Commenting on the Company's second quarter 2020 results, Tim McKay,
President of Canadian Natural, stated "Canadian Natural is in a
strong position as a result of our capital flexibility and
continued focus on cost control, which maximizes margins in a
volatile commodity price environment. The effectiveness of our
strategies and our ability to execute on those strategies allows us
to react quickly to changing markets and commodity price
volatility.
In Q2/20, we delivered top tier operational
results, producing approximately 1,165 MBOE/d, including liquids
production of approximately 922 Mbbl/d, as our teams worked
effectively to bring the majority of the voluntary curtailed
volumes back on production in June 2020. Importantly, in our Oil
Sands Mining and Upgrading assets, we achieved record quarterly
production of high value Synthetic Crude Oil ("SCO") of
approximately 464,300 bbl/d, inclusive of planned maintenance at
Horizon in May. As well, we achieved record low Oil Sands Mining
and Upgrading operating costs of $17.74/bbl (US$12.80/bbl) in Q2/20
levels, a 15% decrease from Q1/20, by continuing to focus on cost
control.
In response to COVID-19, the Company implemented
comprehensive precautions to ensure the health and safety of our
workers while maintaining safe, reliable operations. We continue to
focus on our environmental, social and governance ("ESG")
performance throughout this volatility. ESG performance remains a
top priority within the Company and there has been no change to our
environmental targets set in December 2019, nor our environmental
focused investments, which help reduce our environmental footprint
and our GHG emissions, despite the economic impacts of
COVID-19."
Canadian Natural's Chief Financial Officer, Mark
Stainthorpe, added "The Company maintains a flexible and
disciplined capital allocation strategy, with a focus on
maintaining a strong financial position throughout the commodity
price cycle. We have been proactive in managing our balance sheet
and executing on our capital flexibility, with our targeted 2020
capital program on track at approximately $2.7 billion, while
maintaining strong production levels throughout the year.
We generated adjusted funds flow of $415 million
in Q2/20, reflecting the strength of the Company's long life low
decline asset base, effective and efficient operations and our
ability to maximize netbacks. Maximizing value for our
shareholders, the Company elected to store as inventory at
quarter end, a higher portion than normal of our SCO and
International light crude oil production in the low commodity
price quarter. If these barrels had been sold during the second
quarter of 2020, based on June 2020 commodity prices, the Company
would have generated approximately $60 million in additional cash
flows from operating activities and adjusted funds flow in the
quarter.
Our long life low decline assets continue
to have industry leading low breakeven prices required to cover our
low sustaining capital requirements and our current dividend,
of approximately US$30 to US$31 WTI per barrel, reflecting our
effective and efficient operations and our low to no reservoir
risk, a distinct advantage in a volatile price environment. As a
result, a small percentage of our total proved reserves are
produced during challenging commodity price periods, resulting in
very little impact to the Company's net asset value, thereby
preserving long-term value for our shareholders and creditors.
At June 30, 2020, liquidity was strong at
approximately $4.1 billion. As previously announced, in June
we successfully completed the issue of two US dollar
denominated bonds raising approximately $1.5 billion (US$1.1
billion). The Company's balance sheet remains resilient through
this commodity price cycle, supported by strong investment grade
credit ratings. In the second half of 2020, targeted free cash flow
generation is significant, supporting a sustainable dividend and at
current strip pricing targeted net debt at year end December 31,
2020 to be flat year-over-year."
QUARTERLY HIGHLIGHTS
|
|
Three Months Ended |
|
|
Six Months Ended |
|
|
|
|
|
|
|
|
|
|
|
|
($ millions,
except per common share amounts) |
|
Jun 30 2020 |
|
Mar 31 2020 |
|
Jun 30 2019 |
|
|
Jun 30 2020 |
|
Jun 30 2019 |
Net
earnings (loss) |
|
$ |
(310 |
) |
|
|
$ |
(1,282 |
) |
|
|
$ |
2,831 |
|
|
|
$ |
(1,592 |
) |
|
|
$ |
3,792 |
|
Per common share |
– basic |
|
$ |
(0.26 |
) |
|
|
$ |
(1.08 |
) |
|
|
$ |
2.37 |
|
|
|
$ |
(1.35 |
) |
|
|
$ |
3.17 |
|
|
– diluted |
|
$ |
(0.26 |
) |
|
|
$ |
(1.08 |
) |
|
|
$ |
2.36 |
|
|
|
$ |
(1.35 |
) |
|
|
$ |
3.16 |
|
Adjusted net
earnings (loss) from operations (1) |
|
$ |
(772 |
) |
|
|
$ |
(295 |
) |
|
|
$ |
1,042 |
|
|
|
$ |
(1,067 |
) |
|
|
$ |
1,880 |
|
Per common share |
– basic |
|
$ |
(0.65 |
) |
|
|
$ |
(0.25 |
) |
|
|
$ |
0.87 |
|
|
|
$ |
(0.90 |
) |
|
|
$ |
1.57 |
|
|
– diluted |
|
$ |
(0.65 |
) |
|
|
$ |
(0.25 |
) |
|
|
$ |
0.87 |
|
|
|
$ |
(0.90 |
) |
|
|
$ |
1.57 |
|
Cash flows (used
in) from operating activities |
|
$ |
(351 |
) |
|
|
$ |
1,725 |
|
|
|
$ |
2,861 |
|
|
|
$ |
1,374 |
|
|
|
$ |
3,857 |
|
Adjusted funds
flow (2) |
|
$ |
415 |
|
|
|
$ |
1,337 |
|
|
|
$ |
2,652 |
|
|
|
$ |
1,752 |
|
|
|
$ |
4,892 |
|
Per common share |
– basic |
|
$ |
0.35 |
|
|
|
$ |
1.13 |
|
|
|
$ |
2.22 |
|
|
|
$ |
1.48 |
|
|
|
$ |
4.09 |
|
|
– diluted |
|
$ |
0.35 |
|
|
|
$ |
1.13 |
|
|
|
$ |
2.22 |
|
|
|
$ |
1.48 |
|
|
|
$ |
4.08 |
|
Cash flows used in
investing activities |
|
$ |
693 |
|
|
|
$ |
859 |
|
|
|
$ |
4,464 |
|
|
|
$ |
1,552 |
|
|
|
$ |
5,493 |
|
Net capital
expenditures (3) |
|
$ |
421 |
|
|
|
$ |
838 |
|
|
|
$ |
4,125 |
|
|
|
$ |
1,259 |
|
|
|
$ |
5,102 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Daily production,
before royalties |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (MMcf/d) |
|
1,462 |
|
|
|
1,440 |
|
|
|
1,532 |
|
|
|
1,451 |
|
|
|
1,521 |
|
Crude oil and NGLs (bbl/d) |
|
921,895 |
|
|
|
938,676 |
|
|
|
770,409 |
|
|
|
930,286 |
|
|
|
776,924 |
|
Equivalent production (BOE/d) (4) |
|
1,165,487 |
|
|
|
1,178,752 |
|
|
|
1,025,800 |
|
|
|
1,172,120 |
|
|
|
1,030,480 |
|
(1) Adjusted net earnings (loss) from operations
is a non-GAAP measure that the Company utilizes to evaluate its
performance, as it demonstrates the Company’s ability to generate
after-tax operating earnings from its core business areas. The
derivation of this measure is discussed in the "Advisory" section
of this press release.(2) Adjusted funds flow is a non-GAAP measure
that the Company considers key to evaluate its performance as it
demonstrates the Company’s ability to generate the cash flow
necessary to fund future growth through capital investment and to
repay debt. The derivation of this measure is discussed in the
"Advisory" section of this press release.(3) Net capital
expenditures is a non-GAAP measure that the Company considers a key
measure as it provides an understanding of the Company’s capital
spending activities in comparison to the Company's annual capital
budget. For additional information and details, refer to the net
capital expenditures table in the "Advisory" section of this press
release.(4) A barrel of oil equivalent (“BOE”) is derived by
converting six thousand cubic feet (“Mcf”) of natural gas to one
barrel (“bbl”) of crude oil (6 Mcf:1 bbl). This conversion may be
misleading, particularly if used in isolation, since the 6 Mcf:1
bbl ratio is based on an energy equivalency conversion method
primarily applicable at the burner tip and does not represent a
value equivalency at the wellhead. In comparing the value ratio
using current crude oil prices relative to natural gas prices, the
6 Mcf:1 bbl conversion ratio may be misleading as an indication of
value.
