Canadian Natural Resources Limited Announces 2018 Third Quarter
Results
Commenting on third quarter 2018 results, Steve Laut, Executive
Vice-Chairman of Canadian Natural stated, "The strength of our well
balanced and diverse portfolio, combined with Canadian Natural's
ability to effectively and efficiently execute, delivered a strong
third quarter for the Company. Record quarterly adjusted funds flow
of over $2.8 billion was achieved in the third quarter and adjusted
funds flow of $7.9 billion was achieved in the first nine months of
2018. Capital allocation continued to be balanced amongst our four
pillars to maximize shareholder value. In the first nine months of
2018, economic resource development remained disciplined at 40% of
adjusted funds flow. Returns to shareholders were robust at 26% of
adjusted funds flow and 31% of adjusted funds flow was allocated to
the balance sheet further strengthening our financial position.
Lastly, the Company executed on minor tuck-in acquisitions, 3% of
adjusted funds flow, that add optionality and significant future
value.
Based on the significant progress made to date
in strengthening the Company's balance sheet as well as the
sustainability of Canadian Natural's free cash flow, the Board of
Directors has 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 Normal
Course Issuer Bid (“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. At present, this policy
is expected to be in place until at least the Company's NCIB
renewal in May 2019, subject to quarterly review by the Board of
Directors. This policy is effective November 1, 2018."
Canadian Natural's President, Tim McKay, added,
"Operations were strong in the third quarter of 2018 across our
large, balanced and diverse asset base. The planned turnaround at
our Horizon operations was successfully completed under budget and
production ramped up on schedule. Our focus on effective and
efficient operations resulted in strong quarterly unadjusted
operating costs of $22.90/bbl (US$17.52/bbl) of Synthetic Crude Oil
("SCO") and adjusted operating costs of $19.95/bbl (US$15.26/bbl)
of SCO at our Oil Sands Mining and Upgrading operations.
International production volumes were strong in the quarter and
exceeded previously issued Q3 guidance as a result of the
successfully completed 2018 drilling program in the North Sea and
strong production from a newly drilled well in Offshore Africa. Our
International light crude oil volumes receive Brent pricing which
averaged US$75.46/bbl in the third quarter, generating significant
adjusted funds flow. Thermal in situ quarterly production volumes
averaged 112,542 bbl/d, exceeding Q3/18 guidance, primarily due to
the cyclical nature of steaming cycles and from production resuming
following the completion of planned maintenance activities in
Q2/18, as a result of proactive and strategic decisions made
earlier in the year.
Canadian Natural maintains a flexible and
disciplined capital allocation strategy with a focus on maintaining
a strong financial position and delivering significant shareholder
value. In light of current market conditions driven by market
access restrictions, lack of fiscal competitiveness and regulatory
uncertainties, the Company will exercise its capital flexibility
and allocate capital to those areas that maximize shareholder
value. Canadian Natural will continue to make strategic decisions
to reduce drilling activity, delay well completions and shut in
production. The effectiveness of our strategies, combined with our
ability to execute on these strategies, allows us to be nimble,
capture opportunities and be more sustainable through these
challenges."
Canadian Natural's Chief Financial Officer,
Corey Bieber, continued, "In the third quarter Canadian Natural
continued to deliver on its commitment to strengthen the balance
sheet. The Company achieved quarterly net earnings of $1,802
million and record quarterly adjusted funds flow of $2,830 million,
contributing to absolute net long-term debt reduction of
approximately $2,880 million year to date. In the quarter,
available liquidity improved to $5,350 million, an increase of
approximately $550 million from the second quarter of 2018. Debt to
adjusted EBITDA strengthened to 1.7x and debt to book
capitalization improved to 36.8% over the quarter. Our focus on
returns to shareholders has resulted in $2,030 million being
returned to shareholders, in the first nine months of 2018, by way
of dividends of $1,156 million and share purchases of $874 million.
