Commenting on second quarter 2018 results, Steve Laut, Executive
Vice-Chairman of Canadian Natural stated, "The Company's balanced
strategy was once again evident in the quarter as our robust long
life low decline asset base provided record quarterly funds
flow of approximately $2.7 billion. The allocation of funds flow
was balanced among our four pillars to maximize value for our
shareholders through strengthening the balance sheet, returns to
shareholders through dividends and share buybacks, economic
resource development, and some minor opportunistic acquisitions
year to date. The Company's ability to execute on our strategy is
reflected in our second quarter results, and continues a long track
record of strong results."
Canadian Natural's President, Tim McKay, added,
"In the second quarter of 2018, operations were strong and cost
control remained a focus, specifically at our Oil Sands Mining and
Upgrading assets, where costs continue to come down. Operating
costs of $22.94/bbl (US$17.77/bbl) of Synthetic Crude Oil ("SCO")
were impressive given the successfully completed turnaround and pit
stop activities in the quarter.
Canadian Natural's ability to effectively
allocate capital was demonstrated in the quarter as we have made
strategic and proactive decisions to take advantage of our large,
balanced and diverse asset base due to changing market conditions.
Our asset base is a key competitive advantage providing significant
capital flexibility and as a result, to maximize value, we are
shifting capital from primary heavy crude oil to light crude
oil.
At Kirby North, top tier execution and strong
productivity have resulted in accelerating the projects time line,
bringing forward targeted first oil of the project's 40,000 bbl/d,
by three months into Q4/19, one quarter earlier than originally
planned.
At Horizon, the Company has identified
opportunities to increase reliability, lower costs and add
production growth of between 75,000 bbl/d and 95,000 bbl/d in the
near and long term. The near term opportunities are targeted to add
production growth of 35,000 bbl/d to 45,000 bbl/d of SCO. High
grading of these near term opportunities and further defining of
substantial long term growth opportunities is ongoing and is
targeted to be completed by the end of the year. Additionally,
early results from engineering and design specification work at the
potential Paraffinic Froth Treatment expansion has indicated that
the optimal production range for the expansion has increased by
10,000 bbl/d and is now targeted to add 40,000 bbl/d to 50,000
bbl/d. All of the these identified production growth opportunities
at Horizon are over and above the previously disclosed annual
corporate growth target of approximately 4% or 45,000 BOE/d of
organic production over the next few years. These Horizon
opportunities will be executed in a disciplined and step wise
manner which preserves Canadian Natural's capital flexibility."
Canadian Natural's Chief Financial Officer,
Corey Bieber, continued, "In the second quarter of 2018, the
strength of our asset base and effective and efficient operations
delivered net earnings of $982 million and funds flow from
operations of $2,706 million. Our strong financial results allowed
the Company to further strengthen the balance sheet by decreasing
absolute long term net debt by over $600 million from the previous
quarter, and returning over $850 million to shareholders by way of
dividends and share buybacks in the quarter.
The Company's acquisitions in 2017 were
transformational and our results continue to show the accretive
nature and resilience of these assets. Supported by successful
expansions at Horizon, long life low decline and low capital
exposure assets, we have been able to reduce long term net debt in
the last 12 months since the Athabasca Oil Sands Project ("AOSP")
acquisition by approximately $2,500 million, including the
retirement of the deferred AOSP acquisition liability, improving
our debt to book capitalization to 39.6% from 42.8% and debt to
adjusted EBITDA to 2.1x from 3.4x over the same time frame, clearly
demonstrating our commitment to strengthening the balance
sheet."
HIGHLIGHTS
|
|
Three Months Ended |
|
|
Six Months Ended |
|
|
|
|
|
|
|
|
|
|
|
|
($ millions, except per common share amounts) |
|
Jun 30 2018 |
|
Mar 31 2018 |
|
Jun 30 2017 |
|
|
Jun 30 2018 |
|
Jun 30 2017 |
Net earnings |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
982 |
|
|
$ |
583 |
|
|
$ |
1,072 |
|
|
|
$ |
1,565 |
|
|
$ |
1,317 |
|
Per common share |
– basic |
|
$ |
0.80 |
|
|
$ |
0.48 |
|
|
$ |
0.93 |
|
|
|
$ |
1.28 |
|
|
$ |
1.16 |
|
|
– diluted |
|
$ |
0.80 |
|
|
$ |
0.47 |
|
|
$ |
0.93 |
|
|
|
$ |
1.27 |
|
|
$ |
1.16 |
|
Adjusted
net earnings from operations (1) |
|
$ |
1,279 |
|
|
$ |
885 |
|
|
$ |
332 |
|
|
|
$ |
2,164 |
|
|
$ |
609 |
|
Per common share |
– basic |
|
$ |
1.05 |
|
|
$ |
0.72 |
|
|
$ |
0.29 |
|
|
|
$ |
1.77 |
|
|
$ |
0.54 |
|
|
– diluted |
|
$ |
1.04 |
|
|
$ |
0.71 |
|
|
$ |
0.29 |
|
|
|
$ |
1.76 |
|
|
$ |
0.54 |
|
Funds flow
from operations (2) |
|
$ |
2,706 |
|
|
$ |
2,323 |
|
|
$ |
1,726 |
|
|
|
$ |
5,029 |
|
|
$ |
3,365 |
|
Per common share |
– basic |
|
$ |
2.20 |
|
|
$ |
1.90 |
|
|
$ |
1.50 |
|
|
|
$ |
4.10 |
|
|
$ |
2.97 |
|
|
– diluted |
|
$ |
2.19 |
|
|
$ |
1.89 |
|
|
$ |
1.49 |
|
|
|
$ |
4.08 |
|
|
$ |
2.95 |
|
Total net capital expenditures (3) |
|
$ |
974 |
|
|
$ |
1,103 |
|
|
$ |
13,046 |
|
|
|
$ |
2,077 |
|
|
