Corporate Presentation: December 2018 - 7genergy.com · SEVEN GENERATIONS’ KEY FOCUS AREAS 4...
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TSX: VII.TO CORPORATE PRESENTATION December 2018
Transcript of Corporate Presentation: December 2018 - 7genergy.com · SEVEN GENERATIONS’ KEY FOCUS AREAS 4...
TSX: VII.TO
CORPORATE PRESENTATIONDecember 2018
7G CORPORATE PROFILE
2
Canada’s Largest Condensate Producer
87 Mbbl/d of condensate sales in Q3 2018
156 bbls/MMcf condensate-gas-ratio YTD 2018
Generating Meaningful Returns
15.6% return on capital employed (ROCE) in Q3 2018 (3)
$1.74bn trailing 12 month adjusted funds flow
Financial Strength
1.2x trailing 12 month net debt to adjusted funds flow ratio
$1.4 billion current available funding (3)
Diversity of Product Streams and Markets
40% condensate, 22% NGLs and 38% natural gas in Q3 2018
Multiple market exposures across product streams
Ticker symbol - TSX VII Sales Volumes 220 Mboe/d (61% liquids)
Market Cap(1) $3.7 billion Per-Share Adjusted Funds Flow $1.42
Net Debt(2) $2.1 billion Realized Price ($/boe) $42.99
Enterprise Value $5.8 billion Operating Netback(3) ($/boe) $27.92
Share Count – Basic(1) 362.3 million Adjusted Funds Flow (3) ($/boe) $25.81
(1) November 30, 2018 share price & shares outstanding
(2) US$1.575B in senior unsecured notes converted at $1.3294 CAD/USD plus adjusted net working capital deficiency as of Sept 30, 2018 of $20.6 MM
(3) Non-IFRS Financial Measure. For additional information see “Non-IFRS Measures Advisory” in the “Important Notice” that appears at the end of the presentation
Capitalization and Q3 2018 Financial Highlights
Premier Alberta Montney Pure-PlayCorporate Highlights
LEVEL 1 CORPORATE POLICY
3
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.
SEVEN GENERATIONS’ KEY FOCUS AREAS
4
Profitable
Growth
Balancing production growth with free funds flow profile
Revenue growth driven by increasing liquids production and strong condensate pricing
Reducing production volatility and improving risk profile
Consistent execution and business performance
Tailored completion designs to improve capital efficiencies
Enhancing existing infrastructure, ground logistics, cost structure, and on-stream times
Consistent, industry-leading returns on capital employed
Continued growth of adjusted funds flow per share
Optimized capital allocation that creates options for return of capital to shareholders
Notes: For additional information see “Forward Looking Information Advisory” and “Non-IFRS Measures Advisory” in the “Important Notice” at the end of this presentation.
Operational
Excellence
Shareholder
Returns
$0.51 $0.61 $0.48 $0.41 $0.35 $0.47 $0.38 $0.39 $0.40 $0.66 $0.64 $0.60 $0.75 $0.73 $0.78$1.11 $1.05 $1.19 $1.42
$0.00
$0.50
$1.00
$1.50
$2.00
$2.50
$3.00
$3.50
$4.00
$4.50
$5.00
Q1/14 Q2/14 Q3/14 Q4/14 Q1/15 Q2/15 Q3/15 Q4/15 Q1/16 Q2/16 Q3/16 Q4/16 Q1/17 Q2/17 Q3/17 Q4/17 Q1/18 Q2/18 Q3/18
TRACK RECORD OF INDUSTRY LEADING RETURNS AND ADJUSTED FUNDS FLOW PER-SHARE GROWTH
5(1) Broker estimated CROIC calculated as FactSet EBITDA divided by gross PP&E. FactSet EBITDA and CROIC are non-IFRS financial measures.
(2) For additional information see “Non-IFRS Measures Advisory” in the “Important Notice” that appears at the end of the presentation.
7G Quarterly and Annual Adjusted Funds Flow per Diluted Share ($/share)
>250% increase since IPO
2014 - $1.46/sh 2015 - $1.53/sh
2016 - $2.30/sh
2017 - $3.37/sh
Q1-Q3 Annualized - $4.88/sh
12%
5%
7%
5%
15%
6%6%
4%
19%
8%9% 9%
–
2%
4%
6%
8%
10%
12%
14%
16%
18%
20%
VII Top CanadianLiquids-Rich Gas Peers
Top CanadianGas Weighted Peers
Top U.S.Growth Peers
CR
OIC
(%
)
Historical Cash Return on Invested Capital (CROIC)(1)(2)
Source: CIBC World Markets
Peer groups are comprised of: Liquids-Rich - ARX, CR, KEL, NVA | Gas – AAV, BIR, PEY, PPY, SRX, TOU | U.S. Growth – AR, COG, EOG, EQT, PXD, RRC, SWN
Industry leading
return on capital
metrics
2015A 2016A 2017A 2015A 2016A 2017A 2015A 2016A 2017A 2015A 2016A 2017A
0
50
100
150
200
250
2014 2015 2016 2017 2018
2018 BUDGET - A PRODUCTION BASE THAT DRIVES FREE FUNDS FLOW
Growing high value liquids production
61) For additional information see “Forward Looking Information Advisory” the “Important Notice” at the end of this presentation.
