39
Husky Energy Inc.
Husky Energy Inc.
Husky Energy Inc.
Delivering and Improving on the Five Year Plan 2017 Achievements
Downstream: increase heavy oil processing
capacity
• Superior Refinery acquired November 2017
• 2018 – 2021 incremental FCF of $500MM
Sunrise: 14 new well pairs tied in by year-end
Indonesia: First production at BD Project in
2H/2017
Atlantic In-fill Program: Efficiencies in 2017
drilling leads to the acceleration of two 2018 wells
in Q4 2017
Liwan 29-1: Field sanctioned. Development to
commence in 2018. First production in 2021
Thermal bitumen production growth:
Edam Central and Westhazel thermal projects
sanctioned.
• 2 x 10,000 bbls/day capacity on stream in 2021
• Total of 60,000 bbls/day of to be developed and
on stream by 2021
a
a
a
a
a
a
Key Metrics Investor Day
Targets 2017F
2017F
Delivery Status
Production (mboe/day) 320 – 335 324
Funds from operations (FFO)1 $3.3B $3.2-$3.3B
Free cash flow (FCF)1 $750M $900M
Upstream operating cost/bbl $14.25 ~$14
Downstream realized margins/bbl (CAD) $15.00 ~$14
Earnings break-even oil price (US WTI)2 ~$43.60 ~43
Cash break-even oil price (US WTI)2 ~$33.50 ~33
Ranges and Targets
Sustaining capital $1.8B $1.8B
Capital spending3,4 $2.5-$2.6B $2.2-$2.3B
5-year avg. proved reserve replacement ratio Target >130% >150+%
Net debt to FFO5 < 2x ~1.0x
a
a a
a a
a
r
a a
2
a
a 1,2,3,4,5 see Slide Notes and Advisories
Husky Energy Inc.
• Returns-focused growth
• Investing in a large inventory of low
cost projects
• Low and improving earnings and
cash break-evens
• Strong growth in funds from
operations and free cash flow
• Resilient to volatile market
conditions while preserving upside
3 1 see Slide Notes and Advisories
Value Proposition
Key Metrics ’18F ’21F
Production (mboe/d) 320 – 335 400 (7% CAGR)
Funds from operations (FFO)1 >$4B _
Free cash flow (FCF)1 >$1B _
Upstream operating cost/bbl $13-13.50 < $12
Upgrading & U.S refining operating costs ($CAD) $6 - $7 $6 - $7
Earnings break-even oil price (US WTI) ~$42 < $37
Cash break-even oil price (US WTI) ~$32 < $32
Ranges and Targets ’18F ’17F - ’21F
Sustaining capital $1.8 - $1.9B Avg. $1.9B
Capital expenditures $2.9 - $3.1B Avg. $3.3B
Five-year avg. proved reserve replacement ratio _ Target >130%
Net debt to FFO ~ 1.0 < 2x
Husky Energy Inc.
2018 Guidance Overview
4
• Funds from Operations ($ billion): > $4.0
• Capital Spending ($ billion): $2.9 - $3.1
• Free Cash Flow ($ billion): ~ $1.0
• Production Range (mboe/day): 320 - 335
• 6% YoY increase
• Downstream Throughputs (mbbls/day): 360 – 370
• 7% YoY increase
• Operating Costs ($/boe) $13.00 - $13.50
• 5% YoY decrease
Price Assumptions
• WTI ($US/bbl) $55
• Chicago 321 Crack (US$/bbl) $15.00
• AECO Natural Gas ($/mmcf) $2.50
• Fx – CAD/USD 0.78
30%
25%
5% 5% 7%
25%
3%
Thermal Operations
Atlantic Oil
Non thermal heavy, medium, light, NGLs
Asia Pacific Gas & NGLs
Resource Gas
Downstream
Corporate
2018 Capital Spending By Business Segment
40%
14%
15%
11%
21% Thermal Operations
Asia Pacific Gas & NGLs
Canadian Gas
Atlantic Oil
Non thermal heavy, medium, light, NGLs
2018 Production by Business Segment
Husky Energy Inc.
-
0.5
1.0
1.5
2.0
2.5
3.0
3.5
4.0
4.5
2017 2018-BASE
2018 -Strip
FCF
FFO
Portfolio Investment
Downstream Sustaining Capital
Upstream Sustaining Capital
2018 FFO and Capital Spending
2018 Capital Program Self Funding at $50 US WTI ~$450 Million Free Cash Flow at $50 US WTI , ~$1 Billion Free Cash Flow at $55 US WTI
1, 2 see Slide Notes and Advisories 5
2 ‘18F
@ US$50 WTI
‘18F
@ US$55 WTI
’17F
~ $1 Billion FCF
1
$ billions
Husky Energy Inc.
Major Projects Production 2017 2018 2019 2020 2021 2022
INTEGRATED CORRIDOR
Thermal Bitumen
Tucker Lake (to 30,000 bbls/d, YE 2018)
Rush Lake 2
Dee Valley
Spruce Lake North
Spruce Lake Central
Edam Central
Westhazel Waseca
Future Lloyd Thermal Proejcts (x2)
Sunrise (14 wells)
Resource Plays
Ansell-Kakwa drilling program
Montney drilling program
Downstream
Lima - Crude Oil Flexibility Project
Asphalt Capacity Expansion
OFFSHORE
Asia Pacific
China - Liuhua 29-1
Indonesia - BD Field
Indonesia - MDA-MBH, MDK
Atlantic
White Rose Development / Infill Wells
West White Rose (peak) 52,500 bbls/d
5-8,000 bbls/d
8,300 boe/d
9,000 boe/d
30 mmcf/d
30,000 bbls/d
30,000 bbls/d
11,500 bbls/d
20,000 bbls/d
10,000 bbls/d
10,000 bbls/d
10,000 bbls/d
10,000 bbls/d
10,000 bbls/d
10,000 bbls/d
7,000 bbls/d Ramp Up Period
Ramp Up Period
Heavy Capacity Increase
Five-Year Plan Milestones All Projects On / Ahead Schedule
6
a
a
Accelerated to Q1 2019
On Schedule
16 Wells planned for 2018
8 Wells planned for 2018
On Schedule
Acquired Superior Refinery a
Sanctioned Completed
Completed
On Schedule
2 Wells accelerated to Q4 2017 a On Schedule
On Schedule
On Schedule
Sanctioned Q4 2017
On Schedule
Ramp Up Period
Sanctioned Q4 2017
Husky Energy Inc.
