NATIONAL FUEL GAS CO - FORM 8-K - EX-99 - February 4, 2016

Attached files

file filename
8-K - FORM 8-K - NATIONAL FUEL GAS COd64215d8k.htm
National Fuel Gas Company
Investor Presentation
February 2016
Exhibit
99

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:  Impairments under the SEC’s full cost ceiling test for natural gas and oil reserves; changes in the price of natural gas or oil; 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; 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; 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; 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 price differentials between similar quantities of natural gas or oil
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; the cost and effects
of legal and administrative claims against the Company or activist shareholder campaigns to effect changes at the Company; 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; 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, 2015 and the Form 10-Q for the quarter ended December 31, 2015. 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.
Corporate

Corporate
•
2.3
Tcfe
Proved
Reserves
(1)
•
785,000 net acres in Marcellus Shale
•
3 million Bbls/year California
crude oil production
3
National Fuel Gas Company
Upstream
Downstream
Quality Assets  |  Exceptional Location  | Unique Integration
•
$252 million adjusted EBITDA
(2)
•
$1.2 billion midstream investments
since 2010
•
Coordinated infrastructure build-out  
in Appalachia with NFG Upstream
•
740,000 Utility customer accounts
•
Stable, regulated earnings & cash flows
•
Supports investment grade credit rating
Midstream
Corporate
(1)
Total proved reserves are as of September 30, 2015.
(2)
For the trailing twelve months ended December 31, 2015. 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.

Corporate
Unique Asset Mix and Integrated Model Provide Balance and Stability
The National Fuel Value Proposition
4
Fee ownership on ~715,000 net acres in WDA = limited royalties or drilling commitments
Seneca has >900,000 Dth/day of firm transportation & sales contracts by start of fiscal 2018
Stacked pay potential in Utica and Geneseo shales across Marcellus acreage
Coordinated gathering & interstate pipeline infrastructure build-out with NFG midstream
Opportunity for further pipeline expansion to accommodate Appalachian supply growth
Creating long-term sustainable value remains our #1 shareholder priority
Considerable Upstream and Midstream Growth Opportunities in Appalachia
Geographical and operational integration drives capital flexibility and reduces costs
Cash flow from rate-regulated businesses supports interest costs and funds the dividend
NFG is Well Positioned to Endure Current Commodity Price Environment
Investment grade credit rating and liquidity to support long-term Appalachian growth strategy
Strong hedge book helps insulate near-term earnings and cash flows from commodity volatility
Disciplined and flexible capital investment that is focused on economic returns
Corporate

Appalachia Overview
Exploration & Production  |  Gathering  |  Pipeline & Storage
5
Appalachia Overview
Exploration & Production  |  Gathering  |  Pipeline & Storage

Appalachia
200,000 “Tier 1” WDA acres in Pa.
Fee acreage economic < $2.50/MMBtu
with minimal lease expiration
Just-in-time build-out of Clermont
Gathering System  limits stranded
pipeline assets/capital
Northern Access projects to
transport 660 MDth/d of Seneca-
operated WDA production by FY18
Integrated Vision for Long-term Growth
6
Exploration & Production
Pipeline & Storage
Gathering
1
2
3
1
2
Long-term, return-
driven approach
to developing vast
acreage position
Connecting Our
Production to Our
Interstate Pipeline
System
Expanding Our
Interstate Pipeline
System to Reach
Premium Markets
3
Appalachia

Exploration & Production
Appalachia
$631
$428
$520
$500
$370-$425
$110-$150
$80
$55
$138
$118
$100-$125
$85-$95
$144
$56
$140
$230
$500-$550
$125-$175
$855
$539
$798
$848
$970-$1,100
$320-$420
$0
$250
$500
$750
$1,000
$1,250
$1,500
2012
2013
2014
2015
2016E
(March '15)
2016E
(Current)
  Pipeline & Storage
  Gathering
  E&P - Appalachia
Appalachia Capital Reductions
7
Exercising Capital Flexibility and Discipline
to Respond to Commodity Price Environment
(1)
FY2016 Appalachia Capital Budget Cut 
$665 million, or 64%, since preliminary
budget released in March 2015
(1) Executed “Drill-Co” JDA
(2) 1-rig program
(3) Northern Access delay
KEY ACTIONS
(1)
FY2016 capital expenditure guidance reflects the netting of up-front proceeds received from joint development partner for capital spent on wells drilled and/or completed prior to the execution date of the
joint development agreement. The E&P segment’s FY16 capital budget would be reduced by an additional $90-$110 million if joint development partner exercises right to participate on remaining 38 wells.
Note: A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation. Refer to slide 40 for NFG consolidated capital expenditures.
Exploration & Production

Exploration & Production
Appalachia
Significant Appalachian Acreage Position
8
153
wells
able
to
produce
350
MMcf/d
40-50 remaining Marcellus locations
Additional strong Utica & Geneseo potential
Limited development drilling until firm
transportation on Atlantic Sunrise
(190 MDth/d) is available in late 2017
Mostly leased (16-18% royalty)
No near-term lease expirations
83
wells
able
to
produce
255
MMcf/d
Large inventory of high quality Marcellus acreage
NFG midstream infrastructure supporting growth
660 MDth/d firm transportation by fiscal 2018
Mineral fee ownership enhances economics
Highly contiguous nature drives efficiencies
Seneca Lease
Seneca Fee
715,000 Acres
70,000 Acres
Western Development Area (WDA)
Eastern Development Area (EDA)
Exploration & Production
Appalachia
(1)
(1)

Exploration & Production
Appalachia
Marcellus Shale: Western Development Area
9
WDA Tier 1 Acreage –
200,000 Acres
WDA Tier 1 Marcellus Economics
(1)
WDA Highlights
Large drilling inventory of quality Marcellus dry gas
o
~1,200 locations economic < $2.50/MMBtu
NFG midstream infrastructure supporting growth
o
NFG Clermont Gathering System
o
660 MDth/d firm transport on NFG projects by FY18
Fee acreage enhances economics
o
No royalty on most acreage
o
No lease expirations or requirements to drill acreage
Highly contiguous position drives D&C efficiencies
o
Multi-well pad drilling averaging 10 wells per pad
o
Average lateral length to date = 7,800 ft.
o
Centralized water sourcing & disposal infrastructure
2 Utica tests expected in fiscal 2016/2017
SRC Fee Acreage
SRC Lease Acreage
SRC / EOG Earned
Acreage
Clermont/
Rich Valley
Hemlock
Ridgway
2
-
4 BCF/well
6 -
10 BCF/well
4 -
6 BCF/well
EUR Color Key
(1)
Internal rate of return (IRR) is pre-tax and includes estimated well costs under the current well design and cost structure and projected firm transportation, gathering, LOE and other operating costs. 
CRV and Hemlock/Ridgway well designs assume 8,800 ft. lateral and 190 ft. frac stage spacing.  Other Tier 1 well designs assume 8,500 ft. lateral and 190 ft. frac stage spacing.

