november 2019 vii corporate presentation · 4/30/2017 · canada’s most valuable hydrocarbon...
TRANSCRIPT
TSX: VII
CORPORATE PRESENTATIONNovember 2019
SEVEN GENERATIONS ENERGY
2
• Differentiated attention to selection, development & replenishment of the lowest supply cost resource
• Best in class execution through safe, responsible, innovative and efficient development
• Maximizing profitability by proactively securing access to premium-priced markets
• Maintaining an unwavering focus on balance sheet strength
Serving our stakeholders through:
$1.37 billion adjusted funds flow (trailing twelve months)
1.6x trailing 12 month net debt to adjusted funds flow ratio
$1.3 billion current available funding(3)(4)
Financial Strength and Capital Discipline
3
(1) October 31, 2019 share price & shares outstanding as of September 30, 2019.(2) US$1.575B in senior unsecured notes converted at $1.3164 CAD/USD plus adjusted net working capital deficiency as of September 30, 2019 of $128 MM.(3) Figures may not add due to rounding.(4) For additional information see “Non-IFRS Measures Advisory” and “Other Definitions” in the “Important Notice” that appears at the end of the presentation.
7G CORPORATE PROFILE
Premier Alberta Montney Pure-Play
TSX:VII Capitalization and Q3 2019 Financial Highlights
Market Cap(1) $2.5 billionShare CountBasic(1)
341 million
Net Debt(2) $2.2 billionAdjusted Funds Flowper Diluted Share(4)
$0.98
Enterprise Value(3) $4.7 billionAdjusted Funds Flow ($/boe)(4)
$18.09
205 Mboe/d (37% condensate, 21% NGL, 42% gas) in Q3/19
Multiple market exposures provide maximum gas price optionality
Largest Producer of Condensate,
Canada’s Most Valuable Hydrocarbon
Top-tier assets located near demand centers,
multiple pipeline routes, and future LNG optionality
Over 15 years of premium inventory, with future upside
Sustaining capital requirements of $1 billion, trending lower
Best-in-class GHGe emissions
A Sustainable,
Free Cash Flow Generating Business Model(4)
7.9% return on capital employed (ROCE)(4)
14.1% cash return on invested capital (CROIC)(4)
$1.79 per share of net income
Generating Meaningful Returns(Trailing 12 Month)
Value Creation
• Economic growth in per-share production, cash flow and free cash flow
Shareholder Focus
• Cash flow upside from higher prices benefits shareholders
Consistency
• Commitment to execution, stakeholder service and responsible development
Resiliency
• Cost and operating efficiencies, optimization and naturally moderating decline rates
Budget Objectives:
4
1) For additional information, see “Forward Looking Information Advisory” and “Non-IFRS Measures Advisory” in the “Important Notice” at the end of this presentation
2020 BUDGET - SETTING THE STAGE
5
7G’s business becomes more resilient and expands free cash flow potential
NEAR TERM DEVELOPMENT GOALS
1) For additional information, see “Forward Looking Information Advisory” and “Non-IFRS Measures Advisory” in the “Important Notice” at the end of this presentation.
2019 2020 2021+
• Sub-40% corporate decline
• Sub-US$45 WTI break-even
• Significant free cash flow at $45+ WTI
Corporate
Core
Areas
New
Areas
Evaluate NCIB allocation
Moderate corporate decline
Free cash flow above US$50 WTI
Land swap efficiencies
Integrate Nest 3 development
Define Nest 1 perimeter
Full triple-stack
Assess lower Montney areal extent
• Advance integrated lower Montney development
• Potentially high-grade perimeter areas
• Nest 1 development
• Step into Nest 2 East
• Nest 3 resource to fill infrastructure
• Further reduce decline rate
• Reduced WTI break-even
• Significant free cash flow potential at $50+ WTI
• Balanced Nest developmentacross all 3 layers
• Optimize Nest 1 / Nest 2 boundaries
2020 CAPITAL BUDGET & GUIDANCE
6
$1.1
billion
2020 Capital Budget & Guidance
Sustaining Capital(1) $1.0 billion
Discretionary Capital(2) $0.1 billion
Total Capital Investment $1.1 billion
Average Production 200 - 205 Mboe/d
H1/20 Production 190 - 200 Mboe/d
H2/20 Production 205 - 215 Mboe/d
Development Wells On Stream (#) 75 - 80
Percent Liquids 56 - 60%
Percent Condensate 34 - 38%
Royalty Rate at US$50 WTI 5 - 7%
Royalty Rate at US$60 WTI 7 - 9%
Operating Expenses ($/boe) $4.75 - $5.25
Transportation ($/boe) $6.75 - $7.25
G&A ($/boe) $0.85 - $0.95
Interest ($/boe) $1.80 - $1.90
Completions
Drilling
Equip &
Tie-in
OtherValue
Enhancing
Delineation
Pads &
Pipes
• Organically funded at $50 WTI / $2.50 Henry Hub
• Commodity price upside benefits shareholders in the form
of accelerated buyback / net debt reduction
• Value enhancements improve future condensate pricing
• Sustaining capital continues to trend lower
1) Sustaining capital refers to capital expenditures including drilling, completions, equipping, tie-in and other expenditures required to maintain production from existing facilities at current levels. 2) Discretionary capital refers to capital expenditures that are not required to maintain production from existing facilities at current levels, including but not limited to delineation, infrastructure,
value-enhancing projects, and production growth3) For additional information, see “Forward-Looking Information Advisory” and “Other Definitions” in the “Important Notice” at the end of this presentation.
SustainingSustaining
Sustaining
Growth
Major Infra
Delineation
Delineation
Delineation
Value Enhancing
Value Enhancing
Value Enhancing
$40 WTI
$50 WTI
$60 WTI
$70 WTI
$0
$200
$400
$600
$800
$1,000
$1,200
$1,400
$1,600
$1,800
2018 Actual 2019 Budget 2020 Budget 2021 Budget 2022 Budget Adjusted FundsFlow Sensitivity
2020 CAPITAL ALLOCATION GUIDING PRINCIPLES
7
1) E&P adjusted funds flow reflects US$2.50/MMbtu Henry Hub, US$5/bbl condensate differentials. 2) For additional information, see “Forward-Looking Information Advisory”, “Non-IFRS Measures Advisory” and “Other Definitions” in the “Important Notice” at the end of
this presentation.3) Sustaining capital refers to capital expenditures including drilling, completions, equipping, tie-in and other expenditures required to maintain production from existing
facilities at current levels.