WTI US $45/bbl
$0
$2
$4
$6
$8
$10
$0
$20
$40
$60
$80
Atla
ntic I
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We
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tla
ntic I
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We
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De
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CH
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Op
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ush
La
ke
2 (
10
mb
/d)
Dee
Va
lley (
10
mb
/d)
Sp
ruce L
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10 m
b/d
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0 m
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0 m
b/d
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loyd
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erm
al (1
0 m
b/d
)L
loyd
Th
erm
al (1
0 m
b/d
)L
loyd
Th
erm
al (1
0 m
b/d
)L
loyd
Th
erm
al (1
0 m
b/d
)L
loyd
Th
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al (1
0 m
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Th
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Su
nri
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ast -
A (
20
mb
/d)
Su
nri
se E
ast -
B (
20
mb
/d)
Su
nri
se E
ast -
C (
20
mb/d
)S
un
rise E
ast -
D (
20
mb/d
)S
un
rise S
outh
- A
(2
0 m
b/d
)S
un
rise S
outh
- B
(2
0 m
b/d
)H
ea
vy O
il -
CH
OP
SM
cM
ulle
n T
he
rma
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ulle
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he
rma
lM
cM
ulle
n T
he
rma
lM
cM
ulle
n T
he
rma
l
Ka
kw
a (
Wilr
ich)
An
se
ll (W
ilric
h)
MD
A (
Ma
du
ra)
MB
H (
Ma
du
ra)
Liu
hua
29
-1
MD
K (
Ma
du
ra)
Mad
ura
Dry
Ga
s
Project Inventory Projects Included Plan Spending Period WTI Oil Price
Asp
ha
lt E
xp
ansio
nC
OF
(L
ima)
10%
0%
Short to
Medium
Cycle
2/3 Of Planned
Capital Spend
$16B
Capital
Spending ’17-’21F
Returns-Focused Growth New Project Hurdle of >10% IRR at Flat $45 US WTI and/or Flat $2.50 AECO
Price Required to Generate 10% IRR
Canadian Gas
($ Cdn.)
Asia Pacific Gas
($US)
Gas Portfolio1,2
($/mcf )
Downstream
Portfolio3
(IRR)
Oil Portfolio1
(WTI US $/bbl)
4
1,2,3,4 see Slide Notes and Advisories 7
Husky Energy Inc.
10
20
30
'17F '18F '19F '20F '21F
2017 Operating Netback Asset Improvement Commodity Price Impact
10.00
12.50
15.00
'17F '18F '19F '20F '21F
Capital Investment Lowers Cost Structure Costs Down – Netbacks And Margins Up
$/boe
$/boe
10
14
18
'17F '18F '19F '20F '21F
2017 Margin Asset Improvement Commodity Price Impact
12% ↑ Downstream Margins ’17 - ’21F
$/bbl
23% Upstream Operating Netbacks1
’17 -’21F
17%
↑
Upstream Operating Costs ’17 -’21F
↑
8 1 see Slide Notes and Advisories
Husky Energy Inc.
25
30
35
40
45
'17F '18F '19F '20F '21F
Earnings Break-Even
Cash Break-Even
200
300
400
0.0
1.5
3.0
'17F '18F '19F '20F '21F
Total Sustaining Capital
Daily Production (mboe/d)
Capital Investment Lowers Cost Structure Improving Break-Even Oil Price and Sustaining Capital Requirements
Sustaining Capital vs. Production
$B $US WTI
Break-Evens
mboe/d
Upstream
Sustaining
Cost/Boe ’17-’21F
~$11 Annual Average
Cash
Break-Even ’17-’21F
~$32 (US WTI)
Annual Average
Sustaining
Capital ’17-’21F
~$1.9B Annual Average
9
Husky Energy Inc.
$0.0
$0.2
$0.4
$0.6
$0.8
$1.0
$1.2
$1.4
'18 '19 '20 '21 '22 '23 '24 '25 '26 '27 '37
USD Bonds ($/US$) CAD Bonds ($) Preferred Shares ($)
Healthy Balance Sheet
0
2
4
6
8
'15 '16 '17F '18F - '21F
0
1
2
3
4
5
Husky A B C D E
times
Net Debt to Trailing FFO1 Net Debt
$B
Peer Group
Debt Maturity Schedule
$4.0B
$2.5B
undrawn credit
facilities
cash & cash
equivalents
As at Sept 30, 2017
Net debt of $3.0 billion (Q3’17)
10
Liquidity
2
1,2 see Slide Notes and Advisories
Moody’s Baa2 ; Stable
S&P BBB+; Stable
DBRS A (low); Stable
Credit Ratings
$ billions
Husky Energy Inc.
0.0
0.5
1.0
1.5
'10 '11 '12 '13 '14 '15 '16
0.0
2.0
4.0
6.0
'10 '11 '12 '13 '14 '15 '16
Strong Focus on Safety and ESG
# per 200K hours worked
# per 200K hours worked
Total Recordable Incident Rate
Critical & Serious Incidents
Safety Performance Results Disclosure ESG Performance and Ratings
• Rigorous emissions controls in all operations
• Leading developments of carbon capture and
injection technology
• Supplying low CO2 intensity natural gas for
power generation in Asia, displacing coal
11
Husky Energy Inc.
Asia
Pacific
Atlantic
Integrated Corridor Offshore
Two Businesses
Resource
Plays
Thermal
Downstream
12
Rob Symonds
Chief Operating Officer
Husky Energy Inc.
Sunrise Thermal
Gathering System
Long-term Pipeline
Capacity Lima Refinery Toledo Refinery
Hardisty & Lloyd
Storage Terminals
Lloyd Upgrader Asphalt Refinery Lloyd & Tucker Thermal
Production (Q3 ’17)
• 248 mboe/d
• 117 mboe/d thermal bitumen
• Sunrise 20 mboe/d
• Tucker 21 mboe/d
• Lloyd 76 mboe/d
Reserves Base (YE ’16)
• 2.4 billion boe of proved and probable reserves
Heavy Processing Capacity (Q3 ’17)
• 160 mbbls/d
Finished Products (Q3 ’17)
• 54 mbbls/d of sweet synthetic oil
• 16 mbbls/d of asphalt
• 107 mbbls/d of diesel / distillates
• 137 mbbls/d of gasoline
14
Integrated Corridor Unique and Physically Integrated Assets
Superior Refinery
Husky Energy Inc.
