Attached files
| file | filename |
|---|---|
| 8-K - 8-K - NATIONAL FUEL GAS CO | d442199d8k.htm |
 National Fuel Gas Company
Investor Presentation
November 2012
Exhibit 99 |
 National Fuel Gas
Company 2
Safe Harbor For Forward Looking Statements
This
presentation
may
contain
“forward-looking
statements”
as
defined
by
the
Private
Securities
Litigation
Reform
Act
of
1995,
including
statements
regarding
future
prospects,
plans,
performance and capital structure, anticipated capital expenditures and completion of
construction projects, as well as statements that are identified by the use of the words “anticipates,”
“estimates,”
“expects,”
“forecasts,”
“intends,”
“plans,”
“predicts,”
“projects,”
“believes,”
“seeks,”
“will,”
“may,”
and similar expressions. Forward-looking statements involve risks and
uncertainties, which could cause actual results or outcomes to differ materially from those
expressed in the forward-looking statements. The Company’s expectations, beliefs and
projections
contained
herein
are
expressed
in
good
faith
and
are
believed
to
have
a
reasonable
basis,
but
there
can
be
no
assurance
that
such
expectations,
beliefs
or
projections
will
result
or be achieved or accomplished.
In addition to other factors, the following are important factors that could cause actual
results to differ materially from results referred to in the forward-looking statements: factors
affecting the Company’s ability to successfully identify, drill for and produce
economically viable natural gas and oil reserves, including among others geology, lease availability, title
disputes, weather conditions, shortages, delays or unavailability of equipment and services
required in drilling operations, insufficient gathering, processing and transportation capacity,
the need to obtain governmental approvals and permits, and compliance with environmental laws
and regulations; changes in laws, regulations or judicial interpretations to which the
Company is subject, including those involving derivatives, taxes, safety, employment, climate
change, other environmental matters, real property, and exploration and production
activities
such
as
hydraulic
fracturing;
changes
in
the
price
of
natural
gas
or
oil;
impairments
under
the
SEC’s
full
cost
ceiling
test
for
natural
gas
and
oil
reserves;
uncertainty
of
oil
and
gas
reserve
estimates;
significant
differences
between
the
Company’s
projected
and
actual
production
levels
for
natural
gas
or
oil;
changes
in
demographic
patterns
and
weather
conditions;
changes
in
the
availability,
price
or
accounting
treatment
of
derivative
financial
instruments;
governmental/regulatory
actions,
initiatives
and
proceedings,
including
those
involving
rate
cases (which address, among other things, allowed rates of return, rate design and retained
natural gas), environmental/safety requirements, affiliate relationships, industry structure, and
franchise renewal; delays or changes in costs or plans with respect to Company projects or
related projects of other companies, including difficulties or delays in obtaining necessary
governmental approvals, permits or orders or in obtaining the cooperation of interconnecting
facility operators; financial and economic conditions, including the availability of credit, and
occurrences
affecting
the
Company’s
ability
to
obtain
financing
on
acceptable
terms
for
working
capital,
capital
expenditures
and
other
investments,
including
any
downgrades
in
the
Company’s
credit
ratings
and
changes
in
interest
rates
and
other
capital
market
conditions;
changes
in
economic
conditions,
including
global,
national
or
regional
recessions,
and
their
effect on the demand for, and customers’
ability to pay for, the Company’s products and services; the creditworthiness or
performance of the Company’s key suppliers, customers and counterparties; economic
disruptions or uninsured losses resulting from major accidents, fires, severe weather, natural disasters, terrorist activities, acts of war, cyber attacks or pest
infestation; changes in price differential between similar quantities of natural gas at
different geographic locations, and the effect of such changes on the demand for pipeline
transportation
capacity
to
or
from
such
locations;
other
changes
in
price
differentials
between
similar
quantities
of
oil
or
natural
gas
having
different
quality,
heating
value,
geographic
location or delivery date; significant differences between the Company’s projected and
actual capital expenditures and operating expenses; changes in laws, actuarial assumptions, the
interest
rate
environment
and
the
return
on
plan/trust
assets
related
to
the
Company’s
pension
and
other
post-retirement
benefits,
which
can
affect
future
funding
obligations
and
costs
and plan liabilities; the cost and effects of legal and administrative claims against the
Company or activist shareholder campaigns to effect changes at the Company; increasing health care
costs and the resulting effect on health insurance premiums and on the obligation to provide
other post-retirement benefits; or increasing costs of insurance, changes in coverage and the
ability to obtain insurance.
