Investor Presentation · 2020. 1. 30. · Leidy South (Mid-Atlantic) Firm Sales tied to Firm Transportation (FT) Capacity (Mid-Atlantic/Southeast & Canada-Dawn) Reduced Activity to

Investor Presentation

Q1 Fiscal 2020 UpdateJanuary 30, 2020

2

National Fuel is committed to the safe and environmentally conscious development, transportation, storage, and

distribution of natural gas and oil resources.

For additional information, please visit our corporate responsibility website at https://responsibility.natfuel.com

https://responsibility.natfuel.com/

3

Developing our large, high quality acreage position in Marcellus & Utica shales(1)

NFG: A Diversified, Integrated Natural Gas Company

Providing safe, reliable and affordable service to customers in WNY and NW Pa.

UpstreamExploration &

Production

MidstreamGathering

Pipeline & Storage

38% of NFG EBITDA(1)

DownstreamUtility

% of NFG 20EBITDA(1)

Expanding and modernizing pipeline infrastructure to provide outlets for Appalachian natural gas production

785,000Net acres in Appalachia

~590 MMcf/dayNet Appalachian natural gas production

$1.7 BillionInvestments

since 2010

3.9 MMDthDaily interstate pipeline capacity under contract

743,400Utility

customers

$324 MillionInvestments in safety since 2015

California: oil production generates significant cash flow

(1) This presentation includes forward-looking statements. Please review the safe harbor for forward looking statements on slide 56 of this presentation.(2) Twelve months ending December 31, 2019. 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.




:

4

Why National Fuel?

Diversified Assets Provide Stability and Long-Term Growth Opportunities

5

Midstream

Integrated Model Enhances Shareholder Value . . .

Ability to adjust to changing commodity price environments

More efficient capital investment Higher returns on investment Operational scale Lower cost of capital Lower operating costs More competitive pipeline

infrastructure projects Strong balance sheet Growing, stable dividend

Geographic and Operational Integration Drives Synergies:

Benefits of National Fuel’s Integrated Structure:

Financial Efficiencies: Investment grade credit rating Shared borrowing capacity Consolidated income tax return

DownstreamUtility

MidstreamGathering

Pipeline & Storage

UpstreamExploration &

Production

Co-Development of Marcellus and Utica Just-in-time gathering facilities Pipeline expansion opportunities

Upstream

Rate-regulated entities share common resources, reducing operating expense

Utility business is a large Pipeline & Storage customer

DownstreamMidstream

1

6

Integrated Upstream and Midstream development of 785,000 acre Marcellus and Utica shale position

Drilling program focused on return trips to existing pads and use of existing infrastructure

NFG Gathering transports 100% of natural gas production, driving consolidated returns

NFG pipeline expansions under development create new firm takeaway capacity for E&P business

Further expansion of interstate pipeline systems to satisfy growing natural gas supply and demand

Supply push – Appalachian producers

Demand pull – regional demand-driven projects and utilities

Ongoing investment in safety and modernization of pipeline transportation and distribution systems

$500+ million in new investments expected over the next 5 years

. . . and Drives Organic Growth Opportunities

Near Term Strategy Leverages Integration Across the Value Chain

UtilityGathering Pipeline & Storage Exploration &

Production

7

Impressive Dividend History

Annual Rate at Fiscal Year End

$3.1 BillionDividend payments since 1970

$1.74per share

49 YearsConsecutive Dividend Increases

$0.19per share

117 YearsConsecutive Payments

4.0%yield(1)

(1) As of January 28, 2020.

2

8

Responsible Capital Allocation and Asset Development

Maintaining Focus on Balance Sheet, With Reductions in E&P Activity in Response to

Low Natural Gas Price Environment . . .

E&P3

$492

$415-$455$375-$410

$0

$100

$200

$300

$400

$500

2019 Actual 2020 Guidance(August)

2020 Guidance(Current)

E&P

Cap

ital E

xpen

ditu

res

($ M

M)

. . . While Generating Steady Production, and Optimizing Significant Firm Sales Portfolio

and Firm Transportation Capacity

-

100

200

300

400

500

600

700

800

900

1,000

Gro

ss F

irm C

ontr

act V

olum

es (M

Dth

/day

)

In-Basin Firm Sales Contracts

Leidy South (Mid-Atlantic)

Firm Sales tied to Firm Transportation (FT) Capacity (Mid-Atlantic/Southeast & Canada-Dawn)

Reduced Activity to 2 rigs

Company intends to further reduce activity in summer 2020, driving lower capital

expenditures in fiscal 2020 and beyond

Further Activity

Reduction

Full Year at 3 rigs

Gross Production Trend (Reduced Activity Level)

9

Utilization of Existing Infrastructure for Ongoing Utica Development Amplifies Consolidated Returns

L Leveraging Existing Infrastructure to Enhance Returns

(1) Approximate WDA Marcellus gathering facility costs for 192 wells drilled and completed as of September 30, 2018. (2) Estimated WDA Utica gathering facility costs for remaining return trip locations in the Clermont Rich Valley area of redevelopment. (3) Internal Rate of Return for Seneca WDA includes estimated well costs under current cost structure, and anticipated LOE and Gathering costs. Internal Rate of Return for Seneca WDA and Gathering includes expected gathering capital expenditures for

remaining return trip locations, well costs under current cost structure, and non-gathering LOE.

Gathering CapEx/Well

($ thousands)Marcellus (pre-2019) $1,489

(1)

Utica Return Trips (current) ~$430

(2)

Gathering Pipelines

Compression

Water Handling Facilities

Roadways and Pads

Gathering Costs in Western Development Area (CRV) ~10% IRR Uplift

Expected(3)

Requires modest investment in new Gathering facilities to support production growth

Utica development on Marcellus pads allows use of existing:

Resulting in significant consolidated return uplift for E&P and Gathering

4

10

$1 Billion+ Backlog in Pipeline & Storage Projects

Northern Access Delivery: Canada & NY

490,000 Dth/d

Line N to MonacaDelivery: Shell ethane cracker

facility (Beaver Co., Pa)133,000 Dth/d

FM100Delivery: Transco (Leidy)

330,000 Dth/d

Empire NorthDelivery: Canada & NY

205,000 Dth/d

~$150 Million in Potential Annual Expansion Revenues:

Line N to Monaca: $5 MM(placed into service 11/1/19)

Empire North: $25 MM

FM100: $35 MM

Northern Access: $84 MM

$1.0 – $1.1 Billion in Pipeline Projects under Development:

Expansion Projects:~$850 million

Supply Corp. Modernization: $150 - $250 million

5

11

Financial Highlights

First Quarter Fiscal 2020

12

572 601 45.854.8

Net

Oil

and

Gas

Pr

oduc

tion

First Quarter Fiscal 2020 Results and Drivers

(1) Adjusted Operating results of $1.12 for Q1 FY19 and $1.01 for Q1 FY20 include operating results of Corporate & All Other Segments segment. See slide 65 for a Reconciliation of Adjusted Operating Results to Earnings Per Share.(2) Realized price after hedging.

$61.70 $62.92$2.61

$2.32

Q1 FY 2019 Q1 FY 2020

Oil

and

Gas

Pr

icin

g(2)

Natural Gas ($/Mcfe)Crude Oil ($/Bbl)

Oil Prices

Natural Gas Prices

$29.7 MM

$34.8 MM

Gat

herin

g R

even

ue

Seneca Gross Production

Drivers

Natural Gas Production

Oil Production

Crude Oil (Mbbl) Natural Gas (Bcf)Exploration & Production

$0.37Exploration &

Production $0.28

Gathering $0.16 Gathering

$0.18

Pipeline & Storage

$0.29 Pipeline & Storage

$0.21

Utility$0.30

Utility$0.31

$1.12

$1.01

All Other: $0.00 All Other: $0.03

Q1 FY19 Q1 FY20

Adjusted Operating Results ($/share)(1)

13

Earnings Guidance

FY2019 Adjusted Operating Results

Non-regulated Businesses

Exploration & ProductionGathering

$3.45/share(1) $2.95 to $3.15/shareFY2020 Earnings Guidance

Seneca Net Production: 235 to 245 Bcfe Gathering Revenues: $135-$145 million

Natural Gas: ~$2.10/Mcf(2) (vs. $2.44/Mcf in FY 2019)

Crude Oil: ~$62.00/Bbl(3) (vs. $61.65/Bbl in FY 2019)

Key Guidance Drivers

(1) Excludes items impacting comparability. See non-GAAP disclosure on slide 65 of this presentation.(2) Assumes NYMEX natural gas pricing of $2.05/MMBtu and in-basin spot pricing of $1.70/MMBtu for the remainder of fiscal 2020, and reflects the impact of existing financial hedges, firm sales and firm transportation contracts.(3) Assumes NYMEX (WTI) oil pricing of $55.00/Bbl and California-MWSS pricing differentials of 104% to WTI, and reflects impact of existing financial hedge contracts.

Production & Gathering Throughput

Realized natural gas prices (after-hedge)

Utility Operating Income

Regulated BusinessesPipeline & StorageUtility Guidance assumes normal weather; higher gross margin expected to be offset by cost inflation

~$290-295 million in revenues (expansion revenues partial offset by full year of Empire contract expiration)

Pipeline & Storage Revenues

Tax Rate

Realized oil prices (after-hedge)

Higher effective tax rate Effective tax rate ~25% (enhanced oil recovery credit unavailable in FY2020)

Pipeline & Storage Pension Costs Expected to increase by ~$4 million from FY19

DD&A Expense Guidance of $0.73 - $0.77/Mcf (vs. $0.73 in FY 2019) due to higher recorded asset retirement obligations in California

14

Exploration & Production and Gathering OverviewSeneca Resources Company, LLC ~ National Fuel Gas Midstream Company, LLC

15

Proved Reserves

29.0 30.2 27.7 24.9

1,6751,973

2,357

2,950

1,8492,154

2,523

3,099

0

500

1,000

1,500

2,000

2,500

3,000

3,500

2016 2017 2018 2019At September 30

Natural Gas (Bcf)

Crude Oil (MMbbl)

372% Reserve Replacement Rate

Seneca Drill-bit F&D = $0.67/Mcfe(1)

Appalachia Drill-bit F&D = $0.62/Mcfe(1)

(1) Seneca “Drill-bit” finding and development (“F&D”) costs exclude the impact of reserve revisions. Seneca Drill-Bit F&D and Appalachia Drill-Bit F&D are 3-year averages.