2) Forecast AFF at US$65/bbl WTI.
Corporate Production – MBOE/d 2018 Guidance(1)
Total Production (MBOE/d) 200 – 210
Liquids Production (%) 58 – 60%
Condensate Production (%) 35 – 36%
NGL Production (%) 23 – 24%
Natural Gas Production (%) 40 – 42%
CGR (bbl/MMCF) 145 – 155
LGR (bbl/MMCF) 85 – 90
Capital Expenditures ($MM) 1,675 – 1,775
Adjusted Funds Flow ($MM)(2) 1,725 – 1,775
NGLs
Natural Gas
Condensate
$0 $500 $1,000 $1,500 $2,000
2018 BUDGET: CAPITAL INVESTMENT AND FUNDS FLOWS
WTI pricing drives funds flow and accelerates free funds flow profile
7
1) For additional information see “Forward Looking Information Advisory” in the “Important Notice” at the end of this presentation.
2) Assumptions: US$3.00/MMBtu NYMEX; AECO Basis (US$1.15/MMbtu); USD / CAD $0.78; Dawn Basis (US$0.10/MMbtu); Chicago Basis (US$0.15/MMbtu); Condensate as a % of WTI: 98%; C4 60%, C3 35%; C2 pricing
consistent with the Company’s processing and marketing agreements, cash costs (royalties, operating, transportation, G&A and interest) are reflective of historical averages of $15 - $20/boe dependant on the WTI price
scenario. Additional assumptions are outlined in the “2018 Guidance” table on slide 6.
2018 Budget – Capital Investment and Adjusted Funds Flow(1)(2)
$1,725 MM –
$1,775 MM
Uses of Discretionary Free Funds Flow
Adjusted Funds Flow
- Sustaining Capital
= Discretionary Free Funds Flow
$1,600 MM –
$1,675 MM
$1,450 MM –
$1,525 MM
Major
Infrastructure
$200 MM
Drilling, Completions & Delineation
$1,475-$1,575 MM
US$55.00/bbl WTI
US$60.00/bbl WTI
US$65.00/bbl WTI
Adjusted
Funds Flow
Capital
Investment
Disc. Free Funds Flow
Balance Sheet
Optimization
Netback Enhancing
Investments
Delineation
Drilling
Strategic Acquisitions
Production Growth
Share Repurchases
SustainingCapital
Annual FreeCash Flow
+US$10/bblCondensate
+US$5/bblNGL
10% BetterCapital
Efficiency
5% DeclineRate
Mitigation
10% OpexSavings
DISCRETIONARY FREE FUNDS FLOW ENHANCEMENTS ($60 WTI) (3)
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) Assumptions: WTI US$65/bbl; US$3.00/MMBtu NYMEX; AECO Basis (US$1.15/MMbtu); USD / CAD $0.78; Dawn Basis (US$0.10/MMbtu); Chicago Basis (US$0.15/MMbtu); Condensate as a % of WTI: 98%; NGLs as a % of WTI: C4 60%, C3 35%; C2 pricing
consistent with the Company’s processing and marketing agreements.
3) Discretionary free funds flow is defined as the difference between adjusted funds flow and sustaining capital requirements. Free funds flow is defined as the difference between adjusted funds flow and total capex.
Trajectory of Improvements to Discretionary Free Funds Flow Generation
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Pricing Sensitivities Efficiency Gains
Pricing and efficiency gains are material drivers of discretionary free funds flow
Balance Sheet
Optimization
Netback Enhancing
Investments
Delineation
Optimization of
Production Growth
and Share Repurchases
Strategic
Acquisitions
Capital Allocation
Priorities
Significant
Discretionary
Free Funds Flow
Visibility Today
Funds Flow
0
50
100
150
200
250
300
350
400
450
2015 2016 2017 2018
Alb
ert
a C
on
de
nsa
te S
up
ply
an
d
Dem
an
d (
Mb
bl/d
)
Rest of Alberta Seven Generations BC
$10.00
$20.00
$30.00
$40.00
$50.00
$60.00
$70.00
$80.00
2015 2016 2017 2018
WTI Oil Midland Oil Edm. Condensate WCS Heavy Oil Edm. Light
CONDENSATE – PREMIUM PRICING DRIVES RETURNS
9
Alberta’s Largest Condensate Producer
Source: NEB / Bloomberg / 7G Estimates
7G condensate
production currently
accounts for ~20% of
WCSB supply
WCSB condensate
demand is estimated
at ~600,000 bbl/d
Edmonton Condensate vs. Crude Oil Prices (US$/bbl)
Source: Bloomberg
Canadian condensate pricing in similar range to US WTI and Midland streams,
despite a weakening of Canadian WCS and Edmonton Light differentials
• ~1,400 Locations across Nest development
area:
• Nest 1 – 500 Locations
• Nest 2 – 700 Locations
• South– 140
• West – 100
• North – 290
• East – 170
• Nest 3 – 200 Locations
• 2P Reserves: 1.7 billion BOE
• Contingent Resources (risked): 1.3 billion BOE
• Prospective Resources (risked): 740 MMBOE
7G’S NEST MONTNEY DEVELOPMENT AREA
10
Development Inventory(1)7G Development Area Segmentation
Notes:
(1) As of December 31, 2017. For additional information see “Forward-Looking Information Advisory”, “Presentation of Oil & Gas Information” and “Note Regarding Potential Drilling
Opportunities” in the “Important Notice” at the end of the presentation.
