Canadian Natural Resources Limited Announces 2019 First Quarter
Results
Commenting on the Company's first quarter 2019 results, Steve Laut,
Executive Vice-Chairman of Canadian Natural stated, "In the first
quarter, the Company demonstrated the resilience and strength of
its long life low decline and low capital exposure assets,
generating significant adjusted funds flow of approximately $2.2
billion. The Company was able to achieve adjusted funds flow that
exceeded net capital expenditures by approximately $1.3 billion,
largely due to a strong operational quarter and improvement in
crude oil differentials, driven by the Government of Alberta's
mandatory production curtailments which is strongly supported by
Canadian Natural.
Canadian Natural's top tier low sustaining
capital required to maintain production levels, combined with
industry leading effective and efficient operations, were evident
in Q1/19 as adjusted funds flow less net capital expenditures was
comparable to Q1/18 when West Texas Intermediate ("WTI") was
approximately US$8.00/bbl higher."
Canadian Natural's President, Tim McKay, added,
"Operations were strong in the first quarter as our large, balanced
and diverse asset base allowed the Company to strategically manage
through the mandatory production curtailments to maximize value.
Production was as expected in Q1/19, reaching approximately
1,035,000 BOE/d, consisting of 54% light crude oil, NGLs and
Synthetic Crude Oil ("SCO"), 22% heavy crude oil and 24% natural
gas.
Effective and efficient operations across the
Company continue to be a significant driver of value creation for
Canadian Natural. Our Oil Sands Mining and Upgrading segment Q1/19
operating costs were top tier at $21.46/bbl (US$16.14/bbl) of SCO.
Equally as impressive were our Conventional E&P assets
achieving operating costs of $12.68/BOE (US$9.54/BOE) in Q1/19, a
reduction of 6% from Q4/18 levels, strong results given mandatory
production curtailments in the quarter."
Canadian Natural's Chief Financial Officer, Mark
Stainthorpe, continued, "In the first quarter, Canadian Natural
realized solid results as profitability and value from our diverse
asset base generated net earnings of approximately $1.0 billion.
Net earnings were up dramatically from Q4/18, reflecting the
dysfunctional crude oil market which existed in Q4/18 and the
success of the Government of Alberta's mandatory production
curtailment program to restore a normal market in Q1/19.
The Company's capital discipline and financial
strength resulted in robust free cash flow of $860 million, after
net capital expenditures and dividends. Share purchases were $241
million (6.65 million shares) in Q1/19 pursuant to the Company's
free cash flow allocation policy. As a result of the increased
confidence in free cash flow levels for the remainder of 2019, the
rate of share purchases has increased as Q2/19 commenced, with
purchases totaling $159 million (4.05 million shares) from April 1,
2019 to May 8th, 2019."
QUARTERLY HIGHLIGHTS
|
|
Three Months Ended |
|
|
|
|
|
|
|
($
millions, except per common share amounts) |
|
Mar 31 2019 |
|
|
Dec 31 2018 |
|
|
Mar 31 2018 |
|
Net earnings
(loss) |
|
$ |
961 |
|
|
$ |
(776 |
) |
|
$ |
583 |
|
Per common share |
– basic |
|
$ |
0.80 |
|
|
$ |
(0.64 |
) |
|
$ |
0.48 |
|
|
– diluted |
|
$ |
0.80 |
|
|
$ |
(0.64 |
) |
|
$ |
0.47 |
|
Adjusted net
earnings (loss) from operations (1) |
|
$ |
838 |
|
|
$ |
(255 |
) |
|
$ |
885 |
|
Per common share |
– basic |
|
$ |
0.70 |
|
|
$ |
(0.21 |
) |
|
$ |
0.72 |
|
|
– diluted |
|
$ |
0.70 |
|
|
$ |
(0.21 |
) |
|
$ |
0.71 |
|
Cash flows from operating
activities |
|
|
$ |
996 |
|
|
$ |
1,397 |
|
|
$ |
2,469 |
|
Adjusted funds
flow (2) |
|
$ |
2,240 |
|
|
$ |
1,229 |
|
|
$ |
2,323 |
|
Per common share |
– basic |
|
$ |
1.87 |
|
|
$ |
1.02 |
|
|
$ |
1.90 |
|
|
– diluted |
|
$ |
1.86 |
|
|
$ |
1.02 |
|
|
$ |
1.89 |
|
Cash
flows used in investing activities |
|
$ |
1,029 |
|
|
$ |
1,042 |
|
|
$ |
1,369 |
|
Net
capital expenditures (3) |
|
$ |
977 |
|
|
$ |
1,181 |
|
|
$ |
1,103 |
|
|
|
|
|
|
|
|
Daily
production, before royalties |
|
|
|
|
|
|
Natural gas (MMcf/d) |
|
1,510 |
|
|
1,488 |
|
|
1,614 |
|
Crude oil and NGLs (bbl/d) |
|
783,512 |
|
|
833,358 |
|
|
854,558 |
|
Equivalent production (BOE/d) (4) |
|
1,035,212 |
|
|
1,081,368 |
|
|
1,123,546 |
|
- 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
Management’s Discussion and Analysis (“MD&A”).
