National Fuel Gas Company Analyst Day Presentation November 19, - - PowerPoint PPT Presentation

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National Fuel Gas Company Analyst Day Presentation November 19, - - PowerPoint PPT Presentation

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National Fuel Gas Company Analyst Day Presentation November 19, 2013 Corporate National Fuel Gas Company Safe Harbor For Forward Looking Statements This presentation may contain forward-looking statements as defined by the Private

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SLIDE 1

National Fuel Gas Company

Analyst Day Presentation

November 19, 2013

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SLIDE 2

Analyst Day - November 2013 Corporate

National Fuel Gas Company

Safe Harbor For Forward Looking Statements

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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
  • il; 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
  • f 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.
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Analyst Day - November 2013 Corporate

National Fuel Gas Company

Analyst Day – Schedule of Speakers

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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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Analyst Day - November 2013 Corporate 4

Corporate Overview

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Analyst Day - November 2013 Corporate

National Fuel Gas Company

Exceptional Assets, Focused on Execution

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 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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Analyst Day - November 2013 Corporate

National Fuel Gas Company

A History of Success & A Future of Opportunity

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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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SLIDE 7

Analyst Day - November 2013 Corporate

Corporate Overview

Integrated Businesses Provide Complimentary Benefits

7 $280 $327 $377 $397 $492 $0 $150 $300 $450 $600 2009 2010 2011 2012 2013

Adjusted EBITDA ($ Millions) Fiscal Year

Upstream (E&P)

Tremendous Growth (15% CAGR)

$131 $123 $121 $152 $191 $0 $50 $100 $150 $200 $250 2009 2010 2011 2012 2013 Adjusted EBITDA ($ Millions)

Fiscal Year

Midstream Businesses

Growth & Predictability (10% CAGR)

$164 $167 $169 $160 $172 $0 $50 $100 $150 $200 $250 2009 2010 2011 2012 2013 Adjusted EBITDA ($ Millions)

Fiscal Year

Downstream (Utility)

Stability & Financial Strength

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Analyst Day - November 2013 Corporate

Corporate Overview

Consistent Growth in Low Natural Gas Price Environment

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$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

Adjusted EBITDA ($ Millions)

Fiscal Year

Energy Marketing & Other Utility Segment Pipeline & Storage Segment Gathering Segment Exploration & 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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Analyst Day - November 2013 Corporate

Corporate Overview

Still in the Early Stages of Our Marcellus Growth Story

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

Eastern Development Area Western Development Area

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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Analyst Day - November 2013 Corporate

Corporate Overview

Formula to Grow Our Marcellus Development Program

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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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Analyst Day - November 2013 Corporate

Corporate Overview

Opportunities to Move Gas Out of the Northeast

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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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Analyst Day - November 2013 Corporate

Corporate Overview

Marcellus Infrastructure Growth Still Has Room to Run

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  • 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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Analyst Day - November 2013 Corporate

National Fuel Gas Company

A History of Success & A Future of Opportunity

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10-15% Adjusted EBITDA Growth 15-25% Production Growth $1.5 Billion of Midstream Investment Over 5 Years

Future Goals

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Analyst Day - November 2013 Corporate

  • 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

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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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Analyst Day - November 2013 Upstream 15

Exploration & Production Overview

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Analyst Day - November 2013 Upstream 41 Bcfe 43 Bcfe 50 Bcfe 68 Bcfe 83 Bcfe 121 Bcfe ~155 Bcfe(1) ~200 Bcfe(1)

Total Production

Seneca Resources

Seneca’s Evolution

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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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Analyst Day - November 2013 Upstream

 Total production increased 45% to 120.7 Bcfe

Seneca Resources

Fiscal 2013 Highlights

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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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Analyst Day - November 2013 Upstream

Seneca Resources

Disciplined Capital Spending

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$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 $1,000 2009 2010 2011 2012 2013 2014 Forecast 2015 Forecast Capital Expenditures ($ Millions)

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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Analyst Day - November 2013 Upstream

Seneca Resources

Proven Record of Growth

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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 1,549 500 1000 1500 2000 2008 2009 2010 2011 2012 2013

Total Proved Reserves (Bcfe)

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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Analyst Day - November 2013 Upstream

Seneca Resources

Best-In-Class Marcellus Shale Reserve Growth

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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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Analyst Day - November 2013 Upstream