Subsequent to the quarter, an additional 6,900,000 shares were
purchased at a weighted average share price of $38.66. Our balance
sheet strength gives us the flexibility to deliver our defined
growth plan and continue to drive long-term shareholder value
creation."
HIGHLIGHTS
|
|
Three Months Ended |
|
|
Nine Months Ended |
|
|
|
|
|
|
|
|
|
|
|
|
($ millions, except per common share amounts) |
|
|
Sep 30 2018 |
|
|
|
Jun 30 2018 |
|
|
|
Sep 30 2017 |
|
|
|
|
Sep 30 2018 |
|
|
|
Sep 30 2017 |
|
Net
earnings |
|
$ |
1,802 |
|
|
$ |
982 |
|
|
$ |
684 |
|
|
|
$ |
3,367 |
|
|
$ |
2,001 |
|
Per common share |
– basic |
|
$ |
1.48 |
|
|
$ |
0.80 |
|
|
$ |
0.56 |
|
|
|
$ |
2.75 |
|
|
$ |
1.72 |
|
|
– diluted |
|
$ |
1.47 |
|
|
$ |
0.80 |
|
|
$ |
0.56 |
|
|
|
$ |
2.74 |
|
|
$ |
1.71 |
|
Adjusted net earnings from operations (1) |
|
$ |
1,354 |
|
|
$ |
1,279 |
|
|
$ |
229 |
|
|
|
$ |
3,518 |
|
|
$ |
838 |
|
Per common share |
– basic |
|
$ |
1.11 |
|
|
$ |
1.05 |
|
|
$ |
0.19 |
|
|
|
$ |
2.88 |
|
|
$ |
0.72 |
|
|
– diluted |
|
$ |
1.11 |
|
|
$ |
1.04 |
|
|
$ |
0.19 |
|
|
|
$ |
2.86 |
|
|
$ |
0.72 |
|
Cash flows from
operating activities |
|
|
$ |
3,642 |
|
|
$ |
2,613 |
|
|
$ |
2,522 |
|
|
|
$ |
8,724 |
|
|
$ |
5,824 |
|
Adjusted funds flow (2) |
|
$ |
2,830 |
|
|
$ |
2,706 |
|
|
$ |
1,675 |
|
|
|
$ |
7,859 |
|
|
$ |
5,040 |
|
Per common share |
– basic |
|
$ |
2.32 |
|
|
$ |
2.20 |
|
|
$ |
1.38 |
|
|
|
$ |
6.42 |
|
|
$ |
4.34 |
|
|
– diluted |
|
$ |
2.31 |
|
|
$ |
2.19 |
|
|
$ |
1.37 |
|
|
|
$ |
6.39 |
|
|
$ |
4.32 |
|
Cash flows on (from) investing activities |
|
$ |
1,265 |
|
|
$ |
1,138 |
|
|
$ |
1,960 |
|
|
|
$ |
3,772 |
|
|
$ |
12,028 |
|
Net capital expenditures (3) |
|
$ |
1,473 |
|
|
$ |
974 |
|
|
$ |
2,094 |
|
|
|
$ |
3,550 |
|
|
$ |
15,986 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Daily production, before royalties |
|
|
|
|
|
|
|
|
|
|
|
Natural gas (MMcf/d) |
|
1,553 |
|
|
1,539 |
|
|
1,664 |
|
|
|
1,568 |
|
|
1,664 |
|
Crude oil and NGLs (bbl/d) |
|
801,742 |
|
|
793,899 |
|
|
759,189 |
|
|
|
816,539 |
|
|
665,399 |
|
Equivalent production (BOE/d) (4) |
|
1,060,629 |
|
|
1,050,376 |
|
|
1,036,499 |
|
|
|
1,077,953 |
|
|
942,776 |
|
- 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”).
- 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 fund capital reinvestment
and debt repayment. 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 annual 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 $1,802 million were realized in Q3/18, an
increase of $820 million and $1,118 million over Q2/18 and Q3/17
levels, respectively. Adjusted net earnings in Q3/18 of $1,354
million were achieved, a $75 million increase over Q2/18 and an
increase of $1,125 million over Q3/17 levels.