Total Proved Reserves (Bcfe)

Fiscal 2019 Proved Reserves Stats

$1.32

$0.98 $0.74

$0.56

$0.00

$0.50

$1.00

$1.50

2016 2017 2018 2019

3-Year Average F&D Cost ($/Mcfe)

67%33%

PDPs PUDs

E&P and Gathering

16

Further reduce activity to 1-rig development program in summer 2020 (moved from 3 to 2 rigs in January 2020)

Development focused in WDA-Utica, with return trips to existing pads expected to drive strong E&P and Gathering returns

Gross production growth will benefit NFG’s Gathering segment

Layer in additional firm sales in advance of new firm transportation capacity expected in late 2021 (Leidy South)

Minimal capital investment in California to generate significant cash flow

Growing Production within Disciplined Capital Program

19.4 17.6 15.9 ~16

154.1 160.5 195.9 219-229

173.5 178.1211.8

235-245

050

100150200250

2017 2018 2019 2020E

$38 $26 $30 $25-$30

$208$330

$462$350-$380

$246

$356

$492

$375-$410

$0

$100

$200

$300

$400

$500

$600

2017 2018 2019 2020E

Appalachia West Coast (California)

Near-Term Strategy E&P Net Capital Expenditures ($ millions)(1)

E&P Net Production (Bcfe)

E&P and Gathering

(1) A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation.FY17 and FY18 reflects the netting of $7 million and $17 million, respectively, of up-front proceeds received from joint development partner for working interest in joint development wells.

17

Significant Appalachian Acreage Position

Average gross production(1): ~372 MMcf/d

Mostly leased (16-18% royalty) with no significant near-term lease expirations

~70 remaining Marcellus & Utica locations:

Breakeven (15% IRR) consolidated economics of $1.40 or less

Additional Marcellus (Tioga Co.) & Geneseo(Lycoming Co.) potential

Eastern Development Area (EDA)

Western Development Area (WDA)

Average gross production(1): ~357 MMcf/d Over 1,000 potential Marcellus & Utica locations ~90 locations where gathering/pad infrastructure in

place from prior drilling activities, driving returns: Breakeven (15% IRR) consolidated

economics of $1.60 or less Royalty free mineral ownership Highly contiguous nature drives efficiencies

E&P and Gathering

EDA - 70,000 AcresWDA - 715,000 Acres

(1) Average EDA and WDA gross production, as well as WDA-CRV Utica and Marcellus production (see slide 20), and Covington/Tract 595 Production (see slide 24), is for the quarter ended December 31, 2019.

18

Western Development AreaMarcellus Core Acreage

vs. Utica Appraisal Trend(1)

(1) The Utica Shale lies approximately 5,000 feet beneath Seneca’s WDA Marcellus acreage. (2) Appraisal program currently in progress. Additional tests are planned. Prior Marcellus delineation tests helped define the prospective limits of the Marcellus core acreage; planned testing in the Utica is expected to do the same.

Large well inventory:

Marcellus Shale: 600+ well locations remaining / 200,000 acres

Utica Shale: 500+ potential locations across Utica trend / evaluating extent of prospective acreage(2)

Fee acreage (no royalty) enhances economics and provides development flexibility

Use of existing gathering, pad, and water infrastructure for Utica drives increased Appalachian program returns

Highly contiguous position drives best in class well costs

Long-term firm contracts support growth

Additional appraisal tests planned to delineate the Rich Valley to Boone Mountain corridor

E&P and Gathering

WDA Highlights

Area of Re-Development 70-75 remaining Utica locations

on existing Marcellus pads

?Key Utica testsPast Marcellus delineation testsUtica Trend (currently evaluating)Marcellus Core Acreage

Boone Mountain Utica Test Well2.3 Bcf /1,000ft

19

WDA-CRV Utica Results and Type Curve

Tested / producing from 29 Utica wells in WDA-CRV Drawdown management is critical: restricted

drawdown appears to significantly improve well performance and EURs

Produced fluid blend %: At high produced water blend rates, both well performance and EURs appear to be negatively impacted

WDA-CRV Utica Appraisal Update

E&P and Gathering

WDA-CRV Types Curves – Normalized to 9,000’

WDA-CRV Utica Development Plan

Continue Optimizing Utica D&C completion design, focusing on: Proppant loading

Stage spacing

Produced fluid blend Tailor development plan to use existing pad,

water and gathering infrastructure 0.0

1.0

2.0

3.0

4.0

5.0

6.0

7.0

8.0

9.0

0 12 24 36 48 60 72 84 96 108 120

Cum

ulat

ive

Prod

uctio

n (B

CF)

Months On

WDA-CRV Utica Type Curve

WDA-CRV Marcellus Type Curve

EUR(Bcf/1000’)

IRR% $2.00(1)

Break-even15% IRR(1)

Utica - CRV 1.6 - 1.7 25% $1.60

Marcellus - CRV 1.1 - 1.2 26% $1.57

(1) Internal Rate of Return is for consolidated Seneca and Gathering, is pre-tax, and includes expected gathering capital expenditures for remaining return trip locations, well costs under current cost structure, and non-gathering LOE.

Consolidated WDA-CRV Return Trip Economics

20

Avg. CRV Utica Production: 92 MMcf/d

Est. EURs (Return Trips): 1.6-1.7 Bcf / 1,000 lateral feet Avg. CRV Marcellus Production: 226 MMcf/d

Est. EURs (Return Trips): 1.1-1.2 Bcf / 1,000 lateral feet

Clermont Rich Valley Utica Development Utilizes Existing Gathering, Water & Pad Infrastructure

WDA: CRV Return Trips Drive Utica Economics

WDA-CRV Marcellus WDA-CRV Utica

Existing Line

Leased

Seneca Fee

Producing

FY20 Producer

Development

E&P and Gathering

Existing Line

Leased

Seneca Fee

Producing

FY20 Producer

Development

21

Leveraging Existing Gathering, Water and Pad Infrastructure Enhances Returns

Limited New Infrastructure Needed to Support Production Growth

WDA Well Costs(1) WDA-CRV Consolidated Economics

Coordination between upstream and midstream activities enhances returns,

provides economies of scale and significant operational flexibility

(1) WDA Marcellus well costs reflect drilling, completion & gathering costs for 192 drilled and completed wells as of 9/30/18. WDA-CRV Utica well costs reflect expected drilling, completion & gathering costs for the remaining locations in area of redevelopment. (2) Internal Rate of Return for Seneca WDA includes estimated well costs under current cost structure, and anticipated LOE and Gathering costs. Internal Rate of Return for Seneca WDA and Gathering includes expected gathering capital expenditures for

remaining return trip locations, well costs under current cost structure, and non-gathering LOE.

$685$875-$925

$210

$0

$200

$400

$600

$800

$1,000

Marcellus(Historic)

Utica - CRV(Current)

$/ la

tera

l foo

t

Drilling & Completion Gathering

$895$900 - $950

1.0 -1.1

1.6 -1.7

0.0

0.3

0.6

0.9

1.2

1.5

1.8

Marcellus(Historic)

Utica - CRV(Current)

EUR

/ 1,0

00 fe

et (B

cf)

~60% EUR increase expected per well

Total cost per well expected to marginally increase

WDA EURs

At a $2.00 netback price, consolidated Seneca WDA and Gathering IRR is

approximately 25%, an uplift of ~10% over standalone Seneca WDA economics(2)

~10% IRR Uplift Expected

E&P and Gathering

22

Integrated Development – WDA Gathering System

Current System In-Service

Capacity: 470 MMcf per day

Interconnects with TGP 300 and NFG Supply

Total Investment to Date: $310 million

38,120 HP of compression (3 stations)

Future Build-Out

Modest gathering pipeline and compression investment required to support Seneca’s Utica development

Opportunity for 300 miles of pipelines and six compressor stations (+60,000 HP installed) as Seneca’s drilling activity continues

Gathering System Build-Out Tailored to Accommodate Seneca’s WDA Development

Clermont Gathering System Map

E&P and Gathering

23

WDA Firm Transportation and Sales Capacity

Will continue to layer-in firm sales deals of short and longer duration on TGP 300 to reduce spot exposure

WDA spot realizations track TGP Station 313 pricing, typically 10¢ - 20¢ better than TGP Marcellus Zone 4

Leidy South will provide additional capacity to premium markets (Transco Zone 6)

WDA Exit Capacity Supports Productionand Enhances Consolidated Returns

WDA Contracted Firm Transport and Gross Sales Volumes (MDth/d)

E&P and Gathering

0

100

200

300

400

500

600

Niagara Expansion Project (TGP and NFG)FT Capacity: 158,000 Dth/d @ $0.67/Dth

Firm Sales: NYMEX & DAWN

WDA - TGP 300Firm Sales

Leidy SouthTransco Zone 6 330,000 Dth/d(1)

(1) Portion of Leidy South capacity will likely be utilized by EDA Lycoming County production.