Heavy Oil & Thermal Bitumen Production (boe/day)
Q3 '17 2021F
Lloyd thermal 76,400 125,000
Tucker 21,100 30,000
Sunrise 20,200 37,000
Non-thermal (heavy oil) 49,900 29,000
Total 167,600 221,000
Thermal bitumen as % of total 70% 87%
Western Canada Production (boe/day)
Q3 '17 2021F
Resource plays 30,000 50,000
Other W. Canada production 49,900 30,000
Total 79,900 80,000
Resource plays as % of total 38% 63%
Downstream Throughputs Capacity (bbls/day)
Q3 '17 2021F
Heavy oil processing capacity1 160,000 220,000
Light oil processing capacity1 190,000 175,000
Total upgrading and refining capacity1 350,000 395,000
Heavy oil capacity as % of total 46% 56%
15 1 see Slide Notes and Advisories
-
5
10
15
20
25
30
2015 2016 2017F 2018E
Sunrise Production Growth
mbbls/day
-
5
10
15
20
25
30
2014 2015 2016 2017F 2018E
Tucker Production Growth
mbbls/day
Growing/Expanding the Integrated Corridor Reservoir to Refined Products
Husky Energy Inc.
Downstream Connectivity Downstream assets offer optionality of feedstock, product mix and distribution markets
1, 2 see Slide Notes and Advisories 16
0
30
60
90
120
150
180
210
240
270
'18F '19F '20F
Upstream Heavy Oil Blend
Downstream Heavy Oil Blend Throughput Capacity
Bitumen and Heavy Oil Growth matched
with Heavy Oil Processing Capacity1,2
• Integration of over 85% of heavy oil produced
• Mitigates exposure to light / heavy differentials
mbbls/d
Husky Energy Inc.
• Low cost thermal production
• Low cost refining and upgrading
• Higher value, more diverse basket of
finished products1,2
• Higher finished product yield (98%)
• Extensive local market demand
Lloyd Value Chain Operating Netback3 (per bbl)
Lloyd complex avg. realized price $64.98
Operating costs $14.10
Royalties $2.83
Transportation costs $2.81
Lloyd complex avg. processing costs $7.41
Est. Lloyd Value Chain Operating Netback $37.83
Actual Upstream Operating Netback $22.46
* All figures as Q3 2017. Includes Lloyd thermal, non-thermal and Tucker thermal production
1,2,3 see Slide Notes and Advisories 17
Lloyd Advantage Full Value Chain Netback
$15.37 (per bbl)
Additional Netback From
Integrated Operations
Husky Energy Inc.
• Toledo high-TAN project added processing
capacity for all Sunrise crude
• Dilbit delivered directly to Toledo
• no upgrading cost, no volume lost
• High finished product yield (~104% in Q3 ‘17) 1,2
Sunrise to Toledo “One-Step” Refining, No Upgrading Required
Sunrise Value Chain Operating Netback (per bbl) Full Capacity
Toledo realized product price (Q3 '17) $77.82
Expected Sunrise operating costs (at full capacity) ~ $12.00
Royalties ~ $0.50
Typical blending cost ~ $8.00
Typical transportation cost ~ $14.00
Typical Midwest refining cost ~ $8.00
Illustrative Sunrise Value Chain Operating Netback $35.32
Sunrise Upstream Operating Netback (at full capacity) $19.63
* Full Capacity reflects estimates of cost at Sunrise plant capacity of 60,000 bbls/day
18 1,2 see Slide Notes and Advisories
~$15.00 (per bbl)
Additional Netback From
Integrated Operations
Husky Energy Inc.
(1.5)
0.0
1.5
3.0
4.5
(0.5)
0.0
0.5
1.0
1.5
'17F '18F '19F '20F '21F
Funds From Operations Capital Spending Cumulative FCF
Asia Pacific
• High operating netback production
• Fixed-price contracts at favourable prices
• Liwan: $13.05 per mcf
• BD: $9.50 per mcf
• Q3 2017 operating netback of $61.81/boe
• Low level of investment required for growth
over the five-year plan ($0.9 B)
• Defined growth for next 5 years
• Current gas production of 200 mmcf/day with
8,000 boe/day of liquids
• Production to rise to over 270 mmcf/day of gas
with 9,000 boe/day of liquids by ’21
• Mix of near, mid and long-term development
and exploration opportunities
20
Free Cash Flow Growth
$4.2B Cumulative Free Cash Flow Generated ’17 - ’21F
$ billion $ billion
Husky Energy Inc.
Liwan 3-1, Liuhua 34-2 & 29-1 (China)
• Current production of ~170 mmcf/d (3-1 & 34-2)
• Take-or-pay contract 150-165 mmcf/day (net)
• Full project payout forecast in ’18
• Liuhua 29-1 field sanctioned, first gas in 2021
• Development plan to utilize subsea infrastructure
• Gas sales agreement reached
• Exploration cost recovery
BD Project (Madura Strait, Indonesia)
• Gas sales began in July, initial liquids lifting in October
• Peak: 40 mmcf/day gas, 2,400 bbls/day liquids (net)
MBA-MDH, MDK Fields (Madura Strait , Indonesia)
• First gas in 2019, Peak: 60 mmcf/day gas (net)
• Seven development wells planned for 2018
0
50
100
150
200
250
300
350
400
'17F '18F '19F '20F '21F
Wenchang Liwan 3-1, Liuhua 34-2
Liuhua 29-1 Liuhua 29-1 Cost Recovery
BD (Indonesia) MDA-MBH & MDK (Indonesia)
Five-Year Production Profile
>50% Production Growth ’17-’21
21
Low Volatility Growth In Asia Pacific Fixed Price Gas Projects In Growing Gas Demand Regions
mmcfe/d
Husky Energy Inc. 22
Fixed Price Contracts Provide FFO Stability High Asian Gas Prices Deliver $60+ per boe Operating Netbacks
1 see Slide Notes and Advisories
High Operating Netback1
0
4
8
12
16
20
Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3
'14 '15 '16 '17
Husky Realized Asia Gas PriceAECO gas benchmark
Asia Pacific Realized Gas Price
$Cdn/mcf $Cdn/boe
0
20
40
60
80
100
0
20
40
60
80
100
Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3
'15 '16 '17
Asia Pacific Netback Brent Oil
Husky Energy Inc.
Atlantic Canada
Mizzen
Harpoon
Bay du Nord
Baccalieu
Northwest
White Rose Hibernia
Terra Nova
White Rose
Hebron
Bay de
Verde
Proven Track Record:
• Long history of operations in region
• High operating netback production
• $35.86 per boe operating netback (Q3 ’17)
• Production receives Brent+ pricing
• Investment economics enhanced through
tiebacks to existing infrastructure
• Defined growth into next decade
• Exploration upside opportunities
23
Husky Energy Inc.
