 National Fuel Gas Company
Investor Presentation
May 2013
Exhibit 99 |
 National Fuel Gas
Company 2
Safe Harbor For Forward Looking Statements
May 2013
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 Forms 10-Q for
the periods ended December 31, 2012 and March 31, 2013. 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. |
 National Fuel Gas
Company 3
Our Business Mix Leads to Long-Term Value Creation
Upstream
Crude Oil
Midstream
Downstream
National Fuel Gas
Supply Corporation
Empire Pipeline, Inc.
National Fuel Gas
Midstream Corporation
National Fuel Gas
Distribution
Corporation
National Fuel
Resources, Inc.
The strategic, operational and financial benefits, along with capital
flexibility and consistent growth opportunities generated by this
integrated mix of businesses continues to create significant
long-term value for the Company’s shareholders in nearly all
economic and commodity price scenarios
Upstream
Natural Gas
Seneca Resources
Corporation
(West Division)
Seneca Resources
Corporation
(East Division)
May 2013 |
 National Fuel Gas
Company 4
Integrated Businesses with Significant Marcellus Exposure…
May 2013 |
 National Fuel Gas
Company 5
…And Exposure to Growth from the Utica Shale
May 2013 |
 National Fuel Gas
Company 6
EBITDA Growth Driven by Stability and Continued Success
$164
28%
$167
26%
$169
25%
$160
23%
$171
22%
$131
23%
$121
19%
$
111
17%
$137
19%
$153
20%
$280
48%
$327
52%
$377
57%
$397
56%
$427
56%
$581
$632
$668
$704
$768
$0
$250
$500
$750
$1,000
2009
2010
2011
2012
12 Months Ended
3/31/2013
Fiscal Year
Utility Segment
Exploration & Production Segment
Midstream, Energy Marketing & Other
Pipeline & Storage Segment
May 2013
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.
|
 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 $56
$58
$58
$58
$65-$70
$65-$70
$53
$38
$129
$144
$70-$90
$80-$100
$81
$50-$75
$75-$125
$188
$398
$649
$694
$525-
$585
$550-
$650
$307
(1)
$501
$854
$977
$710-$820
$770-$945
$0
$250
$500
$750
$1,000
$1,250
2009
2010
2011
2012
2013 Forecast
2014 Forecast
Fiscal Year
Utility Segment
Exploration & Production Segment
Midstream, Energy Marketing & Other
Pipeline & Storage Segment
May 2013 |
 Total Debt
(1)
45%
National Fuel Gas Company
8
Strong Balance Sheet and Liquidity Position
$3.691 Billion
As of March 31, 2013
Note: A reconciliation of Adjusted EBITDA to Net Income is included at the end of this
presentation (1)
Long-Term Debt of $1.649 billion
Debt / Adjusted EBITDA
Capitalization
The Company has a total short-term debt capacity of
$1.085 billion of which all remains available
Fiscal Year
May 2013
Shareholders’
Equity
55 %
2009
2010
2011
2012
12-Months
Ended
3/31/13
0.0
0.5
1.0
1.5
2.0
2.5
2.02
1.98
1.75
1.89
2.00 |
 National Fuel Gas
Company 9
Forecasted Cash Flow Position for Fiscal Year 2013
Fiscal 2013 Cash from
Operations will likely
equal or exceed Capital
Expenditures
$775
$ 495
$765
$123
$421
$0
$500
$1,000
$1,500
Debt Repayment
Dividend
CapEx
Cash on Hand
New Financing
Asset Sales & Other
May 2013
Cash from Ops |
 National Fuel Gas
Company 10
Dividend Track Record
Current
Dividend Yield
(1)
2.3%
Dividend Consistency
Consecutive Dividend Payments
110 Years
Consecutive Dividend Increases
42 Years
Current Annualized Dividend Rate
$1.46 per Share
