EX-99

UBS Houston Energy

Conference

August 10, 2011

Exhibit 99

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: 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 terrorist activities, acts of war, major accidents, fires, severe weather, pest infestation or natural

disasters; 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,

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 and regulations to which the Company is subject, including those involving

derivatives, taxes, safety, employment, climate change, other environmental matters, and exploration and production activities such as hydraulic fracturing; uncertainty of oil and gas reserve

estimates; significant differences between the Company’s projected and actual production levels for natural gas or oil; significant changes in market dynamics or competitive factors affecting the

Company’s ability to retain existing customers or obtain new customers; changes in demographic patterns and weather conditions; changes in the availability and/or price of natural gas or oil and

the effect of such changes on the accounting treatment of derivative financial instruments; impairments under the SEC’s full cost ceiling test for natural gas and oil reserves; changes in the

availability and/or cost of derivative financial instruments; changes in the 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; changes in the projected profitability of pending or potential projects, investments or transactions; significant differences between the Company’s

projected and actual capital expenditures and operating expenses; delays or changes in costs or plans with respect to the Company’s 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; governmental/regulatory actions,

initiatives and proceedings, including those involving derivatives, acquisitions, financings, rate cases (which address, among other things, allowed rates of return, rate design and retained natural

gas), affiliate relationships, industry structure, franchise renewal, and environmental/safety requirements; unanticipated impacts of restructuring initiatives in the natural gas and electric industries;

ability to successfully identify and finance acquisitions or other investments and ability to operate and integrate existing and any subsequently acquired business or properties; changes in 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; significant changes in tax rates or policies or in rates of inflation or interest; significant changes in the Company’s relationship with its employees or contractors and the

potential adverse effects if labor disputes, grievances or shortages were to occur; changes in accounting principles or the application of such principles to the Company; 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

You can also obtain this form on the SEC’s website at

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, 2010 and the Company’s Forms 10-Q for the periods ended December 31, 2010, March 31, 2011 and June 30, 2011. 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.

UBS Houston Energy Conference – August 10, 2011

www.nationalfuelgas.com.

www.sec.gov.

National Fuel Gas Company

Business Segment Reporting

National Fuel Gas Company

Exploration &

Production

Seneca

Resources

Corporation

Pipeline &

Storage

National Fuel

Gas Supply

Corporation

Empire Pipeline,

Inc.

Utility

National Fuel

Gas Distribution

Corporation

Energy

Marketing

National Fuel

Resources, Inc.

Publicly Traded

Holding Company

NYSE symbol -

NFG

Reporting

Segments

Operating

Subsidiaries

UBS Houston Energy Conference – August 10, 2011

UBS Houston Energy Conference – August 10, 2011

UBS Houston Energy Conference – August 10, 2011

UBS Houston Energy Conference – August 10, 2011

Net Income from Continuing Operations

Excluding

Items

Impacting

Comparability

(1)

National Fuel Gas Company

(1)

A reconciliation to GAAP Net Income is included at the end of this presentation.

$222.0 Million

Twelve Months Ended

June 30, 2011

E&P

$121.0 MM

54.5%

UBS Houston Energy Conference – August 10, 2011

National Fuel Gas Company

Capital Expenditures

(1)

from Continuing Operations

(1)

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

$970-1,110

$770-885

$501

$307

$417

$248

$1,250

$1,000

$750

$500

$250

$43

$166

$53

$38

$100-150

$100-135

2007

2008

2009

2010

2011

2012

$147

$192

$188

$398

$600-655

$785-875

$54

$57

$56

$58

$55-60

Fiscal Year

Forecast

Utility

Pipeline & Storage

Exploration & Production

All Other

UBS Houston Energy Conference – August 10, 2011

National Fuel Gas Company

Capital Structure

$2.900 Billion

(1)

at June 30, 2011

Forecasted Capital

Structure

(2)

at September 30, 2011

Long-Term

Debt

36%

Shareholders’

Equity

64%

Long-Term

Debt

36%

Shareholders’

Equity

64%

At June 30, 2011, Comprehensive Shareholders’ Equity, Long-Term Debt and the Current Portion of Long-Term Debt totaled $2.90 Billion as presented on the Company’s Balance Sheet, of which $0.899 Billion was Long-Term

Debt, $0.150 Billion was the Current Portion of Long-Term Debt and $1.851 Billion was Comprehensive Shareholders’ Equity