$ |
13,892 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Daily
production, before royalties |
|
|
|
|
|
|
|
|
|
|
|
Natural gas (MMcf/d) |
|
1,539 |
|
|
1,614 |
|
|
1,656 |
|
|
|
1,576 |
|
|
1,664 |
|
Crude oil and NGLs (bbl/d) |
|
793,899 |
|
|
854,558 |
|
|
637,127 |
|
|
|
824,060 |
|
|
617,728 |
|
Equivalent production (BOE/d) (4) |
|
1,050,376 |
|
|
1,123,546 |
|
|
913,171 |
|
|
|
1,086,757 |
|
|
895,139 |
|
(1) |
Adjusted net earnings from
operations is a non-GAAP measure that the Company utilizes to
evaluate its performance. The derivation of this measure is
discussed in the Management’s Discussion and Analysis
(“MD&A”). |
(2) |
Funds flow from operations
is a non-GAAP measure that the Company considers key as it
demonstrates the Company’s ability to fund capital reinvestment and
debt repayment. The derivation of this measure is discussed in the
MD&A. |
(3) |
For additional information
and details, refer to the net capital expenditures table in the
Company's MD&A. |
(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 $982 million were realized in Q2/18, an
increase of 68% over Q1/18 levels, and adjusted net earnings of
$1,279 million were achieved, a 45% increase over Q1/18 levels.
• Canadian Natural generated record quarterly funds flow from
operations of $2,706 million in Q2/18, increases of $383 million
and $980 million from Q1/18 and Q2/17 levels respectively. The
increase over Q1/18 and Q2/17 primarily reflects higher realized
prices from the Company's liquids production together with higher
liquids production volumes when compared to Q2/17.
• In Q2/18, Canadian Natural delivered funds flow from
operations in excess of capital expenditures of approximately
$1,730 million, an increase of approximately $510 million and $890
million from Q1/18 and Q2/17 levels respectively.
• In the first half of 2018, after dividend requirements, free
cash flow totaled approximately $2,200 million.
• The Company maintained balance in the allocation of its funds
flow from operations, consistent with the Company's four pillar
strategy:
- The Company remained disciplined in economic resource
development with capital expenditures of $2,077 million in the
first half of 2018.
- In the first half of the year the Company has reduced long term
net debt by $1,106 million, resulting in debt to adjusted EBITDA
strengthening to 2.1x and debt to book capitalization improving to
39.6%.
- Returns to shareholders remain a key focus for Canadian Natural
as the Company has returned approximately $1,188 million by way of
dividends and share buybacks in the first six months of 2018. Share
buybacks for cancellation totaled 10,140,127 shares in Q2/18 at a
weighted average share price of $43.52.
- Subsequent to quarter end Canadian Natural declared a quarterly
cash dividend on common shares of $0.335 per share payable on
October 1, 2018.
- Subsequent to quarter end, the Company executed additional
share buybacks of 722,600 common shares for cancellation at a
weighted average price of $46.95 per common share.
- Opportunistic acquisitions have been minor in 2018, with year
to date net expenditures of less than $100 million.
• The Company's production volumes in Q2/18 averaged 1,050,376
BOE/d, an increase of 15% from Q2/17 levels, mainly due to the
Horizon Phase 3 expansion and acquisitions in 2017. Production
decreased from Q1/18 levels by 7%, primarily as a result of major
planned turnaround activities at the Company's Oil Sands Mining and
Upgrading and thermal in situ operations as well as proactive and
strategic actions taken to maximize value.
• Canadian Natural’s corporate crude oil and NGL production
volumes averaged 793,899 bbl/d, a decrease of 7% from Q1/18 levels
and a 25% increase from Q2/17 levels. The decrease from Q1/18 was
primarily as a result of proactive turnaround activities at
our Oil Sands Mining and Upgrading and thermal in situ operations
as well as curtailments in Q2/18. The increase from Q2/17 was
primarily as a result of production from the Horizon Phase 3
expansion, as well as high reliability and strong production from
acquisitions completed in 2017.
• At the Company's world class Oil Sands Mining and Upgrading
assets, operations were as expected in Q2/18 with quarterly
production of 407,704 bbl/d of Synthetic Crude Oil ("SCO"), a
decrease of 11% from Q1/18 levels, as planned turnaround and pit
stop activities at all three of the Company's oil sands mines, as
well as a major 62 day turnaround at the Scotford Upgrader were
successfully completed in the quarter.
- Cost control remains a strong focus for the Company as costs
continued to come down resulting in industry leading operating
costs of $22.94/bbl (US$17.77/bbl) of SCO in Q2/18, a 2% decrease
from Q2/17 levels and a 7% increase from Q1/18 levels, impressive
results considering major turnarounds decreased production by 11%
in Q2/18 from Q1/18 levels.
- At the Athabasca Oil Sands Project ("AOSP"), a significant
milestone was reached in July, when the asset produced its 1
billionth barrel of mined bitumen during its first 15 years of
operations, one of the few world class assets to reach such a
milestone. This is a true demonstration of the quality, size and
scale of the Company's Oil Sands Mining and Upgrading operations
which through environmentally responsible, safe, reliable,
effective and efficient operations, provide sustainable long life
low decline production and significant value for stakeholders.