Transaction
Seneca WDA Joint Development Agreement
10
Key Terms
On December 2, 2015, Seneca entered into an asset-level joint development agreement with IOG CRV-Marcellus
Capital, LLC, an affiliate of IOG Capital, LP, and funds managed by affiliates of Fortress Investment Group, LLC, to
jointly develop Marcellus Shale natural gas assets located in Elk, McKean and Cameron counties in north-central PA.
Assets: 80 current and future Marcellus development wells
in the Clermont/Rich Valley region of Seneca’s WDA.
Partner’s Initial Obligation: 42 wells
Partner Option: Partner has one-time option to participate
in remaining 38 wells on or before July 1, 2016.
Economics:
Partner participates as an 80% working interest
owner until the Partner achieves a 15% IRR hurdle. Seneca
retains a 7.5% royalty and remaining 20% working interest.
Strategic Rationale
Significantly reduces near-term upstream capital spending
Initial 42 wells
-
$200 million
(1)
38 well option -
$180 million
(1)
Validates quality of Seneca’s Tier 1 Marcellus WDA acreage
Seneca maintains current activity level driving additional
Marcellus drilling and completion efficiencies
Solidifies NFG’s midstream growth strategy:
Gathering
-
All production from JV wells will flow
through NFG Midstream’s Clermont Gathering System
Pipeline & Storage -
Provides production growth that
will utilize the 660 MDth/d of firm transportation
capacity on NFG’s Northern Access pipeline expansion
projects
Strengthens balance sheet and makes Seneca cash flow
positive in near-term
Marketing: Partner to receive same realized price before
hedging as Seneca on production from the joint
development wells, including firm sales and the cost of firm
transportation.
Interests on Initial 42
Wells
Seneca
Partner
Working Interest
20%
80%
Net Revenue Interest
26%
74%
(1)  Estimated reduction in capital expenditures from joint development agreement assumes current wells costs.
Exploration & Production
Appalachia

Exploration & Production
Appalachia
11
Clermont/Rich Valley Development Map
Pittsburgh
Clermont/Rich
Valley Area
Legend
Drilled Wells
Planned Wells
Clermont Gathering System (in-service)
Clermont Gathering System (future)
CRV Development Summary
•
Current: 62 wells able to produce ~200 MMcf/d
•
200+ MMcf/d gross firm sales in fiscal 2016
•
Currently operating 2-rigs (down from 3 to start
year). Will drop to 1 rig in March 2016
•
Just-in-time gathering infrastructure build-out
provides significant capital flexibility based on
pace of Seneca’s development program
•
Regional focus of development minimizes capital
outlay and improve returns
Exploration & Production
Appalachia
Integrated WDA Development -
Upstream

Appalachia
Gathering
Integrated WDA Development -
Gathering
12
Current System In-Service
•
~44 miles of pipe/13,800 HP of compression
•
Current Capacity: 470 MMcf
per day    
•
Interconnects with TGP 300
•
Total CapEx
To Date: $235 million
Fiscal 2016 Build Out
•
FY16 CapEx: $60 to $75 million
•
Exit FY16 with > 52 miles of pipe installed and
>26,220 HP commissioned
Future Build-Out (FY17+)
•
Ultimate capacity can exceed 1 Bcf/d
•
Over 100 miles of pipelines and five
compressor stations (+60,000 HP installed)
•
Deliverability into TGP 300 and NFG Supply
•
Future third-party volume opportunities
Gathering System Build-Out Tailored
to Accommodate Seneca’s WDA Development
Clermont Gathering System Map

Appalachia
Pipeline & Storage
Integrated WDA Development -
Interstate Pipelines
13
(1) 40,000 Dth per day went in-service on November 1, 2015. The remaining 100,000 Dth per day was placed in-service on December 1, 2015.
Northern Access 2015
•
Customer: Seneca Resources (NFG)
•
In-Service: November 2015
(1)
•
System: NFG Supply Corp.
•
Capacity: 140,000 Dth per day
o
Leased to TGP as part of TGP’s
Niagara Expansion project
•
Interconnect
o
Niagara (TransCanada)
•
Total Cost: $67.5 Million
•
Major Facilities
o
23,000 hp Compression
Expanding Our Interstate Pipelines to Deliver Seneca’s WDA Production to Canada
Pipeline & Storage
Appalachia

14
Northern Access 2016
•
Customer: Seneca Resources (NFG)
•
In-Service: Now targeting Nov. 1, 2017
•
Capacity:  490,000 Dth/d
•
Interconnects:
o
o
TGP 200 –
East Aurora (140 MDth/d)
•
Total Cost: ~$455 Million
•
Major Facilities:
o
98.5 miles –
16/24” Pipeline
o
22,214 hp & 5,350 hp Compression
•
FERC Status
o
Pre-filing: July 2014
o
Certificate filing: March 2015
o
Certificate amendment filed Nov. 2015
Northern
Access
2016
to
Increase
Transport
Capacity
out of WDA to Canada by 490,000 Dth/d by FY18
Integrated WDA Development -
Interstate Pipelines
Chippawa
East Aurora
Pipeline
& Storage
Appalachia
TransCanada
–
Chippawa
(350
MDth/d)

Exploration & Production
Appalachia
$248
$148
$109
$91
$75
$0
$100
$200
$300
FY 2012
FY 2013
FY 2014
FY 2015
FY 2016
15
(1)
Excludes pad construction costs. FY 2016 well costs assume actual costs incurred through December 31, 2016  and projects costs for the remainder of the  fiscal year under the current cost structure.
(2)
Includes dollars spent to drill and complete development wells only. Excludes exploration and delineation wells.
$275
$208
$174
$153
$130
$0
$100
$200
$300
FY 2012
FY 2013
FY 2014
FY 2015
FY 2016
$8.7 MM
Well Cost
$4.9 MM
Well Cost
Fiscal 2012 Average Development Well
(1)
Fiscal 2016 Average Development Well
(1)
Lateral Length: 5,100 ft
Measured Depth: 13,700 ft
Completion Stages: 20
Lateral Length: 7,600 ft
Measured Depth: 14,300 ft
Completion Stages: 40
Drilling Cost per Foot
(2)
Completion Cost per Stage
(2)
(000s)
Marcellus Drilling and Completion Efficiencies

