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| 8-K - 8-K - NATIONAL FUEL GAS CO | d390182d8k.htm |
 National Fuel Gas Company
Investor Presentation
August 2012
Exhibit 99 |
 August
2012 National Fuel Gas Company
2
Safe Harbor For Forward Looking Statements
www.nationalfuelgas.com.You
can
also
obtain
this
form
on
the
SEC’s
website
at
www.sec.gov.
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
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, 2011 and Forms 10-Q
for the periods ended December 31, 2011, March 31, 2012, and June 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. |
 August
2012 National Fuel Gas Company
3
Our Business Mix Leads to Long-Term Value Creation
Upstream
Crude Oil
Midstream
Downstream
National Fuel Gas
Supply Corporation
Empire Pipeline, Inc.
National Fuel Gas
Midstream Corporation
National Fuel Gas
Distribution
Corporation
National Fuel
Resources, Inc.
The strategic, operational and financial benefits created by
the integrated mix of assets continues to generate
significant long-term value for the Company in nearly all
economic and commodity price scenarios
Upstream
Natural Gas
Seneca Resources
Corporation
(West Division)
Seneca Resources
Corporation
(East Division) |
 August
2012 $162
25%
$164
28%
$167
26%
$169
25%
$156
23%
$129
20%
$131
23%
$121
19%
$111
17%
$128
19%
$362
55%
$280
48%
$327
52%
$377
57%
$379
56%
$654
$581
$632
$668
$672
$0
$250
$500
$750
$1,000
2008
2009
2010
2011
12 Months Ended
6/30/12
Fiscal Year
Pipeline & Storage Segment
Exploration & Production Segment
Midstream, Energy Marketing & Other
National Fuel Gas Company
4
Integrated Business Mix Provides Financial Balance
Note: A reconciliation of EBITDA to Net Income as presented on the Consolidated Statement of
Income and Earnings is included at the end of this presentation. Utility
Segment |
 August
2012 National Fuel Gas Company
5
Highly Integrated Assets with Significant Marcellus Exposure…
|
 August
2012 National Fuel Gas Company
6
…And Exposure to Growth from the Utica Shale |
 August
2012 National Fuel Gas Company
Business Mix Allows for Strategic Capital Allocation
Predictable Earnings and Cash Flow
Capital Allocation Priorities
7
Ongoing maintenance capital spending in regulated businesses
Returning earnings to shareholders through consistent dividends
Flexible, return-driven growth capital spending |
 August
2012 National Fuel Gas Company
8
Capital Spending Flexibility to Maintain Financial Strength
Note: A reconciliation to Capital Expenditures as presented on the Consolidated Statement of
Cash Flows is included at the end of this presentation. To the extent additional
infrastructure expansions are available, additional capital
remains flexible and will be deployed
based upon return-driven decision making |
 August
2012 Short-Term
Debt
2.0%
National Fuel Gas Company
9
Strong Balance Sheet and Liquidity Position
$3.458 Billion
(1)
As of June 30, 2012
(1) Includes Notes Payable to Banks and Commercial Paper of $70.2 million and Current Portion
of Long-Term Debt of $250.0 million as of June 30, 2012.