Forward-looking statements include estimates of oil and gas quantities.
Proved oil and gas reserves are those quantities of oil and gas
which, by analysis of geoscience and engineering
data, can be estimated with reasonable certainty to be economically producible under existing
economic conditions, operating methods and government regulations. Other estimates of
oil and
gas
quantities,
including
estimates
of
probable
reserves,
possible
reserves,
and
resource
potential,
are
by
their
nature
more
speculative
than
estimates
of
proved
reserves.
Accordingly, estimates other than proved reserves are subject to
substantially greater risk of being actually realized. Investors are urged to consider closely
the disclosure in our Form 10-K available
at
www.nationalfuelgas.com.
You
can
also
obtain
this
form
on
the
SEC’s
website
at
www.sec.gov.
For a discussion of the risks set forth above and other factors that could cause actual
results to differ materially from results referred to in the forward-looking statements, see “Risk
Factors”
in the Company’s Form 10-K for the fiscal year ended September 30, 2012. 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.
November 2012 |
 November
2012 National Fuel Gas Company
Our Business Mix Leads to Long-Term Value Creation
National Fuel Gas
Supply Corporation
Empire Pipeline, Inc.
National Fuel Gas
Midstream Corporation
National Fuel Gas
Distribution
Corporation
National Fuel
Resources, Inc.
The strategic, operational and financial benefits and flexibility
created by this integrated mix of businesses continues to generate
significant long-term value for the Company’s shareholders in
nearly all economic and commodity price scenarios
Seneca Resources
Corporation
(West Division)
Seneca Resources
Corporation
(East Division)
Upstream
Crude Oil
Upstream
Natural Gas
Midstream
Downstream
3 |
 National Fuel Gas
Company 4
Integrated Business Mix Provides Financial Balance
November 2012
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 5
Integrated Businesses with Significant Marcellus Exposure…
November 2012 |
 November
2012 National Fuel Gas Company
…And Exposure to Growth from the Utica Shale
6 |
 November
2012 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 Additional
infrastructure expansions are being aggressively pursued and as a result, additional
capital spending remains flexible and will be
deployed based upon return-driven decision making |
 November
2012 Total Debt
(1)
44%
National Fuel Gas Company
8
Strong Balance Sheet and Liquidity Position
$3.530 Billion
(2)
As of September 30, 2012
(1)
Includes Long-Term Debt of $1.149 billion, the Current Portion of Long-Term Debt of
$0.250 billion, and Notes Payable to Banks and Commercial Paper of $0.171 billion, as
of September 30, 2012. (2)
Includes Notes Payable to Banks and Commercial Paper of $171.0 million and Current Portion of
Long-Term Debt of $250.0 million as of September 30, 2012. Short-Term Debt
Long
-
Term Debt
Shareholders’
Equity
56 %
Capital Resources
Total Short-Term Capacity: $1,085 Million