At September 30, 2011, forecasted Total Capitalization is $2.943 Billion, of which $0.899 Billion is Long-Term Debt, $0.150 Billion is the Current Portion of Long-Term

Debt and $1.894 Billion is Comprehensive Shareholders’ Equity

UBS Houston Energy Conference – August 10, 2011

UBS Houston Energy Conference – August 10, 2011

Exploration & Production

Seneca Resources Corporation

UBS Houston Energy Conference – August 10, 2011

Exploration & Production

Fiscal Year End Proved Reserves

(1)

West –

California

Reserves: 333 Bcfe (47%)

(55.5 MMBoe)

Gulf of Mexico

Reserves: 34 Bcfe (5%)

East –

Appalachia

Reserves: 333 Bcfe (48%)

(1)

At September 30, 2010

Total Proved Reserves: 700 Bcfe

226

249

428

200

400

600

2008

2009

2010

At September 30

Natural Gas

46.2

46.6

45.2

2008

2009

2010

At September 30

Oil

Exploration & Production

Historical Daily Production

100

150

200

250

West

Upper Devonian

Gulf

Marcellus

UBS Houston Energy Conference – August 10, 2011

UBS Houston Energy Conference – August 10, 2011

Exploration & Production

Capital Expenditures by Region

(1)

Does not include the $34.9MM acquisition of Ivanhoe’s US-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.

(1)

UBS Houston Energy Conference – August 10, 2011

Exploration & Production

Annual Production by Region

Marcellus production in

Fiscal 2012 could equal

the entire company

production in Fiscal 2011

UBS Houston Energy Conference – August 10, 2011

Exploration & Production

California

UBS Houston Energy Conference – August 10, 2011

Seneca’s California Properties

South Lost Hills

~1,800 BOEPD

Monterey Shale

Primary

216 Active Wells

Sespe

~990 BOEPD

Sespe Formation

Primary

193 Active Wells

North Lost Hills

~1,235 BOEPD

Tulare & Etchegoin Formation

Primary & Steamflood

181 Active Wells

North Midway Sunset

~4,050 BOEPD

Potter & Tulare Formation

Steamflood

703 Active Wells

South Midway Sunset

~720 BOEPD

Antelope Formation

Steamflood

100 Active Wells

As of March 27, 2011

UBS Houston Energy Conference – August 10, 2011

California

Average Daily Production

Modest capital spending

to maintain production

Pursue additional bolt-on

acquisitions

2012 Plans:

CapEx -

$45-55 MM

Expect modest production

growth

UBS Houston Energy Conference – August 10, 2011

California

Fiscal Year 2011 Sespe Field Development Plans

First drilling for Seneca at Sespe since 1991

Will drill six wells during this fiscal year

Wells to be drilled at 10-acre spacing: 4 wells

Test wells to be drilled at 5-acre spacing: 2 wells

If successful, 5-acre down-spacing could add substantial new

reserves and resource potential

UBS Houston Energy Conference – August 10, 2011

East Division

Exploration & Production

UBS Houston Energy Conference – August 10, 2011

East Division

Average Daily Production

Rapid growth in the East

Division as Marcellus is

ramping up

UBS Houston Energy Conference – August 10, 2011

Marcellus Shale

Seneca’s Pennsylvania Acreage

Seneca Resource Acreage Position

745,000 Net Acres in the heart of the

PA Marcellus fairway

Risked Resource Potential: 8-15 TCFE

80% Fee –

Seneca owns the minerals

No lease expiration

94% Average NRI

SRC Lease Acreage

SRC Fee Acreage

UBS Houston Energy Conference – August 10, 2011

Marcellus Shale

Seneca’s Development Areas

SRC Lease Acreage

SRC Fee Acreage

Eastern Development Area

(Mostly Leased)

Western Development Area

(Mostly Fee and HBP)

UBS Houston Energy Conference – August 10, 2011

Marcellus Shale

Eastern Development Area

Covington

Area

–

Full

Development

47 Wells Drilled; 39 Producing Wells

Gross Production: ~120 MMCFD

All planned wells have been drilled

Estimated Gross EUR: 6.7 Bcf per Well

DCNR Block 100

Well

IP:

15.8

MMCFD

1 Rig Drilling

2012: 12 Wells Planned

First Production: Q2 FY12

SRC Lease Acreage

SRC Fee Acreage

DCNR

Block

595

–

Full

Development

6 Wells Drilled; 3 Producing (1 Shut-In)

55 Total Well Locations

2 Rigs Drilling

Tioga/Lycoming/Potter

55,000 Acres

Potential: 2 Tcf

UBS Houston Energy Conference – August 10, 2011

Marcellus Shale

Eastern Development Area Typecurve –

6.7 Bcfe EUR

Segment

IP Rate

5,400 MMcf/d

Hyp. Coeff.

