Canadian Natural's President, Tim McKay, commented on the third
quarter results stating "The resilience of our business model, as
witnessed in our third quarter 2020 results, demonstrates Canadian
Natural's competitive advantage as the strength of our long life
low decline asset base allows the Company to effectively manage
through commodity price cycles while preserving net asset value.
Canadian Natural is focused on continuous improvement and is on
track for the targeted operating cost savings in 2020 of
approximately $745 million dollars. With a disciplined capital
program in 2020 of approximately $2.7 billion, we have been able to
maintain our production volumes, grow our dividend and keep a
strong balance sheet.
In the third quarter, we increased liquids
production from our North America Exploration and Production
("E&P") assets by approximately 20% from Q2/20 levels to
494,952 bbl/d and achieved record daily thermal in situ production
in the quarter of 287,978 bbl/d, while achieving low thermal
operating costs of $7.85/bbl (US$5.89/bbl). These results were
achieved as we successfully executed on our curtailment
optimization strategy while we conducted planned maintenance and
turnaround activities in our Oil Sands Mining and Upgrading
segment.
Environmental, Social and Governance ("ESG")
performance remains a priority and investments in improving
environmental performance and reducing our environmental footprint
continue in the current pricing environment. We recently released
our 2019 Report to Stakeholders, which highlights our commitment to
ESG excellence and reducing our environmental footprint.
Subsequent to quarter end, the acquisition of
Painted Pony Energy Ltd. ("Painted Pony") closed on October 6,
2020. With a significant amount of pre-built infrastructure, these
high quality assets in the Townsend areas of Northeast British
Columbia complement our already high quality natural gas asset base
in Western Canada. The Company’s natural gas production, targeted
at over 1.6 Bcf/d in the fourth quarter, and associated natural gas
liquids is forecast to generate approximately $1.2 billion in
annualized operating cash flow at current strip pricing."
Canadian Natural's Chief Financial Officer, Mark
Stainthorpe, added, "Our unique and diversified asset base allows
us to generate significant free cash flow above our disciplined
capital program and maintain our dividend payment level, unchanged
through the commodity price cycle. In the third quarter, we
generated approximately $1.74 billion in adjusted funds flow and
approximately $467 million in free cash flow, after capital
expenditures and dividend payments, reflecting the flexibility and
strength of our long life low decline asset base.
The Company maintains a flexible and disciplined
capital allocation strategy, with a focus on maintaining a strong
and resilient financial position throughout the commodity price
cycle. In the third quarter we allocated our free cash flow to the
balance sheet, contributing to a significant reduction in net debt
of approximately $1.1 billion. Including committed and undrawn
credit facilities, cash balances and short-term investments, the
Company had significant liquidity available at September 30, 2020
of approximately $4.2 billion.
Our effective and efficient operations along
with our low cost structure drives our industry leading break-even
of WTI US$30-$31 per barrel to cover sustaining capital and current
dividend payment levels. Our low break-even maximizes netbacks,
ultimately increasing free cash flow and creating value for our
shareholders."
QUARTERLY HIGHLIGHTS
|
|
Three Months Ended |
|
|
Nine Months Ended |
|
|
|
|
|
|
|
|
|
|
|
|
($ millions,
except per common share amounts) |
|
Sep 30 2020 |
|
|
Jun 30 2020 |
|
|
Sep 30 2019 |
|
|
|
Sep 30 2020 |
|
|
Sep 30 2019 |
|
Net
earnings (loss) |
|
$ |
408 |
|
|
$ |
(310 |
) |
|
$ |
1,027 |
|
|
|
$ |
(1,184 |
) |
|
$ |
4,819 |
|
Per common share |
–
basic |
|
$ |
0.35 |
|
|
$ |
(0.26 |
) |
|
$ |
0.87 |
|
|
|
$ |
(1.00 |
) |
|
$ |
4.04 |
|
|
– diluted |
|
$ |
0.35 |
|
|
$ |
(0.26 |
) |
|
$ |
0.87 |
|
|
|
$ |
(1.00 |
) |
|
$ |
4.03 |
|
Adjusted net
earnings (loss) from operations (1) |
|
$ |
135 |
|
|
$ |
(772 |
) |
|
$ |
1,229 |
|
|
|
$ |
