National Fuel Gas (NFG) 8-K Regulation FD Disclosure

National Fuel Gas Company

Investor Presentation

February 2013

Exhibit 99

February 2013

National Fuel Gas Company

2

Safe Harbor For Forward Looking Statements

This

presentation

may

contain

“forward-looking

statements”

as

defined

by

the

Private

Securities

Litigation

Reform

Act

of

1995,

including

statements

regarding

future

prospects,

plans,

performance

and

capital

structure,

anticipated

capital

expenditures

and

completion

of

construction

projects,

as

well

as

statements

that

are

identified

by

the

use

of

the

words

“anticipates,”

“estimates,”

“expects,”

“forecasts,”

“intends,”

“plans,”

“predicts,”

“projects,”

“believes,”

“seeks,”

“will,”

“may,”

and

similar

expressions.

Forward-looking

statements

involve

risks

and

uncertainties,

which

could

cause

actual

results

or

outcomes

to

differ

materially

from

those

expressed

in

the

forward-looking

statements.

The

Company’s

expectations,

beliefs

and

projections

contained

herein

are

expressed

in

good

faith

and

are

believed

to

have

a

reasonable

basis,

but

there

can

be

no

assurance

that

such

expectations,

beliefs

or

projections

will

result or be achieved or accomplished. 

In

addition

to

other

factors,

the

following

are

important

factors

that

could

cause

actual

results

to

differ

materially

from

results

referred

to

in

the

forward-looking

statements:

factors

affecting

the

Company’s

ability

to

successfully

identify,

drill

for

and

produce

economically

viable

natural

gas

and

oil

reserves,

including

among

others

geology,

lease

availability,

title

disputes,

weather

conditions,

shortages,

delays

or

unavailability

of

equipment

and

services

required

in

drilling

operations,

insufficient

gathering,

processing

and

transportation

capacity,

the

need

to

obtain

governmental

approvals

and

permits,

and

compliance

with

environmental

laws

and

regulations;

changes

in

laws,

regulations

or

judicial

interpretations

to

which

the

Company

is

subject,

including

those

involving

derivatives,

taxes,

safety,

employment,

climate

change,

other

environmental

matters,

real

property,

and

exploration

and

production

activities

such

as

hydraulic

fracturing;

changes

in

the

price

of

natural

gas

or

oil;

impairments

under

the

SEC’s

full

cost

ceiling

test

for

natural

gas

and

oil

reserves;

uncertainty

of

oil

and

gas

reserve

estimates;

significant

differences

between

the

Company’s

projected

and

actual

production

levels

for

natural

gas

or

oil;

changes

in

demographic

patterns

and

weather

conditions;

changes

in

the

availability,

price

or

accounting

treatment

of

derivative

financial

instruments;

governmental/regulatory

actions,

initiatives

and

proceedings,

including

those

involving

rate

cases

(which

address,

among

other

things,

allowed

rates

of

return,

rate

design

and

retained

natural

gas),

environmental/safety

requirements,

affiliate

relationships,

industry

structure,

and

franchise

renewal;

delays

or

changes

in

costs

or

plans

with

respect

to

Company

projects

or

related

projects

of

other

companies,

including

difficulties

or

delays

in

obtaining

necessary

governmental

approvals,

permits

or

orders

or

in

obtaining

the

cooperation

of

interconnecting

facility

operators;

financial

and

economic

conditions,

including

the

availability

of

credit,

and

occurrences

affecting

the

Company’s

ability

to

obtain

financing

on

acceptable

terms

for

working

capital,

capital

expenditures

and

other

investments,

including

any

downgrades

in

the

Company’s

credit

ratings

and

changes

in

interest

rates

and

other

capital

market

conditions;

changes

in

economic

conditions,

including

global,

national

or

regional

recessions,

and

their

effect

on

the

demand

for,

and

customers’

ability

to

pay

for,

the

Company’s

products

and

services;

the

creditworthiness

or

performance

of

the

Company’s

key

suppliers,

customers

and

counterparties;

economic

disruptions

or

uninsured

losses

resulting

from

major

accidents,

fires,

severe

weather,

natural

disasters,

terrorist

activities,

acts

of

war,

cyber

attacks

or

pest

infestation;

changes

in

price

differential

between

similar

quantities

of

natural

gas

at

different

geographic

locations,

and

the

effect

of

such

changes

on

the

demand

for

pipeline

transportation

capacity

to

or

from

such

locations;

other

changes

in

price

differentials

between

similar

quantities

of

oil

or

natural

gas

having

different

quality,

heating

value,

geographic

location

or

delivery

date;

