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| 8-K - FORM 8-K - NATIONAL FUEL GAS CO | d626685d8k.htm |
 National Fuel Gas Company
Investor Presentation
November 2013
Exhibit 99 |
 November
2013 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 and Forms 10-Q for
the periods ended December 31, 2012, March 31, 2013 and June 30, 2013. The Company disclaims any obligation
to update any forward-looking statements to reflect events or circumstances after the date
thereof or to reflect the occurrence of unanticipated events. |
 November
2013 National Fuel Gas Company
3
Our Business Mix Leads to Long-Term Value Creation
Upstream
Crude Oil
Midstream
Downstream
National Fuel Gas
Supply Corporation
Empire Pipeline, Inc.
National Fuel Gas
Midstream Corporation
National Fuel Gas
Distribution
Corporation
National Fuel
Resources, Inc.
The strategic, operational and financial benefits, along with capital
flexibility and consistent growth opportunities generated by this
integrated mix of businesses continues to create significant
long-term value for the Company’s shareholders in nearly all
economic and commodity price scenarios
Upstream
Natural Gas
Seneca Resources
Corporation
(West Division)
Seneca Resources
Corporation
(East Division) |
 National Fuel Gas
Company 4
Integrated Businesses with Significant Marcellus Exposure…
November 2013 |
 November
2013 National Fuel Gas Company
5
…And Exposure to Growth from the Utica Shale |
 National Fuel Gas
Company 6
EBITDA Growth Driven by Stability and Ongoing Success
$1,000
$750
$500
$250
$0
2009
2010
2011
2012
2013
$581
$632
$668
$704
$852
$280
48%
$327
52%
$377
57%
$397
56%
$492
58%
$161
19%
$172
20%
$160
23%
$137
19%
$111
17%
$169
25%
$167
26%
$121
19%
$131
23%
$164
28%
Exploration & Production Segment
Gathering Segment
Pipeline & Storage Segment
Utility Segment
Energy Marketing & Other
Fiscal Year
$30
3%
November 2013
Note: A reconciliation of Adjusted EBITDA to Net Income as presented on the Consolidated
Statement of Income and Earnings is included at the end of this presentation. |
 November
2013 National Fuel Gas Company
7
Capital Spending Flexibility to Maintain Financial Strength
$56
$58
$58
$58
$72
$80-$90
$53
$38
$129
$144
$56
$115-
$135
$80
$55
$100-
$150
$188
$398
$649
$694
$533
$550-
$650
$307
(1)
$501
$854
$977
$717
$845-$1,025
$0
$250
$500
$750
$1,000
$1,250
2009
2010
2011
2012
2013
2014 Forecast
Fiscal Year
Exploration & Production Segment
Gathering Segment
Pipeline & Storage Segment
Utility Segment
Energy Marketing & Other
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 |
 November
2013 Total Debt
(1)
43%
National Fuel Gas Company
8
Strong Balance Sheet and Liquidity Position
$3.843 Billion
As of September 30, 2013
Note: A reconciliation of Adjusted EBITDA to Net Income is included at the end of this
presentation (1)
Long-Term Debt of $1.649 billion
Debt / Adjusted EBITDA
Capitalization
The Company has a total short-term debt capacity of
$1.085 billion of which all remains available
2.02
1.98
1.75
1.89
1.89
0.0
0.5
1.0
1.5
2.0
2.5
2009
2010
2011
2012
2013
Fiscal Year
Shareholders’
Equity
57% |
 National Fuel Gas
Company 9
No Debt Maturities Until Fiscal 2018
Embedded Cost of
Long-Term Debt
5.58%
November 2013
In February, the Company
issued $500 million in
10-year notes at 3.75%
$600
$500
$400
$300
$200
$100
$0
$300
$250
$500
$549
$500
3.750%
$49
7.395%
7.375%
$50
Fiscal Year |
 National Fuel Gas
Company Dividend Track Record
Current
Dividend Yield
(1)
2.1%
Dividend Consistency
Consecutive Dividend Payments
111 Years
Consecutive Dividend Increases
43 Years
Current Annualized Dividend Rate
$1.50 per Share
(1) As of November 1, 2013
November 2013
10
$2.00
$1.50
$1.00
$0.50
$0.00
Annual Rate at Fiscal Year End |
 November
2013 Exploration & Production
11 |
 Seneca
Resources 12
Another Strong Year of Reserve Growth
(1)