(932 |
) |
|
$ |
3,109 |
|
Per common share |
– basic |
|
$ |
0.11 |
|
|
$ |
(0.65 |
) |
|
$ |
1.04 |
|
|
|
$ |
(0.79 |
) |
|
$ |
2.61 |
|
|
– diluted |
|
$ |
0.11 |
|
|
$ |
(0.65 |
) |
|
$ |
1.04 |
|
|
|
$ |
(0.79 |
) |
|
$ |
2.60 |
|
Cash flows from
(used in) operating activities |
|
$ |
2,070 |
|
|
$ |
(351 |
) |
|
$ |
2,518 |
|
|
|
$ |
3,444 |
|
|
$ |
6,375 |
|
Adjusted funds
flow (2) |
|
$ |
1,740 |
|
|
$ |
415 |
|
|
$ |
2,881 |
|
|
|
$ |
3,492 |
|
|
$ |
7,773 |
|
Per common share |
– basic |
|
$ |
1.47 |
|
|
$ |
0.35 |
|
|
$ |
2.43 |
|
|
|
$ |
2.96 |
|
|
$ |
6.51 |
|
|
– diluted |
|
$ |
1.47 |
|
|
$ |
0.35 |
|
|
$ |
2.43 |
|
|
|
$ |
2.96 |
|
|
$ |
6.50 |
|
Cash flows used in
investing activities |
|
$ |
643 |
|
|
$ |
693 |
|
|
$ |
908 |
|
|
|
$ |
2,195 |
|
|
$ |
6,401 |
|
Net capital
expenditures (3) |
|
$ |
771 |
|
|
$ |
421 |
|
|
$ |
963 |
|
|
|
$ |
2,030 |
|
|
$ |
6,065 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Daily production,
before royalties |
|
|
|
|
|
|
|
|
|
|
|
Natural gas (MMcf/d) |
|
1,362 |
|
|
1,462 |
|
|
1,469 |
|
|
|
1,421 |
|
|
1,504 |
Crude oil and NGLs (bbl/d) |
|
884,342 |
|
|
921,895 |
|
|
931,546 |
|
|
|
914,859 |
|
|
829,031 |
Equivalent production (BOE/d) (4) |
|
1,111,286 |
|
|
1,165,487 |
|
|
1,176,361 |
|
|
|
1,151,693 |
|
|
1,079,641 |
(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.
- Net earnings of $408 million and adjusted net earnings of $135
million were realized in Q3/20, a significant improvement over
Q2/20 levels. The increases in net earnings and adjusted net
earnings are primarily a result of strong production volumes,
continued reduction in operating cost levels and improved commodity
prices in Q3/20.
- Cash flows from operating activities were $2,070 million in
Q3/20, a significant increase over Q2/20 levels.
- Canadian Natural generated quarterly adjusted funds flow of
$1,740 million in Q3/20, an increase of 319% over Q2/20 levels,
driven by the Company's effective and efficient operations as well
as higher commodity prices in the quarter.
- Canadian Natural generated approximately $467 million in free
cash flow in Q3/20, after net capital expenditures of $771 million
and dividend payments of $502 million in the quarter, reflecting
the strength of the Company's effective and efficient operations
and its high quality, long life low decline asset base.
- Canadian Natural maintained a strong financial position in
Q3/20 and reduced net debt by approximately $1.1 billion, from
Q2/20 levels.
- The Company had significant liquidity available at September
30, 2020 of approximately $4.2 billion, including committed
and undrawn credit facilities, cash balances and short-term
investments.
- The Company effectively executed on its curtailment
optimization strategy by utilizing its high quality, flexible asset
base to maximize production to offset the previously announced
maintenance and turnaround activities in the Oil Sands Mining and
Upgrading segment.
- In Q3/20, the Company achieved quarterly production volumes of
1,111,286 BOE/d, including liquids production of 884,342 bbl/d
which decreased as expected 5% and 4% from Q3/19 and Q2/20 levels
respectively. The decrease was due to the planned maintenance and
turnaround activities in the Oil Sands Mining and Upgrading
segment, primarily offset by strong thermal in situ production as a
result of the Company's curtailment optimization strategy and
improved commodity pricing in Q3/20.
- Canadian Natural's North America Exploration and Production
("E&P") liquids production averaged 494,952 bbl/d in Q3/20, a
10% increase from Q3/19 levels and a 20% increase from Q2/20
levels. The increase over both periods was due to the Company's
curtailment optimization strategy, primarily as a result of
increased thermal in situ production at Kirby North and Jackfish as
well as the optimization of steam cycles at Primrose.
- Canadian Natural's continued focus on delivering effective and
efficient operations and cost control across its entire asset base
was also demonstrated as the Company's North American E&P
liquids, including thermal in situ operations, achieved operating
costs of $9.80/bbl (US$7.36/bbl) in Q3/20, a decrease of 17% from
Q3/19 levels and a decrease of 16% from Q2/20 levels.
