8-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K

CURRENT REPORT

Pursuant to Section 13 or 15(d) of

the Securities Exchange Act of 1934

Date of Report (Date of earliest event reported): March 18, 2013

NATIONAL FUEL GAS COMPANY

(Exact name of registrant as specified in its charter)

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

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

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

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

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

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

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

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

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

Item 7.01 Regulation FD Disclosure.

National Fuel Gas Company (the “Company”) will participate in the Howard Weil 41st Annual Energy Conference beginning March 18, 2013. The Company also plans to hold meetings with certain industry analysts, money managers and other members of the financial community. A copy of materials to be presented by the Company during the conference and provided to participants in the Company’s meetings is furnished as part of this Current Report as Exhibit 99.

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

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

Certain statements contained herein or in the materials furnished as part of this Current Report, including statements regarding estimated future earnings and statements that are identified by the use of the words “anticipates,” “estimates,” “expects,” “forecasts,” “intends,” “plans,” “predicts,” “projects,” “believes,” “seeks,” “will” and “may” and similar expressions, are “forward-looking statements” as defined by the Private Securities Litigation Reform Act of 1995. There can be no assurance that the Company’s projections will in fact be achieved nor do these projections reflect any acquisitions or divestitures that may occur in the future. While the Company’s expectations, beliefs and projections are expressed in good faith and are believed to have a reasonable basis, actual results may differ materially from those projected in forward-looking statements. Furthermore, each forward-looking statement speaks only as of the date on which it is made. In addition to other factors, the following are important factors that could cause actual results to differ materially from those discussed in the forward-looking statements: factors affecting the Company’s ability to successfully identify, drill for and produce economically viable natural gas and oil reserves, including among others geology, lease availability, title disputes, weather conditions, shortages, delays or unavailability of equipment and services required in drilling operations, insufficient gathering, processing and transportation capacity, the need to obtain governmental approvals and permits, and compliance with environmental laws and regulations; changes in laws, regulations or judicial interpretations to which the Company is subject, including those involving derivatives, taxes, safety, employment, climate change, other environmental matters, real property, and exploration and production

activities such as hydraulic fracturing; changes in the price of natural gas or oil; impairments under the SEC’s full cost ceiling test for natural gas and oil reserves; uncertainty of oil and gas reserve estimates; significant differences between the Company’s projected and actual production levels for natural gas or oil; changes in demographic patterns and weather conditions; changes in the availability, price or accounting treatment of derivative financial instruments; governmental/regulatory actions, initiatives and proceedings, including those involving rate cases (which address, among other things, allowed rates of return, rate design and retained natural gas), environmental/safety requirements, affiliate relationships, industry structure, and franchise renewal; delays or changes in costs or plans with respect to Company projects or related projects of other companies, including difficulties or delays in obtaining necessary governmental approvals, permits or orders or in obtaining the cooperation of interconnecting facility operators; financial and economic conditions, including the availability of credit, and occurrences affecting the Company’s ability to obtain financing on acceptable terms for working capital, capital expenditures and other investments, including any downgrades in the Company’s credit ratings and changes in interest rates and other capital market conditions; changes in economic conditions, including global, national or regional recessions, and their effect on the demand for, and customers’ ability to pay for, the Company’s products and services; the creditworthiness or performance of the Company’s key suppliers, customers and counterparties; economic disruptions or uninsured losses resulting from major accidents, fires, severe weather, natural disasters, terrorist activities, acts of war, cyber attacks or pest infestation; changes in price differential between similar quantities of natural gas at different geographic locations, and the effect of such changes on the demand for pipeline transportation capacity to or from such locations; other changes in price differentials between similar quantities of oil or natural gas having different quality, heating value, geographic location or delivery date; significant differences between the Company’s projected and actual capital expenditures and operating expenses; changes in laws, actuarial assumptions, the interest rate environment and the return on plan/trust assets related to the Company’s pension and other post-retirement benefits, which can affect future funding obligations and costs and plan liabilities; the cost and effects of legal and administrative claims against the Company or activist shareholder campaigns to effect changes at the Company; increasing health care costs and the resulting effect on health insurance premiums and on the obligation to provide other post-retirement benefits; or increasing costs of insurance, changes in coverage and the ability to obtain insurance. The Company disclaims any obligation to update any forward-looking statements to reflect events or circumstances after the date hereof.

