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

National Fuel Gas Company

Investor Presentation

AGA Financial Forum

May 6-8, 2012

Exhibit 99

May 6-8, 2012

National Fuel Gas Company

2

Safe Harbor For Forward Looking Statements

May 6-8, 2012

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 created by

the integrated mix of assets continues to generate

significant long-term value for the Company in nearly all

economic and commodity price scenarios

Upstream

Natural Gas

Seneca Resources

Corporation

(West Division)

Seneca Resources

Corporation

(East Division)

May 6-8, 2012

National Fuel Gas Company

4

Integrated Business Mix Provides Financial Balance

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

May 6-8, 2012

National Fuel Gas Company

5

Businesses with Steady Cash Flows Limit Downside Risk

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

May 6-8, 2012

National Fuel Gas Company

6

Highly Integrated Assets with Significant Marcellus Exposure…

May 6-8, 2012

National Fuel Gas Company

7

…And Exposure to Growth from the Utica Shale

May 6-8, 2012

National Fuel Gas Company

Business Mix Allows for Strategic Capital Allocation

Predictable Earnings and Cash Flow

Capital Allocation Priorities

Ongoing maintenance capital spending in regulated businesses

Returning earnings to shareholders through consistent dividends

Flexible, return-driven growth capital spending

8

May 6-8, 2012

National Fuel Gas Company

9

Strategically Allocating Growth Capital Expenditures

Growth Capital Focus

Increasing Marcellus Production

Eastern Development Area

Western Development Area

Delineate other Appalachian Plays

Utica Shale

Geneseo Shale

Marcellus Wet Gas

Expand FERC-Regulated Infrastructure

Develop New Gathering Infrastructure

Unlock Seneca Acreage Position

Build Projects for 3   Parties

Analyst Day –

September 2011

Current Allocation

Growth Capital Focus

Increasing Marcellus Production

Eastern Development Area

Western Development Area

Delineate other Appalachian Plays

Utica Shale

Geneseo Shale

Marcellus Wet Gas

Expand FERC-Regulated Infrastructure

Develop New Gathering Infrastructure

Unlock Seneca Acreage Position

Build Projects for 3   Parties

rd

rd

May 6-8, 2012

National Fuel Gas Company

10

Broadening Our Infrastructure Expansion Focus

Source: ITG IR (formerly Ross Smith Energy Group)

May 6-8, 2012

National Fuel Gas Company

11

Continued Reduction in Capital Spending

1.

Maintain a strong balance sheet

2.

Flexibility to strategically

redeploy capital based upon

return-driven opportunities

Analyst Day: 6.5 Operated Rigs

Current Plan: 3 Operated Rigs

Factors Behind Capital Reduction

May 6-8, 2012

National Fuel Gas Company

12

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.

To the extent additional infrastructure

expansions are available, additional capital

remains flexible and will be deployed

based upon return-driven decision making

May 6-8, 2012

National Fuel Gas Company

13

Strong Balance Sheet and Liquidity Position

Capital Resources

Total Short-Term Capacity: $1,085 Million

Committed Credit Facility:  $750 Million

Five-year syndicated facility entered into

January 6, 2012

Uncommitted Lines of Credit: $335 Million

$300.0 Million Commercial Paper Program

backed by Committed Credit Facility

$20.0

million

of

outstanding

commercial

paper

as

of

March

31,

2012

$3.386 Billion

(1)

As of March 31, 2012

Short-Term

Debt

0.6%

(1) Includes Notes Payable to Banks and Commercial Paper of $20.0 million and Current Portion of Long-Term Debt of $250.0 million as

of March 31, 2012.

May 6-8, 2012

National Fuel Gas Company

14

Dividend Track Record

Current

Dividend Yield

(1)