- Canadian Natural's thermal in situ assets achieved record daily
production levels in Q3/20, averaging 287,978 bbl/d, an increase of
40% and 35% over Q3/19 and Q2/20 levels respectively. The record
daily production levels in Q3/20 was as a result of the Company
leveraging the flexibility of its thermal in situ assets to
maximize production during planned maintenance and turnaround
activities in the Company's Oil Sands Mining and Upgrading segment
as a part of the Company's curtailment optimization strategy.
- Thermal in situ achieved low operating costs in Q3/20,
averaging $7.85/bbl (US$5.89/bbl), a decrease of 20% and 23% from
Q3/19 and Q2/20 levels respectively. The decrease in unit operating
costs was primarily due to higher production volumes and continued
focus on effective and efficient operations.
- Kirby North had strong quarterly production of approximately
42,400 bbl/d in Q3/20, and has been producing above its nameplate
capacity of 40,000 bbl/d since achieving full ramp-up in June
2020.
- At Jackfish, the Company achieved quarterly production of
122,346 bbl/d in Q3/20, a record quarterly production level since
acquiring the asset in June 2019.
- The Company's world class Oil Sands Mining and Upgrading assets
averaged 350,633 bbl/d of SCO production in Q3/20, decreasing by
19% and 24% from Q3/19 and Q2/20 levels respectively, primarily due
to planned maintenance and turnaround activities at both the
Athabasca Oil Sands Project ("AOSP") and Horizon.
- Operating costs from the Company's Oil Sands Mining and
Upgrading assets averaged $23.81/bbl (US$17.88/bbl) of SCO in Q3/20
and remain industry leading, driven by the Company's continued
focus on cost control.
- A strategic advantage of Canadian Natural is its flexible
portfolio of assets, allowing the Company to allocate capital to
its highest return projects, maximizing value for the Company's
shareholders. As a result of improved natural gas prices, Canadian
Natural has strategically reallocated a portion of its capital
program to its high value, liquids rich natural gas assets at
Septimus and the assets recently acquired as part of the Painted
Pony Energy Ltd. ("Painted Pony") acquisition. As one of the
largest natural gas producers in Canada, the Company's natural gas
assets provide significant value. The Company's natural gas
production, targeted at over 1.6 Bcf/d in Q4/20, and associated
natural gas liquids is forecast to generate approximately $1.2
billion in annualized operating cash flow at current strip pricing.
- Canadian Natural drilled seven wells at Septimus in Q3/20, with
one additional well drilled subsequent to quarter end. All eight
wells are expected to be on production in Q4/20 at a targeted rate
of 41 MMcf/d and 2,500 bbl/d of NGLs, for a cost of approximately
$5,000 per flowing BOE.
- Subsequent to quarter end, in October 2020, Canadian Natural
initiated drilling the first of seven wells on the high quality
Montney lands acquired with the Painted Pony acquisition. These
wells are expected to come on production in the first half of 2021
at a targeted initial rate of 54 MMcf/d and 440 bbl/d of NGLs.
- Canadian Natural targets to release its 2021 capital and
operational budget in December 2020.
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”) and 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, representing approximately 79% of the Company's
total liquids production in Q3/20, the majority of which is zero
decline high value SCO production from the Company's world class
Oil Sands Mining and Upgrading assets. The remaining balance of
long life low decline production comes from Canadian Natural's top
tier thermal in situ oil sands operations and the Company's Pelican
Lake heavy crude oil assets. 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.
In addition, 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, in the right economic conditions, 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 |
Nine Months Ended Sep 30 |
|
|
|
|
2020 |
2019 |
(number
of wells) |
Gross |
Net |
Gross |
Net |
Crude oil |
43 |
|
37 |
|
80 |
|
74 |
|
Natural gas |
25 |
|
21 |
|
21 |
|
15 |
|
Dry |
— |
|
— |
|
3 |
|
3 |
|
Subtotal |
68 |
|
58 |
|
104 |
|
92 |
|
Stratigraphic test / service wells |
426 |
|
372 |
|
411 |
|
358 |
|
Total |
494 |
|
430 |
|
515 |
|
450 |
|
Success rate (excluding stratigraphic test / service wells) |
|
100 |
% |
|
97 |
% |
- The Company's total crude oil and natural gas drilling program
of 58 net wells for the nine months ended September 30, 2020,
excluding stratigraphic/service wells, represents a decrease of 34
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 |
Nine Months Ended |
|
Sep 30 2020 |
Jun 30 2020 |
Sep 30 2019 |
Sep 30 2020 |
Sep 30 2019 |
Crude oil and NGLs production (bbl/d) |
206,974 |
200,699 |
|
244,267 |
|
212,064 |
|
234,944 |
|
Net wells targeting crude
oil |
— |
2 |
|
33 |
|
30 |
|
70 |
|
Net
successful wells drilled |
— |
2 |
|
33 |
|
30 |
|
68 |
|
Success rate |
— |
100 |
% |
100 |
% |
100 |
% |
97 |
% |
- Canadian Natural's North America E&P crude oil and NGL
production volumes, excluding the Company's thermal in situ
operations, averaged 206,974 bbl/d, a decrease of 15% from Q3/19
levels and an increase of 3% from Q2/20 levels. The decrease from
Q3/19 reflects natural declines and limited investment, while the
increase over Q2/20 reflects the reinstatement of production as a
result of the Company curtailing production in Q2/20 due to low
commodity prices.