- A net loss of $310 million was
realized in Q2/20, while the adjusted net loss in Q2/20 was $772
million.
- Cash flows used in operating
activities were $351 million in Q2/20.
- Adjusted funds flow of $415 million
in Q2/20 reflect the strength of the Company's long life low
decline asset base and its effective and efficient operations.
- Maximizing value for shareholders, the Company elected to store
as inventory at quarter end, a higher portion than normal of its
Synthetic Crude Oil ("SCO") and International light crude oil
production in the low commodity price quarter. If these barrels had
been sold during the second quarter of 2020, based on June 2020
commodity prices, the Company would have generated approximately
$60 million in additional cash flows from operating activities and
adjusted funds flow in the quarter.
- The Company reacted quickly to the
changing commodity prices by executing planned maintenance and
temporarily curtailing production when crude oil prices were low,
optimizing its production mix and maximizing margins. Despite the
impact of COVID-19 on the economy, Canadian Natural effectively
executed on its curtailment optimization strategy, prioritizing its
high netback SCO volumes, and achieved strong quarterly production
volumes of 1,165,487 BOE/d in Q2/20, an increase of 14% from Q2/19
and comparable to Q1/20 levels.
- Liquids production in Q2/20 was
921,895 bbl/d, an increase of 20% from Q2/19 and a decrease of 2%
from Q1/20 levels. Increased production relative to Q2/19 reflects
high utilization rates and safe, reliable operations in Oil Sands
Mining and Upgrading, increased production from the acquisition of
Jackfish and primary heavy crude oil assets in 2019 and the ramp up
of Kirby North volumes.
- Higher value light crude oil, NGLs and SCO production was
prioritized in Q2/20, representing approximately 51% of total
corporate BOE production volumes and will continue to be a key
focus of the Company at current commodity price levels.
- As a result of improved commodity prices, substantially all of
the previously announced voluntarily curtailed production in the
Company's thermal in situ and North America Exploration and
Production ("E&P") crude oil and NGL areas was brought back on
production in June 2020.
- At the Company's world class Oil
Sands Mining and Upgrading assets, record quarterly production of
464,318 bbl/d of SCO was achieved in Q2/20. Increases over Q2/19
and Q1/20 levels of 24% and 6% respectively were achieved as a
result of high utilization rates and operational enhancements at
both Horizon and Athabasca Oil Sands Project ("AOSP"), partially
offset by the impact from planned maintenance activities at Horizon
in May 2020.
- The Company's industry leading Oil Sands Mining and Upgrading
assets achieved record low operating costs of $17.74/bbl
(US$12.80/bbl) of SCO in Q2/20, representing decreases of 27% and
15% from Q2/19 and Q1/20 levels respectively. The record low
operating costs in Q2/20 were primarily due to safe, reliable
production, operational enhancements and continued focus on cost
control.
- At AOSP, as previously announced, the Scotford Upgrader
("Scotford") is targeting to increase upgrading capacity to
approximately 320,000 bbl/d in Q3/20. Canadian Natural has
increased gross production capacity at the Albian mines ("Albian")
through optimization projects, process improvements, and enhanced
reliability. In preparation for the increased capacity at Scotford,
Canadian Natural confirmed Albian's ability to deliver incremental
capacity in June 2020, during which time Albian gross production
averaged approximately 339,000 bbl/d. This additional capacity at
AOSP is targeted to provide Canadian Natural with increased margins
and flexibility, maximizing the value of the Company's Oil Sands
Mining and Upgrading assets.
- Canadian Natural's continued focus
on delivering effective and efficient operations and cost control
was also demonstrated as the Company's North American E&P
liquids, including thermal in situ, achieved operating costs of
$11.65/bbl (US$8.41/bbl) in Q2/20, decreases of 11% and 8% from
Q2/19 and Q1/20 levels respectively.
- Thermal in situ production volumes
averaged 212,807 bbl/d in Q2/20, a 94% increase over Q2/19 levels
and a 7% decrease from Q1/20 levels. Production in Q2/20 increased
relative to Q2/19 as a result of the Jackfish acquisition in 2019
and the strong ramp up of Kirby North. Production in Q2/20
decreased relative to Q1/20 as the Company temporarily curtailed
volumes and accelerated maintenance activities into Q2/20 as a
result of low commodity prices.
- Thermal in situ operating costs were strong in Q2/20, averaging
$10.13/bbl (US$7.31/bbl), decreases of 14% and 8% from Q2/19 and
Q1/20 levels respectively. The Company maximized margins by
prioritizing lower Steam to Oil Ratio ("SOR") production, capturing
synergies from the Jackfish acquisition and lower power costs.
- The ramp up of Kirby North is ahead of schedule and has been
top tier with July 2020 production averaging approximately 43,200
bbl/d, exceeding the nameplate capacity of 40,000 bbl/d. Kirby
North's low SOR of 2.3x in Q2/20 resulted in strong operating
costs, maximizing margins within the Company's thermal in situ
segment.
- North America natural gas
production averaged 1,431 MMcf/d in Q2/20, a 3% decrease from Q2/19
levels and a 2% increase from Q1/20 levels. The increase from the
prior quarter reflects the increased volumes from the Company's
previously announced production additions and high reliability,
offsetting natural declines. The Company continues to execute on
its plan to add approximately 60 MMcf/d of highly economic natural
gas volumes at less than $3,000 per flowing BOE and is on track to
achieve the Company's annual incremental production target of
approximately 35 MMcf/d.
