Cost

s per

Sta

ge ($

Tho

usan

ds)

Fiscal Year

DCNR Tract 100 (Lycoming) Average RCS Completion Cost per Stage

How is this being accomplished?

New Frac Contract in 2014 Pumping, sand and chemical costs

reduced ~20% Savings: $10,000/stage

Completion Efficiencies 24-hour operations New technologies Savings: $5,000/stage

Water Infrastructure Full trucking: $7.00/Bbl Limited trucking: $1.50 - $3.00/Bbl Savings: $25,000/stage

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Marcellus Shale Completion Cost Reductions: New Efficient Technologies

89

Prep

• 4 days per well • 24 days per 6-well pad

Frac


Drill-Out


Toe Sub $60,000 savings per well

Time Savings

Time Savings

Time Savings

Sleeve $200,000 savings per well

Dissolvable Balls $300,000 savings per well

$3.4 million saved on a 6-well pad from the utilization of new technologies

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Marcellus Shale Completion Cost Reductions: Water Infrastructure

90

System Cost: $8.5 million 8 miles of pipeline 43 million gallons of storage Will serve at least 70 wells Provides 75% of water needs, with

the remainder being recycled production fluid

Environmental & Cost Benefits Eliminated the need for 47,000

water trucks since February 2012 Saved more than $4 million on Tract

100 development to date

Improved Efficiencies Trucking in water across this

challenging terrain would have delayed completions and production Storage Impoundment

Water Pipeline

This model has been successful in Lycoming & Tioga counties and will be utilized in the WDA as development progresses

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Marcellus Shale Minimizing Backlogs: Coordinated Development

91

Coordination with NFG Midstream to construct gathering systems Development well backlog typically consists of wells on pads in either

the drill or complete phase

Regional development programs Focus on multi-well pads in smaller geographic areas allows for efficient

gathering connectivity

Managing completion schedule Ongoing monitoring of operations and maintaining the flexibility to alter

completion schedules

Sales Lag (Months)

0 6 12 18 IRR(1) @ $4/Mcf Realized Pricing 90% 58% 46% 38%

(1) Assumes 6,000’ completed lateral length, $7.5MM well cost, and 11.5 Bcf EUR

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Seneca Resources Committed to Health, Safety, and the Environment

92

Seneca Resources Corporation – Value Statement

“We ask that each employee share in our philosophy and unwavering commitment to each other’s health and safety and the environment.”

“…creating a systematically

integrated model of EHS stewardship

beyond mere compliance.”

Dedicated 24-Hour EHS Hotline and E-mail Address

Best Practices Incorporating Lean Process Strategies

Management team dedicated to building a culture of continual

EHS improvement Operating Excellence Program

Compliance Department

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93

Midstream Businesses Overview

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NFG Midstream Businesses

Pipeline & Storage Segment

National Fuel Gas Supply Corporation

Empire Pipeline, Inc.

Gathering Segment

National Fuel Gas Midstream Corporation

Midstream Businesses National Fuel’s Midstream Businesses

94

Reporting Segments

Subsidiaries

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Midstream Businesses Positioned Well to Serve Appalachian Producers

95

National Fuel Gas Supply Corporation

System Length ~ 2,550 Miles

Storage Capacity 73.4 Bcf

Contracted Transport 2.58 MMDth/d

2013 Revenue $191.2 Million

2010 – 2013 Capital Expenditures $304.6 Million

Major Interconnects

Niagara(TCPL)

Leidy (Transco/TETCO)

Holbrook (TETCO)

Mercer (TGP)

Independence (Millennium)

Ellisburg (TGP 300)

East Aurora (TGP/DTI)

NFG

NFG

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96

Empire Pipeline

System Length ~250 Miles

Contracted Transport 1.07 MMDth/d


2010 – 2013 Capital Expenditures $62.8 Million

Major Interconnects

Sithe

Mendon (RG&E)

Chippawa (TCPL) Hopewell (TGP 200)

Corning (Millennium)

Jackson (Shell/Talisman)

Lysander

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97

NFG Midstream Corp.

System Length 59 Miles


Capital Expenditures (Since Inception) $168 Million

Major Interconnects

TGP 300

Transco

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Midstream Businesses Long-Term Strategy Driven by Both Seneca & 3rd Parties

98


3rd Party Shippers

Seneca Resources

Develop strong partnerships with customers to help them reach diverse, high-value markets

Diverse Markets

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Midstream Businesses Positioned to Serve Seneca’s Rapidly Growing Production

99

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Gathering Gathering is the Crucial First Step to Reaching a Market

100

TGP 300

Transco

TGP 200

Trout Run Gathering System

(In-Service)

Covington Gathering System

(In-Service)

Clermont Gathering System

(Under Construction)

Gathering Interconnects (In-Service and Under Construction)

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Gathering Existing Systems Supporting Seneca’s Near-Term Growth

101

Covington Gathering System In-service date: November 2009 Capacity: 220,000 Dth per day Interconnect: TGP 300 Capital expenditures (to date): $28.3 million Capital expenditures (future): $7.5 million

Trout Run Gathering System In-service date: May 2012 Capacity: 466,000 to 585,000 Dth per day Interconnect: Transco – Leidy Lateral Capital expenditures (to date): $128.0 million Capital expenditures (future): $60 to $90 million

$14 $16 $15-

$17

$2 $17

$41-

$50

-

40

80

120

160

$0

$25

$50

$75

$100

2010 2011 2012 2013 2014(Est.)