Multi decade drilling inventory identified through reserve and resource reports
• ~900 Wapiti and Rich Gas locations(1)
• ~800 net Lower Montney sections
~230 net sections of Cretaceous Rights
• ~120 identified Falher & Wilrich
locations(1)
• 2 Wilrich wells on-stream in 2018
• ~315 net Deep Southwest sections
Future Development Potential
DEVELOPMENT AREA FORECAST ECONOMICS
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Key StatsNest 1 (2014)
Nest 3
Nest 2
South East West NorthWeighted
Average
IP30 (boe/d) 1,250 2,000 1,950 - 2,350
IP365 (boe/d) 675 1,400 1,150 - 1,650
DCET Cost ($MM) $9.5 $11.0 $10.5 - $11.5
IP365 CGR (bbls/MMcf) 135 55 90 160 170 295 205
IRR (%) 55% 90% 125% 175% >300% 250% 220%
NPV ($MM) $6.5 $9.5 $10.0 $13.5 $20.0 $15.0 $14.5
Locations (#) 500 200 140 170 100 290 700
1) The following pricing assumptions were used to develop the economic forecasts shown above: $60.00 US/bbl WTI, $2.75 US/mcf NYMEX/HH and 0.78 USD/CAD FX. NGLs as % of WTI: C3 35%, C4 53%, C5 95%.
Chicago Basis US$0.30/mcf to NYMEX/HH and AECO Basis US$1.50/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, Nest 1 C$0.30/mcf. Fixed well operating cost = $20,000/mo.
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) 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 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” in the “Important
Notice” at the end of this presentation.
5) The drilling locations reflect the estimated number of drilling opportunities as at December 31, 2017, some of which have been drilled in 2018.
6) Net Present Value (NPV) is calculated based on a 10% annual discount factor.
Tailored to Regional Attributes
Increased Stages, Less Tonnage per
stage
High Intensity Slickwater
Completions
Slickwater Completions
Nitrogen Foam
Completions
CONTINUOUS COMPLETION DESIGN INNOVATION
12
2015 – 2016
• Similar results
as N2 foam
completions
• Increased stage
count, sand
intensity and
cost
2014 – 2015
• Initial early
stage N2 foam
completion
• 28 stage, 120
tonnes per
stage design
2016 – 2017
• Increased
tonnage and
stage count,
cemented liner
• Higher intensity
completion to
maximize
recovery
2017
• Optimized
proppant
placement with
higher stage
counts
• Increased
fracture entry
points across
wellbore
2018 & Beyond
• Integration of
subsurface
studies into
completions
design
• Customized
frac intensity
for optimal
rates and
recoveries
Regionally tailored completions drive maximized capital efficiency
61%
10%
29%
Condensate NGLs Natural Gas
MARKET ACCESS – PRODUCT AND LOCATION DIVERSITY
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Product and Geographical Diversity
Condensate
Close proximity to major demand centre (oil sands)
Alberta condensate trades in-line with WTI pricing
Only Canadian product stream without substantial discount to
U.S. benchmarks
NGLs (Ethane, Propane, Butane)
Diversity of product mix (ethane, propane & butane)
Approximately 50/50 split between Alberta & U.S. Midwest
NGL markets
Natural Gas
Over 80% of gas sales marketed outside of Alberta
Alliance: U.S. Mid-West (Chicago Citygate)
GTN: U.S. Pacific NW (Malin - 2019)
NGPL: U.S. Gulf Coast (Henry Hub)
TCPL: Eastern Canada (Dawn) & Alberta (AECO)
Higher value condensate and NGL barrels cannot be
produced without gas, so firm transportation ensures revenue
capture for liquids
Market Access Initiatives
Evaluation and execution of greenfield marketing opportunities
Includes petrochemical, LNG,LPG export, gas fired power
generation
Gas Market Diversification
Source: ARC Financial
Note:
1) Volumes represent 2020 commitment levels
2) Transportation commitments are not additive
2018 Forecasted Revenue by Product(1)(2)
1) Assumptions: US$60/bbl, $0.81 USD/CAD, NYMEX HH price of US$3.00/MMbtu, Chicago CG basis of -US$0.15/MMbtu, AECO basis of -US$1.15/MMbtu.
2) Notes: For additional information see “Forward Looking Information Advisory” in the “Important Notice” at the end of this presentation.
INFRASTRUCTURE SUMMARY
Natural Gas Processing:
~1 Bcf/d capacity
• 510 MMcf/d owned &
operated at Cutbank/Lator
• 250 MMcf/d owned &
operated at Gold Creek
(on-stream in Q4/18)
• Access to 3rd party capacity
of up to 250 MMcf/d
Condensate Stabilization:
>80 mbbl/d capacity
• >60 mbbl/d owned &
operated
• Access 3rd party capacity of
up to 20 mbbl/d
14
Integrated processing, gathering and distribution infrastructure across entire land base
Infrastructure Footprint
BEYOND THE NEST – MULTIPLE HORIZON DEVELOPMENT POTENTIAL
15
Note: For illustrative purposes, not to scale.