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
$20.2 million of outstanding short-term
notes payable to banks as of June 30, 2012
$300.0 Million Commercial Paper Program
backed by Committed Credit Facility
$50.0 million of outstanding commercial paper
as of June 30, 2012 |
 August
2012 National Fuel Gas Company
10
Dividend Track Record
Current
Dividend Yield
(1)
3.0%
(1) As of July 31, 2012
Dividend Consistency
Consecutive Dividend Payments
110 Years
Consecutive Dividend Increases
42 Years
Current
Annualized Dividend Rate
$1.46
per Share |
 August
2012 Pipeline & Storage / Midstream
11 |
 August
2012 Pipeline & Storage / Midstream
12
Ongoing Expansion to Transport Appalachian Production
Longer-Term
Infrastructure
Expansions
Shipping Gas
to Canada &
Northeast
Serving
Southwest PA
Producers
Gathering
Marcellus
Production |
 August
2012 Pipeline & Storage / Midstream
13
A Closer Look at the Expansion Progress
MERCER
EXPANSION
PROJECT
(2014 In-Service)
LINE “N”
2012
EXPANSION
(Under Construction)
LINE “N”
EXPANSION
(In-Service)
TROUT RUN
GATHERING SYSTEM
(In-Service)
COVINGTON
GATHERING
SYSTEM
(In-Service)
CENTRAL TIOGA
COUNTY EXTENSION
(2014/2015)
TIOGA COUNTY
EXTENSION
(In-Service)
NORTHERN ACCESS
EXPANSION
(Under Construction)
WEST TO EAST
OVERBECK TO LEIDY |
 August
2012 Midstream
14
Using a History of Excellence to Serve Appalachian Producers
Midstream’s gathering systems are
critical to unlock remote, but highly
productive Marcellus acreage
History of operational success and
efficiency within Pennsylvania
Original priority had been to assist
Seneca’s growing development
program and utilize those systems to
gather 3
rd
party producer volumes
As a result of Seneca’s delayed
development plans, the current focus is
shifting to expanding infrastructure for
others in the basin
Transco
Lycoming County
Tioga County
TGP 300 |
 August
2012 Pipeline & Storage
15
Regulatory Rate Filings
National
Fuel
Gas
Supply
Corporation
Filed a general rate case with FERC on
October 31, 2011 as part of an agreement
from a 2006 rate settlement
On April 14, 2012 an agreement in
principle was reached to settle the rate
case, with new rates effective May 1,
2012
Rates are effective subject to refund
beginning May 1, 2012
Empire Pipeline, Inc.
Filing did not propose any changes to the
current rate structure
Filed a cost and revenue study on
March 14, 2012 as part of a 2006 FERC
order related to Empire’s transition to
a FERC-regulated interstate pipeline |
 August
2012 Utility
16 |
 August
2012 Rate Mechanisms
Low Income Rates
Choice Program/POR
Merchant Function Charge
Revenue Decoupling
90/10 Sharing
Weather Normalization
Utility
17
Providing Financial Stability
9.8%
10.6%
10.5%
10.9%
13.2%
14.7%
18.8%
12.4%
0.0%
10.0%
20.0%
30.0%
2009
2010
2011
TME
6/30/2012
Fiscal Year
Return on Equity
NY
PA
Allowed ROE -
NY
Approx. Settled ROE -
PA
New York & Pennsylvania
New York only |
 August
2012 Utility
18
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
12 Months Ended
June 30, 2012
Fiscal Year
All Other O&M Expenses
O&M Expense -
Uncollectibles |
 August
2012 Utility
19
Strong Commitment to Safety
The Utility remains
focused on consistent
spending to maintain the
ongoing safety and
reliability of its system
The anticipated increase in 2013
capital expenditures is largely due
to the implementation of a new
Customer Information System
$42.8
$45.1
$44.4
$45.0
$44.3
$54.2
$57.5
$56.2
$58.0
$58.4
$55-$60
$60
$70
$0
$20
$40
$60
$80
2007
2008
2009
2010
2011
2012
Forecast
2013
Forecast
Fiscal Year
Capital Expenditures for Safety
Total Capital Expenditures
- |
 August
2012 Exploration & Production
20 |
 August
2012 Seneca Resources
21
Ongoing Strategic Responses to Low Gas Prices
Maintain Focus
on California
Crude Oil
Ongoing
Delineation in
Appalachia
Delaying
Marcellus
Completions
Reduction
In Rig Count
Production
Curtailment
•
Generated $175 million of EBITDA in the first nine months of fiscal 2012
•
Increased capital spending in California
•
Continue to delineate Seneca’s Utica Shale acreage potential
•
Evaluate Marcellus rich-gas potential in the Western Development Area
•
Delaying completions in Tioga County (DCNR Tract 595) due to low natural gas
prices on TGP 300
•
Seneca began fiscal 2012 with 6 rigs and will operate a 3 rig program in fiscal 2013
•
EOG advised Seneca that it likely will not be drilling any wells in fiscal 2013
•
Managing production volumes and future completions in Tioga County, targeting
consistent gross volumes of 130 MMcf per day into TGP 300, which is equivalent
to existing firm sales commitments |
 August
2012 California
22
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 |
 August
2012 California
23
Stable Production Fields
South Lost Hills
~1,700 BOEPD
Monterey Shale
Primary
215 Active Wells
Sespe
~1,200 BOEPD
Sespe Formation
Primary
188 Active Wells
North Lost Hills
~1,200 BOEPD
Tulare & Etchegoin Formation
Primary & Steamflood
181 Active Wells
North Midway Sunset
~4,400 BOEPD
Potter & Tulare Formation
Steamflood
728 Active Wells
South Midway Sunset
~1,000 BOEPD
Antelope Formation
Steamflood
109 Active Wells |
 August
2012 California
24
Strong Margins Support Significant Free Cash Flow
Average Revenue
in First Nine Months
of Fiscal 2012
$86.23 per BOE
$8.64
3.18
$2.60
$2.37
$1.03
Non
Steam Fuel LOE
Steam Fuel
G&A
Production & Other Taxes
Other Operating Costs
EBITDA
Fiscal Year 2012 (First Nine Months) EBITDA per BOE
$
$67.64
Note: A reconciliation of Exploration & Production West Division EBITDA to Exploration
& Production Segment Net Income is included at the end of this presentation. |
 August
2012 Seneca Resources
25
California –
Recent Initiatives Driving Near-Term Growth
Production Increase Drivers
1.