Represents a three-year average U.S. Finding and Development Cost
2013 F&D Cost: $1.31
Marcellus F&D: $0.99
Doubled proved reserves
since 2010
71% Proved Developed
46.2
46.6
45.2
43.3
42.9
41.6
226
249
428
675
988
1,300
503
528
700
935
1,246
1,549
0
500
1,000
1,500
2,000
2008
2009
2010
2011
2012
2013
At September 30
Natural Gas (Bcf)
Crude Oil (MMbbl)
November 2013
Fiscal
Years
3-Year
F&D Cost
(1)
($/Mcfe)
2006-2008
$7.63
2007-2009
$5.35
2008-2010
$2.37
2009-2011
$2.09
2010-2012
$1.87
2011-2013
$1.67 |
 November
2013 Seneca Resources
13
Disciplined Capital 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
Gulf of Mexico (Divested in 2011)
East Division (Appalachia)
West Division (California/Kansas)
$1,000
$750
$500
$250
$0
$188
(1)
$139
$31
$28
$47
$63
$105
$90-$130
$398
$356
$649
$596
$694
$631
$533
$428
$550-$650
$460-
$520
2009
2010
2011
2012
2013
2014 Forecast
Fiscal Year |
 Seneca
Resources 14
Production Continues to Grow
20.1
19.8
19.2
20.5
19.9
20-22
8.7
16.5
43.2
62.9
100.8
125-143
13.7
13.3
5.2
42.5
49.6
67.6
83.4
120.7
145-165
0
25
50
75
100
125
150
175
2009
2010
2011
2012
2013
2014 Forecast
Fiscal Year
Gulf of Mexico (Divested in 2011)
East Division (Appalachia)
West Division (California/Kansas)
November 2013 |
 November
2013 Seneca Resources
15
Driving Down Costs
(1)
Represents the midpoint of current General & Administrative Expense guidance of $0.40 to
$0.45 per Mcfe for fiscal 2014 (2)
The total of the two Lease Operating Expense components represents the midpoint of current
Lease Operating Expense guidance of $0.90 to $1.10 per Mcfe for fiscal 2014
$1.35
$1.26
$1.17
$0.91
$0.76
$0.65
$0.52
(2)
$0.17
$0.24
$0.34
$0.48
(2)
$0.60
$0.69
$0.64
$0.73
$0.65
$0.52
$0.43
(1)
$0.28
$0.20
$0.21
$0.18
$0.28
$0.14
$0.15
$2.57
$2.42
$2.22
$2.09
$2.01
$1.75
$1.64
$0.00
$1.50
$3.00
$4.50
2008
2009
2010
2011
2012
2013
2014
Forecast
Fiscal Year
Property, Franchise & Other Taxes
Other O&M Expense
General & Administrative Expense
Lease Operating & Transportation Expense (Transportation Only)
Lease Operating & Transportation Expense (Excl. Transportation)
|
 November
2013 Seneca Resources
16
Expansive Pennsylvania Acreage Position
SRC Lease Acreage
SRC Fee Acreage
NFG Storage Acreage
Eastern
Development
Area
Net Acreage: 60,000 acres
Mostly leased (16-18% royalty)
No near-term lease expiration
First large expiration: 2018
Ongoing development drilling in
Tioga and Lycoming Counties
Western
Development
Area
Net acreage:
~720,000 acres
Own most mineral rights
Minimal
royalty obligation
Minimal
lease expiration
Evaluating rich-gas potential and
initiating dry gas development |
 Seneca
Resources 17
Eastern Development Area (EDA)
Covington
–
Fully
Developed
Gross Production: ~60 MMcf per Day
47 Wells Drilled and Producing
DCNR
Tract
595
Gross Production: ~100 MMcf per Day
34 Wells Drilled
26 Wells Producing
DCNR
Tract
100
Gross Production: ~240 MMcf per Day
40 Wells Drilled
30 Wells Producing
SRC Free Acreage
SRC Lease Acreage
November 2013 |
 November
2013 Seneca Resources
18
Strong Results in Lycoming and Tioga Counties
Development Area
Producing
Well
Count
Average
IP Rate
(MMcf/d)
Average
7-Day
(MMcf/d)
Average
30-Day
(MMcf/d)
Average
EUR
per Well
(Bcf)
Average
Lateral
Length
EUR per
1,000’
of
Lateral
(Bcfe)
Covington
Tioga
County
47
5.2
4.7
4.1
5.7
4,023’
1.42
Tract 595
Tioga
County
26
7.1
6.0
5.1
8.4
4,639’
1.81
Tract 100
Lycoming
County
30
16.1
14.2
11.9
11.5
5,210’
2.21 |
 November
2013 Seneca Resources
19
Continued Steep Growth in the Marcellus
Forecast
0
50
100
150
200
250
300
350
400
450
Tract 100 (Lycoming)
Tract 595 (Tioga)
Covington (Tioga)
Clermont/Other
EOG JV |
 Seneca
Resources Firm Sales in Place for Appalachian Production
20
(1)
Long-term firm sales represent gross volumes
Prices shown represent the sales (netback
price) at the first non-affiliated interstate
pipeline , including the cost of all related
downstream transportation.