- North America natural gas operating costs were strong in Q2/20,
averaging $1.11/Mcf, decreases of 3% and 10% from Q2/19 and Q1/20
levels respectively. These results demonstrate the strength of the
Company's strategy to own and control its infrastructure, continued
focus on cost control and efficient operations.
- Canadian Natural maintained a
strong financial position in Q2/20 with significant liquidity
available at June 30, 2020 of approximately $4.1 billion,
including credit facilities and cash balances. In addition, the
Company has approximately $5.6 billion of availability under its
United States (US$1.9 billion) and Canadian (C$3.0 billion) base
shelf prospectuses, which expire August 2021, allowing the Company
to offer these securities for sale from time to time. During Q2/20,
the Company repaid $900 million of 2.05% medium-term notes and
issued two US$ denominated notes raising approximately $1.5
billion (US$1.1 billion).
- The Government of Alberta enacted
legislation in Q2/19 decreasing the provincial corporate income tax
rate from 12% to 8% over time, commencing on July 1, 2019 through
to 2022. In Q2/20, the Government of Alberta announced its
intention to accelerate this legislation, lowering the current rate
from 10% to 8% effective July 1, 2020. Canadian Natural estimates
current tax savings for 2020 of approximately $35 million,
including the reduction announced in 2019 and the acceleration in
2020. As a result of the tax rate reduction, the Company targets to
invest these 2020 savings in economic projects across its Alberta
operations. The acceleration of the tax rate reduction will also
have an impact on 2021 current taxes and Canadian Natural will
consider the tax savings for inclusion in 2021 investment.
- Canadian Natural appreciates the
support from the Federal and Provincial governments and their
commitment on getting oil and natural gas service providers back to
work through the Abandonment and Reclamation Funding Program. Based
on the total funding that has been announced to date by each
province, the Company will be increasing its investment in
abandonment programs in British Columbia, Saskatchewan and Alberta.
The investments will be deployed to provide much needed jobs
in each of the respective provinces.
- Canadian Natural is leading the crude oil and natural gas
industry in Carbon Capture and Storage ("CCS") and sequestration
initiatives and is one of the largest carbon dioxide ("CO2")
capturers and sequesterers for the oil and natural gas sector
globally. As part of our comprehensive Greenhouse Gas ("GHG")
emissions reduction strategy, our CCS projects include CO2 storage
in geological formations, use of CO2 in enhanced oil recovery
techniques and CO2 injection into tailings. Gross carbon capture
capacity through these projects combined is approximately 2.7
million tonnes of CO2 annually, equivalent to taking approximately
576,000 vehicles off the road per year.
- At the Company’s 70% owned Quest
CCS facility located at Scotford, the facility captures and stores
approximately 1.1 million tonnes of CO2 per year. This highlights
Canadian Natural’s leadership in leveraging technology and
innovation and the strength of industry and government
collaboration to continuously improve operational and environmental
performance.
- Canadian Natural has a 50% working
interest in the North West Redwater Refinery, which combines
gasification technology with an integrated carbon capture and
storage program, capturing approximately 1.2 million tonnes of CO2
per year and eliminating approximately 70% of the refinery's total
carbon footprint. This project successfully reached commercial
operations on June 1, 2020.
- The Company has approximately
400,000 tonnes of CO2 capture capacity per year for sequestration
at Horizon by injecting CO2 into its tailings ponds. This improves
the Company's operating costs as a result of smaller tailings
footprint and more efficient use of natural gas, as well as reduces
GHG emissions and accelerates reclamation.
OPERATIONS REVIEW AND CAPITAL ALLOCATION
Canadian Natural has a balanced and diverse
portfolio of assets, primarily Canadian-based, with international
exposure in the UK section of the North Sea and Offshore Africa.
Canadian Natural’s production is well balanced between light crude
oil, medium crude oil, primary heavy crude oil, Pelican Lake heavy
crude oil, bitumen (thermal oil) and Synthetic Crude Oil ("SCO")
(herein collectively referred to as “crude oil”), natural gas and
NGLs. This balance provides optionality for capital investments,
maximizing value for the Company’s shareholders.
Underpinning this asset base is long life low
decline production from the Company's Oil Sands Mining and
Upgrading, thermal in situ oil sands and Pelican Lake heavy crude
oil assets, representing approximately 79% of the Company's total
liquids production in Q2/20. The combination of long life low
decline, low reserves replacement cost, and effective and efficient
operations, results in substantial and sustainable adjusted funds
flow throughout the commodity price cycle.
Augmenting this, Canadian Natural maintains a
substantial inventory of low capital exposure projects within the
Company's conventional asset base. These projects can be executed
quickly and with the right economic conditions, can provide
excellent returns and maximize value for shareholders. Supporting
these projects is the Company’s undeveloped land base which enables
large, repeatable drilling programs that can be optimized over
time. Additionally, by owning and operating most of the related
infrastructure, Canadian Natural is able to control major
components of the Company's operating costs and minimize production
commitments. Low capital exposure projects can be quickly stopped
or started depending upon success, market conditions or corporate
needs.
Canadian Natural’s balanced portfolio, built
with both long life low decline assets and low capital exposure
assets, enables effective capital allocation, production growth and
value creation.
Drilling
Activity |
Six Months Ended June 30 |
|
|
|
|
2020 |
2019 |
(number of wells) |
Gross |
Net |
Gross |
Net |
Crude oil |
43 |
|
37 |
|
39 |
|
38 |
|
Natural gas |
13 |
|
12 |
|
12 |
|
10 |
|
Dry |
— |
|
— |
|
3 |
|
3 |
|
Subtotal |
56 |
|
49 |
|
54 |
|
51 |
|
Stratigraphic test / service
wells |
424 |
|
371 |
|
379 |
|
335 |
|
Total |
480 |
|
420 |
|
433 |
|
386 |
|
Success rate (excluding stratigraphic test / service wells) |
|
100 |
% |
|
94 |
% |
- The Company's total crude oil and
natural gas drilling program of 49 net wells for the six months
ended June 30, 2020, excluding stratigraphic/service wells,
represents a decrease of 2 net wells from the same period in
2019.
North America Exploration and Production
Crude oil and NGLs
– excluding Thermal In Situ Oil Sands |
|
|
|
Three Months Ended |
Six Months Ended |
|
Jun 30 2020 |
Mar 31 2020 |
Jun 30 2019 |
Jun 30 2020 |
Jun 30 2019 |
Crude oil and NGLs production (bbl/d) |
200,699 |
|
228,574 |
|
235,066 |
|
214,637 |
|
230,205 |
|
Net wells targeting crude oil |
2 |
|
28 |
|
9 |
|
30 |
|
37 |
|
Net successful wells
drilled |
2 |
|
28 |
|
7 |
|
30 |
|
35 |
|
Success rate |
100 |
% |
100 |
% |
78 |
% |
100 |
% |
95 |
% |
- Canadian Natural's North America
E&P crude oil and NGL production volumes, excluding thermal in
situ, averaged 200,699 bbl/d, decreases of 15% and 12% from Q2/19
and Q1/20 levels respectively. The decrease in Q2/20 reflects the
Company's decision to temporarily curtail production and reduce
well servicing activities, as a result of low commodity prices in
the quarter.