Seneca Resources

Delivering Tremendous Production Growth

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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 75 150 225 2010 2011 2012 2013 2014 Forecast 2015 Forecast Annual Production (Bcfe)

Fiscal Year

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

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Analyst Day - November 2013 Upstream

Seneca Resources

Delivering More than Just Absolute Growth

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0.4 0.5 0.7 0.8 1.1

  • 0.5

1.0 1.5

2009 2010 2011 2012 2013

Total Production per Debt-Adjusted Share (Mcfe)

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

Total Proved Reserves per Debt-Adjusted Share (Mcfe)

At September 30

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

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Analyst Day - November 2013 Upstream

Marcellus Shale

Significant Position & Integral Part of Seneca’s Future

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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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Analyst Day - November 2013 Upstream

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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Analyst Day - November 2013 Upstream

Marcellus Shale

Prolific Pennsylvania Acreage

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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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Analyst Day - November 2013 Upstream

Seneca Acreage

Huge Position – Varies in Understanding

26

Seneca Lease Seneca Fee

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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Analyst Day - November 2013 Upstream

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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Analyst Day - November 2013 Upstream

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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Analyst Day - November 2013 Upstream

Seneca’s Operations

Best-In-Class Operator in Lycoming County (EDA)

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8.2 4.2 4.0 3.3 3.1 2.2 2.1 1.5 1.0

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

Horizontal Well Count Average Production per Well (MMcf per Day)

Average MMcf per Day Horizontal Well Count

Source: DEP Production Data (January 2013 to June 2013)
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Analyst Day - November 2013 Upstream

Seneca’s Operations

Top-Notch Lycoming Economics

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12.3 6.6 6.3 4.9 3.7

$0 $2 $4 $6 0.0 5.0 10.0 15.0 NFG APC SWN RRC XCO Breakeven Price ($/Mcfe) EUR (Bcfe)

Lycoming County: EURs & Breakeven Prices

EUR (Bcfe) Breakeven Price

Source: ITG IR, raw data provided by didesktop and state agencies
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Analyst Day - November 2013 Upstream

Seneca’s Operations

Seneca’s Lycoming Economics are in the Top 3

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$2.41 $2.79 $2.80 $2.95 $2.95 $2.96 $3.03 $3.06 $3.09 $3.11 $3.21 $3.23 $3.25 $3.33 $3.35 $3.46 $3.54 $3.62 $3.65 $3.69

$2.00 $3.00 $4.00 $5.00 Breakeven NYMEX ($/Mcf)

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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Analyst Day - November 2013 Upstream

Seneca’s Operations

Driving Down Well Costs

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$10.0 $8.1 $6.7 $5.8 $0.0 $3.0 $6.0 $9.0 $12.0 2012 2013 2014 (Est.) Best YTD

Total Well Costs ($ Millions)

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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Analyst Day - November 2013 Upstream

Seneca’s Gathering & Marketing

Seneca’s Overall Marketing Strategy

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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 Financial hedges to lock in benchmark and basis risk

Historical Strategy Current/Long-Term Strategy

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Analyst Day - November 2013 Upstream

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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Analyst Day - November 2013 Upstream

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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Analyst Day - November 2013 Upstream

California

Outstanding Cash Flow(1)

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$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

$ Millions

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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Analyst Day - November 2013 Upstream

200 400 600 800 1,000 1,200 1,400 1,600 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 Gross Prodcution (BOPD)

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 Flow ($ Millions) Fiscal Year

Ivanhoe Acquisition Cash Flow

Annual Cumulative

Acquisition Date

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Analyst Day - November 2013 Upstream

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

  • pportunities
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Analyst Day - November 2013 Upstream

Seneca Resources

Key Metrics

39

Operational Strategy Metric Fiscal 2009 Strategic Improvements Fiscal 2013 Focus on growth-

  • riented 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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Analyst Day - November 2013 Upstream

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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Analyst Day - November 2013 Upstream 41

Appraisal & Development Overview

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Analyst Day - November 2013 Upstream

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

Seneca Lease Seneca Fee

720,000 Acres 60,000 Acres

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Analyst Day - November 2013 Upstream

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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Analyst Day - November 2013 Upstream

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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Analyst Day - November 2013 Upstream

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

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 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 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 = 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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SLIDE 46