Spirit River
~230 net sections with ~120 locations identified (Falher,
Wilrich, etc.)
Two minority interest Wilrich wells (12.5% 7G) drilled in
2017 with average first-month IP rates of ~16.5 MMcf/d
Upper/Middle
Montney
790 net sections, primary focus of 7G development,
generating >90% of current corporate production
>2,000 development locations across the Nest, Wapiti &
Other Areas
Lower
Montney
790 net sections, contiguous with Upper/Middle Montney
development area
Negligible reserves or resources attributed with
significant upside potential
Duvernay
Significant drilling activity in the formation from other
operators
402 net sections, not contemplated in current
development plans
Multi-horizon development utilizing existing 7G infrastructure drives half-cycle returns
Notes: For additional information see “Forward Looking Information Advisory” and “Note Regarding Potential Drilling Opportunities” in the “Important Notice” at the end of this
presentation.
THE 7G VALUE PROPOSITION
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Asset Quality ✓
Inventory ✓
Among North America’s lowest supply cost oil and condensate producers
Canada’s largest condensate producer
~ 800 net sections of Montney rights with decades of drilling opportunities
~1,400 drilling opportunities within the Nest core development area
Balance Sheet ✓ Conservative balance sheet with ample liquidity
A consistent risk management program to ensure consistent returns
Market
Diversity✓
A diversified product mix with exposures across North America
A natural gas marketing portfolio with multiple egress options
Operational
Excellence✓
Renewed focus on cost-effective resource development
Managing downtime, logistics and safety
Effective Capital
Allocation✓
Track record of consistent per-share production and funds flow growth
Multiple options for free funds flow allocation to maximize shareholder value
Notes: For additional information see “Forward Looking Information Advisory” and “Note Regarding Potential Drilling Opportunities” in the “Important Notice” at the end of this
presentation.
Appendix
17
CURRENT HEDGE POSITION
18
2018
Q4 2018 Q1 2019 Q2 2019 Q3 2019 Q4 2019 2019 Q1 2020 Q2 2020 Q3 2020 Q4 2020 2020 Q1 2021 Q2 2021 Q3 2021 Q4 2021 2021
Liquids Hedging
Total WTI Hedged - bbl/d 35,000 35,000 31,000 29,000 24,000 29,750 23,000 22,000 20,000 16,000 20,250 10,000 5,000 1,000 0 4,000
CAD WTI Hedged - bbl/d 30,000 30,000 26,000 22,000 16,000 23,500 12,000 10,000 8,000 4,000 8,500 0 0 0 0 0
CAD WTI Average Bought Put (Floor) - C$/bbl $58.17 $58.17 $57.88 $58.18 $58.13 $58.09 $57.50 $57.00 $56.25 $57.50 $57.06 $0.00 $0.00 $0.00 $0.00 $0.00
CAD WTI Average Sold Call (Ceiling) - C$/bbl $76.44 $76.44 $75.83 $76.11 $74.90 $75.93 $72.81 $71.38 $70.28 $70.33 $71.50 $0.00 $0.00 $0.00 $0.00 $0.00
CAD WTI Puts Sold - bbl/d** 12,000 12,000 10,000 6,000 2,000 7,500 2,000 2,000 2,000 0 1,500 0 0 0 0 0
CAD WTI Average Sold Put - C$/bbl** $40.83 $40.83 $41.00 $41.67 $40.00 $41.00 $40.00 $40.00 $40.00 $0.00 $40.00 $0.00 $0.00 $0.00 $0.00 $0.00
USD WTI Hedged - bbl/d 5,000 5,000 5,000 7,000 8,000 6,250 11,000 12,000 12,000 12,000 11,750 10,000 5,000 1,000 0 4,000
USD WTI Average Bought Put (Floor) - US$/bbl $54.85 $54.85 $54.85 $53.47 $53.66 $54.08 $52.71 $52.90 $52.90 $52.90 $52.85 $53.03 $54.10 $55.00 $0.00 $53.49
USD WTI Average Sold Call (Ceiling) - US$/bbl $60.28 $60.28 $60.28 $60.16 $61.40 $60.61 $60.35 $60.77 $60.77 $60.77 $60.67 $61.47 $63.54 $70.05 $0.00 $62.65
USD WTI Puts Sold - bbl/d** 0 0 0 0 1,000 250 2,000 3,000 3,000 3,000 2,750 3,000 3,000 1,000 0 1,750
