INVESTOR DAY January 10, 2019 - Calgary AGENDA Timeline Item - - PowerPoint PPT Presentation
TSX: VII INVESTOR DAY January 10, 2019 - Calgary AGENDA Timeline Item Presenters Brian Newmarch 9:00 am Introduction VP Capital Markets Marty Proctor 9:05 am Strategy Chief Executive Officer Derek Aylesworth 9:25 am 2019 Capital
TSX: VII
January 10, 2019 - Calgary
AGENDA
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Timeline Item Presenters 9:00 am Introduction Brian Newmarch VP Capital Markets 9:05 am Strategy Marty Proctor Chief Executive Officer 9:25 am 2019 Capital Allocation Derek Aylesworth Chief Financial Officer 9:50 am Operational Excellence David Holt Chief Operating Officer 10:10 am Planning & Resource Update Chris Feltin VP Corporate Planning Lynne Chrumka Director of Geosciences 10:45 am Q&A
TSX: VII.TO
Marty Proctor, President & Chief Executive Officer
WHO IS SEVEN GENERATIONS ENERGY?
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Serving our stakeholders through:
Strong balance sheet Large, high quality asset base Location/access to infrastructure Control/flexibility Skilled and knowledgeable staff
REVISITING THE CORNERSTONES OF OUR BUSINESS
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Resource Quality & Low Supply Cost Market Access Free Cash Flow Stakeholder Service Return on Capital Financial Sustainability Return of Capital
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7G’S GUIDING PRINCIPLE – STAKEHOLDER SERVICE
Stakeholder Differentiation
We believe that companies have only the rights given to them by society. While people have a natural entitlement to basic rights, corporations are an instrument created by society to provide its needs and ought to have no expectation of basic entitlements other than equitable rights with other corporations, including those wholly owned by a person. We recognize that rights, sufficient to build and
serve the legitimate needs of society in which they exist. To thrive, companies must differentiate, rise above the pack, standout as being among the best with all of their stakeholders. At Seven Generations Energy Ltd., we acknowledge this granted entitlement and accept from our stakeholders a duty to thrive and an understanding of the need to differentiate. Specifically, in acceptance of this challenge to differentiate with all stakeholders, we acknowledge:
The need of society for us to conduct our business in a way that protects the natural beauty of the environment and preserves the capacity of the earth to meet the needs
The need of our business partners and infrastructure customers to be treated fairly and attentively; The need of Canada and Alberta for us to obey all regulations and to proactively assist with the formulation
to better serve society; The need of our suppliers and service providers to be treated fairly and paid promptly for equipment and services provided to us and to receive feedback from us that can help them to be competitive and thrive in their businesses; The need of the communities where we operate to be engaged in the planning of our projects and to participate in the benefits arising from them as they are built and operated; The need of our employees to be compensated fairly and provided a safe, healthy and happy work environment including a healthy work life – outside life balance; and The need of our shareholders and capital providers to have their investment managed responsibly and ethically and to earn strong returns.
We see ourselves as being in the service business, serving the needs of our stakeholders. We seek satisfaction for all stakeholders. Differentiation is imperative. We support an open and competitive business environment, recognizing in the competitive world that we envision, only those who best serve their stakeholders can expect the support required to survive for the longer term.
THE RIGHT LOCATION FOR DEMAND
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WITH A HIGH QUALITY RESOURCE
8 1) For additional information, see “Forward Looking Information Advisory” and “Note Regarding Potential Drilling Opportunities” in the “Important Notice” at the end
15+ years
Nest 1/2/3 Upper & Middle Montney
Most economic resource in Canada Extensive delineation potential Canada’s largest condensate producer 750 MMcf/d of
processing capacity
Gold Creek Cypress Girouxville Groundbirch Glacier Daiber Townsend Tower II Pouce Coupe Bilbo Bigstone Blair Dawson South Dawson Umbach Tupper Tower I North Montney II Gordondale Sunrise East Kakwa Altares Kakwa Greater Placid General Elmworth Gundy Ck Inga/Fireweed Parkland II Town II Pipestone Ante Creek Septimus North Montney I Karr Kaybob Parkland I VII Nest 2
$6.25 $3.51 $2.79 $1.96 $1.89 $1.88 $1.85 $1.78 $1.77 $1.58 $1.45 $1.45 $1.36 $1.23 $1.22 $1.17 $1.13 $0.99 $0.95 $0.95 $0.90 $0.88 $0.84 $0.82 $0.75 $0.67 $0.47 $0.43 $0.42 $0.31 $0.22 $0.16 ($0.01) ($0.16) ($0.20) ($0.26) ($0.29) ($1.15)
$0 $2 $4 $6 $8 $10 $12
9 1) Source: Modified from RSEG 2) For additional information, see “Forward Looking Information Advisory” in the “Important Notice” at the end of this presentation.
… AND LOW SUPPLY COST
Montney Breakeven Henry Hub at Flat $60/bbl WTI, 10% IRR ($/Mcf)1
High Quality Inventory Beyond Nest 2
<10% Liquids 10% to 50% Liquids >50% Liquids
MARKET ACCESS THAT DIFFERENTIATES
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Multiple options available through market access initiatives
Revenue Mix
Condensate NGL Natural Gas
Chicago 55% Chicago 55% Chicago 50% Gulf 18% Gulf 18% Gulf 17% Malin 13% Ventura 4% Dawn 15% Dawn 15% Dawn 13% AECO 9% AECO 11% AECO 5%
2018 2019 2020
7G Gas Market Sales Points
NGPL: 100 MMcf/d Alliance: 500 MMcf/d TCPL: 77 MMcf/d GTN: 90 MMcf/d
100 200 300 400 250 450 650 850
CONDENSATE MARKET OVERVIEW
11 1) Source: Bloomberg, COLC, NEB and 7G Internal forecasts. 2) For additional information, see “Forward Looking Information Advisory” in the “Important Notice” at the end of this presentation.
Local demand continues to support Alberta condensate pricing
Forecast Supply & Demand of WCSB Condensate (Mbbl/d)1 Supply grew faster than demand + Maintenance & curtailments impacts Implied Condensate Imports Required to Meet Demand (Mbbl/d) WCSB Supply Total Demand
2017 2018 2019 2020 2021
Condensate Import Capacity - 275 Mbbl/d
existing gathering and processing network
along the Nest 1 North and East perimeters
initiatives, workovers and water handling
12 1) For additional information, see “Forward Looking Information Advisory”, “Non-IFRS Measures Advisory” and “Note Regarding Potential Drilling Opportunities” in the “Important Notice” at the end of this presentation.
Core investments that enhance margins and expand inventory
2019 BUDGET
FINANCIAL SUSTAINABILITY
13 1) For additional information, see “Forward Looking Information Advisory” and “Non-IFRS Measures Advisory” in the “Important Notice” at the end of this presentation.
A flexible and resilient balance sheet
Leverage
Net debt of $2.2 billion or 1.2x trailing 12 month adjusted funds flow as of September 30, 2018
Liquidity
$1.4 billion (+$0.3 billion option) Undrawn credit facility
Adjusted Funds Flow
~$1.25 billion at US$50/bbl WTI
Risk Management
40-50% of condensate hedged between $62-$78/bbl WTI
Flexibility and Control
React to changing commodity prices NCIB + flex capital in 2019
Capital Allocation
$1.1 billion of sustaining capital Delineation and infrastructure of $150MM (12% of budget)
REVISITING OUR COMMITMENTS
14 1) For additional information, see “Forward Looking Information Advisory” and “Non-IFRS Measures Advisory” in the “Important Notice” at the end of this presentation.
November 2017
What did we say in 2017?
Organic growth of 7-14%/year to add 100 Mboe/d over 5 years 10-15% ROCE Net debt / adjusted funds flow below 2 times Targeting a 2019 funds flow budget at US$55/bbl WTI 2019 forecast of 220-240 Mboe/d at 55% liquids mix (~75 Mbbl/d condensate)
Organic growth of 7-14%/year to add 100 Mboe/d over 5 years 10-15% ROCE Net debt / adjusted funds flow below 2 times Targeting a 2019 funds flow budget at US$55/bbl WTI 2019 forecast of 220-240 Mboe/d at 55% liquids mix (~75 Mbbl/d condensate)
REVISITING OUR COMMITMENTS – DELIVERING WHAT WE PROMISE
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November 2017
What did we say in 2017?