- Adjusted funds flow (previously
referred to as funds flow from operations) is a non-GAAP measure
that the Company considers key 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 MD&A.
- 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 quarterly capital budget.
For additional information and details, refer to the net capital
expenditures table in the Company's MD&A.
- 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 $961 million were
realized in Q1/19, increases of $1,737 million and $378 million
over Q4/18 and Q1/18 levels, respectively. Adjusted net earnings of
$838 million were achieved in Q1/19, a $1,093 million increase over
Q4/18 levels.
- Cash flows from operating
activities were $996 million in Q1/19, a decrease of $401 million
compared to Q4/18 levels.
- Canadian Natural generated
significant quarterly adjusted funds flow of $2,240 million in
Q1/19, an increase of 82% or $1,011 million over Q4/18 levels. The
increase quarter over quarter was primarily due to strong
operations in the quarter and higher netbacks in all segments, as
crude oil markets in Canada returned to normal with the Government
of Alberta's mandatory production curtailments.
- Cash flows used in investing
activities remain disciplined at $1,029 million in Q1/19, in-line
with Q4/18 levels.
- Canadian Natural delivered strong
quarterly free cash flow of $860 million after net capital
expenditures of $977 million and dividend requirements of $403
million, reflecting the strength of our long life low decline asset
base and our effective and efficient operations.
- Canadian Natural is committed to
returns to shareholders, returning a total of $644 million in the
quarter, $403 million by way of dividends and $241 million by way
of share purchases.
- Share purchases for cancellation in the quarter totaled
6,650,000 common shares at a weighted average share price of
$36.24. Subsequent to quarter end and up to and including May 8,
2019, the Company executed on additional share purchases of
4,050,000 common shares for cancellation at a weighted average
share price of $39.34.
- In Q1/19 the Company increased its quarterly dividend by 12%
from Q4/18 levels, marking the 19th consecutive year that the
Company has increased its dividend, reflecting the Board of
Directors' confidence in Canadian Natural's sustainability and
robustness of the Company's asset base and its ability to generate
significant adjusted funds flow.
- Subsequent to quarter end, the Company declared a quarterly
dividend of $0.375 per share, payable on July 1, 2019.
- The Company's Board of Directors has approved a motion to renew
the Normal Course Issuance Bid ("NCIB") and the continuation
of the free cash flow allocation policy.
- The Company achieved quarterly
production volumes of 1,035,212 BOE/d in Q1/19, a decrease of 4%
from Q4/18 levels reflecting the Government of Alberta's mandatory
production curtailments.
- The Company continues to strategically adjust timing of planned
maintenance activities across its asset base, including Oil Sands
Mining and Upgrading, thermal in situ and North American
Exploration & Production ("E&P") to maximize value within
the current curtailment environment.
- At the Company's world class Oil
Sands Mining and Upgrading assets, industry leading operations
provided quarterly production of 416,206 bbl/d of Synthetic Crude
Oil ("SCO"), a decrease of 7% from Q4/18 levels. The decrease in
production was primarily due to mandatory curtailments, previously
announced accelerated maintenance activities as well as unplanned
maintenance.
- Operating costs were top tier, as the Company realized
quarterly unadjusted operating costs of $21.46/bbl (US$16.14/bbl)
of SCO in Q1/19, in-line with Q1/18 levels, strong results given
curtailment and maintenance activities in the quarter.
- As previously announced on May 1, 2019, Canadian Natural
provided a follow up on a fire which occurred at the Scotford
Upgrader on April 15, 2019, in which the Company has a 70%
interest. The fire was promptly extinguished, all personnel were
accounted for, and there were no reported injuries.
- The fire was contained to a process furnace in the North
Upgrader, while operations at the base upgrader plant ("South
Upgrader") were not impacted by the fire. The planned 38 day
turnaround began on April 14, 2019 at the Scotford Upgrader, during
which time the South Upgrader will run at a restricted net
processing rate of approximately 140,000 bbl/d of SCO. Upon
completion of the planned maintenance, May and June average net
production at the Albian mines is targeted to be approximately
171,500 bbl/d versus the Company's previously targeted net
curtailment production volumes at the Albian mines of approximately
178,500 bbl/d. The cost for repairs of the North Upgrader is
estimated to be approximately $15 million gross and is targeted to
be fully operational by early June. The Company continues to
optimize other assets in Alberta to mitigate the impacts of
curtailments on its production.
- International E&P quarterly
production volumes were strong in Q1/19, averaging 47,869 bbl/d,
increases of 11% and 17% from Q4/18 and Q1/18 levels respectively.
The increases were mainly as a result of successful 2018 drilling
and turnaround activities that were completed in Q4/18 in the North
Sea. Additionally, in Offshore Africa, successful 2018 drilling
contributed to International production increases from Q1/18,
partially offset by natural declines.