- At Horizon, following the successful completion of the Phase 3
expansion and after operating the plant for the last 8 months, the
Company continues to evaluate potential expansions and has
identified additional opportunities to increase reliability, lower
costs and add production.
- Results at the potential Paraffinic Froth Treatment expansion
at Horizon are evident as the engineering and design specification
work completed year to date has shown that the optimal production
range of the proposed expansion has increased by 10,000 bbl/d and
is now targeted to be 40,000 bbl/d to 50,000 bbl/d. The expansion
is targeted to produce high quality diluted bitumen at
significantly lower operating costs as the Company leverages
its existing infrastructure. Preliminary estimates of the capital
required for the proposed expansion are approximately $1.4
billion.
- Defining and high grading additional opportunities is ongoing
with the completion of the process targeted by year end. These
opportunities are targeted to add near term growth of 35,000 bbl/d
to 45,000 bbl/d of SCO. All opportunities will be executed in a
disciplined and step wise manner, which preserves Canadian
Natural's capital flexibility. The previously discussed Vacuum Gas
Oil ("VGO") expansion will be included in the high grading
process.
- In preparation to execute on these opportunities in 2019 and
2020, Canadian Natural has increased 2018 capital expenditures
guidance by $170 million to advance engineering and procurement of
certain long lead equipment.
• At Kirby North, top tier execution and strong productivity has
resulted in the project progressing ahead of schedule, advancing
targeted first oil by three months into Q4/19, one quarter earlier
than originally planned. Cost performance remains on budget with
95% of the Central Processing Facility equipment delivered to site
and Steam Assisted Gravity Drainage ("SAGD") drilling nearing 45%
completion. Kirby North targets to add 40,000 bbl/d of SAGD
production.
• Balance sheet strength continues to be a focus of the Company
and strong financial performance was demonstrated in Q2/18 through
reduced long term debt and extensions of select credit
facilities.
- In Q2/18, Standard & Poor's revised the Company's rating
outlook from BBB+/negative to BBB+/stable.
- In Q2/18, the Company reduced absolute long term net debt by
approximately $610 million, from Q1/18 levels.
- Canadian Natural maintains strong financial stability and
liquidity represented by cash balances and committed bank credit
facilities. At June 30, 2018 the Company had approximately $4,800
million of available liquidity, including cash and cash
equivalents, an increase of approximately $800 million from
Q1/18.
- In Q2/18 Canadian Natural continued to have significant support
from its large and diverse banking group as indicated by extensions
of certain credit facilities completed in the quarter.
• In Q2/18 Canadian Natural published its 2017 Stewardship
Report to Stakeholders, now available on the Company's website at
https://www.cnrl.com/corporate-responsibility/stewardship-report/#2017.
The report displays how Canadian Natural continues to focus on
safe, reliable, effective and efficient operations while minimizing
the Company's environmental footprint.
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 and
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, facilitating improved 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 low decline, low reserves
replacement costs, and effective and efficient operations means
these assets provide substantial and sustainable 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 a major component of its
operating cost and minimize production commitments. Low capital
exposure projects can be quickly stopped or started depending upon
success, market conditions, or corporate needs.
Canadian Natural’s balanced portfolio, built
with both long life low decline assets and low capital exposure
assets, enables effective capital allocation, production growth and
value creation.
Drilling Activity
|
Six Months Ended Jun 30 |
|
|
|
|
2018 |
2017 |
(number
of wells) |
Gross |
|
Net |
|
Gross |
|
Net |
|
Crude oil |
210 |
|
203 |
|
236 |
|
216 |
|
Natural gas |
13 |
|
9 |
|
16 |
|
16 |
|
Dry |
2 |
|
2 |
|
3 |
|
3 |
|
Subtotal |
225 |
|
214 |
|
255 |
|
235 |
|
Stratigraphic test / service wells |
555 |
|
477 |
|
232 |
|
232 |
|
Total |
780 |
|
691 |
|
487 |
|
467 |
|
Success rate (excluding stratigraphic test / service wells) |
|
99 |
% |
|
99 |
% |
- The Company's total Q2/18 crude oil and natural gas drilling
program was 85 net wells, excluding strat/service wells, an
increase of 17 net wells from the 68 net wells drilled in Q2/17.
The Company's drilling levels reflects the disciplined capital
allocation process and proactive actions to improve execution and
control costs by balancing overall drilling levels throughout the
year.
North America Exploration and Production
Crude oil
and NGLs – excluding Thermal In Situ Oil Sands |
|
|
|
Three Months Ended |
Six Months Ended |
|
|
|
|
|
|
|
June 30 2018 |
March 31 2018 |
June 30 2017 |
June 30 2018 |
June 30 2017 |
Crude oil and NGLs production (bbl/d) |
238,631 |
|
245,609 |
|
227,083 |
|
242,101 |
|
229,325 |
|
Net wells
targeting crude oil |
58 |
|
101 |
|
57 |
|
159 |
|
204 |
|
Net successful wells drilled |
58 |
|
99 |
|
55 |
|
157 |
|
202 |
|
Success rate |
100 |
% |
98 |
% |
96 |
% |
99 |
% |
99 |
% |
• North America crude oil and NGLs averaged
238,631 bbl/d in Q2/18, within quarterly corporate guidance,
representing a 3% decrease from Q1/18 levels and a 5% increase from
Q2/17 levels. The volume decrease in Q2/18 compared to Q1/18 levels
was primarily as a result of production curtailments and shut-in
volumes of approximately 10,350 bbl/d as well as reduced drilling
activity and delayed completion and ramp up of certain primary
heavy crude oil wells drilled in Q1/18 and Q2/18.