North Midway Sunset Steaming
2.
South Midway Sunset Field Extensions
3.
Sespe Infill Drill Program
8,500
9,000
9,500
10,000
Actual
Forecast
8,000 |
 August
2012 26
Midway Sunset South Activity Update
2011 Drill Program
2012 Drilling Locations
Updip Sand Pinch-out
Approx. Oil/Water Contact
100 ft
100 ft
50 ft
Antelope “A-1”
and “A-2”
Sands
Antelope “B”
and “C”
Sands
Antelope “A-1”
Sand
Seneca Western Minerals 251T
Extended 251 Pool to the West
Seneca Western Minerals 242I
Extended 252 Pool to the West
100 ft
400’
50 ft
50 ft
50 ft
Seneca Resources
2011 Drill Program: 12 Wells / 4 Injectors
2012 Drill Program: 23 Wells / 3 Injectors |
 August
2012 27
350’
Thick
(Medium Blue)
800’
Thick
(Dark Red)
~550’
Thick
(Green)
White Star –
5 Acre Tests
Powell –
10 Acre Tests
Powell 4
61 BOEPD
1 Oil 11/11
WS 534-33
42 BOEPD
1 Oil 1/12
White Star –
10 Acre Test
WS 48-33
1 Production
August 2012
WS 533-33
88 BOEPD
1 Oil 1/12
“X”
SANDS ISOCHORE (Thickness)
Seneca Resources
Sespe Field –
2011 Drilling Highlights and Results
Powell 3
136 BOEPD
1 Oil 10/11
2011 Sespe Highlights
5 Wells Drilled (Two 5-acre infill tests)
Estimated EURs: 150-200 MBoe/Well
1 Mile
st
st
st
st
st |
 August
2012 28
Oak Flat (10)
Frankel A (5)
Thornbury (10/5)
Coldwater Tests
“X”
SANDS ISOCHORE (Thickness)
Seneca Resources
Sespe Field –
2012 Drill Plan Builds Upon 2011 Successes
350’
Thick
(Medium Blue)
800’
Thick
(Dark Red)
~550’
Thick
(Green)
2012 Sespe Plans
6 Wells Planned (2 5-acre infill wells)
Estimated EURs: 140-170 MBoe/Well
1 Mile
Proposed Bottom Hole Locations |
 August
2012 Seneca Resources
29
Monterey Shale Play
Monterey Shale Play
Belridge Field
5 AMIs across the field
Seneca WI: 12.5%
Seneca NRI: 11.1%
Producing (Gross): 50 BOPD
3-4 Delineation Wells Planned
AMI Outlines
Gross Thickness of Monterey Interval |
 August
2012 Seneca Resources
30
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
Western Development Area
Net acreage:
~700,000 acres
Own most mineral rights
Minimal
royalty obligation
Minimal
lease expiration
Evaluating Marcellus rich-gas
NFG Storage Acreage
and Utica Shale potential
Tioga and Lycoming Counties |
 August
2012 Seneca Resources
31
Net Rig Count (Working Interest)
Seneca anticipates
minimal joint venture
activity in fiscal 2013
Seneca Resources -
Delineation
Seneca Resources -
Development
EOG Resources
0
4
6
8
10
Fiscal 2012 -
Q1
Fiscal 2012 -
Q2
Fiscal 2012 -
Q3
Current Rig
Count
Fiscal 2013
Forecast
2
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 |
 August
2012 Seneca Resources
32
Ramping Marcellus Shale Production
Seneca anticipates
ongoing curtailments of
production into TGP 300
due to low pricing basis
Covington
DCNR 595
DCNR 100
EOG JV
WDA/Other
Forecast
0
75
150
225 |
 August
2012 Seneca Resources
33
Eastern Development Area (EDA) –
Results & Plan Forward
DCNR Tract 100
17 Wells Drilled; 5 Wells Producing
FY2013: 1-2 Rigs Operating
Peak IPs: 10.1 to 16.1 MMcf per Day
Net Production: ~30 MMcf per Day
Average EUR: 10 Bcf
~20 MMcf per day of gross
production is curtailed due to
very low pricing basis on