November 2013
Other (Transco)
Dominion South Point
NYMEX
400,000
350,000
300,000
250,000
200,000
150,000
100,000
50,000
-
Winter 2013/2014
Summer 2014
Winter 2014/2015
307,745
244,091
220,000
Dominion
Dominion
Dominion
105,000
Less: $0.265
95,000
Less: $0.305
55,000
Less: $0.236
NYMEX
202,745
Less: $0.284
NYMEX
149,091
Less: $0.281
NYMEX
150,000
Less: $0.257 |
 November
2013 Seneca Resources
21
Successful Delineation Across a Large Acreage Position
Owl’s Nest (2 Wells)
54H Peak 7-day IP: 5.8 MMcfd
Church Run (1 Well)
Peak 7-day IP : 4.5 MMcfd
SRC Lease Acreage
SRC Fee Acreage
Horizontal Well
Ridgway (1 Well)
Peak 7-day IP : 6.4 MMcfd
Rich Valley (1 Well)
Peak 7-Day IP: 7.8 MMcfd
30-Day Rate: 6.7MMcfd
Estimated EUR: 7.4 Bcf
BTU
Contours
Clermont (2 Wells)
9H (RCS) Peak 7-day IP: 10.0 MMcfd
Estimated EUR: 8.6 Bcf
Tionesta
1 Well Drilled |
 November
2013 Seneca Resources
22
Delineation Well Test Data Provides Positive Data Points
Initial well test data in the Western Development Area furthers our
confidence in a long-term Marcellus development program
(1)
RCS –
Reduced Cluster Spacing
(2)
Completed using linear gel to place larger proppant near the wellbore
Well Name
Completion
Design
Treatable
Lateral
Length
Stages
Peak
24-Hour
Rate
(MMcfd)
Peak
7-Day
Rate
(MMcfd)
EUR
(Bcf)
Status
Rich Valley 27H
RCS
6,372’
42
8.1
7.8
7.4
Producing
Clermont 9H
RCS
5,500’
37
11.4
10.0
8.6
Producing
Clermont 10H
Non-RCS
5,565’
23
8.1
7.3
6.6
Producing
Ridgway 19H
RCS
5,537’
37
7.1
6.4
Tested
Church Run 2H
RCS
4,435’
29
4.8
4.5
Tested
Owl’s Nest
RCS
6,139’
41
6.1
5.8
Tested
Owl’s Nest
RCS; Gel
2
5,371’
36
3.4
3.1
Tested
1 |
 November
2013 23
Clermont
Rich Valley
Rich
Valley
7-day IP: 7.8 MMcf/d
EUR: 7.4 BCF
Rich Valley 2
Well
Currently Completing
Rich
Valley/Clermont
Program
SRC Lease Acreage
SRC Fee Acreage
Seneca Resources
Rich Valley/Clermont: Moving Forward with Full Development
Marcellus Faults
Marcellus & Basement Faults
Drilled Well
Planned Well
Clermont
9H (RCS) 7-Day Sales Rate: 10.0 MMcf/d
10H (Non-RCS) 7-Day Sales Rate: 7.3 MMcf/d
Pad E
150-200 horizontal locations
Pad O
Pad D
Pad H
Pad
N
(9
Wells)
Spud Q4 FY2013
nd |
 November
2013 Seneca Resources
24
Utica Shale –
Activity Summary
Permitted
Drilled/Drilling
Completed
Producing
Mt. Jewett
Horizontal: completed September 2013
Peak 24-Hour Rate: 8.5 MMcf/d
Tionesta
Horizontal: Completed Fall 2012
Peak 24-Hour Rate: 3.9 MMcf/d
Rex
9.2 MMcf/d
Chesapeake
6.4 MMcf/d
Range Resources
4.4 MMcf/d
Range Resources
1.4 MMcf/d
“Not Effectively Stimulated”
Halcon
6.6 MMcf/d,
750 Bbls/d
Halcon
2.5 MMcf/d,
360 Bbls/d
Halcon
4.5 MMcf/d,
860 Bbls/d
Point Pleasant Core |
 Seneca
Resources 25
California: Seventh Largest Producer in the State
Net Acreage: 18,418 Acres
Net Wells: 1,485
Oil Gravity: 12 –
37°
Api
NRI: 87.64
Rank
Company
California
2012
BOEPD
(1)
1
Occidental
187,376
2
Chevron