Next Stages of Atlantic Growth Short, Mid and Long Cycle Projects
0
20
40
60
80
'17F '18F '19F '20F '21F '22F '23F '24F '25F '26F
Future Field
Extension
Opportunities
Project Project
Capital To First Production
Net Peak
Production
After-Tax IRR1 Plan Pricing
Assumption
South White Rose
Extension
infill wells
~$70M
per well
~4,500 bbls/day
per well >30%
West White Rose ~$2.2B
~52,500
bbls/day
~17%
West
White
Rose
White Rose
Base Production
Infill and
Development
Wells
Terra Nova
Atlantic Production Profile
24 1 see Slide Notes and Advisories
mbbls/d
Husky Energy Inc.
• Returns-focused growth
• Investing in a large inventory of low
cost projects
• Low and improving earnings and
cash break-evens
• Strong growth in funds from
operations and free cash flow
• Resilient to volatile market
conditions while preserving upside
25
Value Proposition
Key Metrics ’18F ’21F
Production (mboe/d) 320 – 335 400 (7% CAGR)
Funds from operations (FFO) >$4B _
Free cash flow (FCF) >$1B _
Upstream operating cost/bbl $13-13.50 < $12
Upgrading & U.S refining operating costs ($CAD) $6 - $7 $6 - $7
Earnings break-even oil price (US WTI) ~$42 < $37
Cash break-even oil price (US WTI) ~$32 < $32
Ranges and Targets ’18F ’17F - ’21F
Sustaining capital $1.8 - $1.9B Avg. $1.9B
Capital expenditures $2.9 - $3.1B Avg. $3.3B
Five-year avg. proved reserve replacement ratio _ Target >130%
Net debt to FFO ~ 1.0 < 2x
Husky Energy Inc.
Husky Energy Inc.
Slide 2
1. Funds from operations and free cash flow, as referred to throughout this
presentation, are non-GAAP measures. Please see Advisories for further detail.
2. Earnings break-even and cash break-even prices, as referred to throughout this
presentation, are non-GAAP measures. Please see Advisories for further detail.
3. Capital spending, as referred to throughout this presentation, excludes asset
retirement obligations and capitalized interest unless otherwise indicated.
4. Capital expenditures in Asia Pacific exclude amounts related to the Husky-
CNOOC Madura Ltd. joint venture, which is accounted for under the equity
method for financial statement purposes.
5. Net debt and net debt to funds from operations, as referred to throughout this
presentation, are non-GAAP measures. Please see Advisories for further detail.
Slide 3
1. Funds from operations and free cash flow forecast for 2018 based on WTI price
of $55 US per barrel, CAD$2.50/mmbtu gas price, 0.78 US/CAD exchange rate
and US$15 Chicago 3-2-1 crack spread.
Slide 5
1. Funds from operations and free cash flow forecast for 2018 based on WTI price
of $50 US per barrel, CAD$2.50/mmbtu gas price, 0.78 US/CAD exchange rate
and US$15 Chicago 3-2-1 crack spread.
2. Funds from operations and free cash flow forecast for 2018 based on WTI price
of $55 US per barrel, CAD$2.50/mmbtu gas price, 0.78 US/CAD exchange rate
and US$15 Chicago 3-2-1 crack spread.
Slide Notes
Slide 7
1. Other than as indicated in the Advisories, 10% IRR calculations are based on
proved and probable reserves.
2. Gas portfolio break-even prices include assumed associated liquids prices
based on a US$40 WTI price scenario.
3. Downstream portfolio IRR is not directly tied to oil or gas price. See Advisories
for further detail.
4. Projects Included in Plan Spending Period reflect projects that the Company
will allocate capital spending to during the 2018-2021 timeframe.
Slide 8
1. Upstream operating netback, as referred to throughout this presentation, is a
non-GAAP measure. Please see Advisories for further detail.
Slide 10
1. Net debt to trailing funds from operations, as referred to throughout this
presentation, is a non-GAAP measure. Please see Advisories for further detail.
All figures as of September 30, 2017.
2. Husky has redemption option on Preferred Shares.
Slide 15
1. Includes acquisition of the Superior Refinery, which closed in Q4 2017.
27
Husky Energy Inc.
Slide Notes
28
Slide 16
1. Production volumes represent blended heavy oil volumes (bitumen, heavy oil
and diluent).
2. Throughput represents Husky’s 100% interest in the heavy processing capacity
at the Prince George Refinery, Lloydminster Refinery, Lloydminster Upgrader,
Lima Refinery, Superior Refinery and 50% interest in the Toledo Refinery.
Slide 17
1. Product variability can be influenced by several factors, including seasonal
demand, access to feedstock and distribution system interruptions, among
others.
2. Products include Husky Synthetic Blend, asphalt and Ultra Low Sulphur Diesel
(ULSD), among others.
3. Value chain operating netback, as referred to throughout this presentation, is a
non-GAAP measure. Please see Advisories for further detail.
Slide 18
1. Product variability can be influenced by several factors, including seasonal
demand, access to feedstock, distribution system interruptions, among others.
2. Products include gasoline, distillate, Ultra Low Sulphur Diesel (ULSD), propane,
benzene, Sulfur, LPG, LVGO, HVGO, heavy fuels, petro-chemicals and various
other by-products.
Slide 22
1. Q3 2016 Operating Netback reflects the impact of a price adjustment for natural
gas from the Liwan 3-1 and Liuhua 34-2 fields, per the Heads of Agreement
("HOA") signed by the Company with CNOOC Limited in Q3 2016. The price
adjustment under the HOA is effective as of November 2015 and a retroactive
adjustment was recognized in Q3 2016.
Slide 24
1. After-Tax IRRs are calculated using Price Planning Assumptions as shown on
slide 33 and, other than as indicated in the Advisories, are based on proved and
probable reserves.
Slide 37
1. Capital expenditures include exploration capital in each business unit.
2. Asia Pacific oil & NGLs operating costs and capital expenditures reflected in Asia
Pacific natural gas.
3. Capital expenditures in Asia Pacific exclude amounts related to the Husky-
CNOOC Madura Ltd. joint venture, which is accounted for under the equity
method for financial statement purposes.
4. Downstream capital expenditures include scheduled turnarounds.
5. Lloyd and Tucker thermal operating costs include energy and non-energy costs.
6. Downstream operating costs excludes the impact of scheduled
turnarounds in 2018.