~16% organic growth adding ~27 Mboe/d year-over-year ~15.6% Trailing 12-Month ROCE2 ~1.2x net debt/ adjusted funds flow2 Targeting a funds flow budget at US$50/bbl WTI 2019 budget of 200-205 Mboe/d at 58-60% liquids mix (~75 Mbbl/d condensate)
2018
What did we deliver in 2018?
1) For additional information, see “Forward Looking Information Advisory” and “Non-IFRS Measures Advisory” in the “Important Notice” at the end of this presentation. 2) As at Q3 2018.
TODAY’S TAKEAWAYS
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January 2019
1) For additional information, see “Forward Looking Information Advisory” and “Non-IFRS Measures Advisory” in the “Important Notice” at the end of this presentation.
Establish a firm foundation for 2020 and beyond in a US$50-$55/bbl WTI environment Updated Nest 1 economics with development plan for Nest 3 & Nest 1 Advanced resource understanding and Lower Montney delineation upside Ability to generate per-share growth with NCIB option in place Capital allocation is the input, production growth is the output 2019 program improves efficiency and reduces production volatility
THE 7G INVESTMENT THESIS
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Diverse marketing and price differentiation Delivering operating excellence Expanding discretionary adjusted funds flow High quality resource and deep organic inventory Financial strength, flexibility & liquidity
1) For additional information, see “Forward Looking Information Advisory” and “Non-IFRS Measures Advisory” in the “Important Notice” in the “Important Notice” at the end of this presentation.
TSX: VII
Derek Aylesworth, Chief Financial Officer
CAPITAL ALLOCATION – 7G’S BUDGETING PROCESS
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Returns-based approach to capital allocation
allocation and growth rates
moderated pace of development
volume management
A SUSTAINABLE BUSINESS
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capital efficiency
infrastructure investments in place
development
drives top line revenue
similar to a traditional natural gas producer
Capital Efficiencies Netbacks Decline Rates
to support volume growth in the WCSB
government-mandated production curtailments
balance the market
2019 STRATEGIC PRIORITIES
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Macro Backdrop 7G Priorities
funds flow
efficiencies
increases free cash flow potential
and expand margins
1) For additional information, see “Forward Looking Information Advisory” and “Note Regarding Potential DrillingOpportunities” in the “Important Notice” at the end of this presentation.
2019 BUDGET: BALANCE SHEET MANAGEMENT
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Balance sheet strength is core to 7G’s business
2.4x 1.8x 1.4x 1.2x 0.9x 2015 2016 2017 2018E 2019E Historical $70 WTI $60 WTI $50 WTI
Comfortably levered in lower prices Potentially under- levered with higher prices
Net debt to trailing 12 month adjusted EBITDA
6.75% Notes US$425MM 6.875% Notes US$450MM 5.375% Notes US$700MM
2019 2020 2021 2022 2023 2024 2025
Long maturities with fixed coupons
Long-term debt maturities C$1.4B (+C$0.3B accordion) undrawn credit facility with 2023 maturity
4.5 Years to Next Maturity
1.8x 1.2x < 2.0x Target
1) For additional information, see “Forward Looking Information Advisory” and “Non-IFRS Measures Advisory” in the “Important Notice” at the end of this presentation.
$20 $40 $60 2014 2015 2016 2017 2018 Revenue - $/BOE Revenue After Hedging - $/BOE
HEDGING STRATEGY
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Quarterly Revenue ($/boe) Hedged Volumes (2019 base) Net of Royalties(2) 0% 20% 40% 60% 2019 2020 2021 Condensate Gas
C$62-$78 /bbl C$65-$77 /bbl C$71-$83 /bbl ~C$3.48 /Mcf C$3.59 /Mcf C$3.54 /Mcf
Hedging program has reduced revenue volatility by ~25%
Objectives:
Volume + Term: Mechanic, rolling 3-year hedge targets Year 1: 35% to 65% Year 2: 10% to 35% Year 3: 0% to 20%
1) For additional information, see “Forward Looking Information Advisory” in the “Important Notice” at the end of this presentation. 2) For full detailed hedge disclosure please refer to the appendix of the 7G Corporate Deck. Forecast hedged volume percentages are expressed as 2019 / 2020 / 2021 term hedged volumes expressed as a percent of after-royalty full-year 2019 volumes.
2018 NCIB Activity
NAV improvement from NCIB with successful delineation Accelerated Growth NCIB
2019 BUDGET: ROLE OF SHARE REPURCHASES
24 1) For additional information, see “Forward Looking Information Advisory” in the “Important Notice” at the end of this presentation.
An NCIB is a lower-risk method to add per-share NAV
NCIB accretion grows with successful delineation outcomes
Base NAV (Per Share)
NCIB and accelerated growth options are similar in value
2018 2019
2019 CAPITAL ALLOCATION GUIDING PRINCIPALS
25 1) E&P cash flow reflects $4.00 Condensate-WTI differentials in 2019. 2) For additional information, see “Forward Looking Information Advisory” and “Non-IFRS Measures Advisory” in the “Important Notice” at the end of this presentation. 3) Discretionary free funds flow is defined as adjusted funds flow in excess in excess of sustaining capital.
7G has visibility toward discretionary free funds flow
2018E 2019E
Sustaining Infrastructure Substantial discretionary free funds flow with improved prices Growth Other Delineation Delineation E&P Adjusted Funds Flow E&P Adjusted Funds Flow ($50 WTI) $60 WTI $70 WTI $1.0B $2.0B
Sustaining capital declines due to:
efficiencies
management
moderation over time
Sustaining
Spending to fall by $0.5B y/y with flat production
Nest 2 Development Nest 1 & 3 Development Infrastructure Delineation Value Enhancing
2019 BUDGET
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$1.25 billion
2019 Guidance Sustaining Capital $1.1 billion Discretionary Capital $0.15 billion Total Capital Investment $1.25 billion Average Production 200 - 205 Mboe/d H1/19 Production 195-200 Mboe/d H2/19 Production 205-210 Mboe/d Wells Onstream 65 - 70 Percent Liquids 58-60% Royalty Rate 5-7% Operating Expenses ($/boe) $5.00-$5.50 Transportation ($/boe) $6.75-$7.25 G&A ($/boe) $0.80-$0.90 Interest($/boe) $1.80-$1.90
infrastructure to maintain production on an annual basis across Nest 1, 2 and 3
funds flows
processing network
Sustaining Capital
Discretionary Capital Sustaining Capital
1) For additional information, see “Forward Looking Information Advisory” in the “Important Notice” at the end of this presentation.
Drilling Completions Infrastructure Other
2019 BUDGET: NEST 2 DEVELOPMENT
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Low-risk development program sustains base volumes
$780 MM
infrastructure to maintain production on an annual basis
gathering capacity, Super Pads, well tie ins and additional compression for production optimization
Nest 2
1) For additional information, see “Forward Looking Information Advisory” in the “Important Notice” at the end of this presentation.
Nest 3
Nest 1 Development Nest 3 Development Nest 3 Pipeline Network
2019 BUDGET: NEW DEVELOPMENT & INFRASTRUCTURE
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$320 MM
suggest more prudent for 2020 program
2019
Nest 1
1) For additional information, see “Forward Looking Information Advisory” in the “Important Notice” at the end of this presentation.
Denotes approximate areas of delineation activity
Lower Montney Nest 1 Perimeter Rich Gas Boundary Wapiti
2019 BUDGET: DELINEATION FOR ORGANIC INVENTORY EXPANSION
29 1) For additional information, see “Forward Looking Information Advisory” in the “Important Notice” at the end of this presentation.
$125 MM
resource
definition across area
Lower Montney Wapiti Rich Gas Boundary Nest 1 Perimeter
testing
Water Handling Water Disposal Wells
2019 BUDGET: VALUE ENHANCING PROJECTS
30 1) Based on Bloomberg consensus 2018E % Gas and Q3/18 Reported C$/boe operating expenses 2) Peer Group comprised of AAV, ARX, BIR, BNP, BTE, CPG, CR, ECA, ERF, KEL, NVA, OBE, PEY, PMT, PONY, POU, SGY, TOG, TOU, VET, VII, WCP 3) For additional information, see “Forward Looking Information Advisory” in the “Important Notice” at the end of this presentation.
Investments in operations that expand corporate margins
$25 MM
$0 $5 $10 $15 0% 25% 50% 75% 100%
7G per-boe opex is ~38% below trend for peers with similar liquids/gas mix
$/boe opex(1,2) Gas
Operating Expense vs. Corporate Gas Weighting Water Handling Projects
TSX: VII
David Holt, Chief Operating Officer
OBSERVATIONS – FIRST YEAR
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DEVELOPMENT AND OPERATING PHILOSOPHY
34 1) For additional information, see “Forward Looking Information Advisory” in the “Important Notice” at the end of this presentation.