- International production volumes benefit from premium Brent
pricing, generating significant adjusted funds flow for the
Company.
- In the Company's thermal in situ
operations, pad additions at Primrose continue to be on budget and
ahead of schedule with initial production targeted in Q4/19. The
program targets to add approximately 26,000 bbl/d in the first 12
months of production. These pad additions are high return
activities as the Company utilizes available excess oil processing
and steam capacity at Primrose.
- As previously announced, at the
Company's Kirby North Steam Assisted Gravity Drainage ("SAGD")
project, top tier execution and strong productivity have resulted
in the project progressing two quarters ahead of the sanctioned
schedule with overall cost performance remaining on budget. The
commissioning of the central processing facility was also top tier
and as a result, the project began steaming on May 1, 2019 and
targets to progressively ramp up production towards Kirby North's
overall capacity of 40,000 bbl/d, in late 2020.
- Canadian Natural maintains strong
financial stability and liquidity represented by cash balances, and
committed and demand bank credit facilities. At March 31, 2019 the
Company had approximately $4,230 million of available liquidity,
including cash and cash equivalents.
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 and 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. 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 its
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 which can be optimized over time. Additionally,
by owning and operating most of the related infrastructure,
Canadian Natural is able to control major components of its
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
|
Three Months Ended Mar 31 |
|
|
|
|
2019 |
2018 |
(number
of wells) |
Gross |
|
Net |
|
Gross |
|
Net |
|
Crude oil |
30 |
|
30 |
|
127 |
|
122 |
|
Natural gas |
10 |
|
8 |
|
8 |
|
5 |
|
Dry |
1 |
|
1 |
|
2 |
|
2 |
|
Subtotal |
41 |
|
39 |
|
137 |
|
129 |
|
Stratigraphic test / service wells |
375 |
|
332 |
|
528 |
|
450 |
|
Total |
416 |
|
371 |
|
665 |
|
579 |
|
Success rate (excluding stratigraphic test / service wells) |
|
97 |
% |
|
98 |
% |
- The Company's total crude oil and
natural gas drilling program of 39 net wells for the three months
ended March 31, 2019, excluding strat/service wells, decreased by
90 net wells from the same period in 2018. The Company's drilling
levels reflect the disciplined capital allocation process and
continued actions to improve execution.
North America Exploration and Production
Crude oil and NGLs
– excluding Thermal In Situ Oil Sands |
|
Three Months Ended |
|
|
|
|
|
Mar 31 2019 |
|
Dec 31 2018 |
|
Mar 31 2018 |
|
Crude
oil and NGLs production (bbl/d) |
225,291 |
|
240,942 |
|
245,609 |
|
Net wells targeting crude
oil |
28 |
|
62 |
|
101 |
|
Net successful wells
drilled |
28 |
|
61 |
|
99 |
|
Success rate |
100 |
% |
98 |
% |
98 |
% |
- North America crude oil and NGLs
averaged 225,291 bbl/d in Q1/19, reflecting mandatory production
curtailments, representing a decrease of 6% from Q4/18 levels that
were already voluntarily curtailed by approximately 10,600 bbl/d.
- Canadian Natural's primary heavy crude oil production averaged
68,473 bbl/d in Q1/19, reflecting mandatory production
curtailments, and the strategic decision to reduce activity on
drilling, workovers, recompletions and optimization activities in a
curtailed market in Q1/19, representing a decrease of 14% from
Q4/18 levels that were already voluntarily curtailed by
approximately 9,600 bbl/d.
- Operating costs of $17.30/bbl were achieved in the Company's
primary heavy crude oil operations in the quarter, a 2% increase
from Q1/18 levels, strong results given lower production volumes
due to mandatory production curtailments.
- North America light crude oil and NGL production averaged
95,578 bbl/d in Q1/19, reflecting mandatory production curtailments
in the Company's light crude oil segment, representing a decrease
of 3% from Q4/18 levels that were already voluntarily curtailed by
approximately 1,000 bbl/d.
- Within the greater Wembley area, results continue to exceed
expectations. The Company brought 10 net wells on production in
Q1/19 that were drilled late in 2018, with initial 30 day liquids
production rates averaging approximately 580 bbl/d per well. An
additional 3 net wells are targeted to come on production in Q2/19
and Q3/19. Within the greater Wembley area, the Company has
identified 155 net Montney sections and 363 incremental potential
premium light crude oil and liquids rich well locations.
- In the Company's Karr area, 12 net wells came on production in
Q1/19, 9 were drilled in Q4/18 and 3 were drilled in Q1/19. Early
results have been strong from these wells, with total liquids
production of approximately 315 bbl/d per well, exceeding
expectations.
- In Southeast Saskatchewan and Manitoba, the Company drilled 9
net light crude oil wells in Q1/19. Subsequent to quarter end,
these wells came on stream and are currently producing
approximately 85 bbl/d per well, in-line with expectations.