Slide 39
1. Husky has a 50% working interest in the Toledo Refinery.
Husky Energy Inc.
Advisories
Forward-looking Statements and Information
Certain statements in this presentation, including "financial outlook", are forward-looking statements and information (collectively "forward-looking statements"), within the meaning of the
applicable Canadian securities legislation, Section 21E of the United States Securities Exchange Act of 1934, as amended, and Section 27A of the United States Securities Act of 1933, as
amended. The forward-looking statements contained in this presentation are forward-looking and not historical facts.
Some of the forward-looking statements may be identified by statements that express, or involve discussions as to, expectations, beliefs, plans, objectives, assumptions or future events or
performance (often, but not always, through the use of words or phrases such as "will likely result", "are expected to", "will continue", "is anticipated", "is targeting", "estimated", "intend", "plan",
"projection", "could", "aim", "vision", "goals", "objective", "target", "schedules" and "outlook"). In particular, forward-looking statements in this presentation include, but are not limited to,
references to:
• with respect to the business, operations and results of the Company generally: the Company’s general strategic plans and growth strategies; forecasted production, FFO, FCF, upstream
operating cost per barrel, downstream realized refining margins/bbl, earnings break-even oil price and cash break-even oil price for 2017, 2018 and by 2021 and range and targets for
sustaining capital, capital spending, five-year average proved reserve replacement ratio and net debt to FFO from 2017 to 2021; forecast production compound annual growth rate from
2018 to 2021; forecast downstream throughputs for 2018 and 2021; forecast 2018 production by business unit and 2018 capital spending by region; forecast 2018 FCF, FFO, portfolio
investment and sustaining capital at US$50 WTI and US$55 WTI per barrel; forecast 2018, 2019 and 2020 heavy oil processing capacity; forecast production from the Company’s
Integrated Corridor in 2021; forecast sustaining capital and annual average for 2017 to 2021, including annual average upstream sustaining cost per boe, sustaining capital and cash
break-even for such period; forecast net debt for the period from 2017 to 2021; forecast break-evens for the years 2017 to 2021; five-year plan milestones in respect of the Company’s
Integrated Corridor and Offshore projects; capital spending for the years 2017 to 2021; forecast upstream operating costs, upstream operating netbacks and downstream margins for 2017
to 2021; Integrated Corridor and Offshore FFO generation and cash capital less asset retirement obligations at flat $50 US WTI for the years 2017 to 2021; forecast FFO, sustaining
capital, discretionary capital and net debt to FFO assuming $35 US WTI for 2017 and 2021; forecast thermal, non-thermal and Western Canada production for 2021, broken down by
thermal project; prices required to generate targeted IRR for the Company’s listed in-flight and future projects; and total spending for in-flight and future projects and percentage spent in
short to mid-cycle;
• with respect to the Company's thermal developments in the Integrated Corridor: Sunrise plant capacity; expected Sunrise operating costs at full capacity; and forecast Sunrise and Tucker
production growth for 2017 and 2018;
• with respect to the Company's Offshore business in Asia Pacific region: forecasted FFO, capital spending and FCF for the years 2017 to 2021; expected production in 2021; five-year
production profile for Wenchang, Liwan 3-1 and Liuhua 34-2, Liuhua 29-1, Liuhua 29-1 Cost Recovery, BD (Indonesia) and MDA-MBH & MDK (Indonesia); and expected timing for full
project payout for Liwan 3-1 and Liuhua 34-2 and 29-1; and
• with respect to the Company's Offshore business in the Atlantic region: after-tax IRR, capital and peak production at the South White Rose extension infill wells and West White Rose; and
10-year production profile for the region broken down by project.
29
Husky Energy Inc.
Advisories
In addition, statements 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 or resources described can be profitably produced in the future. There are numerous uncertainties inherent in estimating quantities of reserves and resources
and in projecting future rates of production and the timing of development expenditures. The total amount or timing of actual future production may vary from reserve, resource and production
estimates.
Certain of the information in this presentation is “financial outlook” within the meaning of applicable securities laws. The purpose of this financial outlook is to provide readers with disclosure
regarding the Company’s reasonable expectations as to the anticipated results of its proposed business activities. Readers are cautioned that this financial outlook may not be appropriate for
other purposes.
Although the Company believes that the expectations reflected by the forward-looking statements presented in this presentation are reasonable, the Company’s forward-looking statements
have been based on assumptions and factors concerning future events, including timing of regulatory approvals, that may prove to be inaccurate. Those assumptions and factors are based on
information currently available to the Company about itself and the businesses in which it operates. Information used in developing forward-looking statements has been acquired from various
sources including third party consultants, suppliers, regulators and other sources.
Because actual results or outcomes could differ materially from those expressed in any forward-looking statements, investors should not place undue reliance on any such forward-looking
statements. By their nature, forward-looking statements involve numerous assumptions, inherent risks and uncertainties, both general and specific, which contribute to the possibility that the
predicted outcomes will not occur. Some of these risks, uncertainties and other factors are similar to those faced by other oil and gas companies and some are unique to Husky.
The Company’s Annual Information Form for the year ended December 31, 2016 and other documents filed with securities regulatory authorities (accessible through the SEDAR website
www.sedar.com and the EDGAR website www.sec.gov) describe risks, material assumptions and other factors that could influence actual results and are incorporated herein by reference.
New factors emerge from time to time and it is not possible for management to predict all of such factors and to assess in advance the impact of each such factor on the Company’s business
or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statement. The impact of any one factor on
a particular forward-looking statement is not determinable with certainty as such factors are dependent upon other factors, and the Company's course of action would depend upon
management’s assessment of the future considering all information available to it at the relevant time. Any forward-looking statement speaks only as of the date on which such statement is
made and, except as required by applicable securities laws, the Company undertakes no obligation to update any forward-looking statement to reflect events or circumstances after the date
on which such statement is made or to reflect the occurrence of unanticipated events.
30
Husky Energy Inc.
Advisories
Non-GAAP Measures
This presentation contains certain terms which do not have any standardized meanings prescribed by IFRS and are therefore unlikely to be comparable to similar measures presented by other
issuers. None of these measurements are used to enhance the Company's reported financial performance or position. With the exception of funds from operations and free cash flow, there
are no comparable measures to these non-GAAP measures in accordance with IFRS. The following non-GAAP measures are considered to be useful as complementary measures in
assessing Husky's financial performance, efficiency and liquidity:
• "Funds from operations" or "FFO" is a non-GAAP measure which should not be considered an alternative to, or more meaningful than, "cash flow – operating activities" as determined in
accordance with IFRS, as an indicator of financial performance. Funds from operations is presented in the Company’s financial reports to assist management and investors in analyzing
operating performance by business in the stated period. Funds from operations equals cash flow – operating activities plus items not affecting cash, which include settlement of asset
retirement obligations, deferred revenue, income taxes received (paid), interest received and change in non-cash working capital.