• Due to current market conditions the Company
has exercised its capital flexibility by shifting capital from
primary heavy crude oil to light crude oil in 2018, resulting in an
additional 7 net light crude oil wells targeted to be drilled in
the second half of the year. Primary heavy crude oil drilling was
reduced by 24 net primary heavy crude oil wells in Q2/18, with an
additional 35 primary heavy crude oil well reduction targeted for
the second half of the year.
• Canadian Natural's primary heavy crude oil
production averaged 84,811 bbl/d in Q2/18, a 5% decrease from Q1/18
levels. In order to maximize value from the Company’s primary heavy
crude oil assets, Canadian Natural implemented and executed
on proactive decisions and strategic actions in the first half of
2018, such as:
- Disciplined capital allocation and proactive actions to target
only the highest return wells in our primary heavy crude oil assets
which resulted in 39 net wells drilled in Q2/18, less than
originally budgeted.
- The shut in of marginal high cost primary heavy crude oil
production in 2018, which impacted Q2/18 production by
approximately 2,900 bbl/d.
- Proactive decisions to not sell marginal production in the
wider spot WCS differential market versus the index WCS
differential, caused by pipeline apportionment issues. As a result,
the Company curtailed volumes of approximately 7,450 bbl/d in
Q2/18.
• Controlling costs remains a focus with
operating costs of $17.02/bbl in Q2/18, comparable to Q1/18 levels,
strong results given the lower production volumes that were
primarily as a result of proactive curtailments.
• At the Company's Smith primary heavy crude oil
play, initial results have been strong from the 6 net multilateral
wells drilled year to date and are currently producing
approximately 340 bbl/d per well. There is significant potential at
Smith for future development as Canadian Natural has 19 net
sections in the fairway with the potential to add approximately 125
net horizontal multilateral primary heavy crude oil wells. Smith is
an example of Canadian Natural's large, high quality primary heavy
crude oil asset base.
• North America light crude oil and NGL
quarterly production averaged 89,906 bbl/d, a decrease of 3% from
Q1/18 levels and comparable to Q2/17 levels. Production from
additional capital allocated to light crude oil assets is targeted
to begin to be added in Q3/18.
- The Company successfully drilled 38 net light crude oil wells
in the first half of the year. Some initial results from wells
coming on production in the quarter are as follows:
- At the Company's light crude oil development at Tower, 7 net
wells have been drilled and related facility construction has been
completed. Operations are currently ramping up with initial well
capacity targeted to be 850 bbl/d per well. Based on initial flow
back rates, facility capacity of approximately 3,000 bbl/d is
targeted to be reached in late Q3/18. There is additional potential
at Tower with 41 targeted net light crude oil wells locations, on
the Company's 11 net sections in the area.
- At Wembley, 2 net Montney wells that were drilled in Q1/18 came
on production late in Q2/18. Initial results are strong with
production currently reaching approximately 800 bbl/d per well.
There is meaningful potential at Wembley with 175 targeted net
light crude oil well locations, on the Company's 77 net sections of
Montney lands in the area.
- Operating costs of $15.81/bbl were realized in Q2/18,
comparable to Q1/18 levels in the Company's light crude oil and NGL
areas.
• Pelican Lake quarterly production averaged
63,914 bbl/d, comparable with Q1/18 levels and an increase of 36%
from Q2/17 levels. The increase from Q2/17 was as a result of the
Company's successful integration of the acquired assets in
2017.
- Polymer flood restoration on the acquired lands continues to
proceed ahead of schedule, where approximately 60% of acquired
lands are now under polymer flood. To optimize long term oil
recovery and effectiveness of the polymer flood, the Company is
using modified injection parameters in the near term. As polymer
flood conformance improves, the Company expects to increase oil
recovery and further maximize value.
- Operating costs of $6.96/bbl were achieved in Q2/18, a 2%
decrease from Q1/18 levels.
- In the quarter, the Company successfully drilled 11 net
producer wells. When incorporating the 7 net wells drilled in
Q1/18, the Company has drilled 18 net Pelican Lake wells in the
first half of the year, which are performing as expected and are
currently producing approximately 90 bbl/d per
well.
• The Company’s 2018 North America E&P crude
oil and NGL annual production guidance remains unchanged and is
targeted to range from 253,000 bbl/d - 263,000 bbl/d.
|
|
|
Thermal In
Situ Oil Sands |
|
|
|
Three Months Ended |
Six Months Ended |
|
|
|
|
|
|
|
Jun 30 2018 |
|
Mar 31 2018 |
|
Jun 30 2017 |
|
Jun 30 2018 |
|
Jun 30 2017 |
|
Bitumen production (bbl/d) |
104,907 |
|
111,851 |
|
105,719 |
|
108,359 |
|
116,983 |
|
Net wells
targeting bitumen |
21 |
|
22 |
|
4 |
|
43 |
|
12 |
|
Net successful wells drilled |
21 |
|
22 |
|
4 |
|
43 |
|
12 |
|
Success rate |
100 |
% |
100 |
% |
100 |
% |
100 |
% |
100 |
% |
|
|
|
|
|
|
|
|
|
|
|
• Thermal in situ quarterly production volumes averaged 104,907
bbl/d, within Q2/18 guidance and a decrease of 6% as expected from
Q1/18 levels primarily as the Company advanced and completed
turnaround activities in the quarter. Production curtailments
impacted Q2/18 by approximately 700 bbl/d, mainly at Kirby
South.