(1) As of April 30, 2013
$0.00
$0.50
$1.00
$1.50
$2.00
Annual Rate at Fiscal Year End
May 2013 |
 May 2013
Exploration & Production
11 |
 May 2013
Seneca Resources
12
Efficiently Deploying Capital Towards the Best Opportunities
$31
$28
$47
$63
$80-$110
$90-$130
$139
$356
$596
$631
$445-
$475
$460-
$520
$188
(1)
$398
$649
$694
$525-$585
$550-$650
$0
$250
$500
$750
$1,000
2009
2010
2011
2012
2013 Forecast
2014 Forecast
Fiscal Year
Gulf of Mexico (Divested in 2011)
East Division (Appalachia)
West Division (California/Kansas)
(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 2013
Seneca Resources
13
Production Continues to Grow
20.1
19.8
19.2
20.5
20-22
21-23
8.7
16.5
43.2
62.9
90-96
111–119
13.7
13.3
5.2
42.5
49.6
67.6
83.4
110
-
118
132-142
0
25
50
75
100
125
150
2009
2010
2011
2012
2013 Forecast
2014 Forecast
Fiscal Year
Gulf of Mexico (Divested in 2011)
East Division (Appalachia)
West Division (California/Kansas) |
 May 2013
Seneca Resources
14
Continuing to Focus on Improving Its Cost Structure
Even after the new Pennsylvania Impact
Fee, 2012 unit cash costs decreased
from the prior year. We expect this
trend to continue in Fiscal 2013.
(1)
Represents the midpoint of current General & Administrative Expense guidance of $60 to
$62 million, divided by the midpoint of current production guidance of 110 to 118
Bcfe (2)
Represents the midpoint of current Lease Operating Expense Guidance of $0.95 to $1.05 per
Mcfe $1.36
$1.27
$1.24
$1.08
$1.00
$1.00
(2)
$0.60
$0.69
$0.64
$0.73
$0.65
$0.54
(1)
$2.57
$2.42
$2.22
$2.09
$2.01
$1.82
$0.00
$1.50
$3.00
$4.50
2008
2009
2010
2011
2012
2013 Forecast
Fiscal Year
Property, Franchise & Other Taxes
Other O&M Expense
General & Administrative Expense
Lease Operating Expense |
 May 2013
Seneca Resources
15
California: Stable Production and Increasing Cash Flows
Net Acreage: 18,418 Acres
Net Wells: 1,478
Oil Gravity: 12 –
37°
Api
NRI: 87.64
Rank
Company
California
2012
BOEPD
(1)
1
Occidental
187,376
2
Chevron
160,611
3
Aera (Shell/Exxon)
143,983
4
Plains Exploration
36,365
5
Berry Petroleum
19,589
6
Macpherson Oil
10,416
7
Seneca Resources
10,154
8
Venoco Inc
6,113
9
E&B Natural Resources
6,042
10
ExxonMobil
3,664
(1)
Gross operated production (Source: California Division of Oil, Gas, & Geothermal
Resources) |
 May 2013
Seneca Resources
16
California: Stable Production Fields
South Lost Hills
~1,500 BOEPD
Monterey Shale
Primary
219 Active Wells
Sespe
~1,100 BOEPD
Sespe Formation
Primary
172 Active Wells
North Lost Hills
~1,100 BOEPD
Tulare & Etchegoin Formation
Primary & Steamflood
175 Active Wells
North Midway Sunset
~4,100 BOEPD
Potter & Tulare Formation
Steamflood
728 Active Wells
South Midway Sunset
~1,200 BOEPD
Antelope Formation
Steamflood
110 Active Wells
East Coalinga
~100 BOEPD
Temblor Formation
Primary |
 May 2013
Seneca Resources
17
California: Strong Margins Support Significant Free Cash Flow
Average Revenue
(12 Months Ended 3/31/13)
$85.90 per BOE
$9.78
$3.35
$3.44
$2.28
$1.20
$65.85
Non-Steam Fuel LOE
Steam Fuel
G&A
Production & Other Taxes
Other Operating Costs
Adjusted EBITDA
Adjusted EBITDA per BOE
(1)
(12 Months Ended March 31, 2013)
(1) Total production from the Exploration & Production segment’s properties in
California was 3,323 Mboe for the 12 months ended March 31, 2013.