Production from these Saskatchewan and Manitoba wells are not
impacted by production curtailments.
- In Q1/19 operating costs of $15.86/bbl were realized in the
Company's North America light crude oil and NGL areas, comparable
to Q1/18 levels.
- Pelican Lake quarterly production averaged 61,240 bbl/d in
Q1/19, a decrease of 2% from Q4/18 levels.
- Strong operating costs of $6.69/bbl were achieved in Q1/19 at
Pelican Lake, a reduction of 5% from Q1/18 levels.
- Subsequent to quarter end, in April 2019 facility consolidation
was completed on time and on budget, and as a result operating cost
savings of approximately $6 million per year are targeted.
- The Company targets to expand the polymer flood further in
Q2/19, with the conversion of 3 additional pads from water flood to
polymer flood.
- The Company’s annual 2019 North
America E&P crude oil and NGL production guidance remains
unchanged and is targeted to range between 221,000 bbl/d - 241,000
bbl/d.
Thermal In Situ
Oil Sands |
|
Three Months Ended |
|
|
|
|
|
Mar 31 2019 |
|
Dec 31 2018 |
|
Mar 31 2018 |
|
Bitumen
production (bbl/d) |
94,146 |
|
102,112 |
|
111,851 |
|
Net wells targeting
bitumen |
— |
|
41 |
|
22 |
|
Net
successful wells drilled |
— |
|
40 |
|
22 |
|
Success rate |
— |
|
98 |
% |
100 |
% |
- Thermal in situ production volumes
averaged 94,146 bbl/d in Q1/19, reflecting mandatory production
curtailments, representing a decrease of 8% from Q4/18 levels that
were already voluntarily curtailed by approximately 13,900 bbl/d at
Primrose.
- At Primrose, Q1/19 production volumes averaged 61,925 bbl/d, a
decrease of 9% from Q4/18 levels, as a result of production
curtailments. Including energy costs, operating costs were
$20.23/bbl in Q1/19, an increase of 22% from Q1/18, reflecting
lower volumes due to curtailments and higher energy costs.
- Pad additions at Primrose continue to be on budget and ahead of
schedule with initial production targeted in Q4/19. The program
targets to add approximately 26,000 bbl/d in the first 12 months of
production. These pad additions are high return activities as the
Company utilizes available excess oil processing and steam capacity
at Primrose.
- At Kirby South, SAGD production volumes averaged 29,692 bbl/d
in Q1/19, a decrease of 8% from Q4/18 levels. Including energy
costs, Kirby South quarterly operating costs were $12.31/bbl in
Q1/19, an increase of 35% from Q1/18 as a result of lower volumes
and higher energy costs.
- As previously announced, at the Company's Kirby North SAGD
project, top tier execution and strong productivity have resulted
in the project progressing two quarters ahead of the sanctioned
schedule with overall cost performance remaining on budget. The
commissioning of the central processing facility was also top tier
and as a result the project began steaming on May 1, 2019 and
targets to progressively ramp up production towards Kirby North's
overall capacity of 40,000 bbl/d, in late 2020.
- The Company’s annual 2019 thermal
in situ production guidance remains unchanged and is targeted to
range between 104,000 bbl/d - 124,000 bbl/d.
North America
Natural Gas |
|
Three Months Ended |
|
|
|
|
|
Mar 31 2019 |
|
Dec 31 2018 |
|
Mar 31 2018 |
|
Natural gas production (MMcf/d) |
1,454 |
|
1,441 |
|
1,547 |
|
Net wells targeting natural
gas |
9 |
|
3 |
|
5 |
|
Net successful wells
drilled |
8 |
|
3 |
|
5 |
|
Success rate |
89 |
% |
100 |
% |
100 |
% |
- North America natural gas
production was 1,454 MMcf/d in Q1/19, in-line with Q4/18
levels.
- Operating costs of $1.30/Mcf were
realized in Q1/19, in-line with Q1/18 levels.
- At the Company's high value
Septimus Montney liquids rich area, 5 net wells were drilled in
Q1/19 with targeted production of approximately 2,080 bbl/d of NGLs
and approximately 30 MMcf/d of natural gas, in late Q2/19.
- Modest drilling activity from prolific wells targets to return
the Septimus plant to full capacity, while reducing already low
Q1/19 operating costs of $0.36/Mcfe, supporting high netbacks and
maximizing value.
- The Company's natural gas reinjection pilot at Septimus is
targeted to commence first injection of 5 MMcf/d late in Q2/19.
This technology has the potential to materially increase liquids
recovery while storing natural gas in the reservoir, preserving the
value of the natural gas for periods with higher market prices.
- Results from the first injection and production cycle are
targeted for late 2019 with the potential to proceed with
additional cycles at the same location. Given the
opportunities for this process across Canadian Natural's vast
liquids rich Montney land base, the Company is advancing readiness
for a second pilot site within the Company's Greater Wembley
area.