- Cash flows from operating activities were $3,642 million in
Q3/18, increases of $1,029 million and $1,120 million over Q2/18
and Q3/17 levels, respectively.
- Canadian Natural generated record quarterly adjusted funds flow
of $2,830 million in Q3/18, increases of $124 million and $1,155
million from Q2/18 and Q3/17 levels, respectively. The increase
over Q2/18 was primarily due to higher natural gas netbacks and the
Company's continued focus on lowering operating costs in the
Exploration and Production ("E&P") and Oil Sands Mining and
Upgrading segments. The increase over Q3/17 primarily reflects
higher realized prices from the Company's liquids production and
higher liquids production volumes from the completion of the
Horizon Phase 3 expansion.
- In Q3/18, Canadian Natural delivered significant adjusted funds
flow in excess of net capital expenditures of approximately $1,360
million, including deferred discounted purchase consideration. In
the first nine months of 2018, adjusted funds flow in excess of net
capital expenditures was approximately $4,310 million, including
deferred discounted purchase consideration.
- After dividend requirements, free cash flow totaled
approximately $950 million in Q3/18 and in the first nine months of
2018, free cash flow totaled approximately $3,150 million.
- Consistent with the Company's four pillar strategy, the Company
has maintained balance in the allocation of its adjusted funds
flow:
- The Company remained disciplined in its economic resource
development investments with year to date net capital expenditures
of $3,196 million, excluding net acquisitions.
- Year to date, the Company has reduced long term net debt by
approximately $2,880 million, including the impact of foreign
exchange, working capital and other adjustments, resulting in debt
to adjusted EBITDA strengthening to 1.7x and debt to book
capitalization improving to 36.8%.
- Returns to shareholders remain a key focus for Canadian Natural
as the Company has returned approximately $2,030 million in the
first nine months of 2018, by way of dividends of $1,156 million
and share purchases of $874 million.
- Share purchases for cancellation totaled 9,872,600 common
shares in Q3/18 at a weighted average share price of $43.81.
- In the first nine months of 2018, share purchases totaled
20,012,727 common shares at a weighted average share price of
$43.66.
- Subsequent to quarter end and up to October 31, 2018, the
Company executed additional share purchases of 6,900,000 common
shares for cancellation at a weighted average share price of
$38.66.
- Subsequent to quarter end Canadian Natural declared a quarterly
cash dividend on common shares of $0.335 per share payable on
January 1, 2019.
- In the first nine months of 2018, the Company has executed on
opportunistic acquisitions of approximately $354 million, including
Exploration and Evaluation ("E&E") expenditures of $257
million. Included in the E&E expenditures is the deferred
discounted purchase consideration of $118 million, payable over the
next five years. These tuck-in acquisitions add significant
future value to the Company's long life low decline asset
portfolio.
- The Joslyn acquisition has the potential to add significant
long life low decline reserves as well as cost savings through the
extension of existing Horizon South Pit operations. The lease-line
development opportunities reduce the need to relocate Horizon
operations to the North Pit, to install new equipment, and
construct new infrastructure. Over the next decade, synergies with
Horizon are targeted to result in cost savings of over $500
million. At the Joslyn lease, the former operator had project
regulatory approval for a 100,000 bbl/d project.
- The Laricina corporate asset acquisition which includes the
Grand Rapids lands is a great fit with existing lands and
operations in the area. The Company's Thermal team sees the
opportunity to improve the future performance of the Grand Rapids
which is targeted to be piloted through the existing facilities in
the future. Additionally, the Company took over operatorship of a
key road needed for operations in the area, which will result in
immediate savings to the Company. Canadian Natural's lands combined
with the acquired lands, have total Grand Rapids bitumen in place
potential of 15.9 billion barrels, adding significant future
shareholder value.