uncontracted sales volumes
Covington
–
Fully
Developed
47 Wells Drilled and Producing
Net Production: ~55 MMcf per Day
Average EUR: 5.5 Bcf per Well
DCNR Tracts 007 & 001
Expiration Date: January 2020
DCNR Tract 595
33 Wells Drilled; 19 Wells Producing
FY2013: 0-1 Rigs Operating
Net Production: ~60 MMcf per Day
Average EUR: 7 Bcf per Well
SRC Fee Acreage
SRC Lease Acreage |
 August
2012 Seneca Resources
34
Evaluating Marcellus Wet Gas Potential
More
than
100,000
acres
within
the
targeted
window of 1,100 Btu to 1,200 Btu
Will
need
cryogenic
processing
plant
running
in “ethane rejection mode”
processing
SRC Lease Acreage
SRC Fee Acreage
EOG Acreage
Proposed Hz Well
Owl’s Nest (2 Wells)
Church Run (1 Well) |
 August
2012 35
Chesapeake
9.5 MMCFD
1,425 BLPD
Chesapeake
3.8 MMCFD
980 BLPD
Chesapeake
3.1 MMCFD
1,015 BLPD
Dry
Wet
Hess
11 MMCFD
Utica Shale –
Activity Summary
Seneca Resources
Vertical Well Drilled
Horizontal Well Permit
Horizontal Well Drilled
Mt. Jewett
Vertical: Tested Dry Gas
Horizontal: Completing Fall 2012
Henderson
Vertical Well
Tionesta
Horizontal: Completing Fall 2012
Owl’s Nest
Horizontal FY2013
Chesapeake
6.4 MMCFD
Rex
9.2 MMCFD |
 August
2012 Seneca Resources
36
Increased California Spending with Ongoing Marcellus Cuts
(1)
Does not include the $34.9 MM acquisition of Ivanhoe’s U.S.-based assets in
California, as this was accounted for as an investment in subsidiaries on the
Statement of Cash Flows, and was not included in Capital Expenditures
$31
$31
$47
~$50
$60-$75
$68
$71
$332
$585
$625-$640
$340-$425
$188
$398
$649
$675-$690
$400-$500
$0
$250
$500
$750
$1,000
2009
2010
2011
2012 Forecast
2013 Forecast
Fiscal Year
California
Upper Devonian
Marcellus/Utica
Gulf of Mexico
(1)
(1) |
 August
2012 Seneca Resources
37
Production Still Growing
20.1
19.8
19.2
20-21
20-22
8.7
9.3
7.9
7
5-7
7.2
35.3
54-57
67-76
13.7
13.3
5.2
42.5
49.6
67.6
81-85
92-105
0
25
50
75
100
125
150
2009
2010
2011
2012 Forecast
2013 Forecast
Fiscal Year
California
Upper Devonian
Marcellus/Utica
Gulf of Mexico |
 August
2012 National Fuel Gas Company
38
Appendix |
 August
2012 National Fuel Gas Company
39
Fiscal Year 2013 Earnings Guidance Drivers
2013 Forecast
GAAP Earnings per Share
$2.45 -
$2.75
Exploration & Production Drivers
Total Production (Bcfe)
92 -
105
DD&A Expense
$2.30 -
$2.40
LOE Expense
$0.90 -
$1.10
G&A Expense
$59 -
$63 MM
Pipeline & Storage Drivers
O&M Expense
+3%
Revenue
$255 -
$265 MM
Utility Drivers
O&M Expense
+3%
Normal Weather in PA |
 August
2012 National Fuel Gas Company
40
Manageable Debt Maturity Schedule
$250
$300
$250
$500
$49
$50
7.395%
7.375%
$0
$100
$200
$300
$400
$500
$600
Fiscal Year |
 August
2012 National Fuel Gas Company
41
Targeted Capital Structure
Long-Term Consolidated
Capital Structure Target
Capital Structure
Targets by Segment
Debt
35% -
45%
Equity
55% -
65%
40%
30%
50%
50%
60%
70%
50%
50%
All Other
E&P
P&S
Utility
Debt
Equity |
 August
2012 Pipeline & Storage / Midstream
42
Appendix |
 August
2012 Pipeline & Storage
43
Expansion Initiatives
Project Name
Capacity
(Dth/D)
Est.