- Regulatory approval was received
from the National Energy Board on May 3, 2019 regarding the
transfer of assets to British Columbia provincial jurisdiction
of the Pine River plant and operatorship to a subsidiary of
Canadian Natural. The acquisition is targeted to close in Q2/19 and
targets better plant efficiency and running time.
- In 2019, based upon the midpoint of
annual production guidance, Canadian Natural targets to use the
equivalent of approximately 37% of its total corporate natural gas
production in its operations, providing a natural hedge from the
challenging Western Canadian natural gas price environment.
Approximately 34% of the Company's guided 2019 natural gas
production is targeted to be exported to other North American
markets and sold internationally. The remaining 29% of the
Company's 2019 targeted natural gas production would be exposed to
AECO/Station 2 pricing.
- The Company’s annual 2019 corporate
natural gas production guidance remains unchanged and is targeted
to range between 1,485 MMcf/d - 1,545 MMcf/d.
International Exploration and
Production
|
Three Months Ended |
|
|
|
|
|
Mar 31 2019 |
|
Dec 31 2018 |
|
Mar 31 2018 |
|
Crude oil production (bbl/d) |
|
|
|
North Sea |
25,714 |
|
21,071 |
|
21,584 |
|
Offshore Africa |
22,155 |
|
22,185 |
|
19,438 |
|
Natural gas production
(MMcf/d) |
|
|
|
North Sea |
28 |
|
22 |
|
37 |
|
Offshore Africa |
28 |
|
25 |
|
30 |
|
Net wells targeting crude
oil |
1.6 |
|
1.1 |
|
1.0 |
|
Net successful wells
drilled |
1.6 |
|
1.1 |
|
1.0 |
|
Success rate |
100 |
% |
100 |
% |
100 |
% |
- International E&P quarterly
production volumes were strong in Q1/19, averaging 47,869 bbl/d,
increases of 11% and 17% from Q4/18 and Q1/18 levels, respectively,
as described below. The operating costs below include impacts of
IFRS 16.
- International production volumes benefit from premium Brent
pricing, generating significant adjusted funds flow for the
Company.
- In the North Sea, production volumes of 25,714 bbl/d were
achieved in Q1/19, increases of 22% and 19% over Q4/18 and Q1/19
levels respectively. The increase over Q4/18 primarily reflected
the impact of production resuming following the planned turnarounds
and maintenance activities completed during Q4/18. The increase
over Q1/18 primarily reflected the impact of the drilling program
completed in 2018, partially offset by natural field declines.
- Q1/19 operating costs in the North
Sea averaged $39.68/bbl (£22.60/bbl), a reduction of 9% from Q1/18
levels.
- The 2019 drilling program consists
of high value and high netback production additions from 3.8 net
producer wells targeted in the North Sea. Drilling commenced in
Q1/19 at the Ninian South Platform and late in the quarter 1.0 net
well was completed on time and on budget. Production came on stream
subsequent to quarter end and is exceeding expectations of 3,900
bbl/d.
- The Company is targeting planned
turnaround activities at the Ninian Central Platform late in Q2/19.
Production impacts are reflected in Q2/19 and annual 2019
guidance.
- Offshore Africa production volumes in Q1/19 averaged 22,155
bbl/d, in-line with Q4/18 levels and an increase of 14% over Q1/18
levels. The increase in production over Q1/18 primarily reflected
volumes from new wells drilled at Baobab in 2018, partially offset
by the cessation of production at the Olowi field in Gabon in
December 2018 and natural field declines.
- Côte d'Ivoire crude oil operating
costs averaged $9.79/bbl (US$7.36/bbl) in Q1/19, a reduction of 3%
from Q1/18 levels.
- The Company completed the last 0.6
net producer well from the Baobab drilling program late in Q1/19.
The drilling program resulted in current high netback production of
approximately 8,000 bbl/d net, exceeding budgeted expectations.
- The total Baobab drilling program included 4 gross (2.4 net)
producer wells and 2 gross (1.2 net) injector wells, of which the
second gross (0.6 net) injector well was completed subsequent to
quarter end in Q2/19.
- The Company targets to drill an
appraisal well (0.6 net) at Kossipo in Q2/19, and if successful may
lead to development drilling and a pipeline tied-back to the Baobab
Floating Production Storage and Offloading vessel, adding
significant future value with potential gross production capability
of 20,000 bbl/d targeted in 2022.
- Following the successful completion
of the Baobab drilling program, the Company targets to commence an
additional high value drilling program in Q4/19 at Espoir, with
initial production targeted for early 2020.
- The Espoir drilling program is targeting 3 gross producer wells
(1.8 net) and 2 gross injector wells (1.2 net) with the potential
to add an average of approximately 2,500 BOE/d of high netback
production per well in the first 12 months. Approximately 75% of
production is targeted to be light crude oil.
- In Q1/19, the operator of the South Africa exploration well,
where Canadian Natural owns a 20% working interest, announced a
discovery of significant gas condensate. The cost of the first
exploration well is fully carried.