Analyst Day - November 2013 Upstream

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

slide-47
SLIDE 47

Analyst Day - November 2013 Upstream

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’

slide-48
SLIDE 48

Analyst Day - November 2013 Upstream

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

1,000 2,000 3,000 4,000 5,000 6,000 7,000 8,000 9,000 10,000 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)

slide-49
SLIDE 49

Analyst Day - November 2013 Upstream

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

slide-50
SLIDE 50

Analyst Day - November 2013 Upstream 1,000 2,000 3,000 4,000 5,000 6,000 7,000 8,000 100 200 300 400 500 600 700

Flowback Gas Rate (Mcfd) 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

slide-51
SLIDE 51

Analyst Day - November 2013 Upstream

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
slide-52
SLIDE 52

Analyst Day - November 2013 Upstream

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

slide-53
SLIDE 53

Analyst Day - November 2013 Upstream

23% 33% 83%

0% 25% 50% 75% 100% 2009 2010 2011 2012 2013 2014 Percent In Current Target (% of CLL) Well Year

Percentage of Wellbore in Current Target Interval

Wells Averages

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

slide-54
SLIDE 54

Analyst Day - November 2013 Upstream

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)

slide-55
SLIDE 55

Analyst Day - November 2013 Upstream

71% 69% 83% 0% 25% 50% 75% 100% 2009 2010 2011 2012 2013 2014 Percent In Target (% of CLL) Well Year

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

Wells Averages

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)

slide-56
SLIDE 56

Analyst Day - November 2013 Upstream

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

Pounds of Sand per Foot

Well Year

Pounds of Sand per Foot

Wells Averages 349 266 162 10 20 30 40 50 60 100 150 200 250 300 350 400 2009 2010 2011 2012 2013 2014

Stage Count

  • Avg. Stage Spacing per Foot

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

slide-57
SLIDE 57

Analyst Day - November 2013 Upstream

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 Completed Lateral Length (ft) Well Year

Completed Lateral Length (ft)

Wells Averages

50% Increase

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

slide-58
SLIDE 58

Analyst Day - November 2013 Upstream

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

slide-59
SLIDE 59

Analyst Day - November 2013 Upstream

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
slide-60
SLIDE 60

Analyst Day - November 2013 Upstream

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
slide-61
SLIDE 61

Analyst Day - November 2013 Upstream

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 Financial hedges to lock in benchmark and basis risk Financial hedges to lock in benchmark and basis risk

Historical Strategy Current/Long-Term Strategy

Firm sales at interstate pipeline interconnects

slide-62
SLIDE 62

Analyst Day - November 2013 Upstream

Marcellus Shale Marketing

Securing Firm Transportation to Major Markets

62

Current Seneca Development Areas

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

slide-63
SLIDE 63

Analyst Day - November 2013 Upstream

Marcellus Shale Marketing

TGP 300 Production & Firm Sales Aligned Thru 2014

63

20 40 60 80 100 120 140 160 180 200 Gross MMBtu per Day

Dawn NYMEX Dominion Production (Forecast)

Dawn Index Less $0.44 Dominion Index Less $0.37 NYMEX Index Less $0.24

slide-64
SLIDE 64

Analyst Day - November 2013 Upstream

Marcellus Shale Marketing

Targeting Future Firm Sales on Transco

64

50 100 150 200 250 300 350 400 Gross MMBtu per 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

slide-65
SLIDE 65

Analyst Day - November 2013 Upstream

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

2.5 MMcf/d, 360 Bbls/d

Halcon

4.5 MMcf/d, 860 Bbls/d Eastern Ohio Point Pleasant Core Point Pleasant Northern Boundary

slide-66
SLIDE 66

Analyst Day - November 2013 Upstream

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

  • ver 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)

slide-67
SLIDE 67

Analyst Day - November 2013 Upstream 67

California Update

slide-68
SLIDE 68

Analyst Day - November 2013 Upstream

California

Stable Production Fields; Modest Growth Potential

68 4,500 500 1,700 1,200 800 4,000 1,200 1,500 1,100 1,100 500 1,500 3,000 4,500 6,000 North Midway Sunset South Midway Sunset South Lost Hills North Lost Hills Sespe East Coalinga Gross Operated Daily Production (Boe/d) 2010 2013

