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| 8-K - 8-K - NATIONAL FUEL GAS CO | d861483d8k.htm |
 National Fuel Gas Company
Investor Presentation
January 2015
Exhibit 99 |
 National Fuel Gas Company
Safe Harbor For Forward Looking Statements
2
This presentation may contain “forward-looking statements”
as defined by the Private Securities Litigation Reform Act of 1995, including statements
regarding future prospects, plans, objectives, goals, projections, estimates of oil and
gas quantities, strategies, future events or performance and underlying assumptions, capital structure, anticipated
capital expenditures, completion of construction projects, projections for pension and other
post-retirement benefit obligations, impacts of the adoption of new accounting rules,
and
possible
outcomes
of
litigation
or
regulatory
proceedings,
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 are expressed in good faith and are believed by the Company to have a
reasonable basis, but there can be no assurance that management’s expectations, beliefs or projections will result or be
achieved or accomplished.
In addition to other factors, the following are important factors that, in the view of the
Company, could cause actual results to differ materially from those discussed 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;
the cost and effects of legal and administrative claims against the Company or activist
shareholder campaigns to effect changes at the Company; 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; governmental/regulatory actions, initiatives and proceedings, including those involving rate cases
(which address, among other things, target rates of return, rate
design and retained natural gas), environmental/safety requirements, affiliate relationships,
industry structure, and franchise renewal; changes in the price of natural gas or oil;
changes in price differentials between similar quantities of natural gas or oil sold at different geographic
locations, and the effect of such changes on commodity production, revenues and demand for
pipeline transportation capacity to or from such locations; other changes in price
differentials between similar quantities of natural gas or oil having different quality, heating
value, hydrocarbon mix or delivery date; 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;
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; changes in demographic patterns and weather
conditions; changes in the availability, price or accounting treatment of derivative financial
instruments; 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; 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; 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, 2014 and the Form
10-Q for the quarter ended December 31, 2014. 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
Our Business Mix Leads to Long-Term Value Creation
3
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.
Upstream
Natural Gas
Seneca Resources
Corporation
(West Division)
Seneca Resources
Corporation
(East Division)
The strategic, operational and financial benefits, along with capital
integrated mix of businesses continue to create significant
long-term value for the Company’s shareholders in nearly all
economic and commodity price scenarios
flexibility and consistent growth
opportunities, generated by this |
 NFG’s Unique Integration
4
NFG’s concentrated geographical footprint
differentiates our integrated structure and drives
distinct shareholder value creation opportunities
Common Geographic Footprint |
 FINANCIAL
EFFICIENCIES National Fuel Gas Company
Regulated Operations Provide Significant Synergies
5
OPERATIONAL SYNERGIES
Utility segment and Pipeline and Storage
segment share common:
COMMERCIAL RELATIONSHIPS
Utility segment and Energy Marketing segment
collectively hold 32% of Pipeline & Storage
contracted firm transportation and 46% of its
contracted storage capacity
•
Investment grade credit rating
•
Shared borrowing capacity
•
Consolidated tax return
•
Diversified cash flows support dividend
•
Management
•
Engineering services
•
Field labor
•
Facilities
•
Back office
•
Dispatch center
•
Materials warehouse
•
IT systems
•
Vehicles
•
Tools & equipment
Integration significantly reduces
operational and financing costs
and enhances the Company’s
navigate through volatile markets
and execute its long-term growth
strategy
financial strength and
flexibility to
|
 National Fuel Gas Company
Upstream and Midstream –
Common Vision For Growth
6
Western Development Area
Tier I Acreage: 200,000 Acres
High quality
Marcellus acreage
Connected to our
interstate pipeline
network
Pipeline capacity to premium
and alternate markets
Northern Access Projects
490 MMcf/d to Canada by 2016
Clermont Gathering System
NFG Supply & Other Interconnects |
 The Company has a