- In 2019, the operator targets to
acquire 3D seismic on the Block.
- In 2020, the operator targets to
drill a second exploration well and may drill two further
exploration/appraisal wells to further define volumes and
deliverability.
- The Company's annual 2019
International production guidance remains unchanged and is targeted
to range from 42,000 bbl/d - 46,000 bbl/d.
North America Oil Sands Mining and
Upgrading
|
Three Months Ended |
|
|
|
|
|
Mar 31 2019 |
|
Dec 31 2018 |
|
Mar 31 2018 |
|
Synthetic crude oil production (bbl/d) (1) (2) |
416,206 |
|
447,048 |
|
456,076 |
|
- SCO production before royalties and excludes volumes consumed
internally as diesel.
- Consists of heavy and light synthetic crude oil products.
- At the Company's world class Oil
Sands Mining and Upgrading assets, industry leading operations
provided quarterly production of 416,206 bbl/d of SCO, a decrease
of 7% from Q4/18 levels. The decrease in production was primarily
due to mandatory curtailments, previously announced accelerated
maintenance activities as well as unplanned maintenance.
- Operating costs were top tier, as the Company realized
quarterly unadjusted operating costs of $21.46/bbl (US$16.14/bbl)
of SCO in Q1/19, in-line with Q1/18 levels, strong results given
curtailment and maintenance activities in the quarter.
- The Company continues to progress
engineering work on the previously announced potential expansion
and reliability opportunities at Horizon to increase reliability
and lower costs, targeting to add production of 75,000 bbl/d to
95,000 bbl/d. The engineering and design specification work
continued in the quarter and is targeted to be complete in Q3/19.
- The potential Paraffinic Froth Treatment expansion at Horizon
is targeting 40,000 bbl/d to 50,000 bbl/d of high quality diluted
bitumen at significantly lower operating costs as the Company
leverages its existing infrastructure. The preliminary estimate of
the capital required is approximately $1.4 billion.
- Stage 1 and 2 reliability opportunities at Horizon are targeted
to add 35,000 bbl/d to 45,000 bbl/d of SCO.
- The Company targets to sanction the potential expansion and
reliability opportunities with greater clarity on improved market
access.
- As previously announced on May 1,
2019, Canadian Natural provided a follow up on a fire which
occurred at the Scotford Upgrader on April 15, 2019, in which the
Company has a 70% interest. The fire was promptly extinguished, all
personnel were accounted for, and there were no reported injuries.
- The fire was contained to a process furnace in the North
Upgrader, while operations at the base upgrader plant ("South
Upgrader") were not impacted by the fire. The planned 38 day
turnaround began on April 14, 2019 at the Scotford Upgrader, during
which time the South Upgrader will run at a restricted net
processing rate of approximately 140,000 bbl/d of SCO. Upon
completion of the planned maintenance, May and June average net
production at the Albian mines is targeted to be approximately
171,500 bbl/d versus the Company's previously targeted net
curtailment production volumes at the Albian mines of approximately
178,500 bbl/d. The cost for repairs of the North Upgrader is
estimated to be approximately $15 million gross and is targeted to
be fully operational by early June. The Company continues to
optimize other assets in Alberta to mitigate the impacts of
curtailments on its production.
- The Company's annual 2019 Oil Sands
Mining and Upgrading production guidance remains unchanged and is
targeted to range between 415,000 bbl/d - 450,000 bbl/d of
SCO.
MARKETING
|
|
Three Months Ended |
|
|
|
|
|
|
|
|
|
Mar 31 2019 |
|
|
Dec 31 2018 |
|
|
Mar 31 2018 |
|
Crude oil and NGLs
pricing |
|
|
|
|
|
|
WTI benchmark price (US$/bbl) (1) |
|
$ |
54.90 |
|
|
$ |
58.83 |
|
|
$ |
62.89 |
|
WCS heavy differential as a percentage of WTI (%) (2) |
|
23 |
% |
|
67 |
% |
|
39 |
% |
SCO price (US$/bbl) |
|
$ |
52.19 |
|
|
$ |
37.48 |
|
|
$ |
61.45 |
|
Condensate benchmark pricing (US$/bbl) |
|
$ |
50.49 |
|
|
$ |
45.27 |
|
|
$ |
63.12 |
|
Average realized pricing before risk management (C$/bbl) (3) |
|
$ |
53.98 |
|
|
$ |
25.95 |
|
|
$ |
43.06 |
|
Natural gas pricing |
|
|
|
|
|
|
AECO benchmark price (C$/GJ) |
|
$ |
1.84 |
|
|
$ |
1.80 |
|
|
$ |
1.75 |
|
Average realized pricing before risk management (C$/Mcf) |
|
$ |
3.09 |
|
|
$ |
3.46 |
|
|
$ |
2.74 |
|
- West Texas Intermediate (“WTI”).
- Western Canadian Select (“WCS”).
- Average crude oil and NGL pricing excludes SCO. Pricing is net
of blending costs and excluding risk management activities.