- Primary heavy crude oil production averaged 70,982 bbl/d in
Q3/20, a decrease of 19% from Q3/19 levels and an increase of 13%
from Q2/20 levels. The decrease in production relative to Q3/19 was
due to natural field declines and low levels of field activity due
to the Government of Alberta's curtailment rules. The increase from
Q2/20 was due to the reinstatement of previously shut-in production
as a result of improved commodity prices in Q3/20.
- Operating costs in the Company's primary heavy crude oil
operations in Q3/20 averaged $15.96/bbl (US$11.98/bbl), a 7%
decrease from Q3/19 levels and an 11% decrease from Q2/20 levels as
the Company focused on cost control.
- Pelican Lake production averaged 56,392 bbl/d in Q3/20, a
decrease of 6% from Q3/19 levels and a slight increase from Q2/20
levels. The decrease from Q3/19 levels reflects the field's low
natural decline rate, while the slight increase from Q2/20 levels
was primarily due to reduced well servicing activity in Q2/20 due
to low commodity prices.
- The Company continues to demonstrate effective and efficient
operations as Q3/20 operating costs at Pelican Lake averaged
$5.76/bbl (US$4.32/bbl), a decrease of 6% from Q3/19 levels and a
decrease of 9% from Q2/20 levels, reflecting the Company's
continued focus on cost control.
- North American light crude oil and NGL production averaged
79,600 bbl/d in Q3/20, a decrease of 17% and 3% from Q3/19 and
Q2/20 levels respectively. The decrease from Q3/19 was a result of
natural field declines. The decrease from Q2/20 was primarily a
result of natural field declines and deferral of maintenance
activities into Q3/20 as a result of COVID-19.
- Operating costs in the Company's North America light crude oil
and NGL areas averaged $14.13/bbl (US$10.61/bbl) in Q3/20, a
decrease of 6% and 2% from Q3/19 and Q2/20 levels respectively as a
result of the Company's continued focus on cost control.
Thermal In Situ
Oil Sands |
|
|
|
Three Months Ended |
Nine Months Ended |
|
|
|
|
|
|
|
Sep 30 2020 |
Jun 30 2020 |
Sep 30 2019 |
Sep 30 2020 |
Sep 30 2019 |
Bitumen production (bbl/d) |
287,978 |
212,807 |
206,395 |
243,193 |
|
137,124 |
Net wells targeting
bitumen |
— |
— |
— |
6 |
|
— |
Net
successful wells drilled |
— |
— |
— |
6 |
|
— |
Success rate |
— |
— |
— |
100 |
% |
— |
- Canadian Natural's thermal in situ assets achieved record daily
production levels in Q3/20, averaging 287,978 bbl/d, an increase of
40% and 35% over Q3/19 and Q2/20 levels respectively. The record
daily production levels in Q3/20 was as a result of the Company
leveraging the flexibility of its thermal in situ assets to
maximize production during planned maintenance and turnaround
activities in the Company's Oil Sands Mining and Upgrading segment
as a part of the Company's curtailment optimization strategy.
- Thermal in situ achieved low operating costs in Q3/20,
averaging $7.85/bbl (US$5.89/bbl), a decrease of 20% and 23% from
Q3/19 and Q2/20 levels respectively. The decrease in unit operating
costs was primarily due to higher production volumes and continued
focus on effective and efficient operations.
- Kirby North had strong quarterly production of approximately
42,400 bbl/d in Q3/20, and has been producing above its nameplate
capacity of 40,000 bbl/d since achieving full ramp-up in June
2020.
- At Jackfish, the Company achieved quarterly production of
122,346 bbl/d in Q3/20, a record quarterly production level since
acquiring the asset in June 2019.