Free cash flow growth trajectory on track
Dollars ($MM)
Reduced break-even costs
and FCF growth
even with low prices
Strong
balance sheet
Large, high quality asset base
Location/access to infrastructure
Control/flexibility
Skilled and knowledgeable staff
THE CORNERSTONES OF OUR BUSINESS
8
7G’s strategic principles drive value creation
Resource
Quality &
Low Supply
Cost
Market
Access
Free Cash
Flow
Stakeholder
Service
Return on
Capital
Financial
Sustainability
Return of
Capital
Strategic Principles
STRATEGIC PRINCIPLES: FINANCIAL SUSTAINABILITY
9
Balance sheet strength is core to 7G’s business
2.4x
2.1x
1.5x1.3x 1.4x
0.9x
2015 2016 2017 2018 2019E 2020E
Historical US$70 WTI US$60 WTI US$50 WTI
Net debt to trailing 12 month adjusted EBITDA
6.75% NotesUS$425MM
6.875% NotesUS$450MM
5.375% NotesUS$700MM
2020 2021 2022 2023 2024 2025
Long maturities with fixed coupons
3.5 Years to Next
Maturity
1.6x
1.2x
1) For additional information, see “Forward-Looking Information Advisory” and “Non-IFRS Measures Advisory” in the “Important Notice” at the end of this presentation.
2023 is earliest senior
unsecured note maturity
Long term note maturities
$1.3B available on $1.4B facility
C$0.3B accordion
2023 maturity
$1.6B of liquidity
Leverage is
below 2x at US$50 WTI
Solid Balance Sheet
10
(1) Non-IFRS financial measures. For additional information see “Non-IFRS Measures Advisory” and “Forward-Looking Information Advisory” in the “Important Notice”that appears at the end of the presentation.
(2) Subsectors based on SPDR Select Indices: XLK, XLY, XLI, XLP, XLB, XLV, XLC, XLF, XLE, XLU, XLRE, and iShares XEG (TSX Capped Energy).(3) Montney firms include: AAV, ARX, BIR, CR, ECA, KEL, NVA, PIPE, PONY, POU, TOU.
7G’S TRACK RECORD OF INDUSTRY LEADING RETURNS
Top Quartile Returns vs North American Sectors2018 EBITDA / Total Average Capital (2) (3) (4)
17.4%16.4%
17.9%19.1%
2015 2016 2017 2018
7G Cash Return on Invested Capital(CROIC)(2)
30%27% 27%
25% 25%
20% 19% 19% 18% 18%16% 14%
12%10%
Tech Cons.Disc.
VII Industrials Staples Materials Healthcare Comms. Financials USEnergy
CDNEnergy
MontneyFirms (4)
Utilities RealEstate
Source: Bloomberg
11(1) 2020 full-year budgeted assumptions include US$50/bbl WTI, US$2.50/MMbtu Henry Hub, US$5/bbl condensate differentials. Adjusted funds flow and free cash flow shown above use
the same assumptions with $60/bbl WTI price. (2) For additional information see “Forward-Looking Information Advisory” and “Non-IFRS Measures Advisory” in the “Important Notice” that appears at the end of the presentation.
Free cash flow growth via decline moderation and reduced facilities investment drives future capital allocation optionality
7G’S STRATEGIC EVOLUTION TOWARD FREE CASH FLOW (1)(2)(3)
0%
50%
100%
150%
200%
250%
300%
350%
2014 2015 2016 2017 2018 2019E 2020E
Total Capital
Facilities Capital
-$1,000
-$600
-$200
$200
2014 2015 2016 2017 2018 2019E 2020E
Capital InvestmentsAs a Percentage of Adjusted Funds Flow
Free Cash Flow (2) (3)
($MM)
Nearly $300 MM free cash
flow potential between
$50-$60/bbl WTI
Facilities capital intensity
continues to fall across a
$50-$60/bbl environment
12
1) Marty Proctor, Chief Executive Officer, is the only non-independent director.2) Based upon 2017 data. For additional information regarding the company’s estimated carbon intensity, please refer to “Note Regarding Industry Metrics” in
the “Important Notice” at the end of this presentation. Peers include ARX, BTE, CPG, HSE, SU, VET.3) The peer companies in the Liability Management Rating chart include ARX, BIR, CNQ, CVE, CPG, ECA, ERF, HSE, MEG, PEY, TOU, VET, WCP.
Responsible development across all aspects of 7G’s business
STRATEGIC PRINCIPLES: STAKEHOLDER SERVICE
Environment SocialGovernance
• Independent Board Chair
• 9 of 10 Independent Directors(1)
• 100% Board attendance in 2018
• Diverse Board and Management
• Improving ESG ratings reflect
commitment to sustainability
0.0
0.5
1.0
1.5
2014 2015 2016 2017 2018 2019YTD
A Low GHGe Footprint vs Peers (2)
• 85,000 truck loads of water eliminated
due to investments in disposal and
water handling
0
20
40
Peer
1
Peer
2
Peer
3
Peer
4
Peer
5
Peer
6
Peer
7
Peer
8
Peer
9
Peer
10
Peer
11
Peer
12
Peer
13
VII
0.00
0.05
0.10
VII Peer1
Peer2
Peer3
Peer4
Peer5
Peer6
Best in Class Environmental Liability
Management (3)• Over $2.3B of capital, operating and
royalty contributions in 2018,
supporting economic activity in
Western Canada
• Community partner actively engaging
local stakeholders
• >5,000 hours of employee
volunteerism, from ~200 staff
Total Recordable Incident Frequency
LM
RT
on
nes o
f C
O2e / b
oe
Practices That Drive Diversity,
Accountability and Effective Oversight
An
nu
al
Rate
per
100
Fu
ll-T
ime E
mp
loyees
13
1) All figures based on ISS QualityScore ratings, with 1 being the most favorable rating and 10 being the least favorable. 2018 figures are effective December 1, 2018. 2019 Figures are effective November 1, 2019. Figures are calculated relative to a selection of peers determined by ISS.
7G actively measures and improves upon its ESG performance
STRATEGIC PRINCIPLES: STAKEHOLDER SERVICE – ESG PERFORMANCE
2019 2018 2019 2018 2019 2018
Environment 2 3 Social 2 6 Governance 2 3
Risks and
Opportunities3 8 Human Rights 3 4 Board Structure 2 3
Carbon and
Climate2 2
Labor, Health
and Safety1 7 Compensation 3 4
Natural
Resources1 3
Stakeholders
and Society2 6
Shareholder
Rights3 3
Waste and
Toxicity2 5
Product Safety,
Quality and
Brand
N/A N/A Audit 1 2
STRATEGIC PRINCIPLES: HIGH QUALITY RESOURCE
141) For additional information, see “Forward-Looking Information Advisory” and “Note Regarding Potential Drilling Opportunities” in the “Important Notice” at the end
of this presentation.
Natural Gas Processing:
• ~1 Bcf/d capacity
• 510 MMcf/d owned &
operated at Cutbank/Lator
• 250 MMcf/d owned &
operated at Gold Creek
• 250 MMcf/d of 3rd party
capacity access
Condensate Stabilization:
• >80 Mbbl/d capacity
• >60 Mbbl/d owned &
operated
• Access 3rd party capacity of
up to 20 Mbbl/d
Infrastructure Footprint
Canada’s largest producer
of high-value condensate
Nest IRRs average 125%
at US$55 WTI / US$3 Hub
Most Economic
Resource in Canada
Nest upper/middle
Montney: 15+ years
Decades of lower Montney,
Wapiti & Rich Gas future
drilling opportunities
Deep Inventory
with Further Upside
750 MMcf/d of owned
gas processing capacity
Cost & Operating
Advantage
STRATEGIC PRINCIPLES: MARKET ACCESS FOR NATURAL GAS
15 1) 2018 average benchmark prices sourced from Bloomberg.