Committed Credit Facility: $750 Million
Syndicated facility extends until
January 6, 2017
Uncommitted Lines of Credit: $335 Million
$6.0 million of outstanding short-term
notes payable to banks as of
September 30, 2012
$300.0 Million Commercial Paper Program
backed by Committed Credit Facility
$165.0 million of outstanding commercial
paper as of September 30, 2012 |
 November
2012 National Fuel Gas Company
9
Dividend Track Record
Current
Dividend Yield
(1)
2.9%
Dividend Consistency
Consecutive Dividend Payments
110 Years
Consecutive Dividend Increases
42 Years
Current Annualized Dividend Rate
$1.46 per Share
(1) As of November 16, 2012 |
 November
2012 Midstream Businesses
10
Pipeline & Storage/NFG Midstream |
 November
2012 Midstream Businesses
11
Pipeline Expansions to Transport Appalachian Production
Gathering
Marcellus
Production
Shipping Gas
to Canada &
Northeast
Line N
Corridor
Expansions |
 November
2012 Midstream Businesses
12
A Closer Look at the Expansion Progress
COVINGTON
GATHERING
SYSTEM
(In-Service)
TROUT RUN
GATHERING SYSTEM
(In-Service)
TIOGA
COUNTY
EXTENSION
(In-Service)
NORTHERN ACCESS
EXPANSION
(In-Service)
CENTRAL TIOGA
COUNTY EXTENSION
(2015)
LINE “N”
2012
EXPANSION
(In-Service)
MERCER
EXPANSION
PROJECT
(2014)
LINE “N”
2013
EXPANSION
(Nov. 2013)
LINE
“N”
EXPANSION
(In-Service) |
 November
2012 Midstream Businesses
13
Pursuing Additional Opportunities Near the Line N Corridor
Activity along the Pennsylvania/Ohio
border continues to remain robust and is
shifting north as the Utica begins to be
delineated
National Fuel’s Line N system is well-
positioned to expand in conjunction with
growth from both the Marcellus and
Utica shales
Significant expansion opportunities may
be present in the next few years
2013:
Smaller
lateral
pipeline
extensions
between $3 and $20 million
2014/2015:
Larger expansion projects,
possibly including an integrated wet gas
solution, with National Fuel focused on
the high-pressure wet gas gathering
systems and dry gas interstate pipelines |
 November
2012 NFG Midstream
14
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
Using a History of Excellence to Serve Appalachian Producers |
 November
2012 Utility
15 |
 November
2012 Rate Mechanisms
Low Income Rates
Choice Program/POR
Merchant Function Charge
Revenue Decoupling
90/10 Sharing
Weather Normalization
Utility
16
Providing Financial Stability
New York & Pennsylvania
New York only
9.8%
10.6%
10.5%
12.6%
13.2%
14.7%
18.8%
12.5%
0.0%
10.0%
20.0%
30.0%
2009
2010
2011
2012
Fiscal Year
Return on Equity
NY
PA
Allowed ROE -
NY
Approx. Settled ROE -
PA |
 November
2012 Utility
17
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
$25
$27
$14
$11
$9
$203
$191
$181
$179
$177
$0
$50
$100
$150
$200
$250
2008
2009
2010
2011
2012
Fiscal Year
All Other O&M Expenses
O&M
Expense
-
Uncollectibles |
 November
2012 Utility
18
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 |
 November
2012 Exploration & Production
19 |
 November
2012 Seneca Resources
20
Remaining Strategically Opportunistic in Fiscal 2013
presentation.