WDA Gas Marketing Strategy

24

Eastern Development Area

EDA Acreage – 70,000 AcresEDA Highlights

1 DCNR Tract 007 (Tioga Co., Pa)• Utica development resumed in third quarter fiscal 2018

• 35-40 remaining Utica locations

• Gathering infrastructure: NFG Midstream Wellsboro

• Marcellus Shale expected to provide ~60 additional locations

E&P and Gathering

2

1

3

2 Covington & DCNR Tract 595 (Tioga Co., Pa.)• Marcellus locations fully developed (average daily gross production of ~74 MMcf/d)

• Gathering infrastructure: NFG Midstream Covington

• Opportunity for future Utica appraisal

3 DCNR Tract 100 & Gamble (Lycoming Co., Pa.)• 30-35 remaining Marcellus locations• Firm transportation capacity: Atlantic Sunrise (189 MDth/d)

• Gathering infrastructure: NFG Midstream Trout Run

• Geneseo Shale expected to provide 100 - 120 additional locations

25

EDA Marcellus: Lycoming County Development

Marcellus Development in Lycoming County has Resumed in Connection with Atlantic Sunrise

(1) Includes physical fixed price and NYMEX-based firm sales contracts that do not carry any additional transportation costs.

E&P and Gathering

Prolific Marcellus acreage with peer leading well results 30-35 remaining Marcellus locations – breakeven (15% IRR)

‘consolidated economics of ~$1.11 Near-term development focused on filling Atlantic Sunrise capacity

0

50

100

150

200

250

Gro

ss F

irm V

olum

es (M

Dth

/d)

EDA – Transco Firm Contracts

Atlantic Sunrise (Transco)FT Capacity: 189,405 Dth/d

Cost: $0.73/DthFirm Sales: NYMEX+

Transco Firm Sales(1)

Existing Line

Leased

Seneca Fee

Producing

FY20 Producer

Development

26

EDA Utica: Tioga County Development

Development Focused on Tract 007 Production Area, with Production Underpinned by Firm Sales

(1) Includes physical fixed price and NYMEX-based firm sales contracts that do not carry any additional transportation costs.

E&P and Gathering

0

25

50

75

100

125

150

Gro

ss F

irm V

olum

es (M

Dth

/d)

Northeast Supply Diversification ProjectFT Capacity: 50,000 Dth/d @ $0.50/Dth

Firm Sales: NYMEX and DAWN

EDA - TGP 300Firm Sales(1)

UPDATEEDA – TGP 300 Firm Contracts DCNR Tract 007

Existing Line

Leased

Seneca Fee

Producing

FY20 Producer

Development

27

0

100,000

200,000

300,000

400,000

500,000

600,000

700,000

0 2 4 6 8 10 12

Nor

mal

ized

Cum

ulat

ive

Prod

uctio

n (M

CF/

1,00

0’)

Months On

EDA Utica: Tioga County Development

Tract 007 Utica Wells Brought Online in Q2 Fiscal 2019 Tracking Best Industry Results to Date

Production from first multi-well pad (4 wells) brought online in February/March 2019

Early results compare favorably with industry Tioga County wells

35-40 remaining locations – breakeven (15% IRR) consolidated economics at ~$1.40/Mcf

E&P and Gathering

Tract 007 Utica Development Update

Tract 007 Pad K Early Well Results(1)

(1) All numbers are average of 4 Pad K wells brought online in February and March 2019. (2) Three wells brought online in February 2019 restricted to ~15 MMCFPD, and one well brought online in late

March 2019 restricted to ~10 MMCFPD.

(1) Well Count: 4 Lateral Length: 7,582’ IP30 Rate: 13.8 MMcf/day IP180 Rate: 13.3 MMcf/day Drawdown Management: restricted drawdown

appears to improve well performance

Tract 007 Utica Well Results vs. Industry

Early production limited to 10-15 MMcf/day by

drawdown management(2)

Pad K Wells (Avg.)(1)

Industry Tioga Wells

28

Integrated Development – EDA Gathering Systems

Total Investment (to date): ~$48 million

Capacity: 220,000 Dth per day (Interconnect w/ TGP 300)

Production Source: Seneca Resources – Tioga Co. (Covington & DCNR Tract 595)


Capacity: 466,000 to 585,000 Dth per day (Interconnect w/ Transco)

Production Source: Seneca Resources – Lycoming Co. (DCNR Tract 100 & Gamble)

Third-party volumes under contract and expected to come online in early fiscal 2021

Covington Gathering System

Trout Run Gathering System

Gathering Segment Supporting Seneca and Third-Party Production & Future DevelopmentWellsboro Gathering System


Capacity: up to 200,000 Dth per day (Interconnect w/ TGP 300)

Production Source: Seneca Resources – Tioga Co. (DCNR Tract 007)

E&P and Gathering

1

2

3

29

Long-term Contracts Supporting Appalachian Production

(1) Represents base firm sales contracts not tied to firm transportation capacity. Base firm sales are either fixed priced or priced at an index (e.g., NYMEX ) +/- a fixed basis and do not carry any transportation costs.

Seneca continues to layer-in firm sales contracts to lock-in drilling economics and minimize spot exposure ahead of firm transportation in-service dates

E&P and Gathering

-

100

200

300

400

500

600

700

800

900

1,000

Jan-20 Apr-20 Jul-20 Oct-20 Jan-21 Apr-21 Jul-21 Oct-21 Jan-22 Apr-22 Jul-22Northeast Supply Diversification 50,000 Dth/d

Niagara Expansion (TGP & NFG)Delivery Markets: Canada-Dawn & TETCO

158,000 Dth/d

Atlantic Sunrise (Transco)Delivery Markets: Mid-Atlantic & Southeast U.S.

189,405 Dth/d

In-BasinFirm Sales

Contracts(1)

Leidy South (Transco & NFG)

Transco Zone 6 330,000 Dth/d

Seneca Appalachia Natural Gas MarketingGross Firm Contract Volumes (Mdth/day)

30

336,100 ($0.46)

343,000 ($0.54)

341,000 ($0.54) 299,400 ($0.57)

294,100 ($0.61) 233,100

($0.62)233,000 ($0.63)

32,400 ($0.68) 41,000 ($0.81) 41,000 ($0.81)41,600 ($0.81) 43,200 ($0.85)

73,600 ($0.82) 74,100 ($0.82)

25,000 ($0.09)

79,000 ($0.63)

78,400 ($0.69) 123,400 ($0.54)

141,100 $0.04 161,100 ($0.61)

160,600 ($0.70)

149,700 $2.40

108,900 $2.23

108,200 $2.23

109,100 $2.23

112,000 $2.23

118,800 $2.21

118,500 $2.21

~611,900

543,200 571,900 568,600 573,500 590,400 586,600 586,200

Q1 FY20 Q2 FY20 Q3 FY20 Q4 FY20 Q1 FY21 Q2 FY21 Q3 FY21 Q4 FY21

NYMEX Dawn Other Fixed Price

Near-term Firm Sales Provide Market & Price Certainty

Net Contracted Firm Sales Volumes (Dth per day)Contracted Index Price Differentials ($ per Dth)(1)

Daily Net Production

659,300 689,300 681,800 681,800 696,900 689,300 681,800Gross Firm Sales Volumes (Dth/d)

E&P and Gathering

(1) Values shown represent the weighted average fixed price or weighted average differential relative to NYMEX (netback price) less any associated transportation costs. Transportation costs include minor variable components such as the Canadian exchange rate and fuel components. With respect to “Other”, the weighted average differential relative to NYMEX (netback price) includes net contracted firm sales at various indices, which are to subject to fluctuations in the market, such as seasonal demand swings, and is calculated using forward basis at various associated locations as specified by the underlying contract.

31

California Oil

Stable Oil Production | Minimal Capital Investment | Steady Free Cash Flow

1

2

3

4

5

Location Formation Production Method

Avg. Daily Production

(net Boe/d)(1)

1 East Coalinga/ Other Temblor Primary 494

2 North Lost HillsTulare &

EtchegoinPrimary/

Steam flood 880

3 South Lost HillsMonterey

Shale Primary 1,204

4 North Midway SunsetTulare & Potter Steam flood 2,865

5 South Midway Sunset Antelope Steam flood 1,970

TOTAL WEST DIVISION AVG. NET PRODUCTION(1) 7,413 Boe/d

E&P and Gathering

(1) Average daily net production (oil and natural gas) for West division for quarter ended December 31, 2019.

32

California Capital Expenditures vs. Production

8,863 8,033

7,257 ~7,250

2017 2018 2019 2020

Fiscal Year

West Division Average Net Daily Production (Boe)West Division Annual Capital Expenditures ($ MM)(1)

$38

$26$30

$25-$30

2017 2018 2019 2020

Fiscal YearEstimate

(1) Seneca West Division capital expenditures includes Seneca corporate and eliminations.

E&P and Gathering

Sespe Sale Closed on 5/1/18(reduced production by ~900 Boe/d)

Estimate

33

Pioneer

South MWSS

Acreage

North MWSS

AcreageSec. 17N

29%

55%

41%

NMWSS & 17N SMWSS & Pioneer East Coalinga

California Development Activities

Modest near-term capital program focused on locations that earn attractive returns in current oil price environment

A&D will focus on low cost, bolt-on opportunities

Sec. 17, Pioneer, and East Coalinga development to provide future growth

North

Project IRRs at $55/Bbl(1)

(1) Reflects pre-tax IRRs at a $55/Bbl WTI.

E&P and Gathering

Seneca West Economics

South

East Coalinga

North

South

34

Fiscal 2020 Production and Price Certainty

~58 Bcfe

235-245 Bcfe

~102 Bcf

~43 Bcf (2)~25 Bcf

~12 Bcfe

0

40

80

120

160

200

240

280

YTD FY20Actuals

Fixed Price + FirmSales w/ Hedge

Firm Sales(Unhedged)

Spot Sales California TotalSeneca

Prod

uctio

n (B

cfe)

(1) Average realized price reflects uplift from financial hedges less fixed differentials under firm sales contracts and any firm transportation costs.(2) Indicates firm sales contracts with fixed index differentials but not backed by a matching financial hedge.