well-defined strategy to increase long-term value Integrated model provides
significant benefits in variety of market conditions Creating sustainable value for
shareholders remains our #1 priority NFG Focused on Long-Term
Value 7
•
Utility is a vital contributor to the consolidated financial strength of the Company
•
Regulated cash flows provide stability in challenging commodity price environment
•
Strong,
coordinated
emphasis
on
our
considerable
upstream
and
midstream
growth opportunities in Appalachia
•
We regularly evaluate structural alternatives as part of our ongoing assessment
of our strategic direction
•
We firmly believe our current strategy best positions us to deliver long-term
value to investors |
 National Fuel Gas Company
What Makes NFG Unique, Also Maximizes Value
8
Foundation of
Our Appalachian
Growth Strategy
Operational
Synergies
Strategic
Commercial
Relationships
Financial
Efficiencies
High Quality Assets
+ Lower Cost of Capital
+ Lower Operating Costs
+ Efficient Capital Spend
+ More Competitive Projects
+ Higher Free Cash Flow
+ Growing Dividend |
 National Fuel Gas Company
Targeting Sustained EBITDA Growth over the next Five Years
9
Exploration & Production Segment
Gathering Segment
Pipeline & Storage Segment
Utility Segment
Energy Marketing & Other
$0
$250
$500
$750
$1,000
$1,250
$327
$377
$397
$492
$539
$539
$632
$668
$704
$852
$953
$963
$167
$169
$160
$165
$163
$121
$111
$137
$161
$186
$187
$30
$64
$73
2010
2011
2012
2013
2014
TTM
12/31/14
Fiscal Year
$172
Note: A reconciliation of Adjusted EBITDA to Net Income as presented on the Consolidated Statement of
Income and Earnings Reinvested in the Business is included at the end of this presentation. |
 National Fuel Gas Company
Capital Spending Adjusts to Capitalize on Opportunities
10
Note: A reconciliation to Capital Expenditures as presented on the Consolidated Statement of
Cash Flows is included at the end of this presentation. $1,500
$1,250
$1,000
$750
$500
$250
$0
2010
2011
2012
2013
2014
2015E
$501
$854
$977
$717
$970
$990 -
1,155
$115-$130
$89
$72
$58
$58
$58
$38
$129
$144
$80
$55
$56
$138
$140
$125-$175
$225-$275
$525-$575
$603
533
$694
$649
$398
Exploration & Production Segment
Gathering Segment
Pipeline & Storage Segment
Utility Segment
Energy Marketing & Other
Fiscal Year |
 National Fuel Gas Company
Maintaining a Strong Balance Sheet
11
Total Debt
(1)
41%
$4.4 Billion
As of December 31, 2014
Debt/Adjusted EBITDA
Capitalization
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 and short-term debt of $172.9 million
1.98 x
1.75 x
1.89 x
1.89 x
1.77 x
1.80 x
0.0
0.5
1.0
1.5
2.0
2.5
2010
2011
2012
2013
2014
TTM
12/31/14
Fiscal Year
Shareholders’
Equity
59% |
 National Fuel Gas Company
Dividend Track Record
12
(1)
As of January 26, 2015
$2.00
$1.50
$1.00
$0.50
$0.00
Annual Rate at Fiscal Year End
Dividend Consistency
Consecutive Dividend Payments
Consecutive Dividend Increases
Current Annualized Dividend Rate
112 Years
44 Years
$1.54 per Share
Current
Dividend
Yield
(1)
2.3% |
 13
Exploration & Production
Overview |
 (1)
Represents a three-year average U.S. finding and development cost
Fiscal
Years
3-Year
F&D Cost
(1)
($/Mcfe)
2007-2009
$5.35
2008-2010
$2.37
2009-2011
$2.09
2010-2012
$1.87
2011-2013
$1.67
2012-2014
$1.38
45.2
43.3
42.9
41.6
38.5
428
675
988
1,300
1,683
700
935
1,246
1,549
1,914
0
500
1,000
1,500
2,000
2010
2011
2012
2013
2014
At September 30
Natural Gas (Bcf)
Crude Oil (MMbbl)
2014 F&D Cost = $1.15
Marcellus F&D: $1.00
327% Reserve
Replacement Rate
73% Proved Developed
Seneca Resources
Proven Record of Growth
14 |
 Seneca Resources
Delivering Tremendous Production Growth
15
225
150
75
0
2010
2011
2012
2013
2014
2015E
Fiscal Year
49.6
67.6
83.4
120.7
160.5
155-190
13.3
16.5
19.8
19.2
20.5
20.0
21.2
21-23
43.2
62.9
100.7
139.3
134-167
Gulf of Mexico (Divested in 2011)
East Division
West Division |
 Seneca Resources
Disciplined Capital Spending
16
$28
$47
$63
$105
$83
$40-$50
$356
$596
$631
$428
$520
$485-
$525
$398
$649
$694
$533
$603
$525-
$575
$0
$200
$400
$600
$800
$1,000
2010
2011
2012
2013
2014
2015E
Fiscal Year
Gulf of Mexico (Divested in 2011)
East Division
West Division |
 Seneca Resources
LOE: Operating Costs down; Transportation Costs up
17
(1)
Represents the midpoint of current General & Administrative Expense guidance of $0.40 to
$0.45 per Mcfe for fiscal 2015 (2)
The total of the two LOE components represents the midpoint of current LOE guidance of $1.00
to $1.10 per Mcfe for fiscal 2015 (3)
The cost of firm transportation is reflected in price realizations (a deduction to gross
revenues). As such, it is not included in LOE. (2)
$4.00
$3.00
$2.00
$1.00
$0.00
2010
2011
2012
2013
2014
2015E
$2.23
$2.09
$2.01
$1.74
$1.65
$1.65
Property, Franchise & Other Taxes
Other O&M Expense
General & Administrative Expense