Note: A reconciliation of Exploration & Production West Division Adjusted EBITDA to
Exploration & Production Segment Net Income is included at the end of this
presentation.
|
 May 2013
California: Midway Sunset South Activity Update
Seneca Resources
?
500’
2012 Drill Program: 21 Wells / 3 Injectors
2013 Drill Program: 23 Wells / 5 Injectors
2014 Drill Program: 23 Wells / 4 Injectors
0 ft
50 ft
100 ft
100 ft
50 ft
50 ft
Antelope “A-1”
and “A-2”
Sands
Antelope “B”
and “C”
Sands
Antelope “A-1”
Sand
Seneca 232M
Extended 252 Pool to the West
Seneca 252I
Extended 252 Pool to the East
Seneca 222W
Extended S Ext Pool to the East
Seneca 251U
Extended 251 Pool to the West
100 ft
50 ft
100 ft
50 ft
0 ft
50 ft
0 ft
0 ft
0 ft
0 ft
18
2012 Drill Program
2013 Drilling Locations
Producers
Injectors
Producers
Injectors |
 19
WS 48-33
IP: 80 BOEPD
1
Oil
09/12
“X”
SANDS ISOCHORE (Thickness)
Seneca Resources
California:
Sespe
Field
–
Drilling
Programs
and
Results
1 Mile
Oak Flat 1-31
IP: 110 BOEPD
1
Oil 08/12
FA 502-33
IP: 75 BOEPD
1
Oil 1/13
FA 501-33
IP: 100 BOEPD
1
Oil 1/13
Oak Flat 2-31
IP: 100 BOEPD
1
Oil 08/12
TG 562-29
IP: 190 BOEPD
1
Oil 2/13
TG 53-29
IP: 90 BOEPD
1
Oil 3/13
2011 Sespe Wells (5)
2012 Sespe Wells (6)
2013 Sespe Wells (6)
2014 Sespe Wells (4)
May 2013
st
st
st
st
st
st
st |
 May 2013
Seneca Resources
20
California: East Coalinga Overview
Seneca became operator on January 30, 2013
Previous Operator: Chevron
7,764 net acres
~170 wells (60 active)
~350 BOPD (Up from 230 BOPD on 1/30/13)
$30 million capital commitment over first
three years
$100 million of potential opportunities over
the next five to seven years
2013 Plans
Drill ~12 evaluation wells across acreage
block
Place ~50% of currently idled wells back on
production
Have put 20 on since 1/30/13
Upgrade surface facilities
Active Well
Idle Well |
 May 2013
Seneca Resources
21
California: Recent Initiatives Driving Near-Term Growth
Forecast
Key Areas of Focus in 2013
1.
South Midway Sunset Field Extensions
2.
Sespe Infill Drill Program
3.
East Coalinga Evaluation
6,500
7,000
7,500
8,000
8,500
9,000
9,500
10,000
6,000 |
 May 2013
Seneca Resources
22
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:
~720,000 acres
Own most mineral rights
Minimal
royalty obligation
Minimal
lease expiration
Evaluating rich-gas potential and
initiating dry gas development
NFG Storage Acreage |
 May 2013
Seneca Resources
23
Eastern Development Area (EDA)
DCNR Tract 595
Gross Production: ~80 MMcf per Day
34 Wells Drilled
26 Wells Producing
Covington –
Fully Developed
Gross Production: ~60 MMcf per Day
47 Wells Drilled and Producing
DCNR Tract 100
Gross Production: ~155 MMcf per Day
33 Wells Drilled
21 Wells Producing
SRC Lease Acreage
SRC Fee Acreage |
 May 2013
Seneca Resources
24
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
5.7
4,023’
1.42
Tract 595
Tioga
County
26
7.1
6.0
5.1
8.0
4,629’
1.73
Tract 100
Lycoming
County
21
15.2
13.3
10.3
11.0
5,137’
2.14 |
 May 2013
Seneca Resources
25
Western Development Area Marcellus Delineation Program
Owl’s Nest
2 Wells Drilled
3D Seismic Coverage Complete
Church Run
1 Well Drilled
Ridgway
1 Well Drilled
Rich Valley (1 Well)
Peak 7-Day IP: 7.8 MMcf per Day
30-Day Rate: 6.7 MMcf per Day
Estimated EUR: 7 Bcf
BTU
Contours
Clermont
Two Wells Drilled
Tionesta
1 Well Planned
SRC Lease Acreage
SRC Fee Acreage
Horizontal Well |
 May 2013
Seneca Resources
26
Rich Valley/Clermont Marcellus Development Area
Rich Valley/Clermont Development Area
Area of high porosity and GIP
150-200 Horizontal Locations
Anticipated EURs: 5-8 Bcf
WDA Pilot Development Program
Upon completion of initial delineation
drilling, a pilot development program
will begin this summer.