3.0%

Dividend Consistency

Consecutive Dividend Payments

109 Years

Consecutive Dividend Increases

41 Years

Current Annualized Dividend Rate

$1.42 per Share

(1) As of April 30, 2012

May 6-8, 2012

Pipeline & Storage / Midstream

15

May 6-8, 2012

Pipeline & Storage / Midstream

16

Ongoing Expansion to Transport Appalachian Production

May 6-8, 2012

Pipeline & Storage / Midstream

17

A Closer Look at the Expansion Progress

May 6-8, 2012

Midstream

18

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

Original priority had been to assist

Seneca’s growing development

program and utilize those systems to

gather 3

rd

party producer volumes

As a result of Seneca’s delayed

development plans, the current focus is

shifting to expanding infrastructure for

others in the basin

TGP 300

Transco

Tioga County

Lycoming County

May 6-8, 2012

Pipeline & Storage Growth

19

Deploying Significant Growth Capital

Capital spending is increasing to fund system expansion and assuming recently

allowed industry average ROE and capital structure targets, this

segment can

achieve significant growth with a rapid increase in contracted volumes

19

May 6-8, 2012

Pipeline & Storage

20

Regulatory Rate Filings

National Fuel Gas Supply Corporation

Filed

a

general

rate

case

with

FERC

on

October

31,

2011

as

part

of

an

agreement

from

a

2006

rate

settlement

On April 14, 2012 an agreement in

principle was reached to settle the rate

case, with new rates effective May 1,

2012

Rates are effective subject to refund

beginning May 1, 2012

Empire Pipeline, Inc.

Filed a cost and revenue study on

March 14, 2012 as part of a 2006 FERC

order related to Empire’s transition to

a FERC-regulated interstate pipeline

Filing did not propose any changes to

the current rate structure

May 6-8, 2012

Utility

21

May 6-8, 2012

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

22

Providing Financial Stability

May 6-8, 2012

Utility

23

Low Natural Gas Prices Have Reduced Customer Bills

May 6-8, 2012

Utility

24

Continued Cost Control Helps Provide Earnings Stability

Low natural gas prices,

combined with a focus on

cost control, continue to

help reduce expenses

May 6-8, 2012

Utility

25

Strong Commitment to Safety

Capital spending from 2011 to 2014 is

expected to be between

$55 and $60 million per year

May 6-8, 2012

Exploration & Production

26

May 6-8, 2012

Seneca Resources

27

Ongoing Strategic Responses to Low Gas Prices

May 6-8, 2012

California

28

Stable Production and Increasing Cash Flows

Rank

Company

California

2010

BOEPD

1

Chevron

174,856

2

Aera (Shell/Exxon)

158,786

3

Occidental

151,584

4

Plains Exploration

36,488

5

Venoco Inc.

19,121

6

Berry Petroleum

18,513

7

Seneca Resources

9,041

8

Breitburn Energy

7,414

9

MacPherson

7,185

10

E&B Natural Resources

5,259

Net Acreage:  11,833 Acres

Net Wells:  1,322

Oil Gravity:  12 –

37°

Api

NRI:  87.64

May 6-8, 2012

California

29

Stable Production Fields

South Lost Hills

~1,700 BOEPD

Monterey Shale

Primary

215 Active Wells

Sespe

~1,200 BOEPD

Sespe Formation

Primary

188 Active Wells

North Lost Hills

~1,200 BOEPD

Tulare & Etchegoin Formation

Primary & Steamflood

181 Active Wells

North Midway Sunset

~4,400 BOEPD

Potter & Tulare Formation

Steamflood

728 Active Wells

South Midway Sunset

~1,000 BOEPD

Antelope Formation

Steamflood

109 Active Wells

May 6-8, 2012

California

30

Strong Margins Support Significant Free Cash Flow

Average Revenue

in First Six Months of

Fiscal 2012

$87.33 per BOE

Note:

A

reconciliation

of

Exploration

&

Production

West

Division

EBITDA

to

Exploration

&

Production

Segment

Net

Income

is

included

at

the

end

of

this

presentation. 

May 6-8, 2012

Seneca Resources

31

California –

Recent Initiatives Driving Near-Term Growth

Production Increase Drivers

1.North Midway Sunset Steaming

2.South Midway Sunset Field Extensions

3.Sespe Infill Drill Program

May 6-8, 2012

32

Midway Sunset South Activity Update

2011 Drill Program

2012 Drilling Locations

Updip Sand Pinch-out

Approx. Oil/Water Contact

100 ft

100 ft

50 ft

Antelope “A-1”

and “A-2”

Sands

Antelope “B”

and “C”

Sands

Antelope “A-1”

Sand

Seneca Western Minerals 251T

Extended 251 Pool to the West

Seneca Western Minerals 242I

Extended 252 Pool to the West

100 ft

400’

50 ft

50 ft

50 ft

2011 Drill Program:  12 Wells / 4 Injectors

2012 Drill Program:  23 Wells / 3 Injectors

Seneca Resources

May 6-8, 2012

33

350’

Thick

(Medium Blue)

800’

Thick

(Dark Red)

~550’

Thick

(Green)