significant

differences

between

the

Company’s

projected

and

actual

capital

expenditures

and

operating

expenses;

changes

in

laws,

actuarial

assumptions,

the

interest

rate

environment

and

the

return

on

plan/trust

assets

related

to

the

Company’s

pension

and

other

post-retirement

benefits,

which

can

affect

future

funding

obligations

and

costs

and

plan

liabilities;

the

cost

and

effects

of

legal

and

administrative

claims

against

the

Company

or

activist

shareholder

campaigns

to

effect

changes

at

the

Company;

increasing

health

care

costs

and

the

resulting

effect

on

health

insurance

premiums

and

on

the

obligation

to

provide

other

post-retirement

benefits;

or

increasing

costs

of

insurance,

changes

in

coverage

and

the

ability

to

obtain

insurance.

Forward-looking

statements

include

estimates

of

oil

and

gas

quantities.

Proved

oil

and

gas

reserves

are

those

quantities

of

oil

and

gas

which,

by

analysis

of

geoscience

and

engineering

data,

can

be

estimated

with

reasonable

certainty

to

be

economically

producible

under

existing

economic

conditions,

operating

methods

and

government

regulations.

Other

estimates

of

oil

and

gas

quantities,

including

estimates

of

probable

reserves,

possible

reserves,

and

resource

potential,

are

by

their

nature

more

speculative

than

estimates

of

proved

reserves.

Accordingly,

estimates

other

than

proved

reserves

are

subject

to

substantially

greater

risk

of

being

actually

realized.

Investors

are

urged

to

consider

closely

the

disclosure

in

our

Form

10-K

available

at

www.nationalfuelgas.com.

You

can

also

obtain

this

form

on

the

SEC’s

website

at

www.sec.gov.

For

a

discussion

of

the

risks

set

forth

above

and

other

factors

that

could

cause

actual

results

to

differ

materially

from

results

referred

to

in

the

forward-looking

statements,

see

“Risk

Factors”

in

the

Company’s

Form

10-K

for

the

fiscal

year

ended

September

30,

2012

and

Form

10-Q

for

the

period

ended

December

31,

2012.

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.

February 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 and flexibility

created by this integrated mix of businesses continues to generate

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)

February 2013

Appalachian Shale Growth

4

Integrated Businesses with Significant Marcellus Exposure…

February 2013

Appalachian Shale Growth

5

…And Exposure to Growth from the Utica Shale

February 2013

National Fuel Gas Company

6

Integrated Business Mix Provides Financial Balance

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. 

February 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)  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

February 2013

National Fuel Gas Company

8

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. 

February 2013

National Fuel Gas Company

9

Strong Balance Sheet and Liquidity Position

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

$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

December31,

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.

$300.0 Million Commercial Paper Program backed

by Committed Credit Facility

$220.0 million of outstanding commercial

paper  as of December 31, 2012

February 2013

National Fuel Gas Company

10

Dividend Track Record

(1) As of February 7, 2013

February 2013

Midstream Businesses

11

Pipeline & Storage/NFG Midstream

February 2013

Midstream Businesses

12

Pipeline Expansions to Transport Appalachian Production

February 2013

Midstream Businesses

13

A Closer Look at the Expansion Progress

February 2013

Midstream Businesses

14

Pursuing Additional Opportunities Near the Line N Corridor

Activity along the Pennsylvania/Ohio

border continues to remain robust and is

shifting north as the Utica begins to be

delineated

National Fuel’s Line N system is well-

positioned to expand in conjunction with

growth from both the Marcellus and Utica

shales

Significant expansion opportunities may be

present in the next few years

2013:

Smaller lateral pipeline extensions

between $3 and $20 million

2014/2015:

Medium to larger expansion

projects, possibly including an integrated

wet gas solution, with National Fuel

focused on the high-pressure wet gas

gathering systems and dry gas interstate

pipelines

February 2013

NFG Midstream

15

Using a History of Excellence to Serve 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

February 2013

Utility

16

February 2013

Rate Mechanisms

Utility

17

Providing Financial Stability

Low Income Rates

Choice Program/POR

Merchant Function Charge

Revenue Decoupling

90/10 Sharing

Weather Normalization

New York & Pennsylvania

New York only

February 2013

Utility

18

Continued Cost Control Helps Provide Earnings Stability

February 2013

Utility

19

Strong Commitment to Safety

The anticipated increase in 2013

capital expenditures is largely due

to the implementation of a new

Customer Information System

February 2013

Exploration & Production

20

February 2013

Seneca Resources

21

Another Strong Year of Reserve Growth

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

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

February 2013

Seneca Resources

22

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

February 2013

Seneca Resources

23

Production Still Growing

February 2013

Seneca Resources

24

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

February 2013

California

25

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

February 2013

California

26

Stable Production Fields

California

27

Strong Margins Support Significant Free Cash Flow

Average Revenue

(12 Months Ended 12/31/12)