Premium revenue stream enhances 7G’s profitability
Revenue Mix
Condensate
NGL
Natural Gas
Chicago49% Chicago
41%Chicago
38%
Gulf 24%
Gulf 26%Gulf 24%
Malin 13% Malin 18%
Dawn 15%Dawn 15% Dawn 14%
AECO 10% AECO 5% AECO 5%
2019 2020 2021
7G Gas Market Sales Points
NGPL:
155 MMcf/d
Alliance:
500 MMcf/d
TCPL:
77 MMcf/d
GTN:
90 MMcf/d
$0.00
$1.00
$2.00
$3.00
Chicago Gulf Malin Dawn AECO
2019 YTD Benchmark Prices (US$/MMbtu)
100
200
300
400
2017 2018 2019E 2020E 2021E
STRATEGIC PRINCIPLES: MARKET ACCESS FOR CONDENSATE
16
1) Source: Bloomberg, COLC, NEB and 7G internal forecasts.2) Source: Bloomberg.3) 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
WCSB Supply
Total Demand
Condensate Import
Capacity = 275 Mbbl/d
Implied Condensate Imports Required to Meet Demand (Mbbl/d)(3)
• Condensate is Canada’s premium liquids product
• Total demand of ~650 Mbbl/d exceeds local supply by
~250 Mbbl/d
• Canadian condensate continues to price in a range
similar to US WTI and Midland streams
Edmonton Condensate vs. Crude Oil Prices (US$/bbl)(2)Forecast Supply & Demand of WCSB Condensate (Mbbl/d)(1)(3)
Rail imports
potentially set future
marginal price
200
400
600
800~250 Mbbl/d+
gap between
supply & demand
$10
$20
$30
$40
$50
$60
$70
$80
2015 2016 2017 2018 2019
WTI Oil Edm. Light
Midland Oil WCS Heavy Oil
Edm. Condensate
LOWER MONTNEY – EMERGING DEVELOPMENT POTENTIAL
17
Partial triple-stack
IP90: 1,048 boe/d
72% condensate
Successful
vertical test
Triple-Stack Development
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.2) Assumes $11 MM in U/M DCET costs. $50 MM of super-pad and associated shared surface costs, $500k drilling savings on lower Montney, with 30% reduced well productivity.
Illustration not to scale
2,8
00-3
,000
mete
rs
200
metr
es
800 metres
Upper Montney
Middle Montney
Lower Montney
Partial triple-stack
IP30: 1,250 boe/d
63% condensate
Illustrative Economic Uplift Potential
Upper & Middle
Montney
Lower
Montney
Triple
StackΔ%
Wells (#) 24 12 36 +50%
DCET ($MM) $265 $126 $390 +47%
Full Cycle
Capex($MM) $315 $126 $440 +40%
NPV ($MM) $290 $85 $375 +30%
Capital
Efficiency($/boe/d) $12,200 $13,900 $12,500 -2%
Full triple-stack
IP60: 1,520 boe/d
67% condensate
(3-well average)
• Up to 50% more inventory per section
• 30% increased NPV per section
• Similar full-cycle capital efficiency (prior to optimization)
Potential Benefits
Partial triple-stack
IP30: 2,280 boe/d
31% condensate
NEST 3 DEVELOPMENT – NEW HIGH DELIVERABILITY REGION
18
New premium development area gaining momentum
• Up-front capital investment enabled future
cost-effective development
• Hub & spoke model reduces super-pad investment
and surface-related capital
• Ultimate capacity of 30,000 – 40,000 boe/d
1) For additional information, see “Forward-Looking Information Advisory”, and “Note Regarding Development Area Forecast Economics and Type-Curves” in the “Important Notice” at the end of this presentation.
2) Capital efficiency represents total drilling, completion, equipping and tie-in costs divided by total average first-year daily production on a boe basis.
2019 Development 2020+
• Sub-$8,000/boe/d drill, complete, equip and tie-in
capital efficiency (2)
• Limited drill-to-fill capital
• Potential to expand boundaries
• Significant commodity optionality
0
20
40
60
80
100
120
0 30 60 90 120 150 180
2018 Curve Latest Nest 3 Actuals
Cumulative condensate (Mbbl) vs. time (days)
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
Nest 1 2019 Activity
7G IP60 (Restricted Rates)
~1,898 boe/d
72% condensate
NEST 1 DEVELOPMENT – ULTRA-RICH CONDENSATE REGION
19
1) The following pricing assumptions were used to develop the economic forecasts shown above: US$55.00 US/bbl WTI, US$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 = $20,000/mo.
2) For additional information, see “Forward-Looking Information Advisory”, “Further Economic Assumptions”, “Note Regarding Development Area Forecast Economics and Type Curves” and “Note Regarding Potential Drilling Opportunities” in the “Important Notice” at the end of this presentation.
Impressive new results, development planned for 2020+
Key StatsNest 1
(2014
Estimates)
Nest 1
(2018
Estimates)
IP30 (boe/d) 1,250 1,500
IP365 (boe/d) 675 775
DCET Cost ($MM) $9.5 $11
IP365 CGR (bbls/MMcf) 135 478
IRR (%) 29% 83%
NPV ($MM) $2.3 $6.7
Competitor wells
0
50
100
150
200
250
300
0 90 180 270 360
2014 Curve Nest 1 Actuals
Cumulative condensate (Mbbl) vs. time (days)
Enhanced completions have
improved well results
20
SUMMARY OF PREMIUM SINGLE WELL ECONOMICS & OTHER INVENTORY
Core Nest
Development InventoryNest 1
Nest 2
Nest 3Weighted
AverageSouth East West North
IP30 (boe/d) 1,500 1,950 - 2,350 2,000 1,900
IP365 (boe/d) 775 1,150 - 1,650 1,400 1,125
DCET Cost ($MM) $11 $10.5 - $11.5 $11 $11
IP365 CGR (bbls/MMcf) 478 90 160 170 295 55 280
IRR (%) 83% 85% 150% >250% 215% 62% 125%
NPV ($MM) $6.7 $6.4 $11.5 $16.0 $12 $6.4 $8.9
PIR (x) 0.6 0.6 1.0 1.5 1.1 0.6 0.8
Locations (#) 480 90 170 75 280 190 1,285
1) For additional information, see “Forward-Looking Information Advisory” and “Note Regarding Potential Drilling Opportunities”, “Note Regarding Development Area Forecast Economics and Type-Curves” and “Further Economic Assumptions” in the “Important Notice” at the end of this presentation. Inventory counts and economics are based on year-end 2018 estimates.
2) PIRs reflect the NPVs divided by the DCET Costs (taken as the midpoint where ranges are provided).