Thro

ughp

ut (M

MDt

h)

$ M

illio

ns

Fiscal Year Revenue by Project (Covington & Trout Run Systems)

Covington Trout Run Total Throughput

Interconnects

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Gathering Developing a 1+ Bcf/d Gathering System in the WDA

102

In-Service: August 2014

Initial Trunkline Capacity: 700 MMcf per day

Interconnect TGP 300

Total Cost: $60-$92 Million

Major Facilities 24” Pipeline – 6 Miles 8”-20” Pipeline – 25+ Miles

Seneca Pads Producing 2 in Fiscal 2014 (15 Wells)

Clermont 2014 Expansion

Plan to expand ahead of Seneca’s development to

provide natural gas as rig fuel

Compressor Station

Interconnect

C

C

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Gathering Clermont Gathering System has Large Expandability

103

C

C Clermont 2015 Expansion In-Service: Ongoing build-out

Ultimate Trunkline Capacity: 700 to 1,000 MMcf per day

Interconnects TGP 300 and National Fuel

Gas Supply Corporation (anticipated)

Total Cost: $75 - $125 million

Major Facilities Additional Gathering Clermont West, Clermont

East and Rich Valley Compressor Stations

Seneca Pads Connected Up to 25 pads connected

following the 2015 expansion

C

Compressor Station

Interconnect

C

C

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Gathering A Number of Options to Serve 3rd Party Producers

104

C

C

C Midstream is evaluating a number of

trunkline and gathering line expansions in fiscal 2015 and beyond, depending on Seneca

activity and third-party producer interest

Compressor Station

Interconnect

C

C

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Gathering 2014 Spending Driven by Seneca Development

105

60% 28%

6% 6%

2014 Forecast Capital Expenditures

$100 to $150 Million

Clermont - $60 MM - $92 MM Build 30+ miles 24” and smaller diameter pipe Procure 10 compressor units for Phase I Upgrade existing interconnect into TGP

Trout Run - $30 MM - $40 MM Complete two compressor stations

(Total = 15 units) Initiate build out of Gamble Prospect

gathering, south of DCNR Tract 100

Covington - $6 MM - $9 MM Build gathering for 3 additional well pads at

DCNR Tract 595

Other Seneca WDA Prospects - $4 MM - $ 9 MM Build gathering and interconnect locations for

Church Run and Ridgway prospects

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Gathering More than 1.5 Bcf per day of Gathering Capacity by 2015

106

220 220 220 220

466 466 466 466

700

700- 1,000

100 160 220

686 706

1,421

1,421- 1,721

0

500

1,000

1,500

2,000

2,500

2009 2010 2011 2012 2013 2014Forecast

2015Forecast

Year

-End

Gat

herin

g Ca

paci

ty (M

Mcf

per

Day

)

Fiscal Year

NFG Midstream Gathering Capacity

Covington Trout Run WDA Other Clermont

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Gathering Capital Deployment Will Deliver Long-Term Growth

107

$17.5

$34.8

$60-$72

$80-$95

$113

$168

$268-$318

$368-$468

$0

$30

$60

$90

$120

$150

$0

$100

$200

$300

$400

$500

2009 2010 2011 2012 2013 2014Forecast

2015Forecast

Reve

nue

($ M

illio

ns)

Capi

tal E

xpen

ditu

res (

$ M

illio

ns)

Fiscal Year

RevenueCumulative Capital Invested

Revenue Growth (2013 to 2015): ~60% CAGR

Capital Investment (2013 to 2015): ~60% CAGR

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Pipeline & Storage Project Opportunities to Support WDA Growth

108

Develop multiple outlets to high-value markets

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Midstream Businesses Providing Transportation to Higher-Priced Markets

109

Currently Short Supply

Short Supply

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Midstream Businesses NE Supply Approaching NE Peak Demand

110

-

5

10

15

20

25

30

2005 2007 2009 2011 2013 2015 2017

Nor

thea

st S

uppl

y (B

cf p

er D

ay)

Kentucky New York Ohio Pennsylvania Virginia West Virginia

Forecasted Actual

Peak Demand (24-25 Bcf per day)

Median Demand (11.5 Bcf per day)

Supply exceeds demand for 70% of the year by 2016

Source: Production Data – Bentek Northeast Natural Gas Production Monitor (November 2013); Demand Data – TPH Research

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Midstream Businesses Focusing on Projects to Non-Traditional Demand Markets

111

Short Supply The markets of Eastern Canada, the Mid-Atlantic and Southeast look to be the most desirable markets for shippers to reach over the long-term

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Pipeline & Storage Delivering Into the Eastern Canadian Market is Valuable

112

$0.00

$0.20

$0.40

$0.60

$0.80

$1.00

$1.20

$1.40

$ pe

r MM

Btu

Eastern Canada (Dawn) is Currently a Premium Priced Market Dawn to Henry HubDawn to Dominion South Point

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Pipeline & Storage Northeast PA Spot Markets are Heavily Discounted

113

$0.00

$0.50

$1.00

$1.50

$2.00

$2.50

$3.00

$3.50

$4.00

$ pe

r MM

Btu

Eastern Canada (Dawn) is Currently a Premium Priced Market Dawn to Dominion South PointDawn to TGP 300 - Zone 4

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Pipeline & Storage Major Expansion Designed for Canadian Deliveries

114

Northern Access 2015

Niagara (TCPL)

Delivery Point

In-Service: November 2015

System: NFG Supply Corp.