- The Company continues to see positive results from its targeted
two year solvent enhanced oil recovery technology pilot at Kirby
South, with increased bitumen production, a SOR reduction of up to
50%, Greenhouse Gas ("GHG") intensity reduction of up to 50% and
high solvent recovery. The Company will continue to monitor the
solvent recovery of the pilot over the next year. This technology
has the potential for application throughout the Company's
extensive thermal in situ asset base. At Primrose, in the steam
flood area, the Company is targeting to commence a second solvent
pilot in the latter half of 2021.
North America
Natural Gas |
|
|
|
Three Months Ended |
Nine Months Ended |
|
|
|
|
|
|
|
Sep 30 2020 |
Jun 30 2020 |
Sep 30 2019 |
Sep 30 2020 |
Sep 30 2019 |
Natural gas production (MMcf/d) |
1,340 |
|
1,431 |
|
1,425 |
|
1,393 |
|
1,454 |
|
Net wells targeting natural
gas |
9 |
|
1 |
|
5 |
|
21 |
|
16 |
|
Net
successful wells drilled |
9 |
|
1 |
|
5 |
|
21 |
|
15 |
|
Success rate |
100 |
% |
100 |
% |
100 |
% |
100 |
% |
94 |
% |
- North America natural gas production averaged 1,340 MMcf/d in
Q3/20, a decrease of 6% from both Q3/19 and Q2/20 levels. The
decrease in production was primarily as a result of natural field
declines and planned maintenance and turnaround activities
undertaken in the third quarter of 2020, partially offset by
natural gas volumes added through low cost opportunities identified
by the Company in May 2020.
- Through additional cost efficiencies, the Company now targets
to bring on these highly economic incremental volumes for less than
$2,000 per flowing BOE, approximately $1,000 per flowing BOE lower
than previously estimated. Current production from these additional
gas volumes is 58 MMcf/d and the Company is on track to achieve
annualized production of approximately 35 MMcf/d from these
opportunities.
- North America natural gas operating costs were strong in Q3/20,
averaging $1.14/Mcf, an increase of 7% and 3% from Q3/19 and Q2/20
levels respectively. The increase in operating costs relative to
prior periods reflects lower production volumes in Q3/20. As a
result of the Company's strategy to own and control its
infrastructure and its continued focus on cost control, natural gas
operating costs for the first nine months of 2020 were comparable
to the first nine months of 2019.
- Operating costs at Septimus remained strong, averaging
$0.28/Mcfe in Q3/20, a 10% decrease from Q2/20 levels.
- A strategic advantage of Canadian Natural is its flexible
portfolio of assets, allowing the Company to allocate capital to
its highest return projects, maximizing value for the Company's
shareholders. As a result of improved natural gas prices, Canadian
Natural has strategically reallocated a portion of its capital
program to its high value, liquids rich natural gas assets at
Septimus and the assets recently acquired as part of the Painted
Pony acquisition. The Company's natural gas production, targeted at
over 1.6 Bcf/d in Q4/20, and associated natural gas liquids is
forecast to generate approximately $1.2 billion in annualized
operating cash flow at current strip pricing.
- Canadian Natural drilled seven wells at Septimus in Q3/20, with
one additional well drilled subsequent to quarter end. All eight
wells are expected to be on production in Q4/20 at a targeted rate
of 41 MMcf/d and 2,500 bbl/d of NGLs, for a cost of approximately
$5,000 per flowing BOE.
- Subsequent to quarter end, in October 2020, Canadian Natural
initiated drilling the first of seven wells on the high quality
Montney lands acquired with the Painted Pony acquisition. These
wells are expected to come on production in the first half of 2021
at a targeted initial rate of 54 MMcf/d and 440 bbl/d of NGLs.
- In Q3/20, 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 34% was exported to other North American
markets and sold internationally, while the remaining 17% was
exposed to AECO/Station 2 pricing.
International Exploration and
Production
|
Three Months Ended |
Nine Months Ended |
|
|
|
|
|
|
|
Sep 30 2020 |
Jun 30 2020 |
Sep 30 2019 |
Sep 30 2020 |
Sep 30 2019 |
Crude oil production
(bbl/d) |
|
|
|
|
|
North Sea |
21,220 |
26,627 |
27,454 |
|
25,186 |
|
26,927 |
|
Offshore Africa |
17,537 |
17,444 |
21,227 |
|
16,977 |
|
22,341 |
|
Natural gas production
(MMcf/d) |
|
|
|
|
|
North Sea |
5 |
15 |
20 |
|
14 |
|
24 |
|
Offshore Africa |
17 |
16 |
24 |
|
14 |
|
26 |
|
Net wells targeting crude
oil |
— |
— |
3.0 |
|
1.0 |
|
5.5 |
|
Net
successful wells drilled |
— |
— |
3.0 |
|
1.0 |
|
5.5 |
|
Success rate |
— |
— |
100 |
% |
100 |
% |
100 |
% |
- International E&P crude oil production volumes averaged
38,757 bbl/d in Q3/20, a decrease of 20% and 12% from Q3/19 and
Q2/20 levels respectively.