• "Free cash flow" or "FCF" is a non-GAAP measure which should not be considered an alternative to, or more meaningful than, "cash flow – operating activities" as determined in
accordance with IFRS, as an indicator of financial performance. Free cash flow is presented in this presentation to assist management and investors in analyzing operating performance
by business in the stated period. Free cash flow equals funds from operations less capital expenditures.
• "Net debt" is a non-GAAP measure that equals total debt less cash and cash equivalents. Total debt is calculated as long-term debt, long-term debt due within one year and short-term
debt. Net debt is considered to be a useful measure in assisting management and investors to evaluate the Company's financial strength.
• "Net debt to funds from operations" is a non-GAAP measure that equals net debt divided by funds from operations. Net debt to funds from operations is considered to be a useful measure
in assisting management and investors to evaluate the Company's financial strength.
• "Net debt to trailing funds from operations" is a non-GAAP measure that equals net debt by the 12-month trailing funds from operations as at September 30, 2017. Net debt to trailing
funds from operations is considered to be a useful measure in assisting management and investors to evaluate the Company's financial strength.
• “Upstream operating netback" is a common non-GAAP metric used in the oil and gas industry. This measure assists management and investors to evaluate the specific operating
performance by product at the oil and gas lease level. Upstream operating netback is calculated as realized price less royalties, operating costs and transportation costs on a per unit
basis.
31
Husky Energy Inc.
Advisories
• “Value chain operating netback" is a non-GAAP metric used in the oil and gas industry. This measure assists investors to evaluate the operating performance of the Integrated Corridor.
Value chain operating netback is calculated as an average realized price of synthetic crude and other refined products less royalties, operating costs, transportation costs and processing
costs on a per unit basis.
• "Earnings break-even" reflects the estimated WTI oil price per barrel priced in US dollars required in order to generate a net income of Cdn $0 over a 12-month period ending December 31.
This assumption is based on holding several variables constant throughout the period, including: foreign exchange rate, light-heavy oil differentials, realized refining margins, forecast
utilization of downstream facilities, estimated production levels, and other factors consistent with normal oil and gas company operations. Earnings break-even is used to assess the impact
of changes in WTI oil prices on the net earnings of the Company and could impact future investment decisions.
• "Cash break-even" reflects the estimated WTI oil price per barrel priced in US dollars required in order to generate funds from operations equal to the Company’s sustaining capital
requirements in Canadian dollars over a 12-month period ending December 31. This assumption is based on holding several variables constant throughout the period, including: foreign
exchange rate, light-heavy oil differentials, realized refining margins, forecast utilization of downstream facilities, estimated production levels, and other factors consistent with normal oil and
gas company operations. Cash break-even is used to assess the impact of changes in WTI oil prices on the net earnings of the Company and could impact future investment decisions.
Disclosure of Oil and Gas Information
Unless otherwise indicated: (i) reserves and resources estimates in this presentation have been prepared by internal qualified reserves evaluators in accordance with the Canadian Oil and Gas
Evaluation Handbook, have an effective date of December 31, 2016 and represent the Company's working interest share; (ii) projected and historical production volumes provided represent the
Company’s working interest share before royalties; and (iii) historical production volumes provided are for the year ended December 31, 2016. The Company has disclosed its total reserves in
Canada in its Annual Information Form for the year ended December 31, 2016, which reserves disclosure is incorporated by reference in this presentation.
The estimates of reserves and future net revenue for individual properties may not reflect the same confidence level as estimates of reserves and future net revenue for all properties, due to the
effects of aggregation.
IRR calculations shown in this presentation are based on holding several variables constant throughout the period, including estimated WTI oil price per barrel priced in US dollars, foreign
exchange rate, light-heavy oil differentials, realized refining margins, forecast utilization of downstream facilities, estimated production levels, and other factors consistent with normal oil and gas
company operations. This measure is used to assess potential return generated from investment opportunities and could impact future investment decisions. This measure does not have any
standardized meaning and should not be used to make comparisons to similar measures presented by other issuers. IRR calculations in this presentation are based on proved and probable
reserves, except for the IRR calculations for the projects described below, in which cases the IRR calculations are based on resources.
32
Husky Energy Inc.
Advisories
Husky’s Lloydminster Heavy Oil and Gas thermal bitumen unrisked best estimate contingent resources consist of 268 million barrels of economic development pending, 164 million barrels of
economic development unclarified and 554 million barrels of economic status undetermined development unclarified. The figures represent Husky’s working interest volumes. The
development pending category consists of 11 steam assisted gravity drainage (SAGD) projects and one combined SAGD and cyclic steam stimulation (CSS) project that have been scheduled
for initial production starting in 2019 through to 2040. The first three projects have a total capital cost to first production of $1.1 billion based upon the pre-development studies. The estimated
total capital to fully develop these 12 development pending projects is approximately $8 billion.
The economic and economic status undetermined development unclarified projects require additional technical and commercial analysis of the conceptual SAGD or CSS studies. Of these,
the first project requires $0.4 billion to achieve commercial production in 2030. The remaining projects are to be developed over more than 50 years in accordance with the conceptual studies
for this large resource. In total, 311 million barrels of thermal bitumen are based upon pre-development studies while an additional 675 million barrels of thermal bitumen are based upon
conceptual plans. This oil is reported as thermal bitumen and has viscosities ranging from 12,800 centipoise (cP) to as high as 600,000 cP with gravities between 9 and 12 degrees API.
Specific contingencies preventing the classification of contingent resources at the Company’s Lloydminster Heavy Oil thermal contingent resources as reserves include the need for further
reservoir studies, delineation drilling, verification of sub-zone continuity and quality that would enable feasible implementation of a thermal scheme, the formulation of concrete development
plans and facility designs to pursue development of the large inventory of opportunities, the Company’s capital commitment, development over a time frame much greater than the reserve
timing window and regulatory applications and approvals. Positive and negative factors relevant to the contingent resource estimates include potential reservoir heterogeneity in sub-zones
which may limit the applicability of thermal schemes, a higher level of uncertainty in the estimates as a result of lower drilling density in some projects and current lack of development plans in
the unclarified contingent resources. The main risks are the low well density and the associated geological uncertainties in certain projects, the production performance and recovery long
term, future commodity prices and the capital costs associated with wells and facilities planned over an extended future period of time.