White Star –

5 Acre Tests

Powell –

10 Acre Tests

Powell 4

61 BOEPD

1st

Oil 11/11

WS 534-33

42 BOEPD

1st

Oil 1/12

White Star –

10 Acre Test

WS 48-33

Completion Begins

April 2012

WS 533-33

88 BOEPD

1st

Oil 1/12

“X”

SANDS ISOCHORE (Thickness)

Seneca Resources

Sespe Field –

2011 Drilling Highlights and Results

Powell 3

136 BOEPD

1st

Oil 10/11

1 Mile

2011 Sespe Highlights

5 Wells Drilled (Two 5-acre infill tests)

Estimated EURs: 150-200 MBoe/Well

May 6-8, 2012

34

Proposed Bottom Hole Locations

Oak Flat (10)

Frankel A (5)

Thornbury (10/5)

Coldwater Tests

“X”

SANDS ISOCHORE (Thickness)

Type Log for

Frankel A Wells

Seneca Resources

Sespe Field –

2012 Drill Plan Builds Upon 2011 Successes

350’

Thick

(Medium Blue)

800’

Thick

(Dark Red)

~550’

Thick

(Green)

1 Mile

2012 Sespe Plans

6 Wells Planned (2 5-acre infill wells)

Estimated EURs: 140-170 MBoe/Well

May 6-8, 2012

Seneca Resources

35

Monterey Shale Play

Monterey Shale Play

Belridge Field

5 AMIs across the field

Seneca WI:   12.5%

Seneca NRI:  11.1%

Producing (Gross):  50 BOPD

3-4 Delineation Wells Planned

AMI Outlines

Gross Thickness of Monterey Interval

May 6-8, 2012

Seneca Resources

36

Expansive Pennsylvania Acreage Position

SRC Lease Acreage

SRC Fee Acreage

Eastern Development Area

Net Acreage: 55,000 acres

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

Net acreage:

690,000 acres

Own most mineral rights

Minimal

royalty obligation

Minimal

lease expiration

Evaluating Marcellus rich-gas 

and Utica Shale potential

EOG Acreage

May 6-8, 2012

Seneca Resources

37

Net Rig Count (Working Interest)

Fiscal 2013 rig count

range depends on

participation in

EOG JV wells

May 6-8, 2012

Seneca Resources

38

Ramping Marcellus Shale Production

May 6-8, 2012

Seneca Resources

39

Eastern Development Area (EDA) –

Results & Plan Forward

SRC Lease Acreage

SRC Fee Acreage

DCNR Tract 595

FY2012: 1 Rig Operating

FY2013: 0-1 Rigs Operating

Production: 45 MMcf per Day

Covington –

Fully Developed

47 Wells Drilled and Producing

Production: 85 MMcf per Day

DCNR Tract 100

8 Wells Drilled

FY2012 & FY2013: 1-2 Rigs Operating

First Production:  Late May 2012

First Well Test: 15.8 MMcf per Day

DCNR Tract 001

Expiration Date:  January 2020

Minimum Wells to Hold Acreage:  24

DCNR Tract 007

Expiration Date:  January 2020

Minimum Wells to Hold Acreage:  33

May 6-8, 2012

Seneca Resources

40

Evaluating Marcellus Wet Gas Potential

More than 100,000 acres within the targeted

window of 1,100 Btu to 1,200 Btu

Will need cryogenic processing plant running in

“ethane rejection mode”

processing

Potential $0.50 -

$0.70 per Mcf uplift from sale

of NGLs (excluding Ethane)

SRC Lease Acreage

SRC Fee Acreage

EOG Acreage

Owl’s Nest (2 Wells)

Church Run (1 Well)

Proposed  Hz Well

May 6-8, 2012

41

Chesapeake

9.5 MMCFD

1,425 BLPD

Chesapeake

3.8 MMCFD

980 BLPD

Chesapeake

3.1 MMCFD

1,015 BLPD

Dry

Wet

Hess

11 MMCFD

Utica Shale –

Activity Summary

Seneca Resources

Vertical Well Drilled

Horizontal Well Permit

Horizontal Well Drilled

Mt. Jewett

Vertical:  Tested Dry Gas

Horizontal:  Prep to Complete

Henderson

Vertical Well

Tionesta

Horizontal: Drilling

Owl’s Nest

Horizontal FY2013

Chesapeake

6.4 MMCFD

Rex

9.2 MMCFD

May 6-8, 2012

Seneca Resources

42

Increased California Spending with Ongoing Marcellus Cuts

(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

May 6-8, 2012

Seneca Resources

43

Production Still Growing

May 6-8, 2012

National Fuel Gas Company

44

Appendix

May 6-8, 2012

National Fuel Gas Company

45

Manageable Debt Maturity Schedule

May 6-8, 2012

National Fuel Gas Company

46

Targeted Capital Structure

Long-Term Consolidated

Capital Structure Target

Capital Structure

Targets by Segment

May 6-8, 2012

Pipeline & Storage / Midstream

47

Appendix

May 6-8, 2012

Pipeline & Storage

48

Expansion Initiatives

Project Name

Capacity

(Dth/D)

Est.