Seneca’s acreage position and operational strategy allows the flexibility to
ramp up, pull back, or redirect its spending according to its opportunities
•
Maintain two rigs drilling in the Eastern Development Area (EDA), largely in
DCNR Tract 100 in Lycoming County, Pennsylvania
•
Continue
wet/dry
gas
delineation
in
the
Western
Development
Area
(WDA)
Marcellus
Shale
•
Evaluate initial results on the first two Utica delineation wells in the Tionesta
and Mt. Jewett prospect areas
•
Drill two additional delineation wells, one each in the Henderson and Owl’s
Nest prospect areas
Utica
Shale
•
Continue ongoing efforts to grow production in Sespe and South Midway
Sunset, which were large drivers of the $227 million of EBITDA in fiscal 2012
•
Evaluate and pursue opportunities in the East Coalinga field as part of a new
farm-in agreement
California
Oil
•
Evaluating 9,300 net acres acquired in late fiscal 2012
•
Participate in 4 to 10 gross horizontal wells to further evaluate potential
Mississippian
Lime
Note: A reconciliation of Exploration & Production West Division Adjusted EBITDA to
Exploration & Production Segment Net Income is included at the end of this |
 November
2012 Seneca Resources
21
Another Strong Year of Reserve Growth
Seneca has more than doubled
its proved reserves since 2009,
while maintaining a relatively
high percentage of proved
developed reserves (67%),
given its large resource base
(1)
Represents a three-year average U.S. finding and development cost
47.6
46.2
46.6
45.2
43.3
226
249
428
675
988
503
528
700
935
1,246
0
300
600
900
1200
1500
2008
2009
2010
2011
2012
At September 30
Natural Gas (Bcf)
Crude Oil (MMbbl)
Fiscal
Years
3-Year
F&D Cost
(1)
($/Mcfe)
2006-2008
$7.63
2007-2009
$5.35
2008-2010
$2.37
2009-2011
$2.09
2010-2012
$1.87 |
 November
2012 Seneca Resources
22
Increased Oil Spending and Tempered Marcellus Spending
(1)
Does not include the $34.9 MM acquisition of Ivanhoe’s U.S.-based assets in
California, as this was accounted for as an investment in subsidiaries on the
Statement of Cash Flows, and was not included in Capital Expenditures
|
 November
2012 Seneca Resources
23
Production Still Growing |
 November
2012 Seneca Resources
24
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 $58 to
$62 million, divided by the midpoint of current production guidance of 95 to 107
Bcfe (2)
Represents the midpoint of current Lease Operating Expense Guidance of $0.90 to $1.10 per
Mcfe |
 November
2012 California
25
Stable Production and Increasing Cash Flows
Net Acreage: 11,833 Acres
Net Wells: 1,322
Oil Gravity: 12 –
37°
Api
NRI: 87.64
Rank
Company
California
2011
BOEPD
1
Occidental
164,796
2
Chevron
163,153
3
Aera (Shell/Exxon)
149,974
4
Plains Exploration
36,775
5
Venoco Inc.
18,988
6
Berry Petroleum
18,872
7
Seneca Resources
9,209
8
Macpherson Oil
9,022
9
E&B Natural Resources
5,992
10
ExxonMobil
3,238 |
 November
2012 California
26
Stable Production Fields
South Lost Hills
~1,600 BOEPD
Monterey Shale
Primary
219 Active Wells
Sespe
~1,200 BOEPD
Sespe Formation
Primary
172 Active Wells
North Lost Hills
~1,200 BOEPD
Tulare & Etchegoin Formation
Primary & Steamflood
175 Active Wells
North Midway Sunset
~4,300 BOEPD
Potter & Tulare Formation
Steamflood
728 Active Wells
South Midway Sunset
~1,100 BOEPD
Antelope Formation
Steamflood
110 Active Wells
East Coalinga
Temblor Formation
Primary |
 November
2012 California
27
Strong Margins Support Significant Free Cash Flow
Average Revenue
In Fiscal 2012
$85.16 per BOE
$9.09
$2.82
$2.74
$2.46
$1.08
Non-
Steam Fuel LOE
Steam Fuel
G&A
Production & Other Taxes
Other Operating Costs
Adjusted EBITDA
Fiscal Year 2012 Adjusted EBITDA per BOE
$70.86
Note: A reconciliation of Exploration & Production West Division Adjusted EBITDA to