102 Bcf locked-in realizing net ~$2.28/Mcf (1)

43 Bcf of additional basis protection

Spot production assumed to be sold

at ~$1.70 for remainder of FY20

145 Bcf of Appalachian Production Protected by Firm Sales

73% of oil production hedged at $61.88 /Bbl

E&P and Gathering

35

1,278

852

456

0

250

500

750

1,000

1,250

1,500

1,750

2,000

2,250

2,500

FY 2020 FY 2021 FY 2022

Brent NYMEX

FY 20 Crude Oil~73% Hedged(2)

Strong Hedge Book

Natural Gas Swap & Fixed Physical Sales Contracts (Millions MMBtu)

105.1

57.440.5

0

25

50

75

100

125

150

175

200

225

250

275

FY 2020 FY 2021 FY 2022

NYMEX Swaps Dawn Swaps Fixed Price Physical Sales

(1) Fixed price physical sales exclude joint development partner’s share of fixed price contract WDA volumes as specified under the joint development agreement.(2) Reflects percentage of projected production for FY20 hedged at the midpoint of the production guidance range.(3) Seneca’s remaining FY20 production reflects the total FY20 production guidance of 235-245 Bcfe, or 240 Bcfe at the midpoint, less Q1 actual production.

Crude Oil Swap Contracts (Thousands Bbls)

(1)

FY 20 Nat Gas~60% Hedged(2)

Remaining FY 2020 Production(3) Remaining FY 2020 Production(3)

E&P and Gathering

36

$0.70 $0.73$0.73 -$0.77

FY 2018 FY 2019 FY 2020E

$0.60 $0.60 $0.61

$0.09 $0.07 $0.08$0.69 $0.67 ~$0.69

FY 2018 FY 2019 FY 2020E Gathering & Transport LOE (non-Gathering) G&A Taxes & Other

UPDATE

Seneca Operating Costs

Competitive, low cost structure in Appalachia and California supports strong cash margins

Gathering fee generates significant revenue stream for affiliated gathering company

Seneca DD&ARate

$/Mcfe

$0.54 $0.56 $0.57

$0.38 $0.32 $0.30

$0.34 $0.30 $0.28

$0.14 $0.14 $0.11

$1.40 $1.32 ~$1.26

FY 2018 FY 2019 FY 2020E

(1)

$20.81$17.91

~$20.40

FY 2018 FY 2019 FY 2020E

Appalachia LOE & Gathering $/Mcfe

California LOE$/Boe

Total Seneca Cash OpEx$/Mcfe

(1)

(2)

(2)

(1) G&A estimate represents the midpoint of the G&A guidance of $0.27 to $0.30 for fiscal 2020.(2) The total of the two LOE components represents the midpoint of the LOE guidance range of $0.85 to $0.89 for fiscal 2020.

E&P and Gathering

37

Pipeline and Storage OverviewNational Fuel Gas Supply Corporation ~ Empire Pipeline, Inc.

38

Pipeline & Storage Segment Overview

(1) As of September 30, 2019 as disclosed in the Company’s fiscal 2019 form 10-K.(2) As of December 31, 2018 calculated from National Fuel Gas Supply Corporation’s and Empire Pipeline, Inc.’s 2018 FERC Form-2 reports, respectively.

Empire Pipeline, Inc.

National Fuel Gas Supply Corporation

Empire Pipeline

Supply Corp.

Contracted Capacity(1): Firm Transportation: 3,078 MDth per day Firm Storage: 70,693 Mdth (fully subscribed)

Rate Base(2): ~$863 million FERC Rate Proceeding Status:

Filed rate case on 7/31/19 New rates expected to go into effect (subject to

refund) on 2/1/20

Contracted Capacity(1): Firm Transportation: 853 MDth per day Firm Storage: 3,753 Mdth (fully subscribed)

Rate Base(2): ~$247 million FERC Rate Proceeding Status:

Rate case settlement approved May 2019 New transportation rates went into effect on 1/1/19

Pipeline & Storage

39

Empire North Project

Target in-service: fourth quarter fiscal 2020 (construction underway)

Est. capital cost: $145 million Est. annual revenues: ~$25 million Receipt point: Jackson (Tioga Co., Pa. production) Design capacity and delivery points: 175,000 Dth/d to Chippawa (TCPL interconnect)

30,000 Dth/d to Hopewell (TGP 200 interconnect) Major facilities: 2 new compressor stations in NY (1) & Pa. (1)

No new pipeline construction Regulatory process: FERC Certificate issued 3/7/19

FERC Notice to Proceed issued 5/2/19

Pipeline & Storage

Fully Subscribed Project will Provide 205,000 Dth/day of Incremental Firm Transportation

40

All Seneca volumes will flow through wholly-owned NFG gathering facilities

FM100 Project - Consolidated Benefit for NFG

330,000 Dth/d of new transportation capacity from WDA and EDA acreage positions to premium markets

New Transco capacity (Leidy South): 330,000 Dth/day Rate(1) : competitive with other expansion project rates in

Seneca’s current transportation portfolio Delivery point(s): Transco Zone 6 interconnections

Seneca

Lease to Transco of new capacity: 330,000 Dth/day Estimated annual lease revenues: ~$35 million Target in-service: late calendar year 2021

Supply Corp.

Project expected to provide long-term earnings uplift to Seneca, Supply Corp. and Gathering

Pipeline & Storage

Gathering

(1) Includes lease of new capacity from Supply Corp. to Transco.

41

FM100 Project – Significant Investment by Supply Corp.

Pipeline & Storage

Estimated capital cost: $279 million Expansion facilities: ~$159 million Modernization facilities: ~$120 million

Facilities (all in Pennsylvania) include: Approximately 30 miles of new pipeline 2 new compressor stations (totaling

approximately 37,000 HP) New interconnection station and modification

of existing interconnection station Abandonment of approximately 45 miles of

existing pipeline and compressor station

Regulatory process: FERC 7(b) / 7(c) certificate application

submitted 7/18/19

42

Continued Expansion of the NFG Supply System

Line N to Monaca Project

Project: Firm transportation service to a new ethane cracker facility being built by Shell Chemical Appalachia, LLC

In-service date: November 1, 2019 Capital cost: ~$24.5 million Contracted capacity: 133,000 Dth/day

Project: New firm transportation service for on-system demand

Open season capacity: Awarded 165,000 Dth/day to foundation shipper. Precedent agreement in negotiations.

Pipeline & Storage

Additional Line N Expansion Potential (Supply OS 221)

43

Northern Access Project

Total cost: ~$500 MM(1) (~$57 MM spent to date)

Estimated annual revenues: ~$84 million

Delivery points:

350,000 Dth/d to Chippawa (TCPL interconnect)

140,000 Dth/d to East Aurora (TGP 200 line)

Regulatory/legal status:

Feb. 2017 – FERC 7(c) certificate issued

Aug. 2018 – FERC issued Order finding that NY DEC waived water quality certification (WQC)

Feb. 2019 – U.S. Second Circuit Court of Appeals vacated and remanded NY DEC denial of WQC

April 2019 – FERC denied rehearing of WQC waiver order (upholding waiver finding)

Supply and Empire currently working to finalize remaining federal authorizations

Pipeline & Storage

To Dawn

(1) Preliminary Cost Estimate.

44

Pipeline & Storage Customer Mix

Producer35%

LDC42%

Marketer10%

Outside Pipeline

7%

End User6%

3.9 MMDth/d

(1) Contracted as of 10/31/2019.

Customer Transportation by Shipper Type(1) Affiliated Customer Mix (Contracted Capacity)

72%

6%25%

44%

28%

94%75%

56%

LDCs Producers Marketers FirmStorage

Affiliated Non-Affiliated

Firm Transport

Pipeline & Storage

45

Utility OverviewNational Fuel Gas Distribution Corporation

46

New York & Pennsylvania Service Territories

New York

Total Customers(1): 531,400ROE: 8.7% (NY PSC Rate Case Order, April 2017)Rate Mechanisms:o Revenue Decouplingo Weather Normalizationo Low Income Rateso Merchant Function Charge (Uncollectibles Adj.)o 90/10 Sharing (Large Customers)o System Modernization Tracker

Pennsylvania

Total Customers(1): 212,000ROE: Black Box Settlement (2007)Rate Mechanisms:o Low Income Rateso Merchant Function Charge

(1) As of September 30, 2019.

Utility

47

New York Rate Case Outcome

Rate Order Summary:

Revenue Requirement: $5.9 million Rate Base: $704 million Allowed Return on Equity (ROE): 8.7% Capital Structure: 42.9% equity Other notable items:

New rates became effective 5/1/17 Retains rate mechanisms in place under prior order (revenue decoupling, weather

normalization, merchant function charge, 90/10 large customer sharing) System modernization tracker for Leak Prone Pipe (LPP) Earnings sharing started 4/1/18 (50/50 sharing starts at ROE in excess of 9.2%)

On April 20, 2017, the New York Public Service Commission issued a Rate Order relating to NFG Distribution’s rate case (No. 16-G-0257) filed in April 2016.

Utility

48

Utility Continues its Significant Investments in Safety

$61.8 $63.6$69.9 $74.1

$98.0

$80.9 $85.6$95.8 $90-$100

$0.0

$25.0

$50.0

$75.0

$100.0

$125.0

2016 2017 2018 2019 2020E

Cap

ital E

xpen

ditu

res

($ m

illio

ns)

Fiscal Year

Capital Expenditures for Safety Total Capital Expenditures

Modernization Spending in NY Expected to Grow Gross Margin By $2 MM - $5 MM Annually

(1)

(1) A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation.