Full development planned for 2014.
SRC Lease Acreage
SRC Fee Acreage
Delineation Well |
 May 2013
Marcellus Shale
27
Clermont / Rich Valley Pilot Development Project
Clermont
Rich Valley
Rich Valley 27H
7-day IP: 7.8 MMcf/d
30-day IP: 6.7 MMcf/d
Pad A: 2 Wells
Production: Q4 FY13
Pad N: 3 Wells
Production: Q3/Q4 FY14
Rich Valley 2
Well
Production: Q1/Q2 FY14
Marcellus Faults
Marcellus & Basement Faults
Pad E: 3 Wells
Production: Q3/Q4 FY14
nd |
 May 2013
Seneca Resources
28
Rich Valley 27H Type Curve
Lateral Length: 6,300’
Completion Stages: 42 (Reduced Cluster Spacing)
0.0
2.0
4.0
6.0
8.0
10.0
0
2
4
6
8
10
12
Months
Rich Valley 27H
7 Bcf Typecurve |
 May 2013
Seneca Resources
29
Ongoing Production Growth in the East Division
Forecast
0
50
100
150
200
250
300
Tract 100 (Lycoming)
Tract 595 (Tioga)
Covington (Tioga)
WDA/Other
EOG JV
Shallow Devonian (Historical Production) |
 May 2013
Seneca Resources
30
Utica Shale –
Activity Summary
Permitted
Drilled/Drilling
Completed
Producing
Range Resources
1.4 MMcfd
“Not Effectively Stimulated”
Mt. Jewett
Tested 3 Frac Stages at 1.6 MMcfd
(Typical Well: 17 Frac Stages)
2
nd
Horizontal: Moving in Rig
Rex
9.2 MMcfd
Henderson
Vertical Well: Tested
Tionesta
Horizontal: Completed Fall 2012
Peak 24-Hour Rate: 3.9 MMcfd
Range Resources
4.4 MMcfd
Chesapeake
6.4 MMcfd |
 May 2013
Seneca Resources
31
Initial Entry into the Mississippian Lime Play in Kansas
Total Net Acres: 9,300
Unit
30-day IP:
352 BOED
(92% Oil/NGLs)
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 |
 Midstream
Businesses 32
Pipeline & Storage/NFG Midstream
May 2013 |
 May 2013
Midstream Businesses
33
Pipeline Expansions to Transport Appalachian Production
Line N
Corridor
Expansions
Gathering
Marcellus
Production
Shipping Gas
to Canada &
Northeast |
 May 2013
Midstream Businesses
34
A Closer Look at the Expansion Progress
LINE “N”
2013
EXPANSION
(Nov. 2013)
LINE “N”
EXPANSION
(In-Service)
MERCER
EXPANSION
PROJECT
(Nov. 2014)
WEST SIDE
EXPANSION
(2015)
LINE “N”
2012
EXPANSION
(In-Service)
TIONESTA
GATHERING
SYSTEM
(In-Service)
NORTHERN ACCESS
EXPANSION
(In-Service)
TIOGA COUNTY
EXTENSION
(In-Service)
CENTRAL TIOGA
COUNTY EXTENSION
(2015/2016)
COVINGTON
GATHERING
SYSTEM
(In-Service)
TROUT RUN
GATHERING SYSTEM
(In-Service)
MT. JEWETT
GATHERING SYSTEM
(Under
Construction) |
    May 2013
Midstream Businesses
35
Pursuing Additional Opportunities Near the Line N Corridor
Activity in the Marcellus and Utica shales
along the Pennsylvania/Ohio border
continues to remain robust
NFG Supply Corporation’s Line N system is