A level-loaded drilling program supports lower volatility production
EXECUTION: PLANNING STRATEGIES
50 100 150 200 250 14
2015 2016 2017 2018 2019 Production Quarterly Average Rig Counts
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DRILLING & COMPLETIONS – FOCUSED ON EXECUTION EFFICIENCY
Rig 1 Rig 2 Rig 3 Rig 4 Rig 5 Rig 6 Rig 7 Rig 8 Rig 9
1) For additional information, see “Forward Looking Information Advisory” in the “Important Notice” at the end of this presentation.
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EXECUTION: COMPLETIONS EFFICIENCIES
Completion design optimization
1) For additional information, see “Forward Looking Information Advisory” in the “Important Notice” at the end of this presentation.
Benefits
per well year-over-year
mitigation work and well bore architecture
0% 5% 10% 15% January-2017 July-2017 January-2018 July-2018 Wellhead Down Superpad / Satellite Major Plant Concurrent Ops
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Focused on improving in-field efficiency
EXECUTION: FOCUSED ON DOWNTIME
Better pace, plant performance, and planning of concurrent operations Operating ‘friction’ with high pace of growth
Downtime as a % of Total Sales Volumes
OPTIMIZATION: BASE PRODUCTION IS A PRIORITY
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The sustainability of 7G’s business naturally improves with time
Production-Weighted Average Well Age
2018 Exit 2020E Exit
Historical pace of growth means most production is from new, high-decline wells
Production-Weighted Average Well Age 1Y 2Y 3Y 4Y 5Y+ 1Y 2Y 3Y 4Y 5Y+ Sustaining capital reduced by up to $100 MM Maturing business means a more balanced, lower-decline portfolio
1) For additional information, see “Forward Looking Information Advisory” in the “Important Notice” at the end of this presentation.
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2018 FIELD OPTIMIZATION INITIATIVES
Project Description Incremental Production (Post 30d Avg) Satellite Compression Installed gas compression on satellite pads to reduce wellhead pressures on pad wells 615 Tubing Changes Changed tubing sizes and conventional gas lift designs 284 Gas Lift Valve Changes Enhanced gas lift valve designs in side pocket gas lift mandrels 1,785 Electric Submersible Pumps (ESP) Piloted ESP's on high CGR wells 970 Compressor Auto-Pockets (VVP) Installed automatic volume pockets on select compression in the field 580 Project Description Decreased OPEX ($k/month) Plunger Installations Installed de-waxing plunger lift systems on wells 300 1,000 2,000 3,000 4,000 5,000 6,000 7,000 BOE/d
boe/d of sustainable base production
equate to $3,000 per boe/d capital efficiencies
Pre Optimization Post Optimization
1) For additional information, see “Forward Looking Information Advisory” in the “Important Notice” at the end of this presentation.
10 20 30 40 50 60 70 80
OPTIMIZATION: ACTIVELY MANAGING LEGACY VOLUMES
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2015 Vintage Wells 2016 Vintage Wells Base is stabilizing with renewed focus
Production (Mboe/d) H1/2018 H2/2018
COST CONTROL: CAPITAL INVESTMENT IMPROVEMENTS
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Sourcing strategies have yielded the following savings for 2019
integrated and cross functional area strategies
Category % Change
Completions
Drilling
Facilities
Camp Facilities
Other - Drill, Comp, FAC
Total
1) For additional information, see “Forward Looking Information Advisory” in the “Important Notice” at the end of this presentation.
COST CONTROL: THE VALUE OF WATER HANDLING INFRASTRUCTURE
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Reduced opex by $1.30/boe since 2017, with project payout of ~18 months
WDW1 WDW2 WDW3 WDW4 Pembina WDW
Pembina Plant
2017
2018
2019
1) For additional information, see “Forward Looking Information Advisory” in the “Important Notice” at the end of this presentation.
OPERATIONS WRAP-UP
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We are instilling a culture of cost awareness Investments and
enhancements that drive results We are progressing
improvements on multiple fronts
TSX: VII
Chris Feltin, VP Corporate Planning
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2019 DEVELOPMENT OBJECTIVES
Expand Nest 2 Boundaries
2 North and Nest 1
Integrate Nest 3
development program
Enhance Nest 1 Understanding
Provide greater inventory clarity
1) For additional information, see “Forward Looking Information Advisory” in the “Important Notice” at the end of this presentation.
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NEST 3 STRATEGIC BENEFITS
CGR: 300– 500 bbl/mmcf
CGR: 50–80 bbl/mmcf
CGR: 90–300 bbl/mmcf
condensate rates per well in line with Nest 2 South
Nest 3 wells comparable in performance to 2 Nest 2 wells
blend with higher CGR regions of Nest 1 and Nest 2 to manage corporate condensate and natural gas mix
1) For additional information, see “Forward Looking Information Advisory” in the “Important Notice” at the end of this presentation.
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INTEGRATED APPROACH TO DEVELOPMENT Integrated Development Strategy
aspects of development and execution
execution plans
deliverability can be tracked and integrated into future pads
minimized health, safety, environmental impacts
Value Driven Development Production Operations Drilling
Completions
Facilities Reservoir G&G Marketing / Midstream HSE Corporate Planning Land
DELINEATION STRATEGY
48 1) For additional information, see “Forward Looking Information Advisory” in the “Important Notice” at the end of this presentation.
resource
definition across area
Lower Montney Wapiti Rich Gas Boundary Nest 1 Perimeter
testing
Denotes approximate areas of delineation activity
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DEVELOPMENT PLAN
regions
handling
liners and perf clusters
pads
Delineation
& efficiencies
development
pipeline capacity
conjunction with Upper / Middle Montney
1) For additional information, see “Forward Looking Information Advisory” in the “Important Notice” at the end of this presentation.
TSX: VII
Lynne Chrumka, Director of Geosciences
7G’S NEST MONTNEY DEVELOPMENT AREA
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Integrated Reservoir Characterization
New Development Area Segmentation
Utilizing 3D Seismic
pore fluids, rock properties)
Core & Petrophysics
Science Pad
3D Reservoir Model
NEST 2 UPDATE
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Enhanced understanding of 7G’s core asset
Condensate gas ratios (bbl/MMcf) vs. time (normalized month) 500 12 24
2017 Nest 2 Type Curve North South East West
latest interpretation
Liquids & Gas Details Nov 2017 Budget May 2018 Update 2019 Budget Total Liquids
%
55-60% 58-60% 58-60% Condensate
%
30-32% 35-36% 36-38% NGLs
%
25-28% 23-24% 22% Natural Gas
%
40-45% 40-42% 40-42% CGR
bbl/MMcf
125 145-155 159
1) For additional information, see “Forward Looking Information Advisory” in the “Important Notice” at the end of this presentation.
Nest 2 2019 Activity NEST 3 UPDATE
53 1) For additional information, see “Forward Looking Information Advisory” in the “Important Notice” at the end of this presentation.
Cumulative condensate (Mbbl) vs. time (normalized days) 50 100 30 60 90 120 150 180
development capacity
30,000 – 40,000 boe/d
Development Plans Resource View
Nest 3 2019 Activity
NEST 1 UPDATE – ENHANCED ECONOMICS
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1) The following pricing assumptions were used to develop the economic forecasts shown above: $55.00 US/bbl WTI, $3.00 US/mcf NYMEX/HH and 0.76 USD/CAD FX. NGLs as % of WTI: Alberta - C3 25%, C4 35%, C5 91%, Chicago - C3 35%, C4 45%, C5 95%. Chicago Basis US$0.15/mcf to NYMEX/HH and AECO Basis US$1.75/mcf to NYMEX/HH. Chicago transport US$1.20/mcf and AECO transport US$0.25/mcf. Variable liquids opex C$5.00/bbl and Variable gas opex C$0.60/mcf. Fixed well operating cost = $20,000/mo. 2) For additional information, see “Forward Looking Information Advisory”, “Further Economic Assumptions” and “Note Regarding Potential Drilling Opportunities” in the “Important Notice” at the end of this presentation.