- Primary heavy crude oil production
averaged 62,546 bbl/d in Q2/20, decreases of 19% and 24% from Q2/19
and Q1/20 levels respectively. The decrease in production was
primarily as a result of temporarily curtailed production and
reduced well servicing activity as a result of low commodity
prices, as well as the execution of the Company's curtailment
optimization strategy.
- Operating costs in the Company's primary heavy crude oil
operations in Q2/20 averaged
$17.97/bbl (US$12.97/bbl), a 4%
decrease from Q1/20 levels, as the Company continues to focus on
cost control and maximizing margins.
- Pelican Lake production averaged
55,731 bbl/d in Q2/20, comparable to Q2/19 and a 4% decrease from
Q1/20 levels. The decrease from Q1/20 is primarily due to reduced
well servicing activity as a result of low crude oil prices in
Q2/20.
- The Company continues to demonstrate effective and efficient
operations as Q2/20 operating costs at Pelican Lake of $6.31/bbl
(US$4.55/bbl) decreased by 6% from Q2/19 levels and increased 2%
from Q1/20 levels.
- North American light crude oil and NGL production averaged
82,422 bbl/d in Q2/20, decreases of 19% and 7% from Q2/19 and Q1/20
levels respectively, primarily as a result of temporarily curtailed
production and reduced well servicing activity as a result of low
commodity prices in Q2/20.
- Operating costs in the Company's
North America light crude oil and NGL areas averaged
$14.41/bbl (US$10.40/bbl) in Q2/20,
decreases of 2% and 10% from Q2/19 and Q1/20 levels
respectively.
|
|
|
Thermal In Situ
Oil Sands |
|
|
|
Three Months Ended |
Six Months Ended |
|
|
|
|
|
|
|
Jun 30 2020 |
Mar 31 2020 |
Jun 30 2019 |
Jun 30 2020 |
Jun 30 2019 |
Bitumen production (bbl/d) |
212,807 |
|
228,303 |
|
109,599 |
|
220,555 |
|
101,915 |
|
Net wells targeting bitumen |
— |
|
6 |
|
— |
|
6 |
|
— |
|
Net successful wells
drilled |
— |
|
6 |
|
— |
|
6 |
|
— |
|
Success rate |
— |
|
100 |
% |
— |
|
100 |
% |
— |
|
- Thermal in situ production volumes
averaged 212,807 bbl/d in Q2/20, a 94% increase over Q2/19 levels
and a 7% decrease from Q1/20 levels. Production in Q2/20 increased
relative to Q2/19 as a result of the Jackfish acquisition in 2019
and the strong ramp up of Kirby North. Production in Q2/20
decreased relative to Q1/20 as the Company temporarily curtailed
volumes and accelerated maintenance activities into Q2/20 as a
result of low commodity prices.
- Thermal in situ operating costs were strong in Q2/20, averaging
$10.13/bbl (US$7.31/bbl), decreases of 14% and 8% from Q2/19 and
Q1/20 levels respectively. The Company maximized margins by
prioritizing lower SOR production, capturing synergies from the
Jackfish acquisition and lower power costs.
- The ramp up of Kirby North is ahead of schedule and has been
top tier with July 2020 production averaging approximately 43,200
bbl/d, exceeding the nameplate capacity of 40,000 bbl/d. Kirby
North's low SOR of 2.3x in Q2/20 resulted in strong operating
costs, maximizing margins within the Company's thermal in situ
segment.
- At Kirby South, the solvent
enhanced oil recovery technology pilot targets to increase oil
recovery, reduce SOR by up to 50% and lower GHG intensity by up to
50%. To date, the Company continues to see positive results with
increased bitumen production, lower SOR and high solvent recovery.
This technology has the potential for application throughout the
Company's extensive thermal in situ asset base.
|
|
|
North America
Natural Gas |
|
|
|
Three Months Ended |
Six Months Ended |
|
|
|
|
|
|
|
Jun 30 2020 |
Mar 31 2020 |
Jun 30 2019 |
Jun 30 2020 |
Jun 30 2019 |
Natural gas production (MMcf/d) |
1,431 |
|
1,407 |
|
1,482 |
|
1,419 |
|
1,468 |
|
Net wells targeting natural gas |
1 |
|
11 |
|
2 |
|
12 |
|
11 |
|
Net successful wells
drilled |
1 |
|
11 |
|
2 |
|
12 |
|
10 |
|
Success rate |
100 |
% |
100 |
% |
100 |
% |
100 |
% |
91 |
% |
- North America natural gas
production averaged 1,431 MMcf/d in Q2/20, a 3% decrease from Q2/19
levels and a 2% increase from Q1/20 levels. The increase from the
prior quarter reflects the increased volumes from the Company's
previously announced production additions, high reliability and
strong base production, offsetting natural declines. The Company
continues to execute on its plan to add approximately 60 MMcf/d of
highly economic natural gas volumes at less than $3,000 per flowing
BOE and is on track to achieve the Company's annual incremental
production target of approximately 35 MMcf/d.
- North America natural gas operating costs were strong in Q2/20,
averaging $1.11/Mcf, decreases of 3% and 10% from Q2/19 and Q1/20
levels respectively. These results demonstrate the strength of the
Company's strategy to own and control its infrastructure, continued
focus on cost control and efficient operations.
- At the Company's high value Septimus Montney liquids rich area,
operating costs remained strong, averaging $0.31/Mcfe in Q2/20, a
6% decrease from Q2/19 levels.
- In Q2/20, Canadian Natural used the
equivalent of approximately 49% of corporate annual natural gas
production within its operations, providing a natural hedge from
Western Canadian natural gas prices. Approximately 32% was exported
to other North American markets and sold internationally, while the
remaining 19% was exposed to AECO/Station 2 pricing.
International Exploration and
Production
|
Three Months Ended |
Six Months Ended |
|
|
|
|
|
|
|
Jun 30 2020 |
Mar 31 2020 |
Jun 30 2019 |
Jun 30 2020 |
Jun 30 2019 |
Crude oil production (bbl/d) |
|
|
|
|
|
North Sea |
26,627 |
|
27,755 |
|
27,594 |
|
27,191 |
|
26,659 |
|
Offshore Africa |
17,444 |
|
15,943 |
|
23,650 |
|
16,694 |
|
22,907 |
|
Natural gas production (MMcf/d) |
|
|
|
|
|
North Sea |
15 |
|
23 |
|
23 |
|
19 |
|
25 |
|
Offshore Africa |
16 |
|
10 |
|
27 |
|
13 |
|
28 |
|
Net wells targeting crude oil |
— |
|
1.0 |
|
0.9 |
|
1.0 |
|
2.5 |
|
Net successful wells
drilled |
— |
|
1.0 |
|
0.9 |
|
1.0 |
|
2.5 |
|
Success rate |
— |
|
100 |
% |
100 |
% |
100 |
% |
100 |
% |
- International E&P crude oil
production volumes averaged 44,071 bbl/d in Q2/20, a decrease of
14% from Q2/19 levels and comparable to Q1/20 levels.