USD WTI Average Sold Put - US$/bbl** $0.00 $0.00 $0.00 $0.00 $40.00 $40.00 $40.00 $40.00 $40.00 $40.00 $40.00 $40.00 $40.00 $40.00 $0.00 $40.00
Natural Gas Hedging
Total Gas Hedged - MMbtu/d 256,869 226,869 266,869 236,869 206,869 234,369 149,478 89,478 69,478 69,478 94,478 40,000 10,000 0 0 12,500
Gas Hedged - NYMEX HH - MMbtu/d 60,000 70,000 70,000 70,000 70,000 70,000 90,000 40,000 40,000 40,000 52,500 40,000 10,000 0 0 12,500
Average NYMEX HH Swap - USD/Mmbtu $2.95 $2.92 $2.92 $2.92 $2.92 $2.92 $2.90 $2.81 $2.81 $2.81 $2.85 $2.81 $2.73 $0.00 $0.00 $2.79
Gas Hedged - Chi CG - MMbtu/d 140,000 100,000 140,000 110,000 80,000 107,500 50,000 40,000 20,000 20,000 32,500 0 0 0 0 0
Average Chi CG Swap - USD/MMbtu $2.84 $2.83 $2.87 $2.84 $2.83 $2.84 $2.76 $2.73 $2.71 $2.71 $2.74 $0.00 $0.00 $0.00 $0.00 $0.00
Gas Hedged - AECO - GJ/d 60,000 60,000 60,000 60,000 60,000 60,000 10,000 10,000 10,000 10,000 10,000 0 0 0 0 0
Average AECO Bought Put (Floor) - C$/GJ $2.44 $2.44 $2.44 $2.44 $2.44 $2.44 $2.13 $2.13 $2.13 $2.13 $2.13 $0.00 $0.00 $0.00 $0.00 $0.00
Average AECO Sold Call (Ceiling) - C$/GJ $2.85 $2.85 $2.85 $2.85 $2.85 $2.85 $2.13 $2.13 $2.13 $2.13 $2.13 $0.00 $0.00 $0.00 $0.00 $0.00
Natural Gas Basis Hedging
Basis Hedged - Chi CG - GJ/d 0 0 0 0 10,000 2,500 50,000 50,000 50,000 50,000 50,000 50,000 30,000 0 0 20,000
Average Chi CG Basis Swap - US$/MMbtu $0.00 $0.00 $0.00 $0.00 -$0.23 -$0.23 -$0.22 -$0.22 -$0.22 -$0.22 -$0.22 -$0.22 -$0.23 $0.00 $0.00 -$0.23
FX Hedging
FX Forwards USD Notional Hedged ($MM) $57.5 $46.1 $46.4 $41.1 $35.6 $169.3 $32.3 $29.7 $24.8 $24.8 $111.7 $19.8 $19.8 $5.0 $0.0 $44.6
Average Rate 1.3058 1.2888 1.2877 1.2864 1.2948 1.2892 1.2808 1.2768 1.2725 1.2725 1.2760 1.2792 1.2792 1.3039 0.0000 1.2819
FX Collars USD Notional Hedged ($MM) $2.5 $2.5 $5.0 $5.0 $5.0 $17.3 $5.0 $5.0 $5.0 $5.0 $19.8 $5.0 $5.0 $0.0 $0.0 $9.9
Average Rate Bought Put (Floor) 1.2600 1.2600 1.2650 1.2650 1.2650 1.2643 1.2650 1.2650 1.2650 1.2650 1.2650 1.2650 1.2650 0.0000 0.0000 1.2650
Average Rate Sold Call (Ceiling) 1.3135 1.3135 1.3118 1.3118 1.3118 1.3120 1.3118 1.3118 1.3118 1.3118 1.3118 1.3118 1.3118 0.0000 0.0000 1.3118
**Represents volumes and prices for additional puts sold for 3-way WTI collars
2019 2020 2021
September 30, 2018
Hedge Position
SELECTED FINANCIAL AND OPERATIONAL INFORMATION
19
VII - Recent Quarterly ResultsOPERATING RESULTS Q3 2018 Q2 2018 Q1 2018 Q4 2017 Q3 2017 Q2 2017 Q1 2017 Q4 2016 Q3 2016 Q2 2016 Q1 2016 YE 2017 YE 2016
Average daily production
Condensate (1) (mbbl/d) 87.3 69.0 67.3 70.0 64.5 59.0 51.6 47.2 50.6 42.5 31.0 61.3 42.9
Natural gas (MMcf/d) 511.3 461.3 473.3 493.4 453.2 409.6 384.5 334.0 314.0 290.0 225.0 435.5 291.0
NGLs (1) (mbbl/d) 47.4 41.2 41.5 45.1 43.9 38.0 37.4 29.4 29.7 26.5 20.0 41.1 26.4
Total (mboe/d) 219.8 187.1 187.7 197.3 183.9 165.2 153.1 132.3 132.6 117.4 88.5 175.0 117.8
CGR Ratio 171 150 142 142 142 144 134 141 161 147 138 141 147
LGR Ratio 93 89 88 91 97 93 97 88 95 91 89 94 91
Realized Prices
Condensate (1) ($/bbl) 79.26 81.67 73.39 67.95 54.95 58.28 63.84 57.03 49.31 51.68 39.56 61.28 50.35
Natural gas ($/Mcf) 3.65 3.79 3.54 3.53 3.46 4.09 4.36 4.15 3.92 2.62 3.24 3.84 3.53
NGLs (1) ($/bbl) 14.02 13.39 13.33 18.30 15.17 11.45 12.45 12.81 6.84 7.59 5.61 14.56 8.32
42.99 42.42 38.19 37.13 31.43 33.59 35.52 33.67 29.65 26.91 23.33 34.45 28.92
FINANCIAL RESULTS (4)
Condensate (1) ($MM) 636.6 512.8 444.5 437.7 326.2 312.9 296.5 247.8 229.7 200.3 110.2 1,373.3 788.0