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

Key Areas of Focus in 2014

  • 1. East Coalinga Evaluation
  • 2. South Midway Sunset Extensions
  • 3. Sespe Coldwater Evaluation
slide-69
SLIDE 69

Analyst Day - November 2013 Upstream

California

South Midway Sunset Has Delivered Significant Growth

69 500 1,000 1,500 2,000 Daily Production (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

slide-70
SLIDE 70

Analyst Day - November 2013 Upstream

California

South MWSS Growth Opportunities Continue into 2014

70

slide-71
SLIDE 71

Analyst Day - November 2013 Upstream

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

250 500 750 Daily Production (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
slide-72
SLIDE 72

Analyst Day - November 2013 Upstream

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
slide-73
SLIDE 73

Analyst Day - November 2013 Upstream

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

slide-74
SLIDE 74

Analyst Day - November 2013 Upstream

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

slide-75
SLIDE 75

Analyst Day - November 2013 Upstream

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

slide-76
SLIDE 76

Analyst Day - November 2013 Upstream

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.) Average Daily Net Production (BOE per Day) Fiscal Year

California

Modest Growth Anticipated in 2014 and 2015

76

Forecast

slide-77
SLIDE 77

Analyst Day - November 2013 Upstream 77

Marcellus Operational & Environmental Overview

slide-78
SLIDE 78

Analyst Day - November 2013 Upstream

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

slide-79
SLIDE 79

Analyst Day - November 2013 Upstream

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

slide-80
SLIDE 80

Analyst Day - November 2013 Upstream

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

slide-81
SLIDE 81

Analyst Day - November 2013 Upstream

Marcellus Shale

Faster Spud-to-Sales: Drilling Efficiencies

81

642 624 829 1,050 1,200 1,320 500 1,000 1,500 2011 2012 2013 2013 Q4 2014 (Est.) Best FYTD Daily Footage 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

slide-82
SLIDE 82

Analyst Day - November 2013 Upstream

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 4 8 12 16 20 24 1 2 4 6 8 Wells per Year Rig Moves 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 $500 1 2 4 6 8 Cumulative Annual Cost Savings ($ Millions) Average per Well Move Cost ($ Thousands) Wells per Pad

Average Rig Move Cost per Well

Average per Well Move Cost Average Savings per Year (per Rig)
slide-83
SLIDE 83

Analyst Day - November 2013 Upstream

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 2,000 4,000 6,000 10 20 30 2010 2011 2012 2013 2014 (Est.) Average Lateral Length (Feet) Wells per Rig per Year 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

slide-84
SLIDE 84

Analyst Day - November 2013 Upstream

Marcellus Shale

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

84

3 7 10 12 5 10 15 2012 2013 2014 Q1 2014 (Est.) RCS Stages per Day 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
slide-85
SLIDE 85

Analyst Day - November 2013 Upstream

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
slide-86
SLIDE 86

Analyst Day - November 2013 Upstream

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 1,888 200 400 500 1,000 1,500 2,000 2009 2010 2011 2012 2013 2014 (Est.) Lateral Feet Completed (Thousands) Stages Completed

Fiscal Year

Total Lateral Feet & Stages Completed

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

slide-87
SLIDE 87

Analyst Day - November 2013 Upstream

Marcellus Shale

Drilling Cost Reductions: Several Contributing Factors

87

22.0 24.0 18.0 14.8 12.0 11.1 10 20 30 2011 2012 2013 2013 Q4 2014 (Est.) Best FYTD Drilling Days 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 $5.0 2011 2012 2013 2013 Q4 2014 (Est.) Best FYTD Drilling Cost ($ Millions) 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

slide-88
SLIDE 88

Analyst Day - November 2013 Upstream

Marcellus Shale

Completion Cost Reductions: Ongoing Optimization

88

$160 $131 $120 $113 $0 $50 $100 $150 $200 2012 2013 2014 (Est.) Best FYTD Completion Costs per Stage ($ Thousands) 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
slide-89
SLIDE 89

Analyst Day - November 2013 Upstream

Marcellus Shale

Completion Cost Reductions: New Efficient Technologies

89

Prep

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

Frac

  • 6 days per well
  • 36 days per 6-well pad

Drill-Out

  • 5 days per well
  • 30 days per 6-well pad

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

slide-90
SLIDE 90

Analyst Day - November 2013 Upstream

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

slide-91
SLIDE 91

Analyst Day - November 2013 Upstream

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) 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
slide-92
SLIDE 92