$85.69 per BOE

February 2013

$9.40

$3.35

$3.06

$2.32

$1.11

$66.45

Non

Steam Fuel LOE

Steam Fuel

G&A

Production & Other Taxes

Other Operating Costs

Adjusted EBITDA

(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. 

Adjusted EBITDA per BOE

(1)

(12 Months Ended December 31, 2012)

February 2013

Seneca Resources

28

California –

Recent Initiatives Driving Near-Term Growth

February 2013

Midway Sunset South Activity Update

Seneca Resources

29

February 2013

30

“X”

SANDS ISOCHORE (Thickness)

Seneca Resources

Sespe Field –

Drilling Programs and Results

February 2013

Seneca Resources

31

Monterey Shale Play

February 2013

Seneca Resources

32

Expansive Pennsylvania Acreage Position

February 2013

Seneca Resources

33

Eastern Development Area (EDA)

February 2013

Seneca Resources

34

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

Tioga

County

19

6.9

6.0

5.1

7.3

4,455’

1.65

Tract 100 –

Pad C & D

Lycoming

County

7

12.7

11.6

10.4

11.6

5,788’

2.00

Tract 100 Pad M

Lycoming

County

7

18.2

TBD

TBD

TBD

4,721

TBD

February 2013

Seneca Resources

35

Ramping Marcellus Shale Production

February 2013

Seneca Resources

36

Fiscal 2013 Western Development Area Delineation Program

February 2013

Seneca Resources

Utica Shale –

Activity Summary

37

February 2013

Seneca Resources

38

Initial Entry into the Mississippian Lime Play in Kansas

Total Net Acres: 9,300

The initial entry into the Mississippian Lime play furthers the Company’s goal of

maintaining a significant contribution from oil-producing properties

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

February 2013

National Fuel Gas Company

39

Appendix

February 2013

National Fuel Gas Company

40

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

February 2013

National Fuel Gas Company

41

Manageable Debt Maturity Schedule

February 2013

Pipeline & Storage / Midstream

42

Appendix

February 2013

Pipeline & Storage

43

Expansion Initiatives

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

~$10 MM

11/2013

Fully Subscribed

Executed Precedent Agreement

Mercer Expansion Project

105,000

~$20 MM

9/2014

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

Late 2015

OS Concluded

Evaluating market interest and facility

design

West to East

~425,000

~$290 MM

~2015

29% Subscribed

Marketing continues with producers in

various stages of exploratory drilling

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

Capital Investment: ~$682+ MM

February 2013

Midstream Corporation

44

Expansion Initiatives

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

$2.5 MM

FY2013

Q2

Fully Subscribed

Under Construction

Mt. Jewett Gathering System

10,000

$2.7 MM

FY2013

Q2

Fully Subscribed

Under Construction

Total Firm Capacity:  ~706,000 Mcf/D

Capital Investment: ~$230 MM

February 2013

Exploration & Production

45

Appendix

February 2013

National Fuel Gas Company

46

Hedge Positions and Strategy

Natural Gas

Swaps

Volume

(Bcf)

Average

Hedge Price

Fiscal 2013

43.2

$4.68 / Mcf

Fiscal 2014

49.9

$4.24 / Mcf

Fiscal 2015

22.7

$4.10 / 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

1.2

$98.95 / Bbl

Fiscal 2015

0.4

$90.14 / Bbl

Most hedges executed at sales point to eliminate basis risk

Seneca has hedged approximately 62% of its

forecasted production for Fiscal 2013 

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

February 2013

Marcellus Shale

47

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. 

February 2013

Marcellus Shale

48

Water Management Program

Water Sourcing:

Coal mine runoff

Permitted freshwater sources

Recycled water

Water Management:

Instituted a “Zero Surface Discharge”

policy

Recycle Marcellus flowback and produced water

Centralized water handling in development areas

Installing new evaporative technology

Permitting underground injection

Established a Water Protection Team

Seneca is committed to protecting the surface and fresh water aquifers from any pollution

February 2013

National Fuel Gas Company

49

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. 

February 2013

50

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

$                    

February 2013

51

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

February 2013

52

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