1.25

Decline

65.5%

Limit

6 Mo.

Compression Segment

IP Rate

3,800 MMcf/d

Hyp. Coeff.

1.25

Decline

48%

Exp. Tail

Marcellus Shale

Western Development Area -

Activity

SRC Lease Acreage

SRC Fee Acreage

EOG Contributed JV Acreage

SRC Contributed JV Acreage

Seneca Operated

EOG Operated

Punxy Area –

Full Development

EOG Operated

45 Wells Drilled; 25 Producing

Gross Production (As of 8/2/11): 36 MMCFD

Owl’s Nest Area

Seneca Operated

Development Focus Area

2012: 8 Wells Planned

300-500 Possible Locations

Acquiring 3D Seismic

Approx. Outline of JV Acreage

200,000 Gross Acres

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

Mt. Jewett Area

Seneca Operated

1 Rig Drilling

Boone Mountain Area

Seneca Operated

1 Rig Drilling

UBS Houston Energy Conference – August 10, 2011

UBS Houston Energy Conference – August 10, 2011

Marcellus Shale

Target Zone Example

Marcellus

Interval

Optimal

Target

Zone

Important to

Find Ideal Target

Must account for the

variable rock quality and

geomechanical profile

Major factor in quality of

Fracture Stimulation

Marcellus Shale

Centralized Water System

Recovering water discharged from an

abandoned coal mine which was adversely

impacting a local trout stream

Authorized by SRBC to withdraw

approximately 500,000 gallons per day of

mine discharge

Water pipeline system supplies frac water

for Seneca in Tioga County (90 wells)

Can supply water for 3 fracs per month

System Cost: ~$3.7 Million

Cost Savings: ~$120,000 per well

Pay Out: 31 Wells

Other Benefits:

Improved stream quality

Substantial reduction of water truck

activity

No need to withdraw water elsewhere

UBS Houston Energy Conference – August 10, 2011

UBS Houston Energy Conference – August 10, 2011

Utica Shale

Source rock maturation status based on combined CAI to Ro regression equation. (Trenton-Black River Research Consortium, 2006)

Seneca

Acreage

Seneca Resources

Mt. Jewett Area

Spud Date: April 2011

Seneca Resources

Henderson Area

Planned Spud Date: Aug 2011

Seneca Resources

Tionesta Area

Planned Spud Date: 2012

Utica Shale

Pennsylvania & Ohio

Permitting Activity Since 2009

Vertical Well Permit

Horizontal Well Permit

UBS Houston Energy Conference – August 10, 2011

UBS Houston Energy Conference – August 10, 2011

National Fuel Gas Supply Corporation

Empire Pipeline, Inc.

National Fuel Gas Midstream Corporation

Pipeline & Storage / Midstream

LAMONT

COMPRESSOR

STATION

PHASE I & II

COVINGTON

GATHERING

SYSTEM

TROUT RUN

GATHERING

SYSTEM

WEST TO EAST

OVERBECK TO

LEIDY

TIOGA COUNTY

EXTENSION

LINE “N”

EXPANSION

PIPELINE & STORAGE / MIDSTREAM

EXPANSION INITIATIVES

NORTHERN

ACCESS

EXPANSION

Seneca Drilling Activity

EOG JV Drilling Activity

W2E Overbeck to Leidy

Northern Access Expansion

Expansion Projects

CENTRAL TIOGA

COUNTY

EXTENSION

LINE “N”

2012

EXPANSION

UBS Houston Energy Conference – August 10, 2011

UBS Houston Energy Conference – August 10, 2011

Midstream Corporation

Trout Run Gathering System –

Lycoming County

Capacity: 466,000 Dth/d

Will Interconnect with Transco

Pipelines in Lycoming County

Seneca Resources will be the

anchor shipper

Estimated In-Service: Q2 FY2012

Interstate Pipeline

Gathering System

Transco

UBS Houston Energy Conference – August 10, 2011

National Fuel Gas Company

2012 EPS Guidance & Sensitivity

NFG & Subsidiaries

(1)