Lease Operating & Transportation Expense (Gathering Only)
Lease Operating & Transportation Expense (Excl. Gathering)
(3)
Fiscal Year
$0.64
$0.73
$0.65
$0.52
$0.40
$0.43
$0.17
$0.24
$0.34
$0.46
$0.51
$1.17
$0.91
$0.76
$0.65
$0.57
$0.54
(1)
(2)
$0.21
$0.18
$0.28
$0.14
$0.13
$0.10 |
 Marcellus Shale
Prolific Pennsylvania Acreage
18
720,000
Acres
60,000
Acres
Average net revenue interest (NRI): 98%
No lease expiration
No royalty on most acreage
Highly contiguous
Significant economies of scale
1,700 to 2,000 locations de-risked
Seneca Lease
Seneca Fee
Mostly leased (16-18% royalty)
No near-term lease expiration
Limited development drilling until firm
transportation capacity on Atlantic
Sunrise becomes available in late 2017
Drilling activity will HBP key acreage
Eastern
Development
Area
(EDA)
Western
Development
Area
(WDA) |
 Marcellus Shale
EDA Delivering Significant Growth
19
Covington
–
Fully
Developed
DCNR Tract 595
DCNR Tract 100
Gamble
(1)
One well included in this total is drilled into and producing from the Geneseo Shale
DCNR Tract 007
Utica & Marcellus delineation wells
Results expected 1H FY2015
Productive Capacity: ~45MMcf per Day
47 Wells Drilled and Producing
Productive Capacity: ~115 MMcf per Day
45
Wells
Drilled
(52
Total
Locations)
44
Wells
Producing
Productive Capacity: ~380 MMcf per Day
58
Wells
Drilled
(70
Total
Locations)
58
Wells
Producing
Opportunity for Geneseo development
30 to 50 future locations
3 Wells Drilled; 1 Well Producing
Opportunity for Geneseo development
(1)
(1)
(1)
(1) |
 Marcellus Shale
EDA –
Historical Well Results are Exceptional
20
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
5.8
4,023’
1.44
Tract 595
Tioga
County
43
(1)
7.4
6.1
5.2
8.1
4,765’
1.70
Tract 100
Lycoming
County
57
(1)
16.8
14.8
12.6
12.6
5,270’
2.39
(1)
Does not include a well drilled into and producing from the Geneseo Shale
|
 Marcellus Shale
Focusing on WDA Development
21
Note: Assumes 6,000’
treated lateral length
Seneca’s Tier I Acreage:
200,000 Acres
6-8 Bcfe EUR Wells
Economic
at
$2.60
to
$4.00/MMbtu
4 -
6 BCF/well
6 -
8 BCF/well
4 -
6 BCF/well
2-4 BCF/well
2-4 BCF/well
SRC Fee Acreage
SRC Lease Acreage
EOG Earned JV Acreage |
 Marcellus Shale
Strong Wells Currently Producing Across WDA Acreage
22
Area
Producing Well
Count
Peak 24-Hour
Rate (MMcfd)
Average
7-Day (MMcf/d)
Average Treatable
Lateral Length (ft)
Clermont/Rich Valley
Elk, Cameron & McKean
counties
19
8.1
7.2
5,710’
WDA Development Areas:
WDA Delineation Areas:
Area
Producing Well
Count
Peak 24-Hour
Rate (MMcfd)
Average
7-Day (MMcf/d)
Average Treatable
Lateral Length (ft)
Ridgway
Elk County
1
7.1
6.4
5,537’
Church Run
Elk & Jefferson counties
2
4.8
4.5
4,690’
Hemlock
Elk County
2
5.4
5.2
7,067’
Owl’s Nest
Elk & Forest counties
1
6.1
5.8
6,137’
Sulger Farms
Jefferson County
1
6.1
5.6
5,778’ |
 Marcellus Shale
Clermont/Rich Valley (CRV) Area
23
Planned Wells
Drilled Wells
Producing Wells
Pad H
6 Wells
Ave. IP: 8.0 MMCFD
Pad N
9 Wells
Ave. IP: 8.2 MMCFD
Clermont/Rich Valley
200-250
Planned
Horizontal
Locations
Productive
Capacity:
19
Wells;
~
60
MMcfd
Pad C8-F
Completing
Pad C8-G
Drilling
Pad D9-D
6 Wells
Completed
SRC Lease Acreage
SRC Fee Acreage
Marcellus Faults
Marcellus & Basement Faults |
   Marcellus Shale
~2,000 Economic WDA Locations Below $4/MMBtu
24
Prospect
Product
Locations
Remaining to
Be Drilled
Completed
Lateral
Length (ft)
EUR
Assumption
(MMcf)
BTU
$4.50
Dawn/Nymex
(% IRR)
$4.00
Dawn/Nymex
(% IRR)
15% IRR
Realized Price
DCNR 100
Dry Gas
13
5,582
13,540
1030
>100%
74%
$1.84
Gamble
Dry Gas
28
4,605
11,240
1030
72%
50%
$2.08
DCNR 595
Dry Gas
8
4,475
6,890
1030
46%
33%
$2.28
Clermont - Rich Valley
Dry Gas
148
7,000
7,817
1050
42%
28%
$2.60
Hemlock
Dry Gas
157
7,000
7,000
1050
35%
24%
$2.78
Ridgway
Dry Gas
564
7,000
6,300
1111
31%
21%
$2.90
Remaining Tier 1
Dry Gas
1,020
7,000
6,000
1030 - 1100
$3.00 -
$4.00
Future Resource
Dry & Wet
Gas
1,620
7,000
6,000
1030 - 1350
>$4.00
Additional Delineation Required
(1)
(1)
Internal Rate of Return (IRR) includes estimated well costs under current cost structure, LOE,
and Gathering tariffs anticipated for each prospect. |
 Marcellus Shale
WDA Mineral Interests Significantly Enhance Returns
25
In Clermont/Rich Valley, a typical producer burdened by a
15%
royalty
would
require
a
$0.46
higher
net
realized
price
to achieve same level of economics as Seneca Resources
(1)
Clermont/Rich Valley Example
($/Mcf)
Typical
Producer
15% Royalty
Average Net Realized Price
$ 3.06
Less: Cash Operating Expenses
(0.65)
Less: Royalty Payment
(0.46)
Cash Margin
$ 1.95
Before Tax IRR
(1)
15%
The Seneca
Advantage
0% Royalty
$ 2.60
(0.65)
(0.00)
$ 1.95
15%
Internal Rate of Return (IRR) includes estimated well costs under current cost structure, LOE,
and Gathering tariffs anticipated for each prospect. |
 Natural Gas Marketing
How Does Seneca Sell its Production?