Future Development
OpportunitiesNest Area
Lower MontneyCretaceous Wapiti Rich Gas Total
Undeveloped
2P Reserve
Locations
(#) 7 0 68 0 75
Contingent (2C)
Resource
Locations
(#) >170 >60 >250 >100 >730
>25 Years
of Potential Inventory
Including Development
Outside the Montney
Core
>15 years
Tier 1 Nest
Development
Inventory
High-impact
upside
Opportunistic
development
Longer-term delineation
Potentially expand boundaries
of Nest 2 West and Nest 3
THE 7G INVESTMENT THESIS
21
Diverse marketing and price differentiation• Strong netbacks
• Diversified natural gas exposures
Delivering operating excellence• Execution, optimization and cost control
• Consistent results
Expanding free cash flow• Moderating declines reduce sustaining capital
• Major gas processing investments completed
High quality resource and deep organic inventory• 15+ years of inventory within core area
• Delineation is expanding premium inventory
Financial strength, flexibility & liquidity• Conservative use of leverage
• Ample liquidity
TSX: VII
APPENDIX
23
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
operate an energy project, can be granted and taken away by society. Over the longer term, companies can only expect to thrive if they
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
of present and future generations;
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
of new policy that enables our company and our industry
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.
Nest 2Development
Nest 1 & 3 Development
Infrastructure
Delineation
Value Enhancing
2019 BUDGET
24
$1.25
billion
2019 Guidance
Sustaining Capital(1) $1.1 billion
Discretionary Capital(2) $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 On Stream (#) 65 - 70
Percent Liquids 58 - 60%
Royalty Rate at US$50 WTI 5 - 7%
Royalty Rate at US$60 WTI 7 - 9%
Operating Expenses ($/boe) $5.00 - $5.25
Transportation ($/boe) $6.75 - $7.25
G&A ($/boe) $0.80 - $0.90
Interest ($/boe) $1.80 - $1.90
• Maintains corporate production
• Core Nest 2 development & Nest 1 tie-ins
• New Nest 3 development
• Enables Larger Nest 3 Development
• ~$160 MM initial infrastructure build
• ~$130 MM is non-repeating infrastructure
• Trends lower over time with decline mitigation
• Delineation to enhance the value of:
• Lower Montney
• Nest 1 Perimeter
• Rich Gas boundary / Wapiti
• Strategic infrastructure:
• Water handling to reduce operating costs
• Compression to optimize well productivity
Sustaining Capital
$150 MM Discretionary Capital$1.1 B Sustaining Capital
1) Sustaining capital refers to capital expenditures including drilling, completions, equipping, tie-in and other expenditures required to maintain production from existing facilities at current levels. 2) Discretionary capital refers to capital expenditures that are not required to maintain production from existing facilities at current levels, including but not limited to delineation, infrastructure,
value-enhancing projects, and production growth3) For additional information, see “Forward-Looking Information Advisory” and “Other Definitions” in the “Important Notice” at the end of this presentation.
-$4.00
$0.00
$4.00
$8.00
$12.00
$20
$30
$40
$50
$60
Hedging Gains/Losses ($/boe) Revenue with Hedges ($/boe) Revenue ($/boe)
HEDGING STRATEGY
25
Quarterly Revenue ($/boe)
C$62-$78
/bbl
C$65-$77
/bbl
Hedging program has
reduced revenue
volatility by ~25%
Objectives:
- Reduce revenue volatility
- Protect capital program
- Preserve balance sheet
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 next slide in this 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.
Pri
ce
Rea
liza
tio
n (
$/b
oe
)R
ea
lize
d H
ed
ge
Ga
in/(L
oss
) ($b
/oe
)
Crude Oil
bbl/d bbl/d C$/bbl bbl/d bbl/d US$/bbl
RoY 2019 16,000 $58.13 $74.90 2,000 $40.00 23,000 $58.64 $61.85 2,000 $40.00
2020 8,500 $57.06 $71.50 1,500 $40.00 19,750 $54.13 $59.11 3,750 $40.00
2021 0 $0.00 $0.00 0 $0.00 7,000 $53.85 $59.09 1,750 $40.00
2022 0 $0.00 $0.00 0 $0.00 1,250 $52.31 $52.31 0 $0.00
Natural Gas
MMbtu/d MMbtu/d US$/MMbtu
RoY 2019 90,000 $2.89 $3.02 10,000 $2.50
2020 102,500 $2.70 $2.84 0 $0.00
2021 42,500 $2.62 $2.96 0 $0.00
2022 5,000 $2.58 $3.05 0 $0.00
Natural Gas
Basis Markets MMbtu/d US$/MMbtu MMbtu/d US$/MMbtu GJ/d
RoY 2019 80,000 $2.83 10,000 -$0.23 60,000 $2.44 $2.85
2020 32,500 $2.74 55,000 -$0.21 10,000 $2.13 $2.13
2021 0 $0.00 52,500 -$0.17 0 $0.00 $0.00
2022 0 $0.00 12,500 -$0.08 0 $0.00 $0.00
.
Foreign Exchange
Notional
(US$MM)
RoY 2019 $56.0 1.2954 1.3027
2020 $292.6 1.2934 1.3039
2021 $179.6 1.2969 1.3114
2022 $30.4 1.3117 1.3298
Note: Swaps are treated as collars with puts and calls with same strike price.