The preliminary earnings guidance and sensitivity table are current as of August 4, 2011. The sensitivity table only considers revenue from the Exploration and Production segment’s crude oil and natural gas sales. The

sensitivities will become obsolete with the passage of time, changes in Seneca’s production forecast, changes in basis differentials, as additional hedging contracts are entered into, and with the settling of hedge contracts

at their maturity. For its fiscal 2012 updated earnings forecast, the Company is using flat commodity

pricing of $4.50 per MMBtu for natural gas and $95.00 per Bbl for crude oil, and adjusting for basis differential.

On August 4, 2011, the Company

updated its fiscal 2012 earnings

guidance utilizing flat commodity

pricing of $4.50 per MMBtu for

natural gas and $95.00 per Bbl

for crude oil, and adjusting for

basis differential

Seneca Resources

Preliminary

Production Guidance:

87 to 101 Bcfe

Fiscal 2012

Preliminary Earnings per Share (Diluted) Guidance

(1)

Range

Consolidated Earnings

$2.85 -

$3.15

(1)

Earnings per Share Sensitivity to Changes from

$4.50/MMBtu

for

natural

gas

and

$95.00/Bbl

for

crude

oil

(1)

$1 change per MMBtu gas

$5 change per Bbl oil

Increase

Decrease

Increase

Decrease

+$0.31

-$0.31

+$0.04

-$0.04

UBS Houston Energy Conference – August 10, 2011

National Fuel Gas Company

Seneca Oil and Gas Hedge Positions

For fiscal year 2012,

Seneca has hedged

47% of its forecasted

production

NYMEX

Strip Prices

(at 08/04/11)

Natural

Gas

Oil

Fiscal 2011

(1)

$4.11

$91.49

Fiscal 2012

$4.33

$89.56

Fiscal 2013

$4.85

$93.11

Fiscal 2014

$5.27

$94.33

(1)

The NYMEX strip prices for fiscal year 2011 include the settlement prices for the October 2010 through August 2011 contracts.

Natural Gas

Swaps

Volume

(Bcf)

Average

Hedge Price

Fiscal 2011

10.6

$5.77 / Mcf

Fiscal 2012

35.0

$5.89 / Mcf

Fiscal 2013

23.9

$5.67 / Mcf

Fiscal 2014

4.6

$5.89 / Mcf

Oil Swaps

Volume

(MMBbl)

Average

Hedge Price

Fiscal 2011

0.4

$70.93 / Bbl

Fiscal 2012

1.6

$77.03 / Bbl

Fiscal 2013

0.9

$86.21 / Bbl

Fiscal 2014

0.2

$94.90 / Bbl

National Fuel Gas Company

Key Takeaways

High-Quality Marcellus Acreage Position

745,000 net acres with a resource potential of 8-15 Tcfe

Fee ownership results in superior economics

Rapid Growth: 0 –

150 MMCFD in 24 months

Balanced Business Model

Regulated segments support dividend and are not sensitive to

commodity prices

Sizable oil production provides earnings stability

Strong Financial Position

Simple balance sheet

Well capitalized

Significant internally generated cash flows

UBS Houston Energy Conference – August 10, 2011

UBS Houston Energy Conference – August 10, 2011

Corporate & Financial Highlights

National Fuel Gas Company

UBS Houston Energy Conference – August 10, 2011

UBS Houston Energy Conference – August 10, 2011

National Fuel Gas Company

Dividend Growth

$1.42

$0.19

Compound Annual

Growth Rate

5.0%

National Fuel has had 109 uninterrupted

years of dividend payments and has increased

its dividend for 41

consecutive years

Annual Rate at Fiscal Year End

Utility Segment

National Fuel Gas Distribution Corporation

UBS Houston Energy Conference – August 10, 2011

(1) Calculated using Average Total Comprehensive Shareholder Equity.

Utility

Return on Equity

(1)

UBS Houston Energy Conference – August 10, 2011

National Fuel Gas Supply Corporation

Empire Pipeline, Inc.