Utility

System modernization tracker in NY allows recovery of pipeline replacementcosts, which is expected to drive modest gross margin and rate base growth

49

Accelerating Pipeline Replacement & Modernization

Wrought Iron

Plastic

Coated Bare

130146 144

159 158

2015 2016 2017 2018 2019Calendar Year

NY9,738 miles

PA*4,843 miles

* No Cast Iron Mains in Pa.*

Miles of Utility Main Pipeline ReplacedUtility Mains by Material(1)

Wrought Iron

Cast Iron

Plastic

Coated Bare

Utility

(1) All values are reported on a calendar year basis as of December 31, 2019.

50

A Proven History of Controlling Costs

$200 $189 $195

$166 $169 $168

$31 $28 $27

$197 $196 $196

$0

$50

$100

$150

$200

$250

2015 2016 2017 2018 2019 TTM 12/31/19Fiscal Year

O&M Expense (GAAP) Non-Service Pension Costs

Utility O&M Expense and Non-Service Pension Costs ($ millions)

Utility

(1)

(1) As of October 1, 2018, Operation and Maintenance Expense does not include non-service pension costs, which were re-classified as Other Income (Deductions) on the Company’s Income Statement.

51

Consolidated Financial OverviewUpstream I Midstream I Downstream

52

Adjusted Operating Results ($ per share)(1)

Diversified, Balanced Earnings and Cash Flows

(1) A reconciliation of Adjusted Operating Results to Earnings per Share, by segment, as presented on the Consolidated Statement of Income and Earnings Reinvested in the Business is included at the end of this presentation.(2) Consolidated Adjusted EBITDA includes Corporate & All Other Segments. A reconciliation of Adjusted EBITDA to Net Income, by segment, as presented on the Consolidated Statement of Income and Earnings Reinvested in the Business is included

at the end of this presentation.

Adjusted EBITDA ($ millions)(2)

$176 $178

$162 $157

$108 $112

$351 $353

$785 $788

$0

$200

$400

$600

$800

FY 2019 TTM 12/31/19

$0.70 Utility

$0.85 Pipeline & Storage

$0.67 Gathering

$1.26

$3.45 $2.95 to $3.15

$0.00

$1.00

$2.00

$3.00

$4.00

FY 2019 FY 2020 Guidance

Exploration & Production

Rate Regulated

~50%

Rate Regulated

~43%

53

$89 $94 $98 $81 $86 $96 $90-$100

$140$230

$114 $95 $93 $143 $180-$215

$138$118

$54$33 $48

$50 $50-$60

$603$557

$99 $246$356

$492 $375-$410

$970 $1,001

$366$455

$583

$781 $695-$785

$0

$250

$500

$750

$1,000

$1,250

2014 2015 2016 2017 2018 2019 2020GuidanceFiscal Year

Exploration & Production Gathering Pipeline & Storage Utility

Disciplined, Flexible Capital Allocation

(2)

(1) Total Capital Expenditures include Corporate and All Other. A reconciliation to Capital Expenditures as presented on the Consolidated Statement of Cash Flows is included at the end of this presentation. (2) FY16, FY17, and FY18 reflects the netting of $157 million, $7 million, and $17 million, respectively, of up-front proceeds received from joint development partner for working interest in joint development wells, and $21M in intercompany asset transfers in FY18.

Capital Expenditures by Segment ($ millions)(1)

54

Maintaining Strong Balance Sheet & Liquidity

Total Equity51%

Total Debt49%

$4.3 Billion Total Capitalizationas of December 31, 2019

2.51 x 2.45 x 2.47 x 2.61 x2.72 x

2016 2017 2018 2019 TTM 12/31/19

Fiscal Year End

Net Debt / Adjusted EBITDA(1) Capitalization

Debt Maturity Profile ($MM) Liquidity

Committed Credit FacilitiesShort-term Debt OutstandingAvailable Short-term Credit FacilitiesCash Balance at 12/31/19Total Liquidity at 12/31/19

$ 750 MM(140 MM)

610 MM35 MM

$ 645 MM

$500 $549 $500

$300 $300

$0

$200

$400

$600

(1) Net Debt is net of cash and temporary cash investments. Reconciliations of Net Debt and Adjusted EBITDA to Net Income are included at the end of this presentation.

55

Appendix

56

Safe Harbor For Forward Looking StatementsThis 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, anticipatedcapital 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 couldcause actual results or outcomes to differ materially from those expressed in the forward-looking statements. The Company’s expectations, beliefs and projections are expressedin 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 beachieved or accomplished.

In addition to other factors, the following are important factors that could cause actual results to differ materially from those discussed in the forward-looking statements: changesin the price of natural gas or oil; impairments under the SEC’s full cost ceiling test for natural gas and oil reserves; changes in laws, regulations or judicial interpretations to whichthe Company is subject, including those involving derivatives, taxes, safety, employment, climate change, other environmental matters, real property, and exploration andproduction activities such as hydraulic fracturing; delays or changes in costs or plans with respect to Company projects or related projects of other companies, includingdifficulties or delays in obtaining necessary governmental approvals, permits or orders or in obtaining the cooperation of interconnecting facility operators;governmental/regulatory actions, initiatives and proceedings, including those involving rate cases (which address, among other things, target rates of return, rate design andretained natural gas), environmental/safety requirements, affiliate relationships, industry structure, and franchise renewal; changes in price differentials between similarquantities of natural gas or oil at different geographic locations, and the effect of such changes on commodity production, revenues and demand for pipeline transportationcapacity to or from such locations; financial and economic conditions, including the availability of credit, and occurrences affecting the Company’s ability to obtain financing onacceptable terms for working capital, capital expenditures and other investments, including any downgrades in the Company’s credit ratings and changes in interest rates andother capital market conditions; factors affecting the Company’s ability to successfully identify, drill for and produce economically viable natural gas and oil reserves, includingamong 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;increasing health care costs and the resulting effect on health insurance premiums and on the obligation to provide other post-retirement benefits; other changes in pricedifferentials between similar quantities of natural gas or oil having different quality, heating value, hydrocarbon mix or delivery date; the cost and effects of legal andadministrative claims against the Company or activist shareholder campaigns to effect changes at the Company; uncertainty of oil and gas reserve estimates; significantdifferences between the Company’s projected and actual production levels for natural gas or oil; changes in demographic patterns and weather conditions; changes in theavailability, price or accounting treatment of derivative financial instruments; changes in laws, actuarial assumptions, the interest rate environment and the return on plan/trustassets related to the Company’s pension and other post-retirement benefits, which can affect future funding obligations and costs and plan liabilities; changes in economicconditions, 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; thecreditworthiness or performance of the Company’s key suppliers, customers and counterparties; the impact of information technology, cybersecurity or data security breaches;economic disruptions or uninsured losses resulting from major accidents, fires, severe weather, natural disasters, terrorist activities or acts of war; significant differencesbetween the Company’s projected and actual capital expenditures and operating expenses; or increasing costs of insurance, changes in coverage and the ability to obtaininsurance.

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 andengineering data, can be estimated with reasonable certainty to be economically producible under existing economic conditions, operating methods and governmentregulations. Other estimates of oil and gas quantities, including estimates of probable reserves, possible reserves, and resource potential, are by their nature more speculativethan estimates of proved reserves. Accordingly, estimates other than proved reserves are subject to substantially greater risk of being actually realized. Investors are urged toconsider 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, 2019 and the Form 10-Q for the quarter ended December 31, 2019. The Company disclaimsany obligation to update any forward-looking statements to reflect events or circumstances after the date thereof or to reflect the occurrence of unanticipated events.

Appendix

http://www.nationalfuelgas.com/http://www.sec.gov/

57

Consolidated Seneca and Gathering Economics

(1) Stand-alone Seneca breakeven economics (15% pre-tax IRR) by prospect are as follows: Tract 100 & Gamble: $1.51; Tract 007: $1.74; CRV Return Trip (Utica): $2.00; CRV Return Trip (Marcellus): $1.95. Internal Rate of Return (IRR) for stand-alone Seneca is pre-tax and includes estimated well costs under current cost structure, LOE, and Gathering tariffs anticipated for each prospect.

(2) Net realized price reflects either (a) price received at the gathering system interconnect or (b) price received at delivery market net of firm transportation charges.(3) Consolidated Seneca and Gathering IRR is pre-tax and includes expected gathering capital expenditures, well costs under current cost structure, and non-gathering LOE.

Over 1,000 Potential Additional Marcellus and Utica Locations Economic on a Stand-Alone Basis at ~$2.00/MMBtu(1)

Appendix

$2.50IRR (%) (3)

$2.25IRR (%) (3)

$2.00IRR (%) (3)

Tract 100 & GambleLycoming Co.

Marcellus 30-35 5,500 -6,000

2.5-2.9 $1,050-$1,100

89% 73% 59% $1.11

Tract 007Tioga Co.