USD WTI Sold Puts
US$/bbl
AECO 7A Swaps & Collars
C$/GJ
Chicago Basis Swaps
USD WTI Swaps and Collars
Chicago CG Swaps
C$/US$
C$/bbl
CAD WTI Collars CAD WTI Sold Puts
NYMEX HH Swaps & Collars
US$/MMbtu
NYMEX HH Sold Puts
FX Swaps & Collars
CURRENT HEDGE POSITIONS – AS AT SEPTEMBER 30, 2019
26
SELECTED FINANCIAL AND OPERATIONAL INFORMATION
27
VII - Recent Quarterly ResultsOPERATING RESULTS Q3 2019 Q2 2019 Q1 2019 Q4 2018 Q3 2018 Q2 2018 Q1 2018 Q4 2017 Q3 2017 Q2 2017 Q1 2017 YE 2018 YE 2017
Average daily production
Condensate (1) (mbbl/d) 75.5 75.9 72.7 81.8 87.3 69.0 67.3 70.0 64.5 59.0 51.6 76.4 61.3
Natural gas (MMcf/d) 515.3 489.6 483.6 515.4 511.3 461.3 473.3 493.4 453.2 409.6 384.5 490.5 435.5
NGLs (1) (mbbl/d) 43.2 44.3 44.1 47.4 47.3 41.2 41.5 45.1 43.9 37.9 37.4 44.4 41.1
Total (mboe/d) 204.6 201.8 197.4 215.1 219.8 187.1 187.7 197.3 183.9 165.2 153.1 202.6 175.0
CGR Ratio 147 155 150 155 175 150 142 142 142 144 134 156 141
LGR Ratio 84 90 91 92 93 89 88 91 97 93 97 91 94
Realized Prices
Condensate (1) ($/bbl) 65.59 71.91 63.00 53.57 79.26 81.67 73.39 67.95 54.95 58.28 63.84 71.63 61.28
Natural gas ($/Mcf) 2.85 3.29 4.32 4.77 3.65 3.79 3.54 3.53 3.46 4.09 4.36 3.98 3.84
NGLs (1) ($/bbl) 2.74 4.19 7.46 8.44 14.02 13.39 13.33 18.30 15.18 11.45 12.45 12.21 14.56
31.97 35.95 35.44 33.66 42.99 42.42 38.19 37.13 31.43 33.58 35.52 39.33 34.45
FINANCIAL RESULTS (4)
Condensate (1) ($MM) 455.6 496.7 412.2 403.2 636.6 512.8 444.5 437.6 326.1 312.9 296.5 1,997.3 1,371.1
Natural gas ($MM) 135.3 146.6 187.9 225.7 171.8 159.2 156.1 160.3 144.2 152.4 150.8 712.6 610.3
NGLs (1) ($MM) 10.9 16.9 29.6 36.8 61.0 50.2 49.8 76.0 61.3 39.5 42.1 197.8 218.3
Liquids and natural gas sales (2) ($MM) 601.8 660.2 629.7 665.7 869.4 722.2 650.4 673.9 531.6 504.8 489.4 2,907.7 2,199.7
Royalties ($MM) (37.5) (40.2) (40.9) (19.5) (44.4) (16.4) (18.9) (21.5) (14.5) (9.3) (16.8) (99.2) (62.1)
Operating expense ($MM) (90.6) (91.8) (87.5) (103.8) (105.5) (102.2) (96.8) (103.3) (91.8) (93.9) (68.8) (408.3) (357.8)
Transportation, processing and other expense ($MM) (121.6) (121.9) (118.1) (139.9) (124.2) (118.0) (109.7) (116.8) (109.4) (88.3) (74.3) (491.8) (388.8)
Operating netback before the following (3) ($MM) 352.1 406.3 383.2 402.5 595.3 485.6 425.0 432.3 315.9 313.3 329.5 1,908.4 1,391.0
Realized hedging gain (loss) ($MM) 30.6 0.8 (6.0) (31.2) (36.2) (17.7) (13.1) 6.9 14.2 1.8 (7.2) (98.2) 15.7
Marketing Income (3)(5) ($MM) 3.6 1.3 13.6 3.9 5.7 9.1 10.0 11.8 4.6 6.3 2.3 28.7 25.0
Operating netback (3) ($MM) 386.3 408.4 390.8 375.2 564.8 477.0 421.9 451.0 334.7 321.4 324.6 1,838.9 1,431.7
Adjusted funds flow (3) ($MM) 340.6 355.0 338.5 337.4 522.0 434.0 380.8 403.8 284.3 268.1 272.1 1,674.2 1,228.3
Cash provided by operating activities ($MM) 320.4 422.1 259.3 410.1 536.9 425.2 424.1 310.3 314.1 193.9 336.0 1,796.3 1,154.3
Revenue (6) ($MM) 718.0 795.5 546.3 1,146.8 809.0 560.4 653.7 652.3 563.7 608.8 629.8 3,169.9 2,454.6
Net Income (loss) ($MM) 85.1 295.3 10.8 245.4 196.4 (24.6) 22.7 83.1 85.7 178.1 215.6 439.9 562.5
Netbacks (4)
Liquids and natural gas sales ($/boe) 31.97 35.95 35.44 33.66 42.99 42.42 38.19 37.13 31.43 33.58 35.52 39.33 34.45
Royalties ($/boe) (1.99) (2.19) (2.30) (0.99) (2.20) (0.96) (1.12) (1.18) (0.86) (0.62) (1.22) (1.34) (0.97)
Operating expense ($/boe) (4.81) (5.00) (4.93) (5.25) (5.22) (6.00) (5.73) (5.69) (5.43) (6.24) (4.99) (5.52) (5.60)
Transportation, processing and other expense ($/boe) (6.46) (6.64) (6.65) (7.07) (6.14) (6.93) (6.24) (6.43) (6.47) (5.88) (5.39) (6.65) (6.09)
Operating netback before the following (3) ($/boe) 18.71 22.12 21.56 20.35 29.43 28.53 25.10 23.83 18.67 20.84 23.92 25.82 21.79
Realized hedging gain (loss) ($/boe) 1.63 0.04 (0.34) (1.58) (1.79) (1.04) (0.78) 0.38 0.84 0.12 (0.52) (1.33) 0.25
Marketing Income (3)(5) ($/boe) 0.19 0.07 0.77 0.20 0.28 0.53 0.62 0.65 0.27 0.43 0.17 0.39 0.39
Operating netback (3) ($/boe) 20.53 22.23 21.99 18.97 27.92 28.02 24.94 24.86 19.78 21.39 23.57 24.88 22.43
General and administrative expense ($/boe) (0.84) (0.85) (0.94) (0.91) (0.66) (0.82) (0.65) (0.65) (0.65) (0.82) (0.79) (0.76) (0.72)
Finance expense and other ($/boe) (1.60) (2.05) (2.00) (1.00) (1.45) (1.71) (1.75) (1.95) (2.33) (2.74) (3.03) (1.47) (2.48)
Adjusted funds flow per boe (3) ($/boe) 18.09 19.33 19.05 17.06 25.81 25.49 22.54 22.25 16.80 17.83 19.75 22.65 19.23
Capital investments
Drilling and completions ($MM) 171.0 172.9 231.4 148.9 232.6 335.9 319.6 167.4 252.8 342.3 259.4 1,037.0 1,021.9
Facilities and infrastructure ($MM) 76.9 119.5 132.2 67.7 90.8 179.3 207.0 115.0 176.5 153.9 85.2 544.8 530.6
Land and other ($MM) 36.7 18.7 37.3 45.7 34.8 47.4 56.0 39.9 25.0 16.3 17.7 183.9 98.9
Total capital investments ($MM) 284.6 311.1 400.9 262.3 358.2 562.6 582.6 322.3 454.3 512.5 362.3 1,765.7 1,651.4
(1) Starting in 2018, 7G began presenting C5+ in the NGL mix as a condensate volume (previously reported as an NGL volume). 2017 figures have been adjusted to conform to this current period presentation.
(2) Excludes the purchase and resale of liquids and natural gas in respect of transportation commitment optimization and marketing activities. Refer to the Q3 2019 MD&A as filed on SEDAR for additional information.
(3) For additional information, see "Non-IFRS Measures Advisory" in the "Important Notice" at the end of this presentation.
(4) Certain prior period figures have been re-classified to conform with current period presentation.
(5) The marketing income of the purchase and resale of liquids and natural gas, net of applicable pipeline tariffs, represent the margins earned in respect of the Company's transportation optimization and marketing activities.
(6) Represents the total of liquids and natural gas sales, net of royalties, gains (losses) on risk management contracts and other income.
SWEET SPOT IN THE MONTNEY
281) Sources: Canadian Discovery Ltd. & Graham Davies Geological Consultants Ltd. (2008, 2011), & Steven Burnie (2011), BC Ministry of Energy & Mines, Alberta Geological
Survey (modified by RBC & 7G) Lands as of 4/30/17.