WDA Upstream & Midstream Development
16
WDA Well Costs
WDA Clermont / Rich Valley Economics
WDA Clermont / Valley Economics vs. NYMEX Futures Strip
$10.8
$9.6
$7.2
$5.8
$0
$5
$10
$15
FY 2013
FY 2014
FY 2015
FY 2016E
$2.94
$2.71
$2.22
$1.92
$0.00
$1.00
$2.00
$3.00
$4.00
FY 2013
FY 2014
FY 2015
FY 2016E
Normalized for a 8,800 ft. Lateral Length
Normalized for a 8,800 ft. Lateral Length
NA 2016 FT Cost
(2)
Northern Access 2016 In-Service (+490 Mdth/d)
(1)
Internal Rate of Return (IRR) is pre-tax and includes estimated well costs under current cost structure, LOE and gathering tariffs anticipated for each prospect. Assumes Dawn is on par with NYMEX.
(2)
Northern Access 2016 FT cost reflects $0.70 per Dth reservation charge and assumes approximately $0.06 per Dth of variable fees (commodity, fuel, etc.)
While Seneca has consistently driven down its well costs and break-even economics …
… near-term development pace modified to achieve value-added returns on investments 
NA 2016 1-year Delay
$0.76
Appalachia
$2.68
$1.92
$1.50
$2.00
$2.50
$3.00
$3.50
  NYMEX Futures Strip (2/2/16)
  CRV Break-even Realized Price
(1)
Realized
Price
Required
for
15%
IRR

Marcellus Shale: Eastern Development Area
17
(1)  One well included in the total for both Tract 595 and Tract 100 is drilled into and producing from the Geneseo Shale.
EDA Acreage –
70,000 Acres
1
2
3
EDA Highlights
1
Covington & DCNR Tract 595
o
Tioga County, Pa. 
o
92 wells
(1)
with 110  MMcf/d productive capacity
o
75 MMcf/d firm sales/FT in FY16
o
NFG Covington Gathering System
o
Opportunity for future Geneseo & Utica dev.
DCNR Tract 100 & Gamble
o
Lycoming County, Pa. 
o
61 wells
(1)
with 240 MMcf/d productive capacity
o
130-185 MMcf/d firm sales/FT in FY16
o
Atlantic Sunrise capacity (190 MDth/d) in FY18
o
NFG Trout Run Gathering System
o
Geneseo to provide additional 100-120 locations
DCNR Tract 007
o
Tioga County, Pa. 
o
1 Utica and 1 Marcellus exploration well
o
Utica well 24 IP = 22.7 MMcf/d
o
Utica Resource potential  = ~1 Tcf
2
3
Exploration & Production
Appalachia

Integrated EDA Development -
Gathering
18
•
In-Service Date: November 2009
•
Capital Expenditures (to date):
$33 Million
•
Capacity: 220,000 Dth per day
•
Production
Source:
Seneca
Resources
–
Tioga
Co.
(Covington and DCNR Tract 595 acreage)
•
Interconnect: TGP 300
•
Facilities: Pipelines and dehydration
•
Future third-party volume opportunities
Interconnects
•
In-Service Date: May 2012
•
Capital Expenditures (to date): $166 Million
•
Capacity: 466,000 to 585,000 Dth per day
•
Production
Source:
Seneca
Resources
–
Lycoming
Co.
(DCNR Tract 100 and Gamble acreage)
•
Interconnect:
Transco
–
Leidy
Lateral
•
Facilities: Pipelines, compression, and dehydration
•
Future third-party volume opportunities
Covington Gathering System
Trout Run Gathering System
Gathering Segment Supporting Seneca’s EDA Production & Future Development
Gathering
Appalachia

Utica/Point Pleasant: Industry Activity
19
Range
59 MMcf/d
Rice
42 MMcf/d
Shell
26.5 MMcf/d
Permitted
Drilling
Completed
Production
Seneca Vert.
Seneca Horiz.
EQT
73 MMcf/d
Color-filled contours are Trenton TVDSS; CI = 1000’
Seneca –
Mt. Jewett
IP: 8.9 MMcf/d
CNX
61 MMcf/d
MHR
46 MMcf/d
Seneca –
WDA
2 Utica Test Wells
Planned for FY16/17
Seneca -
DCNR 007
IP: 22.7 MMcf/d
CNX
61.9 MMcf/d
CNX
44 MMcf/d
Appalachia
Exploration & Production

Exploration & Production
Appalachia
Exploration & Production
Appalachia
Exploration & Production
20
32.8 Bcf
150 –
180 Bcfe
59.4 Bcf
29.3 Bcf
4.9 Bcf
0 -
30 Bcf
~21 Bcfe
2.5 Bcf
(3)
129 –
159 Bcf
0
50
100
150
200
250
Q1 East
Division
Production
Firm Sales +
Hedges
Fixed Price
Firm Sales
NYMEX
Firm Sales
(No Hedge)
Spot Sales
Production
Total
Appalachia
West Coast
(CA)
Total
Seneca
Production
Remaining FY16 Production
with Price Certainty
88.7 Bcf Realizing ~$3.25/Mcf
(1)
4.9 Bcf of Additional Basis Protection
(2)
Appalachia
Productive
Capacity
Seneca Total
Productive
Capacity
(1)
Average realized price reflects uplift from financial hedges less fixed differentials under firm sales contracts and firm transportation costs.
(2)
Indicates firm sales contracts with fixed index differentials to NYMEX but not backed by a matching NYMEX financial hedge.
(3)
Represents 2.5 Bcf of non-operated production from Western Development Area .
FY 2016 Production -
Firm Sales & Spot Exposure

Exploration & Production
Appalachia
-
250
500
750
1,000
1,250
2016
2017
2018
2019
2020
2021
2022
2023
Fiscal Year Start
Significant Base of Long-Term Firm Contracts
21
Atlantic Sunrise (Transco)
Delivery Markets: Mid-Atlantic & Southeast U.S.
189,405 Dth/d
Northern Access 2016 (NFG
(1)
, TransCanada & Union)
Delivery Markets: Canada-Dawn & NY-TGP200
490,000 Dth/d
Niagara Expansion (TGP & NFG)
Delivery Markets: Canada-Dawn & TETCO
170,000 Dth/d
Firm Sales
(2)
914,405 Dth per day
Total Gross Firm Contracts by FY2018
(1)
Includes capacity on both National Fuel Gas Supply Corp. and Empire Pipeline, Inc., both wholly owned subsidiaries of National Fuel Gas Company.
(2)
Includes base firm sales contracts not tied to firm transportation capacity.
Northeast Supply Diversification  50,000 Dth/d

Exploration & Production
Appalachia
28.5
29.5
20.4
11.4
14.1
12.7
19.0
22.1
30.4
32.9
8.0
5.8
92.0
97.2
30.2
17.2
4.9
0
50
100
150
FY 2016
FY 2017
FY 2018
FY 2019
FY 2020
NYMEX
Dominion
Dawn & MichCon
Fixed Price Physical Sales
Strong Hedge Book in Fiscal 2016 and 2017
22
FY 2016 = 78% hedged
(1)
at $3.53 per MMBtu
Natural Gas Swap & Fixed Physical Sales Contracts (Million MMBtu)
(3)
(2)
(2)
(1)
Assumes midpoint of natural gas production guidance, adjusted for year-to-date actual results.
(2)
For the remaining nine months ended September 30, 2016.
(3)
Fixed price physical sales exclude  joint development partner’s share of fixed price contract WDA volumes as specified under the joint development agreement.