Utica 35-40 8,500 -9,000

2.0-2.3 $1,250-$1,300

63% 51% 41% $1.40

CRV Return Trip Utica 70-75 9,000-10,000

1.6-1.7 $900-$950 39% 30% 25% $1.60

CRV Return Trip Marcellus 15-20 8,500-9,500

1.1-1.2 $675-$725 42% 33% 26% $1.57

EDA

EUR (Bcf/1000')

Average CAPEX

($M/1000')

Realized Pricing (2)15% IRR (3)

RealizedPrice

WDA

Prospect ReservoirLocations

Remainingto Be Drilled

Average Completed

Lateral Length (ft)

COVER

FY19 Q4 Investor Relations Packet

01/30/2020

Model Inputs

WDA Utica

xyy

DurationCost

70 wells700.9460.928

120 wells1200.8820.886

100 wells1000.90760.9028

DCNR 007 Utica

xyy

DurationCost

20 wells201.081

70 wells701.0220.975

43 wells431.053320.9885

PadAreaMarcUtica $/bbl 1019$/bblAve Well #

CRV D09-D2 UWDA4$2.00MarcWDA2.1565

DCNR 100 M3 MLycoming2$1.75MarcLycoming2.3114

HEMLOCK E09-S2WDA6$2.00UticaDCNR 0072.0006

CRV C08-X2 UWDA6$2.70UticaWDA2.2125

DCNR 100 R2 MLycoming5$1.80

HEMLOCK E09-UWDA42$1.75

GAMBLE J Lycoming5$3.25

CRV C09-G2 UWDA6$1.600719$/bblAve Well #Water Delta

GAMBLE K2 MLycoming8$3.50MarcWDA2.12570.031

HEMLOCK E09-T2 MWDA4$2.25MarcLycoming2.21750.094

CRV D08-O2 UWDA4$2.25UticaDCNR 0071.56350.438

CRV D08-U2 UWDA4$2.25UticaWDA1.67160.541

WEST BRANCH E08-L2 UWDA6$2.25

DCNR 007 D UDCNR 0076$2.00

CRV E09-E2 UWDA5$2.25

Boone Mtn. F14-COP-I UWDA1$2.25

CRV C08-G2 UWDA4$2.25

HEMLOCK F10-F2WDA82$2.25

GAMBLE A2 MLycoming5$2.00

CRV C09-D3WDA35$2.25

GAMBLE GLycoming4$2.50

HEMLOCK E09-U2 MWDA8$2.25

BEECHWOOD B09-I UWDA7$2.25

GAMBLE OLycoming5$2.00

BEECHWOOD C09-J UWDA5$2.25

CRV D09-M UWDA5$2.25

HEMLOCK E09-T3 UWDA6$2.25

GAMBLE J2 MLycoming4$2.00

CRV E08-T2 UWDA5$2.25

HEMLOCK E09-J2 UWDA4$2.25

CRV D08-N2 UWDA6$2.25

HEMLOCK F10-F3 UWDA4$2.25

HEMLOCK E09-U3WDA38$2.25

GAMBLE P2 MLycoming2$2.00

CRV D09-M2 UWDA7$2.25

CRV D08-M2WDA26$2.25

BEECHWOOD C09-Q UWDA7$2.25

HEMLOCK E09-S3 UWDA4$2.25

Lycoming

AREA INFORMATION

PROSPECTLycoming*DCNR 100 & Gamble comboTest Month09/2020

COUNTYLycomingGross Gas Prod, MMcf (shrunk)2386.91

Avg Wells per Pad5*from planningGross Gas Prod, MMcf (unshrunk)2391.69Frac$1,557,400drill duration16.2373940763

Net Var Exp, M$$1,316.70Drillout$360,570

ECONOMIC ASSUMPTIONSNet Fix Exp, M$$11.93Toe Prep$87,000

BTU (mmBTU/mcf)1.03112*in LOE sheet, ARIES inputsNet Tot Exp, M$$1,328.62Flowback$218,200W/ Water

FIXED LOE ($/month/well)$994Actual Gas Price, $/Mcf$2.000Sum Total Compl$2,223,170$2,692,326

VARIABLE LOE ($/mcf)$0.036Net Gas Price, $/Mcf$2.062Water$469,156

MIDSTREAM FEE ($/mcf)$0.516*$0.50 transport feeNet Gas Revenue. M$$4,134.80

WATER DISPOSAL LOE ($/well, 1 time fee)$0*water disposal cost removed

PRICING (Realized)$2.50 / $2.25 / $2.00

BASIS DIFFERENTIAL($0.730)

SHRINKAGE %0.20.998

IMPACT FEESPUD_2019*sames as start date

CAPITAL (and Timing)ARIES EntriesValuesCapitalModel(s) Used

DRILLING (-6 Months)$2,211,350*drill capital x efficiencies + rig move/#wellsDRILLING (-6 Months)2211.350DRILLING (-6 Months)DCNR 100 Marc, No Capital Efficiency

COMPLETION (-2 Months)$2,583,308*frac + drillout + toe prep + flowback + waterCOMPLETION (-2 Months)2583.308COMPLETION (-2 Months)used components: DCNR 100/Gamble 200' stg

PRODUCTION (-1 Month)$426,000PRODUCTION (-1 Month)426.000PRODUCTION (-1 Month)EDA 5-7 wells

PAD (-7 Months)$440,000*from planningPAD (-7 Months)440.000PAD (-7 Months)Provided by Planning

TOTAL CAPEX$5,660,657TOTAL CAPEX5660.657

TREATED LENGTH (FT)5,800*per KWMUL Factor1.07411.056

STAGE LENGTH200

OWNERSHIP

WI (%)100

NRI (%)84

TIMING ASSUMPTIONSTYPE CURVE - 5,400' 13,534 MMcf

Production start date of 05/2020*current month + 7 months16706XM/D1.84MOSB/1.276.5

See CAPITAL section for CAPEX timings (relative to production start)*report date = current quarter10627XM/D16.16IMOSB/1.145

6603XM/D6EXPB/.743.8

RESERVESX30M/DXIMOSEXP6

P50 EUR/1000'2.70 BCF/1000'*in TC sheet

P50 EUR15.65 BCF17943.481XM/D1.84MOSB/1.276.5

11414.185XM/D16.16IMOSB/1.145

7092.111XM/D6EXPB/.743.8

X30M/DXIMOSEXP6

2.702037037NEW TYPE CURVE - 5,400' 14,591 MMcf (18 month compression)

15671.8148148148162004788.4M/D18MOSB/2.265

6224XM/D6EXPB/1.041.5

X30M/DXIMOSEXP 6

17400.0005143.096M/D18MOSB/2.265

6685.037XM/D6EXPB/1.041.5

X30M/DXIMOSEXP 6

2.6983333333NEW TYPE CURVE - 5,400' 14,571 MMcf (12 month compression)

15650.3333333333162005670M/D12MOSB/2.265

7371XM/D6EXPB/1.044.5

X30M/DXIMOSEXP 6

17400.0006090.000M/D12MOSB/2.265

7917.000XM/D6EXPB/1.044.5

X30M/DXIMOSEXP 6

DCNR 007 - Tioga Utica

AREA INFORMATION

PROSPECTDCNR 007 UticaTest Month

COUNTYTiogaGross Gas Prod, MMcf (shrunk)3109.73

Avg Wells per Pad6Gross Gas Prod, MMcf (unshrunk)3173.193877551Frac$3,605,280drill duration29.6562218316



BTU (mmBTU/mcf)1.01560*in LOE sheet, ARIES inputsNet Tot Exp, M$$1,705.28Flowback$392,600

FIXED LOE ($/month/well)$994Actual Gas Price, $/Mcf$2.000Water$928,000

VARIABLE LOE ($/mcf)$0.036Net Gas Price, $/Mcf$2.031Total w/ 200' stg$5,666,885





SHRINKAGE %2.00.98



DRILLING (-6 Months)$3,492,515*drill capital x efficiencies + rig movesDRILLING (-6 Months)3492.515DRILLING (-6 Months)007/Boone Mtn Utica, 43 well capital efficiency (0.97286)

COMPLETION (-2 Months)$5,414,515*frac + drillout + toe prep + flowback + waterCOMPLETION (-2 Months)5414.515COMPLETION (-2 Months)used components: Various Utica 200' stg

PRODUCTION (-1 Month)$426,000PRODUCTION (-1 Month)426.000PRODUCTION (-1 Month)EDA 5-7 wells

PAD (-7 Months)$366,667*from planningPAD (-7 Months)366.667PAD (-7 Months)Provided by Planning


TREATED LENGTH (FT)8,700MUL Factor1.16001.13

STAGE LENGTH150

OWNERSHIP

WI (%)100

NRI (%)82

TYPE CURVE - 7,500' 15,212 MMcf

TIMING ASSUMPTIONS

Production start date of 05/2020*current month + 7 months

See CAPITAL section for CAPEX timings (relative to production start)*report date = current quarter

RESERVES


P50 EUR19.57 BCF*in TC sheetSTARTNov-18

GAS1941019410M/D2MOEXPX

"21000XM/D6EXPB/172

"X30M/DXYRSEXP6

DCNR 100

AREA INFORMATION

PROSPECTDCNR 100Test Month

COUNTYLycomingGross Gas Prod, MMcf (shrunk)2788.3

Avg Wells per Pad4.4444444444Gross Gas Prod, MMcf (unshrunk)2822.1659919028Frac$1,631,200



BTU (mmBTU/mcf)1.03120*in LOE sheet, ARIES inputsNet Tot Exp, M$$1,540.30Flowback$40,000W/ Water

FIXED LOE ($/month/well)$1,264Actual Gas Price, $/Mcf$2.000Sum Total Compl$1,953,120$2,355,253

VARIABLE LOE ($/mcf)$0.031Net Gas Price, $/Mcf$1.031Calc Total Compl$2,040,420$2,442,553

MIDSTREAM FEE ($/mcf)$0.516*$0.50 transport feeNet Gas Revenue. M$$2,875.29Water$402,133

WATER DISPOSAL LOE ($/well, 1 time fee)$29,885



SHRINKAGE %1.2



DRILLING (-6 Months)$1,726,811DRILLING (-6 Months)1726.811DRILLING (-6 Months)DCNR 100 Marc, 2018 Capital Efficiency (1.00)

COMPLETION (-2 Months)$2,355,253COMPLETION (-2 Months)2355.253COMPLETION (-2 Months)used components: Model 7, RCS 10K 200' stg WDA or DCNR 595 6 stg/day

PRODUCTION (-1 Month)$426,000PRODUCTION (-1 Month)426.000PRODUCTION (-1 Month)DCNR 100 5 well

PAD (-7 Months)$495,000PAD (-7 Months)495.000PAD (-7 Months)$2.2MM split out by well


TREATED LENGTH (FT)5,600*from geoMUL Factor1.03701.018

STAGE LENGTH190

OWNERSHIP

WI (%)100

NRI (%)84

TIMING ASSUMPTIONS

Production start date of 08/2018*current month + 7 months

See CAPITAL section for CAPEX timings (relative to production start)*report date = current quarter