Item 9.01 Financial Statements and Exhibits.

(d) Exhibits

Exhibit 99 Presentation materials furnished for the Howard Weil 41st Annual Energy Conference

SIGNATURES

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

NATIONAL FUEL GAS COMPANY
By:	/s/    James R. Peterson
	James R. Peterson
	Assistant Secretary

Dated: March 18, 2013

EXHIBIT INDEX

Exhibit Number	Description
99	Presentation materials furnished for the Howard Weil 41st Annual Energy Conference

EX-99

National Fuel Gas Company

Investor Presentation

March 2013

Exhibit 99

March 2013

National Fuel Gas Company

3

Our Business Mix Leads to Long-Term Value Creation

Upstream

Crude Oil

Midstream

Downstream

National Fuel Gas

Supply Corporation

Empire Pipeline, Inc.

National Fuel Gas

Midstream Corporation

National Fuel Gas

Distribution

Corporation

National Fuel

Resources, Inc.

The strategic, operational and financial benefits, along with capital

flexibility and consistent growth opportunities generated by this

integrated mix of businesses continues to create significant

long-term value for the Company’s shareholders in nearly all

economic and commodity price scenarios

Upstream

Natural Gas

Seneca Resources

Corporation

(West Division)

Seneca Resources

Corporation

(East Division)

March 2013

National Fuel Gas Company

4

Integrated Businesses with Significant Marcellus Exposure…

March 2013

National Fuel Gas Company

5

…And Exposure to Growth from the Utica Shale

March 2013

National Fuel Gas Company

6

EBITDA Growth Driven by Stability and Continued Success

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. 

March 2013

National Fuel Gas Company

7

Capital Spending Flexibility to Maintain Financial Strength

Note: A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation.

(1)

(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

March 2013

National Fuel Gas Company

8

Strong Balance Sheet and Liquidity Position

$3.653 Billion

(2)

As of December 31, 2012

(1)

Includes Long-Term Debt of $1.149 billion, the Current Portion of Long-Term Debt of $0.250 billion, and Notes Payable to Banks and Commercial Paper

of $0.238 billion, as of December 31, 2012.

(2)

Includes Notes Payable to Banks and Commercial Paper of $238.0 million and Current Portion of Long-Term Debt of $250.0 million as of December 31, 2012.

In February 2013, the Company issued $500

million in 10-year notes to repay a $250 maturity

and all

outstanding short-term debt

Capital Resources

Total Short-Term Capacity: $1,085 Million

Committed Credit Facility:  $750 Million

Syndicated facility extends until

January 6, 2017

Uncommitted Lines of Credit: $335 Million

$18.0 million of outstanding short-

term notes payable to banks as of

December 31, 2012

$300.0 Million Commercial Paper

Program backed by Committed Credit

Facility

$220.0 million of outstanding

commercial paper  as of

December 31, 2012

March 2013

Midstream Businesses

9

Pipeline & Storage/NFG Midstream

March 2013

Midstream Businesses

10

Pipeline Expansions to Transport Appalachian Production

March 2013

Exploration & Production

11

March 2013

Seneca Resources

12

Another Strong Year of Reserve Growth

Seneca has more than doubled

its proved reserves since 2009,

while maintaining a relatively

high percentage of proved

developed reserves (67%),

given its large resource base

(1)

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

March 2013

Seneca Resources

13

Operational Efficiencies Continue to Drive Production Growth

Ongoing efficiency allows for more activity with a flat rig count

(1)

RCS –

Reduced Cluster Spacing

(2)

Drilling pace represents the average feet drilled per day from the time the well is spud until it reaches total depth (TD)

March 2013

Seneca Resources

14

Increased Oil Spending and Tempered Marcellus Spending

(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

March 2013

Seneca Resources

15

March 2013

Seneca Resources

16

California: Stable Production Fields

March 2013

Seneca Resources

17

California: Strong Margins Support Significant Free Cash Flow

(1)  Total production from the Exploration & Production segment’s properties in California  was 3,374 Mboe for the 12 months ended December 31, 2012.

Note: A reconciliation of Exploration & Production West Division

Adjusted EBITDA to Exploration & Production Segment Net Income is included at the end of this

presentation. 