Pipeline & Storage: Premier Appalachian Position
23
In addition to serving our own upstream and downstream subsidiaries,
NFG is uniquely positioned to expand our regional pipeline systems and
provide valuable outlets for 3
rd
party producers and shippers in Appalachia
Canada &
Michigan
New England
& Northeast
Midwest &
Southeast
Mid-Atlantic
Appalachia
Pipeline
& Storage

Appalachia
Pipeline & Storage
Recent 3
rd
Party Expansions Highly Successful
24
Expansions for 3
rd
Parties since 2010
Line N Projects
+633 MDth/d
Northern
Access 2012
+320 MDth/d
Empire & Lamont
Expansions
+489 MDth/d
3
rd
Party Expansion Capital Cost ($MM)
Annual Expansion Revenues Added ($MM)
$387 million
since FY 2010
1,442 MDth/d
since FY2010
$4
$37
$19
$4
$5
$25
~$95
$0
$25
$50
$75
$100
$125
FY11
FY12
FY13
FY14
FY15
FY16E
Cum.
$72
$132
$183
Northern Access 2012
Empire & Lamont
Line N Projects

Appalachia
Pipeline & Storage
Planned Empire System Expansion
25
Empire North Expansion Project
•
Target In-Service: Late 2018
•
System: Empire Pipeline
•
Target Market:
o
Marcellus & Utica producers in Tioga &
Potter County, Pa.
•
Open Season Capacity: 300,000 Dth/d
•
Delivery Points:
o
180,000 Dth/d to Chippawa
(TCPL)
o
Up to 158,000 Dth/d to Hopewell (TGP)
•
Estimated Cost: $185 million
•
Major Facilities:
o
3 new compressor stations
•
FERC Status:
o
Open Season concluded in Nov. 2015
o
Preparing precedent agreements

Appalachia
$111
$137
$161
$186
$188
$190
$10
$15
$30
$64
$69
$62
$121
$152
$191
$250
$257
$252
$0
$100
$200
$300
2011
2012
2013
2014
2015
TTM
12-31-2015
Fiscal Year
  Gathering
  Pipeline & Storage
Midstream Businesses EBITDA
26
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.

Downstream Overview
Utility  |  Energy Marketing
27

Downstream
New York & Pennsylvania Service Territories
28
(1)  As of September 30, 2015.
New York
Pennsylvania
Total Customers
(1)
: 526,323
ROE: 9.1% (NY PSC Rate Case Settlement, May 2014)
Rate Mechanisms:
o
Earnings Sharing
o
Revenue Decoupling
o
Weather Normalization
o
Low Income Rates
o
Merchant Function Charge (Uncollectibles
Adj.)
o
90/10 Sharing (Large Customers)
Total Customers
(1)
: 213,652
ROE: Black Box Settlement (2007)
Rate Mechanisms:
o
Low Income Rates
o
Merchant Function Charge

Downstream
Utility: Shifting Trends in Customer Usage
29
(1)  Weighted Average of New York and Pennsylvania service territories (assumes normal weather).
80
90
100
110
120
12-Months Ended December 31
20
25
30
35
40
12-Months Ended December 31
Residential Usage
Industrial Usage

Downstream
$152
$152
$152
$151
$163
$160
$16
$16
$20
$33
$28
$28
$11
$9
$6
$10
$9
$10
$179
$177
$178
$193
$200
$198
$0
$50
$100
$150
$200
$250
2011
2012
2013
2014
2015
12 Months
ended
12/31/15
Fiscal Year
  All Other O&M Expenses
  O&M Pension Expense
  O&M Uncollectible Expense
A Proven History of Controlling Costs
30
(1)
$10 million of increase in pension costs from fiscal 2013 primarily due to  the NY PSC rate case settlement in May 2014.
(1)

Downstream
The Utility
remains focused on maintaining the
ongoing safety and reliability of its system
Utility: Strong Commitment to Safety
31
Near-term increase due to
~$60MM upgrade of the Utility’s
Customer Information System
and anticipated acceleration of
pipeline replacement program
$44.3
$43.8
$48.1
$49.8
$54.4
$58.4
$58.3
$72.0
$88.8
$94.4
$95 -
$105
0
30
60
90
120
150
2011
2012
2013
2014
2015
2016E
Fiscal Year
Capital Expenditures for Safety
Total Capital Expenditures

32
32
California
Exploration & Production

California: Stable Production; Modest Growth
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
0
1,500
3,000
4,500
6,000
North
Midway
Sunset
South
Midway
Sunset
South Lost
Hills
North Lost
Hills
Sespe
East
Coalinga
FY 2010
FY 2015
Upstream

Upstream
8,773
9,322
9,078
9,699
9,674
9,560
0
2,500
5,000
7,500
10,000
2011
2012
2013
2014
2015
2016
Forecast
Fiscal Year
California Average Daily Net Production
34
$40-$50 Million Annual Capital Spending to Keep Production Flat

Upstream
Strong Margins Support Significant Free Cash Flow
35
$12.74
$3.37
$5.56
$2.90
$2.44
$33.83
Non-Steam Fuel LOE
Steam Fuel
G&A
Production & Other
Taxes
Other Operating Costs
Adjusted EBITDA
West Division Adjusted EBITDA per BOE
(1)
Trailing 12-months Ended 12/31/15
DD&A
Average Revenue
for TTM 12/31/15
(1)
$60.84 per BOE
(1)
Average revenue per BOE  includes impact of hedging and other revenues. 
Note: A reconciliation of Adjusted EBITDA margin 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.
EBITDA per BOE includes Seneca corporate results and eliminations.

Consolidated Financial Overview
Upstream  |  Midstream  | Downstream
36

Corporate
Appalachia Driving Proved Reserve Growth
37
43.3
42.9
41.6
38.5
33.7
675
988
1,300
1,683
2,142
935
1,246
1,549
1,914
2,344
0
500
1,000
1,500
2,000
2,500
3,000
2011
2012
2013
2014
2015
At September 30
Natural Gas (Bcf)
Crude Oil (MMbbl)
Fiscal
Years
3-Year
F&D Cost
(2)
($/Mcfe)
2008-2010
$2.37
2009-2011
$2.09
2010-2012
$1.87
2011-2013
$1.67
2012-2014
$1.38
2013-2015
$1.12
•
2015 F&D Cost = $0.96
•
Marcellus F&D: $0.79
•
373% Reserve
Replacement Rate
•
65% Proved Developed
(1)
(1)
Includes approximately 150 Bcf of natural gas PUD reserves in Clermont/Rich Valley that will be transferred in fiscal 2016 as interests in the joint development wells are conveyed to the partner.
(2)
Represents a three-year average U.S. finding and development cost.