Capacity: 140,000 Dth per day

Interconnect Niagara (TransCanada)

Total Cost: $67 Million

Major Facilities 23,000 HP Compressor


Canada & Eastern U.S.

Clermont

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Pipeline & Storage Clermont to Chippawa Provides Delivery Options

115

Delivery Point

Clermont to Chippawa

Chippawa (TCPL) Hopewell (TGP 200)

Corning (Millennium)

In-Service: 2016

System: Supply & Empire

Capacity 250,000+ Dth per day

Interconnects Corning (Millennium) Hopewell (TGP 200) Chippawa (TransCanada)

Total Cost: ~$250 Million


Canada & Eastern U.S.

New England

New York City

Clermont

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Pipeline & Storage Longer-Term: Reaching Markets Along the Atlantic

116

Transco

In-Service: 2017


Capacity 300,000 to 500,000 Dth per day

Interconnect Transco Leidy Line

Total Cost: $100 to $150 Million

Clermont to Transco

To Mid-Atlantic &

Southeast

Clermont to Transco

Delivery Point

Clermont

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Pipeline & Storage Expansions to Move Gas from the WDA are Significant

117

Projects to Support WDA Growth

Project Capacity (Dth/day)

Northern Access 2015 140,000

Clermont to Chippawa 250,000+

Clermont to Transco 300,000-500,000

Total New Capacity 690,000-890,000+

Project Capital Cost

Northern Access 2015 $67 million

Clermont to Chippawa $250 million

Clermont to Transco $100-$150 million

Total Capital Expenditures $417-$467 million



Longer-Term WDA Expansion

Clermont

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Pipeline & Storage Seneca Currently Represents a Small Portion of Capacity

118

3%

7%

9%

21%

29%

31%

Affiliated Producer

All Other

Non-Affiliate Marketer

Non-Affiliate LDC

Affiliated LDC

Non-Affiliate Producer

Contracted Transportation Capacity (National Fuel Gas Supply Corp. & Empire Pipeline)

Total Contracted Transportation Capacity (at 9/30/13): 3.6 MMDth per Day

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Pipeline & Storage Recent 3rd Party Expansions Have Been Highly Successful

119

Projects to Support 3rd Parties

Project Capacity

(Dth/day)


Tioga County Extension 350,000

Line N (2011, 2012 & 2013) 353,000

Total New Capacity 1,023,000

Project Capital Cost

Northern Access 2013 $72 million

Tioga County Extension $58 million

Line N (2011, 2012 & 2013) $104 million

Total Capital Expenditures $234 million


Tioga County Extension

Line N Projects

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Pipeline & Storage NFGSC is Now a Net Exporter of Natural Gas to Canada

120

(500)

(400)

(300)

(200)

(100)

-

100

MD

th p

er D

ay

Throughput at the Niagara Delivery Point (Canadian Border)

Tennessee Gas Pipeline

National Fuel Gas Supply Corp.

Northern Access project was placed in-service

November 2011

Source: Internal data; TGP Flow Data – Bentek Northeast Observer (Monthly Average from June 2011 through October 2013)

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0

100

200

300

400

500

600

700

800

2008 2009 2010 2011 2012 2013

Aver

age

Daily

Thr

ough

put (

MD

th p

er D

ay)

All Other Pipes NFGSC

Pipeline & Storage National Fuel Becoming a Major SW PA Transporter

121

National Fuel Gas Supply Corp. went from no SW Pennsylvania receipts in 2008 to nearly 40% of all volumes today

Source: Production Data – Bentek Northeast Natural Gas Production Monitor (November 2013)

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Pipeline & Storage Additional Line N Expansions Planned for the Future

122



Capacity: 105,000 Dth per day Precedent agreements signed for all

available capacity

Interconnect Mercer (TGP Station 219)

Total Cost: $30 Million Expansion: $27 million System Modernization: $3 million

Major Facilities 3,500 HP Compressor 2.1 miles – 24” Replacement Pipeline

Mercer Expansion

Mercer (TGP Station 219)

Mercer Expansion

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Mercer (TGP Station 219)

Pipeline & Storage Pairing Line N Expansions with System Modernization

123



Capacity: 175,000 Dth per day Precedent agreements signed for

145,000 Dth per day

Interconnect Mercer (TGP Station 219) Holbrook (TETCO)

Total Cost: $74 Million Expansion: $39 million System Modernization: $35 million

Major Facilities 3,600 HP Compressor 23.5 miles – 24” Replacement Pipeline

Westside Expansion & Modernization

Holbrook (TETCO)

Westside Expansion &

Modernization

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Pipeline & Storage Developing Unique Solutions for Shippers