Exploration & Production Segment Net Income is included at the end of this
presentation. |
 November
2012 Seneca Resources
28
California –
Recent Initiatives Driving Near-Term Growth
Key Areas of Focus in 2013
6,500
7,000
7,500
8,000
8,500
9,000
9,500
10,000
6,000
Actual
Forecast
1. North Midway Sunset Steaming 2.
South Midway Sunset Field Extensions
3. Sespe Infill Drill Program |
 November
2012 Midway Sunset South Activity Update
Seneca Resources
500’
2012 Drill Program: 21 Wells / 3 Injectors
2013 Drill Program: 17
-
23
Wells
/
5
-
9
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
2012 Drill Program
Producers Injectors
2013 Drilling Locations
Producers
Injectors
100 ft
50 ft
100 ft
50 ft
0 ft
50 ft
0 ft
0 ft
0 ft
0 ft
29 |
 November
2012 30
WS 48-33
80 BOEPD
1
Oil 09/12
“X”
SANDS ISOCHORE (Thickness)
Seneca Resources
Sespe Field –
2011 & 2012 Drilling Programs and Results
2011 Sespe Wells (5)
2012 Sespe Wells (6)
Oak Flat 1-31
110 BOEPD
1 Oil 08/12
FA 502-33
Completing
1 Oil 12/12
FA 501-33
Completing
1 Oil 12/12
Oak Flat 2-31
100 BOEPD
1
Oil 08/12
TG 562-29
Completing
1
Oil 12/12
TG 53-29
Completing
1st
Oil 12/12
2013 Sespe Wells (6)
1 Mile
st
st
st
st
st
st
st |
 Seneca
Resources 31
Monterey Shale Play
Monterey Shale Play
Belridge Field
5 AMIs across the field
Seneca WI: 12.5%
Seneca NRI: 11.4%
Producing (Gross): 65 BOEPD
5 Delineation Wells Planned
AMI Outlines
Gross Thickness of Monterey Interval
Drilling/Drilled
Planned
November 2012 |
 November
2012 Seneca Resources
32
Expansive Pennsylvania Acreage Position
SRC Lease Acreage
SRC Fee Acreage
NFG Storage Acreage
Western Development Area
Net acreage:
~720,000 acres
Own most mineral rights
Minimal royalty obligation
Minimal lease expiration
Evaluating Marcellus rich-gas
and Utica Shale potential
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
Eastern Development Area |
 November
2012 Seneca Resources
33
Net Rig Count (Working Interest)
Seneca anticipates
minimal joint venture
activity in fiscal 2013
1.0
1.0
1.0
1.0
5.0
3.0
2.0
2.0
2.0
1.5
1.5
1.5
0.5
7.5
5.5
4.5
2.5
3.0
0
2
4
6
8
10
Fiscal 2012 -
Q1
Fiscal 2012 -
Q2
Fiscal 2012 -
Q3
Fiscal 2012 -
Q4
Fiscal 2013
Forecast
Seneca
Operated
-
Delineation
Seneca
Operated
-
Development
EOG Operated |
 November
2012 Seneca Resources
34
Eastern
Development
Area
(EDA)
–
Results
&
Plan
Forward
DCNR Tract 595
Gross Production: ~70 MMcf per Day
34 Wells Drilled
19 Wells Producing
DCNR Tract 100 Area
IPs: 10.5 –
16.1 MMcf per Day
Gross Production: ~50 MMcf per Day
20 Wells Drilled
8 Wells Producing
SRC Lease Acreage
SRC Fee Acreage
Covington
–
Fully
Developed
47 Wells Drilled and Producing
Gross Production: ~75 MMcf per Day |
 November
2012 Seneca Resources
35
Lycoming and Tioga Counties Are Highly Productive Areas
Development
Area
Producing
Well
Count
Average
IP Rate
(MMcf/d)
Average
7-Day
(MMcf/d)
Average
30-Day
(MMcf/d)
Average
EUR
per Well
(Bcf)
Average
Lateral
Length
EUR per
1,000’
of
Lateral
(Bcfe)
Covington
(Tioga
County)
47
5.2
4.7
4.1
5.3
4,049’
1.30
Tract 595
(Tioga
County)
19
6.9
6.0
5.1
7.3
4,455’
1.65
Tract 100
(Lycoming
County)
7
12.7
11.6
10.4
11.6
5,788’
2.00 |
 November
2012 Seneca Resources
36