160,611
3
Aera (Shell/Exxon)
143,983
4
Plains Exploration
36,365
5
Berry Petroleum
19,589
6
Macpherson Oil
10,416
7
Seneca Resources
10,154
8
Venoco Inc
6,113
9
E&B Natural Resources
6,042
10
ExxonMobil
3,664
(1)
Gross operated production (Source: California Division of Oil, Gas, & Geothermal
Resources) November 2013 |
 Seneca Resources
26
California: Stable Production Fields
South
Lost
Hills
~1,500 BOEPD
Monterey Shale
Primary
222 Active Wells
Sespe
~1,100 BOEPD
Sespe Formation
Primary
172 Active Wells
North
Lost
Hills
~1,100 BOEPD
Tulare & Etchegoin Formation
Primary & Steamflood
175 Active Wells
North
Midway
Sunset
~4,000 BOEPD
Potter & Tulare Formation
Steamflood
728 Active Wells
South
Midway
Sunset
~1,200 BOEPD
Antelope Formation
Steamflood
120 Active Wells
East
Coalinga
~240 BOEPD
Temblor Formation
Primary
November 2013 |
 Seneca
Resources 27
California: Strong Margins Provide Significant Free Cash Flow
Average Revenue
(Fiscal Year Ended 9/30/13)
$88.67 per BOE
(1)
Total
production
from
the
Exploration
&
Production
segment’s
properties
in
California
was
3,313
Mboe
for
the
fiscal
year
ended
September
30,
2013.
Note:
A
reconciliation
of
Exploration
&
Production
West
Division
Adjusted
EBITDA
to
Exploration
&
Production
Segment
Net
Income
is
included
at
the
end
of
this
presentation.
November 2013
Adjusted EBITDA per BOE
(1)
(Fiscal Year Ended September 30, 2013)
Non-Steam Fuel LOE
Steam Fuel
G&A
Production & Other Taxes
Other Operating Costs
Adjusted EBITDA
$11.36
$4.27
$4.10
$2.58
$1.45
$64.90 |
 November
2013 Seneca Resources
28
California: Midway-Sunset South Activity Update |
 29
Seneca Resources
California: Sespe Field –
Drilling Programs and Results
TC 524-28
IP: 100 BOEPD
1 Oil 10/13
1 Mile
Oak Flat 3-31
IP: 120 BOEPD
1 Oil 08/13
FA 502-33
IP: 75 BOEPD
1 Oil 1/13
FA 501-33
IP: 100 BOEPD
1 Oil 1/13
Oak Flat 4-31
IP: 60 BOEPD
1 Oil 08/13
TG 562-29
IP: 190 BOEPD
1 Oil 2/13
TG 53-29
IP: 90 BOEPD
1 Oil 3/13
2011 Sespe Wells (5)
2012 Sespe Wells (6)
2013 Sespe Wells (6)
2014 Sespe Wells (4)
TC 525-28
IP: 160 BOEPD
1 Oil 10/13
WS 525-33
1 Oil in 11/13
WS 535-33
1 Oil in 11/13
st
st
st
st
st
st
st
st
st
st
November 2013
“X”
SANDS ISOCHORE (Thickness) |
 November
2013 Seneca Resources
30
California: East Coalinga Overview
Seneca became operator on January 30, 2013
Previous Operator: Chevron
7,764 net acres
90 active wells
Gross Production: 530 BOPD
Up from 230 BOPD on 1/30/13
$30 million capital commitment over first
three years
$100 million of potential opportunities over
the next five to seven years
2013
Drilled 12 evaluation wells across acreage
block
Placed ~50% of currently idled wells back on
production
Have put 40 on since 1/30/13
Upgraded surface facilities |
 Seneca
Resources 31
California: Delivering Steady Results
Forecast
November 2013
10,000
9,500
9,000
8,500
8,000
7,500
7,000
6,500
6,000
1.