- Q1/19 differentials between SCO and
West Texas Intermediate ("WTI") benchmark pricing and Western
Canadian Select ("WCS") and WTI benchmark pricing narrowed
significantly to more normalized levels following the Government of
Alberta's announcement of mandatory curtailments of crude oil
production on December 2, 2018.
- AECO natural gas prices increased
in Q1/19 from Q1/18 levels, reflecting the easing of third party
pipeline constraints.
- The North West Redwater ("NWR") refinery, upon completion, will
strengthen the Company’s position by providing a competitive return
on investment and by creating incremental demand for approximately
80,000 bbl/d of heavy crude oil blends that will not require export
pipelines, helping to reduce pricing volatility in all Western
Canadian heavy crude oil.
- The Company has a 50% interest in
the NWR Partnership. For updates on the project, please refer
to:
https://nwrsturgeonrefinery.com/whats-happening/news/.
ENVIRONMENTAL HIGHLIGHTS
- Canadian Natural has invested over
$3.4 billion in research and development since 2009 and continues
to invest in technology to unlock reserves, become more effective
and efficient, increase production 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.
- Canadian Natural has invested
significant capital to capture and sequester CO2. The Company has
carbon capture and sequestration facilities at Horizon, a 70%
working interest in the Quest Carbon Capture and Storage project at
Scotford and carbon capture facilities at its 50% interest through
the NWR refinery. As a result, Canadian Natural targets capacity to
capture and sequester 2.7 million tonnes of CO2 annually,
equivalent to taking 576,000 vehicles off the road per year, making
the Company one of the largest CO2 capturer and sequester for the
oil and natural gas sector globally once the NWR refinery is fully
running.
- At Canadian Natural's Oil Sands
Mining and Upgrading and thermal in situ operations, which
represent approximately 65% of the Company's liquids production,
the Company's emissions intensity is only approximately 5% higher
than the average intensity for all global crude oils. By investing
in and leveraging technology, including carbon capture initiatives,
Canadian Natural has developed a pathway to reduce the Company's
greenhouse gas emissions intensity to below the average for global
crude oils.
- Canadian Natural's commitment to leverage technology, adopting
innovation and continuous improvement is evidenced by its In Pit
Extraction Process ("IPEP") pilot at Horizon, which will determine
the feasibility of producing stackable dry tailings. The project
has the potential to reduce the Company's carbon emissions and
environmental footprint by reducing the usage of haul trucks, the
size and need for tailings ponds and accelerating site reclamation.
In addition, this process has the potential to significantly reduce
capital and operating costs.
- The initial testing phase for the
Company's IPEP pilot has concluded and results have been positive
with excellent recovery rates and evidence of stackable tailings.
As a result of the positive results thus far, the Company continues
to make enhancements and will operate and test the pilot through
2019.
FINANCIAL REVIEW
The Company continues to implement proven
strategies and 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
programs all support a flexible financial position and provide the
appropriate financial resources for the near-, mid- and
long-term.
- The Company’s strategy is to
maintain a diverse portfolio balanced across various commodity
types. The Company achieved production levels of 1,035,212 BOE/d in
Q1/19, with approximately 97% of total production located in G7
countries.
- Canadian Natural maintains a balance of products with Q1/19
production mix on a BOE/d basis of 54% light crude oil and SCO
blends, 22% heavy crude oil blends and 24% natural gas.
- Canadian Natural delivered strong
quarterly free cash flow of $860 million after net capital
expenditures of $977 million and dividend requirements of $403
million, reflecting the strength of our long life low decline asset
base and our effective and efficient operations.
- Canadian Natural maintains strong
financial stability and liquidity represented by cash balances, and
committed and demand bank credit facilities. At March 31, 2019 the
Company had approximately $4,230 million of available liquidity,
including cash and cash equivalents.
- Canadian Natural is committed to
returns to shareholders, returning a total of $644 million in the
quarter, $403 million by way of dividends and $241 million by way
of share purchases.
- Share purchases for cancellation in the quarter totaled
6,650,000 common shares at a weighted average share price $36.24.
Subsequent to quarter end and up to and including May 8, 2019, the
Company executed on additional share purchases of 4,050,000 common
shares for cancellation at a weighted average share price of
$39.34.
- In Q1/19 the Company increased its quarterly dividend 12% from
Q4/18 levels, marking the 19th consecutive year that the Company
has increased its dividend, reflecting the Board of Directors'
confidence in Canadian Natural's sustainability and robustness of
the asset base driving the ability to generate significant adjusted
funds flow.
- Subsequent to quarter end, the Company declared a quarterly
dividend of $0.375 per share, payable on July 1, 2019.
- In 2018, the Board of Directors
approved a more defined free cash flow allocation policy in
accordance with the Company's four stated pillars. Under the new
policy, the Company will target to allocate, on an annual basis,
50% of its residual free cash flow, after budgeted capital
expenditures and dividends, to share purchases under its NCIB and
the remaining 50% to reducing debt levels on the Company's balance
sheet. This free cash flow policy will target a ratio of debt to
adjusted 12 months trailing EBITDA of 1.5x, and an absolute debt
level of $15.0 billion, at which time the policy will be reviewed
by the Board. This policy was effective November 1, 2018.