- In the North Sea, crude oil production volumes averaged 21,220
bbl/d in Q3/20, a decrease of 23% and 20% from Q3/19 and Q2/20
levels respectively. The decrease in production in Q3/20 was
primarily a result of planned maintenance and turnaround
activities, the permanent cessation of production from the Banff
and Kyle fields and natural field declines.
- Crude oil operating costs in the North Sea increased by 13% and
48% from Q3/19 and Q2/20 levels respectively, averaging $42.10/bbl
(US$31.61/bbl) in Q3/20. The increase in operating costs from the
comparable periods primarily reflects lower production volumes on a
relatively fixed cost base, together with the timing of liftings
from various fields that have different cost structures.
- Offshore Africa crude oil production volumes averaged 17,537
bbl/d in Q3/20, a decrease of 17% from Q3/19 levels and comparable
to Q2/20 levels. The decrease in production from Q3/19 levels was
primarily due to natural field declines.
- Offshore Africa crude oil operating costs averaged $16.41/bbl
(US$12.32/bbl) in Q3/20, an increase of 48% and 55% from Q3/19 and
Q2/20 levels respectively. The increase in operating costs from the
comparable periods was primarily due to the timing of liftings from
various fields that have different cost structures.
- Subsequent to quarter end, as announced on October 28, 2020,
the operator of the South Africa block 11B/12B has made a
significant gas condensate discovery on the Luiperd prospect. This
discovery follows the previously announced Brulpadda discovery in
2019. The Luiperd exploratory well encountered 73 meters of net gas
condensate pay, and is currently being tested with deliverability
results targeted by year end 2020. Canadian Natural has a 20%
working interest and expects the costs for this well to be fully
carried pursuant to Farm-Out Agreements.
North America Oil Sands Mining and
Upgrading
|
Three Months Ended |
Nine Months Ended |
|
|
|
|
|
|
|
Sep 30 2020 |
Jun 30 2020 |
Sep 30 2019 |
Sep 30 2020 |
Sep 30 2019 |
Synthetic crude oil production (bbl/d) (1) (2) |
350,633 |
|
464,318 |
|
432,203 |
|
417,439 |
|
407,695 |
|
(1) SCO production before royalties and excludes volumes
consumed internally as diesel.(2) Consists of heavy and light
synthetic crude oil products.
- The Company's world class Oil Sands Mining and Upgrading assets
averaged 350,633 bbl/d of SCO production in Q3/20, decreasing by
19% and 24% from Q3/19 and Q2/20 levels respectively, primarily due
to planned maintenance and turnaround activities at both AOSP and
Horizon.
- Operating costs from the Company's Oil Sands Mining and
Upgrading assets remain industry leading, driven by the Company's
continued focus on cost control. In Q3/20, operating costs averaged
$23.81/bbl (US$17.88/bbl) of SCO, an increase of 19% and 34% from
Q3/19 and Q2/20 levels respectively. The increase in operating
costs in Q3/20 includes the cost of planned maintenance and
turnaround activities and impact of lower production volumes.
- During the maintenance period at the Scotford Upgrader
("Scotford"), the front end capacity was expanded to approximately
320,000 bbl/d from the previous capacity of 300,000 bbl/d. This
additional capacity at AOSP is targeted to increase margins,
further maximizing value of the Company's Oil Sands Mining and
Upgrading assets.
- At the non-operated Scotford Upgrader, maintenance activities
were completed 13 days later than originally planned. As well, upon
start-up of Scotford, additional work was identified resulting in
the plant running at reduced gross rates until October 16, 2020. As
a result, gross production at AOSP averaged approximately 267,000
bbl/d in October 2020.
- In late October, Albian ran at gross rates of approximately
345,000 bbl/d of bitumen, and Scotford processed rates at
approximately 323,000 bbl/d. As a result of mandatory curtailments
in November 2020, AOSP will target to resume production near these
full expanded capacity rates in December 2020.
- Maintenance activities at the Albian mines were aligned with
the timing of maintenance and turnaround activities at
Scotford.
- Planned maintenance and turnaround activities at Horizon, which
commenced in late September, were successfully completed subsequent
to quarter end. Upon start-up, a small bore pipe failed, which
resulted in the plant running initially at reduced rates. The cost
of the repair was minor and is included within the Horizon
maintenance budget. Production at Horizon in October 2020 averaged
approximately 134,000 bbl/d of SCO, and is currently at
approximately 260,000 bbl/d.
