Investor Presentation · 2020. 1. 30. · Leidy South (Mid-Atlantic) Firm Sales tied to Firm...
Transcript of Investor Presentation · 2020. 1. 30. · Leidy South (Mid-Atlantic) Firm Sales tied to Firm...
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Investor Presentation
Q1 Fiscal 2020 UpdateJanuary 30, 2020
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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/
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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.
45% of NFG EBITDA(2)
34% of NFG EBITDA(2)
21% of NFG EBITDA(2)
:
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Why National Fuel?
Diversified Assets Provide Stability and Long-Term Growth Opportunities
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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
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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
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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.
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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
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1,000
Gro
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Dth
/day
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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)
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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
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$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
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Financial Highlights
First Quarter Fiscal 2020
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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)
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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
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Exploration & Production and Gathering OverviewSeneca Resources Company, LLC ~ National Fuel Gas Midstream Company, LLC
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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
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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.
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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.
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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
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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
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Cum
ulat
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Prod
uctio
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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
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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
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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
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0.9
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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
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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
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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
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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
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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
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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
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irm V
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/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
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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
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irm V
olum
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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
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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
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ulat
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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
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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)
Total Investment (to date): ~$239 million
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
Total Investment (to date): ~$22 million
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
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2
3
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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
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700
800
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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)
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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.
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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.
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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
Net Var Exp, M$$1,693.36Drillout$634,005
ECONOMIC ASSUMPTIONSNet Fix Exp, M$$11.93Toe Prep$107,000
BTU (mmBTU/mcf)1.01560*in LOE sheet, ARIES inputsNet Tot Exp, M$$1,705.28Flowback$392,600
FIXED LOE ($/month/well)$994Actual Gas Price, $/Mcf$2.000Water$928,000
VARIABLE LOE ($/mcf)$0.036Net Gas Price, $/Mcf$2.031Total w/ 200' stg$5,666,885
MIDSTREAM FEE ($/mcf)$0.508*$0.50 transport feeNet Gas Revenue. M$$5,179.52
WATER DISPOSAL LOE ($/well, 1 time fee)$0*water disposal cost removed
PRICING (Realized)$2.50 / $2.25 / $2.00
BASIS DIFFERENTIAL($0.695)
SHRINKAGE %2.00.98
IMPACT FEESPUD_2019*sames as start date
CAPITAL (and Timing)ARIES EntriesValuesCapitalModel(s) Used
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
TOTAL CAPEX$9,699,697TOTAL CAPEX9849.697
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 EUR/1000'2.25 BCF/1000'*in TC sheet
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
Net Var Exp, M$$1,525.13Drillout$221,920
ECONOMIC ASSUMPTIONSNet Fix Exp, M$$15.17Toe Prep$60,000
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
PRICING (Realized)$2.50 / $2.25 / $2.00
BASIS DIFFERENTIAL($0.730)
SHRINKAGE %1.2
IMPACT FEESPUD_2018*sames as start date
CAPITAL (and Timing)ARIES EntriesValuesCapitalModel(s) Used
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
TOTAL CAPEX$5,003,065TOTAL CAPEX5153.065
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 EUR/1000'2.49 BCF/1000'*in TC sheet
P50 EUR13.95 BCF
CRV Marcellus
AREA INFORMATION
PROSPECTCore Areas*CRV/Hemlock/RidgewayTest Month
COUNTYVariousGross Gas Prod, MMcf (shrunk)984.4150'
Avg Wells per Pad5*from planningGross Gas Prod, MMcf (unshrunk)993.3400605449Frac$2,851,900drill duration10.3601820412
Net Var Exp, M$$597.50Drillout$429,900
ECONOMIC ASSUMPTIONSNet Fix Exp, M$$4.34Toe Prep$84,000
BTU (mmBTU/mcf)1.04120*in LOE sheet, ARIES inputsNet Tot Exp, M$$601.84Flowback$80,000W/ Water
FIXED LOE ($/month/well)$362Actual Gas Price, $/Mcf$2.000Sum Total Compl$3,445,800$4,027,988
VARIABLE LOE ($/mcf)$0.034Net Gas Price, $/Mcf$2.082Water$582,188
MIDSTREAM FEE ($/mcf)$0.573*$0.55 transport feeNet Gas Revenue. M$$2,049.91
WATER DISPOSAL LOE ($/well, 1 time fee)$0*water disposal cost removed
PRICING (Realized)$2.50 / $2.25 / $2.00
BASIS DIFFERENTIAL($0.770)
SHRINKAGE %0.90.991
IMPACT FEESPUD_2019*sames as start date
CAPITAL (and Timing)ARIES EntriesValuesCapitalModel(s) Used
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
TOTAL CAPEX$5,924,228TOTAL CAPEX6074.228
TREATED LENGTH (FT)9,000*from geo - adjustedMUL Factor1.20000.99
STAGE LENGTH150
OWNERSHIP
WI (%)100$0.658
NRI (%)1000.0466666667
TIMING ASSUMPTIONSTYPE CURVE - 8,500' 8,885 MMcf
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
COUNTYVariousGross Gas Prod, MMcf (shrunk)984.4150'
Avg Wells per Pad5*from planningGross Gas Prod, MMcf (unshrunk)993.3400605449Frac$2,700,000drill duration10.1458747721
Net Var Exp, M$$597.50Drillout$417,850
ECONOMIC ASSUMPTIONSNet Fix Exp, M$$4.34Toe Prep$84,000
BTU (mmBTU/mcf)1.04120*in LOE sheet, ARIES inputsNet Tot Exp, M$$601.84Flowback$80,000W/ Water
FIXED LOE ($/month/well)$362Actual Gas Price, $/Mcf$2.000Sum Total Compl$3,281,850$3,825,225
VARIABLE LOE ($/mcf)$0.034Net Gas Price, $/Mcf$2.082Water$543,375
MIDSTREAM FEE ($/mcf)$0.573*$0.55 transport feeNet Gas Revenue. M$$2,049.91
WATER DISPOSAL LOE ($/well, 1 time fee)$0*water disposal cost removed
PRICING (Realized)$2.50 / $2.25 / $2.00
BASIS DIFFERENTIAL($0.770)
SHRINKAGE %0.90.991
IMPACT FEESPUD_2019*sames as start date
CAPITAL (and Timing)ARIES EntriesValuesCapitalModel(s) Used
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
PAD (-7 Months)$440,000PAD (-7 Months)440.000PAD (-7 Months)Provided by planning
TOTAL CAPEX$5,943,213TOTAL CAPEX6093.213
TREATED LENGTH (FT)8,500*from geo - adjustedMUL Factor1.13330.99
STAGE LENGTH150
OWNERSHIP$1.21
WI (%)100$1.47
NRI (%)100
TIMING ASSUMPTIONSTYPE CURVE - 8,500' 8,885 MMcf
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
COUNTYVariousGross Gas Prod, MMcf (shrunk)1514.85200'
Avg Wells per Pad5Gross Gas Prod, MMcf (unshrunk)1528.6074672048Frac$3,201,600drill duration24.2008243446
Net Var Exp, M$$948.47Drillout$534,950
ECONOMIC ASSUMPTIONSNet Fix Exp, M$$4.34Toe Prep$107,000