well-positioned for continued expansion
NFG Midstream Corporation is focused on
building new high-pressure wet and dry gas
gathering systems
Significant expansion opportunities may be
present in the next few years
2013:
Smaller pipeline expansions
2014+:
Larger expansion projects, possibly
including an integrated wet gas solution,
with NFG Midstream focused on the high-
pressure wet gas gathering systems and
NFG Supply transporting dry gas on its
interstate system
Line N
Focus Area |
 May 2013
Midstream Businesses
36
NFG Midstream is Focused on Serving Appalachian Producers
Midstream’s gathering systems are
critical to unlock remote, but highly
productive Marcellus acreage
History of operational success and
efficiency within Pennsylvania
Current focus is on developing and
expanding gathering infrastructure
for both Seneca and other producers
in the Appalachian Basin |
 May 2013
Utility
37 |
 May 2013
Total Customers: 520,000
Rate Mechanisms:
Revenue Decoupling
Weather Normalization
Low Income Rates
Choice Program/Purchase of
Merchant Function Charge
90/10 Sharing (Large Customers)
Natural Gas Vehicle Pilot Program
Allowed ROE: 9.1%
Utility
38
New York Service Territory
(Uncollectibles Adjustment)
Return on Equity
Fiscal Year
Receivables (POR) |
 May 2013
Utility
39
New York -
Earnings Sharing Proposal and Show Cause Order
March 27, 2013
Filed a plan with the NY PSC
to adopt an earnings
sharing and stabilization
mechanism on earnings
above a 9.96% ROE
April 19, 2013
NY PSC issued an Order
to Show Cause (OTSC)
commencing a
proceeding to establish
“temporary rates”
June 1, 2013
OTSC suggests
“temporary rates”
could
become effective
May 8, 2013
Company responds to
OTSC
Further proceedings
would follow to establish
permanent rates
Most recent NY PSC multi-
year plan include:
ROE: 9.4%
Equity Ratio: 48%
National Fuel continues to
maintain a dialogue with
regulators and is
responding to the OTSC |
 May 2013
Utility
40
Pennsylvania Service Territory
Total Customers: 213,000
Rate Mechanisms:
Low Income Rates
Choice Program/Purchase of
Merchant Function Charge
Allowed ROE: N/A
(1)
(1)
Black Box Settlement
Return on Equity
Fiscal Year
Receivables (POR) |
 May 2013
Utility
41
Consistently Delivering Excellent Customer Service
National
Fuel
has
ranked
2
nd
among
Gas
Utilities
in
the
East Region for business customer service in each of the
past three years and continues to focus on safety,
corporate citizenship and quality customer service
Study Year
(March)
Customer Satisfaction
Study Rank
2013
#2
2012
#2
2011
#2
and $50,000 monthly on natural gas.