CapEx
In-Service
Market
Status
Lamont Compressor Station
40,000
$6 MM
6/2010
Fully Subscribed
Completed
Lamont Phase II Project
50,000
$7.6 MM
7/2011
Fully Subscribed
Completed
Line “N”
Expansion
160,000
$22 MM
10/2011
Fully Subscribed
Completed
Tioga County Extension
350,000
$56 MM
11/2011
Fully Subscribed
Completed
Northern Access Expansion
320,000
~$75 MM
~11/2012
Fully Subscribed
Currently under construction
Line “N”
2012 Expansion
163,000
~$43 MM
~11/2012
Fully Subscribed
Currently under construction
Line “N”
2013 Expansion
30,000
~$4 MM
11/2013
OS Concluded
Negotiating with an anchor shipper for all
capacity
Mercer Expansion Project
150,000
~$30 MM
~6/2014
OS Concluded
In discussions with an anchor shipper
Central Tioga County
Extension
~260,000
~$135 MM
2014/2015
OS Concluded
In discussions with an anchor shipper
West to East
~425,000
~$290 MM
~2015
29% Subscribed
Marketing continues with producers in
various stages of exploratory drilling
Total Firm Capacity: ~1,948,000 Dth/D
Capital Investment: ~$669 MM |
 August
2012 Midstream Corporation
44
Expansion Initiatives
Project Name
Capacity
(Mcf/D)
Est.
CapEx
In-Service
Date
Market
Comments
Covington Gathering System
220,000
$54 MM
Multiple
Phases -
Most
In-Service
Capacity Available
[Marketing to
Third Parties]
Completed
–
Flowing into TGP 300
Line. This includes $30 million of
spending to build pipeline and
compression needed to connect
future wells.
Trout Run Gathering System
466,000
$130 MM
May 2012
Capacity Available
[Marketing to
Third Parties]
Completed
–
Flowing into Transco
Leidy Line. This includes $55
million of spending to build
pipeline and compression needed
to connect future 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: ~$294 MM |
 August
2012 Exploration & Production
45
Appendix |
 August
2012 National Fuel Gas Company
46
Hedge Positions and Strategy
Natural Gas
Swaps
Volume
(Bcf)
Average
Hedge Price
Fiscal 2012
(1)
12.4
$4.99 / Mcf
Fiscal 2013
46.7
$4.82 / Mcf
Fiscal 2014
27.4
$4.26 / Mcf
Fiscal 2015
17.8
$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 2012
(1)
0.4
$77.03 / Bbl
Fiscal 2013
1.5
$92.52 / Bbl
Fiscal 2014
0.6
$95.68 / Bbl
Most hedges executed at sales point to eliminate basis risk
(1)
Fiscal 2012 hedge positions are for the remaining three months of the fiscal year
Seneca has hedged approximately 57% of its
forecasted production for Fiscal 2013 |
 August
2012 Marcellus Shale
47
Western Development Area (WDA) –
Results & Plan Forward
Approx. Outline of JV Acreage
200,000 Gross Acres
Seneca 50% W.I. (Avg. 58% NRI)
Punxy (EOG Operated)
80 Wells Drilled; 55 Producing
FY2012: 1 Rig Operating
Gross Production: ~60 MMcf per Day
Owl’s Nest
Drilled 3 Horizontal Wells
Acquiring 3D Seismic
Potential 2013 Wet Gas Development
Expected IPs: 4-5 MMcf per Day
Mt. Jewett
Drilled 3 Horizontal Wells
IPs: 2.4 -
3.1 MMcf per Day
Boone Mountain
Drilled 3 Horizontal Wells
IPs: 3.8 -
4.6 MMcf per Day
Rich Valley
To be completed in
August 2012
Church Run
FY2012: 1 Well
To Test EUR & BTU Content
SRC Fee Acreage
SRC Lease Acreage
SRC Contributed JV Acreage
EOG Contributed JV Acreage
Seneca Operated
EOG Operated |
 August
2012 Marcellus Shale
48
Expanding 3D Seismic Coverage
Completed
In Progress
Punxy
West Branch
Mt. Jewett
DCNR 001
DCNR 007
Covington
DCNR 595
DCNR 100
Owl’s Nest |
 August
2012 Marcellus Shale
49
Targeting Continued Cost Reductions
$200
$300
$400
$500
$600
$700
$800
2010
2011
2012
Forecast
2013
Target
Drilling Cost per Lateral Foot
WDA/DCNR 595
DCNR 100
$100
$150
$200
$250
$300
$350
$400
2010
2011
2012
Forecast
2013