124


System: NFG Supply & Empire Pipeline

New No-Notice Services Preserving 172,500 Dth per day (RG&E) Preserving 20,000 Dth per day (NYSEG) Precedent agreement executed with

RG&E

Capacity Transportation: 69,000 Dth per day Retained Storage: 3.3 Bcf

Interconnect Tuscarora (NFG/Supply)

Total Cost: $56 Million

Major Facilities 1,500 HP Compressor 18 miles – 20” Replacement Pipeline

Tuscarora Lateral

Tuscarora Lateral

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Pipeline & Storage Significant Expansions Are Driving Growth

125

Completed Projects

Project Capacity

(Dth/day)

Lamont Compressor Station 90,000

Line “N” Expansion 160,000

Tioga County Extension 350,000

Northern Access Expansion 320,000

Line “N” 2012 Expansion 163,000

Line “N” 2013 Expansion 30,000

New Capacity Additions 1,113,000

Mercer Expansion Project 105,000

West Side Expansion 145,000


Tuscarora Lateral 69,000

Planned Capacity Additions 459,000

Line N Corridor Line “N” Expansion

Line “N” 2012 Expansion Line “N” 2013 Expansion

Mercer Expansion West Side Expansion

Total Capacity 603 MDth/d

Delivering Gas North Tioga County Extension

Northern Access Northern Access 2015 Clermont to Chippawa

Total Capacity 1,060 MDth/d

Leaving the WDA Lamont Compressor Clermont to Transco

Total Capacity 390 to 590 MDth/d

Planned Projects

Clermont to Chippawa ~250,000

Clermont to Transco 300,000 – 500,000

Potential Capacity Additions 550,000 – 750,000

Potential Projects

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Pipeline & Storage Expansion Project Revenue Growth

126

$4

$37

$59 $60 $65

$91

$0

$50

$100

$150

$200

2011 2012 2013 2014(Est.)

2015(Est.)

2016(Est.)

2017(Est.)

2018(Est.)

Expa

nsio

n Pr

ojec

t Rev

enue

($ M

illio

ns)

Fiscal Year

Annual Expansion Revenue Projects Placed in Service Since Fiscal 2011

Larger projects under consideration for fiscal 2016 and 2017 will drive

significant revenue growth

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Midstream Businesses New Shale Production Driving Tremendous Growth

127

1,315 1,140

1,301 1,419

2,174

2,444 2,614

0

1,000

2,000

3,000

2009 2010 2011 2012 2013 2014(Est.)

2015(Est.)

Syst

em T

hrou

ghpu

t (M

Dth

per

Day

)

Fiscal Year

Average Daily System Throughput of NFG’s Midstream Businesses Doubling From Fiscal 2009 to 2015

Empire Throughput NFGSC Throughput NFG Midstream

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128

Utility Overview

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Utility New York & Pennsylvania Service Territories

129

New York

Total Customers: 520,000

Rate Mechanisms: Revenue Decoupling Weather Normalization Low Income Rates Choice Program/Purchase of

Receivables Merchant Function Charge

(Uncollectibles Adjustment) 90/10 Sharing (Large Customers)

Natural Gas Vehicle Pilot Program

ROE: 9.1% (Litigated - 2007)

Pennsylvania

Total Customers: 213,000

Rate Mechanisms: Low Income Rates Choice Program/Purchase of

Receivables Merchant Function Charge

ROE: Black Box Settlement (2007)

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Utility Customer Usage

130

80

90

100

110

120

Usa

ge P

er A

ccou

nt(1

) (M

cf)

12-Months Ended Sept 30

15

20

25

30

35

Usa

ge P

er A

ccou

nt(1

) (M

Mcf

)

12-Months Ended Sept 30

Residential Usage Industrial Usage

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

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Utility Continued Cost Control Helps Provide Earnings Stability

131

$178 $164 $167 $168 $168 $172

$25 $27 $14 $11 $9 $6

$203 $191

$181 $179 $177 $178

$0

$50

$100

$150

$200

$250

2008 2009 2010 2011 2012 2013

O&

M E

xpen

se ($

Mill

ions

)

Fiscal Year

All Other O&M Expenses O&M Uncollectible Expense

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Utility Capital Spending Largely Focused on Maintenance

132

$44.4 $45.0 $44.3 $43.8 $48.1

$56.2 $58.0 $58.4 $58.3

$72.0

$80-$90 $80-$90

$0

$20

$40

$60

$80

$100

2009 2010 2011 2012 2013 2014Forecast

2015Forecast

Capi

tal E

xpen

ditu

res

($ M

illio

ns)

Fiscal Year

Capital Expenditures for SafetyTotal Capital Expenditures

The Utility remains focused on spending to maintain the ongoing safety and reliability of its system

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Utility Providing Predictability and Stability

133

$164 $167 $169 $160

$172

$0

$50

$100

$150

$200

$250

2009 2010 2011 2012 2013

Adju

sted

EBI

TDA

($ M

illio

ns)

Fiscal Year

The Utility has Delivered Consistent Results

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

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Utility Working Towards a Settlement in New York

134

March 27, 2013

Filed a plan with the NY PSC to adopt an earnings

sharing and stabilization mechanism on earnings

above a 9.96% ROE

April 19, 2013

NY PSC issued an Order to Show Cause (OTSC)

commencing a proceeding to establish

“temporary rates”

June 1, 2013

OTSC suggests “temporary rates” could

become effective

An agreement in principle has been reached with five parties and the litigation schedule has been extended indefinitely to allow the settlement process to move forward

May 8, 2013

Company responds to OTSC

June 14, 2013

“Temporary rates” become effective

July 26, 2013

Settlement discussions commence for

permanent rates

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135

Hedging Overview

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Hedging Overview How Does Seneca Sell its Production?