RESERVES


P50 EUR13.95 BCF

CRV Marcellus

AREA INFORMATION

PROSPECTCore Areas*CRV/Hemlock/RidgewayTest Month

COUNTYVariousGross Gas Prod, MMcf (shrunk)984.4150'


Net Var Exp, M$$597.50Drillout$429,900


BTU (mmBTU/mcf)1.04120*in LOE sheet, ARIES inputsNet Tot Exp, M$$601.84Flowback$80,000W/ Water







SHRINKAGE %0.90.991



DRILLING (-6 Months)$1,655,874*drill capital x efficiencies + rig movesDRILLING (-6 Months)1655.874DRILLING (-6 Months)WDA Marc, No Capital Efficiency

COMPLETION (-2 Months)$3,828,355*frac + drillout + toe prep + flowback + waterCOMPLETION (-2 Months)3828.355COMPLETION (-2 Months)used components: Hemlock Marc 200' stg

PRODUCTION (-1 Month)$260,000PRODUCTION (-1 Month)260.000PRODUCTION (-1 Month)WDA Bulk 7-10 wells

PAD (-7 Months)$180,000PAD (-7 Months)180.000PAD (-7 Months)Provided by planning


TREATED LENGTH (FT)9,000*from geo - adjustedMUL Factor1.20000.99

STAGE LENGTH150

OWNERSHIP

WI (%)100$0.658

NRI (%)1000.0466666667


Production start date of 05/2020*current month + 7 monthsGAS8075XM/D1MOSB/459

See CAPITAL section for CAPEX timings (relative to production start)*report date = current quarter"5758.75XM/D23IMOSB/257

"1873.4XM/D4.8791EXPB/119

RESERVES"X30M/DXIMOSEXP4.8791

P50 EUR/1000'1.15 BCF/1000'*not in TC sheet

P50 EUR10.35 BCF

Core Areas

AREA INFORMATION

PROSPECTCore Areas*CRV/Hemlock/RidgewayTest Month












SHRINKAGE %0.90.991



DRILLING (-6 Months)$1,606,988*drill capital x efficiencies + rig movesDRILLING (-6 Months)1606.988DRILLING (-6 Months)WDA Marc, No Capital Efficiency

COMPLETION (-2 Months)$3,636,225*frac + drillout + toe prep + flowback + waterCOMPLETION (-2 Months)3636.225COMPLETION (-2 Months)used components: Hemlock Marc 200' stg

PRODUCTION (-1 Month)$260,000PRODUCTION (-1 Month)260.000PRODUCTION (-1 Month)WDA Bulk 7-10 wells



TREATED LENGTH (FT)8,500*from geo - adjustedMUL Factor1.13330.99

STAGE LENGTH150

OWNERSHIP$1.21

WI (%)100$1.47

NRI (%)100


Production start date of 05/2020*current month + 7 monthsGAS8075XM/D1MOSB/459

See CAPITAL section for CAPEX timings (relative to production start)*report date = current quarter"5758.75XM/D23IMOSB/257

"1873.4XM/D4.8791EXPB/119

RESERVES"X30M/DXIMOSEXP4.8791

P50 EUR/1000'1.08 BCF/1000'*not in TC sheet

P50 EUR9.18 BCF

Rich Valley Utica

AREA INFORMATION

PROSPECTCRV UticaTest Month09/2020












SHRINKAGE %0.90.991



DRILLING (-5 Months)$3,007,356*drill capital x efficiencies + rig movesDRILLING (-6 Months)3007.356DRILLING (-6 Months)WDA Utica, 100 well Capital Efficiency


PRODUCTION (-1 Month)$352,148*Prod + Fresh Wtr InjPRODUCTION (-1 Month)352.148PRODUCTION (-1 Month)WDA Bulk Utica 7-10 well + Fresh Water Injection Capital for 5 well pad




STAGE LENGTH200

OWNERSHIP

WI (%)100

NRI (%)100

TYPE CURVE - 1,200' spacing, Q419

TIMING ASSUMPTIONS

Production start date of 05/2020*current month + 7 monthsSegmentStart RateEnd RateUnitsDurationDecline Type & ExponentDecline Rate

See CAPITAL section for CAPEX timings (relative to production start)*report date = current quarter101M/D0.75MOSSPDX