Source: J.D. Power and Associates Gas Utility Business Customer Satisfaction Study for the
years 2009-2013 - businesses that spend between $200 |
 May 2013
Utility
42
Lower Natural Gas Prices Led to Increased Normalized Usage
Residential
Industrial
(1)
Weighted Average of New York and Pennsylvania service territories (assumes normal
weather) Industrial load increasing
slightly for Fiscal Year 2013
Twelve Months Ended March 31
Twelve Months Ended March 31
102.3
98.5
97.8
101.5
100.8
26,410
24,227
25,838
25,290
27,886 |
 Utility
43
Continued Cost Control Helps Provide Earnings Stability
Low natural gas prices,
combined with a focus on
cost control, continue to
help reduce expenses
$178
$164
$167
$168
$168
$168
$25
$27
$14
$11
$9
$7
$203
$191
$181
$179
$177
$175
$0
$50
$100
$150
$200
$250
2008
2009
2010
2011
2012
12 Months
Ended 03/31/13
Fiscal Year
All Other O&M Expenses
O&M Uncollectible Expense
May 2013 |
 Utility
44
Strong Commitment to Safety
The anticipated increase in 2013
capital expenditures is largely due
to the implementation of a new
Customer Information System
The Utility remains
focused on consistent
spending to maintain
the ongoing safety and
reliability of its system
$45.1
$44.4
$45.0
$44.3
$43.8
$57.5
$56.2
$58.0
$58.4
$58.3
$65-$70
$0
$20
$40
$60
$80
2008
2009
2010
2011
2012
2013
Forecast
Fiscal Year
Capital Expenditures for Safety
Total Capital Expenditures
May 2013 |
 National Fuel Gas
Company 45
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.
May 2013
136% Increase in Proved Reserves Since 2009
Total oil and gas proved reserves reached 1,246 Bcfe at September 30, 2012, with a 3-year
average F&D cost of $1.87/Mcfe
96% Production Growth Since 2009
Despite
the
2011
sale
of
its
offshore
Gulf
of
Mexico
properties,
Seneca
has
increased
production from 42.5 Bcfe in 2009 to 83.4 Bcfe in 2012
37% Increase in Pipeline & Storage Adjusted EBITDA since Fiscal 2011
As a result of major Appalachian pipeline expansions, Adjusted EBITDA reached $153 million
for the last 12 months and new projects will continue to drive growth beyond fiscal
2013 44.3 Bcfe in 2012 NFG Midstream Gathering Volumes
NFG Midstream gathered more than 44 Bcfe of volumes for Seneca Resources, eliminating
the need to rely upon and provide payment to third party infrastructure operators
|
 National Fuel Gas
Company 46
Appendix
May 2013 |
 National Fuel Gas
Company 47
Fiscal Year 2013 Earnings Guidance Drivers
2013 Forecast
GAAP Earnings per Share
$2.95 -
$3.10
Exploration & Production Drivers
Total Production (Bcfe)
110 -
118
DD&A Expense (per Mcfe)
$2.05 -
$2.15
LOE Expense (per Mcfe)
$0.95 -
$1.05
G&A Expense
$60 -
$62 MM
Pipeline & Storage Drivers
O&M Expense
+3%
Revenue
$260 -
$265 MM
Utility Drivers
O&M Expense
+3%
Normal Weather in PA
Energy Marketing Drivers
Operating Income
$5 -
$10 MM
May 2013 |
 May 2013
National Fuel Gas Company
48
No Debt Maturities Until Fiscal 2018
Embedded Cost of
Long-Term Debt
5.58%
In February, the Company
Issued $500 million in
10-year notes at 3.75% |
 Midstream
Businesses 49
Appendix
May 2013 |
 May 2013
Midstream Businesses
50
Regulated Interstate Expansion Initiatives (Pipeline & Storage)
Project Name
Capacity
(Dth/D)
Est.
CapEx
In-Service
Market
Status
Lamont Compressor Station
90,000
$14 MM
2010/2011
Fully Subscribed
Completed –
Two Phases
Line “N”
Expansion
160,000
$22 MM
10/2011
Fully Subscribed
Completed
Tioga County Extension
350,000
$58 MM
11/2011
Fully Subscribed
Completed
Northern Access Expansion
320,000
$77 MM
11/2012
Fully Subscribed
Completed
Line “N”
2012 Expansion
163,000
$40 MM
11/2012
Fully Subscribed
Completed
Line “N”
2013 Expansion
30,000
~$5 MM
11/2013
Fully Subscribed
Executed Precedent Agreement
Mercer Expansion Project
105,000
~$30 MM
11/2014
Fully Subscribed
Executed Precedent Agreement
West Side Expansion
95,000+
~$65 MM
2015
OS Concluded
Negotiating Precedent Agreements
Central Tioga County
Extension
260,000
~$150 MM
2015/2016
OS Concluded
Discussions with anchor shipper
West to East
~425,000
~$290 MM
~2016
29% Subscribed
Marketing continues with producers in
various stages of exploratory drilling
Total Firm Capacity: ~1,998,000+ Dth/D
Capital Investment: ~$751 MM |
 May 2013
Midstream Businesses
51
Gathering Expansion Initiatives (NFG Midstream)
Project Name
Capacity
(Mcf/D)
Est.