26
Well Head
Interconnection
with Interstate
Pipeline Network
Gathering
System
3rd Party
Marketer
(or spot market)
Firm Transport
Demand Center
(firm sales or
spot market)
Contracted Basis
Differential
FT Rate
Breakeven economics based on a
realized price after gathering
Spot Market |
 Natural Gas Marketing
Adding Long-Term Firm Transport to the Portfolio
27
(1)
A
large majority of the executed firm sales agreements continue for the remainder of the
firm transportation contract term.
Project
(Counterparty)
In-
Service
Date
Contract
Term
Delivery
Market
FT Capacity (Dth/day)
Matched Firm
Sales
Fiscal
2015
Fiscal
2016
Fiscal
2017
Fiscal
2018
Northeast Supply
Diversification
Project (TGP)
Nov.
2012
15 years
Canada
50,000
50,000
50,000
50,000
Executed Contracts
50,000 Dth/d
for 10 years
Niagara
Expansion/
TETCO (TGP & NFG)
Nov.
2015
15 years
Canada/
TETCO
---
170,000
170,000
170,000
Executed Contracts
140,000 Dth/d
for 15 years
Northern Access
2016 (NFG/
TransCanada/
Union)
Nov.
2016
15 years
Canada
---
---
350,000
350,000
Evaluating
marketing
opportunities
Atlantic Sunrise
(Transco)
Nov.
2017
15 years
Mid-
Atlantic/
Southeast
---
---
---
189,405
Executed Contracts
189,405 Dth/d
for first 5 years
(1)
Total Firm Transportation Capacity
50,000
220,000
570,000
759,405 |
 Natural Gas Marketing
Significant Base of Long-Term Firm Contracts
28
Atlantic Sunrise
189,405 Dth/d
Northern Access 2016
350,000 Dth/d
Niagara Expansion
TETCO
170,000 Dth/d
1,000
750
500
250
-
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
Base Firm Sales Contracts
Firm Sales Matched to Firm Transport Capacity
Additional Firm Transport Capacity
Fiscal Year |
 Natural Gas Marketing
Firm Sales Provide a Market for Appalachian Production
29
Values shown represent the price or differential to a reference
price (netback price) at the first non-affiliated interstate pipeline,
including the cost of all related downstream transportation
29
EDA
(1)
320,098 Dth/d
280,036 Dth/d
280,036 Dth/d
WDA
(1)
61,427 Dth/d
60,000 Dth/d
60,000 Dth/d
Dominion
95,327
Less: $0.42
Dominion
85,000
Less: $0.47
Dominion
85,000
Less: $0.47
NYMEX
236,198
Less: $0.51
NYMEX
205,036
Less: $0.59
NYMEX
205,036
Less: $0.59
50,000
Fixed $3.77
50,000
Fixed $3.77
50,000
Fixed $3.77
381,525
340,036
340,036
0
100,000
200,000
300,000
400,000
500,000
Fixed Price
NYMEX
Dominion South Point
(1)
EDA and WDA carry an average net revenue interest (NRI) of 82% - 84% and 98%,
respectively. Q2
FY 2015
Q3
FY 2015
Q4
FY 2015 |
 Natural Gas Marketing
Current Natural Gas Hedge Positions
30
(1)
For the remaining nine months of fiscal 2015.
100
75
50
25
0
2015
2016
2017
2018
Fiscal Year
68.7
65.7
46.8
5.6
18.6
18.8
12.7
NYMEX
Dominion
Dawn & MichCon
SoCal
14.5
5.6
49.1
32.4
23.1
11.0 |
 Natural Gas Marketing
FY 2015 Production –
Firm Sales & Hedge Composition
31
(1)
Spot price assumptions reflected in fiscal 2015 earnings guidance range
(2)
Indicates firm sales not backed by financial hedges
Firm Sales with Price Certainty
76.5 Bcf at ~$3.70/Mcf
Spot Price Exposure
27 Bcf at $2.00-$2.25/Mcf
(1)
2.7 Bcf
(2)
1.7 Bcf
(2)
42.9 Bcf
47.4 Bcf
18 Bcf
11.1 Bcf
8.6 Bcf
18.6 Bcf
134-167 Bcf
0
100
150
200
Q1
East Division
Production
NYMEX
Firm Sales
DOM
Firm Sales
Fixed Price
Sales
WDA
Spot Sales
EDA
Total Spot Sales
East Division
Production
50 |
 Utica Shale
Seneca Activity in Tioga County
32
Seneca -
Tionesta
Horizontal: Completed Fall 2012
Peak 24-Hour Rate: 3.9 MMcf/d
Seneca -
Mt Jewett
Horizontal: Completed September 2013
Peak 24-Hour Rate: 8.5 MMcf/d
Seneca -
DCNR 007
Completing
Shell
26 MMcf/d
Shell
11 MMcf/d |
 California
Stable Production Fields; Modest Growth Potential
33
East Coalinga
Temblor Formation
Primary
North Lost Hills
Tulare & Etchegoin Formation
Primary/Steamflood
South Lost Hills
Monterey Shale
Primary
North Midway Sunset
Tulare & Potter Formation
Steamflood
South Midway Sunset
Antelope Formation
Steamflood
Sespe
Sespe Formation
Primary
Key Areas of Focus in 2015:
(1) LTM reflects the twelve month period ending 12/31/2014.
North
Midway
Sunset
South
Midway
Sunset
South Lost
Hills
North Lost
Hills
Sespe
East
Coalinga
1.
South Midway Sunset Extensions
2.
East Coalinga Evaluation
3.