CapEx

In-Service

Market

Status

Lamont Compressor Station

40,000

$6 MM

6/2010

Fully Subscribed

Completed

Lamont Phase II Project

50,000

$7.6 MM

7/2011

Fully Subscribed

Completed

Line “N”

Expansion

160,000

$22 MM

10/2011

Fully Subscribed

Completed

Tioga County Extension

350,000

$56 MM

11/2011

Fully Subscribed

Completed

Northern Access Expansion

320,000

~$71 MM

~11/2012

Fully Subscribed

Currently under construction

Line “N”

2012 Expansion

164,000

~$36 MM

~11/2012

Fully Subscribed

Currently under construction

Line “N”

2013 Expansion

30,000

~$4 MM

11/2013

OS Concluded

Negotiating with an anchor shipper for all

capacity

Mercer Expansion Project

150,000

~$30 MM

~6/2014

OS Concluded

In discussions with an anchor shipper for

all capacity

Central Tioga County

Extension

~250,000

~$135 MM

2014/2015

OS Concluded

In discussions with an anchor shipper

West to East

~425,000

~$290 MM

~2015

29% Subscribed

Marketing continues with producers in

various stages of exploratory drilling

Total Firm Capacity:  ~1,939,000 Dth/D

Capital Investment: ~$658 MM

May 6-8, 2012

Midstream Corporation

49

Expansion Initiatives

Project Name

Capacity

(Mcf/D)

Est.

CapEx

In-Service

Date

Market

Comments

Covington Gathering System

220,000

$54 MM

Multiple

Phases -

Most

In-Service

Fully Subscribed

Completed

–

Flowing into TGP 300

Line.  This includes $32 million of

spending to build pipeline and

compression needed to connect

future wells.

Trout Run Gathering System

466,000

$130 MM

May 2012

70% Subscribed

Under construction. This includes

spending to build pipeline and

compression needed to connect

future wells. 

Mt. Jewett Gathering System

170,000

$22 MM

FY2013

Fully Subscribed

Preliminary work underway

Owl’s Nest Gathering System

50,000

$17 MM

FY2014

Fully Subscribed

Preliminary work underway.  Any

processing costs would be

incremental. 

Total Firm Capacity:  ~906,000 Mcf/D

Capital Investment: ~$223 MM

The relative increase in spending on these projects from prior guidance is a result of a shift in

spending on certain gathering infrastructure from Seneca to NFG Midstream, which will now

handle the future build out of compression and well lines previously associated with Seneca.

May 6-8, 2012

Exploration & Production

50

Appendix

May 6-8, 2012

National Fuel Gas Company

51

Hedge Positions and Strategy

Natural Gas

Swaps

Volume

(Bcf)

Average

Hedge Price

Fiscal 2012

(1)

17.5

$5.89 / Mcf

Fiscal 2013

38.9

$4.97 / Mcf

Fiscal 2014

19.5

$4.34 / Mcf

Oil Swaps

Volume

(MMBbl)

Average

Hedge Price

Fiscal 2012

(1)

0.8

$77.03 / Bbl

Fiscal 2013

1.5

$92.52 / Bbl

Fiscal 2014

0.6

$95.68 / Bbl

Most hedges executed at sales point to eliminate basis risk

(1)

Fiscal 2012 hedge positions are for the remaining six months of the fiscal year

Seneca has hedged approximately 46% of its remaining

forecasted production for Fiscal 2012 

May 6-8, 2012

Marcellus Shale

52

Western Development Area (WDA) –

Results & Plan Forward

SRC Lease Acreage

SRC Fee Acreage

EOG Contributed JV Acreage

SRC Contributed JV Acreage

Seneca Operated

EOG Operated

Approx. Outline of JV Acreage

200,000 Gross Acres

Seneca 50% W.I. (Avg. 58% NRI)

Punxy (EOG Operated)