March 2013

California: Midway Sunset South Activity Update

Seneca Resources

18

March 2013

19

“X”

SANDS ISOCHORE (Thickness)

Seneca Resources

California: Sespe Field –

Drilling Programs and Results

March 2013

Seneca Resources

20

California: East Coalinga Overview

Seneca became operator on January 30, 2013

Previous Operator: Chevron

7,764 net acres

~170 wells (60 active)

~250 BOPD

$30 million capital commitment over first

three years

$100 million of potential opportunities over

the next five to seven years

2013 Plans

Drill ~12 evaluation wells across acreage

block

Place ~50% of currently idled wells back on

production

Upgrade surface facilities

Active Well

Idle Well

March 2013

Seneca Resources

21

Expansive Pennsylvania Acreage Position

March 2013

Seneca Resources

22

Eastern Development Area (EDA)

March 2013

Seneca Resources

23

Lycoming and Tioga Counties Are Highly Productive Areas 

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

5.3

4,049’

1.30

Tract 595

(1)

Tioga

County

19

6.9

6.0

5.1

7.5

4,455’

1.68

Tract 100

Lycoming

County

14

15.4

13.3

10.3

11.0

5,256’

2.09

(1) Seven new wells on Tract 595 began production in February 2013 and are awaiting sufficient production history to include within the table

March 2013

Seneca Resources

24

Fiscal 2013 Western Development Area Delineation Program

March 2013

Seneca Resources

25

Rich Valley/Clermont Development Area

March 2013

Seneca Resources

26

Utica Shale –

Activity Summary

Permitted

Drilled/Drilling

Completed

Producing

Mt. Jewett

Tested 3 Frac Stages at 1.6 MMcfd

(Typical Well: 17 Frac Stages)

2

nd

Horizontal: FY 2013

Henderson

Vertical Well: Tested

Tionesta

Horizontal: Completed Fall 2012

Peak 24-Hour Rate: 3.9 MMcfd

Rex

9.2 MMcfd

Chesapeake

6.4 MMcfd

Range Resources

4.4 MMcfd

Range Resources

1.4 MMcfd

“Not Effectively

Stimulated”

March 2013

Seneca Resources

27

Initial Entry into the Mississippian Lime Play in Kansas

Total Net Acres: 9,300

1

st

Well Spud: FY2013 –

Q3

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)

100% working interest in 4,600

gross acres

25% net working interest in 18,500

gross acres

2013: Participate in 3 to 5 gross

horizontal wells

March 2013

National Fuel Gas Company

28

Capital Deployment Has Led to Significant Accomplishments

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. 

•

Total oil and gas proved reserves reached 1,246 Bcfe at September 30, 2012, with a 3-year

average F&D cost of $1.87/Mcfe

•

Despite the 2011 sale of its offshore Gulf of Mexico properties,

Seneca has increased

production from 42.5 Bcfe in 2009 to 83.4 Bcfe in 2012

31% Increase in Pipeline & Storage Adjusted EBITDA since Fiscal 2011

•

As a result of major Appalachian pipeline expansions, Adjusted EBITDA reached $146 million

for the last 12 months and new projects will continue to drive growth beyond fiscal 2013

44.3 Bcfe in 2012 NFG Midstream Gathering Volumes

•

NFG Midstream gathered more than 44 Bcfe of volumes for Seneca Resources, eliminating

the need to rely upon and provide payment to third party infrastructure operators

March 2013

National Fuel Gas Company

29

Appendix

March 2013

National Fuel Gas Company

30

Fiscal Year 2013 Earnings Guidance Drivers

2013 Forecast

GAAP Earnings per Share

$2.75 -

$3.00

Exploration & Production Drivers

Total Production (Bcfe)

102 -

112

DD&A Expense

$2.10 -

$2.25

LOE Expense

$0.90 -

$1.10

G&A Expense

$58 -

$62 MM

Pipeline & Storage Drivers

O&M Expense

+3%

Revenue

$255 -

$265 MM

Utility Drivers

O&M Expense

+3%

Normal Weather in PA

Energy Marketing Drivers

Operating Income

$5 -

$10 MM

March 2013

National Fuel Gas Company

31

Dividend Track Record

Current

Dividend Yield

(1)