- In the North Sea, crude oil production volumes averaged of
26,627 bbl/d in Q2/20, a decrease of 4% from both Q2/19 and Q1/20
levels as expected. Production in Q2/20 was lower, primarily as a
result of the planned permanent cessation of production in the
Banff and Kyle fields on June 1, 2020 and natural field declines.
The Banff decommissioning project is on time and on budget.
- Crude oil operating costs in the North Sea decreased by 24% and
4% from Q2/19 and Q1/20 levels respectively, averaging $28.47/bbl
(US$20.55/bbl) in Q2/20. The decreases from the comparable periods
primarily reflected reduced maintenance activities, timing of
liftings from various fields that have different cost structures
and the Company's continued focus on cost control.
- Offshore Africa crude oil production volumes averaged 17,444
bbl/d in Q2/20, a decrease of 26% from Q2/19 levels and an increase
of 9% from Q1/20 levels. The decrease in production from Q2/19
levels was primarily due to natural field declines. The increase in
production from Q1/20 levels primarily reflects the successful
completion of planned turnaround activities at Espoir in Q1/20.
- Offshore Africa crude oil operating costs averaged $10.62/bbl
(US$7.67/bbl) in Q2/20, an increase of 26% from Q2/19 and a
decrease of 11% from Q1/20 levels. The changes in operating costs
from the comparable periods primarily reflected fluctuations in
production volumes on a relatively fixed cost base and the
Company's continued focus on cost control.
- In Q3/20, the operator is targeting to commence the drilling
program of the previously announced discovery of significant gas
condensate in South Africa, where Canadian Natural has a 20%
working interest.
North America Oil Sands Mining and
Upgrading
|
Three Months Ended |
Six Months Ended |
|
|
|
|
|
|
|
Jun 30 2020 |
Mar 31 2020 |
Jun 30 2019 |
Jun 30 2020 |
Jun 30 2019 |
Synthetic crude oil production (bbl/d) (1) (2) |
464,318 |
|
438,101 |
|
374,500 |
|
451,210 |
|
395,238 |
|
(1) SCO production before royalties and excludes
volumes consumed internally as diesel.(2) Consists of heavy and
light synthetic crude oil products.
- At the Company's world class Oil Sands Mining and Upgrading
assets, record quarterly production of 464,318 bbl/d of SCO was
achieved in Q2/20. Increases over Q2/19 and Q1/20 levels of 24% and
6% respectively were achieved as a result of high utilization rates
and operational enhancements at both Horizon and AOSP, partially
offset by the impact from planned maintenance activities at Horizon
in May 2020.
- The Company's industry leading Oil Sands Mining and Upgrading
assets achieved record low operating costs of $17.74/bbl
(US$12.80/bbl) of SCO in Q2/20, representing decreases of 27% and
15% from Q2/19 and Q1/20 levels respectively. The record low
operating costs in Q2/20 are primarily due to safe, reliable
production, operational enhancements and continued focus on cost
control.
- Oil Sands Mining and Upgrading reduced operating costs by
approximately $84 million or 10% from Q2/19 levels to approximately
$730 million in Q2/20, as a result of safe, reliable production,
operational enhancements and continued focus on cost control.
- In the second half of 2020, the Company is targeting planned
turnaround activities at both AOSP and Horizon. The Company's
strength of operations and diverse asset base allows Canadian
Natural to optimize maintenance activities within its Oil Sands
Mining and Upgrading assets.
- The turnaround at the non-operated Scotford Upgrader base plant
began on July 8, 2020 and is targeted to be completed in 55 days,
during which time the plant will run at restricted rates. Timing of
maintenance activities at Albian is aligned with the turnaround at
the Scotford Upgrader. During the turnaround, net production from
AOSP is targeted to average approximately 100,000 bbl/d lower than
normal.
- At Horizon, the Company is targeting to begin a 20 day planned
turnaround in mid-September. Monthly average production is targeted
to be approximately 80,000 bbl/d lower than normal in September
2020 and October 2020.
- At AOSP, as previously announced, the Scotford Upgrader is
targeting to increase upgrading capacity to approximately 320,000
bbl/d in Q3/20. Canadian Natural has increased gross production
capacity at the Albian mines ("Albian") through optimization
projects, process improvements, and enhanced reliability. In
preparation for the increased capacity at Scotford, Canadian
Natural confirmed Albian's ability to deliver incremental capacity
in June 2020, during which time Albian gross production averaged
approximately 339,000 bbl/d. This additional capacity at AOSP is
targeted to provide Canadian Natural with increased margins and
flexibility, maximizing the value of the Company's Oil Sands Mining
and Upgrading assets.
- Commercial engineering of the In Pit Extraction Process
("IPEP") for Horizon continues, although the Company has
temporarily delayed the field pilot in order to limit staffing
levels to personnel who are critical to maintaining safe, reliable
operations in response to COVID-19 guidelines. Canadian Natural is
confident in the results from the initial testing phase of the
pilot, which shows excellent recovery rates and evidence of
stackable tailings. The IPEP pilot will determine the feasibility
of producing stackable dry tailings on a commercial basis. The
project has the potential to reduce the Company's bitumen
production GHG emissions by approximately 40% and lower the
Company's environmental footprint by decreasing the handling of
material, reducing the distance driven by its fleet of haul trucks,
decreasing the size and need for tailings ponds and accelerating
site reclamation. In addition, this process has the potential to
reduce capital and operating costs.