Corporate
Seneca Production
38
(1)
Refer to slide 20 for additional details on fiscal 2016 firm sales and local Appalachian spot market exposure.  
19.2
20.5
20.0
21.2
21.2
~21
43.2
62.9
100.7
139.3
136.6
129.0
Appalachia
Spot Sales
67.6
83.4
120.7
160.5
157.8
150 –
180 Bcfe
0
50
100
150
200
2011
2012
2013
2014
2015
2016E
Fiscal Year
Gulf of Mexico (Divested in 2011)
Appalachia Division
West Coast Division
(1)

Corporate
$169
$160
$172
$165
$164
$157
$111
$137
$161
$186
$188
$190
$64
$69
$62
$377
$397
$492
$539
$422
$378
$668
$704
$852
$953
$843
$785
$0
$250
$500
$750
$1,000
$1,250
2011
2012
2013
2014
2015
TTM
12/31/15
Fiscal Year
Exploration & Production Segment
Gathering Segment
Pipeline & Storage Segment
Utility Segment
Energy Marketing & Other
EBITDA Contribution by Segment
39
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.

Corporate
$58
$58
$72
$89
$94
$95-$105
$129
$144
$56
$140
$230
$125-$175
$80
$55
$138
$118
$85-$95
$649
$694
533
$603
$557
$150-$200
$854
$977
$717
$970
$1,001
$455-
$575
$0
$500
$1,000
$1,500
2011
2012
2013
2014
2015
2016E
Fiscal Year
Exploration & Production Segment
Gathering Segment
Pipeline & Storage Segment
Utility Segment
Energy Marketing & Other
Capital Expenditures by Segment
40
(1)
(1)
FY2016 capital expenditure guidance reflects the netting of up-front proceeds received from joint development partner for capital spent on wells drilled and/or completed prior to the execution date of the 
joint development agreement. The E&P segment’s FY16 capital budget would be reduced by an additional $90-$110 million if joint development partner exercises right to participate in remaining 38 wells.
Note: A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation.

Corporate
Financial Position & Liquidity
41
Note:  A reconciliation of Adjusted EBITDA to Net Income is included at the end of this presentation.
Total
Debt
54%
$3.9 Billion Total Capitalization
as of December 31, 2015
Debt/Adjusted EBITDA
Capitalization
Debt Maturity Profile ($MM)
Liquidity
Committed Credit Facilities
Short-term Debt Outstanding
Available Short-term Credit Facilities
Cash Balance at 12/31/15
Total Liquidity at 12/31/15
$ 1,250 MM
$ 31 MM
$ 1,219 MM
$ 36 MM
$ 1,255 MM
Total
Equity
46%
1.75 x
1.89 x
1.89 x
1.77 x
2.27 x
2.52 x
2011
2012
2013
2014
2015
TTM            
12-31-15
Fiscal Year
$300
$250
$500
$549
$500
$0
$200
$400
$600

Corporate
Dividend Track Record
42
(1) As of February 3, 2016.
Current
Dividend Yield
(1)
3.4%
Dividend Consistency
Consecutive Dividend Payments
113 Years
Consecutive Dividend Increases
45 Years
Current
Annualized Dividend Rate
$1.58
per Share
$0.00
$0.50
$1.00
$1.50
$2.00
Annual Rate at Fiscal Year End

Appendix
43
43

Appendix
2015 Pipeline Expansion Projects In-Service
44
Westside Expansion & Modernization
In-Service (October 2015)
Tuscarora Lateral
In-Service (November 2015)
2015 Completed Pipeline Expansion Projects
•
Total Cost: $60.0 million
•
Incremental annual revenues of $10.9
million on 49,000 Dth per day capacity
•
Preserves $16.1 million in annual revenues
on existing FT (192,500 Dth/d) and retained
storage (3.3 Bcf) services
•
Total Cost: $86 million
o
Expansion: $45 million
o
Modernization: $41 million
•
Incremental Annual Revenues: $8.8 million
•
Capacity: 175,000 Dth per day
o
Range Resources (145,000 Dth/d)
o
Seneca Resources (30,000 Dth/d)
Tuscarora
Lateral
Westside
Expansion &
Modernization

Appendix
Total Seneca Capital Spending by Division
45
$47
$63
$105
$83
$57
$40-$50
$596
$631
$428
$520
$500
$110-
$150
$649
$694
$533
$603
$557
$150 -
$200
$0
$200
$400
$600
$800
$1,000
2011
2012
2013
2014
2015
2016E
Fiscal Year
Gulf of Mexico (Divested in 2011)
Appalachia
West Coast (California)
(2)
(1)
(1)
FY2016 capital expenditure guidance reflects the netting of up-front proceeds received from joint development partner for capital spent on wells drilled and/or completed prior to the execution date of the joint
development agreement. The FY16 capital budget would be reduced by an additional $90-$110 million if joint development partner exercises right to participate in remaining 38 wells.
(2)
Seneca’s West Coast division includes Seneca corporate and eliminations.

Exploration & Production
Appalachia
Marcellus Operated Well Results
46
EDA Development Wells:
Area
Producing
Well
Count
Average IP Rate
(MMcfd)
Average
30-Day (MMcf/d)
Average Treatable
Lateral Length (ft)
Covington
Tioga
County
47
5.2
4.1
4,023’
Tract 595
Tioga
County
44
(2)
7.4
4.9
4,754’
Tract 100
Lycoming
County
57
(2)
16.8
12.6
5,270’
Area
Producing
Well
Count
Average IP Rate
(MMcfd)
Average
30-Day (MMcf/d)
Average Treatable
Lateral Length (ft)
Clermont/Rich Valley
(CRV) & Hemlock
Elk, Cameron &
McKean
counties
56
(1)
7.5
5.7
(1)
6,823’
WDA Development Wells:
(1)
Excludes 2 wells now operated by Seneca that were drilled by another operator as part of a joint-venture.  30-day average excludes 2 wells that have not been on line 30 days.
(2)
Does not include 1 well drilled into and producing from the Geneseo Shale.

Appendix
$0.91
$0.76
$0.65
$0.57
$0.57
$0.55
$0.17
$0.24
$0.34
$0.46
$0.49
$0.50
$0.73
$0.65
$0.52
$0.40
$0.42
$0.43
$0.18
$0.28
$0.14
$0.13
$0.13
$0.13
$2.09
$2.01
$1.74
$1.65
$1.70
~$1.68
$0.00
$1.00
$2.00
$3.00
2011
2012
2013
2014
2015
2016E
Fiscal Year
Property, Franchise & Other Taxes
Other O&M Expense
General & Administrative Expense
Lease Operating & Transportation Expense (Gathering Only)
Lease Operating & Transportation Expense (Excl. Gathering)
Highly Competitive Cost Structure
47
(1)
(2)
(2)
(3)
(1)
(2)
(2)
(1)
Represents the midpoint of General & Administrative Expense guidance of $0.40 to $0.45 per Mcfe for fiscal 2016.
(2)
The total of the two LOE components represents the midpoint of LOE guidance of $1.00  to $1.10 per Mcfe for fiscal 2016.
(3)
The cost of firm transportation is reflected in price realizations (a deduction to gross revenues). As such, it is not included in LOE.