Thickness→ Large Resources in Place
Over Pressured→ High Productivity Brittle Rock→ High Recovery Factor
Lower Temperature→ High Liquids Content
29
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 presentation. Without
limitation, prospective investors should read the 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 the media about
Seven Generations, should not be relied upon. In this presentation, unless
otherwise indicated, all dollar amounts are expressed in Canadian dollars, 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 investors.
Seven Generations’ business is subject to the risks normally 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 of development. An
investment in the Company’s securities is suitable only 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
“available funding”, “adjusted funds flow per diluted share”, “adjusted funds flow
per boe”, “operating netback” (also referred to herein as “netback”), “adjusted
EBITDA”, “return on capital employed” (or “ROCE”), “EBITDA”, “adjusted
working capital”, “marketing income”, “cash return on invested capital” (or
“CROIC”), “capital efficiency” and “free cash flow”, 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 other companies
without also taking into account any differences in the way that the calculations
were prepared. For further details about “available funding”, “adjusted funds
flow per boe”, “operating netback”, “adjusted EBITDA”, “return on capital
employed” (or “ROCE”), “adjusted working capital”, “marketing income”, “cash
return on invested capital” (or “CROIC”) and reconciliations between these
measures and the most directly comparable measures under IFRS, see “Non-
IFRS Financial Measures” in the Company’s Management’s Discussion and
Analysis dated November 6, 2019, for the three and nine months ended
September 30, 2019 and 2018, which is available on the SEDAR website at
www.sedar.com.
The 2018 EBITDA figure ($1,815 million) that is referenced for 7G on the slide
titled “7G’s Track Record of Industry Leading Returns” was derived from 2018
Net income ($440 million), after adding back the effects of interest ($127
million), taxes ($233 million), DD&A ($847 million), FX Gain/Loss ($166 million)
and loss on associate ($2 million).
Adjusted funds flow per diluted share and adjusted funds flow per boe were
calculated by dividing adjusted funds flow by the Company’s diluted share
count and total barrel of oil equivalent sales volumes, respectively. Capital
efficiency represents total drilling, completion, equipping and tie-in costs
divided by total average first-year daily production on a boe basis.
For additional information about “adjusted funds flow” and “net debt”, which are
measures that have been prepared in accordance with IFRS, please see note
17 of the company’s Consolidated Financial Statements for the years ended
December 31, 2018 and 2017 and note 14 of the company’s condensed interim
consolidated financial statements for the three and nine months ended
September 30, 2019 and 2018, available on the SEDAR website.
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 or statements. In particular, but without
limiting the foregoing, this presentation contains forward-looking information
and statements pertaining to the following: the Company’s strategies, strategic
pursuits, priorities, goals, strategic objectives and competitive strengths;
development plans and timing of development; the selection, development and
replenishment of the lowest supply cost resource; best in class execution
through safe, responsible, innovative and efficient development; maximization
of profitability by proactively securing access to premium markets; maintaining
an unwavering focus on balance sheet strength; free cash flow potential and
ability to sustain a free cash flow generating business model; expected drilling
inventory/ potential drilling opportunities; potential inventory expansion;
expected number of years to develop drilling inventory/potential drilling
opportunities; objectives on the slide titled “2020 Budget – Setting the Stage”;
the expected moderation of corporate production decline rates; planned capital
investments and capital allocation including references to sustaining capital
and discretionary capital; the information on the slides titled “2020 Capital
Budget & Guidance” and “2019 Budget”, including expected production,
development wells to be brought on stream, liquids yields, royalty rates,
operating, transportation, G&A and interest expenses, and the expectation that
capital investments will be organically funded at stated commodity price
assumptions; plans for commodity price upside to be returned to shareholders
in the form of share buybacks and/or net debt reduction; expectation that
certain value enhancements will improve average future condensate pricing;
future net debt to adjusted EBITDA forecasts; forecast supply and demand of
condensate; imports of condensate expected to be required to meet demand;
potential benefits from further development of the lower Montney formation and
further development in the Nest 3 area; projections regarding adjusted funds
flow and funds flow sensitivities; access to sales points; delineation potential
and planned delineation; possible expansion of the boundaries of the Nest area
with further delineation; forecast economics, including single well economics,
IRRs, break-even costs, NPVs and PIRs; hedge targets; objectives of hedging
program; the information provided under “Illustrative Economic Uplift Potential”
and “Potential Benefits” on the slide titled “Lower Montney – Emerging
Development Potential”; the information provided on the slide titled “Near Term
Development Goals”; strong netbacks expected to be maintained; improved
execution, optimization and cost control expected in the future; plans to use
leverage conservatively and maintain ample liquidity; upside potential; future
capital efficiency; future 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; 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; 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 pace of development will be consistent with the company’s current
plans; 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.
Except where otherwise indicated, the adjusted funds flow, free cash flow and
adjusted EBITDA forecasts referenced in this presentation were calculated
based upon the assumptions outlined on the slide titled “2020 Capital Budget
& Guidance” and the following commodity pricing assumptions: US$50.00/bbl
WTI, US$2.50/MMbtu NYMEX/HH and 0.75 USD/CAD FX. NGLs as % of WTI:
C3 26%, C4 30%, C5 – $5 USD/bbl differential. AECO Basis US$1.15/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$60/bbl WTI, net of credits as of December
31, 2019 and projected C* for new wells to be drilled in 2020. 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 staff count
and information technology investments in 2020.
30
IMPORTANT NOTICE
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.
Assumptions made in the calculations of forecasted economics, including
forecasted NPVs, IRRs, price sensitivities, commodity prices and recovery
factors reflect cost assumptions that are 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 drilled or 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.
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
opportunities that are referenced herein, various assumptions have been
made. These assumptions are described under the heading “Note
Regarding Potential Drilling Opportunities” below.
Actual results could differ materially from those anticipated in the forward-
looking information that is contained herein as a result of the risks and risk
factors that are set forth in the company’s annual information form dated
February 27, 2019 for the year ended December 31, 2018 (“AIF”), which is
available on the SEDAR website, 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, operating costs
and economic returns from those anticipated; the ability to find, develop or
acquire additional reserves and the availability of the capital or financing
necessary to do so on satisfactory terms; risks related to the 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, including changes in government regulation,
royalties and taxation; political risk; potential legislative and regulatory
changes; 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 or
investments, or successfully integrate future acquisitions or businesses; the
availability, cost or shortage of rigs, equipment, raw materials, supplies or
qualified personnel; the adoption or modification of climate change
legislation by governments and the potential impact of climate change on
the company's operations; the absence or loss of 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 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; the risks of fires, floods and natural disasters, which
could become more frequent or of a greater magnitude as a result of climate
change; 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; unforeseen title defects;
indigenous 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; government
regulations; changes in the application, interpretation and enforcement of
applicable laws and regulations; environmental, health and safety
requirements; restrictions on development 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 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; third party
credit risk; 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; the
potential for security deposits to be required under provincial liability
management programs; reassessment by taxing or regulatory authorities of
the company’s prior transactions and filings; variations in foreign exchange
rates and interest rates; risks associated with counterparties in risk
management activities related to commodity prices and foreign exchange
rates; sufficiency of insurance policies; potential for litigation; variation in
future calculations of non-IFRS measures; 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.