MARKETING
|
|
Three Months Ended |
|
|
Six Months Ended |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Jun 30 2020 |
|
Mar 31 2020 |
|
Jun 30 2019 |
|
|
Jun 30 2020 |
|
Jun 30 2019 |
Crude oil and NGLs pricing |
|
|
|
|
|
|
|
|
|
|
|
WTI benchmark price (US$/bbl) (1) |
|
$ |
27.85 |
|
|
$ |
46.08 |
|
|
$ |
59.83 |
|
|
|
$ |
36.97 |
|
|
$ |
57.38 |
|
WCS heavy differential as a percentage of WTI (%) (2) |
|
41 |
% |
|
44 |
% |
|
18 |
% |
|
|
43 |
% |
|
20 |
% |
SCO price (US$/bbl) |
|
$ |
23.28 |
|
|
$ |
43.39 |
|
|
$ |
59.96 |
|
|
|
$ |
33.33 |
|
|
$ |
56.10 |
|
Condensate benchmark pricing (US$/bbl) |
|
$ |
22.19 |
|
|
$ |
45.54 |
|
|
$ |
55.86 |
|
|
|
$ |
33.86 |
|
|
$ |
53.19 |
|
Average realized pricing before risk management (C$/bbl) (3) |
|
$ |
18.97 |
|
|
$ |
25.90 |
|
|
$ |
63.45 |
|
|
|
$ |
22.70 |
|
|
$ |
59.05 |
|
Natural gas pricing |
|
|
|
|
|
|
|
|
|
|
|
AECO benchmark price (C$/GJ) |
|
$ |
1.81 |
|
|
$ |
2.03 |
|
|
$ |
1.11 |
|
|
|
$ |
1.92 |
|
|
$ |
1.47 |
|
Average realized pricing before risk management (C$/Mcf) |
|
$ |
2.03 |
|
|
$ |
2.22 |
|
|
$ |
1.98 |
|
|
|
$ |
2.13 |
|
|
$ |
2.53 |
|
(1) West Texas Intermediate ("WTI").(2) Western
Canadian Select ("WCS").(3) Average crude oil and NGL pricing
excludes SCO. Pricing is net of blending costs and excluding risk
management activities.
- Canadian Natural has many strengths
when marketing its products, including a balanced and diverse
product mix of natural gas, conventional heavy crude oil,
conventional light crude oil, thermal in situ and SCO.
- Commodity prices continue to
improve and Western Canadian Select ("WCS") differentials have
tightened as a result of reduced activity in the Western Canadian
Sedimentary Basin, production declines and price-related
curtailments and shut-ins. Since June, WCS differentials to WTI
remain relatively tight, with Q3/20 estimated to be approximately
22%. The Company continues to see sufficient egress in the
foreseeable future as operators bring back on production
volumes.
- Canadian Natural has storage at
major hubs in Edmonton and Hardisty, which allows the Company to
adjust monthly sales, manage pipeline logistical constraints, and
production fluctuations, as well as pricing differences from month
to month.
- Market egress continues to improve
in the mid-term as the Trans Mountain Expansion ("TMX") and
Keystone XL projects are progressing with construction, on which
Canadian Natural has 94,000 bbl/d and 200,000 bbl/d of committed
capacity respectively. Combining these two pipeline projects and
including Enbridge Line 3 replacement, Western Canadian egress is
targeted to increase by approximately 1.8 MMbbl/d in the mid-term.
- TMX construction continues to progress and is targeted to be on
stream in late 2022.
- Canadian Natural is committed to approximately 10,000 bbl/d of
the targeted 50,000 bbl/d base Keystone export pipeline
optimization expansion, which is targeted to be available in
2021.
- The North West Redwater Refinery
reached commercial operations on June 1, 2020 and targets to
process approximately 80,000 bbl/d of diluted bitumen, which will
improve heavy oil demand in western Canada, effectively increasing
egress out of the Western Canadian Sedimentary Basin. For more
details, please contact the North West Redwater Partnership.
FINANCIAL
REVIEW
The Company continues to implement proven
strategies including its disciplined approach to capital
allocation. As a result, the financial position of Canadian Natural
remains strong. Canadian Natural’s adjusted funds flow generation,
credit facilities, US commercial paper program, access to capital
markets, diverse asset base and related flexible capital
expenditure program, all support a flexible financial position and
provide the appropriate financial resources for the near-, mid- and
long-term.
- The Company’s strategy to maintain
a diverse portfolio, balanced across various commodity types,
achieved production of 1,165,487 BOE/d in Q2/20, with approximately
98% of total production located in G7 countries.
- Canadian Natural generated
quarterly adjusted funds flow of $415 million in Q2/20, reflecting
the strength of the Company's long life low decline asset base and
its effective and efficient operations.
- Maximizing value for shareholders, the Company elected to store
as inventory at quarter end, a higher portion than normal of its
SCO and International light crude oil production in the low
commodity price quarter. If these barrels had been sold during the
second quarter of 2020, based on June 2020 commodity prices, the
Company would have generated approximately $60 million in
additional cash flows from operating activities and adjusted funds
flow in the quarter.
- Net capital expenditures in Q2/20
were disciplined at approximately $421 million.
- Returns to shareholders totaled
$502 million in Q2/20 by way of dividends paid on April 1, 2020. As
previously announced on March 18, 2020, the Company's share
repurchase program has been suspended and the Board of Directors
made the decision to not renew the Company's NCIB program, which
expired in May 2020.
- Canadian Natural maintained a
strong financial position in Q2/20 with significant liquidity
available at June 30, 2020 of approximately $4.1 billion,
including credit facilities and cash balances. The Company's
liquidity is more than sufficient to retire, when due, any upcoming
debt maturities.
- In May 2020, the Company's $750 million non-revolving term
credit facility, originally due February 2021, was increased by
$250 million to $1,000 million and extended to February 2022.
- The Company repaid $900 million of 2.05% medium-term notes that
matured on June 1, 2020.
- In June 2020, the Company issued two US$ denominated notes for
total proceeds of approximately $1.5 billion (US$1.1 billion),
including US$600 million of unsecured notes due in 2025 and US$500
million of unsecured notes due in 2030. Net proceeds from these
notes were used primarily to refinance the Company's outstanding
short-term indebtedness and for general corporate purposes.
- The Company has approximately $5.6 billion of availability
under its United States (US$1.9 billion) and Canadian (C$3.0
billion) base shelf prospectuses, which expire August 2021,
allowing the Company to offer these securities for sale from time
to time.
- In addition to adjusted funds flow, capital flexibility and
access to debt capital markets, Canadian Natural has additional
financial levers at its disposal to effectively manage its
liquidity. The current approximate value of these financial levers
includes third party equity investments of $275 million and cross
currency swaps with a total value of $206 million.
- Debt to book capitalization and debt to adjusted EBITDA
remained strong at 41.3% and 3.0x respectively.
- Canadian Natural continues to
maintain strong investment grade credit ratings. The Company has a
high degree of communication with credit rating agencies to ensure
they understand the robust and sustainable nature of the Company's
assets.
- Canadian Natural’s business is unique, robust and sustainable.
The strength of the Company's assets and its ability to generate
significant and sustainable free cash flow over the long term
combined with strong liquidity, production flexibility, significant
capital reductions and targeted operating costs savings provided
the Board of Directors with the confidence that the Company’s
current dividend levels can be sustained through the commodity
price cycle.
- Subsequent to quarter end, the
Company declared a quarterly dividend of $0.425 per share, payable
on October 5, 2020.