- The Company's Board of Director's has approved a motion to
renew the NCIB and the continuation of the free cash flow
allocation policy.
- In addition to its strong 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. As at March 31, 2018, these
financial levers include the Company’s third party equity
investments of $549 million, and cross currency swaps and foreign
currency forward contracts with a total value of $266 million.
- All Q1/19 operating costs stated
above reflect the impact of the adoption of IFRS 16. The lease
liability recognized as required under IFRS 16 as a percentage of
total enterprise value is approximately 2.4%, one of the lowest
amongst the Company's Canadian peers, reflecting Canadian Natural's
disciplined approach to managing longer term contractual
arrangements.
OUTLOOK
The Company targets annual 2019 production
levels to average between 782,000 bbl/d and 861,000 bbl/d of crude
oil and NGLs and between 1,485 MMcf/d and 1,545 MMcf/d of natural
gas, before royalties. Q2/19 production guidance before royalties
is targeted to average between 773,000 bbl/d and 831,000 bbl/d of
crude oil and NGLs and between 1,500 MMcf/d and 1,530 MMcf/d of
natural gas. Detailed guidance on production levels, capital
allocation and operating costs can be found on the Company’s
website at www.cnrl.com.
Canadian Natural's annual 2019 capital
expenditures are targeted to be approximately $3.7 billion.
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” 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 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 but not limited to the 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 timing and future
operations of 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
which will, among other things, impact demand for and market prices
of the Company’s products; volatility of and assumptions regarding
crude oil and natural gas prices; 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 resumption of 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 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;
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; 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 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 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, 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 and Other 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 (previously referred to as funds flow from
operations); net capital expenditures; free cash flow; debt to
adjusted EBITDA; available liquidity; adjusted operating costs;
unadjusted operating costs; and enterprise value. These financial
measures are not defined by International Financial Reporting
Standards ("IFRS") and therefore are referred to as non-GAAP
measures and other financial measures. The non-GAAP measures used
by the Company may not be comparable to similar measures presented
by other companies. The Company uses these non-GAAP measures to
evaluate its performance. The non-GAAP measures should not be
considered an alternative to or more meaningful than net earnings
(loss), cash flows from operating activities, cash flows used in
investing activities, and cash flows used in financing activities
as determined in accordance with IFRS, as an indication of the
Company's performance.
Adjusted net earnings (loss) from operations is
a non-GAAP measure that represents net earnings (loss) as presented
in the Company's consolidated Statements of Earnings (Loss),
adjusted for the after-tax effects of certain items of a
non-operational nature. The Company considers adjusted net earnings
(loss) from operations a key measure in evaluating its performance,
as it demonstrates the Company's ability to generate after-tax
operating earnings from its core business areas. The reconciliation
“Adjusted Net Earnings (Loss) from Operations, as Reconciled to Net
Earnings (Loss)" is presented in 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.
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.
Adjusted operating costs are derived as
production expense based on sales volumes excluding costs incurred
in turnaround periods. See "Operating Highlights - Oil Sands Mining
and Upgrading" section in the Company’s MD&A.
Unadjusted operating costs also referred to as
cash production costs in the Company’s MD&A. See
"Operating Highlights - Oil Sands Mining and Upgrading" section in
the Company’s MD&A.
Enterprise value is derived as the sum of the
Company’s market capitalization and total long-term debt less cash
and cash equivalents. Market capitalization is derived as total
outstanding common shares multiplied by the market price per common
share at any given period.
Special Note Regarding Currency,
Financial Information and Production
The Company's MD&A should be read in
conjunction with the unaudited interim consolidated financial
statements for the three months ended March 31, 2019 and the
MD&A and the audited consolidated financial statements of the
Company for the year ended December 31, 2018.
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
months ended March 31, 2019 and the Company's MD&A have
been prepared in accordance with IFRS as issued by the
International Accounting Standards Board ("IASB"). Changes in the
Company's accounting policies in accordance with IFRS, including
the adoption of IFRS 16 "Leases" on January 1, 2019, are discussed
in the "Changes in Accounting Policies" section of the Company's
MD&A. In accordance with the new "Leases" standard, comparative
period balances in 2018 reported in the Company's MD&A have not
been restated.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, 2018, is available on SEDAR at
www.sedar.com, and on EDGAR at www.sec.gov. Detailed guidance on
production levels, capital expenditures and production expenses can
be found on the Company's website at www.cnrl.com.
CONFERENCE CALL
A conference call will be held at 8:00 a.m.
Mountain Time, 10:00 a.m. Eastern Time on Thursday, May 9,
2019.
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, May 23, 2019. 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 9681416.
The conference call will also be webcast live
and can be accessed on the home page of 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.
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