2.5%

(1) As of March 12, 2013

March 2013

National Fuel Gas Company

32

No Debt Maturities Until Fiscal 2018

March 2013

Midstream Businesses

33

Appendix

March 2013

Midstream Businesses

34

A Closer Look at the Expansion Progress

COVINGTON

GATHERING

SYSTEM

(In-Service)

TROUT RUN

GATHERING SYSTEM

(In-Service)

TIOGA

COUNTY

EXTENSION

(In-Service)

LINE “N”

EXPANSION

(In-Service)

NORTHERN ACCESS

EXPANSION

(In-Service)

CENTRAL TIOGA

COUNTY EXTENSION

(2015/2016)

LINE “N”

2012

EXPANSION

(In-Service)

MERCER

EXPANSION

PROJECT

(Nov. 2014)

LINE “N”

2013

EXPANSION

(Nov. 2013)

WEST SIDE

EXPANSION

(2013 to 2015)

TIONESTA

GATHERING

SYSTEM

(Under Construction)

MT. JEWETT

GATHERING SYSTEM

(Under Construction)

March 2013

Midstream Businesses

35

Pursuing Additional Opportunities Near the Line N Corridor

Activity in the Marcellus and Utica shales

along the Pennsylvania/Ohio border

continues to remain robust

NFG Supply Corporation’s  Line N system is

well-positioned for continued expansion

NFG Midstream Corporation is focused on

building new high-pressure wet and dry gas

gathering systems

Significant expansion opportunities may be

present in the next few years

2013:

Smaller

pipeline

expansions

2014+:

Larger expansion projects, possibly

including an integrated wet gas solution,

with NFG Midstream focused on the high-

pressure wet gas gathering systems and

NFG Supply transporting dry gas on its

interstate system

March 2013

Midstream Businesses

36

Regulated Interstate Expansion Initiatives (Pipeline & Storage)

Project Name

Capacity

(Dth/D)

Est.

CapEx

In-Service

Market

Status

Lamont Compressor Station

90,000

$14 MM

2010/2011

Fully Subscribed

Completed –

Two Phases

Line “N”

Expansion

160,000

$22 MM

10/2011

Fully Subscribed

Completed

Tioga County Extension

350,000

$58 MM

11/2011

Fully Subscribed

Completed

Northern Access Expansion

320,000

$77 MM

11/2012

Fully Subscribed

Completed

Line “N”

2012 Expansion

163,000

$41 MM

11/2012

Fully Subscribed

Completed

Line “N”

2013 Expansion

30,000

~$5 MM

11/2013

Fully Subscribed

Executed Precedent Agreement

Mercer Expansion Project

105,000

~$30 MM

11/2014

Fully Subscribed

Executed Precedent Agreement

West Side Expansion

95,000+

TBD

2013 to

2015

OS Concluded

Negotiating Precedent Agreements

Central Tioga County

Extension

260,000

~$150MM

2015/2016

OS Concluded

Discussions with anchor shipper

West to East

~425,000

~$290 MM

~2016

29% Subscribed

Marketing continues with producers in

various stages of exploratory drilling

Total Firm Capacity:  ~1,998,000+ Dth/D

Capital Investment: ~$687+ MM

March 2013

Midstream Businesses

37

NFG Midstream is Focused on Serving Appalachian Producers

Midstream’s gathering systems are

critical to unlock remote, but highly

productive Marcellus acreage

History of operational success and

efficiency within Pennsylvania

Current focus is on developing and

expanding gathering infrastructure

for both Seneca and other producers

in the Appalachian Basin

March 2013

Midstream Businesses

38

Gathering Expansion Initiatives (NFG Midstream)

Project Name

Capacity

(Mcf/D)

Est.

CapEx

In-Service

Date

Market

Comments

Covington Gathering System

220,000

$40 MM

Multiple

Phases -

Most

In-Service

Capacity Available

[Marketing to

Third Parties]

Completed

–

Flowing into TGP 300

Line.  This includes ~$10 million of

current and future spending to

build pipeline to connect additional

wells

Trout Run Gathering System

466,000

$185 MM

May 2012

Capacity Available

[Marketing to

Third Parties]