ADVISORY
Special Note Regarding Forward-Looking
Statements
Certain statements relating to Canadian Natural
Resources Limited (the "Company") in this document or documents
incorporated herein by reference constitute forward-looking
statements or information (collectively referred to herein as
"forward-looking statements") within the meaning of applicable
securities legislation. Forward-looking statements can be
identified by the words "believe", "anticipate", "expect", "plan",
"estimate", "target", "continue", "could", "intend", "may",
"potential", "predict", "should", "will", "objective", "project",
"forecast", "goal", "guidance", "outlook", "effort", "seeks",
"schedule", "proposed", "aspiration" or expressions of a similar
nature suggesting future outcome or statements regarding an
outlook. Disclosure related to expected future commodity pricing,
forecast or anticipated production volumes, royalties, production
expenses, capital expenditures, income tax expenses and other
guidance provided throughout this press release and the Company's
Management’s Discussion and Analysis ("MD&A") of the financial
condition and results of operations of the Company, constitute
forward-looking statements. Disclosure of plans relating to and
expected results of existing and future developments, including,
without limitation, those in relation to the Company's assets at
Horizon Oil Sands ("Horizon"), the Athabasca Oil Sands Project
("AOSP"), Primrose thermal projects, the Pelican Lake water and
polymer flood project, the Kirby Thermal Oil Sands Project, the
Jackfish Thermal Oil Sands Project, the North West Redwater bitumen
upgrader and refinery, construction by third parties of new, or
expansion of existing, pipeline capacity or other means of
transportation of bitumen, crude oil, natural gas, natural gas
liquids ("NGLs") or synthetic crude oil ("SCO") that the Company
may be reliant upon to transport its products to market, and the
development and deployment of technology and technological
innovations also constitute forward-looking statements. These
forward-looking statements are based on annual budgets and
multi-year forecasts, and are reviewed and revised throughout the
year as necessary in the context of targeted financial ratios,
project returns, product pricing expectations and balance in
project risk and time horizons. These statements are not guarantees
of future performance and are subject to certain risks. The reader
should not place undue reliance on these forward-looking statements
as there can be no assurances that the plans, initiatives or
expectations upon which they are based will occur.
In addition, statements relating to "reserves"
are deemed to be forward-looking statements as they involve the
implied assessment based on certain estimates and assumptions that
the reserves described can be profitably produced in the future.
There are numerous uncertainties inherent in estimating quantities
of proved and proved plus probable crude oil, natural gas and NGLs
reserves and in projecting future rates of production and the
timing of development expenditures. The total amount or timing of
actual future production may vary significantly from reserves and
production estimates.
The forward-looking statements are based on
current expectations, estimates and projections about the Company
and the industry in which the Company operates, which speak only as
of the date such statements were made or as of the date of the
report or document in which they are contained, and are subject to
known and unknown risks and uncertainties that could cause the
actual results, performance or achievements of the Company to be
materially different from any future results, performance or
achievements expressed or implied by such forward-looking
statements. Such risks and uncertainties include, among others:
general economic and business conditions (including as a result of
effects of the novel coronavirus ("COVID-19") pandemic and the
actions of the Organization of the Petroleum Exporting Countries
("OPEC") and non-OPEC countries) which may impact, among other
things, demand and supply for and market prices of the Company’s
products, and the availability and cost of resources required by
the Company's operations; volatility of and assumptions regarding
crude oil and natural gas and NGLs prices including due to actions
of OPEC and non-OPEC countries taken in response to COVID-19 or
otherwise; fluctuations in currency and interest rates; assumptions
on which the Company’s current guidance is based; economic
conditions in the countries and regions in which the Company
conducts business; political uncertainty, including actions of or
against terrorists, insurgent groups or other conflict including
conflict between states; industry capacity; ability of the Company
to implement its business strategy, including exploration and
development activities; impact of competition; the Company’s
defense of lawsuits; availability and cost of seismic, drilling and
other equipment; ability of the Company and its subsidiaries to
complete capital programs; the Company’s and its subsidiaries’
ability to secure adequate transportation for its products;
unexpected disruptions or delays in the mining, extracting or
upgrading of the Company’s bitumen products; potential delays or
changes in plans with respect to exploration or development
projects or capital expenditures; ability of the Company to attract
the necessary labour required to build, maintain, and operate its
thermal and oil sands mining projects; operating hazards and other
difficulties inherent in the exploration for and production and
sale of crude oil and natural gas and in mining, extracting or
upgrading the Company’s bitumen products; availability and cost of
financing; the Company’s and its subsidiaries’ success of
exploration and development activities and its ability to replace
and expand crude oil and natural gas reserves; timing and success
of integrating the business and operations of acquired companies
and assets; production levels; imprecision of reserves estimates
and estimates of recoverable quantities of crude oil, natural gas
and NGLs not currently classified as proved; actions by
governmental authorities (including production curtailments
mandated by the Government of Alberta); government regulations and
the expenditures required to comply with them (especially safety
and environmental laws and regulations and the impact of climate
change initiatives on capital expenditures and production
expenses); asset retirement obligations; the adequacy of the
Company’s provision for taxes; the continued availability of the
Canada Emergency Wage Subsidy ("CEWS") or other subsidies; and
other circumstances affecting revenues and expenses.
The Company’s operations have been, and in the
future may be, affected by political developments and by national,
federal, provincial, state and local laws and regulations such as
restrictions on production, changes in taxes, royalties and other
amounts payable to governments or governmental agencies, price or
gathering rate controls and environmental protection regulations.
Should one or more of these risks or uncertainties materialize, or
should any of the Company’s assumptions prove incorrect, actual
results may vary in material respects from those projected in the
forward-looking statements. 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 its assessment of the
future considering all information then available.
Readers are cautioned that the foregoing list of
factors is not exhaustive. Unpredictable or unknown factors not
discussed in this press release or the Company's MD&A could
also have adverse effects on forward-looking statements. Although
the Company believes that the expectations conveyed by the
forward-looking statements are reasonable based on information
available to it on the date such forward-looking statements are
made, no assurances can be given as to future results, levels of
activity and achievements. All subsequent forward-looking
statements, whether written or oral, attributable to the Company or
persons acting on its behalf are expressly qualified in their
entirety by these cautionary statements. Except as required by
applicable law, the Company assumes no obligation to update
forward-looking statements in this press release or the Company's
MD&A, whether as a result of new information, future events or
other factors, or the foregoing factors affecting this information,
should circumstances or the Company’s estimates or opinions
change.
Special Note Regarding non-GAAP Financial
Measures
This press release includes references to
financial measures commonly used in the crude oil and natural gas
industry, such as: adjusted net earnings (loss) from operations,
adjusted funds flow and net capital expenditures. These financial
measures are not defined by International Financial Reporting
Standards ("IFRS") and therefore are referred to as non-GAAP
financial measures. The non-GAAP financial measures used by the
Company may not be comparable to similar measures presented by
other companies. The Company uses these non-GAAP financial measures
to evaluate its performance. The non-GAAP financial measures should
not be considered an alternative to or more meaningful than net
earnings (loss), cash flows (used in) from operating activities,
and cash flows used in investing activities as determined in
accordance with IFRS, as an indication of the Company's
performance. The non-GAAP financial measure adjusted net earnings
(loss) from operations is reconciled to net earnings (loss), as
determined in accordance with IFRS, in the "Financial Highlights"
section of the Company's MD&A. Additionally, the non-GAAP
financial measure adjusted funds flow is reconciled to cash flows
(used in) from operating activities, as determined in accordance
with IFRS, in the "Financial Highlights" section of the Company's
MD&A. The non-GAAP financial measure net capital expenditures
is reconciled to cash flows used in investing activities, as
determined in accordance with IFRS, in the "Net Capital
Expenditures" section of the Company's MD&A. The Company also
presents certain non-GAAP financial ratios and their derivation in
the "Liquidity and Capital Resources" section of the Company's
MD&A.