- At Primrose, Q2/18 production volumes averaged 67,569 bbl/d, a
decrease of 6% from Q1/18 levels, primarily as a result of major
turnaround activities. Including energy costs, operating costs were
strong at $14.66/bbl in Q2/18, a decrease of 12% and 8% from Q1/18
and Q2/17 levels respectively, excellent results given downtime
relating to the turnarounds in the quarter.
- Pad additions at Primrose are going as planned with the
drilling targeted to add approximately 32,000 bbl/d in 2020, with
initial production targeted late in 2019. These pad additions are
high return activities as the Company utilizes available oil
processing and steam capacity.
- At Kirby South, SAGD production volumes of 35,322 bbl/d were
achieved in Q2/18, a decrease of 5% from Q1/18 levels following
planned turnaround activities brought forward into Q2/18 and
curtailments of approximately 700 bbl/d and a 2% increase from
Q2/17 levels.
- Including energy costs, Kirby South achieved strong Q2/18
operating costs of $9.12/bbl, comparable to Q1/18 and a decrease of
11% from Q2/17 levels.
- At Kirby North, top tier execution and strong productivity has
resulted in the project progressing ahead of schedule, advancing
targeted first oil by three months into Q4/19, one quarter earlier
than originally planned. Cost performance remains on budget with
95% of the Central Processing Facility equipment delivered to site
and SAGD drilling nearing 45% completion. Kirby North targets to
add 40,000 bbl/d of SAGD production.
• The Company’s 2018 thermal in situ annual production guidance
remains unchanged and is targeted to range between 107,000 bbl/d -
127,000 bbl/d.
|
|
|
North
America Natural Gas |
|
|
|
Three Months Ended |
Six Months Ended |
|
|
|
|
|
|
|
Jun 30 2018 |
|
Mar 31 2018 |
|
Jun 30 2017 |
|
Jun 30 2018 |
|
Jun 30 2017 |
|
Natural gas production (MMcf/d) |
1,485 |
|
1,547 |
|
1,603 |
|
1,515 |
|
1,607 |
|
Net wells
targeting natural gas |
4 |
|
5 |
|
5 |
|
9 |
|
17 |
|
Net successful wells drilled |
4 |
|
5 |
|
5 |
|
9 |
|
16 |
|
Success rate |
100 |
% |
100 |
% |
100 |
% |
100 |
% |
94 |
% |
• North America natural gas production was as expected at 1,485
MMcf/d in Q2/18, representing decreases of 4% and 7% from Q1/18 and
Q2/17 levels respectively.
• Operating costs of $1.28/Mcf were realized in Q2/18, a
decrease of 2% from Q1/18 levels, strong results given lower
natural gas volumes due to the Company's proactive decision to
shut-in volumes and delay activity on certain natural gas
assets.
• In Q2/18 the Company has made the following proactive and
strategic actions to maximize value in the Company's natural gas
assets, including:
- Completion of major turnaround activities at natural gas
processing facilities to correspond with challenged natural gas
prices.
- Deferred capital and development activity including
recompletions and workovers of certain natural gas assets,
resulting in a production impact of approximately 20 MMcf/d in
Q2/18. The Company will look to execute these deferrals in Q3/18 or
Q4/18 with improved natural gas prices.
- Q2/18 production volumes of approximately 27 MMcf/d were
shut-in, due to low natural gas prices.
- Q2/18 production was impacted by 12 MMcf/d related to solution
gas associated with the curtailment of primary heavy crude oil
production.
• Additionally, the Company's natural gas production was reduced
by approximately 65 MMcf/d in Q2/18 due to restrictions at the Pine
River plant, operated by a third party. In Q2/18 Canadian Natural,
subject to regulatory approval, agreed to acquire the facility from
the third party, which needs to complete a meter upgrade that will
take approximately four weeks, at which time the Company targets to
complete maintenance work on the facility and will assess
increasing plant throughput and reliability to match field capacity
of approximately 145 MMcf/d.
• As a result of the items listed above and proactive actions
going forward, the Company’s 2018 corporate natural gas annual
production guidance has been revised and is targeted to range from
1,550 MMcf/d - 1,600 MMcf/d.
• The Company uses natural gas in its operations representing
approximately 35% of its total equivalent gas production providing
a natural hedge from the challenging Western Canadian natural gas
price environment. Approximately 32% of the natural gas production
is exported to other North American markets or sold
internationally, with the remaining 33% of the Company's production
being exposed to AECO/Station 2 pricing.
International Exploration and
Production
|
Three Months Ended |
Six Months Ended |
|
|
|
|
|
|
|
Jun 30
2018 |
|
Mar 31 2018 |
|
Jun 30 2017 |
|
Jun 30
2018 |
|
Jun 30 2017 |
|
Crude oil
production (bbl/d) |
|
|
|
|
|
|
|
|
|
|
North Sea |
24,456 |
|
21,584 |
|
26,304 |
|
23,028 |
|
24,682 |
|
Offshore Africa |
18,201 |
|
19,438 |
|
20,480 |
|
18,816 |
|
21,542 |
|
Natural gas
production (MMcf/d) |
|
|
|
|
|
North Sea |
30 |
|
37 |
|
37 |
|
34 |
|
37 |
|
Offshore Africa |
24 |
|
30 |
|
16 |
|
27 |
|
20 |
|
Net wells
targeting crude oil |
1.9 |
|
1.0 |
|
1.8 |
|
2.9 |
|
1.8 |
|
Net successful wells drilled |
1.9 |
|
1.0 |
|
1.8 |
|
2.9 |
|
1.8 |
|
Success rate |
100 |
% |
100 |
% |
100 |
% |
100 |
% |
100 |
% |
|
|
|
|
|
|
|
|
|
|
|
• International E&P quarterly production volumes were within
quarterly production guidance and reached 42,657 bbl/d in Q2/18, an
increase of 4% from Q1/18 levels.