Financial outlook and future-oriented financial information contained in this
presentation regarding prospective financial performance, financial position,
cash flows or well economics are 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 available. Projected operational information also contains forward-
looking 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 of the Company’s operations for any period will likely vary
from the amounts set forth in these projections, and such variations may be
material. Actual results will vary from projected results. Financial outlook
and future-oriented financial information has been included in this
presentation to inform readers of the estimated implications of the capital
investments planned by the company. Readers are cautioned that any such
financial outlook and future-oriented financial information contained herein
should 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
or verified by the Company.
Presentation of Oil and Gas Information
Estimates of the Company’s reserves, contingent resources and
prospective resources contained herein are based upon the reports dated
February 27, 2019 prepared by McDaniel & Associates Consultants Ltd.
(“McDaniel”), the Company’s independent qualified reserves evaluator, as
at December 31, 2018 (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
discovered. If discovered, there is no certainty that it will be commercially
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.
This presentation includes estimates of contingent resources and
prospective resources, as at December 31, 2018, 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, 2018, in the upper, middle and lower intervals of the Montney
formation in certain parts of the Nest 1, Nest 2, Nest 3, Rich Gas and Wapiti
areas within the Kakwa River Project. 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
development. Approximately 98% of the contingent resources attributed to
the Company’s properties by McDaniel, as at December 31, 2018, have
been classified as “development pending” and the balance of the contingent
resources have been classified as “development unclarified”. Contingent
resources in the “development unclarified” project maturity subclass have
been assigned by McDaniel, as at December 31, 2018, in the Wilrich
formation within the Cretaceous stack across the Project area. The COGE
Handbook indicates that it is appropriate to 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. There is uncertainty that it will be commercially viable to
produce any portion of the contingent resources.
31
IMPORTANT NOTICE
Prospective resources have both an associated chance of discovery and a
chance of development. Not all exploration projects will result in
discoveries. The chance that an exploration project will result in the
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
development. The prospective resources associated within the Kakwa
River 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. Approximately
40% of the prospective resources would be expected to be upper and
middle Montney wells in the Wapiti and Rich Gas areas, and approximately
58% would be expected to be lower Montney wells across the Project area
and approximately 2% would be expected to be within the Wilrich formation
within the Cretaceous stack across the Project area.
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 the SEDAR
website. 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”) and GHGe or CO2e, which do not have standardized
meanings or standard methods of calculation and therefore such measures
may not be comparable to similar measures used by other companies and
should not be used to make comparisons. Such metrics have been
included herein to provide readers with additional information to evaluate
the Company’s performance; however, such measures are not reliable
indicators of the future performance of the Company and future
performance may not compare to the performance in previous periods.
Unless otherwise specified, all production is reported on the basis of the
company’s working interest (operating and non-operating) before the
deduction of royalties payable. Seven Generations has adopted the
standard of 6 Mcf:1 bbl when converting natural gas to boes. Condensate
and other NGLs are converted to boes at a 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 is 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 of value.
The GHGe or CO2e estimates for 7G that are provided herein were
calculated by the company. For the 2018 reporting year, based on 2017
performance, 7G’s carbon intensity of 0.0136 tonnes of CO2e per boe, the
lowest carbon intensity estimate compared to six peer companies, was
calculated by 7G. 7G quantified and reported its GHG emissions using
what is referred to as the “operational control” approach. 7G’s deemed
organizational boundary included its corporate offices and all natural gas
extraction and processing facilities (including well pads). 7G elected to
report its Scope 1 and 2 GHG emissions and not to report its Scope 3 GHG
emissions. For the purposes of 7G’s GHG emissions reporting: (i) Scope 1
emissions were defined as direct emissions from GHG sources that 7G
owned or controlled (including, but not limited to, emissions from stationary
equipment, mobile combustion, and process emissions and fugitive
emissions); (ii) Scope 2 emissions were defined as indirect GHG emissions
that resulted from 7G’s consumption of energy in the form of purchased
electricity; and (iii) Scope 3 emissions were defined as 7G’s indirect
emissions other than those covered in Scope 2, including from all sources
not owned or controlled by 7G, but which occurred as a result of 7G’s
activities. Notably, 7G’s drilling and completion activities in the relevant
periods were conducted by third parties and, consequently, those activities
were deemed to be Scope 3.
7G retained Brightspot Climate Inc. to support the quantification of its 2018
GHG emissions. Emissions for all facilities were quantified in accordance
with the methodologies specified in Alberta’s Carbon Competitiveness
Incentive Regulation (“CCIR”) and Specified Gas Reporting Regulation
(“SGRR”), and Environment and Climate Change Canada’s Greenhouse
Gas Emissions Reporting Program, as applicable. Measured quantities,
such as fuel volume, fuel carbon content, flare volumes, venting volumes,
fugitive volumes, and electricity consumption were used, where metered
data was available. Emission factors from published government sources
were applied to the calculations. Third party verification was conducted by
Millennium EMS Solutions. This verification was completed in accordance
with the ISO 14064:3 standard and the requirements of CCIR.
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 or 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-
curves. When type-curves are used for budgeting purposes, facility
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
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
or lateral length.
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
of expected future performance, excluding effects from parent-child well
interactions, unusually tight spacing, facility constraints, downtime and
mechanical failures. Historical tonnage and stage counts may not be
representative of go-forward completion designs. The 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.
The 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.
The 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
fluid. 4 wells drilled in the upper and middle Montney formation provide the
statistical basis for the Nest 3 type-curve.
32
IMPORTANT NOTICE
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, 2018, were evaluated by
McDaniel in the McDaniel Reports. In the McDaniel Reports, McDaniel
assigned proved plus probable reserves to approximately 72% of the Nest
1 sections evaluated; best estimate contingent resources to approximately
28% of the Nest 1 sections evaluated; proved plus probable reserves to
approximately 90% of the Nest 2 sections evaluated; best estimate
contingent resources to approximately 10% of the Nest 2 sections
evaluated; proved plus probable reserves to approximately 55% of the Nest
3 sections evaluated; best estimate contingent resources to approximately
45% of the Nest 3 sections evaluated; proved plus probable reserves to
approximately 19% of the Wapiti sections evaluated; best estimate
contingent resources to approximately 60% of the Wapiti sections
evaluated and best estimate prospective resources to approximately 21%
of the Wapiti sections evaluated.
On the slide titled “Summary of Premium Single Well Economics & Other
Inventory”, the following pricing assumptions were used to develop the
economic forecasts shown: US$55.00/bbl WTI, US$3.00/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. NGL recoveries and shrinkage factors reflected in the
analysis 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.
The forecast economics reflected 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 overhead (G&A) expenses, financing costs or corporate taxes.
Such forecast economics are intended to represent the marginal return of a
single well investment on an existing Super Pad. No adjustments were
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 the forecasts for the reasons described above and
because of the risks and risk factors that are described in the “Forward-
Looking Information Advisory” set forth above. NPV figures have been
calculated using a 10% annual discount factor.
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, 2018. Some of the locations
have already been drilled as part of the Company’s 2019 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, 2018, 64% were attributed proved plus probable reserves
and 36% were attributed best estimate contingent resources in the
McDaniel Reports.