CapEx
In-Service
Date
Market
Comments
Covington Gathering System
220,000
$40 MM
Multiple
Phases -
Most
In-Service
Capacity Available
[Marketing to
Third Parties]
Completed
–
Flowing
into
TGP
300
Line. This includes ~$10 million of
current and future spending to
build pipeline to connect additional
wells
Trout Run Gathering System
466,000
$185 MM
May 2012
Capacity Available
[Marketing to
Third Parties]
Completed
–
Flowing
into
Transco
Leidy Line. This includes ~$90
million of current and future
spending to build compression and
pipeline to connect additional wells
Tionesta Gathering System
10,000
$2.1 MM
April 2012
Fully Subscribed
Completed
–
Flowing
into
TGP
300
Line.
Mt. Jewett Gathering System
10,000
$3.9 MM
FY2013
Q3
Fully Subscribed
Under Construction
Total Firm Capacity: ~706,000 Mcf/D
Capital Investment: ~$231 MM |
 Exploration &
Production 52
Appendix
May 2013 |
 May 2013
Seneca Resources
53
Another Strong Year of Reserve Growth
Fiscal
Years
3-Year
F&D Cost
(1)
($/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
|
 May 2013
Seneca Resources
54
Hedge Positions and Strategy
Natural Gas
Swaps
Volume
(Bcf)
Average
Hedge Price
Fiscal 2013
38.7
$4.49 / Mcf
Fiscal 2014
62.7
$4.28 / Mcf
Fiscal 2015
39.7
$4.27 / Mcf
Fiscal 2016
37.3
$4.35 / Mcf
Fiscal 2017
23.0
$4.19 / Mcf
Oil Swaps
Volume
(MMBbl)
Average
Hedge Price
Fiscal 2013
0.9
$94.92 / Bbl
Fiscal 2014
1.6
$100.26 / Bbl
Fiscal 2015
0.6
$93.66 / Bbl
Fiscal 2016
0.4
$88.39 / Bbl
Most hedges executed at sales point to eliminate basis risk
Seneca has hedged approximately 73% of its
forecasted production for Fiscal 2013
Note: Fiscal 2013 hedge positions are for the remaining six months of the fiscal year
|
 May 2013
Seneca Resources
55
Operational Efficiencies Continue to Drive Production Growth
Ongoing efficiency allows for more activity with a flat rig count
(1)
RCS – Reduced Cluster
Spacing (2) Drilling pace represents the average feet drilled per day from
the time the well is spud until it reaches total depth (TD) |
 May 2013
Marcellus Shale
56
Targeting Continued Cost Reductions
(1) Completion Cost per Stage is for horizontal wells completed utilizing a standard
completion design, not a Reduced Cluster Spacing (RCS) completion design. |
 May 2013
National Fuel Gas Company
57
Comparable GAAP Financial Measure Slides and Reconciliations
This presentation contains certain non-GAAP financial measures. For pages
that contain non-GAAP financial measures, pages containing the most directly
comparable GAAP financial measures and reconciliations are provided in the
slides that follow.