- In the North Sea, volumes of 24,456 bbl/d were achieved in
Q2/18, an increase of 13% from Q1/18 levels and a decrease of 7%
from Q2/17 levels. The increase in production in Q2/18 from Q1/18
levels was primarily due to new wells at Tiffany and Ninian. The
decrease from Q2/17 levels was a result of the impact of the
shut-in of the Ninian North platform in May 2017 in preparation for
decommissioning and natural field declines, partially offset by new
wells at Ninian South and production optimization.
- The Company's continued focus on production enhancements,
increased reliability and water flood optimization in the North Sea
resulted in Q2/18 operating costs decreasing by 19% from Q1/18
levels to $35.12/bbl.
- In the first half of 2018, 2.9 net wells were drilled in the
North Sea, with current light crude oil production exceeding 1,700
bbl/d per well.
- On April 26, 2018, the Ninian North platform was permanently
de-manned in readiness for future removal as part of the ongoing
decommissioning program. This milestone was achieved 3 months ahead
of schedule and below budget.
- Offshore Africa production volumes in Q2/18 averaged 18,201
bbl/d, a decrease of 6% and 11% from Q1/18 and Q2/17 levels
respectively. The decrease from Q2/17 was primarily as a result of
planned maintenance activities at Espoir that were successfully
completed in Q2/18, as well as natural field declines.
- Côte d'Ivoire crude oil operating costs in Q2/18 were strong at
$16.39/bbl, a 5% decrease from Q2/17 levels.
- The Company is targeting to drill 1.7 net producing wells at
Baobab, where drilling has commenced. The program targets to add
average net production of approximately 5,700 bbl/d of light crude
oil with the first well targeted to come on production in late
Q3/18.
• The Company's 2018 International annual production guidance
remains unchanged and is targeted to range from 40,000 bbl/d -
45,000 bbl/d.
North America Oil Sands Mining and
Upgrading
|
Three Months Ended |
Three Months Ended |
|
|
|
|
|
|
|
Jun 30 2018 |
Mar 31 2018 |
Jun 30 2017 |
Jun 30 2018 |
Jun 30 2017 |
Synthetic crude oil production (bbl/d) (1) (2) |
407,704 |
|
456,076 |
|
257,541 |
|
431,756 |
|
225,196 |
|
• |
Q2/18 SCO production
before royalties excludes 3,026 bbl/d of SCO consumed internally as
diesel (Q1/18 – 3,224 bbl/d; Q2/17 – 438 bbl/d). |
(3) |
Consists of heavy and
light synthetic crude oil products. |
• At the Company's world class Oil Sands Mining and Upgrading
assets, operations were as expected in Q2/18 with quarterly
production of 407,704 bbl/d of SCO, a decrease of 11% from Q1/18
levels as planned turnaround and pit stop activities at all three
of the Company's oil sands mines as well as a major 62 day
turnaround at the Scotford Upgrader were successfully completed in
the quarter.
- Cost control remains a strong focus for the Company as costs
continued to come down resulting in industry leading operating
costs of $22.94/bbl (US$17.77/bbl) of SCO in Q2/18, a 2% decrease
from Q2/17 levels and a 7% increase from Q1/18 levels, impressive
results considering major turnarounds decreased production by 11%
in Q2/18 from Q1/18 levels.
- At the AOSP, a significant milestone was reached in July, when
the asset produced its 1 billionth barrel of mined bitumen during
its first 15 years of operations, one of the few world class assets
to reach such a milestone. This is a true demonstration of the
quality, size and scale of the Company's Oil Sands Mining and
Upgrading operations which through environmentally responsible,
safe, reliable, effective and efficient operations, provide
sustainable long life low decline production and significant value
for stakeholders.
- At Horizon, following the successful completion of the Phase 3
expansion and after operating the plant for the last 8 months, the
Company continues to evaluate potential expansions and has
identified additional opportunities to increase reliability, lower
costs and add production.
- Results at the potential Paraffinic Froth Treatment expansion
at Horizon are evident as the engineering and design specification
work completed year to date has shown that the optimal production
range of the proposed expansion has increased by 10,000 bbl/d and
is now targeted to be 40,000 bbl/d to 50,000 bbl/d. The expansion
is targeted to produce high quality diluted bitumen at
significantly lower operating costs as the Company leverages
its existing infrastructure. Preliminary estimates of the capital
required for the proposed expansion are approximately $1.4
billion.
- Defining and high grading additional opportunities is ongoing
with the completion of the process targeted by year end. These
opportunities are targeted to add near term growth of 35,000 bbl/d
to 45,000 bbl/d of SCO. All opportunities will be executed in a
disciplined and step wise manner, which preserves Canadian
Natural's capital flexibility. The previously discussed VGO
expansion will be included in the high grading process.
- The Company's planned 21 day turnaround is targeted for
September 2018. Subsequently, the plant will run at restricted
rates of approximately 130,000 bbl/d for 12 days to perform
maintenance on the Vacuum Distillate Unit ("VDU") furnaces.
• The Company's 2018 Oil Sands Mining and
Upgrading annual production guidance remains unchanged and is
targeted to range from 415,000 bbl/d - 450,000 bbl/d of upgraded
products.