National Fuel Gas Midstream Corporation

Pipeline & Storage / Midstream

UBS Houston Energy Conference – August 10, 2011

COVINGTON

GATHERING

SYSTEM

TROUT RUN

GATHERING

SYSTEM

WEST TO EAST

OVERBECK TO

LEIDY

LAMONT

COMPRESSOR

STATION

PHASE I & II

TIOGA COUNTY

EXTENSION

LINE “N”

EXPANSION

PIPELINE & STORAGE / MIDSTREAM

EXPANSION INITIATIVES

NORTHERN

ACCESS

EXPANSION

Seneca Drilling Activity

EOG JV Drilling Activity

W2E Overbeck to Leidy

Northern Access Expansion

Expansion Projects

CENTRAL TIOGA

COUNTY

EXTENSION

LINE “N”

2012

EXPANSION

UBS Houston Energy Conference –

August 10, 2011

Pipeline & Storage/Midstream

Project Name

Capacity

(Dth/D)

Est.

CapEx

In-Service

Date

Market

Status

Covington Gathering System

145,000

$16 MM

11/17/09

Fully Subscribed

Completed

–

Flowing into TGP 300 Line

Lamont Compressor Station

40,000

$6 MM

6/15/10

Fully Subscribed

Completed

–

Flowing

into

TGP

300

Line

Lamont Phase II Project

50,000

$7.6 MM

07/1/11

Fully Subscribed

First 10,000 Dth/d in-service. Remaining

40,000 Dth/d in-service 10/2011.

Line “N”

Expansion

160,000

$20 MM

~ 09/2011

Fully Subscribed

Construction began February 2011

Covington Gathering System

Expansion

75,000

$3.5 MM

~11/2011

Fully Subscribed

Will increase total system capacity to

220,000 Dth/d

Tioga County Extension

350,000

$49 MM

~ 11/2011

Fully Subscribed

Construction began July 2011

Trout Run Gathering System

466,000

$51 MM

Q2 FY2012

70% Subscribed

Preliminary work has begun

Northern Access Expansion

320,000

$62 MM

~11/2012

Fully Subscribed

Certificate filed in March 2011

Line “N”

2012 Expansion

150,000

$36 MM

~ 11/2012

Fully Subscribed

Certificate filed in July 2011

West to East

~425,000

$290 MM

Late 2013/

2014

29% Subscribed

Marketing continues with producers in

various stages of exploratory drilling

Central Tioga County

Extension

260,000

$135 MM

2014

Open Season

Closed

Evaluating market interest and facility design

UBS Houston Energy Conference – August 10, 2011

Expansion Initiatives

Exploration & Production

UBS Houston Energy Conference – August 10, 2011

Seneca Resources Corporation

SRC Lease Acreage

SRC Fee Acreage

SRC Contributed JV Acreage

EOG Contributed JV Acreage

UBS Houston Energy Conference – August 10, 2011

Pennsylvania Acreage Holdings

Marcellus Shale

Marcellus Shale

Eastern Development Area

Western Development Area

Seneca is in active development within the Eastern Development Area. It is currently

testing various well and completion designs in its Western Development Area and

expects to see results continue to improve over time.

Description

EUR

Net

Working

Interest

Net

Revenue

Interest

Well Costs ($ Millions)

$6.0

$6.4

Seneca –

EDA Well

8 Bcf

100%

85%

73%

63%

Seneca –

EDA Well

6 Bcf

100%

85%

40%

34%

Description

EUR

Net

Working

Interest

Net

Revenue

Interest

Well Costs ($ Millions)

$5.0

$6.0

Seneca –

EOG JV Well

4 Bcf

50%

60%

44%

29%

Seneca –

WDA Well

4 Bcf

100%

28%

19%

UBS Houston Energy Conference – August 10, 2011

Pre-Tax IRR Comparison at NYMEX of $4.00/MMBtu

Marcellus Shale

Gross Horizontal Wells Drilled per Year

Marcellus Horizontal Rig Count

Current Rig Count:

Seneca : 5 Rigs

EOG : 2 Rigs

Rig: January 2012

UBS Houston Energy Conference – August 10, 2011

Additional Seneca Rig Scheduled:

National Fuel Gas Company

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.