Nest 1 results are promising, development planned for 2020+
Cumulative condensate (Mbbl) vs. time (normalized month) Key Stats Nest 1 (2014) Nest 1 (2018 Estimates) IP30
(boe/d)
1,250 1,500 IP365
(boe/d)
675 775 DCET Cost
($MM)
$9.5 $11 IP365 CGR
(bbls/MMcf)
135 478 IRR
(%)
29% 83% NPV
($MM)
$2.3 $6.7
Major changes to completions since 2014 Latest 7G results see high CGRs 7G’s 2018 wells saw high CGRs with offset wells that help confirm the geological model throughout Nest 1
IP94 1,730 BOE/d 44% Condensate Flowtest IP20 (7 HZ) 1,068 – 1,972 BOE/d ~63% Condensate IP60 (2 HZ) 1,413 – 1,963 BOE/d ~64% Condensate IP96 2,030 BOE/d 55% Condensate IP80 1,203 BOE/d 52% Condensate IP90 1,464 BOE/d 68% Condensate
50 100 150 200 250 300 3 6 9 12
2014 Curve Nest 1 Actuals
Competitor wells
Nest 1 2019 Activity
LOWER MONTNEY UPDATE
55 Illustration not to scale
2,800-3,000 meters 200 metres 800 metres
IP90: 1048 boe/d, 72% condensate Comingled vertical test (5d): 2MMcf gas; 162 bbls condensate
Triple-stack test
1) For additional information, see “Forward Looking Information Advisory” and “Note Regarding Potential Drilling Opportunities” in the “Important Notice” at the end of this presentation.
Upper Montney Middle Montney Lower Montney Denotes approximate areas of delineation activity
CRETACEOUS UPDATE – OPPORTUNISTIC DEVELOPMENT
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1) Assumes a stand-alone well fully burdened with an allocation of initial pad capital and fixed operating costs 2) Assumes a well isn’t burdened with initial site/pad costs associated with existing Montney development, and isn’t burdened with a portion of the fixed operating costs 3) As per (2) but assumes a 2019 blended realized price at AECO, Dawn, Malin - ~$1.00/MMbtu higher than (1) & (2) 4) The following pricing assumptions were used to develop the economic forecasts shown above: $55.00 US/bbl WTI, $3.00 US/MMbtu NYMEX/HH and 0.76 USD/CAD FX. NGLs as % of WTI: Alberta - C3 25%, C4 35%, C5 91%. AECO Basis US$1.75/mcf to NYMEX/HH narrowing at US$0.10/year to $1.25/MMbtu. Variable liquids opex C$5.00/bbl and Variable gas opex C$0.60/mcf. Fixed well operating cost = $1,500/mo to $5,000/mo. 5) The forecast economics shown above do not take into account certain other costs that would be required to construct infrastructure, including central processing facilities, regional gathering facilities and other infrastructure, nor do they take into account land acquisition costs, corporate overhead (G&A) expenses, financing costs or corporate taxes. No adjustments have been made for expected downtime or facility constraints, so the forecasts present an idealistic view of results that could be achieved in the absence of additional infrastructure costs, operational challenges or downtime. Actual results will differ from these forecasts for the reasons described above and because of the risks and risk factors that are described in the “Forward-Looking Information Advisory” in the “Important Notice” at the end of this presentation. 6) For additional information, see “Forward Looking Information Advisory”, “Further Economic Assumptions” in the “Important Notice” at the end of this presentation.
Key Stats Stand-alone Development 1 Existing Infrastructure 2 Existing + Premium Price 3 IP30
(boe/d)
1,250 IP365
(boe/d)
800 Total Cost
($MM)
$7.0 $5.5 $5.5 IP365 CGR
(bbls/MMcf)
5 IRR
(%)
5% 55% NPV
($MM)
3.3
EOR of the Montney resource
larger multi-well pad spud-sales time
Spirit River Upper / Middle Montney Lower Montney Kakwa River Resource Stack
2 HZ Up to 190 locations
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1) The following pricing assumptions were used to develop the economic forecasts shown above: $55.00 US/bbl WTI, $3.00 US/mcf NYMEX/HH and 0.76 USD/CAD FX. NGLs as % of WTI: Alberta - C3 25%, C4 35%, C5 91%, Chicago - C3 35%, C4 45%, C5 95%. Chicago Basis US$0.15/mcf to NYMEX/HH and AECO Basis US$1.75/mcf to NYMEX/HH. Chicago transport US$1.20/mcf and AECO transport US$0.25/mcf. Variable liquids
2) NGL recoveries and shrinkage factors are based on the company’s best estimate of the liquids to be extracted at the Pembina Kakwa River Plant and at 7G’s wholly owned plants in Alberta, as well as the liquids to be processed by Aux Sable at its facilities near Chicago, Illinois pursuant to the terms of the rich gas premium agreement between 7G and Aux Sable, which depends upon an assumed heating value and has been assumed to extend for the entire productive life of the wells. 3) For a description of the methodology used and the assumptions made by the company in preparing the type-curve forecasts that were used to develop the forecast economics shown in the above table, and for important additional information regarding the type-curve forecasts and the estimated potential drilling opportunities that are reflected above, please see the “Note Regarding Development Area Forecast Economics and Type Curves” and the “Note Regarding Potential Drilling Opportunities” in the “Important Notice” at the end of this presentation. 4) Nest 1 (2018 Estimates) represent an average of Nest 1 Pads brought on-stream in 2018, economics on total remaining locations may vary from 2018 results. 5) The forecast economics shown above are half-cycle economics and include only the cost to drill, complete, tie and equip wells. The forecasts do not take into account certain other costs that would be required to construct infrastructure, including Super Pads, central processing facilities, regional gathering facilities, condensate stabilization facilities and other infrastructure, nor do they take into account land acquisition costs, corporate
made for expected downtime or facility constraints, so the forecasts present an idealistic view of results that could be achieved in the absence of additional infrastructure costs, operational challenges or downtime. Actual results will differ from these forecasts for the reasons described above and because of the risks and risk factors that are described in the “Forward-Looking Information Advisory” in the “Important Notice” at the end of this presentation. 6) The drilling locations reflect the estimated number of drilling opportunities as at December 31, 2018. 7) Net Present Value (NPV) is calculated based on a 10% annual discount factor.