MARKETING
|
|
Three Months Ended |
|
|
Six Months Ended |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Jun 30 2018 |
|
Mar 31 2018 |
|
Jun 30 2017 |
|
|
Jun 30 2018 |
|
Jun 30 2017 |
Crude oil and NGLs
pricing |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
WTI
benchmark price (US$/bbl) (1) |
|
$ |
67.90 |
|
|
$ |
62.89 |
|
|
$ |
48.29 |
|
|
|
$ |
65.41 |
|
|
$ |
50.07 |
|
WCS heavy
differential as a percentage of WTI (%) (2) |
|
28 |
% |
|
39 |
% |
|
23 |
% |
|
|
33 |
% |
|
26 |
% |
SCO price
(US$/bbl) |
|
$ |
67.27 |
|
|
$ |
61.45 |
|
|
$ |
49.83 |
|
|
|
$ |
64.38 |
|
|
$ |
50.63 |
|
Condensate benchmark pricing (US$/bbl) |
|
$ |
68.85 |
|
|
$ |
63.12 |
|
|
$ |
48.44 |
|
|
|
$ |
66.00 |
|
|
$ |
50.31 |
|
Average
realized pricing before risk management (C$/bbl) (3) |
|
$ |
61.14 |
|
|
$ |
43.06 |
|
|
$ |
47.12 |
|
|
|
$ |
52.32 |
|
|
$ |
47.08 |
|
Natural gas
pricing |
|
|
|
|
|
|
|
|
|
|
|
AECO
benchmark price (C$/GJ) |
|
$ |
0.97 |
|
|
$ |
1.75 |
|
|
$ |
2.63 |
|
|
|
$ |
1.36 |
|
|
$ |
2.71 |
|
Average realized pricing before risk management (C$/Mcf) |
|
$ |
1.95 |
|
|
$ |
2.74 |
|
|
$ |
2.97 |
|
|
|
$ |
2.35 |
|
|
$ |
3.11 |
|
(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.
• In Q2/18, the WCS heavy differential narrowed
as heavy crude oil began to be moved to market. The WCS heavy
differential widened in Q1/18 as a result of third party pipeline
outages backing up heavy crude oil into Western Canada. This
resulted in anomalous heavy crude oil pricing as the pipeline
operators and rail transport worked to remove the backlog of
inventory.
• Canadian Natural and other industry
participants, as part of a working committee, are working towards a
more effective nomination process that verifies actual production
and sales.
- Having an effective nomination process is significant to
Canadian Natural as the Company is required to sell portions of its
heavy crude oil production at a discount to the WCS index as a
result of apportionment on the Enbridge pipeline.
• AECO natural gas prices for Q2/18 continued to
reflect third party pipeline constraints limiting flow of natural
gas to export markets, increased natural gas production in the
basin and constraints on export capacity out of Western Canada.
• 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 North West Redwater refinery began processing light crude
oil late in November 2017 and continues to progress as
expected.
- The Company has a 50% interest in the NWR Partnership. For
updates on the project, please refer to:
https://nwrsturgeonrefinery.com/whats-happening/news/.
2017 Stewardship Report to
Stakeholders
In Q2/18 Canadian Natural published its 2017
Stewardship Report to Stakeholders, now available on the Company's
website at
https://www.cnrl.com/corporate-responsibility/stewardship-report/#2017.
The report displays how Canadian Natural continues to focus on
safe, reliable, effective and efficient operations while minimizing
its environmental footprint.
- 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 has carbon capture
facilities at its 50% interest in the NWR refinery. As a result,
Canadian Natural targets capacity to capture and sequester 2.7
million tonnes of CO2 annually, equivalent to taking 570,000
vehicles off the road, making the Company the 5th largest capturer
and sequester of CO2 globally once the NWR refinery is fully
running.
- At Canadian Natural's Oil Sands operations, which represent
approximately 66% 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, specifically carbon capture initiatives,
Canadian Natural has developed a pathway to reduce the Company's
greenhouse gas ("GHG") emissions intensity to be 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 Company’s GHG emissions intensity has decreased materially
by 18% from 2013 to 2017.
- Methane emissions have decreased 71% from 2013 to 2017 at the
Company's Alberta primary heavy crude oil operations.
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 funds flow generation, credit facilities, US
commercial paper program, 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 1,050,376 BOE/d in Q1/18, with approximately
98% of total production located in G7 countries.
- Canadian Natural maintains a balance of products with current
approximate product mix on a BOE/d basis of 50% light crude oil and
SCO blends, 25% heavy crude oil blends and 25% natural gas, based
upon the midpoint of annual 2018 production guidance.
- Canadian Natural’s production is resilient as long life low
decline assets make up approximately 73% of 2018 liquids production
guidance, including the AOSP, Horizon, Pelican Lake and thermal in
situ oil sands assets.
• In Q2/18, Canadian Natural delivered funds flow from
operations in excess of capital expenditures of approximately
$1,730 million, an increase of approximately $510 million and $890
million from Q1/18 and Q2/17 levels respectively.
• Balance sheet strength continues to be a focus of the Company
and strong financial performance was demonstrated in Q2/18 through
reduced long term debt and extensions of select credit
facilities.
- In Q2/18, Standard & Poor's revised the Company's rating
outlook from BBB+/negative to BBB+/stable.
- In Q2/18, the Company reduced long term net debt by
approximately $610 million, from Q1/18 levels.
- Additionally, the Company has reduced long term debt in the
past 12 months since the AOSP acquisition by approximately $2,500
million, from Q2/17 levels, when including the retirement of the
deferred AOSP acquisition liability.