Target
Completion Cost per Stage ($000)
WDA/DCNR 595
DCNR 100 |
 August
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
Investigating underground injection
Seneca is committed to protecting the surface from any type of pollution
|
 August
2012 Marcellus Shale
51
“Zero Liquid Discharge Operation”
Utilizing a state-of-the-art evaporative technology to ensure no liquid is
discharged at the surface
Building a centrally located unit in Eastern Development Area (EDA)
Removes all liquids from the production stream
Has the ability to be powered by the waste heat from a compressor station
End products:
Non-hazardous solidified salt material
Clean water vapor emissions |
 August
2012 National Fuel Gas Company
52
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. |
Reconciliation of Segment Capital Expenditures to Consolidated Capital Expenditures
($ Thousands)
| FY 2009 | FY 2010 | FY 2011 | FY 2012 Forecast | FY 2013 Forecast | ||||||||||||
| Capital Expenditures from Continuing Operations |
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| Exploration & Production Capital Expenditures |
$ | 188,290 | $ | 398,174 | $ | 648,815 | $675,000-690,000 | $400,000-500,000 | ||||||||
| Pipeline & Storage Capital Expenditures - Expansion |
52,504 | 37,894 | 129,206 | $160,000-175,000 | $45,000-65,000 | |||||||||||
| Utility Capital Expenditures |
56,178 | 57,973 | 58,398 | $55,000-60,000 | $60,000-70,000 | |||||||||||
| Marketing, Corporate & All Other Capital Expenditures |
9,829 | 7,311 | 17,767 | $90,000-110,000 | $50,000-75,000 | |||||||||||
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| Total Capital Expenditures from Continuing Operations |
$ | 306,801 | $ | 501,352 | $ | 854,186 | $980,000-1,035,000 | $555,000-710,000 | ||||||||
| Capital Expenditures from Discountinued Operations |
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| All Other Capital Expenditures |
216 | $ | 150 | $ | — | $— | $— | |||||||||
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| Plus (Minus) Accrued Capital Expenditures |
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| Exploration & Production FY 2011 Accrued Capital Expenditures |
$ | — | $ | — | $ | (63,460 | ) | $— | $— | |||||||
| Pipeline & Storage FY 2011 Accrued Capital Expenditures |
— | — | (7,271 | ) | — | — | ||||||||||
| All Other FY 2011 Accrued Capital Expenditures |
— | — | (1,389 | ) | — | — | ||||||||||
| Exploration & Production FY 2010 Accrued Capital Expenditures |
— | (55,546 | ) | 55,546 | — | — | ||||||||||
| Exploration & Production FY 2009 Accrued Capital Expenditures |
(9,093 | ) | 9,093 | — | — | — | ||||||||||
| Pipeline & Storage FY 2008 Accrued Capital Expenditures |
16,768 | — | — | — | — | |||||||||||
| All Other FY 2009 Accrued Capital Expenditures |
(715 | ) | 715 | — | — | — | ||||||||||
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| Total Accrued Capital Expenditures |
$ | 6,960 | $ | (45,738 | ) | $ | (16,574 | ) | $— | $— | ||||||
| Eliminations |
$ | (344 | ) | $ | — | $ | — | $— | $— | |||||||
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| Total Capital Expenditures per Statement of Cash Flows |
$ | 313,633 | $ | 455,764 | $ | 837,612 | $980,000-1,035,000 | $555,000-710,000 | ||||||||
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Reconciliation of Exploration & Production West Division EBITDA to Exploration & Production Segment Net Income
($ Thousands)
| 9 Months Ended June 30, 2012 |
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| Exploration & Production - West Division EBITDA |