68 Wells Drilled; 39 Producing

FY2012: 2 Rigs Operating (Drill 33 wells)

Gross Production: ~54 MMcf per Day

Owl’s Nest

Drilled 3 Horizontal Wells

Acquiring 3D Seismic

Potential 2013 Wet Gas Development

Expected IPs: 4-5 MMcf per Day

Mt. Jewett

Drilled 3 Horizontal Wells

IPs: 2.4 -

3.1 MMcf per Day

Boone Mountain

Drilled 3 Horizontal Wells

IPs: 3.8 -

4.6 MMcf per Day

Rich Valley

1 Well to be completed

in FY2012 2Q

Church Run

FY2012: 1 Well 

To Test EUR & BTU Content

May 6-8, 2012

Marcellus Shale

53

Expanding 3D Seismic Coverage

Completed

In Progress

Punxy

West  Branch

Mt. Jewett

DCNR 001

DCNR 007

Covington

DCNR 595

DCNR 100

Owl’s Nest

May 6-8, 2012

Marcellus Shale

54

Covington

Typecurve

–

6.7

Bcfe

EUR

(Greater

Than

3,500’

Lateral)

May 6-8, 2012

Marcellus Shale

55

Targeting Continued Cost Reductions

May 6-8, 2012

Marcellus Shale

56

Breaking Down Our Acreage Position

Area

Net Acres

Possible

Locations

Wells Drilled

Wells

Completed

EUR (Bcfe)

Status

Eastern Development Area (EDA)

Covington

7,000

47

47

47

5.5

Developed

595

6,000

55

29

13

7.0

Full Development

100

10,000

70

12

1

8.0

Full Development

007

15,000

75

1

1

3.0 -

5.0

Delineating

001

13,000

58

1

1

3.0 -

5.0

Delineating

Other EDA

4,000

10

-

-

3.0 -

8.0

Untested

55,000

315

90

63

Western Development Area (WDA)

Owl's Nest / Ridgeway

91,000

680

4

4

4.0

Waiting on Development

Mt. Jewett

25,000

232

4

4

3.0 

Delineating

James City

30,000

340

1

1

3.0 -

5.0

Delineating

Boone Mtn

8,500

59

4

4

4.0

Waiting on Development

Rich Valley

30,000

188

1

-

4.0 -

5.0

Delineating

WDA Other

337,000

2,654

4

3

2.0 -

6.0

Untested

521,500

4,153

18

16

EOG Operated

Punxy

12,000

87

72

39

4.0

Full Development

West Branch

12,500

121

9

5

3.0 -

5.0

Delineating

Clermont

10,000

96

2

2

3.0 -

5.0

Delineating

Brady

13,500

113

-

-

4.0 -

5.0

Untested

EOG Other

120,500

502

2

2

2.0 -

5.0

Untested

168,500

919

85

48

Seneca Resources Total

745,000

5,387

193

127

May 6-8, 2012

Marcellus Shale

57

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

Tioga County –

DCNR 595 and Covington

Lycoming County –

DCNR 100

Elk County -

Owl’s Nest

Installing new evaporative technology

Investigating underground injection

Seneca is committed to protecting the surface from any type of pollution

May 6-8, 2012

Marcellus Shale

58

“Zero Liquid Discharge Operation”

Utilizing a state-of-the-art evaporative technology to ensure no liquid is

discharged at the surface

Building centrally located units in the Western Development Area

(WDA)

and the Eastern Development Area (EDA)

Removes all liquids from the production stream

Has the ability to be powered by the waste heat from a compressor station

End products:

Non-hazardous solidified salt material

Clean water vapor emissions

May 6-8, 2012

National Fuel Gas Company

59

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.  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. 

Reconciliation of Segment Capital Expenditures to Consolidated Capital Expenditures

($ Thousands)