UBS Houston Energy Conference – August 10, 2011

Comparable GAAP Financial Measure

Slides and Reconciliations

Reconciliation of GAAP Net Income to Income From Continuing Operations

Excluding Items Impacting Comparability

($ Thousands)


										12 Mos. Ended
	FY 2008			FY 2009			FY 2010			6/30/2011
GAAP Net Income
E&P Segment GAAP Net Income	$	146,612		$	(10,238	)	$	112,531		$	120,941
P&S Segment GAAP Net Income		54,148			47,358			36,703			30,703
Utility Segment GAAP Net Income		61,472			58,664			62,473			62,617
Marketing Segment GAAP Net Income		5,889			7,166			8,816			9,466
Corporate & All Other GAAP Net Income		607			(2,242	)		5,390			35,720

Total GAAP Net Income	$	268,728		$	100,708		$	225,913		$	259,447

Discontinued Operations
(Income) Loss from Operations, Net of Tax (Corporate & All Other)	$	(1,821	)	$	2,776		$	(470	)	$	301
Gain on Disposal, Net of Tax (Corporate & All Other)		—			—			(6,310	)		(6,310	)

(Income) Loss from Discontinued Operations, Net of Tax	$	(1,821	)	$	2,776		$	(6,780	)	$	(6,009	)

Items Impacting Comparability
Gain on sale of turbine (Corporate & All Other)	$	(586	)	$	—		$	—		$	—
Gain on life insurance policies (Corporate & All Other)		—			(2,312	)		—			—
Gain on sale of unconsolidated subsidiaries (Corporate & All Other)		—			—			—			(31,418	)
Impairment of investment partnership (Corporate & All Other)		—			1,085			—			—
Impairment of oil and gas properties (E&P)		—			108,207			—			—

Total Items Impacting Comparability	$	(586	)	$	106,980		$	—		$	(31,418	)

Income from Continuing Operations excluding Items Impacting Comparability
E&P Segment Operating Income	$	146,612		$	97,969		$	112,531		$	120,941
P&S Segment Operating Income		54,148			47,358			36,703			30,703
Utility Segment Operating Income		61,472			58,664			62,473			62,617
Marketing Segment Operating Income		5,889			7,166			8,816			9,466
Corporate & All Other Operating Income		(1,800	)		(693	)		(1,390	)		(1,707	)

Total Income from Continuing Operations excluding Items Impacting Comparability	$	266,321		$	210,464		$	219,133		$	222,020

Reconciliation of Segment Capital Expenditures to

Consolidated Capital Expenditures

($ Thousands)


												FY 2011		FY 2012
	FY 2007		FY 2008			FY 2009			FY 2010			Forecast		Forecast
Capital Expenditures from Continuing Operations
Exploration & Production Capital Expenditures	$	146,687	$	192,187		$	188,290		$	398,174		$	600,000-655,000	$	785,000-875,000
Pipeline & Storage Capital Expenditures		43,226		165,520			52,504			37,894		$	100,000-150,000	$	100,000-135,000
Utility Capital Expenditures		54,185		57,457			56,178			57,973		$	55,000-60,000	$	55,000-60,000
Marketing, Corporate & All Other Capital Expenditures		3,414		1,614			9,829			7,311		$	15,000-20,000	$	30,000-40,000

Total Capital Expenditures from Continuing Operations	$	247,512	$	416,778		$	306,801		$	501,352		$	770,000-885,000	$	970,000-1,110,000

Capital Expenditures from Discountinued Operations
Exploration & Production Capital Expenditures	$	29,129	$	—		$	—		$	—		$	—	$	—
All Other Capital Expenditures		87		131			216			150

Total Capital Expenditures from Discontinued Operations	$	29,216	$	131		$	216		$	150		$	—	$	—

Plus (Minus) Accrued Capital Expenditures
Exploration & Production FY 2010 Accrued Capital Expenditures	$	—	$	—		$	—		$	(55,546	)	$	—	$	—
Exploration & Production FY 2009 Accrued Capital Expenditures		—		—			(9,093	)		9,093			—		—
Pipeline & Storage FY 2008 Accrued Capital Expenditures		—		(16,768	)		16,768			—			—		—
All Other FY 2009 Accrued Capital Expenditures		—		—			(715	)		715			—		—

Total Accrued Capital Expenditures	$	—	$	(16,768	)	$	6,960		$	(45,738	)	$	—	$	—

Elimintations	$	—	$	(2,407	)	$	(344	)	$	—		$	—	$	—

Total Capital Expenditures per Statement of Cash Flows	$	276,728	$	397,734		$	313,633		$	455,764		$	770,000-885,000	$	970,000-1,110,000