South Lost Hills Monterey Evaluation |
 California
South Midway Sunset Has Delivered Significant Growth
34
252 Pool
97X Pool
SE Pool
251 Pool
B Pool
A Pool
Extended Pool Boundary
Original Pool Boundary
Existing Wells
1000’
16X Pool
Seneca Acquired
in June 2009
Highlights Since Acquisition
Significantly increased daily production
Drilled 114 new producers
Added 3.3 MMBO of proven reserves
Increased steam capacity by 420%
Identified opportunities for additional
pool development |
 California
East Coalinga Summary
35
Production has increased from 214 BOPD to
750 BOPD
Drilled 31 new producers and 1 water
disposal well in 2014
Plan to drill 5 wells in 2015
Evaluating potential of undeveloped Upper
Temblor heavy oil reservoir in Section 28
Seneca Acquired
in January 2013 |
 California
Evaluating the Monterey Shale at South Lost Hills
Citrus 11
Upper Antelope A
Upper Antelope B
McDonald
Truman 1H
2013
190 BOEPD
Citrus 2H
2014
100 BOEPD
Truman 2H
Currently
Installing
Artificial Lift
GR
SP
ResD
Brittleness
Gas
Oil
18 potential locations in
each of the three
horizons (concept)
Seneca Lease
Lower Reef Ridge
1000’
36 |
 California
Modest Growth Opportunities, But Strong Economics
37
Field
Average
Well Cost
Average
EUR
(MBO)
Estimated
IRR
@$55/Bbl
Fiscal 2015
Locations
South Midway Sunset
$250,000
39
57%
36
North Midway Sunset
$300,000
30
25%
15
East Coalinga
$420,000
29
15%
5 |
 California
Modest Growth Anticipated in 2015
38
9,056
8,773
9,322
9,078
9,699
9,800-
10,200
7,000
8,000
9,000
10,000
11,000
2010
2011
2012
2013
2014
2015
Forecast
Fiscal Year |
 California
Strong Margins Support Significant Free Cash Flow
39
Average Revenue
for TTM 12/31/14
$84.26 per BOE
$12.98
$4.77
$3.99
$3.15
$1.72
$57.65
Non-Steam Fuel LOE
Steam Fuel
G&A
Production & Other Taxes
Other Operating Costs
EBITDA
12-months ended 12/31/14 EBITDA per BOE
Note: A reconciliation of Exploration & Production West Division EBITDA to Exploration
& Production Segment Net Income is included at the end of this presentation. |
 40
Midstream Businesses
Overview |
 Midstream Businesses
Positioned to Serve Rapidly Growing Production in Appalachia
41 |
 Gathering
Gathering is the First Step to Reaching a Market
42
TGP 300
Transco
Trout Run
Gathering System
(In-Service)
Covington
Gathering System
(In-Service)
Clermont
Gathering System
(In-Service)
Gathering Interconnects
(1)
Fiscal 2015 estimated revenue reflects projected throughput based on the range of
Seneca’s Fiscal 2015 production guidance (155-190 Bcfe) (1)
$34.8
$70.6
$75 -
$95
$0
$30
$60
$90
$120
2010
2011
2012
2013
2014
2015E
Fiscal Year
Gathering Segment Revenue |
 Gathering
Gathering Systems Supporting Seneca’s EDA Production
43
Covington Gathering System
In-Service Date: November 2009
Capacity: 220,000 Dth per day
Interconnect: TGP 300
Capital Expenditures (to date): $32 Million
Trout Run Gathering System
In-Service Date: May 2012
Capacity: 466,000 to 585,000 Dth per day
Interconnect: Transco
–
Leidy Lateral
Capital Expenditures (to date): $162 Million
Interconnects
(1)
Fiscal 2015 estimated throughput reflects the midpoint of Seneca’s Fiscal 2015
production guidance range (155-190 Bcfe) (1)
2010
2011
2012
2013
2014
2015E
Covington
Trout Run
0
25
50
75
100
125
150
7.0
30.9
44.7
51.0
48.3
41
5.3
45.0
103
87.4
Fiscal Year Throughput by Project
(Covington & Trout Run Systems) |
 Gathering
Clermont Gathering System has Large Expandability
44
Clermont Gathering
System
In-Service: July 2014
Ultimate Trunkline Capacity:
1+ Bcf per day
Interconnects
TGP 300 (current)
NFG Supply Corporation
(Northern Access 2016)
Capital Expenditures:
To date: $115 Million
2015
(1)
: $95 -
$135 Million
Compressor Station
Interconnect
(1)
For the remaining nine months of fiscal 2015. |
 Pipeline & Storage
Project Opportunities to Support Appalachian Growth
45
Develop multiple outlets
to high-value markets |
 Pipeline & Storage
Expansions to Move Gas from the WDA Are Significant
46
Projects to Support WDA Growth
Project
Capacity
(Dth/day)
Northern Access 2015
140,000
Northern Access 2016
350,000
Total New Capacity
490,000
Project
Capital Cost
Northern Access 2015
$66 Million
Northern Access 2016
$449 Million
Total Capital
Expenditures
$515 Million
Northern
Access 2015
(November 2015)
Northern
Access 2016
(Late 2016) |
 Pipeline & Storage
Major Expansion Designed for Canadian Deliveries
47
Customer: Seneca Resources
In-Service: November 2015
System: NFG Supply Corp.
Capacity: 140,000 Dth per day
Lease to TGP as part of their
Niagara Expansion project
Interconnect
Niagara (TransCanada)
Total Cost: $66 Million
Major Facilities
23,000 HP Compression
Northern Access 2015
Northern
Access 2015
(November 2015) |
 Pipeline & Storage
Northern Access 2016 Provides Additional Access to Canada
48
Customer: Seneca Resources
In-Service: Late 2016
System: NFG Supply Corp. &
Empire Pipeline, Inc.