SUMMARY OF PREMIUM SINGLE WELL DCE&T ECONOMICS
Key Stats Nest 1 (2018 Estimates) Nest 2 Nest 3 South East West North Weighted Average IP30
(boe/d)
1,500 1,950 - 2,350 2,000 IP365
(boe/d)
775 1,150 - 1,650 1,400 DCET Cost
($MM)
$11 $10.5 - $11.5 $11.0 IP365 CGR
(bbls/MMcf)
478 90 160 170 295 225 55 IRR
(%)
83% 85% 150% >250% 215% 185% 62% NPV
($MM)
$6.7 $6.4 $11.5 $16.0 $12 $11.5 $6.4 PIR
(x)
0.6 0.6 1.0 1.5 1.1 1.0 0.6 Locations
(#)
480 90 170 75 280 615 190
TSX: VII
Marty Proctor, President & Chief Executive Officer
2019 TAKEAWAYS
59
Diverse marketing and price differentiation
Delivering operating excellence
Expanding discretionary adjusted funds flow
High quality resource and deep organic inventory
Financial strength, flexibility & liquidity
60
IMPORTANT NOTICE
General Advisory The information contained in this presentation does not purport to be all- inclusive or contain all information that readers may require. Prospective investors are encouraged to conduct their own analysis and review of Seven Generations Energy Ltd. (“Seven Generations”, “7G”, “VII”, the “company” or the “Company”) and of the information contained in this
entire record of publicly filed documents relating to the Company, consider the advice of their financial, legal, accounting, tax and other professional advisors and such other factors they consider appropriate in investigating and analyzing the Company. An investor should rely only on the information provided by the Company and is not entitled to rely on parts of that information to the exclusion of others. The Company has not authorized anyone to provide investors with additional or different information, and any such information, including statements in media articles about Seven Generations, should not be relied upon. In this presentation, unless
and per share amounts are presented on a diluted basis. An investment in the securities of Seven Generations is speculative and involves a high degree of risk that should be considered by potential
encountered in the oil and gas industry and, more specifically, the shale and tight liquids-rich natural gas sector of the oil and natural gas industry, and certain other risks that are associated with Seven Generations’ stage
for those purchasers who are willing to risk a loss of some or all of their investment and who can afford to lose some or all of their investment. Non-IFRS Measures Advisory In addition to using financial measures prescribed by International Financial Reporting Standards (“IFRS”), references are made in this presentation to “return on capital employed” (or “ROCE”), “cash return on invested capital” (or “CROIC”) and “adjusted EBITDA”, which are measures that do not have any standardized meaning as prescribed by IFRS. Accordingly, the Company’s use of such terms may not be comparable to similarly defined measures presented by other entities and comparisons should not be made between such measures provided by the Company and by
companies without also taking into account any differences in the way that the calculations were prepared. For further details about these measures, and reconciliations between those measures and the most directly comparable measures under IFRS for the most recently completed quarter, see “Non-IFRS Financial Measures” in the Company’s Management’s Discussion and Analysis dated October 30, 2018 for the three and nine months ended September 30, 2018 and 2017, which is available on the SEDAR website at www.sedar.com. For additional information about “adjusted funds flow” and “net debt”, which are measures prepared in accordance with IFRS, please see note 14 of the company’s Condensed Interim Consolidated Financial Statements for the three and nine months ended September 30, 2018 and 2017, available on the SEDAR website at www.sedar.com Forward-Looking Information Advisory This presentation contains certain forward-looking information and statements that involve various risks, uncertainties and other factors. The use of any of the words “anticipate”, “continue”, “estimate”, “expect”, “may”, “will”, “should”, “believe”, “plans”, “outlook”, “forecast” and similar expressions are intended to identify forward-looking information
contains forward-looking information and statements pertaining to the following: the Company’s strategies, strategic pursuits and priorities, strategic objectives and competitive strengths; the Company’s development plans and the anticipated timelines for development; adjusted funds flow forecasts; leverage ratio forecasts; forecast production, planned production growth (aggregate and per share), forecast gas rates, condensate and liquids yields and CGRs; forecast production profiles; forecast ROCE; forecast CROIC; the extensive upside potential, potential to expand boundaries for Nest quality resource, and improved inventory depth expected in connection with further delineation that is planned; forecast capital efficiencies; reduced production volatility and lower production decline rates expected in connection with the Company’s development plans; expected drilling inventory and number of years to drill such inventory; expectation that planned capital investments will lead to a permanently lower cost structure; forecast condensate supply and demand and import pipeline capacity required to balance the market; pressure estimates; available transportation and processing capacity; planned capital investments, capital investment budget and allocation of capital; expected value enhancement to result from infrastructure investments; plans to expand discretionary free adjusted funds flow; forecast costs and expenses, including OPEX, transportation, G&A and interest; cost savings projected from planned capital investments and from the Company’s sourcing strategies; planned operational activities, including the number of drilling rigs to be utilized and the number of completions spreads to be utilized, and the planned D&C schedule; potential NAV enhancements to result from production growth, NCIB investments, and delineation activities; expectation that reductions in sustaining capital will occur with projected increases in production weighted average well age; upside potential from various formations; improved production sustainability over time; the number of wells estimated to be required to sustain production; expectation that base production will continue to stabilize with a renewed focus on well interventions for legacy wells; forecast economics, including single well economics, IRRs, break-even costs and NPVs; hedge targets; expectation that a “triple-stack” development model will likely be optimal for the development of the Lower Montney formation; prices and the references to development area forecasts and type-curve estimates. In addition, information and statements in this presentation relating to reserves and resources are deemed to be forward-looking statements as they involve the implied assessment, based on certain estimates and assumptions, that the reserves and resources described exist in the quantities predicted or estimated, and that the they can be profitably produced in the future. With respect to forward-looking information contained in this presentation, assumptions have been made regarding, among other things: future oil, NGLs and natural gas prices being consistent with current commodity price forecasts after factoring in quality adjustments at the company’s points of sale; the company’s continued ability to obtain qualified staff and equipment in a timely and cost-efficient manner; third party transportation and processing facilities will be operated in an efficient and reliable manner; drilling and completions techniques and infrastructure and facility design concepts that have been successfully applied by the Company elsewhere in its Kakwa River Project may be successfully applied to other properties within the Kakwa River Project; that wells drilled in the same fashion in the same formations in proximity to the type-wells that were used in 7G’s type- curve forecasts will deliver similar production results, including liquids yields; the geology and reservoir quality being relatively consistent within each of the Company’s separate asset areas; well results from future wells to be drilled in the Company’s asset areas being similar to wells that have been drilled in those areas to date, as well as the type-curve estimates for those areas; the consistency of the current regulatory regime and legal framework, including the laws and regulations governing the company’s oil and gas operations, royalties, taxes and environmental matters in the jurisdictions in which the Company conducts its business and any other jurisdictions in which the Company may conduct its business in the future; the company’s ability to market production of oil, NGLs and natural gas successfully to customers; that the company’s future production levels, amount of future investment, costs, royalties, unabsorbed demand charges, facilities downtime and development timing will be consistent with the company’s current development plans and budget; the applicability of new technologies for recovery and production of the company’s reserves and resources may improve capital and operational efficiencies in the future; the recoverability of the company’s reserves and resources; sustained future capital investment by the company; future cash flows from production; the Company’s future sources of funding; the Company’s future debt levels; geological and engineering estimates in respect of the Company’s reserves and resources; the geography of the areas in which the Company is conducting exploration and development activities, and the access, economic, regulatory and physical limitations to which the Company may be subject from time to time; the impact of competition on the Company; and the Company’s ability to obtain financing on acceptable terms. The adjusted funds flow forecasts referenced in this presentation were calculated based upon the assumptions outlined on the slide that is titled “2019 Budget” and the following commodity pricing assumptions: $50.00 US/bbl WTI, $3.00 US/MMbtu NYMEX/HH and 0.74 USD/CAD FX. NGLs as % of WTI: C3 35%, C4 50%, C5 – $4 CAD/bbl differential. AECO Basis US$1.75/MMbtu. Operating cost assumptions reflect recent actual cost trends with adjustments to address planned activity levels. Royalty rate assumptions were calculated using a price range of US$50-US$65/bbl WTI, net of credits as of December 31, 2018 and projected C* for new wells to be drilled in 2019. Royalty rate assumptions are net of expected gas cost allowance investments in gas plants. G&A cost assumptions reflect recent actuals and expectations for a larger staff count and information technology investments in 2019. Net debt forecasts were calculated by adding the principal of the unsecured notes to the forecasted principal of the Company‘s Credit Facility, less forecast adjusted net working capital. The CROIC forecast provided in this presentation was calculated by dividing forecast adjusted EBITDA by the forecast average gross carrying value of the company’s oil and natural gas assets. For the purposes of the calculation, the forecast average carrying value of the company’s oil and natural gas assets, excluded forecast accumulated depletion and
flow less forecasted interest expense and forecasted gross oil and natural gas assets is based on the company’s currently anticipated capital investment profile.