Appendix
Marcellus Shale Program Economics
~1,200 WDA Locations Economic Below $2.50/MMBtu
$3.25
IRR %
(1)
$3.00
IRR %
(1)
$2.75
IRR %
(1)
DCNR 100
Dry Gas
12
5,400
13-14
1033
78%
59%
43%
$1.57
Gamble
Dry Gas
44
4,600
11-12
1033
47%
35%
22%
$1.83
CRV
Dry Gas
72
8,800
10-11
1045
32%
23%
17%
$1.92
Hemlock /
Ridgway
Dry Gas
662
8,800
8-9
1045 - 1110
23%
16%
11%
$2.14
Remaining
Tier 1
Dry Gas
423
8,500
7-8
1030 - 1110
21%
14%
10%
$2.31
15% IRR
(1)
Realized Price
NYMEX / DAWN Pricing
Prospect
Product
Locations
Remaining
to Be Drilled
Completed
Lateral
Length (ft)
Average
EUR (Bcf)
BTU
(1)
Internal Rate of Return (IRR) is pre-tax and includes estimated well costs under current cost structure, LOE, and Gathering tariffs anticipated for each prospect.
48

Appendix
Firm Transportation Portfolio
49
(1)
A large majority of the  executed firm sales agreements continue for the remainder of the firm transportation contract term.
(2)
Excludes throughput-based commodity charges, fuel charges and other surcharges.
Project
(Counterparty)
In-
Service
Date
Contract
Term
Delivery
Market
Demand
Charge
($/Dth)
Gross FT Capacity
(Dth/day)
Matched Firm
Sales Contracts
Fiscal
2016
Fiscal
2017
Fiscal
2018
Northeast
Supply
Diversification
Project (TGP)
Nov.
2012
15 years
Canada
$0.49
50,000
50,000
50,000
Executed Contracts
50,000 Dth/d
for 10 years
Niagara Expansion
(TGP
&
NFG)
Nov.
2015
15 years
Canada
$0.67
158,000
158,000
158,000
Executed Contracts
140,000 Dth/d
for 15 years
TETCO
$0.12
12,000
12,000
12,000
Atlantic Sunrise
(Transco)
Sept.
2017
15 years
Mid-
Atlantic/
Southeast
$0.73
---
---
189,405
Executed
Contracts
189,405 Dth/d
for first 5 years
(1)
Northern Access
2016 (NFG/
TransCanada/
Union)
Nov.
2017
15 years
Canada
$0.70
---
---
350,000
Executed Contracts
145,000 Dth/d
For first 3 years
TGP 200
(NY)
$0.38
---
---
140,000
Total Firm Transportation Capacity
220,000
220,000
899,405
Weighted Average
Transportation Charge per Dth
(2)
$0.59
$0.60
$0.63

Appendix
219,698
Plus $0.07
178,098
Less: $0.01
178,098
Less:  $0.01
65,000  Less: $0.55
50,000  Less: $0.33
50,000  Less: $0.33
25,000  Less: $0.02
65,000  Less: $0.01
65,000  Less: $0.01
160,000
$2.78
175,000
$2.61
175,000
$2.61
469,698
468,098
468,098
0
200,000
400,000
600,000
Q2
Q3
Q4
Fixed Price
Dawn
Dominion SP
NYMEX
Firm Sales Provide Market for Appalachian Production
50
(1)
Reflects gross firm sales volumes before impact of lease royalties  in EDA or  net revenue interests assigned to  joint development partner  on certain contracts in WDA.
(2)
Values shown represent the price or differential to a reference price (netback price) at the point of sale.
WDA
(1)
209,600/d
263,000/d
263,000/d
EDA
(1)
260,098/d
205,098/d
205,098/d
Fiscal 2016 Firm Sales by Fiscal Quarter
Pricing Index Key:
EDA/WDA Split:
Gross
Contracted
Volumes
(Dth
per
day)
(1)
Contracted
Index
Price
Differentials
($
per
Dth)
(2)

Exploration & Production
Appalachia
$3.35
$3.99
$3.18
$2.83
$2.77
$2.62
$2.46
$2.02
NFG
P1
P2
P3
P4
P5
P6
P7
Before Hedging
Hedging Uplift
$2.06
$2.06
$1.85
$1.58
$1.57
$1.18
$0.86
$0.77
NFG
P1
P2
P5
P4
P7
P6
P3
Peer Average
$1.41/Mcfe
Appalachian Price Realizations & Margins
51
Q4 FY15 Average Natural Gas Realizations per Mcf 
vs. Appalachian Peer Group
(1)
Q4 FY15 Adjusted EBITDA per Mcfe
(2)
vs. Appalachian Peer Group
(1)
Strong hedge book,
firm sales portfolio, and cost
discipline generating impressive
natural gas price realizations and margins in challenging commodity environment 
Peer Average
$2.84/Mcf
Appalachia
Appalachia
(1)
Appalachian peer group includes AR, COG, CNX, EQT,  GPOR, RICE, &RRC . Peer group information obtained or estimated by National Fuel Gas Company from peer company quarterly public filings (press release &
Form 10-Q) for the quarter-ended September 30, 2015.  Where necessary, peer company realizations and margins were adjusted to reflect cash settled hedges and results of  exploration and production
operations only.
(2)
Note: A reconciliation of Adjusted EBITDA per Mcfe 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.