Capacity
350,000 Dth per day
Interconnect
Chippawa (TransCanada)
Total Cost: ~$449 Million
FERC Timing
Pre-filing: July 2014
Certificate filing: anticipated
Q2 FY2015
Northern Access 2016
Northern
Access 2016
(Late 2016) |
 Pipeline & Storage
Recent 3
rd
Party Expansions Have Been Highly Successful
49
Completed Expansions
for 3
Parties
Capacity (Dth/day)
Northern Access 2012
320,000
Tioga County Extension
350,000
Line N & Mercer Expansion
458,000
Total New Capacity
1,128,000
Capital Cost ($Millions)
Northern Access 2012
$72
Tioga County Extension
$58
Line N & Mercer Expansion
$138
Total Capital Expenditures
$268
Northern
Access 2012
Tioga County
Extension
Line N Projects
Annual Reservation Charges ($Millions)
Northern Access 2012
$14.5
Tioga County Extension
$41.9
Line N & Mercer Expansion
$21.3
Total Reservation Charges
$77.7
rd |
 Mercer
(TGP Station 219)
Pipeline & Storage
Pairing Line N Expansions with System Modernization
50
In-Service: November 2015
System: NFG Supply Corp.
Capacity: 175,000 Dth per day
Range Resources (145,000 Dth/d)
Seneca Resources (30,000 Dth/d)
Interconnect
Mercer (TGP Station 219)
Holbrook (TETCO)
Total Cost: $86 Million
Expansion: $45 Million
Modernization: $41 Million
Major Facilities
3,550 HP Compressor
23.3 miles –
24”
Replacement Pipe
Westside Expansion &
Modernization
Holbrook (TETCO)
Westside
Expansion &
Modernization |
 Pipeline & Storage
Developing Unique Solutions for Shippers
51
In-Service: November 2015
System: NFG Supply & Empire Pipeline
New No-Notice Services
Precedent agreements executed with
RG&E, NYSEG & NFG Utility
Preserving 172,500 Dth per day (RG&E)
Preserving 20,000 Dth per day (NYSEG)
Retained Storage: 3.3 Bcf
New incremental transportation
capacity of 49,000 Dth per day
Interconnect
Tuscarora (NFG/Supply)
Total Cost: $58.5 Million
Major Facilities
1,384 HP Compressor
17 miles –
12”/16”
Pipeline
Tuscarora Lateral
Tuscarora
Lateral |
 Pipeline & Storage
Significant Expansions Are Driving Growth
52
Completed Projects (Since 2009)
Recent Capacity
Additions
1,128,000 Dth/day
Planned Projects (2015+)
Precedent Agreements Executed
Total Expansion (2009-2016+)
Capacity
Additions
1,932,000 Dth/day
In-Service 2015
364,000 Dth/day
In-Service 2016+
350,000 Dth/day
Delivering Gas North
Tioga County Extension
Northern Access 2012
Northern Access 2015
Northern Access 2016
Total Capacity
1,160 MDth/d
Other Projects
Lamont Compressor
Tuscarora Lateral
Total Capacity
139 MDth/d
Line N Corridor
Line “N”
Expansion
Line “N”
2012 Expansion
Line “N”
2013 Expansion
Mercer Expansion
West Side Expansion
Total Capacity
633 MDth/d |
 53
Utility
Overview |
 Utility
New York & Pennsylvania Service Territories
54
Revenue Decoupling
Weather Normalization
Low Income Rates
90/10 Sharing (Large Customers)
Rates Unchanged
9.1% ROE Confirmed
2-Tier Earnings Sharing Mechanism
9.5% to 10.5% -
Share 50%
10.5% > -
Share 80%
$8.2 MM CapEx -
system replacement
Low Income Rates
Merchant Function Charge
NY PSC Rate Case Settlement, May 2014
Natural Gas Vehicle Pilot Program
Total Customers: 213,500
Rate Mechanisms:
ROE: Black Box Settlement (2007)
Rate Mechanisms:
Total Customers: 524,300
Merchant Function Charge (Uncollectibles
Adjustment)
$8.0 MM incremental O&M (post-
retirement benefits)
New York
Pennsylvania |
 Utility
Shifting Trends in Customer Usage
55
Residential Usage
Industrial Usage
(1)
Weighted Average of New York and Pennsylvania service territories (assumes normal
weather) 80
90
100
110
120
15
20
25
30
35
12-Months Ended December 31
12-Months Ended December 31 |
 Utility
A Proven History of Controlling Costs
56
$154
$152
$152
$152
$151
$154
$13
$16
$16
$20
$33
$31
$14
$11
$9
$6
$10
$10
$181
$179
$177
$178
$193
$195
$0
$100
$150
$200
$250
2010
2011
2012
2013
2014
12 Months
Ended
Fiscal Year
All Other O&M Expenses
O&M Pension Expense
O&M Uncollectible Expense
$50
12/31/14 |
 Utility
Strong Commitment to Safety
57
The Utility remains focused on maintaining the ongoing
safety and reliability of its system
Near-term increase due
to ~$60MM upgrade of
the Utility’s Customer
Information System and
~$25MM NRG Dunkirk
power plant project
$45.0
$44.3
$43.8
$48.1
$49.8
$58.0
$58.4
$58.3
$72.0
$88.8
$115 -
$130
$0
$30
$60
$90
$120
$150
2010
2011
2012
2013
2014
2015E
Fiscal Year
Capital Expenditures for Safety
Total Capital Expenditures |
 58
Appendix |
 National Fuel Gas Company
Natural Gas Hedge Positions
59
(Volumes in thousands Mmbtu; Prices in $/Mmbtu)
Fiscal 2015
(1)
Fiscal 2016
Fiscal 2017
Fiscal 2018
Volume
Avg.