136

Well Head Interconnection with Interstate

Pipeline Network

Gathering System

3rd Party Marketer

(or spot market)

Firm Transport

Demand Center (firm sales or spot market)

Contracted Basis Differential

FT Rate

The 1,700 to 2,000 economic locations at less than $4.00/Mcf are based on a

realized price after gathering

Spot Market

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Hedging Overview Firm Sales Provide a Market for Appalachian Production

137

NYMEX 202,745

Less: $0.284 NYMEX 149,091

Less: $0.281 NYMEX 150,000

Less: $0.257

Dominion 105,000

Less: $0.265

Dominion 95,000

Less: $0.305 Dominion

55,000 Less: $0.236

307,745

244,091 220,000

0

100,000

200,000

300,000

400,000

Winter2013/2014

Summer2014

Winter2014/2015

Long

-Ter

m F

irm S

ales

(1) (

MM

Btu

per D

ay)

Other (Transco)NYMEXDominion South Point

Prices shown represent the sales (netback price) at the first non-affiliated interstate pipeline, including the cost of all related

downstream transportation.

(1) Long-term firm sales represent gross volumes 137

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Hedging Overview Seneca Methodically Layers in Index Hedges Over Time

138

0%

20%

40%

60%

80%

100%

Fiscal2014

Fiscal2015

Fiscal2016

Fiscal2017

Fiscal2018

% H

edge

d

Hedging Policy RangeOil HedgesNatural Gas Hedges

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Hedging Overview Current Hedge Book has Seneca Positioned Very Well

139

66%

35% 30%

10%

3%

67%

31%

18% 14%

2% 0%

20%

40%

60%

80%

100%

Fiscal2014

Fiscal2015

Fiscal2016

Fiscal2017

Fiscal2018

% H

edge

d

Hedging Policy RangeOil HedgesNatural Gas Hedges

(1) Hedge positions for fiscal years 2016-2018 reflect the midpoint of Seneca’s target annual production growth (20%) starting with the midpoint of Fiscal 2015 guidance (180-220 Bcfe)

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Commodity Risk Management Oil & Natural Gas Hedges are Above the Current Strip(1)

140

$94.53 $89.81

$85.57 $83.12 $81.67 $94.00 $88.00

$84.00 $82.00 $81.00

$4.25 $4.27 $4.35 $4.45 $4.81

$3.81 $4.07 $4.22 $4.34 $4.44

$0.00

$2.50

$5.00

$7.50

$10.00

$0.00

$25.00

$50.00

$75.00

$100.00

$125.00

2014 2015 2016 2017 2018

Nat

ural

Gas

Ave

rage

Hed

ge P

rice

($/M

cf)

Oil

Aver

age

Hedg

e Pr

ice

($ p

er B

bl)

Fiscal Year

Crude Oil (Average Hedge Price)Crude Oil (NYMEX Strip)Natural Gas (Average Hedge Price)Natural Gas (NYMEX Strip)

(1) Data as of November 13, 2013

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Hedging Overview Determining Seneca’s Realized Price on Firm Sales

141

Realized Price =

Firm Sales Reference

Price

+-

Basis Differential

+-

Financial Hedging

Gain/Loss

NYMEX & Dominion Monthly Settlement Prices

Natural Gas Index Swaps

Negotiated at time of Agreement Based on Current Market at Sales/Delivery Point

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NYMEX 202,745

Less: $0.284 NYMEX 149,091

Less: $0.281 NYMEX 150,000

Less: $0.257

Dominion 105,000

Less: $0.265

Dominion 95,000


55,000 Less: $0.236

307,745

244,091 220,000

0

100,000

200,000

300,000

400,000

Winter2013/2014

Summer2014

Winter2014/2015

Long

-Ter

m F

irm S

ales

(1) (

MM

Btu

per D

ay)

Hedging Overview The Impact of Firm Sales on Realized Price

142 (1) Long-term firm sales represent gross volumes

Determining the Price of a Firm Sales Contract With a $4.25/MMBtu Hedge at the Reference Point

Contract Reference Point NYMEX Dominion

December Settlement $4.000 $3.650

Less: Average Sales Basis Differential ($0.284) ($0.265)

Average Realized Price (Before Hedging) $3.716 $3.235

142

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NYMEX 202,745

Less: $0.284 NYMEX 149,091

Less: $0.281 NYMEX 150,000

Less: $0.257

Dominion 105,000

Less: $0.265

Dominion 95,000


55,000 Less: $0.236

307,745

244,091 220,000

0

100,000

200,000

300,000

400,000

Winter2013/2014

Summer2014

Winter2014/2015

Long

-Ter

m F

irm S

ales

(1) (

MM

Btu

per D

ay)