BTU (mmBTU/mcf)1.02281*in LOE sheet, ARIES inputsNet Tot Exp, M$$952.82Flowback$393,200W/ Water
FIXED LOE ($/month/well)$362Actual Gas Price, $/Mcf$2.000Sum Total Compl$4,236,750$5,232,150
VARIABLE LOE ($/mcf)$0.063Net Gas Price, $/Mcf$2.046Water$995,400
MIDSTREAM FEE ($/mcf)$0.563*$0.55 transport feeNet Gas Revenue. M$$3,098.81
WATER DISPOSAL LOE ($/well, 1 time fee)$0*water disposal cost removed
PRICING (Realized)$2.50 / $2.25 / $2.00
BASIS DIFFERENTIAL($0.770)
SHRINKAGE %0.90.991
IMPACT FEESPUD_2019*sames as start date
CAPITAL (and Timing)ARIES EntriesValuesCapitalModel(s) Used
DRILLING (-5 Months)$3,007,356*drill capital x efficiencies + rig movesDRILLING (-6 Months)3007.356DRILLING (-6 Months)WDA Utica, 100 well Capital Efficiency
COMPLETION (-2 Months)$5,008,038*frac + drillout + toe prep + flowback + waterCOMPLETION (-2 Months)5008.038COMPLETION (-2 Months)used components: Various Utica 200' stg
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
PAD (-6 Months)$440,000180000PAD (-7 Months)440.000PAD (-7 Months)Provided by planning
TOTAL CAPEX$8,807,542TOTAL CAPEX8807.542
TREATED LENGTH (FT)9,000*from geoMUL Factor1.20001.1843
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
PROSPECTCRV UticaTest Month09/2020
COUNTYVariousGross Gas Prod, MMcf (shrunk)1514.85200'
Avg Wells per Pad5Gross Gas Prod, MMcf (unshrunk)1528.6074672048Frac$3,201,600drill duration24.2008243446
Net Var Exp, M$$948.47Drillout$534,950
ECONOMIC ASSUMPTIONSNet Fix Exp, M$$4.34Toe Prep$107,000
BTU (mmBTU/mcf)1.02281*in LOE sheet, ARIES inputsNet Tot Exp, M$$952.82Flowback$393,200W/ Water
FIXED LOE ($/month/well)$362Actual Gas Price, $/Mcf$2.000Sum Total Compl$4,236,750$5,232,150
VARIABLE LOE ($/mcf)$0.063Net Gas Price, $/Mcf$2.046Water$995,400
MIDSTREAM FEE ($/mcf)$0.563*$0.55 transport feeNet Gas Revenue. M$$3,098.81
WATER DISPOSAL LOE ($/well, 1 time fee)$0*water disposal cost removed
PRICING (Realized)$2.50 / $2.25 / $2.00
BASIS DIFFERENTIAL($0.770)
SHRINKAGE %0.90.991
IMPACT FEESPUD_2019*sames as start date
CAPITAL (and Timing)ARIES EntriesValuesCapitalModel(s) Used
DRILLING (-5 Months)$3,007,356*drill capital x efficiencies + rig movesDRILLING (-6 Months)3007.356DRILLING (-6 Months)WDA Utica, 100 well Capital Efficiency
COMPLETION (-2 Months)$5,008,038*frac + drillout + toe prep + flowback + waterCOMPLETION (-2 Months)5008.038COMPLETION (-2 Months)used components: Various Utica 200' stg
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
PAD (-6 Months)$440,000180000PAD (-7 Months)440.000PAD (-7 Months)Provided by planning
TOTAL CAPEX$8,807,542TOTAL CAPEX8807.542
TREATED LENGTH (FT)9,000*from geoMUL Factor1.20001.1843
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/1000'1.82 BCF/1000'50XM/D4.8558EXPB/1.227.4
P50 EUR16.40 BCF6X30M/DXIMOSEXP4.8558
18007650M/D0.75MOSSPDX
7650XM/D1IMOSFLAT0
7650XM/D12IMOSB/246
4131XM/D4.8558EXPB/1.227.4
X30M/DXIMOSEXP4.8558
Hemlock - West Branch Utica
AREA INFORMATION
PROSPECTCRV UticaTest Month09/2020
COUNTYVariousGross Gas Prod, MMcf (shrunk)1514.85200'
Avg Wells per Pad5Gross Gas Prod, MMcf (unshrunk)1528.6074672048Frac$3,372,700drill duration25.00578795
Net Var Exp, M$$948.47Drillout$553,075
ECONOMIC ASSUMPTIONSNet Fix Exp, M$$4.34Toe Prep$107,000
BTU (mmBTU/mcf)1.02281*in LOE sheet, ARIES inputsNet Tot Exp, M$$952.82Flowback$393,200W/ Water
FIXED LOE ($/month/well)$362Actual Gas Price, $/Mcf$2.000Sum Total Compl$4,425,975$5,361,651
VARIABLE LOE ($/mcf)$0.063Net Gas Price, $/Mcf$2.046Water$935,676
MIDSTREAM FEE ($/mcf)$0.563*$0.55 transport feeNet Gas Revenue. M$$3,098.81
WATER DISPOSAL LOE ($/well, 1 time fee)$0*water disposal cost removed
PRICING (Realized)$2.50 / $2.25 / $2.00
BASIS DIFFERENTIAL($0.770)
SHRINKAGE %0.90.991
IMPACT FEESPUD_2019*sames as start date
CAPITAL (and Timing)ARIES EntriesValuesCapitalModel(s) Used
DRILLING (-5 Months)$2,735,634*drill capital x efficiencies + rig movesDRILLING (-6 Months)2735.634DRILLING (-6 Months)WDA Utica, 100 well Capital Efficiency
COMPLETION (-2 Months)$5,125,562*frac + drillout + toe prep + flowback + waterCOMPLETION (-2 Months)5125.562COMPLETION (-2 Months)used components: Various Utica 200' stg
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
PAD (-6 Months)$180,000180000PAD (-7 Months)180.000PAD (-7 Months)Provided by planning
TOTAL CAPEX$8,393,344TOTAL CAPEX8393.344
TREATED LENGTH (FT)9,500*from geoMUL Factor1.26671.1843
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/1000'1.62 BCF/1000'50XM/D4.8558EXPB/1.227.4
P50 EUR15.38 BCF6X30M/DXIMOSEXP4.8558
19008075M/D0.75MOSSPDX
8075XM/D1IMOSFLAT0
8075XM/D12IMOSB/246
4360.5XM/D4.8558EXPB/1.227.4
X30M/DXIMOSEXP4.8558
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
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800.77672187620.70062687070.78294900220.7678361937
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