McMullen contains unrisked best estimate economic development pending contingent resources of 44 million barrels of bitumen for Phase 1 of the development with a further 1.3 billion barrels
of bitumen of unrisked best estimate economic status undetermined development unclarified contingent resources. McMullen is a thermal play in the Wabiskaw formation covering over 130
sections southwest of Wabasca. Husky has a working interest of 100 percent. The cost to first production for Phase 1, based upon the pre-development study, is approximately $452 million
for the initial commercial demonstration facility and horizontal cyclic steam stimulation (HCSS) wells in 2023. The results of the commercial demonstration will be utilized to refine the
subsequent phases that are based upon a conceptual development plan at this time and each has the same capital estimate with initial production scheduled for 2028 for Phase 2. The total
commercial facilities and wells will be developed over more than 50 years at an estimated total cost of $40 billion in accordance with the conceptual study for this large resource. The
development of these projects depends on the results of the technical analysis, future bitumen prices and the Company’s commitment to dedicate capital to this large inventory of projects.
Specific contingencies preventing the classification of contingent resources at the McMullen thermal development project as reserves include the need for further reservoir studies, delineation
drilling, facility design, preparation of firm development plans, regulatory applications and approvals and Company approvals. Positive and negative factors relevant to the estimates of these
resources include a higher level of uncertainty in the estimates as a result of lower core-hole drilling density. The main risks are the low well density and the associated geological
uncertainties, the production performance and recovery long term and the capital costs associated with wells and facilities planned over an extended future period of time.
33
Husky Energy Inc.
Advisories
The Ansell liquids-rich natural gas resource play is located in the deep basin Cretaceous formations of west-central Alberta, and Husky has an average 92 percent working interest. Husky is
actively developing Ansell. This producing property contains unrisked best estimate economic development pending contingent resources of 248 million barrels of oil equivalent, consisting of
1.4 Tcf of natural gas and 14 million barrels of natural gas liquids (NGL). Ansell also includes unrisked best estimate economic development on hold contingent resources of 174 million
barrels of oil equivalent from the Cardium formation, consisting of 0.8 Tcf of natural gas and 35 million barrels of NGL from approximately 300 potential drilling opportunities. The initial
contingent resource fracture stimulated horizontal wells are scheduled to be drilled starting in 2024, following the development of the proved and probable reserves. The cost to achieve initial
commercial production is the cost of the first well of $4.5 million. The remaining development pending drilling opportunities (259 working interest) will be drilled over the next 10 to 20 years in
accordance with the pre-development study for the resource play. Specific contingencies preventing the classification of contingent resources in the Ansell liquids-rich resource play as
reserves include the timing of development which is outside the timing allowed for booking as reserves and final Company approvals of capital expenditures. Positive and negative factors
relevant to the estimate of Ansell contingent resources include a lower level of uncertainty in the estimates as a result of the large number of producing wells, extensive production history from
the property, Husky’s large contiguous land base and Husky’s ownership of existing infrastructure in the area. Key risks include the performance of future wells when the play is expanded and
reducing costs to achieve optimal results in a low gas and NGL price environment.
Liuhua 29-1, located in the South China Sea approximately 300 km southeast of the Hong Kong Special Administrative Region, contains unrisked best estimate economic development
pending contingent resources of 28 million barrels of oil equivalent, consisting of 139 Bcf of natural gas and 5 million barrels of condensate. Husky has a working interest of 49 percent. The
project uses conventional offshore gas wells and will be connected to the producing Liwan gas field. Based on the pre-development study, the cost to first production to complete and tie-in the
well is approximately $650 million with an on-stream date in 2018. The development of this project depends on the Company's and its partners’ commitment to dedicate capital to the project.
Specific contingencies preventing the classification of contingent resources for Liuhua 29-1 are the signing of a gas sales agreement and regulatory approvals. Positive and negative factors
relevant to the estimates of these resources include a higher level of certainty in the estimates as a result of extensive appraisal drilling and testing. The main risk is the production
performance and recovery long term.
Husky's Lloydminster Heavy Oil cold heavy oil production with sand (CHOPs) and Horizontal well opportunity includes 189 million barrels (Husky’s working interest) of unrisked economic best
estimate contingent resources in the development pending sub-class and a further 593 million barrels (Husky’s working interest) of unrisked best estimate contingent resources in the
development unclarified sub-class with the economic status undetermined. A typical CHOPS well has a cost estimate to drill, complete and equip of $580,000, while a five-well horizontal pad
has a cost estimate of $7.1 million with the first developments online in 2026 based on a pre-development study. This is a continuation of the CHOPs and horizontal well development
programs which have been proven to be successful in the Lloydminster area. The timing of development and Company approvals are the main contingencies preventing the booking of these
volumes as reserves. Positive and negative factors relevant to these contingent resources include a lower level of uncertainty in the estimates as a result of the large number of producing
wells, extensive production history from the property, Husky's large contiguous land base and Husky's ownership of existing infrastructure in the area. The key risk is the execution of a multi-
year program and reducing capital and operating costs in a low heavy oil price environment.
34
Husky Energy Inc.
Advisories
Heavy Oil Cold EOR, located in the Lloydminster area, contains 307 million barrels (Husky’s working interest) of unrisked economic status undetermined best estimate contingent resources in
the development unclarified sub-class. Cold EOR Solvent Injection is a cyclic process utilizing CO2 which has been demonstrated to be technically successful in the area. The wells and area
have been identified in the conceptual development study, but more detailed development plans are required for each field. The first phase of the projects is planned for 2021 with a capital
cost of $207 million to reach first oil production in one of the identified fields. The timing of development, regulatory and Company approvals are the specific contingencies preventing the
booking of these volumes as reserves as well as the need for additional assessment for the area where the economic status is undetermined. Positive and negative factors include the
extensive land base and infrastructure while the ultimate recovery for this technology is still being evaluated in the field. Key risks include the range of uncertainty in the ultimate recovery and
accessing a long term supply of CO2 for the projects.
The Company uses the term "barrels of oil equivalent" (or "boe") and "thousand cubic feet of gas equivalent" (or "mcfe"), which are consistent with other oil and gas companies’ disclosures.