Natural gas ($MM) 171.8 159.2 156.1 160.3 144.1 152.4 150.8 127.3 113.3 69.0 66.6 607.6 376.2
NGLs (1) ($MM) 61.0 50.2 49.8 75.9 61.3 39.5 42.1 34.7 18.7 18.1 11.2 218.8 82.7
Liquids and natural gas sales (2) ($MM) 869.4 722.2 650.4 673.9 531.6 504.8 489.4 409.8 361.7 287.4 188.0 2,199.7 1,246.9
Royalties ($MM) (44.4) (16.4) (18.9) (21.5) (14.5) (9.3) (16.8) (11.9) (0.4) 18.6 (13.0) (62.1) (6.7)
Operating expense ($MM) (105.5) (102.2) (96.8) (103.3) (91.8) (93.9) (68.8) (59.1) (47.0) (44.8) (31.0) (357.8) (181.9)
Transportation, processing and other expense ($MM) (124.2) (118.0) (110.6) (116.8) (109.4) (88.3) (74.3) (77.0) (77.9) (57.5) (39.9) (388.8) (252.3)
Operating netback before the following (3) ($MM) 595.3 485.6 424.1 432.3 315.9 313.3 329.5 261.8 236.4 203.7 104.2 1,391.0 806.1
Realized hedging gain (loss) ($MM) (36.2) (17.7) (13.1) 6.9 14.2 1.8 (7.2) 5.8 19.2 29.5 36.3 15.7 90.8
Marketing Income (3)(5) ($MM) 5.7 9.1 10.0 11.8 4.6 6.3 2.3 5.0 3.2 1.3 4.2 25.0 13.7
Operating netback (3) ($MM) 564.8 477.0 421.0 451.0 334.7 321.4 324.6 272.6 258.8 234.5 144.7 1,431.7 910.6
Adjusted funds flow (6) ($MM) 522.0 434.0 380.8 403.8 284.3 268.1 272.1 219.7 212.1 197.6 110.6 1,228.3 740.0
Netbacks (4)
Liquids and natural gas sales ($/boe) 42.99 42.42 38.51 37.13 31.43 33.59 35.52 33.67 29.65 26.91 23.33 34.45 28.92
Royalties ($/boe) (2.20) (0.96) (1.12) (1.18) (0.86) (0.62) (1.22) (0.98) (0.03) 1.74 (1.61) (0.97) (0.16)
Operating expense ($/boe) (5.22) (6.00) (5.73) (5.69) (5.43) (6.25) (4.99) (4.86) (3.85) (4.19) (3.85) (5.60) (4.22)
Transportation, processing and other expense ($/boe) (6.14) (6.93) (6.54) (6.43) (6.47) (5.87) (5.39) (6.33) (6.39) (5.38) (4.95) (6.09) (5.85)
Operating netback before the following (3) ($/boe) 29.43 28.53 25.12 23.83 18.67 20.85 23.92 21.50 19.38 19.08 12.92 21.79 18.69
Realized hedging gain (loss) ($/boe) (1.79) (1.04) (0.78) 0.38 0.84 0.12 (0.52) 0.48 1.57 2.76 4.51 0.25 2.11
Marketing Income (3)(5) ($/boe) 0.28 0.53 0.60 0.65 0.27 0.42 0.17 0.41 0.26 0.12 0.52 0.39 0.32
Operating netback (3) ($/boe) 27.92 28.02 24.94 24.86 19.78 21.39 23.57 22.39 21.21 21.96 17.95 22.43 21.12
Adjusted funds flow per boe (3)(6) ($/boe) 25.81 25.49 22.54 22.25 16.80 17.83 19.75 18.05 17.39 18.50 13.73 19.23 17.16
Capital investments (4)
Drilling and completions ($MM) 232.6 335.9 319.6 167.4 252.8 342.3 259.4 186.7 133.4 125.0 152.6 1,021.9 597.7
Facilities and infrastructure ($MM) 90.8 179.3 207.0 115.0 176.5 153.9 85.2 78.5 62.6 88.1 107.9 530.6 337.1
Land and other ($MM) 34.8 47.4 56.0 39.9 25.0 16.3 17.7 18.6 11.7 6.2 6.7 98.9 43.2
Total capital investments ($MM) 358.2 562.6 582.6 322.3 454.3 512.5 362.3 283.8 207.7 219.3 267.2 1,651.4 978.0
(1) Starting in 2018, 7G began presenting C5+ in the NGL mix as a condensate volume (previously reported as an NGL volume). 2017 and 2016 figures have been adjusted to conform to this current period presentation.
(2) Excludes the purchase and resale of condensate and natural gas in respect of transportation commitment optimization and marketing activities. Refer to the Q3 2018 MD&A as filed on SEDAR for additional information.
(3) Figure is a non-IFRS financial measure. Refer to the Company's Q3 2018 MD&A as filed on SEDAR for additional information.
(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 gas, net of applicable pipeline tariffs, represent the margins earned in respect of the Company's transportation optimization and marketing activities.
(6) Refer to Note 14 of the Q3 2018 condensed interim consolidated financial statements for further details.