Hedging Overview Pairing Firm Sales with Hedges Leads to Price Certainty







December Hedge $4.250 $4.250

Less: December Settlement $4.000 $3.650

Hedge Gain $0.250 $0.600

143








Hedge Gain $0.250 $0.600

Average Realized Price (After Hedging) $3.966 $3.985

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NYMEX 202,745

Less: $0.284 NYMEX 149,091

Less: $0.281 NYMEX 150,000

Less: $0.257

Dominion 105,000

Less: $0.265

Dominion 95,000


55,000 Less: $0.236

307,745

244,091 220,000

0

100,000

200,000

300,000

400,000

Winter2013/2014

Summer2014

Winter2014/2015

Long

-Ter

m F

irm S

ales

(1) (

MM

Btu

per D

ay)

Hedging Dominion Firm Sales Contracts With a $4.25/MMBtu Hedge at NYMEX vs. Dominion

Contract Reference Point Dominion

December Settlement $3.650

Less: Average Sales Basis Differential ($0.265)

Average Realized Price (Before Hedging) $3.385

Hedge Reference Point Dominion

December Hedge $4.250

Less: December Settlement $3.650

Hedge Gain $0.600

Average Realized Price (After Hedging) $3.985

Hedging Dominion Firm Sales Contracts With a $4.25/MMBtu Hedge at NYMEX vs. Dominion

Contract Reference Point Dominion Dominion




Hedge Reference Point NYMEX Dominion



Hedge Gain $0.250 $0.600

Average Realized Price (After Hedging) $3.635 $3.985

Hedging Overview Price Certainty only if Firm Sales & Hedge Index Match


Dominion to NYMEX Basis 144

Difference: $0.35

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Hedging Overview FY 2014 Production – Firm Sales & Hedge Composition

145

125-143

50 Bcf

30 Bcf 25 Bcf

29 Bcf

0

30

60

90

120

150

EDA NYMEXFirm Sales

EDA DOMFirm Sales

EDASpot Sales

WDAProduction

TotalEast DivisionProduction

Tota

l Pro

duct

ion

(Bcf

e)

Price Certainty 100% Hedged

@ $4.24 /MMcf

Price Certainty 92% Hedged

@ $4.26/MMcf

Seneca has an additional 12.7 Bcf of NYMEX hedges to help mitigate commodity exposure

on its WDA sales

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146

Financial Overview

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$164 $167 $169 $160 $172

$131 $121 $111 $137 $161

$30 $280 $327 $377 $397

$492 $581 $632 $668

$704

$852

$0

$250

$500

$750

$1,000

$1,250

2009 2010 2011 2012 2013 2014Forecast

2015Forecast

Adju

sted

EBI

TDA

($ M

illio

ns)

Fiscal Year

Exploration & Production SegmentGathering SegmentPipeline & Storage SegmentUtility SegmentEnergy Marketing & Other

National Fuel Gas Company Targeting Sustained Growth for the Next Five Years

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

2014 – 2018 10-15%

Forecasted EBITDA CAGR

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National Fuel Gas Company Capital Spending Adjusts to Capitalize on Opportunities

148

Note: A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation. (1) Does not include the $34.9 MM Seneca Resources Corporation’s acquisition of Ivanhoe’s U.S.-based assets in California, as this was accounted for as an investment in subsidiaries on

the Statement of Cash Flows, and was not included in the Exploration & Production segment’s Capital Expenditures

$56 $58 $58 $58 $72 $80-$90 $80-$90 $53 $38

$129 $144 $56 $115- $135

$225- $275

$80 $55

$100- $150

$100- $150

$188 $398

$649

$694

$533

$550- $650

$650- $750

$307(1)

$501

$854

$977

$717

$845- $1,025

$1,055- $1,265

$0

$250

$500

$750

$1,000

$1,250

$1,500

2009 2010 2011 2012 2013 2014Forecast

2015Forecast

Capi

tal E

xpen

ditu

res (

$ M

illio

ns)

Fiscal Year

Exploration & Production SegmentGathering SegmentPipeline & Storage SegmentUtility SegmentEnergy Marketing & Other

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$835 +/- $940(1) +/-

$175 +/-

$347 +/-

$935 +/- $1,160 +/-

~$125

~$127

$0

$500

$1,000

$1,500

$ M

illio

ns

Cash from Ops Change in Cash & Other New Financing CapEx Dividend

2015 Forecast

National Fuel Gas Company Forecasting a Modest Outspend in 2014 2014

Forecast

149 (1) Forecasted cash from operations for Fiscal 2015 is projected assuming a 12.5% growth rate on 2014 forecasted results

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National Fuel Gas Company Maintaining a Strong Balance Sheet

150

Shareholders’ Equity 57%

Total Debt(1)

43%

$3.843 Billion

As of September 30, 2013

2.02 1.98 1.75

1.89 1.89

0.0

0.5

1.0

1.5

2.0

2.5

2009 2010 2011 2012 2013

Aver

age

Debt

/ A

djus

ted

EBIT

DA

Fiscal Year

Debt / Adjusted EBITDA Capitalization

Note: A reconciliation of Adjusted EBITDA to Net Income is included at the end of this presentation (1) Long-Term Debt of $1.649 billion

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6.5% 8.75% 4.9% 7.395% 7.375%