21XM/D1IMOSFLAT0

RESERVES31XM/D12IMOSB/246

P50 EUR/1000'1.73 BCF/1000'50XM/D4.8558EXPB/1.227.4

P50 EUR15.61 BCF6X30M/DXIMOSEXP4.8558

18007650M/D0.75MOSSPDX

7650XM/D1IMOSFLAT0

7650XM/D12IMOSB/246

4131XM/D4.8558EXPB/1.227.4

X30M/DXIMOSEXP4.8558

RV-Boone Mt Utica

AREA INFORMATION













SHRINKAGE %0.90.991









STAGE LENGTH200

OWNERSHIP

WI (%)100

NRI (%)100


TIMING ASSUMPTIONS



21XM/D1IMOSFLAT0


P50 EUR/1000'1.82 BCF/1000'50XM/D4.8558EXPB/1.227.4



7650XM/D1IMOSFLAT0

7650XM/D12IMOSB/246

4131XM/D4.8558EXPB/1.227.4


Hemlock - West Branch Utica

AREA INFORMATION













SHRINKAGE %0.90.991









STAGE LENGTH200

OWNERSHIP

WI (%)100

NRI (%)100


TIMING ASSUMPTIONS



21XM/D1IMOSFLAT0


P50 EUR/1000'1.62 BCF/1000'50XM/D4.8558EXPB/1.227.4



8075XM/D1IMOSFLAT0

8075XM/D12IMOSB/246

4360.5XM/D4.8558EXPB/1.227.4


Sheet1

9K Q39K Q4IR Q3IR Q4

00.01679882980.01679882980.02336391130.0172836988

10.03915017460.03781140970.05091333280.0426968661

20.06259734420.05776837330.07803916610.0672299669

30.08377965740.07525710840.10149202140.0898237404

40.10438538550.09207933340.1236035240.1095586515

50.12327981650.10738642520.14340591810.1294226497

60.14187758520.12235976150.16254252040.1476241213

70.159656780.13660002620.18056475310.1655295665

80.17617685740.14977556960.19710939290.1820981345

90.19261802920.16284096490.21340963060.1985297589

100.20798208210.17501257930.22851186320.2143395662

110.22334808360.18715302650.24350518750.2291092649

120.23824275110.19889291730.25794444170.2438770424

130.25171153550.21042451860.27121974430.2577318492

140.26727869460.22312205390.28600343120.2716044046

150.28153194680.23497507630.29960102240.2850462224

160.29557825760.24681859570.31304639520.2968406469

170.30861849040.25792474950.32556128650.3095387265

180.32160688090.26906627560.33805577590.3214882218

190.33419427490.27989577070.3501886460.3335064488

200.34603460560.29010224850.36161446490.3448360942

210.3579383360.30038730930.37311374210.356249722

220.36915588610.31010526680.38396102850.3673809366

230.38045265510.31992054240.394895220.3778982577

240.39146623510.32952048620.40556493370.3885162354

250.40152633820.33832732410.4153189770.3985616854

260.41203380330.34758750260.42551471080.408715763

270.42197175090.35640356320.4351650640.41865071

280.43201434220.36536853230.444923970.4274443137

290.44152398730.37390881830.45417122850.4369896351

300.4511446750.38259852050.46353247080.4460445403

310.46056550450.39115532120.47270493570.4552207389

320.46950054360.3993136940.48140948010.4639334291

330.47855356110.40762159340.49023385320.4727705177

340.48714774260.41554672610.498615420.4814455927

350.49586312920.42362111560.50711949950.4896925936

360.5044173010.43158227160.51547038510.4980671779

370.51201042890.43867852780.52288639780.5060343339

380.5202751830.44643353510.53096184940.5141304138

390.52813652830.45383962480.53864642150.5220926043

400.53612379450.46139345980.54645729250.5291731578

410.543726410.46861037340.55389494610.5368935078

420.55145589210.47597417080.56145958690.5442498304

430.55906124140.48324535840.5689055090.551736518

440.56630712050.49019619310.5760019950.5588741678

450.57368055920.49729242050.58322586170.5661422068

460.58070946010.50407838420.59011443460.573304414

470.58786599750.51100865350.59713031210.580137956

480.59491758620.51785780730.60404544730.5871014927

490.60119932830.52397613430.61020739130.5937485849

500.60806023510.53067653140.61693931210.600525185

510.61460865160.53708902230.62336639320.6072109438

520.62128395360.5436428980.6299197610.6133854615

530.62765804920.54991697960.63617904530.6199027855

540.6341584460.55633120260.64256395780.6261304166

550.64057375640.56267692960.64886685330.6324857839

560.64670338070.56875423550.65489048940.6385609312

570.65295820880.57496976640.66103857080.6447629398

580.65893676530.58092389990.66691640130.6508900845

590.66503968590.58701497040.6729177950.6567501454

600.67106847040.59304486490.67884754880.6627356258

610.67645172850.59843975130.68414342360.6684620518

620.68234474510.60435686730.68994189390.6743128793

630.68798225420.61002842510.69549002660.6800977943

640.69374178130.61583370840.70115930720.6852675675

650.69925330140.62139927650.70658545870.6909314391

660.70488581540.62709727390.71213171710.6963541324

670.71045611050.63274240120.71761767580.701898568

680.71578888370.63815609360.72287059630.7072083401

690.72124105360.64370027130.72824200970.712638744

700.72646215980.64901818080.73338660790.7180131489

710.73180157880.65446529720.73864860910.7231620498

720.73708563840.65986450410.74385686220.7284298869

730.74197977910.66487281530.7486814980.733477892

740.74716019630.67018187640.75378907620.7386437021

750.75212415380.67527654470.75868393430.7437593081

760.75720367920.68049728430.76369344770.7483375871

770.76207207720.68550803540.76849539560.753360546

780.76705493490.69064362270.77341089310.758176507

790.77199019870.69573709470.77828008190.7631074744

800.77672187620.70062687070.78294900220.7678361937

810.78156634510.70563964840.78772981070.7726787964

820.78621192360.71045268660.79231489890.7774778124

830.7909691930.71538752990.79701078120.7820813254

840.79568345610.72028377870.80166476180.786797043

850.79990523970.72467357180.80583301920.7913214747

860.80453996870.72949816980.81040947980.7959570099

870.80898650740.73413215620.81480059590.8005529337

880.81354204640.73888505680.81929983520.8046706574

890.81791338170.7434507870.82361760.8091932107

900.82239264780.74813429330.82804242780.813534136

910.82683421750.75278337980.83243046650.8179834887

920.83109726960.75725024330.83664255520.8222548289

930.83546666160.76183319870.84096013060.8266335378

940.83966110620.76623706090.8451052270.830977282

950.84396085180.770755920.84935478140.8351481874

960.84822612970.77524295450.85357066220.8394248911

970.85204951420.7792688130.85735009540.8435320143

980.85625084240.78369661960.86150348150.8477439125

990.86028544280.78795260950.86549238750.8519236966

1000.86442283090.79232095980.86958326480.8558052173

1010.86839658420.79652025730.87351267470.8599243497

1020.87247213470.80083087980.8775430760.8638814806

1030.87651703130.80511280310.88154349030.8679409008

1040.88040273450.80922966710.88538676570.8718411626

1050.88438876810.81345632660.88932958250.8758427424

1060.88821841440.81752046540.89311799680.8798156165

1070.89214743730.82169340620.89700500950.8836334248

1080.89604816870.82583961840.90086432260.8875511147

1090.89954746260.82956192140.90432670390.891316331

1100.90339556770.83365828890.90813447960.8951804955

1110.90709379920.83759807490.91179420960.8990180697

1120.91088910920.84164427370.91555026690.9024617431

1130.91453701630.84553616080.91916069110.9062498053

1140.91828109920.84953352320.92286655070.9098914304

1150.92199972650.85350656020.92654746070.9136297568

1160.92557451680.85732857830.93008622180.9172239424

1170.92924414880.86125468710.93371910010.9209139473

1180.93277220830.86503187840.93721204320.9245799176

1190.93639424310.86891226130.94079824750.9281050686

1200.93999260540.87276985210.94436123370.9317247359

1210.94333768360.87635819150.9476736210.9352056974

1220.94689118090.88017249440.95119259470.9387803291

1230.95030843080.88384285330.95457684130.9423325425

1240.95381755810.88761422750.9580522770.9455219798

1250.95719245650.89124355480.9613949610.949032369

1260.96065841470.89497304910.96482802640.9524090035

1270.96410287870.89868164950.96823999150.9558772734

1280.96741603980.90225096480.97152206970.959213683

1290.97081905310.90591919380.97489333630.9626409297

1300.97409262940.90944990610.97813654350.9660477345

1310.97745527370.9130787180.98146816460.9693254299

1320.98079780330.91668785290.9847800280.972692783

1330.9837997920.91993099810.98775461950.9759327838

1340.98710476060.92350332410.99102958260.9792616765

1350.99028467560.92694231010.99418078170.9825713915

1360.99355177280.9304774370.99741853180.9855445287

1370.99669549830.93388083461.0005341670.9888184072

1380.99992566590.93737960411.0037356210.9919690696

1391.0031374150.940860211.0069189720.9952067823

1401.006228240.94421143841.0099826060.9983228694

1411.0094044130.94765690171.013130981.001525284

1421.0124612270.95097449761.0161611741.004710082

1431.015602680.95438558961.0192754071.007775571

1441.0187268050.95777950151.0223725991.01092632

1451.0215338770.9608303611.0251555861.013959244

1461.0246255990.96419209521.0282209061.017076734

1471.0276016560.96742954151.0311716721.020177616

1481.0306606440.97075870491.0342047891.023063577

1491.033605390.97396496581.0371247481.026132861

1501.0366323960.97726224461.0401263971.029087852

1511.0396434290.98054357571.0431123261.032125728

1521.0425422980.98370403181.0459871391.035050666

1531.0455224360.98695447191.0489426611.038057833

1541.0483917420.99008534211.0517883751.041049654

1551.0513416730.99330552371.0547141621.043930514

1561.054276510.99651056421.0576250881.046892635

1571.0569144970.99939255491.0602416761.049745066

1581.059821071.0025692071.0631247731.052678128

1591.0626199681.0056293921.0659011661.055596661

1601.0654979411.0087772681.0687560981.058220398

1611.0682694611.0118098821.0715055261.061111712

1621.0711194461.014929551.0743328931.063896351

1631.0739554361.0180350941.0771464731.066760103

1641.0766867581.0210271431.0798563051.069518349

1651.0794956461.0241053021.0826431851.072355111

1661.0822010151.0270711061.0853274481.075178371

1671.0849833631.0301224061.0880881791.077897834

1681.0877524341.0331602521.0908358261.080694932

1691.0903309581.0359900441.0933944821.083389333

1701.0930747231.0390022191.0961171911.086160797

1711.0957177191.041904761.0987399851.08891943

1721.0984362721.0448912331.1014378441.091400178

1731.1010551151.0477690161.1040368311.094134749

1741.1037489611.0507300151.1067103341.096769245

1751.1064304391.0536781511.1093716431.099479418

1761.1090137581.0565189921.1119356081.102090535

1771.111671261.0594419821.1145732771.104776785

1781.1142316041.0622585911.1171145881.107451054

1791.1168655961.0651566481.1197290741.11002776

1801.1194878151.0680421151.122331951.112678794

1811.1218462481.0706375691.1246730491.115233229

1821.1244463761.0734992281.1272541371.117861467

1831.1269517331.0762567381.1297412161.120478277

1841.1295294491.0790939881.1323001921.122832075

1851.132013321.0818279771.1347660371.125427293

1861.1345690151.0846410251.1373031851.127928059

1871.1371136081.0874418531.1398293131.13050114

1881.1395655921.0901407471.1422635041.132980576

1891.1420884811.0929176841.1447680841.135531709

1901.144519551.0955935571.1471815111.138071759

1911.1470209181.0983468081.1496647271.140519367

1921.1495114211.1010880981.1521371571.143037751

1931.1517516071.1035538661.1543610861.145464481

1941.1542215591.1062725371.1568131141.147961384

1951.156601621.1088922641.1591759031.150447441

1961.1590505041.1115877451.1616070161.152763329

1971.1614102631.1141851271.163949651.155228526

1981.1638382581.1168576161.1663600261.157604004

1991.1662557061.1195184961.1687599311.160048173

2001.1685851741.1220825351.1710724941.162403389

2011.1709820021.1247207181.1734519281.16482671

2021.1732915991.1272628871.1757447651.167239504

2031.1756679821.1298785671.1781039031.169564486

2041.1780340421.1324828841.1804527931.171956699

2051.1801622941.1348254461.18256561.17426185

2061.1825088311.1374082741.1848951091.176633658

2071.1847699681.1398971021.1871398371.178995163

2081.1870964891.1424578991.1894494751.181119317

2091.1893383391.1449254981.1916750561.183461336

2101.1916450161.1474644521.1939649941.18571812

2111.1939416721.1499923771.1962449841.188040162

2121.1961547441.15242831.1984419951.190277695

2131.198431811.1549346621.2007025371.192579931

2141.2006260041.1573498061.2028808081.194872166

2151.2028836481.1598347891.2051220691.197080977

2161.2051314841.1623089781.2073535931.199353659

2171.2072254581.164613811.2094323711.201543629

2181.2094544341.1670672391.2116451711.203796926

2191.2116022871.1694313761.2137774381.206040434

2201.213812251.1718638771.2159713631.208058451

2211.2159417831.1742078491.2180854421.210283448

2221.2181328951.1766196021.2202606541.212427467

2231.2203144891.1790208771.2224264161.214633485

2241.2224166851.181334761.2245133571.216759216

2251.2245796711.1837155531.2266606461.218946417

2261.2266639361.1860096991.2287297861.221124116

2271.2288084711.1883701841.2308587591.22322256

2281.2309436911.1907204161.2329784831.225381684

2291.2328643031.1928344291.2348851581.227462229

2301.2349819041.1951652681.2369873921.229602936

2311.2370224361.1974112781.2390131171.231734344

2321.2391219751.1997222351.2410974191.233651527

2331.2411451021.2019490861.2431058641.235765348

2341.2432267321.2042403321.2451723881.237802238

2351.2452993191.2065216241.2472299341.239898029

2361.2472964751.2087198891.2492125981.241917544

2371.2493513841.2109817221.2512525941.243995458

2381.2513315051.2131612371.2532183461.246064345

2391.2533688851.2154037771.2552409411.248057937

2401.2553974151.2176365751.257254751.250109177

2411.257222061.2196449591.2590661541.252085763

2421.2592338521.2218593331.2610633471.254119506

2431.2611724261.2239931171.2629878531.256144415

2441.2631670581.2261886041.264968011.25803072

2451.2650890961.2283041871.26687611.260038639

2461.2670667131.2304809461.2688393661.26197348

2471.269035741.232648251.2707941041.263964272

2481.2709331061.2347366761.2726777011.265882609

2491.2728853371.2368854921.2746157651.26785642

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Investor Presentation · 2020. 1. 30. · Leidy South (Mid-Atlantic) Firm Sales tied to Firm Transportation (FT) Capacity (Mid-Atlantic/Southeast & Canada-Dawn) Reduced Activity to