Appendix
Volume
Avg.
Price
Volume
Avg.
Price
Volume
Avg.
Price
Volume
Avg.
Price
Volume
Avg.
Price
NYMEX Swaps
28,440
$3.92
29,530
$4.20
20,350
$3.62
11,400
$3.39
2,000
$3.49
Dominion
Swaps
14,130
$3.78
12,720
$3.87
-
-
-
-
-
-
MichCon Swaps
9,000
$4.10
3,000
$4.10
-
-
-
-
-
-
Dawn Swaps
9,990
$3.92
19,100
$3.70
1,800
$3.40
-
-
-
-
Fixed Price
Physical Sales
30,426
$2.75
32,893
$3.03
8,010
$3.21
5,840
$3.25
2,928
$3.25
Total
91,986
$3.53
97,243
$3.66
30,160
$3.50
17,240
$3.34
4,928
$3.35
Fiscal 2019
Fiscal 2020
Fiscal 2016
Fiscal 2017
Fiscal 2018
Natural Gas Hedge Positions
52
(Volumes in thousands MMBtu; Prices in $/MMBtu)
(1)
For the remaining nine months of Fiscal 2016.
(2)
Fixed price physical sales exclude joint development partner’s share of fixed price contract WDA volumes as specified under the joint development agreement.
(1)
(2)

Appendix
Crude Oil Hedge Positions
53
Fiscal 2016
Fiscal 2017
Fiscal 2018
Volume
Avg.
Price
Volume
Avg.
Price
Volume
Avg.
Price
Brent Swaps
404,000
$94.63
231,000
$92.14
51,000
$91.00
NYMEX Swaps
640,000
$83.33
465,000
$66.77
24,000
$90.52
Total
1,044,000
$87.70
696,000
$75.19
75,000
$90.85
(Volumes & Prices in Bbl)
(1)
For the remaining nine months of Fiscal 2016.
(1)

Utica/Point Pleasant: EDA Opportunities
54
Shell: Gee
11.2 MMcf/d
PGE
Vertical Tests
Permitted
Drilling
Completed
Producing
Seneca
Horizontal
Planned
or Potential
Shell: Neal
26.5 MMcf/d
Other Operators
DCNR Tract 001
Potential Future Location
DCNR 595
Potential Future Location
JKLM
Pt Pleasant Test
Seneca DCNR Tract 007
IP: 22.7 MMcf/d
Lateral Length: 4,640’
Potential locations: ~ 70
Anticipated Development Well
Cost: $7-$10 Million (5,500’ Lat.) 
Travis Peak:
Currently Drilling

Appendix
Comparable GAAP Financial Measure Slides & Reconciliations
55
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.

Appendix
National Fuel Gas Company
56
Reconciliation of Adjusted EBITDA to Consolidated Net Income
($ Thousands)
FY 2011
FY 2012
Total Adjusted EBITDA
Exploration & Production Adjusted EBITDA
377,457
$           
397,129
$           
492,383
$              
539,472
$              
422,289
$              
377,998
           
Pipeline & Storage Adjusted EBITDA
111,474
             
136,914
             
161,226
                
186,022
                
188,042
                
189,890
           
Gathering Adjusted EBITDA
9,386
                  
14,814
                
29,777
                  
64,060
                  
68,783
                  
62,478
             
Utility Adjusted EBITDA
168,540
             
159,986
             
171,669
                
164,643
                
164,037
                
156,524
           
Energy Marketing Adjusted EBITDA
13,178
                
5,945
                  
6,963
                     
10,335
                  
12,150
                  
9,355
               
Corporate & All Other Adjusted EBITDA
(12,346)
              
(10,674)
              
(9,920)
                   
(11,078)
                 
(11,900)
                 
(11,391)
            
Total Adjusted EBITDA
667,689
$           
704,114
$           
852,098
$              
953,454
$              
843,401
$              
784,854
$        
Total Adjusted EBITDA
667,689
$           
704,114
$           
852,098
$              
953,454
$              
843,401
$              
784,854
$        
Minus: Interest Expense
(78,121)
              
(86,240)
              
(94,111)
                 
(94,277)
                 
(99,471)
                 
(108,122)
         
Plus:  Interest and Other Income
8,863
                  
8,822
                  
9,032
                     
13,631
                  
11,961
                  
13,737
             
Minus: Income Tax Expense
(164,381)
            
(150,554)
            
(172,758)
               
(189,614)
               
319,136
                
518,646
           
Minus: Depreciation, Depletion & Amortization
(226,527)
            
(271,530)
            
(326,760)
               
(383,781)
               
(336,158)
               
(303,962)
         
Minus: Impairment of Oil and Gas Properties (E&P)
-
                      
-
                      
-
                          
-
                          
(1,126,257)
           
(1,561,708)
      
Plus: Reversal of Stock-Based Compensation
-
                      
-
                      
-
                          
-
                          
7,961
                     
7,961
               
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)
                          
-
                          
-
                          
-
                          
-
                    
Minus: Joint Development Agreement Professional Fees
-
                      
-
                      
-
                          
-
                          
-
                          
(4,682)
              
Consolidated Net Income
258,402
$           
220,077
$           
260,001
$              
299,413
$              
(379,427)
$            
(653,276)
$       
Consolidated Debt to Total Adjusted EBITDA
Long-Term Debt, Net of Current Portion (End of Period)
899,000
$           
1,149,000
$        
1,649,000
$          
1,649,000
$          
2,099,000
$          
2,099,000
$     
Current Portion of Long-Term Debt (End of Period)
150,000
             
250,000
             
-
                          
-
                          
-
                          
-
                     
Notes Payable to Banks and Commercial Paper (End of Period)
40,000
                 
171,000
             
-
                          
85,600
                   
-
                          
31,400
             
Total Debt (End of Period)
1,089,000
$        
1,570,000
$        
1,649,000
$          
1,734,600
$          
2,099,000
$          
2,130,400
$     
Long-Term Debt, Net of Current Portion (Start 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 (Start of Period)
200,000
             
150,000
             
250,000
                
-
                          
-
                          
-
                    
Notes Payable to Banks and Commercial Paper (Start of Period)
-
                      
40,000
                
171,000
                
-
                          
85,600
                   
172,900
           
Total Debt (Start of Period)
1,249,000
$        
1,089,000
$        
1,570,000
$          
1,649,000
$          
1,734,600
$          
1,821,900
$     
Average Total Debt
1,169,000
$        
1,329,500
$        
1,609,500
$          
1,691,800
$          
1,916,800
$          
1,976,150
$     
Average Total Debt to Total Adjusted EBITDA
1.75 x
1.89 x
1.89 x
1.77 x
2.27 x
2.52 x
FY 2013
12-Months
Ended 12/31/15
FY 2014
FY 2015

Appendix
National Fuel Gas Company
57
Reconciliation of Exploration & Production - West Coast division Adjusted EBITDA per Mboe of Production
($ Thousands)
12-Months
Ended 12/31/15
Appalachia Division Adjusted EBITDA
259,134
$        
West Coast Division Adjusted EBITDA
118,864
          
Total Exploration & Production Adjusted EBITDA
377,998
$        
West Coast Division Adjusted EBITDA
118,864
$        
West Coast Production (Mboe)
3,514
             
West Coast Division Adjusted EBITDA per Mboe
33.83
$           
Note: Seneca West Coast division includes Seneca corporate and eliminations.