Ramping Marcellus Shale Production
Forecast
0
50
100
150
200
250
WDA/Other
EOG JV
Lycoming
DCNR 595
Covington |
 November
2012 Seneca Resources
37
Delineating the Western Development Area
Owl’s Nest (2 Wells)
Church Run (1 Well)
Currently Drilling
Ridgway (1 Well)
Rich Valley (1 Well)
Peak IP: 6.3 MMcf per Day
Estimated EUR: 6.4 Bcf
BTU
Contours
Proposed Hz Well
SRC Fee Acreage
SRC Lease Acreage |
 November
2012 Seneca Resources
Utica Shale –
Activity Summary
Permitted Well
Drilled Well
Completed Well
Mt. Jewett
Vertical: Tested Dry Gas
Horizontal: Completing Fall 2012
Henderson
Vertical Well: Tested
Horizontal: FY2013
Tionesta
Horizontal: Completed Fall 2012
Peak 24-Hour Rate: 3.9 MMcfd
Owl’s Nest
Horizontal: FY2013
Rex
9.2 MMcfd
Chesapeake
6.4 MMcfd
Range Resources
4.4 MMcfd
Wet
Dry
38 |
 November
2012 Seneca Resources
39
Initial Entry into the Mississippian Lime Play in Kansas
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 4 to 10 gross
horizontal wells
Total Net Acres: 9,300 |
 November
2012 National Fuel Gas Company
40
Appendix |
 November
2012 National Fuel Gas Company
41
Fiscal Year 2013 Earnings Guidance Drivers
2013 Forecast
GAAP Earnings per Share
$2.65 -
$2.95
Exploration & Production Drivers
Total Production (Bcfe)
95 -
107
DD&A Expense
$2.10 -
$2.25
LOE Expense
$0.90 -
$1.10
G&A Expense
$58 -
$62 MM
Pipeline & Storage Drivers
O&M Expense
+3%
Revenue
$255 -
$265 MM
Utility Drivers
O&M Expense
+3%
Normal Weather in PA |
 November
2012 National Fuel Gas Company
42
Manageable Debt Maturity Schedule
The Company is planning a new long-term
debt issuance in fiscal 2013, likely totaling
$350 million, to refinance maturing long-
term and outstanding short-term debt
$250
$300
$250
$500
$49
$50
7.395%
7.375%
$0
$100
$200
$300
$400
$500
$600
Fiscal Year |
 November
2012 National Fuel Gas Company
43
Targeted Capital Structure
Long-Term Consolidated
Capital Structure Target
Capital Structure
Targets by Segment
40%
30%
50%
50%
60%
70%
50%
50%
All Other
E&P
P&S
Utility
Debt
Equity
Debt
35% -
45%
Equity
55% -
65% |
 Pipeline &
Storage / Midstream 44
Appendix
November 2012 |
 November
2012 Pipeline & Storage
45
Expansion Initiatives
Project Name
Capacity
(Dth/D)
Est.
CapEx
In-Service
Market
Status
Lamont Compressor Station
40,000
$6 MM
6/2010
Fully Subscribed
Completed
Lamont Phase II Project
50,000
$8 MM
7/2011
Fully Subscribed
Completed
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
$75 MM
11/2012
Fully Subscribed
240,000 Dth/d In-Service as of 11/1/12
Line “N”
2012 Expansion
163,000
$43 MM
11/2012
Fully Subscribed
Completed
Line “N”
2013 Expansion
30,000
~$4 MM
11/2013
OS Concluded
Negotiating with an anchor shipper for all
capacity
Mercer Expansion Project
~150,000
~$30 MM
2013/2014
OS Concluded
In discussions with prospective shippers
Central Tioga County
Extension
~260,000
~$135 MM
2015
OS Concluded
In discussions with an anchor shipper
West to East
~425,000
~$290 MM
~2015
29% Subscribed
Marketing continues with producers in
various stages of exploratory drilling
Total Firm Capacity: ~1,948,000 Dth/D
Capital Investment: ~$671 MM |
 November
2012 Midstream Corporation
46
Expansion Initiatives
Project Name
Capacity
(Mcf/D)
Est.