Boe amounts have been calculated by using the conversion ratio of 6 mcf of natural gas to 1 bbl of oil and mcfe amounts have been calculated by using the conversion ratio of 1 bbl of oil or
NGL to 6 mcf of natural gas. A boe conversion ratio of 6 mcf: 1 bbl and an mcfe conversion ratio of 1 bbl: 6 mcf are based on an energy equivalency conversion method primarily applicable at
the burner tip and do not represent value equivalency at the wellhead. Readers are cautioned that the terms boe and mcfe may be misleading, particularly if used in isolation.
"Sustaining cost per boe" is the additional development capital that is required by the business to maintain production and operations at existing levels on a per unit basis. It is calculated as
sustaining capital divided by EUR. Sustaining cost per boe does not have any standardized meaning and therefore should not be used to make comparisons to similar measures presented by
other issuers.
The Company uses the term "reserve replacement ratio", which is consistent with other oil and gas companies’ disclosures. Reserve replacement ratios for a given period are determined by
taking the Company's incremental proved reserve additions for that period divided by the Company's upstream gross production for the same period. The reserve replacement ratio measures
the amount of reserves added to a company's reserve base during a given period relative to the amount of oil and gas produced during that same period. A company's reserve replacement
ratio must be at least 100 percent for the company to maintain its reserves. The reserve replacement ratio only measures the amount of reserves added to a company's reserve base during a
given period.
EUR (estimated ultimate recovery) estimates referred to in this presentation have been prepared by internal qualified reserves engineer and in accordance with COGEH. EUR reflects the
unrisked proved plus profitable estimate.
Note to U.S. Readers
The Company reports its reserves and resources information in accordance with Canadian practices and specifically in accordance with National Instrument 51-101 Standards of Disclosure for
Oil and Gas Activities, adopted by the Canadian securities regulators. Because the Company is permitted to prepare its reserves and resources information in accordance with Canadian
disclosure requirements, it may use certain terms in that disclosure that U.S. oil and gas companies generally do not include or may be prohibited from including in their filings with the SEC.
All currency is expressed in Canadian dollars unless otherwise directed.
35
Husky Energy Inc.
Husky Energy Inc.
2018 Guidance Planning Assumptions Updated December 4, 2017
1,2,3,4,5,6 see Slide Notes and Advisories 37
Upstream Capital Expenditures1 Production Corporate Costs ($ millions) Upstream Operating Costs ($/bbl)
Oil and Liquids ($ millions) (mbbls/day) Corporate Capital 100 - 110 Lloyd and Tucker thermal5 9.50 - 10.50
Lloyd & Tucker thermal bitumen 835 - 860 103 - 110 Total Capital Budget 2,940 - 3,125 Atlantic Region light oil 18.50 - 19.50
Sunrise thermal bitumen 60 - 70 25 - 27 ($/mcfe)
Lloyd Non-Thermal 85 - 90 45 - 47 Other ($ millions) Resource Play Natural Gas 1.00 - 1.30
Atlantic light 750 - 775 34 - 35 Capitalized Interest 110 - 120 Asia Pacific Region Gas 1.00 - 1.25
W. Canada Light, medium, heavy & NGLs 55 - 60 21 - 22 Corporate SG&A 175 - 225
Asia Pacific light & NGLs2,3 - - 10 - 11 ($/boe)
Total Crude Oil and Liquids 1,785 - 1,855 240 - 252 Sustaining Capital ($ millions) Total Upstream Operating Costs 13.00 - 13.50
Upstream 1,275 - 1,325
Natural Gas ($ millions) (mmcf/day) Downstream 500 - 550 Downstream Operating Costs6 ($/boe)
Canada 215 - 225 280 - 290 Total Sustaining Capital 1,775 - 1,875 Lloyd Upgrader 6.50 - 7.50
Asia Pacific3 130 - 150 200 - 210 US Refineries 6.00 - 7.00
Total Natural Gas 345 - 375 480 - 500
($ millions) (mboe/day)
Total Upstream 2,130 - 2,230 320 - 335
Throughput 4 2018 Pricing Assumptions
Downstream ($ millions) (mbbls/day) WTI, Cushing ($US/bbl)
Canada downstream 130 - 160 110 - 115 3-2-1 Chicago Crack ($US/bbl)
U.S. downstream 580 - 625 250 - 255 Natural Gas, AECO ($Cdn/mcf)
Downstream Total 710 - 785 360 - 370 Exchange Rate ($US/$Cdn)
2.50
0.78
55.00
15.00
Husky Energy Inc.
Today’s Portfolio 2021 Portfolio
$35 US WTI
$12 US Chicago 3-2-1 Crack
<2x Net Debt /
FFO
$1.8B Sustaining
Capital
$0.1B Discretionary
$1.9B FFO
<2x Net Debt /
FFO
$2.1B Sustaining
Capital
$1.0B Discretionary
Today vs. 2021: What We Could Do at $35 US WTI As Assets Improve, Funds from Operations, Free Cash Flow and Debt Capacity Increase
$35 US WTI
$12 US Chicago 3-2-1 Crack
38
$3.1B FFO
Husky Energy Inc.
Downstream Assets
Lloyd Upgrader
Asphalt Refinery Gathering System
Lima Refinery
Toledo Refinery
Hardisty & Lloyd
Storage Terminals
Capacity: 80 mbbls/d
• Produces Husky
Synthetic Crude (HSB)
• Low operating costs
Lloyd Complex U.S. Refining & Marketing Pipelines & Storage
• 110,000 bbls/day processing capacity
• Physically connected to Lloyd and
Tucker production
• 290,000 bbls/day processing capacity
• Product marketing footprint centered in
Ohio
• Five million barrels tank storage
• 75,000+ bbls/day takeaway capacity
3.1 mmbbls at
Hardisty
1.0 mmbbls at Lloyd
• Profitable blending
business
• Increases flexibility
in marketing crude
Capacity: 30 mbbls/d
• Supplies ~4% of asphalt
manufactured in
North America
• Lloyd feedstock
provides for premium
quality
• Transportation by rail
Capacity: 80 mbbls/d1
• Configured to process high-
TAN Sunrise crude
• Husky markets its products as
well as secondary products on
behalf of JV
• Firm takeaway
commitments
• Connections to several
main pipelines ensure
Husky crude can
reach market
Capacity: 160 mbbls/d
• Light oil refinery
• Access to diverse
crude supply
39 1 see Slide Notes and Advisories
Superior Refinery
Capacity: 50 mbbls/d
• Light / Heavy oil refinery
• Asphalt, diesel, gasoline