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, 2018, 78% were attributed proved plus probable reserves
and 22% were attributed best estimate contingent resources in the
McDaniel Reports.
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, 2018, 68% were attributed proved plus probable reserves,
and 32% were attributed best estimate contingent resources in the
McDaniel Reports.
For the purposes of estimating potential drilling locations or drilling
opportunities, the company has assumed well spacing of 12 wells per
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 number of future drilling opportunities described for the “Nest Area
Lower Montney”, “Cretaceous”, “Wapiti” and “Rich Gas” areas on the slide
titled “Summary of Premium Single Well Economics & Other Inventory”
represents the number of locations estimated to be attributed to those
areas by McDaniel in the McDaniel reports. For additional information refer
to the AIF, which is available on the SEDAR website.
There is no certainty that the company will drill any of the identified drilling
opportunities or drilling locations and there is no certainty that such
locations will result in additional reserves, resources or production. The
drilling locations on which the company will actually drill 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 or production.
The competitor flow test and initial production history shown on the slide
titled “Nest 1 Development – Ultra-Rich Condensate Region” 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 Nest 1 well that is described on that same slide was drilled in the
middle interval of the Montney formation in the company’s Nest 1 area. The
results have been obtained during a 60 day initial flow period (includes
completions flowback and flow through permanent facilities). The average
gas production rate observed to date is 3,136 Mcf/d and the average
condensate production rate observed to date is 1,375 bbl/d. Cumulative gas
production has been 188 MMcf, cumulative condensate production has
been 82,505 bbls and cumulative produced water has been 59,082 bbls.
Gas, condensate, and water rates ramped up over a period of 12 days. Gas
maintained a plateau rate of about 4,100 Mcf/d) while condensate gradually
declined as expected. Tubing pressure reached a maximum of 9,300 KPa
(1,350 psi) after 5 days of flow and gradually decreased to about 3,500 KPa
(510 psi), consistent with a relatively high liquid/gas ratio of about 750
bbl/MMcf. Pressure transient analysis and well test interpretation has not
yet been conducted for this well.
The “successful vertical test” referenced on the slide titled “Lower Montney
Emerging Development Potential” 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). 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.
The lower Montney wells drilled on “triple-stack” pads shown on the slide
titled “Lower Montney – Emerging Development Potential” were drilled in
the Nest 2 area.
The initial and/or early production rates described in this presentation are
not necessarily indicative of longer-term performance or ultimate recovery.
33
IMPORTANT NOTICE
Oil and Gas Definitions
“best estimate” is a classification of estimated resources described in the
“COGE Handbook” or “COGEH”, 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
contingencies. Contingencies may include factors such as economic,
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 or prospective
resources, which are the Company’s working interest (operating or non-
operating) share before deduction of royalties and without including any
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.
“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.
“undeveloped reserves” are those reserves expected to be recovered from
known accumulations where a significant expenditure (for example, when
compared to the cost of drilling a well) is required to render them capable of
production. They must fully meet the requirements of the reserves
classification (proved, probable) to which they are assigned.
References in this presentation to “2P 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.
Nest 1 2018 estimates represent an average of Nest 1 pads brought on-
stream in 2018.
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 on the slide titled “Nest 1
Development – Ultra-Rich Condensate Region” and for important additional
information, please see the “Note Regarding Development Area Forecast
Economics and Type-Curves” and the “Note Regarding Potential Drilling
Opportunities” above.
The forecasts for Nest 1 reflect 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 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
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” above.
Other Definitions
Throughout this presentation, 7G uses the terms “sustaining capital” and
“discretionary capital”. These measures do not have any standardized
meaning and therefore should not be used to make comparisons to similar
measures presented by other entities.
“Sustaining capital” refers to capital expenditures including drilling,
completions, equipping, tie-in and other expenditures required to maintain
production from existing facilities at current levels.
“Discretionary capital” refers to capital expenditures that are not required to
maintain production from existing facilities at current levels, including but
not limited to delineation, infrastructure, value-enhancing projects, and
production growth.
34
DEFINITIONS AND ABBREVIATIONS
A
AECO
Alliance
avg
bbl or bbls
B or bn
Bcf
Boe or BOE
Btu
C*
°C
CAD or C$ or $
Capex
CDN
CF
CGR
CG
COLC
CO2e
COGE Handbook
or COGEH
CROIC
C2
C3
C4
C5 or C5+
d
D&C
DCET
DD&A
Deep Southwest
EBITDA
ESG
E&P
FCF
FX
G&A
G&G
GHGe
GJ
GTN
H1
H2
H2S
HH or Hhub or Hub
Hz
IFRS
IP
IPO
IRR
ISS
Km
Kpa
LMR
LNG
LGR
annual
physical storage and trading hub for natural gas on the TransCanada Alberta transmission system
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
capital expenditures
Canadian
cash flow
condensate/gas ratio
citygate
Crude Oil Logistics Committee
carbon dioxide equivalent
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
depletion, depreciation and amortization
the “Deep Southwest” area that is shown in the map in this presentation
earnings before interest, taxes, depreciation and amortization
environmental, social, and governance
exploration & production
free cash flow
foreign exchange rate
general and administrative expense
geology and geophysics
greenhouse gas equivalent
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 for the number of days specified
initial public offering
internal rate of return
Institutional Shareholder Services
kilometres
kilopascals
liability management rating
liquefied natural gas
liquid to gas ratio
LPG
LTIF
m
Mbbl
Mboe
Mcf
MM
MMboe
MMbtu
MMcf
mo
N2
NAV
NCIB
NEB
Nest
Nest 1
Nest 2
Nest 3
NGL or NGLs
NGPL
NGTL
NPV
NYMEX
OPEX
PDP
PIR
PP&E
psi
Q1 or 1Q
Q2 or 2Q
Q3 or 3Q
Q4 or 4Q
R&D
Rich Gas
ROCE
ROY
SEDAR
sh
Super Pad
TCPL
TSX
TRIF
TTM
US
USD or US$
Wapiti
WCS
WCSB
WTI
YE
YTD
Y/Y
1P
2P
2C
$MM or MM$
Δ
liquified petroleum gas
lost time incidence frequency
metres
thousand of barrels
thousands of barrels of oil equivalent
thousand cubic feet
million
million barrels of oil equivalent
million British thermal units
million cubic feet
month
Nitrogen
net asset value
normal course issuer bid
National Energy Board
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
operating expense
gross proved developed producing reserves
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
research and development
the “Rich Gas” area that is shown in the map in this presentation
return on capital employed
rest of year
System for Electronic Document Analysis and Retrieval
share
decentralized processing plants that separate field condensate and natural gas
TransCanada Pipelines
Toronto Stock Exchange
total recordable incident frequency
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 reserves
gross total proved plus probable reserves
gross best estimate contingent resources
millions of dollars
Change
TSX: VII
For more information:
Brian NewmarchVice President, Capital Markets
and Stakeholder Engagement
1.403.767.0752
Ryan GallowayInvestor Relations Manager
1.403.718.0709
www.7genergy.com