MARKETING
|
|
Three Months Ended |
|
|
Nine Months Ended |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sep 30 2020 |
|
Jun 30 2020 |
|
Sep 30 2019 |
|
|
Sep 30 2020 |
|
Sep 30 2019 |
Crude oil and NGLs
pricing |
|
|
|
|
|
|
|
|
|
|
|
WTI benchmark price (US$/bbl) (1) |
|
$ |
40.94 |
|
|
$ |
27.85 |
|
|
$ |
56.45 |
|
|
|
$ |
38.30 |
|
|
$ |
57.06 |
|
WCS heavy differential as a percentage of WTI (%) (2) |
|
22 |
% |
|
41 |
% |
|
22 |
% |
|
|
36 |
% |
|
21 |
% |
SCO price (US$/bbl) |
|
$ |
38.61 |
|
|
$ |
23.28 |
|
|
$ |
56.87 |
|
|
|
$ |
35.11 |
|
|
$ |
56.36 |
|
Condensate benchmark pricing (US$/bbl) |
|
$ |
37.55 |
|
|
$ |
22.19 |
|
|
$ |
52.00 |
|
|
|
$ |
35.10 |
|
|
$ |
52.79 |
|
Average realized pricing before risk management (C$/bbl) (3) |
|
$ |
40.14 |
|
|
$ |
18.97 |
|
|
$ |
55.19 |
|
|
|
$ |
28.91 |
|
|
$ |
57.49 |
|
Natural gas pricing |
|
|
|
|
|
|
|
|
|
|
|
AECO benchmark price (C$/GJ) |
|
$ |
2.03 |
|
|
$ |
1.81 |
|
|
$ |
0.99 |
|
|
|
$ |
1.96 |
|
|
$ |
1.31 |
|
Average realized pricing before risk management (C$/Mcf) |
|
$ |
2.31 |
|
|
$ |
2.03 |
|
|
$ |
1.64 |
|
|
|
$ |
2.19 |
|
|
$ |
2.24 |
|
(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 a balanced and diverse product mix with a
history of strong expertise in marketing its products.
- Commodity prices, including WTI, have improved and stabilized
relative to the volatility experienced in the first half of 2020
and Western Canadian Select ("WCS") differentials have tightened as
a result of returning demand combined with reduced activity in the
Western Canadian Sedimentary Basin ("WCSB"), production declines
and price-related curtailments and shut-ins.
- Natural gas prices have also improved in Q3/20, with AECO
averaging $2.03/GJ, an increase of 105% and 12% from the Q3/19
and Q2/20 averages respectively. The increase in natural gas prices
from the comparable periods primarily reflects lower WCSB
production.
- Canadian Natural has storage at major hubs in Edmonton and
Hardisty, which allows the Company to adjust monthly sales and
manage pipeline logistical constraints and production fluctuations,
as well as pricing differences from month to month.
- Market egress will continue to improve in the mid-term as
construction is progressing on the Trans Mountain Expansion ("TMX")
and Keystone XL projects, on which Canadian Natural has 94,000
bbl/d and 200,000 bbl/d respectively of committed capacity.
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.
- Keystone XL construction continues to progress in both Canada
and the United States.
- 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 continues to ramp-up to its targeted processing
capacity of approximately 80,000 bbl/d of diluted bitumen, which
will improve heavy oil demand in western Canada, effectively
increasing egress out of the WCSB. For more details, please contact
the North West Redwater Partnership.
- Subsequent to quarter end, the Government of Alberta has
suspended the mandatory curtailment production limits as of
December 2020 and will only issue curtailment orders in 2021 when
deemed necessary.
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
1,111,286 BOE/d in Q3/20, with approximately 98% of total
production located in G7 countries.
- Canadian Natural generated quarterly adjusted funds flow of
$1,740 million in Q3/20, an increase of 319% over Q2/20 levels,
driven by the Company's effective and efficient operations as well
as higher commodity prices in the quarter.
- Canadian Natural generated approximately $467 million in free
cash flow, after net capital expenditures and dividend payments in
Q3/20 reflecting the strength of the Company's effective and
efficient operations and its high quality, long life low decline
asset base.
- Returns to shareholders totaled $502 million in Q3/20 by way of
dividends paid on July 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 and
reduced net debt in Q3/20 from Q2/20 levels by approximately $1.1
billion. The Company has significant liquidity available at
September 30, 2020 of approximately $4.2 billion, including
committed and undrawn credit facilities, cash balances and
short-term investments.
- The Company repaid $1.0 billion in medium term notes that
matured in August 2020.
- The Company has approximately $5.5 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.