$ | 174,568 | ||
| Exploration & Production - All Other Divisions EBITDA |
111,944 | |||
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| Total Exploration & Production EBITDA |
$ | 286,512 | ||
| Minus: Exploration & Production Net Interest Expense |
(19,794 | ) | ||
| Minus: Exploration & Production Income Tax Expense |
(56,034 | ) | ||
| Minus: Exploration & Production Depreciation, Depletion & Amortization |
(136,262 | ) | ||
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| Exploration & Production Net Income |
$ | 74,422 | ||
| Exploration & Production Net Income |
$ | 74,422 | ||
| Exploration & Production - West Division Production (MBoe) |
2,581 | |||
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| Exploration & Production - Net Income per West Division Production (Boe) |
$ | 28.83 | ||
| Exploration & Production - West Division EBITDA |
$ | 174,568 | ||
| Exploration & Production - West Division Production (MBoe) |
2,581 | |||
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| Exploration & Production - West Division EBITDA per West Division Production (Boe) |
$ | 67.64 | ||
Reconciliation of EBITDA to Net Income
($ Thousands)
| FY 2008 | FY 2009 | FY 2010 | FY 2011 | 12 Months Ended June 30, 2012 |
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| Exploration & Production - West Division EBITDA |
$ | 188,008 | $ | 170,611 | $ | 187,838 | $ | 187,603 | $ | 223,155 | ||||||||||
| Exploration & Production - All Other Divisions EBITDA |
174,216 | 109,100 | 139,624 | 189,854 | 156,138 | |||||||||||||||
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| Total Exploration & Production EBITDA |
$ | 362,224 | $ | 279,711 | $ | 327,462 | $ | 377,457 | $ | 379,293 | ||||||||||
| Exploration & Production EBITDA |
$ | 362,224 | $ | 279,711 | $ | 327,462 | $ | 377,457 | $ | 379,293 | ||||||||||
| Utility EBITDA |
161,575 | 164,443 | 167,328 | 168,540 | 155,530 | |||||||||||||||
| Pipeline & Storage EBITDA |
129,171 | 130,857 | 120,858 | 111,474 | 128,372 | |||||||||||||||
| Energy Marketing EBITDA |
8,699 | 11,589 | 13,573 | 13,178 | 6,107 | |||||||||||||||
| Corporate & All Other EBITDA |
(8,156 | ) | (5,575 | ) | 2,429 | (2,960 | ) | 2,508 | ||||||||||||
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| Total EBITDA |
$ | 653,513 | $ | 581,025 | $ | 631,650 | $ | 667,689 | $ | 671,810 | ||||||||||
| Total EBITDA |
$ | 653,513 | $ | 581,025 | $ | 631,650 | $ | 667,689 | $ | 671,810 | ||||||||||
| Minus: Net Interest Expense |
(62,555 | ) | (81,013 | ) | (90,217 | ) | (75,205 | ) | (78,234 | ) | ||||||||||
| Plus: Other Income |
7,164 | 8,200 | 3,638 | 6,706 | 5,954 | |||||||||||||||
| Minus: Income Tax Expense |
(167,672 | ) | (52,859 | ) | (137,227 | ) | (164,381 | ) | (135,003 | ) | ||||||||||
| Minus: Depreciation, Depletion & Amortization |
(169,846 | ) | (170,620 | ) | (191,199 | ) | (226,527 | ) | (255,835 | ) | ||||||||||
| Minus: Exploration & Production Impairment |
(182,811 | ) | — | |||||||||||||||||
| Plus/Minus: Income/(Loss) from Discontinued Operations, Net of Tax |
1,821 | (2,776 | ) | 6,780 | — | — | ||||||||||||||
| Plus: Gain on Sale of Unconsolidated Subsidiaries |
— | — | — | 50,879 | — | |||||||||||||||
| Plus/Minus: Income/(Loss) from Unconsolidated Subsidiaries |
6,303 | 3,366 | 2,488 | (759 | ) | (61 | ) | |||||||||||||
| Minus: Impairment of Investment in Partnership |
— | (1,804 | ) | — | ||||||||||||||||
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| Net Income |
$ | 268,728 | $ | 100,708 | $ | 225,913 | $ | 258,402 | $ | 208,631 | ||||||||||