CapEx
In-Service
Date
Market
Comments
Covington Gathering System
220,000
$40 MM
Multiple
Phases -
Most
In-Service
Capacity Available
[Marketing to
Third Parties]
Completed
–
Flowing into TGP 300
Line. This includes ~$10 million of
current and future spending to
build pipeline to connect additional
wells
Trout Run Gathering System
466,000
$185 MM
May 2012
Capacity Available
[Marketing to
Third Parties]
Completed
–
Flowing into Transco
Leidy Line. This includes ~$100
million of current and future
spending to build compression and
pipeline to connect additional wells
Owl’s Nest Gathering System
200,000
$110 MM
First Phase
FY2014
Fully Subscribed
Preliminary work underway with
development phased in over a five
year period. Any processing costs
would be incremental.
Total Firm Capacity: ~886,000 Mcf/D
Capital Investment: ~$335 MM |
 November
2012 Exploration & Production
47
Appendix |
 November
2012 National Fuel Gas Company
48
Hedge Positions and Strategy
Natural Gas
Swaps
Volume
(Bcf)
Average
Hedge Price
Fiscal 2013
50.2
$4.76 / Mcf
Fiscal 2014
30.4
$4.26 / Mcf
Fiscal 2015
18.1
$4.07 / Mcf
Fiscal 2016
17.9
$4.07 / Mcf
Fiscal 2017
17.9
$4.07 / Mcf
Oil Swaps
Volume
(MMBbl)
Average
Hedge Price
Fiscal 2013
1.8
$94.75 / Bbl
Fiscal 2014
0.9
$97.67 / Bbl
Fiscal 2015
0.1
$90.20 / Bbl
Most hedges executed at sales point to eliminate basis risk
Seneca has hedged approximately 60% of its
forecasted production for Fiscal 2013 |
 November
2012 Marcellus Shale
49
Targeting Continued Cost Reductions
$200
$300
$400
$500
$600
$700
$800
2010
2011
2012
2013
Target
Drilling Cost per Lateral Foot
WDA/DCNR 595
DCNR 100
$100
$150
$200
$250
$300
$350
$400
2010
2011
2012
2013
Target
Completion Cost per Stage ($000)
WDA/DCNR 595
DCNR 100 |
 November
2012 Marcellus Shale
50
Water Management Program
Water Sourcing:
Coal mine runoff
Permitted freshwater sources
Recycled water
Water Management:
Instituted a “Zero Surface Discharge”
policy
Recycle Marcellus flowback and produced water
Centralized water handling in development areas
Tioga County –
DCNR 595 and Covington
Lycoming County –
DCNR 100
Elk County -
Owl’s Nest
Installing new evaporative technology
Permitting underground injection
Established a Water Protection Team
Seneca is committed to protecting the surface and fresh water aquifers from any pollution
|
 November
2012 National Fuel Gas Company
51
Comparable GAAP Financial Measure Slides and Reconciliations
This presentation contains certain non-GAAP financial measures. For pages
that contain non-GAAP financial measures, pages containing the most directly
comparable GAAP financial measures and reconciliations are provided in the
slides that follow.