- Debt to book capitalization and debt to adjusted EBITDA
remained strong at 40.3% and 3.4x 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 are shown in its ability to
generate significant and sustainable free cash flow over the long
term, combined with its low cost structure and industry leading
corporate break-even price of WTI US$30-31 per barrel.
- The Company's 2020 capital program is on target to be
approximately $2.7 billion, before acquisitions, while maintaining
base production near 2019 levels.
- Subsequent to quarter end, the Company declared a quarterly
dividend of $0.425 per share, payable on January 5, 2021.
ENVIRONMENTAL, SOCIAL AND GOVERNANCE ("ESG")
HIGHLIGHTS
Canada and Canadian Natural are well positioned
to deliver responsibly produced energy the world needs through
leading ESG performance.
In September 2020, Canadian Natural published
its 2019 Stewardship Report to Stakeholders, which is available on
the Company's website at
https://www.cnrl.com/report-to-stakeholders. The report displays
how Canadian Natural continues to focus on safe, reliable,
effective and efficient operations while minimizing its
environmental footprint. Canadian Natural outlined its pathway to
lower carbon emissions and its journey to achieve its aspirational
goal of net zero GHG emissions in the oil sands. Highlights from
the Company's 2019 report are as follows:
- Achieved record low corporate total recordable injury frequency
("TRIF") in 2019, with a TRIF of 0.28 in 2019 compared to 0.57 in
2015. The Company's TRIF is down 51% since 2015, while man-hours
have increased over this time period.
- 3 of the 8 independent directors of the Board are female,
achieving the Company's Board gender diversity target of no less
than 30% of independent directors.
- Awarded over $550 million in contracts to more than 150
Indigenous businesses in 2019.
- Canadian Natural has invested over $3.7 billion in research and
development over the last decade and continues to invest in
technology to unlock reserves, become more effective and efficient
and reduce the Company's environmental footprint. Canadian
Natural's culture of continuous improvement leverages the use of
technology and innovation to drive sustainable operations and
long-term value for shareholders. In 2019, the Company invested
$77.4 million in GHG research, technologies and projects as part of
its research and development budget.
- Canadian Natural's corporate GHG emissions intensity has
decreased by 16% from 2015 to 2019, a material reduction in
emissions intensity.
- 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 owners of carbon capture
capacity in the oil and natural gas sector globally. As part of our
comprehensive GHG emissions reduction strategy, our CCS projects
include carbon dioxide ("CO2") storage in geological formations,
the use of CO2 in enhanced oil recovery techniques and injection of
CO2 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 and recently reached the milestone
of 5 million tonnes of stored carbon dioxide. Quest highlights the
crude oil and natural gas industry'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.
- The Company reduced its GHG emissions intensity in its Oil
Sands Mining and Upgrading and thermal in situ segments by 36% from
2016 to 2019.
- The Company reduced methane emissions in its North American
E&P segment by 15% from 2016 to 2019.
- Oil Sands Mining and Upgrading fresh river water use intensity
decreased by 68% from 2012 to 2019.
- Thermal in situ fresh water use intensity decreased by 61% from
2012 to 2019.
- In 2019, Canadian Natural abandoned 2,035 inactive wells in its
North America E&P segment, a corporate record, and an increase
of 57% over 2018 levels. The Company also submitted 912 reclamation
certificates in 2019.
- The Company has reclaimed more than 7,600 hectares of land
since 2015 in its North America E&P segment, equivalent to
approximately 9,400 Canadian football fields. In 2019 alone, the
Company reclaimed 2,160 hectares of land, a 56% increase from
2018.
- Commercial engineering of the In Pit Extraction Process
("IPEP") at 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 pleased
with the results from the initial testing phase of the pilot, which
showed 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.
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 oil 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 NGL 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 from (used in) 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
from (used in) 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.
Operating cash flow is a forward looking
supplementary measure that represents the Company’s currently
forecasted cash flow from operating activities for the stated
forecast period for a particular product or group of products or
segment, excluding the impact of administration expense, interest,
foreign exchange, and taxes. The Company considers operating cash
flow by product or segment a key measure in evaluating the
contribution of a product to the Company’s cash flow from operating
activities.
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 nine months ended September 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 nine months ended September 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, November 5,
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, November 19, 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 2768477
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, T2P4J8Phone:
403-514-7777 Email: ir@cnrl.comwww.cnrl.com |
|
|
TIM S. MCKAYPresidentMARK A.
STAINTHORPEChief Financial Officer and Senior
Vice-President, FinanceJASON M. POPKOManager,
Investor RelationsTrading Symbol - CNQToronto Stock ExchangeNew
York Stock Exchange |
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