61
IMPORTANT NOTICE
The ROCE forecast was determined by dividing Seven Generations’ forecast adjusted EBIT by the forecast average carrying value of the company's net assets. For the purposes of the calculation, net assets were forecast total assets less forecast current liabilities. Forecasted EBIT is based on forecasted adjusted funds flow less forecasted interest and forecasted depletion. Depletion was forecasted using forecasted production volumes and the Company’s current depletion rate. For additional information regarding the methodologies that the company uses in respect of the above calculations, please see “Advisories and Guidance – Non-IFRS financial measures” in Management’s Discussion and Analysis dated October 30, 2018, for the three and nine months ended September 30, 2018 and 2017, and the notes to the company’s Condensed Interim Consolidated Financial Statements for the three and nine months ended September 30, 2018 and 2017. Assumptions made in the calculations of forecasted economics, including forecasted NPVs, IRRs, price sensitivities, commodity prices and recovery factors reflect cost assumptions that based upon recent actual cost trends with adjustments to address planned activity levels. Royalty rates were calculated using a price range of US$50-US$65/bbl, net of credits as of Dec.31/18 and projected C* for new wells to be drilled in 2019. Royalty rates were calculated net of expected gas cost allowance investments in gas plants. G&A costs used in the forecasts reflect recent actuals and expectations for a larger staff count and IT investments in 2019. Various factors and assumptions were applied in developing the production weighted average well age projections that are provided in this presentation, including the production weighted average of well age at the end of each year. An assumption has also been made that further well delineation activities will confirm management’s estimates regarding reservoir quality of its properties that fall outside of the Company’s core development areas. With respect to the estimated number of drilling locations or potential drilling
made. These assumptions are described under the heading “Note Regarding Potential Drilling Opportunities” below. Actual results could differ materially from those anticipated in forward- looking information as a result of the risks and risk factors that are set forth in the Company’s Annual Information Form dated March 13, 2018 (the “AIF”), which is available on SEDAR at www.sedar.com, including, but not limited to: volatility in market prices and demand for oil, NGLs and natural gas, and hedging activities related thereto; general economic, business and industry conditions; variance of the Company’s actual capital costs,
find, develop or acquire additional reserves and the availability of the capital
exploration, development and production of oil and natural gas reserves and resources; negative public perception of oil sands development, oil and natural gas development and transportation, hydraulic fracturing and fossil fuels; actions by governmental authorities; changes in laws or regulations, including those pertaining to royalties or taxation; the rescission, or amendment to the conditions of, groundwater licenses of the Company; management of the Company’s growth; the ability to successfully identify and make attractive acquisitions, joint ventures
investments,
successfully integrate future acquisitions or businesses; the availability, cost or shortage of rigs, equipment, raw materials, supplies or qualified personnel; adoption or modification of climate change legislation by governments; the absence
loss
key employees; uncertainty associated with estimates of oil, NGLs and natural gas reserves and resources and the variance of such estimates from actual future production; dependence upon processing facilities, compressors, gathering lines, pipelines and other facilities, certain of which the Company does not control; the ability to satisfy obligations under the Company’s firm commitment transportation arrangements; the uncertainties related to the Company’s identified drilling locations; the high-risk nature of successfully stimulating well productivity and drilling for and producing oil, NGLs and natural gas; operating hazards and uninsured risks; risk of fires, floods and natural disasters; the possibility that the Company’s drilling activities may encounter sour gas; execution risks associated with the Company’s business plan; failure to acquire or develop replacement reserves; the concentration of the Company’s assets in the Kakwa River Project area; unforeseen title defects; aboriginal claims; failure to accurately estimate abandonment and reclamation costs; development and exploratory drilling efforts and well operations may not be profitable or achieve the targeted return; horizontal drilling and completion technique risks and failure of drilling results to meet expectations for reserves or production; limited intellectual property protection for operating practices and dependence on employees and contractors; third-party claims regarding the Company’s right to use technology and equipment; expiry of certain leases for the undeveloped leasehold acreage in the near future; failure to realize the anticipated benefits of acquisitions or dispositions; failure of properties acquired now or in the future to produce as projected and inability to determine reserve and resource potential, identify liabilities associated with acquired properties or obtain protection from sellers against such liabilities; changes in the application, interpretation and enforcement of applicable laws and regulations; restrictions on drilling intended to protect certain species of wildlife; potential conflicts of interests; actual results differing materially from management estimates and assumptions; seasonality of the Company’s activities and the Canadian oil and gas industry; alternatives to and changing demand for petroleum products; extensive competition in the Company’s industry; changes in the Company’s credit ratings; dependence upon a limited number of customers; lower oil, NGLs and natural gas prices and higher costs; failure of seismic data used by the Company to accurately identify the presence of oil and natural gas; risks relating to commodity price hedging instruments; terrorist attacks or armed conflict; cyber security risks, loss of information and computer systems; inability to dispose of non-strategic assets on attractive terms; security deposits required under provincial liability management programs; reassessment by taxing authorities of the Company’s prior transactions and filings; variations in foreign exchange rates and interest rates; third-party credit risk including risk associated with counterparties in risk management activities related to commodity prices and foreign exchange rates; sufficiency of insurance policies; potential litigation; variation in future calculations of non-IFRS measures; sufficiency of internal controls; breach of agreements by counterparties and potential enforceability issues in contracts; impact of expansion into new activities on risk exposure; inability of the Company to respond quickly to competitive pressures; and the risks related to the common shares that are publicly traded and the Company’s senior notes and other indebtedness, including the potential inability to comply with the covenants in the credit agreement related to the Company’s credit facilities and/or the covenants in the indentures in respect of the Company’s senior unsecured notes. Financial outlook and future-oriented financial information contained in this presentation regarding prospective financial performance, financial position, cash flows or well economics is based on assumptions about future events, including economic conditions and proposed courses of action, based on management’s assessment of the relevant information that is currently
information and is based on a number of material assumptions and factors, as are set out herein. Such projections may also be considered to contain future oriented financial information or a financial outlook. The actual results
amounts set forth in these projections, and such variations may be material. Actual results will vary from projected results. Financial outlook and future-
inform readers of the estimated implications of the capital investments planned by the company. Readers are cautioned that any such financial
not be used for purposes other than those for which it is disclosed herein. The forward-looking statements included in this presentation are expressly qualified by the foregoing cautionary statements and are made as of the date of this presentation. The Company does not undertake any obligation to publicly update or revise any forward-looking statements except as required by applicable securities laws. No assurance can be given that these expectations will prove to be correct and such forward-looking statements included in this presentation should not be unduly relied upon. Certain information contained herein has been prepared by third-party sources (and is identified as such) and has not been independently audited
Presentation of Oil and Gas Information Estimates
the Company’s reserves, contingent resources and prospective resources contained herein are based upon the reports dated March 13, 2018 prepared by McDaniel & Associates Consultants Ltd. (“McDaniel”), the Company’s independent qualified reserves evaluator, as at December 31, 2017 (the “McDaniel Reports”). The estimates of reserves, contingent resources and prospective resources provided in this presentation are estimates only and there is no guarantee that the estimated reserves, contingent resources and prospective resources will be recovered. Actual reserves, contingent resources and prospective resources may be greater than or less than the estimates provided in this in this presentation and the differences may be material. There is no assurance that the forecast price and cost assumptions applied by McDaniel in evaluating Seven Generations’ reserves, contingent resources and prospective resources will be attained and variances could be material. There is no certainty that any portion of the prospective resources will be
viable to produce any portion of the prospective resources. There is also uncertainty that it will be commercially viable to produce any part of the contingent resources.
62
IMPORTANT NOTICE
(Continued) This presentation includes estimates of contingent resources and prospective resources, as at December 31, 2017, that have been risked by McDaniel for the probability of loss or failure in accordance with the COGE Handbook. For contingent resources, the risk component relating to the likelihood that an accumulation will be commercially developed is referred to as the chance of development. Contingent resources in the “development pending” project maturity subclass have been assigned by McDaniel, as at December 31, 2017, in the upper and middle intervals of the Montney formation in certain parts of the Nest 1, Nest 2, Nest 3, Rich Gas and Wapiti areas. The COGE Handbook indicates that it is appropriate to categorize contingent resources in the development pending project maturity subclass where resolution of the final conditions for development are being actively pursued and there is a high chance of
maturity subclass have been assigned by McDaniel, as at December 31, 2017, in the lower interval of the Montney formation in the northwest corner
categorize contingent resources in the development unclarified project maturity subclass when the evaluation is incomplete and there is ongoing activity to resolve any risks or uncertainties. These resource estimates are not classified as reserves at this time, pending further reservoir delineation, project application, facility and reservoir design work. There is uncertainty that it will be commercially viable to produce any portion of the contingent resources. Prospective resources have both an associated chance of discovery and a chance
development. Not all exploration projects will result in
discovery of petroleum is referred to as the chance of discovery. For an undiscovered accumulation, the chance of commerciality is the product of two risk components - the chance of discovery and the chance of
were evaluated, as at December 31, 2017 by maturity status, consistent with the requirements of the COGE Handbook. The prospective resources associated with the upper and middle intervals of the Montney formation in the Deep Southwest and Wapiti areas of the Project have been sub- classified as “prospect” by McDaniel, which the COGE Handbook defines as a potential accumulation within a play that is sufficiently well defined to present a viable drilling target. The prospective resources associated with the lower interval of the Montney formation across the Project area (with the exception of lower Montney properties in the Wapiti area that have been attributed development unclarified contingent resources by McDaniel) have been sub-classified as “lead” by McDaniel, which the COGE Handbook defines as a potential accumulation within a play that requires more data acquisition and/or evaluation in order to be classified as a prospect. The evaluation of the risks and the risking process relevant to the contingent resources and prospective resources estimates that are contained herein are described in the AIF, which is available on SEDAR at www.sedar.com. The reserves and resources estimates contained in this presentation should be reviewed in connection with the AIF, which contains important additional information regarding the independent reserve, contingent resource and prospective resource evaluations that were conducted by McDaniel and a description of, and important information about, the reserves and resources terms used in this presentation. Note Regarding Industry Metrics This presentation includes certain industry metrics, including barrels of oil equivalent (“boes”), which does not have a standardized meaning or standard method of calculation and therefore may not be comparable to similar measures used by other companies and should not be used to make comparisons. Unless otherwise specified, all production is reported