Analyst Day - November 2013 Upstream

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

  • f 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

slide-93
SLIDE 93

Analyst Day - November 2013 Midstream 93

Midstream Businesses Overview

slide-94
SLIDE 94

Analyst Day - November 2013 Midstream

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

slide-95
SLIDE 95

Analyst Day - November 2013 Midstream

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
slide-96
SLIDE 96

Analyst Day - November 2013 Midstream

Midstream Businesses

Positioned Well to Serve Appalachian Producers

96

Empire Pipeline

System Length ~250 Miles Contracted Transport 1.07 MMDth/d 2013 Revenue $76.4 Million 2010 – 2013 Capital Expenditures $62.8 Million Major Interconnects

Sithe Mendon (RG&E) Chippawa (TCPL) Hopewell (TGP 200) Corning (Millennium) Jackson (Shell/Talisman) Lysander
slide-97
SLIDE 97

Analyst Day - November 2013 Midstream

Midstream Businesses

Positioned Well to Serve Appalachian Producers

97

NFG Midstream Corp.

System Length 59 Miles 2013 Revenue $34.8 Million Capital Expenditures (Since Inception) $168 Million Major Interconnects

TGP 300 Transco
slide-98
SLIDE 98

Analyst Day - November 2013 Midstream

Midstream Businesses

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

98

Midstream Businesses 3rd Party Shippers Seneca Resources Develop strong partnerships with customers to help them reach diverse, high-value markets Diverse Markets

slide-99
SLIDE 99

Analyst Day - November 2013 Midstream

Midstream Businesses

Positioned to Serve Seneca’s Rapidly Growing Production

99

slide-100
SLIDE 100

Analyst Day - November 2013 Midstream

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)

slide-101
SLIDE 101

Analyst Day - November 2013 Midstream

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.)

Throughput (MMDth)

$ Millions

Fiscal Year Revenue by Project

(Covington & Trout Run Systems)

Covington Trout Run Total Throughput

Interconnects

slide-102
SLIDE 102

Analyst Day - November 2013 Midstream

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

slide-103
SLIDE 103

Analyst Day - November 2013 Midstream

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

slide-104
SLIDE 104

Analyst Day - November 2013 Midstream

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

slide-105
SLIDE 105

Analyst Day - November 2013 Midstream

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

slide-106
SLIDE 106

Analyst Day - November 2013 Midstream

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

500 1,000 1,500 2,000 2,500

2009 2010 2011 2012 2013 2014 Forecast 2015 Forecast

Year-End Gathering Capacity (MMcf per Day)

Fiscal Year

NFG Midstream Gathering Capacity

Covington Trout Run WDA Other Clermont

slide-107
SLIDE 107

Analyst Day - November 2013 Midstream

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 2014 Forecast 2015 Forecast

Revenue ($ Millions) Capital Expenditures ($ Millions)

Fiscal Year

Revenue Cumulative Capital Invested

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

slide-108
SLIDE 108

Analyst Day - November 2013 Midstream

Pipeline & Storage

Project Opportunities to Support WDA Growth

108

Develop multiple outlets to high-value markets

slide-109
SLIDE 109

Analyst Day - November 2013 Midstream

Midstream Businesses

Providing Transportation to Higher-Priced Markets

109

Currently Short Supply

Short Supply

slide-110
SLIDE 110

Analyst Day - November 2013 Midstream

Midstream Businesses

NE Supply Approaching NE Peak Demand

110

  • 5

10 15 20 25 30 2005 2007 2009 2011 2013 2015 2017 Northeast Supply (Bcf per Day) 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
slide-111
SLIDE 111

Analyst Day - November 2013 Midstream

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

slide-112
SLIDE 112

Analyst Day - November 2013 Midstream

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 $ per MMBtu

Eastern Canada (Dawn) is Currently a Premium Priced Market

Dawn to Henry Hub Dawn to Dominion South Point

slide-113
SLIDE 113

Analyst Day - November 2013 Midstream

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 $ per MMBtu

Eastern Canada (Dawn) is Currently a Premium Priced Market

Dawn to Dominion South Point Dawn to TGP 300 - Zone 4

slide-114
SLIDE 114

Analyst Day - November 2013 Midstream

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

Northern Access 2015

Canada & Eastern U.S.