SWEET SPOT OF THE MONTNEY
20Sources: 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
RESPONSIBLE DEVELOPMENT HIGHLIGHTS
21
Low GHGs 0.0126 carbon intensity(1)
GP Hospital $2.4 million raised
Safety first 0.64 TRIF in 2017
• Building a culture of safety
• Total Recordable Incident Frequency up 14%
• Lost-Time Incident Frequency down 40%
• Among lowest carbon intensity of Canadian producers
• Independent verification: Leak Detection and Repair Program “clearly working” to reduce methane emissions, says Stanford researcher
• 7G’s annual golf tournament raised $2.4 million for the GP Regional Hospital Foundation and Grande Prairie Regional College in its first six years
Safety Environment Community
(1) Based upon 2016 data. Represents estimated metric tonnes of carbon dioxide equivalent per barrel of oil equivalent of production. 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.
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
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
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”, “operating netback”, “adjusted EBITDA”, “return on
capital employed” (or “ROCE”), “Factset EBITDA”, “cash return on invested
capital” (or “CROIC”) and “marketing income”, 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” (also referred to herein
as “netback”), “adjusted EBITDA”, “return on capital employed” (or ROCE),
“marketing income”, 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.
“FactSet EBITDA” is calculated by a third party and differs from adjusted
EBITDA primarily through the exclusion of realized hedging gains and
losses. “Cash return on invested capital” (or “CROIC”) is FactSet EBITDA
divided by the average unamortized cost of developed and producing oil
and natural gas assets and is a performance measure of a company’s
ability to generate returns on capital investments. The 2017 CROIC of 19%
reflects FactSet EBITDA of $1,341.5 million divided by the average cost of
oil and natural gas assets of $7,213.5 million. The 2016 CROIC of 15%
reflects FactSet EBITDA of $757.9 million divided by the average cost of oil
and natural gas assets of $5,104.6 million. The 2015 CROIC of 12%
reflects FactSet EBITDA of $334.2 million divided by the average cost of oil
and natural gas assets of $2,769.9 million.
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 priorities, objectives and
competitive strengths; the Company’s development plans; continued
growth of adjusted funds flow per share; 2018 guidance, including expected
total production, liquids production condensate production, NGL production,
condensate production, CGR, LGR, capital investment and adjusted funds
flow; free funds flow enhancements possible with commodity price
increases, efficiency improvements, decline rate mitigation and reduced
operating costs; the decades of drilling opportunities/drilling inventory
expected from the company’s properties; forecast economics, including
NPVs and IRRs and the production and cost assumptions used to develop
the forecasts; ability to maximize capital efficiencies; forecast revenue by
product type; the options available for free funds flow allocation to
maximize shareholder value; temperature and pressure estimates in
various formations and regions; investment priorities for 2019 and beyond;
the ability to tailor completion designs to achieve optimal production rates
and recovery and maximize capital efficiencies; drilling locations or drilling
inventory; gas processing, condensate stabilization and transportation
capacity; capacity and on-stream dates of new gas processing facility in the
Gold Creek area; upside development potential of various formations and
secondary targets; expectation that the utilization of 7G infrastructure may
provide half-cycle returns from the development of secondary targets; 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.
Assumptions made in the calculation of forecasted economics, including
forecasted NPVs, IRRs, price sensitivities, commodity prices and recovery
factors are provided in footnotes proximate to those disclosures.
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 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,
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;
IMPORTANT NOTICE
22
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; 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 or
investments, or 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 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 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
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
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
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, 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
development. Contingent resources in the “development unclarified” project
maturity subclass have been assigned by McDaniel, as at December 31,
2017, in the lower interval of the Montney formation in the northwest corner
of the Wapiti 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. 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 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. McDaniel has subclassified the prospective resources that
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.
IMPORTANT NOTICE
23
Note Regarding Industry Metrics
This presentation includes certain industry metrics, including barrels of oil
equivalent (“boes” and carbon intensity, 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 and therefore such metrics should not be relied
upon.
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 oil equivalent. Condensate and other NGLs are
converted to oil equivalent 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 7G’s sales points.
Given the value ratio based on the current price of oil as compared to natural gas
is significantly different from the energy equivalency of 6 Mcf: 1 bbl, utilizing a
conversion ratio at 6 Mcf: 1 bbl may be misleading as an indication of value.
The carbon intensity estimates for 7G that are provided herein were calculated
by the Company with the assistance of third parties. 7G quantified and reported
its greenhouse gas (“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:
• 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);
• Scope 2 emissions were defined as indirect GHG emissions that resulted from
7G’s consumption of energy in the form of purchased electricity; and
• 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 used third parties to help quantify its GHG emissions. For the 2015 and 2016
reporting years, Deloitte LLP was retained by 7G to evaluate GHG emissions
from all major facilities located in Alberta (gas plants, gas gathering systems and
batteries) in accordance with Alberta’s Specified Gas Emitters Regulation
(“SGER”) reporting program, Alberta’s Specified Gas Reporting Regulation and
Environment and Climate Change Canada’s Greenhouse Gas Emissions
Reporting Program. To conduct this quantification, emission calculation methods
were taken from the approved reference sources listed in the SGER guidance
publication titled “Technical Guidance for Completing Specified Gas Baseline
Emission Intensity Applications”. Additional quantification of Scope 1 GHG
emissions (e.g., vented emissions and fugitives) was conducted by DXD
Consulting Inc. (“DXD”) using API 2009 guidance and emissions factors. Scope 2
emissions were quantified by DXD using utility statements for all purchased
electricity (i.e., Calgary and Grande Prairie offices and the Lator 1 facilities).