East Coalinga Evaluation
2.
South Midway Sunset Extensions
3.
Sespe Coldwater Evaluation
Key Areas of Focus in 2014 |
 November
2013 Currently drilling first well
Will drill up to 5 evaluation wells in
2014
Seneca Resources
32
Initial Entry into the Mississippian Lime Play in Kansas
Unit
30-day IP:
352 BOED
(92% Oil/NGLs)
The initial entry into the Mississippian Lime play furthers the Company’s goal of
maintaining a significant contribution from oil-producing properties
Total
Net
Acres:
13,615
100% working interest in 4,400 gross
acres
55% net working interest in 17,365
gross acres
Negotiated an increase in Seneca’s
working interest and have taken over
as operator |
 Seneca
Resources 33
Hedge Positions and Strategy
Natural Gas
Swaps
Volume
(Bcf)
Fiscal 2014
91.3
$4.25 / Mcf
Fiscal 2015
57.3
$4.27 / Mcf
Fiscal 2016
40.3
$4.35 / Mcf
Fiscal 2017
38.8
$4.45 / Mcf
Fiscal 2018
5.3
$4.81 / Mcf
Oil Swaps
Volume
(MMBbl)
Average
Hedge Price
Fiscal 2014
2.0
$100.22 / Bbl
Fiscal 2015
1.1
$94.95 / Bbl
Fiscal 2016
0.9
$91.77 / Bbl
Fiscal 2017
0.3
$91.55 / Bbl
Fiscal 2018
0.1
$91.00 / Bbl
Seneca has hedged approximately 67% of its
forecasted production for Fiscal 2014
Note:
Fiscal
2014
hedge
positions
are
for
the
full
twelve
months
of
the
fiscal
year
November 2013
Average Hedge
Price |
 Midstream
Businesses 34
Pipeline & Storage/NFG Midstream
November 2013 |
 Midstream
Businesses 35
Pipeline Expansions to Transport Appalachian Production
Gathering
Marcellus
Production
Shipping Gas
to Canada &
Northeast
Line N
Corridor
Expansions
November 2013 |
 Midstream
Businesses 36
A Closer Look at the Expansion Progress
COVINGTON
GATHERING SYSTEM
(In-Service)
TROUT RUN
GATHERING SYSTEM
(In-Service)
TIOGA
COUNTY
EXTENSION
(In-Service)
LINE “N”
EXPANSION
(In-Service)
NORTHERN ACCESS
EXPANSION
(In-Service)
CENTRAL TIOGA
COUNTY EXTENSION
(2016)
LINE “N”
2012
EXPANSION
(In-Service)
MERCER
EXPANSION
PROJECT
(Nov. 2014)
LINE “N”
2013
EXPANSION
(In-Service)
WEST SIDE
EXPANSION
(Nov. 2015)
TIONESTA
GATHERING SYSTEM
(In-Service)
MT. JEWETT
GATHERING SYSTEM
(In-Service)
CLERMONT
GATHERING SYSTEM
(Q4 FY2014)
November 2013 |
 Midstream
Businesses 37
NFG Midstream is Focused on Serving Appalachian Producers
Midstream’s gathering systems are
critical to unlock remote, but highly
productive Marcellus acreage
History of operational success and
efficiency within Pennsylvania
Current focus is on developing and
expanding gathering infrastructure
for both Seneca and other producers
in the Appalachian Basin
November 2013 |
 November
2013 Midstream Businesses
38
Regulated Interstate Expansion Initiatives (Pipeline & Storage)
Project Name
Capacity
(Dth/D)
Est.