Clermont
slide-115
SLIDE 115

Analyst Day - November 2013 Midstream

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

Clermont to Chippawa

Canada & Eastern U.S. New England New York City

Clermont
slide-116
SLIDE 116

Analyst Day - November 2013 Midstream

Pipeline & Storage

Longer-Term: Reaching Markets Along the Atlantic

116

Transco
  • In-Service: 2017
  • System: NFG Supply Corp.
  • 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
slide-117
SLIDE 117

Analyst Day - November 2013 Midstream

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

Northern Access 2015 Clermont to Chippawa Longer-Term WDA Expansion

Clermont
slide-118
SLIDE 118

Analyst Day - November 2013 Midstream

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

slide-119
SLIDE 119

Analyst Day - November 2013 Midstream

Pipeline & Storage

Recent 3rd Party Expansions Have Been Highly Successful

119

Projects to Support 3rd Parties

Project Capacity (Dth/day) Northern Access 2013 320,000 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

Northern Access 2013 Tioga County Extension Line N Projects

slide-120
SLIDE 120

Analyst Day - November 2013 Midstream

Pipeline & Storage

NFGSC is Now a Net Exporter of Natural Gas to Canada

120

(500) (400) (300) (200) (100)

  • 100

MDth per Day

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)
slide-121
SLIDE 121

Analyst Day - November 2013 Midstream

100 200 300 400 500 600 700 800 2008 2009 2010 2011 2012 2013 Average Daily Throughput (MDth per Day) 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)
slide-122
SLIDE 122

Analyst Day - November 2013 Midstream

Pipeline & Storage

Additional Line N Expansions Planned for the Future

122

  • In-Service: November 2014
  • System: NFG Supply Corp.
  • 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

slide-123
SLIDE 123

Analyst Day - November 2013 Midstream

Mercer (TGP Station 219)

Pipeline & Storage

Pairing Line N Expansions with System Modernization

123

  • In-Service: November 2015
  • System: NFG Supply Corp.
  • 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

slide-124
SLIDE 124

Analyst Day - November 2013 Midstream

Pipeline & Storage

Developing Unique Solutions for Shippers

124

  • In-Service: November 2015
  • 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

slide-125
SLIDE 125

Analyst Day - November 2013 Midstream

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 Northern Access 2015 140,000 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

slide-126
SLIDE 126

Analyst Day - November 2013 Midstream

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.) Expansion Project Revenue ($ Millions)

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

slide-127
SLIDE 127

Analyst Day - November 2013 Midstream

Midstream Businesses

New Shale Production Driving Tremendous Growth

127

1,315 1,140 1,301 1,419 2,174 2,444 2,614 1,000 2,000 3,000 2009 2010 2011 2012 2013 2014 (Est.) 2015 (Est.) System Throughput (MDth 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

slide-128
SLIDE 128

Analyst Day - November 2013 Downstream 128

Utility Overview

slide-129
SLIDE 129

Analyst Day - November 2013 Downstream

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)
slide-130
SLIDE 130

Analyst Day - November 2013 Downstream

Utility

Customer Usage

130 80 90 100 110 120

Usage Per Account(1) (Mcf)

12-Months Ended Sept 30 15 20 25 30 35

Usage Per Account(1) (MMcf)

12-Months Ended Sept 30

Residential Usage Industrial Usage

(1) Weighted Average of New York and Pennsylvania service territories (assumes normal weather)
slide-131
SLIDE 131

Analyst Day - November 2013 Downstream

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 Expense ($ Millions) Fiscal Year

All Other O&M Expenses O&M Uncollectible Expense

slide-132
SLIDE 132

Analyst Day - November 2013 Downstream

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 2014 Forecast 2015 Forecast

Capital Expenditures ($ Millions)

Fiscal Year

Capital Expenditures for Safety Total Capital Expenditures The Utility remains focused

  • n spending to maintain

the ongoing safety and reliability of its system

slide-133
SLIDE 133

Analyst Day - November 2013 Downstream

Utility

Providing Predictability and Stability

133 $164 $167 $169 $160 $172

$0 $50 $100 $150 $200 $250

2009 2010 2011 2012 2013 Adjusted EBITDA ($ Millions) 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.
slide-134
SLIDE 134