Adjusted funds flow (previously referred to as
funds flow from operations) is a non-GAAP measure that represents
cash flows from operating activities as presented in the Company's
consolidated Statements of Cash Flows, adjusted for the net change
in non-cash working capital, abandonment expenditures and movements
in other long-term assets, including the unamortized cost of the
share bonus program and prepaid cost of service tolls. The Company
considers adjusted funds flow a key measure as it demonstrates the
Company’s ability to generate the cash flow necessary to fund
future growth through capital investment and to repay debt. The
reconciliation “Adjusted Funds Flow, as Reconciled to Cash Flows
from Operating Activities” is presented in the Company’s
MD&A.
Net capital expenditures is a non-GAAP measure
that represents cash flows used in investing activities as
presented in the Company's consolidated Statements of Cash Flows,
adjusted for the net change in non-cash working capital, investment
in other long-term assets, share consideration in business
acquisitions and abandonment expenditures. The Company considers
net capital expenditures a key measure as it provides an
understanding of the Company’s capital spending activities in
comparison to the Company's annual capital budget. The
reconciliation “Net Capital Expenditures, as Reconciled to Cash
Flows used in Investing Activities” is presented in the Net Capital
Expenditures section of the Company’s MD&A.
Free cash flow is a non-GAAP measure that
represents cash flows from operating activities as presented in the
Company's consolidated Statements of Cash Flows, adjusted for the
net change in non-cash working capital from operating activities,
abandonment, certain movements in other long-term assets, less net
capital expenditures and dividends on common shares. The Company
considers free cash flow a key measure in demonstrating the
Company’s ability to generate cash flow to fund future growth
through capital investment, pay returns to shareholders, and to
repay debt.
Adjusted EBITDA is a non-GAAP measure that
represents net earnings (loss) as presented in the Company's
consolidated Statements of Earnings (Loss), adjusted for interest,
taxes, depletion, depreciation and amortization, stock based
compensation expense (recovery), unrealized risk management gains
(losses), unrealized foreign exchange gains (losses), and accretion
of the Company’s asset retirement obligation. The Company considers
adjusted EBITDA a key measure in evaluating its operating
profitability by excluding non-cash items.
Debt to adjusted EBITDA is a non-GAAP measure
that is derived as the current and long-term portions of long-term
debt, divided by the 12 month trailing Adjusted EBITDA, as defined
above. The Company considers this ratio to be a key measure in
evaluating the Company's ability to pay off its debt.
Debt to book capitalization is a non-GAAP
measure that is derived as net current and long-term debt, divided
by the book value of common shareholders' equity plus net current
and long-term debt. The Company considers this ratio to be a key
measure in evaluating the Company's ability to pay off its
debt.
Available liquidity is a non-GAAP measure that
is derived as cash and cash equivalents, total bank and term credit
facilities, less amounts drawn on the bank and credit facilities
including under the commercial paper program. The Company considers
available liquidity a key measure in evaluating the sustainability
of the Company’s operations and ability to fund future growth. See
note 9 - Long-term Debt in the Company’s consolidated financial
statements.
Special Note Regarding Currency, Financial Information
and Production
This press release should be read in conjunction
with the unaudited interim consolidated financial statements for
the three and six months ended June 30, 2020 and the Company's
MD&A and audited consolidated financial statements for the year
ended December 31, 2019. All dollar amounts are referenced in
millions of Canadian dollars, except where noted otherwise. The
Company’s unaudited interim consolidated financial statements for
the three and six months ended June 30, 2020 and the Company's
MD&A have been prepared in accordance with IFRS as issued by
the International Accounting Standards Board ("IASB").
Production volumes and per unit statistics are
presented throughout the Company's MD&A on a "before royalties"
or "company gross" basis, and realized prices are net of blending
and feedstock costs and exclude the effect of risk management
activities. In addition, reference is made to crude oil and natural
gas in common units called barrel of oil equivalent ("BOE"). A BOE
is derived by converting six thousand cubic feet ("Mcf") of natural
gas to one barrel ("bbl") of crude oil (6 Mcf:1 bbl). This
conversion may be misleading, particularly if used in isolation,
since the 6 Mcf:1 bbl ratio is based on an energy equivalency
conversion method primarily applicable at the burner tip and does
not represent a value equivalency at the wellhead. In comparing the
value ratio using current crude oil prices relative to natural gas
prices, the 6 Mcf:1 bbl conversion ratio may be misleading as an
indication of value. In addition, for the purposes of the
Company's MD&A, crude oil is defined to include the
following commodities: light and medium crude oil, primary heavy
crude oil, Pelican Lake heavy crude oil, bitumen (thermal oil), and
SCO. Production on an "after royalties" or "company net" basis is
also presented for information purposes only.
Additional information relating to the Company,
including its Annual Information Form for the year ended
December 31, 2019, is available on SEDAR at www.sedar.com, and
on EDGAR at www.sec.gov. Information on the Company's website does
not form part of and is not incorporated by reference in the
Company's MD&A.
CONFERENCE CALL
A conference call will be held at 9:00 a.m.
Mountain Time, 11:00 a.m. Eastern Time on Thursday, August 6,
2020.
The North American conference call number is
1-866-521-4909 and the outside North American conference call
number is 001-647-427-2311. Please call in 10 minutes prior to the
call starting time.
An archive of the broadcast will be available
until 6:00 p.m. Mountain Time, Thursday, August 20, 2020. To access
the rebroadcast in North America, dial 1-800-585-8367. Those
outside of North America, dial 001-416-621-4642. The conference
archive ID number is 6796237.
The conference call will also be webcast and can
be accessed on the home page our website at www.cnrl.com.
Canadian Natural is a senior oil and natural gas
production company, with continuing operations in its core areas
located in Western Canada, the U.K. portion of the North Sea and
Offshore Africa.
|
CANADIAN NATURAL RESOURCES LIMITED |
2100, 855
- 2nd Street S.W. Calgary, Alberta, T2P4J8 Phone:
403-514-7777 Email: ir@cnrl.comwww.cnrl.com |
|
|
TIM S. MCKAY President MARK A.
STAINTHORPEChief Financial Officer and Senior
Vice-President, Finance JASON M. POPKOManager,
Investor Relations Trading Symbol - CNQToronto Stock ExchangeNew
York Stock Exchange |
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