Completed

–

Flowing into Transco

Leidy Line.  This includes ~$90

million of current and future

spending to build compression and

pipeline to connect additional wells

Tionesta Gathering System

10,000

$2.1 MM

FY2013

Q2

Fully Subscribed

Under Construction

Mt. Jewett Gathering System

10,000

$3.9 MM

FY2013

Q2

Fully Subscribed

Under Construction

Total Firm Capacity:  ~706,000 Mcf/D

Capital Investment: ~$231 MM

March 2013

Exploration & Production

39

Appendix

March 2013

Seneca Resources

40

Hedge Positions and Strategy

Natural Gas

Swaps

Volume

(Bcf)

Average

Hedge Price

Fiscal 2013

48.9

$4.57 / Mcf

Fiscal 2014

51.0

$4.24 / Mcf

Fiscal 2015

23.8

$4.12 / Mcf

Fiscal 2016

17.9

$4.07 / Mcf

Fiscal 2017

17.9

$4.07 / Mcf

Oil Swaps

Volume

(MMBbl)

Average

Hedge Price

Fiscal 2013

1.3

$94.92 / Bbl

Fiscal 2014

1.5

$100.01 / Bbl

Fiscal 2015

0.5

$92.54 / Bbl

Fiscal 2016

0.3

$86.09/Bbl

Most hedges executed at sales point to eliminate basis risk

Seneca has hedged approximately 69% of its

forecasted production for Fiscal 2013 

Note: Fiscal 2013 hedge positions are for the remaining nine months of the fiscal year

March 2013

Seneca Resources

41

Continuing to Focus on Improving Its Cost Structure

(1)

Represents the midpoint of current General & Administrative Expense guidance of $58 to $62 million, divided by the midpoint of current production guidance

of 95 to 107 Bcfe

(2)

Represents the midpoint of current Lease Operating Expense Guidance of $0.90 to $1.10 per Mcfe

March 2013

Seneca Resources

42

California: Stable Production and Increasing Cash Flows

Net Acreage:  18,418 Acres

Net Wells:  1,478

Oil Gravity:  12 –

37°

Api

NRI:  87.64

Rank

Company

California

2011

BOEPD

1

Occidental

164,796

2

Chevron

163,153

3

Aera (Shell/Exxon)

149,974

4

Plains Exploration

36,775

5

Venoco Inc.

18,988

6

Berry Petroleum

18,872

7

Seneca Resources

9,209

8

Macpherson Oil

9,022

9

E&B Natural Resources

5,992

10

ExxonMobil

3,238

March 2013

Seneca Resources

43

California: Recent Initiatives Driving Near-Term Growth

March 2013

Seneca Resources

44

Ramping Marcellus Shale Production

March 2013

Marcellus Shale

45

Targeting Continued Cost Reductions

(1) Completion Cost per Stage is for horizontal wells completed utilizing a standard completion design, not a Reduced Cluster Spacing (RCS) completion design. 

March 2013

Utility

46

March 2013

Rate Mechanisms

New York & Pennsylvania

Low Income Rates

Choice Program/POR

Merchant Function Charge

New York only

Revenue Decoupling

90/10 Sharing

Weather Normalization

Utility

47

Providing Financial Stability

March 2013

Utility

48

Continued Cost Control Helps Provide Earnings Stability

March 2013

Utility

49

Strong Commitment to Safety

The anticipated increase in 2013

capital expenditures is largely due

to the implementation of a new

Customer Information System

The Utility remains

focused on consistent

spending to maintain

the ongoing safety and

reliability of its system

March 2013

National Fuel Gas Company

50

Comparable GAAP Financial Measure Slides and Reconciliations

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

operating

results

in

a

manner

that

is

focused

on

the

performance

of

the

Company’s

ongoing

operations,

or

on

earnings

absent

the

effect

of

certain

credits

and

charges,

including

interest,

taxes,

and

depreciation,

depletion

and

amortization.

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. 

March 2013

51

Reconciliation of Exploration & Production West Division Adjusted EBITDA

to Exploration & Production Segment Net Income

($ Thousands)

12 Months Ended

December 31, 2012

Exploration & Production - West Division Adjusted EBITDA

224,201

$                           

Exploration & Production - All Other Divisions Adjusted EBITDA

180,063

Total Exploration & Production Adjusted EBITDA

404,264

$                           

Minus: Pennsylvania Impact Fee Related to Prior Fiscal Years

(6,206)

Minus: Exploration & Production Net Interest Expense

(31,020)

Minus: Exploration & Production Income Tax Expense

(76,111)

Minus: Exploration & Production Depreciation, Depletion & Amortization

(198,064)