Price
Volume
Avg.
Price
Volume
Avg.
Price
Volume
Avg.
Price
NYMEX Swaps
49,130
$4.18
32,350
$4.24
23,130
$4.50
5,550
$4.59
Dominion
Swaps
18,630
$3.74
18,840
$3.78
12,720
$3.87
-
-
SoCal Swaps
900
$4.35
-
-
-
-
-
-
MichCon
Swaps
-
-
9,000
$4.10
3,000
$4.10
-
-
Dawn Swaps
-
-
5,490
$4.36
7,950
$4.14
-
-
Fixed Price
Physical Sales
13,650
$3.77
18,300
$3.77
18,250
$3.77
1,550
$3.77
Total
82,310
$4.01
83,980
$4.03
65,050
$4.11
7,100
$4.41
(1)
For the remaining nine months of fiscal 2015. |
 National Fuel Gas Company
Crude Oil Hedge Positions
60
Fiscal 2015
(1)
Fiscal 2016
Fiscal 2017
Fiscal 2018
Volume
Avg.
Price
Volume
Avg.
Price
Volume
Avg.
Price
Volume
Avg.
Price
Midway
Sunset
(MWSS)
Swaps
108,000
$92.10
36,000
$92.10
-
-
-
-
Brent
Swaps
765,000
$98.32
933,000
$95.18
384,000
$92.30
75,000
$91.00
NYMEX
Swaps
297,000
$90.14
300,000
$86.09
-
-
-
-
Total
1,170,000
$95.67
1,269,000
$92.95
384,000
$92.30
75,000
$91.00
(Volumes & Prices in Bbl)
(1)
For the remaining nine months of fiscal 2015. |
 Geneseo Shale
Path to Geneseo Development –
2018/2019 Start
61
1 Well (Tract 100 –
Pad N)
Peak IP: 14.1 MMcf per day
30-Day Average Rate: 8.6 MMcf per day
Estimated EUR: 7.0 Bcf
Lateral Length: 4,920’
Frac Stages: 33 stages
Current developed infrastructure from DCNR
100 & Gamble:
13 well pads
3 compressor pads
3 water impoundments
Gathering infrastructure
Savings estimate of ~$300,000 per well from
shared infrastructure
•
>125 Wells
•
Water Infrastructure = $13MM
•
Usable Pads = $16MM
•
Road Infrastructure = $16MM
Tract 100/Gamble (Lycoming County)
Geneseo Well
st |
 National Fuel Gas Company
Comparable GAAP Financial Measure Slides and Reconciliations
62
This presentation contains certain non-GAAP financial measures. For pages
that contain non-GAAP financial measures, pages containing the most directly
comparable GAAP financial measures and reconciliations are provided in the
slides that follow.
The Company believes that its non-GAAP financial measures are useful to
investors because they provide an alternative method for assessing the
Company’s ongoing operating results, for measuring the Company’s cash flow
and liquidity, and for comparing the Company’s financial performance to
other companies. The Company’s management uses these non-GAAP financial
measures for the same purpose, and for planning and forecasting purposes.
The presentation of non-GAAP financial measures is not meant to be a
substitute for financial measures prepared in accordance with GAAP.
The Company defines Adjusted EBITDA as reported GAAP earnings before the
following items: interest expense, depreciation, depletion and amortization,
interest and other income, impairments, items impacting comparability and
income taxes. |
 63
Reconciliation of Adjusted EBITDA to Consolidated Net Income
($ Thousands)
FY 2010
FY 2011
FY 2012
Exploration & Production - West Division Adjusted EBITDA
187,838
$
187,603
$
226,897
$
215,042
$
217,150
$
206,875
$
Exploration & Production - All Other Divisions Adjusted EBITDA
139,624
189,854
170,232
277,341
322,322
332,332
Total Exploration & Production Adjusted EBITDA
327,462
$
377,457
$
397,129
$
492,383
$
539,472
$
539,207
$
Total Adjusted EBITDA
Exploration & Production Adjusted EBITDA
327,462
$
377,457
$
397,129
$
492,383
$
539,472
$
539,207
$
Pipeline & Storage Adjusted EBITDA
120,858
111,474
136,914
161,226
186,022
186,799
Gathering Adjusted EBITDA
2,021
9,386
14,814
29,777
64,060
73,437
Utility Adjusted EBITDA
167,328
168,540
159,986
171,669
164,643
162,779
Energy Marketing Adjusted EBITDA
13,573
13,178
5,945
6,963
10,335
12,359
Corporate & All Other Adjusted EBITDA
408
(12,346)
(10,674)
(9,920)
(11,078)
(11,515)
Total Adjusted EBITDA
631,650
$
667,689
$
704,114
$
852,098
$
953,454
$
963,066
$
Total Adjusted EBITDA
631,650
$
667,689
$
704,114
$
852,098
$
953,454
$
963,066
$
Minus: Net Interest Expense
(90,217)
(75,205)
(82,551)
(89,776)
(90,107)
(88,818)
Plus: Other Income
6,126
5,947
5,133
4,697
9,461
10,416
Minus: Income Tax Expense
(137,227)
(164,381)
(150,554)
(172,758)
(189,614)
(189,349)
