 UBS Houston
Energy Conference
August 10, 2011
Exhibit 99 |
 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: 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.
|
 3
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
3
UBS Houston Energy Conference – August 10, 2011
|
 4
UBS Houston Energy Conference – August 10, 2011
|
 5
UBS Houston Energy Conference – August 10, 2011
|
 6
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%
7
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
$0
$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
$55-60
Fiscal Year
Forecast
Forecast
Utility
Pipeline & Storage
Exploration & Production
All Other
UBS Houston Energy Conference – August 10, 2011
8 |
 National Fuel Gas
Company Capital Structure
$2.900 Billion
(1)
at June 30, 2011
Forecasted Capital
Structure
(2)
at September 30, 2011
9
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
|
 10
10
UBS Houston Energy Conference – August 10, 2011
Exploration & Production
Seneca Resources Corporation |
 11
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
0
200
400
600
2008
2009
2010
At September 30
Natural Gas
46.2
46.6
45.2
0
20
40
60
2008
2009
2010
At September 30
Oil |
 12
Exploration & Production
Historical Daily Production
50
100
150
200
250
West
Upper Devonian
Gulf
Marcellus
-
UBS Houston Energy Conference – August 10, 2011
|
 13
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
14
Exploration & Production
Annual Production by Region
Marcellus production in
Fiscal 2012 could equal
the entire company
production in Fiscal 2011 |
 15
15
UBS Houston Energy Conference – August 10, 2011
Exploration & Production
California |
 16
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 |
 17
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 |
 18
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 |
 19
19
UBS Houston Energy Conference – August 10, 2011
East Division
Exploration & Production |
 20
UBS Houston Energy Conference – August 10, 2011
East Division
Average Daily Production
Rapid growth in the East
Division as Marcellus is
ramping up |
 21
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 |
 22
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) |
 23
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
1
st
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 |
 24
UBS Houston Energy Conference – August 10, 2011
Marcellus Shale
Eastern Development Area Typecurve –
6.7 Bcfe EUR
1
st
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
6% |
 25
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
|
 26
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 |
 27
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
|
   28
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 |
 29
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
|
 30
30
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
31
CENTRAL TIOGA
COUNTY
EXTENSION
LINE “N”
2012
EXPANSION
UBS Houston Energy Conference – August 10, 2011
|
 32
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 |
 33
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 |
 34
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 |
 35
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
|
 36
36
UBS Houston Energy Conference – August 10, 2011
|
 37
37
Corporate & Financial Highlights
National Fuel Gas Company
UBS Houston Energy Conference – August 10, 2011
|
 38
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
39
UBS Houston Energy Conference – August 10, 2011 |
 (1)
Calculated using Average Total Comprehensive Shareholder Equity. 40
Utility
Return on Equity
(1)
UBS Houston Energy Conference – August 10, 2011 |
 41
41
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
42
CENTRAL TIOGA
COUNTY
EXTENSION
LINE “N”
2012
EXPANSION
UBS Houston Energy Conference –
August 10, 2011 |
 43
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
$135 MM
2014
Open Season
Closed
Evaluating market interest and facility design
UBS Houston Energy Conference – August 10, 2011
Expansion Initiatives |
 Exploration &
Production UBS Houston Energy Conference – August 10, 2011 44
Seneca Resources Corporation |
 SRC Lease
Acreage SRC Fee Acreage
SRC Contributed JV Acreage
EOG Contributed JV Acreage
UBS Houston Energy Conference – August 10, 2011
45
Pennsylvania Acreage Holdings
Marcellus Shale |
 46
Marcellus Shale
Eastern Development Area
Western Development Area
Seneca is in active development within the Eastern Development Area. It is currently
testing various well and completion designs in its Western Development Area and
expects to see results continue to improve over time.
Description
EUR
Net
Working
Interest
Net
Revenue
Interest
Well Costs ($ 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%
100%
28%
19%
UBS Houston Energy Conference – August 10, 2011
Pre-Tax IRR Comparison at NYMEX of $4.00/MMBtu |
 47
Marcellus Shale
Gross Horizontal Wells Drilled per Year
Marcellus Horizontal Rig Count
Current Rig Count:
Seneca : 5 Rigs
EOG : 2 Rigs
6
th
Rig: January 2012
UBS Houston Energy Conference – August 10, 2011
Additional Seneca Rig Scheduled: |
 48
National Fuel Gas Company
This presentation contains certain non-GAAP financial measures. For pages
that contain non-GAAP financial measures, pages containing the most directly
comparable GAAP financial measures and reconciliations are provided in the
slides that follow.
The Company believes that its non-GAAP financial measures are useful to
investors because they provide an alternative method for assessing the
Company’s operating results in a manner that is focused on the performance
of the Company’s ongoing operations. The Company’s management uses
these non-GAAP financial measures for the same purpose, and for planning
and forecasting purposes. The presentation of non-GAAP financial measures
is not meant to be a substitute for financial measures prepared in accordance
with GAAP.
UBS Houston Energy Conference – August 10, 2011
Comparable GAAP Financial Measure
Slides and Reconciliations |
Reconciliation of GAAP Net Income to Income From Continuing Operations
Excluding Items Impacting Comparability
($ 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 | ) | ||||||||||
|
|
|
|
|
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| (Income) Loss from Discontinued Operations, Net of Tax |
$ | (1,821 | ) | $ | 2,776 | $ | (6,780 | ) | $ | (6,009 | ) | |||||
| Items Impacting Comparability |
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| 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 | — | — | ||||||||||||
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| Total Items Impacting Comparability |
$ | (586 | ) | $ | 106,980 | $ | — | $ | (31,418 | ) | ||||||
| Income from Continuing Operations excluding Items Impacting Comparability |
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| 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 | ) | ||||||||
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| Total Income from Continuing Operations excluding Items Impacting Comparability |
$ | 266,321 | $ | 210,464 | $ | 219,133 | $ | 222,020 | ||||||||
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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 |
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| 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 | ||||||||||||||||
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| 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 |
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| Exploration & Production Capital Expenditures |
$ | 29,129 | $ | — | $ | — | $ | — | $ | — | $ | — | ||||||||||||
| All Other Capital Expenditures |
87 | 131 | 216 | 150 | ||||||||||||||||||||
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| Total Capital Expenditures from Discontinued Operations |
$ | 29,216 | $ | 131 | $ | 216 | $ | 150 | $ | — | $ | — | ||||||||||||
| Plus (Minus) Accrued Capital Expenditures |
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| 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 | — | — | |||||||||||||||||
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| Total Accrued Capital Expenditures |
$ | — | $ | (16,768 | ) | $ | 6,960 | $ | (45,738 | ) | $ | — | $ | — | ||||||||||
| Elimintations |
$ | — | $ | (2,407 | ) | $ | (344 | ) | $ | — | $ | — | $ | — | ||||||||||
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| 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 | ||||||||||||
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