has adopted the standard of 6 Mcf:1 bbl when converting natural gas to oil
ratio of 1 bbl:1 bbl. Boes may be misleading, particularly if used in isolation. A boe conversion ratio of 6 Mcf:1 bbl is based roughly on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the company’s sales point. Given the value ratio based on the current price of oil as compared to natural gas and NGLs are significantly different from the energy equivalency of 6 Mcf: 1 bbl and 1 bbl: 1 bbl, respectively, utilizing a conversion ratio at 6 Mcf: 1 bbl for natural gas and 1 bbl :1 bbl for NGLs may be misleading as an indication
value. Note Regarding Development Area Forecast Economics and Type-Curves Type-curves were used to develop the development area forecast economics shown in this presentation. The type-curves were prepared by internal qualified reserves evaluators from 7G. For each of the type-curves, wells with significant deviation in completions technique, or that had mechanical issues
parent-child interactions between wells, were excluded from the analysis to avoid perceived outlier effects. Non- producing days were removed from the producing time plotted in the type-
constraints, parent-child well interactions, mechanical issues, expected downtime for concurrent operations, facility outages and gas processing shrink adjustment factors are then accounted for, but those assumptions and adjustments are not reflected in the type-curves themselves or in the forecast economics that have been provided in this presentation. All data reflected in the type-curves is raw wellhead data. Condensate rates have been adjusted downwards in the type-curves to account for assumed shrinkage due to entrainment of NGLs in the wellhead separator liquid, as directly measured. This correction is the result of an empirical equation based upon internal observations of sample data. Raw gas has not been adjusted and includes significant NGLs in the gas stream. The referenced type-curves were prepared using a combination of a statistical approaches to early-life production from the type-wells selected, matched to volumetric estimates attributable to properties in the Company’s Nest 1, Nest 2 (North, South, East, West) and Nest 3 areas, respectively, based upon the Company’s understanding of the geology and reservoir parameters at the time the type curves were developed. Early-life statistics use data from the Nest 1, Nest 2 (East) and Nest 3 type-wells, adjusted for stage count and lateral length on a producing rate versus time basis, a cumulative volume versus time basis, and a producing rate versus cumulative volume basis, to ensure a reasonable fit. For Nest 2 (North, South, West) recent high intensity completion wells were selected that are adjacent to undeveloped acreage, with no adjustment made for stage count
The Nest 1 type-curve that was referenced is the same type-curve that was provided in the prospectus filed in connection with the Company’s IPO. That type-curve is based upon production data from wells that were drilled in 2014 and prior years and reflects a 2,200 m lateral well length and a 28 stage, 120 tonnes of proppant per stage completion design, utilizing N2 foam as the fracturing fluid. 11 wells drilled in the upper and middle Montney formation provide the statistical basis for the Nest 1 type-curve. The various Nest 2 type-curves referenced were created in July 2018 based upon production data from the wells that are described below: These Nest 2 wells were used because they are considered to be reflective
interactions, unusually tight spacing, facility constraints, downtime and mechanical failures. Historical tonnage and stage counts may not be representative of go-forward completion designs. Nest 2 (South) type curve is based on production data from wells drilled in 2016-2017 that were landed at various depths in the top 125 m (average 67m) from the top of the Montney formation and utilized slickwater completions. Nest 2 (North) type curve is based on production data mostly from wells drilled in 2016-2017 with varying horizontal landing depths from 35m to 110m (average 79 m) from the top of the Montney formation and were completed with slickwater completions. Nest 2 (West) type curve is based on production data from wells completed in 2017 that were landed from 20m to 95m from the top of the Montney formation and were completed with slickwater completions. Type-wells in the Nest 2 (East) area were drilled in 2014 and 2015 using N2 foam as the fracturing fluid and were initially facility constrained. To develop the type-curve for the region, production rates from the unconstrained period of flow were extrapolated to create an estimated early flow profile, while taking into account cumulative production volumes, and then the results were compared to type-wells in the surrounding areas to ensure for consistency. The Nest 3 type-curve was created in the fourth quarter of 2017. It is based upon production data from wells that were drilled in 2017 and prior years and reflects a 2,500 m lateral well length and a 40 stage, 200 tonnes of proppant per stage completion design, utilizing slickwater as the fracturing
statistical basis for the Nest 3 type-curve.
63
IMPORTANT NOTICE
(Continued) The Company has opted to rely upon the type-curve forecasts that have been prepared by internal qualified reserves evaluators from 7G in this presentation, rather than the type-curves prepared by McDaniel because the internally generated type-curves are what the Company has used for capital budgeting and corporate planning purposes. Type-curves do not have any standardized preparation methodology or meaning and readers are cautioned that the type-curves and forecast development area economics shown in this presentation may not be comparable to similar information that is presented by other companies. Actual results may vary significantly from the Company’s forecasts and estimates. The Company’s oil, natural gas and NGL reserves, contingent resources and prospective resources, as at December 31, 2017, were evaluated by McDaniel in the McDaniel Reports. In the McDaniel Reports, McDaniel assigned proved plus probable reserves to approximately 53% of the Nest 1 sections evaluated; best estimate contingent resources to approximately 47% of the Nest 1 sections evaluated; proved plus probable reserves to approximately 88% of the Nest 2 sections evaluated; best estimate contingent resources to approximately 12% of the Nest 2 sections evaluated; proved plus probable reserves to approximately 54% of the Nest 3 sections evaluated; best estimate contingent resources to approximately 40% of the Nest 3 sections evaluated and best estimate prospective resources to approximately 5% of the Nest 3 sections evaluated. Note Regarding Potential Drilling Opportunities The references to drilling locations or potential drilling opportunities that are contained herein were prepared by internal qualified reserves evaluators from Seven Generations, as at December 31, 2017. Some of the locations have already been drilled as part of the Company’s 2018 development program. Of the 480 potential drilling locations or drilling opportunities that were estimated to be contained within the company’s Nest 1 area, as at December 31, 2017, 51% were attributed proved plus probable reserves and 49% were attributed best estimate contingent resources in the McDaniel Reports. The reduction from the previously noted 500 wells reflects wells drilled in 2018. Of the 615 potential drilling locations or drilling opportunities that were estimated to be contained within in the company’s Nest 2 area, as at December 31, 2017, 95% were attributed proved plus probable reserves and 5% were attributed best estimate contingent resources in the McDaniel
drilled in 2018. Of the 190 potential drilling locations or drilling opportunities that were estimated to be contained within in the company’s Nest 3 area, as at December 31, 2017, 69% were attributed proved plus probable reserves, 31% were attributed best estimate contingent resources in the McDaniel
For the purposes of estimating potential drilling locations or drilling
section and a lateral well lengths of 2,310 metres based upon industry practice and internal review. The anticipated well spacing and lateral well length is expected to change over time as technology and the Company’s understanding of the reservoir changes. For the purposes of the estimates, the Company has assumed that natural gas production will be delivered into the Alliance Pipeline or NGTL system and that liquids will be extracted at the Pembina Kakwa River plant, at 7G’s wholly-owned plants in Alberta and at Aux Sable’s facilities near Chicago, Illinois. The estimated drilling locations or drilling opportunities that do not have reserves, contingent resources or prospective resources attributed to them in the McDaniel Reports are based upon internal estimates and the evaluation of applicable geologic, seismic, engineering and reserves
identified drilling opportunities or drilling locations and there is no certainty that such locations will result in additional reserves, resources
wells, including the number and timing thereof will be dependent upon the availability of funding, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs, actual drilling results, additional reservoir information that is obtained, and other factors. While certain of the estimated undeveloped drilling locations have been de-risked by drilling existing wells in relative close proximity to such locations, many of the locations are further away from existing wells where management has less information about the characteristics of the reservoir and therefore there is more uncertainty as to whether wells will be drilled in such locations, and if wells are drilled in such locations there is more uncertainty that such wells will result in additional oil and natural gas reserves, resources
production. The competitor flow test and initial production history shown on the slide titled “Nest 1 Update – Enhanced Economics” has been obtained by 7G from public sources as at the date of this presentation. The information was provided to such public sources by 7G’s competitors and 7G is unable to confirm if the information is accurate or was provided in accordance with applicable regulatory requirements. All of the competitor wells referenced were drilled in the Montney formation. The information is considered to be relevant because the geology of properties owned by 7G are considered to be similar to the competitor properties that are referenced. Significant production or pressure decline was noted in the data for the flowtests and early production history, and pressure transient analysis and well test interpretation had not yet been carried out at the time the data was posted. As such, the information should be considered to be preliminary until further analysis and interpretation has been completed. The commingled vertical test referenced on the slide titled “Lower Montney Update” reflects a production test conducted by the Company in the Lower Montney formation. The full duration of the test was 5 days with 4.2 days of flowing hydrocarbons (water was produced for the first 1.2 days). The production information shown on the slide reflects the total aggregate volumes of hydrocarbons recovered during the production test. During the test a total of 11,436 bbls of load fluid was also recovered. Significant production and pressure decline was noted during the test and pressure transient analysis and well test interpretation has not been carried out. Such data should be considered to be preliminary until further analysis and interpretation has been completed. Oil and Gas Definitions “best estimate” is a classification of estimated resources described in the COGE Handbook, which is considered to be the best estimate of the quantity that will actually be recovered. It is equally likely that the actual quantities recovered will be greater or less than the best estimate. Resources in the best estimate case have a 50% probability that the actual quantities recovered will equal or exceed the estimate. “COGE Handbook” means the Canadian Oil and Gas Evaluation Handbook maintained by the Society of Petroleum Evaluation Engineers (Calgary Chapter), as amended from time to time. “contingent resources” are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more
environmental, social, political factors and regulatory matters, a lack of markets or a prolonged timetable for development. It is also appropriate to classify as contingent resources the estimated discovered recoverable quantities associated with a project in the early evaluation stage. “gross” means: (i) in relation to the Company’s interest in production, reserves, contingent resources or prospective resources, its “company gross” production, reserves, contingent resources
prospective resources, which are the Company’s working interest (operating or non-
royalty interests of the Company; (ii) in relation to wells, the total number of wells in which a company has an interest; and (iii) in relation to properties, the total area of properties in which the Company has an interest. “liquids” refers to oil, condensate and other NGLs. “net” means: (i) in relation to the Company’s interest in production or reserves, the Company’s working interest (operating or non-operating) share after deduction of royalty obligations, plus the Company’s royalty interest in production or reserves; (ii) in relation to the Company’s interest in wells, the number of wells obtained by aggregating the Company’s working interest in each of its gross wells; and (iii) in relation to the Company’s interest in a property, the total area in which the Company has an interest multiplied by the working interest owned by the Company. “probable reserves” are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves. “prospective resources” means quantities of petroleum estimated, as of a given date, to be potentially recoverable from undiscovered accumulations by application of future development projects. Prospective resources have both an associated chance of discovery and a chance of development.