Analyst Day - November 2013 Downstream

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

slide-135
SLIDE 135

Analyst Day - November 2013 Corporate 135

Hedging Overview

slide-136
SLIDE 136

Analyst Day - November 2013 Corporate

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

slide-137
SLIDE 137

Analyst Day - November 2013 Corporate

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

100,000 200,000 300,000 400,000

Winter 2013/2014 Summer 2014 Winter 2014/2015 Long-Term Firm Sales(1) (MMBtu per Day)

Other (Transco) NYMEX Dominion 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

slide-138
SLIDE 138

Analyst Day - November 2013 Corporate

Hedging Overview

Seneca Methodically Layers in Index Hedges Over Time

138

0% 20% 40% 60% 80% 100% Fiscal 2014 Fiscal 2015 Fiscal 2016 Fiscal 2017 Fiscal 2018

% Hedged

Hedging Policy Range Oil Hedges Natural Gas Hedges

slide-139
SLIDE 139

Analyst Day - November 2013 Corporate

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% Fiscal 2014 Fiscal 2015 Fiscal 2016 Fiscal 2017 Fiscal 2018

% Hedged

Hedging Policy Range Oil Hedges Natural 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)
slide-140
SLIDE 140

Analyst Day - November 2013 Corporate

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

Natural Gas Average Hedge Price ($/Mcf)

Oil Average Hedge Price ($ per Bbl)

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
slide-141
SLIDE 141

Analyst Day - November 2013 Corporate

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

slide-142
SLIDE 142

Analyst Day - November 2013 Corporate

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

100,000 200,000 300,000 400,000

Winter 2013/2014 Summer 2014 Winter 2014/2015

Long-Term Firm Sales(1) (MMBtu per Day)

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

slide-143
SLIDE 143

Analyst Day - November 2013 Corporate

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

100,000 200,000 300,000 400,000

Winter 2013/2014 Summer 2014 Winter 2014/2015

Long-Term Firm Sales(1) (MMBtu per Day)

Hedging Overview

Pairing Firm Sales with Hedges Leads to Price Certainty

143

(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 $3.385

December Hedge

$4.250 $4.250

Less: December Settlement

$4.000 $3.650

Hedge Gain

$0.250 $0.600

143

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 $3.385

December Hedge

$4.250 $4.250

Less: December Settlement

$4.000 $3.650

Hedge Gain

$0.250 $0.600

Average Realized Price (After Hedging)

$3.966 $3.985

slide-144
SLIDE 144

Analyst Day - November 2013 Corporate

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

100,000 200,000 300,000 400,000

Winter 2013/2014 Summer 2014 Winter 2014/2015

Long-Term Firm Sales(1) (MMBtu per Day)

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

December Settlement

$3.650 $3.650

Less: Average Sales Basis Differential

($0.265) ($0.265)

Average Realized Price (Before Hedging)

$3.385 $3.385

Hedge Reference Point

NYMEX Dominion

December Hedge

$4.250 $4.250

Less: December Settlement

$4.000 $3.650

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

144

(1) Long-term firm sales represent gross volumes

Dominion to NYMEX Basis

144

Difference: $0.35

slide-145
SLIDE 145

Analyst Day - November 2013 Corporate

Hedging Overview

FY 2014 Production – Firm Sales & Hedge Composition

145

125-143

50 Bcf 30 Bcf 25 Bcf 29 Bcf 30 60 90 120 150

EDA NYMEX Firm Sales EDA DOM Firm Sales EDA Spot Sales WDA Production Total East Division Production

Total Production (Bcfe)

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

  • n its WDA sales
slide-146
SLIDE 146

Analyst Day - November 2013 Corporate 146

Financial Overview

slide-147
SLIDE 147

Analyst Day - November 2013 Corporate

$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 2014 Forecast 2015 Forecast

Adjusted EBITDA ($ Millions)

Fiscal Year

Exploration & Production Segment Gathering Segment Pipeline & Storage Segment Utility Segment Energy 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

slide-148
SLIDE 148

Analyst Day - November 2013 Corporate

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 2014 Forecast 2015 Forecast

Capital Expenditures ($ Millions)