The Company believes that its non-GAAP financial measures are useful to
investors because they provide an alternative method for assessing the
Company’s operating results in a manner that is focused on the performance
of the Company’s ongoing operations, or on earnings absent the effect of
certain credits and charges, including interest, taxes, and depreciation,
depletion and amortization. The Company’s management uses these non-
GAAP financial measures for the same purpose, and for planning and
forecasting purposes. The presentation of non-GAAP financial measures is not
meant to be a substitute for financial measures prepared in accordance with
GAAP. |
 May 2013
58
Reconciliation of Exploration & Production West Division Adjusted EBITDA
to Exploration & Production Segment Net Income
($ Thousands)
12 Months Ended
March 31, 2013
Exploration & Production - West Division Adjusted EBITDA
218,842
$
Exploration & Production -
All Other Divisions Adjusted EBITDA 208,620
Total Exploration &
Production Adjusted EBITDA 427,462
$
Minus: Exploration & Production Net
Interest Expense (33,788)
Minus: Exploration
& Production Income Tax Expense (80,420)
Minus: Exploration
& Production Depreciation, Depletion & Amortization (214,871)
Exploration & Production Net
Income 98,383
$
Exploration & Production
Net Income 98,383
$
Pipeline & Storage
Net Income 71,455
Utility Net
Income 68,356
Energy Marketing Net Income
5,208
Corporate & All Other
Net Income 2,248
Consolidated Net Income
245,650
$
|
 May 2013
59
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
$
218,842
$
Exploration & Production - All Other Divisions Adjusted EBITDA
108,139
139,624
189,854
170,232
208,620
Total Exploration & Production Adjusted EBITDA
279,711
$
327,462
$
377,457
$
397,129
$
427,462
$
Total Adjusted EBITDA
Exploration & Production Adjusted EBITDA
279,711
$
327,462
$
377,457
$
397,129
$
427,462
$
Utility Adjusted EBITDA
164,443
167,328
168,540
159,986
170,824
Pipeline & Storage Adjusted EBITDA
130,857
120,858
111,474
136,914
152,563
Energy Marketing Adjusted EBITDA
11,589
13,573
13,178
5,945
7,656
Corporate & All Other Adjusted EBITDA
(5,575)
2,429
(2,960)
4,140
9,773
Total Adjusted EBITDA
581,025
$
631,650
$
667,689
$
704,114
$
768,278
$
Total Adjusted EBITDA
581,025
$
631,650
$
667,689
$
704,114
$
768,278
$
Minus: Net Interest Expense
(81,013)
(90,217)
(75,205)
(82,551)
(87,061)
Plus: Other Income
9,762
6,126
5,947
5,133
4,646
Minus: Income Tax Expense
(52,859)
(137,227)
(164,381)
(150,554)
(163,691)
Minus: Depreciation, Depletion & Amortization
(170,620)
(191,199)
(226,527)
(271,530)
(298,194)
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)
-
Rounding
-
-
-
(1)
-
Consolidated Net Income
100,708
$
225,913
$
258,402
$
220,077
$
245,650
$
Consolidated Debt to Total Adjusted EBITDA
Long-Term Debt, Net of Current Portion (End of Period)
1,249,000
$
1,049,000
$
899,000
$
1,149,000
$
1,649,000
$
Current Portion of Long-Term Debt (End of Period)
-
200,000
150,000
250,000
-
Notes Payable to Banks and Commercial Paper
(End of Period) -
-
40,000
171,000
-
Total Debt (End of Period)
1,249,000
$
1,249,000
$
1,089,000
$
1,570,000
$
1,649,000
$
Long-Term Debt, Net of Current Portion (Start of Period)
999,000
1,249,000
1,049,000
899,000
1,149,000
Current Portion of Long-Term Debt (Start of Period)
100,000
-
200,000
150,000
250,000
Notes Payable to Banks and Commercial Paper (Start of Period)
-
-
-
40,000
20,000
Total Debt (Start of Period)
1,099,000
$
1,249,000
$
1,249,000
$
1,089,000
$
1,419,000
$
Average Total Debt
1,174,000
$
1,249,000
$
1,169,000
$
1,329,500
$
1,534,000
$
Average Total Debt to Total Adjusted EBITDA
2.02
1.98
1.75
1.89
2.00
12-Months Ended
3/31/13 |
 May 2013
60
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
$
$525,000-585,000
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
$
$710,000-820,000
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
$
$710,000-820,000 |