CapEx
In-Service
Market
Status
Lamont Compressor Station
90,000
$14 MM
2010/2011
Fully Subscribed
Completed
–
Two
Phases
Line “N”
Expansion
160,000
$61 MM
(1)
10/2011
Fully Subscribed
Completed
Tioga County Extension
350,000
$58 MM
11/2011
Fully Subscribed
Completed
Northern Access Expansion
320,000
$77 MM
11/2012
Fully Subscribed
Completed
Line “N”
2012 Expansion
163,000
$39 MM
(2)
11/2012
Fully Subscribed
Completed
Line “N”
2013 Expansion
30,000
$4.5 MM
11/2013
Fully Subscribed
Completed
Mercer Expansion Project
105,000
$30 MM
(3)
11/2014
Fully Subscribed
Executed Precedent Agreement
West Side Expansion and
Modernization Project
175,000
$74 MM
(4)
11/2015
OS Concluded
Executed one of three Precedent
Agreements
Central Tioga County
Extension
260,000
~$150 MM
2016
OS Concluded
Evaluating market
West to East
~425,000
~$290 MM
~2017
29% Subscribed
Marketing continues with producers in
various stages of exploratory drilling
(1)
The Line “N” Expansion Project consists of $22 million in expansion capital
expenditures and $39 million in replacement capital expenditures
(2)
The Line “N” 2012 Expansion Project consists of $32 million in
expansion capital expenditures and $7 million in replacement capital expenditures (3) The Mercer Expansion Project consists of $27 million in expansion
capital expenditures and $3 million in replacement capital expenditures (4) The Westside Expansion and Modernization Project consists of $39
million in expansion capital expenditures and $35 million in replacement capital expenditures |
 November
2013 Midstream Businesses
39
Gathering Expansion Initiatives (NFG Midstream)
Project Name
Capacity
(Mcf/D)
Est.
CapEx
In-Service
Date
Market
Comments
Covington Gathering System
220,000
$36 MM
Multiple
Phases -
Most
In-Service
Capacity
Available
[Marketing to
Third Parties]
Completed
–
Flowing into TGP
300 Line. $26 million spent to
date.
Trout Run Gathering System
466,000
$185 MM
May 2012
Capacity
Available
[Marketing to
Third Parties]
Completed
–
Flowing into Transco
Leidy Line. $128 million spent to
date.
Tionesta Gathering System
10,000
$2.1 MM
April 2013
Fully Subscribed
Completed
–
Flowing into TGP
300 Line
Mt. Jewett Gathering System
10,000
$3.9 MM
September
2013
Fully Subscribed
Completed
–
Flowing into TGP
300 Line
Clermont Gathering System
~1,000,000
~$80 MM
(FY2014)
FY2014
Q4
Evaluating
Fiscal 2014 capital spending on
the Clermont Gathering System is
for trunkline/initial facilities |
 November
2013 Utility
40 |
 Total Customers:
520,000 Rate Mechanisms:
Revenue Decoupling
Weather Normalization
Low Income Rates
Choice Program/Purchase of
Receivables (POR)
Merchant Function Charge
(Uncollectibles Adjustment)
90/10 Sharing (Large Customers)
Natural Gas Vehicle Pilot Program
Allowed ROE: 9.1%
Utility
41
New York Service Territory
November 2013 |
 November
2013 Utility
42
New York -
Earnings Sharing Proposal and Show Cause Order
March
27,
2013
Filed a plan with the NY PSC
to adopt an earnings
sharing and stabilization
mechanism on earnings
above a 9.96% ROE
April
19,
2013
NY PSC issued an Order
to Show Cause (OTSC)
commencing a
proceeding to establish
“temporary rates”
June 1, 2013
OTSC suggests
“temporary rates”
could
become effective
Further proceedings would follow to establish
permanent rates
Most recent NY PSC multi-year plan include:
ROE: 9.4%
Equity Ratio: 48%
National Fuel continues to maintain a dialogue
with regulators
May 8, 2013
Company responds to
OTSC
June 14, 2013
“Temporary rates”
become effective
July 26, 2013
Settlement discussions
commence for
permanent rates |
 November
2013 Utility