Fiscal Year

Exploration & Production Segment Gathering Segment Pipeline & Storage Segment Utility Segment Energy Marketing & Other

slide-149
SLIDE 149

Analyst Day - November 2013 Corporate

$835 +/- $940(1) +/- $175 +/- $347 +/- $935 +/- $1,160 +/- ~$125 ~$127

$0 $500 $1,000 $1,500

$ Millions

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
slide-150
SLIDE 150

Analyst Day - November 2013 Corporate

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

Average Debt / Adjusted EBITDA

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
slide-151
SLIDE 151

Analyst Day - November 2013 Corporate 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

slide-152
SLIDE 152

Analyst Day - November 2013 Corporate

0% 4% 8% 12% 2009-2011 2010-2012 2011-2013

Annualized Return on Capital

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)

slide-153
SLIDE 153

Analyst Day - November 2013 Corporate

National Fuel Gas Company

Dividend Track Record

153

$0.00 $0.50 $1.00 $1.50 $2.00

Annual Dividend 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
slide-154
SLIDE 154

Analyst Day - November 2013 Corporate

National Fuel Gas Company

A History of Success & A Future of Opportunity

154

30% CAGR

Since 2009 Adjusted EBITDA Growth Production Growth Midstream Businesses EBITDA

10-15% CAGR

2014 to 2018 Adjusted EBITDA Growth

15-25% CAGR

2014 to 2018 Production Growth

10-15% CAGR

2014 to 2018 Midstream Businesses 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

slide-155
SLIDE 155

Analyst Day - November 2013 Appendix 155

Appendix

slide-156
SLIDE 156

Analyst Day - November 2013 Appendix

Gathering

Historical Financials – 2010 & 2011

156

QTD ended QTD ended QTD ended QTD ended 12/31/2009 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 $ QTD ended QTD ended QTD ended QTD ended 12/31/2010 3/31/2011 6/30/2011 9/30/2011 FISCAL 2011 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 $ Capital Expenditures 17,021 $

FISCAL 2010 FISCAL 2011

slide-157
SLIDE 157

Analyst Day - November 2013 Appendix

Gathering

Historical Financials – 2012 & 2013

157

QTD ended QTD ended QTD ended QTD ended 12/31/2011 3/31/2012 6/30/2012 9/30/2012 FISCAL 2012 Operating Revenue 3,565 $ 3,346 $ 4,494 $ 6,069 $ 17,474 $ 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 Income 2,881 $ 2,620 $ 3,413 $ 4,207 $ 13,121 $ Capital Expenditures 80,012 $ QTD ended QTD ended QTD ended QTD ended 12/31/2012 3/31/2013 6/30/2013 9/30/2013 FISCAL 2013 Operating Revenue 5,682 $ 8,222 $ 10,586 $ 10,291 $ 34,781 $ 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 Operating Income 3,918 $ 6,082 $ 8,170 $ 7,662 $ 25,832 $ Capital Expenditures 54,792 $

FISCAL 2012 FISCAL 2013

slide-158
SLIDE 158

Analyst Day - November 2013 Appendix

National Fuel Gas Company

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.

slide-159
SLIDE 159

Analyst Day - November 2013 Appendix 159

Reconciliation of Exploration & Production West Division Adjusted EBITDA to 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 $

slide-160
SLIDE 160

Analyst Day - November 2013 Appendix 160

Reconciliation of Adjusted EBITDA to Consolidated Net Income ($ Thousands) FY 2009 FY 2010 FY 2011 FY 2012 Exploration & 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 EBITDA Exploration & 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 EBITDA Long-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 FY 2013
slide-161
SLIDE 161

Analyst Day - November 2013 Appendix 161

Reconciliation of Segment Capital Expenditures to Consolidated Capital Expenditures ($ Thousands) FY 2014 FY 2009 FY 2010 FY 2011 FY 2012 FY 2013 Forecast Capital Expenditures from Continuing Operations Exploration & Production Capital Expenditures 188,290 $ 398,174 $ 648,815 $ 693,810 $ 533,129 $ $550,000-650,000 Pipeline & Storage Capital Expenditures 52,504 37,894 129,206 144,167 56,144 $ $115,000-135,000 Gathering Segment Capital Expenditures 9,433 6,538 17,021 80,012 54,792 $ $100,000-150,000 Utility Capital Expenditures 56,178 57,973 58,398 58,284 71,970 $ $80,000-90,000 Energy 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 Expenditures Exploration & 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