Minus: Depreciation, Depletion & Amortization
(191,199)
(226,527)
(271,530)
(326,760)
(383,781)
(393,414)
Plus/Minus: Income/(Loss) from Discontinued Operations, Net of Tax (Corp. & All Other)
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
-
-
-
Minus: Pennsylvania Impact Fee Related to Prior Fiscal Years (E&P)
-
-
(6,206)
-
-
-
Minus: New York Regulatory Adjustment (Utility)
-
-
-
(7,500)
-
-
Rounding
-
-
(1)
-
-
-
Consolidated Net Income
225,913
$
258,402
$
220,077
$
260,001
$
299,413
$
301,901
$
Consolidated Debt to Total Adjusted EBITDA
Long-Term Debt, Net of Current Portion (End of Period)
1,049,000
$
899,000
$
1,149,000
$
1,649,000
$
1,649,000
$
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
-
85,600
172,900
Total Debt (End of Period)
1,249,000
$
1,089,000
$
1,570,000
$
1,649,000
$
1,734,600
$
1,821,900
$
Long-Term Debt, Net of Current Portion (Start of Period)
1,249,000
1,049,000
899,000
1,149,000
1,649,000
1,649,000
Current Portion of Long-Term Debt (Start of Period)
-
200,000
150,000
250,000
-
-
Notes Payable to Banks and Commercial Paper (Start of Period)
-
-
40,000
171,000
-
-
Total Debt (Start of Period)
1,249,000
$
1,249,000
$
1,089,000
$
1,570,000
$
1,649,000
$
1,649,000
$
Average Total Debt
1,249,000
$
1,169,000
$
1,329,500
$
1,609,500
$
1,691,800
$
1,735,450
$
Average Total Debt to Total Adjusted EBITDA
1.98 x
1.75 x
1.89 x
1.89 x
1.77 x
1.80 x
FY 2013
12-Months
Ended 12/31/14
FY 2014 |
 64
Reconciliation of Segment Capital Expenditures to
Consolidated Capital Expenditures
($ Thousands)
FY 2015
FY 2010
FY 2011
FY 2012
FY 2013
FY 2014
Forecast
Capital Expenditures from Continuing Operations
Exploration & Production Capital Expenditures
398,174
$
648,815
$
693,810
$
533,129
$
602,705
$
$525,000-575,000
Pipeline & Storage Capital Expenditures
37,894
129,206
144,167
56,144
$
139,821
$
$225,000-275,000
Gathering Segment Capital Expenditures
6,538
17,021
80,012
54,792
$
137,799
$
$125,000-175,000
Utility Capital Expenditures
57,973
58,398
58,284
71,970
$
88,810
$
$115,000-130,000
Energy Marketing, Corporate & All Other Capital Expenditures
773
746
1,121
1,062
$
772
$
-
Total
Capital Expenditures from Continuing Operations 501,352
$
854,186
$
977,394
$
717,097
$
969,907
$
$990,000-1,155,000
Capital Expenditures from Discountinued Operations
All Other Capital Expenditures
150
$
-
$
-
$
-
$
-
$
-
$
Plus (Minus)
Accrued Capital Expenditures Exploration & Production FY 2014 Accrued Capital
Expenditures -
$
-
$
-
$
-
$
(80,108)
$
Exploration & Production FY 2013 Accrued Capital Expenditures
-
-
-
(58,478)
58,478
-
Exploration & Production FY 2012 Accrued Capital Expenditures
-
-
(38,861)
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
19,517
-
-
-
-
-
Pipeline & Storage FY 2014 Accrued Capital Expenditures
-
-
-
-
(28,122)
Pipeline & Storage FY 2013 Accrued Capital Expenditures
-
-
-
(5,633)
5,633
-
Pipeline & Storage FY 2012 Accrued Capital Expenditures
-
-
(12,699)
12,699
-
-
Pipeline & Storage FY 2011 Accrued Capital Expenditures
-
(16,431)
16,431
-
-
-
Pipeline & Storage FY 2010 Accrued Capital Expenditures
-
3,681
-
-
-
-
Pipeline & Storage FY 2008 Accrued Capital Expenditures
-
-
-
-
-
-
Gathering FY 2014 Accrued Capital Expenditures
-
-
-
-
(20,084)
Gathering FY 2013 Accrued Capital Expenditures
-
-
-
(6,700)
6,700
-
Gathering FY 2012 Accrued Capital Expenditures
-
-
(12,690)
12,690
-
-
Gathering FY 2011 Accrued Capital Expenditures
-
(3,079)
3,079
-
-
-
Gathering FY 2009 Accrued Capital Expenditures
715
-
-
-
-
-
Utility FY 2014 Accrued Capital Expenditures
-
-
-
-
(8,315)
Utility FY 2013 Accrued Capital Expenditures
-
-
-
(10,328)
10,328
-
Utility FY 2012 Accrued Capital Expenditures
-
-
(3,253)
3,253
-
-
Utility FY 2011 Accrued Capital Expenditures
-
(2,319)
2,319
-
-
-
Utility FY 2010 Accrued Capital Expenditures
-
2,894
-
-
-
-
Total
Accrued Capital Expenditures (58,401)
$
(39,908)
$
57,613
$
(13,636)
$
(55,490)
$
-
$
Eliminations
-
$
-
$
-
$
-
$
-
$
-
$
Total Capital
Expenditures per Statement of Cash Flows 443,101
$
814,278
$
1,035,007
$
703,461
$
914,417
$
$990,000-1,155,000 |