43
Pennsylvania Service Territory
Total Customers: 213,000
Rate Mechanisms:
Low Income Rates
Choice Program/Purchase of
Receivables (POR)
Merchant Function Charge
Allowed ROE: N/A
(1)
(1)
Black Box Settlement |
 Utility
44
Continued Cost Control Helps Provide Earnings Stability
Low natural gas prices,
combined with a focus on
cost control, continue to
help reduce expenses
November 2013
$178
$164
$167
$168
$168
$172
$25
$27
$14
$11
$9
$6
$203
$191
$181
$179
$177
$178
$0
$50
$100
$150
$200
$250
2008
2009
2010
2011
2012
2013
Fiscal Year
All Other O&M Expenses
O&M Uncollectible Expense |
 November
2013 Utility
45
Strong Commitment to Safety
The increase in 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
Capital Expenditures for Safety
Total Capital Expenditures
$100
$80
$60
$40
$20
$0
2009
2010
2011
2012
2013
2014
Forecast
$56.2
$44.4
$58.0
$45.0
$58.4
$44.3
$58.3
$43.8
$72.0
$48.1
$80-$90
Fiscal Year |
 November
2013 National Fuel Gas Company
46
Comparable GAAP Financial Measure Slides and Reconciliations
This presentation contains certain non-GAAP financial measures. For pages
that contain non-GAAP financial measures, pages containing the most directly
comparable GAAP financial measures and reconciliations are provided in the
slides that follow.
The Company believes that its non-GAAP financial measures are useful to
investors because they provide an alternative method for assessing the
Company’s operating results in a manner that is focused on the performance
of the Company’s ongoing operations, or on earnings absent the effect of
certain credits and charges, including interest, taxes, and depreciation,
depletion and amortization. The Company’s management uses these non-
GAAP financial measures for the same purpose, and for planning and
forecasting purposes. The presentation of non-GAAP financial measures is not
meant to be a substitute for financial measures prepared in accordance with
GAAP. |
 November
2013 47
Reconciliation of Exploration & Production West Division Adjusted EBITDA
to Exploration & Production Segment Net Income
($ Thousands)
FY 2013
Exploration & Production -
West Division Adjusted EBITDA
215,042
$
Exploration & Production -
All Other Divisions Adjusted EBITDA
277,341
Total Exploration & Production Adjusted EBITDA
492,383
$
Minus: Exploration & Production Net Interest Expense
(38,244)
Minus: Exploration & Production Income Tax Expense
(95,317)
Minus: Exploration & Production Depreciation, Depletion &
Amortization (243,431)
Exploration & Production Net Income
115,391
$
Exploration & Production Net Income
115,391
$
Pipeline & Storage Net Income
63,245
Gathering Net Income
13,321
Utility Net Income
65,686
Energy Marketing Net Income
4,589
Corporate & All Other Net Income
(2,231)
Consolidated Net Income
260,001
$ |
 November
2013 48
Reconciliation of Adjusted EBITDA to Consolidated Net Income
($ Thousands)
FY 2009
FY 2010
FY 2011
FY 2012
171,572
$
187,838
$
187,603
$
226,897
$
215,042
$
108,139
139,624
189,854
170,232
277,341
Total Exploration & Production Adjusted EBITDA
279,711
$
327,462
$
377,457
$
397,129
$
492,383
$
Total Adjusted EBITDA
Exploration & Production Adjusted EBITDA
279,711
$
327,462
$
377,457
$
397,129
$
492,383
$
Pipeline & Storage Adjusted EBITDA
130,857
120,858
111,474
136,914
161,226
Gathering Adjusted EBITDA
(141)
2,021
9,386
14,814
29,777
Utility Adjusted EBITDA
164,443
167,328
168,540
159,986
171,669
Energy Marketing Adjusted EBITDA
11,589
13,573
13,178
5,945
6,963
Corporate & All Other Adjusted EBITDA
(5,434)
408
(12,346)
(10,674)
(9,920)
Total Adjusted EBITDA
581,025
$
631,650
$