	FY 2009			FY 2010			FY 2011			FY 2012 Forecast	FY 2013 Forecast
Capital Expenditures from Continuing Operations
Exploration & Production Capital Expenditures	$	188,290		$	398,174		$	648,815		$610,000-690,000	$450,000-550,000
Pipeline & Storage Capital Expenditures - Expansion		52,504			37,894			129,206		$135,000-165,000	$30,000-50,000
Utility Capital Expenditures		56,178			57,973			58,398		$55,000-60,000	$55,000-60,000
Marketing, Corporate & All Other Capital Expenditures		9,829			7,311			17,767		$100,000-130,000	$75,000-125,000
Total Capital Expenditures from Continuing Operations	$	306,801		$	501,352		$	854,186		$900,000-1,045,000	$610,000-785,000
Capital Expenditures from Discountinued Operations
All Other Capital Expenditures		216		$	150		$	—		$—	$—
Plus (Minus) Accrued Capital Expenditures
Exploration & Production FY 2011 Accrued Capital Expenditures	$	—		$	—		$	(63,460	)	$—	$—
Pipeline & Storage FY 2011 Accrued Capital Expenditures		—			—			(7,271	)	—	—
All Other FY 2011 Accrued Capital Expenditures		—			—			(1,389	)	—	—
Exploration & Production FY 2010 Accrued Capital Expenditures		—			(55,546	)		55,546		—	—
Exploration & Production FY 2009 Accrued Capital Expenditures		(9,093	)		9,093			—		—	—
Pipeline & Storage FY 2008 Accrued Capital Expenditures		16,768			—			—		—	—
All Other FY 2009 Accrued Capital Expenditures		(715	)		715			—		—	—
Total Accrued Capital Expenditures	$	6,960		$	(45,738	)	$	(16,574	)	$—	$—
Eliminations	$	(344	)	$	—		$	—		$—	$—
Total Capital Expenditures per Statement of Cash Flows	$	313,633		$	455,764		$	837,612		$900,000-1,045,000	$610,000-785,000

Reconciliation of Exploration & Production West Division EBITDA to Exploration & Production Segment Net Income

($ Thousands)

	6 Months Ended March 31, 2012
Exploration & Production - West Division EBITDA	$	118,341
Exploration & Production - All Other Divisions EBITDA		68,866
Total Exploration & Production EBITDA	$	187,207
Minus: Exploration & Production Net Interest Expense		(11,825	)
Minus: Exploration & Production Income Tax Expense		(39,053	)
Minus: Exploration & Production Depreciation, Depletion & Amortization		(83,822	)
Exploration & Production Net Income	$	52,507
Exploration & Production Net Income	$	52,507
Exploration & Production - West Division Production (MBoe)		1,703
Exploration & Production - Net Income per West Division Production (Boe)	$	30.84
Exploration & Production - West Division EBITDA	$	118,341
Exploration & Production - West Division Production (MBoe)		1,703
Exploration & Production - West Division EBITDA per West Division Production (Boe)	$	69.50

Reconciliation of EBITDA to Net Income

($ Thousands)

	FY 2008			FY 2009			FY 2010			FY 2011			12 Months Ended March 31, 2012
Exploration & Production - West Division EBITDA	$	188,008		$	170,611		$	187,838		$	187,603		$	217,180
Exploration & Production - All Other Divisions EBITDA		174,216			109,100			139,624			189,854			161,651
Total Exploration & Production EBITDA	$	362,224		$	279,711		$	327,462		$	377,457		$	378,831
Exploration & Production EBITDA	$	362,224		$	279,711		$	327,462		$	377,457		$	378,831
Utility EBITDA		161,575			164,443			167,328			168,540			155,457
Pipeline & Storage EBITDA		129,171			130,857			120,858			111,474			116,965
Energy Marketing EBITDA		8,699			11,589			13,573			13,178			7,419
Corporate & All Other EBITDA		(8,156	)		(5,575	)		2,429			(2,960	)		716
Total EBITDA	$	653,513		$	581,025		$	631,650		$	667,689		$	659,388
Total EBITDA	$	653,513		$	581,025		$	631,650		$	667,689		$	659,388
Minus: Net Interest Expense		(62,555	)		(81,013	)		(90,217	)		(75,205	)		(74,978	)
Plus: Other Income		7,164			8,200			3,638			6,706			6,621
Minus: Income Tax Expense		(167,672	)		(52,859	)		(137,227	)		(164,381	)		(139,792	)
Minus: Depreciation, Depletion & Amortization		(169,846	)		(170,620	)		(191,199	)		(226,527	)		(238,901	)
Minus: Exploration & Production Impairment					(182,811	)
Plus/Minus: Income/(Loss) from Discontinued Operations, Net of Tax		1,821			(2,776	)		6,780			—			—
Plus: Gain on Sale of Unconsolidated Subsidiaries		—			—			—			50,879			—
Plus/Minus: Income/(Loss) from Unconsolidated Subsidiaries		6,303			3,366			2,488			(759	)		—
Minus: Impairment of Investment in Partnership		—			(1,804	)								—
Net Income	$	268,728		$	100,708		$	225,913		$	258,402		$	212,338