Exploration & Production Net Income

92,863

$                             

Exploration & Production Net Income

92,863

$                             

Pipeline & Storage Net Income

67,500

Utility Net Income

62,115

Energy Marketing Net Income

4,235

Corporate & All Other Net Income

609

Consolidated Net Income

227,322

$                    

March 2013

52

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

$           

224,201

$              

Exploration & Production - All Other Divisions Adjusted EBITDA

108,139

139,624

189,854

170,232

180,063

Total Exploration & Production Adjusted EBITDA

279,711

$           

327,462

$           

377,457

$           

397,129

$           

404,264

$              

Total Adjusted EBITDA

Exploration & Production Adjusted EBITDA

279,711

$           

327,462

$           

377,457

$           

397,129

$           

404,264

$              

Utility Adjusted EBITDA

164,443

167,328

168,540

159,986

164,386

Pipeline & Storage Adjusted EBITDA

130,857

120,858

111,474

136,914

146,147

Energy Marketing Adjusted EBITDA

11,589

13,573

13,178

5,945

6,065

Corporate & All Other Adjusted EBITDA

(5,575)

2,429

(2,960)

4,140

5,849

Total Adjusted EBITDA

581,025

$           

631,650

$           

667,689

$           

704,114

$           

726,711

$              

Total Adjusted EBITDA

581,025

$           

631,650

$           

667,689

$           

704,114

$           

726,711

$              

Minus: Net Interest Expense

(81,013)

(90,217)

(75,205)

(82,551)

(85,375)

Plus:  Other Income

9,762

6,126

5,947

5,133

5,212

Minus: Income Tax Expense

(52,859)

(137,227)

(164,381)

(150,554)

(153,379)

Minus: Depreciation, Depletion & Amortization

(170,620)

(191,199)

(226,527)

(271,530)

(281,314)

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

21,672

Minus: Pennsylvania Impact Fee Related to Prior Fiscal Years (E&P)

-

-

-

(6,206)

(6,206)

Rounding

-

-

-

(1)

2

Consolidated Net Income

100,708

$           

225,913

$           

258,402

$           

220,077

$           

227,322

$              

12-Months Ended

12/31/12

March 2013

53

Reconciliation of Segment Capital Expenditures to

Consolidated Capital Expenditures

($ Thousands)

FY 2013

FY 2009

FY 2010

FY 2011

FY 2012

Forecast

Capital Expenditures from Continuing Operations

Exploration & Production Capital Expenditures

188,290

$ 

398,174

$       

648,815

$       

693,810

$       

$480,000-560,000

Pipeline & Storage Capital Expenditures -

Expansion

52,504

37,894

129,206

144,167

$70,000-90,000

Utility Capital Expenditures

56,178

57,973

58,398

58,284

$65,000-70,000

Marketing, Corporate & All Other Capital Expenditures

9,829

7,311

17,767

81,133

$50,000-75,000

Total Capital Expenditures from Continuing Operations

306,801

$ 

501,352

$       

854,186

$       

977,394

$       

$665,000-795,000

Capital Expenditures from Discountinued Operations

All Other Capital Expenditures

216

150

$                

-

$                 

-

$                 

-

Plus (Minus) Accrued Capital Expenditures

Exploration & Production FY 2012 Accrued Capital Expenditures

-

-

$                 

(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 2012 Accrued Capital Expenditures

-

-

-

(2,696)

-

Pipeline & Storage FY 2011 Accrued Capital Expenditures

-

-

(7,271)

7,271

-

Pipeline & Storage FY 2008 Accrued Capital Expenditures

16,768

-

-

-

-

All Other FY 2012 Accrued Capital Expenditures

-

-

-

(11,000)

-

All Other FY 2011 Accrued Capital Expenditures

-

-

(1,389)

1,389

-

All Other FY 2009 Accrued Capital Expenditures

(715)

715

-

-

-

Total Accrued Capital Expenditures

6,960

$      

(58,401)

$        

(33,314)

$        

59,390

$         

-

Eliminations

(344)

$        

-

-

-

$                 

-

Total Capital Expenditures per Statement of Cash Flows

313,633

$ 

443,101

$       

820,872

$       

1,036,784

$   

$665,000-795,000

-

$          

$                 

$                 

$                                

$                                

$                                

$                                

$