$49

$500 3.75%

$300 $250

$500 $549

$50

$0

$100

$200

$300

$400

$500

$600

Fiscal Year

National Fuel Gas Company Strong Liquidity with an Investment Grade Rating

151

5.58% Embedded Cost of

Long-Term Debt

Moody’s Standard & Poor’s Fitch

Ratings/ Outlook

Baa1 Stable

BBB Stable

BBB+ Stable

Liquidity ($Millions)

Cash and Temporary Investments $ 65

Available Short-Term Credit Facilities $1,085

Total Short-term Liquidity $1,150

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0%

4%

8%

12%

2009-2011 2010-2012 2011-2013

Annu

alize

d Re

turn

on

Capi

tal

Three-Year Annualized Return on Capital NFG

2009-2011 2010-2012 2011-2013

National Fuel Gas Company Focused on Delivering Strong Returns

152

2009-2011 2010-2012 2011-2013

NFG Percentile 81% 75% 88%

(Fiscal Years) (Fiscal Years) (12-Months Ended 6/30)

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National Fuel Gas Company Dividend Track Record

153

$0.00

$0.50

$1.00

$1.50

$2.00

Annu

al D

ivid

end

Rate

Annual Rate at Fiscal Year End

Current Dividend Yield(1)

2.1%

Dividend Consistency Consecutive Dividend Payments 111 Years

Consecutive Dividend Increases 43 Years

Current Annualized Dividend Rate $1.50 per Share

(1) As of November 14, 2013

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154

30% CAGR Since 2009

Adjusted EBITDA Growth

Production Growth


EBITDA

10-15% CAGR 2014 to 2018

Adjusted EBITDA Growth

15-25% CAGR 2014 to 2018

Production Growth

10-15% CAGR 2014 to 2018


EBITDA

A History of Success

10% CAGR Since 2009

10% CAGR Since 2009

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

A Future of Opportunity

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155

Appendix

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Historical Financials – 2010 & 2011

156

QTD ended QTD ended QTD ended QTD ended12/31/2009 3/31/2010 6/30/2010 9/30/2010 FISCAL 2010

Operating Revenue 94$ 843$ 1,224$ 1,237$ 3,398$

Operating Expenses:Operation & Maintenance Expense 143 344 398 484 1,369 Property, Franchise & Other Taxes 1 7 1 - 9 Depreciation, Depletion & Amortization - 129 153 104 386

144 480 552 588 1,764

Operating Income (50)$ 363$ 672$ 649$ 1,634$

Capital Expenditures 6,538$


Operating Revenue 1,999$ 2,974$ 3,043$ 3,235$ 11,251$

Operating Expenses:Operation & Maintenance Expense 437 535 435 437 1,844 Property, Franchise & Other Taxes 8 4 8 2 22 Depreciation, Depletion & Amortization 173 159 161 168 661

618 698 604 607 2,527

Operating Income 1,381$ 2,276$ 2,439$ 2,628$ 8,724$


FISC

AL 2

010

FISC

AL 2

011

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Historical Financials – 2012 & 2013

157



Operating Expenses:Operation & Maintenance Expense 493 534 633 780 2,440 Property, Franchise & Other Taxes 25 25 4 169 223 Depreciation, Depletion & Amortization 166 167 444 913 1,690

684 726 1,081 1,862 4,353





Operating Expenses:Operation & Maintenance Expense 943 1,027 1,311 1,447 4,728 Property, Franchise & Other Taxes 141 51 41 44 277 Depreciation, Depletion & Amortization 680 1,062 1,064 1,138 3,944

1,764 2,140 2,416 2,629 8,949



FISC

AL 2

012

FISC

AL 2

013

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Comparable GAAP Financial Measure Slides and Reconciliations

158

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.

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159

Reconciliation of Exploration & Production West Division Adjusted EBITDAto Exploration & Production Segment Net Income($ Thousands)

FY 2013

Exploration & Production - West Division Adjusted EBITDA 215,042$ Exploration & Production - All Other Divisions Adjusted EBITDA 277,341 Total Exploration & Production Adjusted EBITDA 492,383$ Minus: Exploration & Production Net Interest Expense (38,244) Minus: Exploration & Production Income Tax Expense (95,317) Minus: Exploration & Production Depreciation, Depletion & Amortization (243,431) Exploration & Production Net Income 115,391$

Exploration & Production Net Income 115,391$ Pipeline & Storage Net Income 63,245 Gathering Net Income 13,321 Utility Net Income 65,686 Energy Marketing Net Income 4,589 Corporate & All Other Net Income (2,231) Consolidated Net Income 260,001$

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160

Reconciliation of Adjusted EBITDA to Consolidated Net Income($ Thousands)

FY 2009 FY 2010 FY 2011 FY 2012Exploration & Production - West Division Adjusted EBITDA 171,572$ 187,838$ 187,603$ 226,897$ 215,042$ Exploration & Production - East Division Adjusted EBITDA 57,179$ 75,098$ 175,392$ 167,806$ 283,509$ Exploration & Production - All Other Divisions Adjusted EBITDA 50,960 64,526 14,462 2,426 (6,168)

Total Exploration & Production Adjusted EBITDA 279,711$ 327,462$ 377,457$ 397,129$ 492,383$