The Company believes that its non-GAAP financial measures are useful to
investors because they provide an alternative method for assessing the
Company’s operating results in a manner that is focused on the performance
of the Company’s ongoing operations, or on earnings absent the effect of
certain credits and charges, including interest, taxes, and depreciation,
depletion and amortization. The Company’s management uses these non-
GAAP financial measures for the same purpose, and for planning and
forecasting purposes. The presentation of non-GAAP financial measures is not
meant to be a substitute for financial measures prepared in accordance with
GAAP. |
 November
2012 52
Reconciliation of Segment Capital Expenditures to
Consolidated Capital Expenditures
($ Thousands)
FY 2013
FY 2009
FY 2010
FY 2011
FY 2012
Forecast
Capital Expenditures from Continuing Operations
Exploration & Production Capital Expenditures
188,290
$
398,174
$
648,815
$
693,810
$
$425,000-525,000
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
$
$610,000-760,000
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
$
$610,000-760,000 |
 November
2012 53
Reconciliation of Exploration & Production West Division Adjusted EBITDA
to Exploration & Production Segment Net Income
($ Thousands)
12 Months Ended
September 30, 2012
Exploration & Production - West Division Adjusted EBITDA
226,897
$
Exploration & Production -
All Other Divisions Adjusted EBITDA 170,232
Total Exploration &
Production Adjusted EBITDA 397,129
$
Minus: Pennsylvania Impact Fee Related to
Prior Fiscal Years (6,206)
Minus:
Exploration & Production Net Interest Expense (27,751)
Minus: Exploration
& Production Income Tax Expense (79,050)
Minus: Exploration
& Production Depreciation, Depletion & Amortization (187,624)
Exploration & Production Net
Income 96,498
$
Exploration & Production
Net Income 96,498
$
Pipeline & Storage
Net Income 60,527
Utility Net
Income 58,590
Energy Marketing Net Income
4,169
Corporate & All Other Net
Income 293
Consolidated
Net Income 220,077
$
|
 November
2012 54
Reconciliation of Adjusted EBITDA to Consolidated Net Income
($ Thousands)
FY 2008
FY 2009
FY 2010
FY 2011
FY 2012
Exploration & Production - West Division Adjusted EBITDA
188,008
$
170,611
$
187,838
$
187,603
$
226,897
$
Exploration & Production - All Other Divisions Adjusted EBITDA
174,216
109,100
139,624
189,854
170,232
Total Exploration & Production Adjusted EBITDA
362,224
$
279,711
$
327,462
$
377,457
$
397,129
$
Total Adjusted EBITDA
Exploration & Production Adjusted EBITDA
362,224
$
279,711
$
327,462
$
377,457
$
397,129
$
Utility Adjusted EBITDA
161,575
164,443
167,328
168,540
159,986
Pipeline & Storage Adjusted EBITDA
129,171
130,857
120,858
111,474
136,914
Energy Marketing Adjusted EBITDA
8,699
11,589
13,573
13,178
5,945
Corporate & All Other Adjusted EBITDA
(8,156)
(5,575)
2,429
(2,960)
4,140
Total Adjusted EBITDA
653,513
$
581,025
$
631,650
$
667,689
$
704,114
$
Total Adjusted EBITDA
653,513
$
581,025
$
631,650
$
667,689
$
704,114
$
Minus: Net Interest Expense
(62,555)
(81,013)
(90,217)
(75,205)
(82,551)
Plus: Other Income
7,164
8,200
3,638
6,706
5,133
Minus: Income Tax Expense
(167,672)
(52,859)
(137,227)
(164,381)
(150,554)
Minus: Depreciation, Depletion & Amortization
(169,846)
(170,620)
(191,199)
(226,527)
(271,530)
Minus: Impairment of Oil and Gas Properties (E&P)
-
(182,811)
-
-
-
Plus/Minus: Income/(Loss) from Discontinued
Operations, Net of Tax (Corp. & All Other) 1,821
(2,776)
6,780
-
-
Plus: Gain on Sale of Unconsolidated
Subsidiaries (Corp. & All Other) -
-
-
50,879
-
Plus/Minus: Income/(Loss) from Unconsolidated
Subsidiaries (Corp. & All Other) 6,303
3,366
2,488
(759)
-
Minus: Impairment of Investment in Partnership
(Corp. & All Other) -
(1,804)
-
-
-
Plus: Elimination of Other Post-Retirement
Regulatory Liability (P&S) -
-
-
-
21,672
Minus: Pennsylvania Impact Fee Related to Prior Fiscal Years (E&P)
-
-
-
-
(6,206)
Rounding
-
-
-
-
(1)
Consolidated Net Income
268,728
$
100,708
$
225,913
$
258,402
$
220,077
$
|