64
IMPORTANT NOTICE
(Continued) “proved reserves” are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves. “reserves” are estimated remaining quantities of oil and natural gas and related substances anticipated to be recoverable from known accumulations, as of a given date, based on: (i) analysis of drilling, geological, geophysical and engineering data; (ii) the use of established technology; and (iii) specified economic conditions, which are generally accepted as being reasonable. Reserves are classified according to the degree of certainty associated with the estimates. “risked” means adjusted for the probability of loss or failure in accordance with the COGE Handbook. References in this presentation to “proved plus probable reserves”, “contingent resources” and “prospective resources”, refer to gross proved plus probable reserves, gross best estimate contingent resources and gross best estimate prospective resources, respectively. Further Economic Assumptions For Nest 1: NGL recoveries and shrinkage factors are based on the company’s best estimate of the liquids to be extracted at the Pembina Kakwa River Plant and at 7G’s wholly owned plants in Alberta, as well as the liquids to be processed by Aux Sable at its facilities near Chicago, Illinois pursuant to the terms of the rich gas premium agreement between 7G and Aux Sable, which depends upon an assumed heating value and has been assumed to extend for the entire productive life of the wells. For the Cretaceous: NGL recoveries and shrinkage factors are based on the company’s best estimate of the liquids to be extracted at 7G’s wholly
For a description of the methodology used and the assumptions made by the company in preparing the type-curve forecasts that were used to develop the forecast economics shown in the above table, and for important additional information regarding the type-curve forecasts and the estimated potential drilling opportunities that are reflected above, please see the “Note Regarding Development Area Forecast Economics and Type Curves” and the “Note Regarding Potential Drilling Opportunities” in the “Important Notice” at the end of this presentation. Nest 1 2018 estimates represents an average of Nest 1 Pads brought on- stream in 2018 The forecasts for Nest 1 shown reflect half-cycle economics and include
take into account certain other costs that would be required to construct infrastructure, including Super Pads, central processing facilities, regional gathering facilities, condensate stabilization facilities and
infrastructure, nor do they take into account land acquisition costs, corporate overhead (G&A) expenses, financing costs or corporate taxes. These forecast economics are intended to represent the marginal return of a single well investment on an existing Super Pad. No adjustments have been made for expected downtime or facility constraints, so the forecasts present an idealistic view of results that could be achieved in the absence
Actual results will differ from these forecasts for the reasons described above and because of the risks and risk factors that are described in the “Forward-Looking Information Advisory” in the “Important Notice” at the end
65
DEFINITIONS AND ABBREVIATIONS
A AECO AFF Alliance avg bbl or bbls B or bn Bcf Boe or BOE Btu C* °C CAD or C$ or $ CGR CG COGE Handbook CROIC C2 C3 C4 C5 or C5+ d D&C DCET Deep Southwest EBITDA E&P FX G&A G&G GJ GTN H1 H2 H2S HH or Hhub Hz IFRS IP IP IP 30 IP 60 IP80 or 94 or 96 IP 365 IPO IRR Km kpa LNG LGR LPG annual physical storage and trading hub for natural gas on the TransCanada Alberta transmission system adjusted funds flow Alliance pipeline average barrels or barrels billion billion cubic feet barrels of oil equivalent British thermal units Alberta drilling and completion cost allowance Degrees Celsius Canadian dollars condensate/gas ratio citygate the Canadian Oil and Gas Evaluation Handbook maintained by the Society of Petroleum Engineers (Calgary Chapter), as amended from time to time. cash return on invested capital ethane propane butane pentanes plus day drill and complete drill, complete and tie-in the “Deep Southwest” area that is shown in the map in this presentation earnings before interest, taxes, depreciation and amortization exploration & production foreign exchange rate general and administrative expense Geology and geophysics Gigajoule Gas Transmission Northwest LLC first half of the year second half of the year hydrogen sulfide Henry Hub Horizontal International financial reporting standards initial production initial production for the first 20 days initial production for the first 30 days initial production for the first 60 days initial production for the first 80 or 94 or 96 days initial production for the first 365 days initial public offering internal rate of return kilometres kilopascals liquefied natural gas liquid to gas ratio liquefied petroleum gas m Mbbl Mboe Mcf mcfe MM MMboe MMbtu MMcf mo N2 NAV NCIB ND Nest Nest 1 Nest 2 Nest 3 NGL NGPL NGTL NPV NYMEX OPEX PIR PP&E psi Q1 or 1Q Q2 or 2Q Q3 or 3Q Q4 or 4Q Rich Gas ROCE SEDAR sh Super Pad TCPL TSX TTM US USD or US$ Wapiti WCS WCSB WTI YE YTD Y/Y 2P $MM or MM$ metres thousand of barrels thousands of barrels of oil equivalent thousand cubic feet thousand cubic feet equivalent million million barrels of oil equivalent million British thermal units million cubic feet month Nitrogen net asset value normal course issuer bid net debt the Nest 1, Nest 2 and Nest 3 areas combined the “Nest 1” area that is shown in the map in this presentation the “Nest 2” area that is shown in the map in this presentation the “Nest 3” area that is shown in the map in this presentation natural gas liquids Natural Gas Pipeline Company of America pipeline system NOVA Gas Transmission Ltd. pipeline system net present value New York Mercantile Exchange
profit to investment ratio property, plant and equipment pounds per square inch first quarter of the year second quarter of the year third quarter of the year fourth quarter of the year the “Rich Gas” area that is shown in the map in this presentation return on capital employed System for Electronic Document Analysis and Retrieval share decentralized processing plants that separate field condensate and natural gas TransCanada Pipelines Toronto Stock Exchange Trailing twelve month United States United Stated dollars the “Wapiti” area that is shown in the map in this presentation Western Canadian Select Western Canadian Sedimentary Basin West Texas Intermediate year-end year to date year-over-year gross total proved plus probable reserves millions of dollars
TSX: VII
For more information:
Brian Newmarch
Vice President Capital Markets 1.403.767.0752 bnewmarch@7genergy.com
Ryan Galloway
Investor Relations Manager 1.403.718.0709 ryan.galloway@7genergy.com www.7genergy.com