- Canadian Natural maintains strong financial stability and
liquidity represented by cash balances and committed bank credit
facilities. At June 30, 2018 the Company had approximately $4,800
million of available liquidity, including cash and cash
equivalents, an increase of approximately $800 million from
Q1/18.
- Canadian Natural continues to have significant support from its
large and diverse banking group as indicated by credit facility
extensions during the quarter. In Q2/18 the Company extended its
$2,425 million revolving syndicated credit facility originally
maturing in June 2020 to June 2022. Additionally in the quarter,
Canadian Natural's $2,200 million non-revolving facility was
extended from October 2019 to October 2020.
- As at June 30, 2018, debt to book capitalization improved to
39.6% from 40.5% in Q1/18 and debt to adjusted EBITDA strengthened
to 2.1x from 2.5x from Q1/18.
• Returns to shareholders remains a key focus for Canadian
Natural as the Company returned approximately $850 million by way
of dividend and share buybacks in Q2/18. Share buybacks for
cancellation totaled 10,140,127 shares in the quarter at an
weighted average share price of $43.52.
- Subsequent to quarter end, the Company had additional share
buybacks of 722,600 common shares for cancellation at a weighted
average price of $46.95 per common share.
• In addition to its strong 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 June 30, 2018, these financial levers include the
Company’s third party equity investments of approximately $745
million.
• Subsequent to quarter end, Canadian Natural declared a
quarterly cash dividend on common shares of $0.335 per share
payable on October 1, 2018.
OUTLOOK
The Company forecasts annual 2018 production
levels to average between 815,000 and 885,000 bbl/d of crude oil
and NGLs and between 1,550 and 1,600 MMcf/d of natural gas, before
royalties. Q3/18 production guidance before royalties is forecast
to average between 771,000 and 819,000 bbl/d of crude oil and NGLs
and between 1,535 and 1,565 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 2018 capital
expenditures are targeted to be approximately $4.6 billion.
Forward-Looking
StatementsCertain 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 this 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") operations and future expansions, the Athabasca Oil
Sands Project ("AOSP"), Primrose thermal projects, the Pelican Lake
water and polymer flood project, the Kirby Thermal Oil Sands
Project, the cost and timing of construction 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 or synthetic crude oil (“SCO”) that the
Company may be reliant upon to transport its products to market,
and the assumption of operations at processing facilities also
constitute forward-looking statements. This forward-looking
information is based on annual budgets and multi-year forecasts,
and is 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 natural gas liquids (“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 reserve 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 reserve 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 this MD&A could also have
material 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 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 Currency, Production and Non-GAAP
Financial Measures
The Company's MD&A of the financial
condition and results of operations of the Company should be read
in conjunction with the unaudited interim consolidated financial
statements for the six months ended June 30, 2018 and the MD&A
and the audited consolidated financial statements for the year
ended December 31, 2017.
All dollar amounts are referenced in millions of
Canadian dollars, except where noted otherwise. The Company’s
unaudited interim consolidated financial statements for the period
ended June 30, 2018 and the Company's MD&A have been prepared
in accordance with International Financial Reporting Standards
(“IFRS”) as issued by the International Accounting Standards Board.
The Company's MD&A includes references to financial measures
commonly used in the crude oil and natural gas industry, such as
adjusted net earnings from operations, funds flow from operations,
adjusted cash production costs and adjusted depreciation, depletion
and amortization. These financial measures are not defined by IFRS
and therefore are referred to as non-GAAP 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 and cash flows from operating
activities, as determined in accordance with IFRS, as an indication
of the Company's performance. The non-GAAP measures adjusted net
earnings from operations and funds flow from operations are
reconciled to net earnings, as determined in accordance with IFRS,
in the “Financial Highlights” section of the Company's MD&A.
The non-GAAP measure funds flow from operations is also reconciled
to cash flows from operating activities in this section. The
derivation of adjusted cash production costs and adjusted
depreciation, depletion and amortization are included in the
“Operating Highlights - Oil Sands Mining and Upgrading” 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.
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. 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 volumes and per unit statistics are
presented throughout the Company's MD&A on a “before royalty”
or “gross” basis, and realized prices are net of blending and
feedstock costs and exclude the effect of risk management
activities. Production on an “after royalty” or “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, 2017, is available on SEDAR at www.sedar.com, and
on EDGAR at www.sec.gov.
CONFERENCE CALL
A conference call will be held at 9:00 a.m.
Mountain Time, 11:00 a.m. Eastern Time on Thursday, August 2,
2018.
The North American conference call number is
1-866-521-4909 and the outside North American conference call
number is 001-647-427-2311. Please call in 10 minutes prior to the
call starting time.
An archive of the broadcast will be available
until 6:00 p.m. Mountain Time, Thursday, August 16, 2018. 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 5289004.
The conference call will also be webcast live
and may 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.
CANADIAN NATURAL RESOURCES LIMITED |
2100,
855 - 2nd Street S.W. Calgary, Alberta, T2P4J8Phone:
403-517-7777 Email: ir@cnrl.comwww.cnrl.com |
|
|
STEVE W. LAUTExecutive Vice-Chairman TIM
S. MCKAYPresident COREY B. BIEBERChief
Financial Officer and Senior Vice-President, Finance MARK
A. STAINTHORPEVice-President, Finance – Capital Markets
Trading Symbol - CNQToronto Stock ExchangeNew York Stock
Exchange |
Canadian Natural Resources (TSX:CNQ)
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