667,689
$
704,114
$
852,098
$
Total Adjusted EBITDA
581,025
$
631,650
$
667,689
$
704,114
$
852,098
$
Minus: Net Interest Expense
(81,013)
(90,217)
(75,205)
(82,551)
(89,776)
Plus: Other Income
9,762
6,126
5,947
5,133
4,697
Minus: Income Tax Expense
(52,859)
(137,227)
(164,381)
(150,554)
(172,758)
Minus: Depreciation, Depletion & Amortization
(170,620)
(191,199)
(226,527)
(271,530)
(326,760)
Minus: Impairment of Oil and Gas Properties (E&P)
(182,811)
-
-
-
-
Plus/Minus: Income/(Loss) from Discontinued Operations, Net of Tax (Corp. & All
Other) (2,776)
6,780
-
-
-
Plus: Gain on Sale of Unconsolidated Subsidiaries (Corp. & All Other)
-
-
50,879
-
-
Plus: Elimination of Other Post-Retirement Regulatory Liability (P&S)
-
-
-
21,672
-
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
100,708
$
225,913
$
258,402
$
220,077
$
260,001
$
Consolidated Debt to Total Adjusted EBITDA
Long-Term Debt, Net of Current Portion (End of Period)
1,249,000
$
1,049,000
$
899,000
$
1,149,000
$
1,649,000
$
Current Portion of Long-Term Debt (End of Period)
-
200,000
150,000
250,000
-
Notes Payable to Banks and Commercial Paper (End of Period)
-
-
40,000
171,000
-
Total Debt (End of Period)
1,249,000
$
1,249,000
$
1,089,000
$
1,570,000
$
1,649,000
$
Long-Term Debt, Net of Current Portion (Start of Period)
999,000
1,249,000
1,049,000
899,000
1,149,000
Current Portion of Long-Term Debt (Start of Period)
100,000
-
200,000
150,000
250,000
Notes Payable to Banks and Commercial Paper (Start of Period)
-
-
-
40,000
171,000
Total Debt (Start of Period)
1,099,000
$
1,249,000
$
1,249,000
$
1,089,000
$
1,570,000
$
Average Total Debt
1,174,000
$
1,249,000
$
1,169,000
$
1,329,500
$
1,609,500
$
Average Total Debt to Total Adjusted EBITDA
2.02
1.98
1.75
1.89
1.89
FY 2013
Exploration & Production - All Other Divisions Adjusted EBITDA
Exploration & Production - West Division Adjusted EBITDA |
 49
Reconciliation of Segment Capital Expenditures to
Consolidated Capital Expenditures
($ Thousands)
FY 2014
FY 2009
FY 2010
FY 2011
FY 2012
FY 2013
Forecast
Capital Expenditures from Continuing Operations
Exploration & Production Capital Expenditures
188,290
$
398,174
$
648,815
$
693,810
$
533,129
$
$550,000-650,000
Pipeline & Storage Capital Expenditures
52,504
37,894
129,206
144,167
56,144
$
$115,000-135,000
Gathering Segment Capital Expenditures
9,433
6,538
17,021
80,012
54,792
$
$100,000-150,000
Utility Capital Expenditures
56,178
57,973
58,398
58,284
71,970
$
$80,000-90,000
Energy Marketing, Corporate & All Other Capital Expenditures
396
773
746
1,121
1,062
$
-
Total Capital Expenditures from Continuing Operations
306,801
$
501,352
$
854,186
$
977,394
$
717,097
$
$845,000-1,025,000
Capital Expenditures from Discountinued Operations
All Other Capital Expenditures
216
150
$
-
$
-
$
-
$
-
$
Plus (Minus) Accrued Capital Expenditures
Exploration & Production FY 2013 Accrued Capital Expenditures
-
$
-
$
-
$
-
$
(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
(9,093)
19,517
-
-
-
-
Pipeline & Storage FY 2013 Accrued Capital Expenditures
-
-
-
-
(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
16,768
-
-
-
-
-
Gathering FY 2013 Accrued Capital Expenditures
-
-
-
-
(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)
715
-
-
-
-
Utility FY 2013 Accrued Capital Expenditures
-
-
-
-
(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
6,960
$
(58,401)
$
(39,908)
$
57,613
$
(13,636)
$
-
$
Eliminations
(344)
$
-
$
-
$
-
$
-
$
-
$
Total Capital Expenditures per Statement of Cash Flows
313,633
$
443,101
$
814,278
$
1,035,007
$
703,461
$
$845,000-1,025,000
November 2013 |