Appendix
National Fuel Gas Company
58
(1)
FY2016  Exploration and Production capital expenditure guidance reflects the netting of up-front proceeds received from joint development partner for capital spent on wells drilled and/or
completed prior to the execution date of the joint development agreement.
Reconciliation of Segment Capital Expenditures to
Consolidated Capital Expenditures
($ Thousands)
FY 2016
FY 2011
FY 2012
FY 2013
FY 2014
FY 2015
Forecast
Capital Expenditures from Continuing Operations
Exploration & Production Capital Expenditures
648,815
$        
693,810
$        
533,129
$        
602,705
$        
557,313
$        
$150,000-200,000
Pipeline & Storage Capital Expenditures
129,206
          
144,167
          
56,144
$          
139,821
$        
230,192
$        
$125,000-175,000
Gathering Segment Capital Expenditures
17,021
            
80,012
            
54,792
$          
137,799
$        
118,166
$        
$85,000-95,000
Utility Capital Expenditures
58,398
            
58,284
            
71,970
$          
88,810
$          
94,371
$          
$95,000-105,000
Energy Marketing, Corporate & All Other Capital Expenditures
746
                  
1,121
               
1,062
$            
772
$                
467
$                
-
                                 
Total Capital Expenditures from Continuing Operations
854,186
$        
977,394
$        
717,097
$        
969,907
$        
1,000,509
$    
$455,000-575,000
Capital Expenditures from Discountinued Operations
All Other Capital Expenditures
-
$                 
-
$                 
-
$                 
-
$                 
-
$                 
-
$                               
Plus (Minus) Accrued Capital Expenditures
Exploration & Production FY 2015 Accrued Capital Expenditures
-
$                  
-
$                  
-
$                  
-
$                  
(46,173)
$         
Exploration & Production FY 2014 Accrued Capital Expenditures
-
                   
-
                   
-
                   
(80,108)
           
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
            
-
                   
-
                   
-
                   
-
                   
-
                                 
Pipeline & Storage FY 2015 Accrued Capital Expenditures
-
                         
-
                   
-
                   
-
                   
(33,925)
           
Pipeline & Storage FY 2014 Accrued Capital Expenditures
-
                   
-
                   
-
                   
(28,122)
           
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
                
-
                    
-
                    
-
                    
-
                    
-
                                 
Gathering FY 2015 Accrued Capital Expenditures
-
                        
-
                   
-
                   
-
                   
(22,416)
           
Gathering FY 2014 Accrued Capital Expenditures
-
                   
-
                   
-
                   
(20,084)
           
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
               
-
                   
-
                   
-
                   
-
                                 
Utility FY 2015 Accrued Capital Expenditures
-
                    
-
                    
-
                    
-
                    
(16,445)
           
Utility FY 2014 Accrued Capital Expenditures
-
                   
-
                   
-
                   
(8,315)
             
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
(39,908)
$         
57,613
$          
(13,636)
$         
(55,490)
$         
17,670
$          
-
$                               
Eliminations
-
$                 
-
$                 
-
$                 
-
$                 
-
$                 
-
$                               
Total Capital Expenditures per Statement of Cash Flows
814,278
$        
1,035,007
$    
703,461
$        
914,417
$        
1,018,179
$    
$455,000-575,000
(1)

Appendix
National Fuel Gas Company
59
Reconciliation of Exploration & Production Adjusted EBITDA for Appalachia and West Coast divisions
to Exploration & Production Segment Net Income
($ Thousands)
Appalachia
West Coast
Total E&P
Appalachia
West Coast
Total E&P
Appalachia
West Coast
Total E&P
Appalachia
West Coast
Total E&P
Reported GAAP Earnings
(144,511)
$    
(62,508)
$      
(207,019)
$    
12,104
$        
21,557
$        
33,661
$        
(378,594)
$    
(178,380)
$    
(556,974)
$    
47,962
$        
73,607
$        
121,569
$     
Depreciation, Depletion and Amortization
36,837
          
9,440
            
46,277
          
65,422
          
15,609
          
81,031
          
188,489
        
51,329
          
239,818
        
238,541
        
57,669
          
296,210
        
Interest and Other Income
-
                 
(661)
              
(661)
              
-
                 
(604)
              
(604)
              
-
                 
(2,554)
           
(2,554)
           
-
                 
(1,909)
           
(1,909)
           
Interest Expense
13,613
          
563
                
14,176
          
9,977
            
607
                
10,584
          
44,798
          
1,928
            
46,726
          
40,015
          
2,217
            
42,232
          
Income Taxes
(123,825)
      
(45,796)
         
(169,621)
      
(4,190)
           
18,336
          
14,146
          
(295,912)
      
(132,305)
      
(428,217)
      
18,179
          
63,191
          
81,370
          
Impairment of Oil and Gas Producing Properties
285,038
        
132,159
        
417,197
        
-
                 
-
                 
-
                 
730,115
        
396,142
        
1,126,257
    
-
                 
-
                 
-
                 
Reversal of Stock Based Compensation
(825)
              
(1,942)
           
(2,767)
           
-
                 
-
                 
-
                 
(825)
              
(1,942)
           
(2,767)
           
-
                 
-
                 
-
                 
Adjusted EBITDA
66,327
$        
31,255
$        
97,582
$        
83,313
$        
55,505
$        
138,818
$     
288,071
$     
134,218
$     
422,289
$     
344,697
$     
194,775
$     
539,472
$     
Appalachia
West Coast
Total E&P
Appalachia
West Coast
Total E&P
Appalachia
West Coast
Total E&P
Appalachia
West Coast
Total E&P
Production:
Gas Production (MMcf)
32,183
          
785
                
32,968
          
40,456
          
808
                
41,264
          
136,404
        
3,159
            
139,563
        
139,097
        
3,210
            
142,307
        
Oil Production (MBbl)
8
                    
770
                
778
                
8
                    
774
                
782
                
30
                  
3,004
            
3,034
            
31
                  
3,005
            
3,036
            
Total Production (Mmcfe)
32,231
          
5,405
            
37,636
          
40,504
          
5,452
            
45,956
          
136,584
        
21,183
          
157,767
        
139,283
        
21,240
          
160,523
        
Adjusted EBITDA Margin per Mcfe
2.06
$            
5.78
$            
2.59
$            
2.06
$            
10.18
$          
3.02
$            
2.11
$            
6.34
$            
2.68
$            
2.47
$            
9.17
$            
3.36
$            
Total Production (Mboe)
5,372
            
901
                
6,273
            
6,751
            
909
                
7,660
            
22,764
          
3,531
            
26,295
          
23,214
          
3,540
            
26,754
          
Adjusted EBITDA Margin per Boe
12.35
$          
34.69
$          
15.56
$          
12.34
$          
61.06
$          
18.12
$          
12.65
$          
38.01
$          
16.06
$          
14.85
$          
55.02
$          
20.16
$          
Note: Seneca West Coast division includes Seneca corporate and eliminations.
Three Months Ended
September 30, 2015
Three Months Ended
September 30, 2014
Twelve Months Ended
September 30, 2015
Twelve Months Ended
September 30, 2014

Stock widget

Investing forum

NATIONAL FUEL GAS CO Reports