Total Adjusted EBITDAExploration & Production Adjusted EBITDA 279,711$ 327,462$ 377,457$ 397,129$ 492,383$ Pipeline & Storage Adjusted EBITDA 130,857 120,858 111,474 136,914 161,226 Gathering Adjusted EBITDA (141) 2,021 9,386 14,814 29,777 Utility Adjusted EBITDA 164,443 167,328 168,540 159,986 171,669 Energy Marketing Adjusted EBITDA 11,589 13,573 13,178 5,945 6,963 Corporate & All Other Adjusted EBITDA (5,434) 408 (12,346) (10,674) (9,920) Total Adjusted EBITDA 581,025$ 631,650$ 667,689$ 704,114$ 852,098$

Total Adjusted EBITDA 581,025$ 631,650$ 667,689$ 704,114$ 852,098$ Minus: Net Interest Expense (81,013) (90,217) (75,205) (82,551) (89,776) Plus: Other Income 9,762 6,126 5,947 5,133 4,697 Minus: Income Tax Expense (52,859) (137,227) (164,381) (150,554) (172,758) Minus: Depreciation, Depletion & Amortization (170,620) (191,199) (226,527) (271,530) (326,760) Minus: Impairment of Oil and Gas Properties (E&P) (182,811) - - - - Plus/Minus: Income/(Loss) from Discontinued Operations, Net of Tax (Corp. & All Other) (2,776) 6,780 - - - 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) - Consolidated Net Income 100,708$ 225,913$ 258,402$ 220,076$ 260,001$

Consolidated Debt to Total Adjusted EBITDALong-Term Debt, Net of Current Portion (End of Period) 1,249,000$ 1,049,000$ 899,000$ 1,149,000$ 1,649,000$ Current Portion of Long-Term Debt (End of Period) - 200,000 150,000 250,000 - Notes Payable to Banks and Commercial Paper (End of Period) - - 40,000 171,000 -

Total Debt (End of Period) 1,249,000$ 1,249,000$ 1,089,000$ 1,570,000$ 1,649,000$ Long-Term Debt, Net of Current Portion (Start of Period) 999,000 1,249,000 1,049,000 899,000 1,149,000 Current Portion of Long-Term Debt (Start of Period) 100,000 - 200,000 150,000 250,000 Notes Payable to Banks and Commercial Paper (Start of Period) - - - 40,000 171,000

Total Debt (Start of Period) 1,099,000$ 1,249,000$ 1,249,000$ 1,089,000$ 1,570,000$ Average Total Debt 1,174,000$ 1,249,000$ 1,169,000$ 1,329,500$ 1,609,500$

Average Total Debt to Total Adjusted EBITDA 2.02 1.98 1.75 1.89 1.89

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Reconciliation of Segment Capital Expenditures to Consolidated Capital Expenditures($ Thousands)

FY 2014FY 2009 FY 2010 FY 2011 FY 2012 FY 2013 Forecast

Capital Expenditures from Continuing OperationsExploration & Production Capital Expenditures 188,290$ 398,174$ 648,815$ 693,810$ 533,129$ $550,000-650,000Pipeline & Storage Capital Expenditures 52,504 37,894 129,206 144,167 56,144$ $115,000-135,000Gathering Segment Capital Expenditures 9,433 6,538 17,021 80,012 54,792$ $100,000-150,000Utility Capital Expenditures 56,178 57,973 58,398 58,284 71,970$ $80,000-90,000Energy Marketing, Corporate & All Other Capital Expenditures 396 773 746 1,121 1,062$ - Total Capital Expenditures from Continuing Operations 306,801$ 501,352$ 854,186$ 977,394$ 717,097$ $845,000-1,025,000

Capital Expenditures from Discountinued Operations

All Other Capital Expenditures 216 150$ -$ -$ -$ -$

Plus (Minus) Accrued Capital ExpendituresExploration & Production FY 2013 Accrued Capital Expenditures -$ -$ -$ -$ (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) 78,633 - - - Exploration & Production FY 2009 Accrued Capital Expenditures (9,093) 19,517 - - - - Pipeline & Storage FY 2013 Accrued Capital Expenditures - - - - (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 - - - Pipeline & Storage FY 2008 Accrued Capital Expenditures 16,768 - - - - - Gathering FY 2013 Accrued Capital Expenditures - - - - (6,700) - Gathering FY 2012 Accrued Capital Expenditures - - - (12,690) 12,690 - Gathering FY 2011 Accrued Capital Expenditures - - (3,079) 3,079 - - Gathering FY 2009 Accrued Capital Expenditures (715) 715 - - - - Utility FY 2013 Accrued Capital Expenditures - - - - (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 6,960$ (58,401)$ (39,908)$ 57,613$ (13,636)$ -$

Eliminations (344)$ -$ -$ -$ -$ -$ Total Capital Expenditures per Statement of Cash Flows 313,633$ 443,101$ 814,278$ 1,035,007$ 703,461$ $845,000-1,025,000

Documents

National Fuel Gas Company · 2015-10-17 · Analyst Day -November 2013 Corporate. National Fuel Gas Company . Safe Harbor For Forward Looking Statements . 2 . This presentation may