For the 2016 reporting year, third party verification of both the SGER (i.e., Scope
1 GHG emissions) report developed on behalf of 7G by Deloitte LLP and the
Carbon Disclosure Project’s (“CDP”) Climate Change 2017 Questionnaire and
CDP Oil and Gas Sector Module 2017 (i.e., Scope 1 and 2 GHG) reports
developed by 7G was conducted by Brightspot Climate Inc. This verification was
completed in accordance with the ISO 14064:3 standard.
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 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 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 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.
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 fluid. 4 wells drilled in the
upper and middle Montney formation provide the statistical basis for the Nest 3
type-curve.
The Company has opted to rely upon the type-curve forecasts that have been
prepared by 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.
IMPORTANT NOTICE
24
AreaNumber
of Wells
Stage
Count
Tonnes
Proppant
/Stage
Lateral
Well
Length
(m)
Average
Spacing
(m)
Nest 2 (South) 19 39 167 2,739 267
Nest 2 (West) 4 50 160 2,444 267
Nest 2 (North) 21 41 155 2,758 267
Nest 2 (East) 3 32 119 2,629 267
Average - Nest 2 47 40.4 158 2,715 267
Note Regarding Potential Drilling Opportunities
The references to drilling locations or potential drilling opportunities that are
contained herein were prepared by 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 500 potential drilling locations or drilling opportunities that were
estimated to be contained within the company’s Nest 1 area, as at
December 31, 2017, 50% were attributed proved plus probable reserves
and 50% were attributed best estimate contingent resources in the
McDaniel Reports.
Of the 700 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, 83% were attributed proved plus probable reserves
and 17% were attributed best estimate contingent resources in the
McDaniel Reports.
Of the 200 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, 54% were attributed proved plus probable reserves,
41% were attributed best estimate contingent resources and 5% were
attributed best estimate prospective resources in the McDaniel Reports.
Of the 900 potential drilling locations or drilling opportunities that were
estimated to be contained within the company’s Wapiti & Rich Gas area, as
at December 31, 2017, 5% were attributed proved plus probable reserves,
70% were attributed best estimate contingent resources and 25% were
attributed best estimate prospective resources in the McDaniel Reports.
None of the 120 potential drilling locations or drilling opportunities identified
in the Wilrich & Falher formations that are described in this presentation
were attributed reserves, contingent resources or prospective 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 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
information. 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.
Early production rates described in this presentation are not necessarily
indicative of longer term performance or ultimate recovery.
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 the 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 are conditions that must be satisfied for a
portion of contingent resources to be classified as reserves that are: (a)
specific to the project being evaluated; and (b) expected to be resolved
within a reasonable timeframe. Contingencies may include factors such as
economic, legal, environmental, political and regulatory matters or a lack of
markets. 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.
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.
IMPORTANT NOTICE
25
DEFINITIONS AND ABBREVIATIONS
26
A
AECO
AFF
avg
bbl or bbls
B or bn
Boe or BOE
Btu
°C
CAD or C$ or $
CGR
CG
COGE Handbook
CROIC
C2
C3
C4
C5 or C5+
d
DCET
Deep Southwest
EBITDA
FX
G&A
GJ
GTN
H1
H2
H2S
HH or Hhub
hz
IP
IP 30
IP 365
IPO
IRR
km
kpa
LNG
LGR
LPG
m
Mbbl
Mboe
annual
physical storage and trading hub for natural gas on the TransCanada Alberta transmission
system
adjusted funds flow
average
barrels or barrels
billion
barrels of oil equivalent
British thermal units
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, complete and tie-in
the “Deep Southwest” area that is shown in the map in this presentation
earnings before interest, taxes, depreciation and amortization
foreign exchange rate
general and administrative expense
Gigajoule
Gas Transmission Northwest LLC
first half of the year
second half of the year
hydrogen sulfide
Henry Hub
horizontal
initial production
initial production for the first 30 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
metres
thousand of barrels
thousands of barrels of oil equivalent
Mcf
mcfe
MM
MMboe
MMbtu
MMcf
mo
N2
Nest
Nest 1
Nest 2
Nest 3
NGL
NGPL
NGTL
NPV
NYMEX
OPEX
PP&E
psi
Q1 or 1Q
Q2 or 2Q
Q3 or 3Q
Q4 or 4Q
Rich Gas
ROCE
SEDAR
sh
Super Pad
TCPL
TSX
US
USD or US$
Wapiti
WCS
WCSB
WTI
YE
YTD
2P
$MM or MM$
thousand cubic feet
thousand cubic feet equivalent
million
million barrels of oil equivalent
million British thermal units
million cubic feet
month
nitrogen
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
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
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
gross total proved plus probable reserves
millions of dollars
INVESTOR RELATIONS CONTACTS
27
Brian Newmarch
Vice President Capital Markets
403.767.0752
Ryan Galloway
Investor Relations Manager
403.718.0709
Seven Generations Energy Ltd.
4400, 525 – 8th Ave SW
Eighth Avenue Place East
Calgary, AB T2P 1G1