- Based on the significant progress made to date in strengthening
the Company's balance sheet as well as the sustainability of
Canadian Natural's free cash flow, the Board of Directors has
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
Normal Course Issuer Bid (“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. At present,
this policy is expected to be in place until at least the Company's
NCIB renewal in May 2019, subject to quarterly review by the Board
of Directors. This policy is effective November 1, 2018.
- The Company's production volumes in Q3/18 averaged 1,060,629
BOE/d, comparable to Q2/18 and an increase of 2% from Q3/17 levels.
The increase from Q3/17 was mainly due to the completion of the
Horizon Phase 3 expansion, acquisitions completed in 2017 and
production from new wells in the North Sea, partially offset by
declines in natural gas production along with natural gas and heavy
crude oil shut ins and reduced activity of 21,500 BOE/d.
- In the first nine months of 2018, strong operating costs of
$11.91/BOE were realized in the Company's E&P segment, a 7%
decrease from Q2/18 levels, a significant achievement given
strategic and proactive decisions to curtail, defer and shut in
production during the year.
- At the Company's world class Oil Sands Mining and Upgrading
assets, operations were strong and above the midpoint of guidance
in Q3/18, with quarterly production of 394,382 bbl/d of Synthetic
Crude Oil ("SCO"), a decrease of 3% from Q2/18 levels, as planned
pit stop activities at the Athabasca Oil Sands Project ("AOSP") and
a major planned turnaround at Horizon were successfully completed
in the quarter. Quarterly production increased from Q3/17 levels by
11% mainly due to the production from the Horizon Phase 3
expansion.
- Through safe, steady and reliable operations, high utilization,
and leveraging expertise to capture synergies, the Company realized
average unadjusted operating costs of $22.90/bbl (US$17.52/bbl) of
SCO in Q3/18, an impressive result given the planned downtime at
Horizon in the quarter. After normalizing for planned turnaround
downtime, operating costs reached $19.95/bbl (US$15.26/bbl) of SCO
in Q3/18.
- At Horizon, during the planned turnaround, optimization and
reliability work on the Vacuum Distillate Unit ("VDU") furnaces and
coker train was completed under budget and the units ramped up on
schedule.
- At Pelican Lake, polymer flood restoration for 2018 on the
acquired lands was completed ahead of schedule, where approximately
62% 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. In Q3/18, as a result of
effective and efficient operations, strong operating costs of
$6.43/bbl were achieved, an 8% decrease from Q2/18 levels and a 9%
decrease from Q1/18 levels.
- Thermal in situ quarterly production volumes exceeded Q3/18
guidance, averaging 112,542 bbl/d, resulting in an increase of 7%
from Q2/18 levels. The increase was primarily due to the cyclical
nature of steaming cycles and from production resuming following
the completion of planned maintenance in Q2/18 and proactive and
strategic decisions to curtail production earlier in the year.
- Pad additions at Primrose are ahead of schedule and on budget
with initial production targeted to add approximately 10,000 bbl/d
in Q4/19 and the total program is targeted to add approximately
32,000 bbl/d in 2020. These pad additions are high return
activities as the Company targets to utilize available excess oil
processing and steam capacity at Primrose.
- At Kirby North, top tier execution and strong productivity has
resulted in the project progressing ahead of the sanctioned
schedule. Cost performance remains on budget with 80% of the
Central Processing Facility complete and Steam Assisted Gravity
Drainage ("SAGD") drilling nearing 70% completion. Kirby North
targets to add 40,000 bbl/d of SAGD production with first oil
targeted for Q4/19, one quarter earlier than originally
planned.
- International E&P quarterly production volumes were strong
in Q3/18, exceeding quarterly production guidance and reaching
47,504 bbl/d. International production receives Brent pricing that
averaged US$75.46/bbl in Q3/18, generating significant adjusted
funds flow. The increase in production of 11% and 9% from Q2/18 and
Q3/17 levels respectively, was primarily due to a successful
drilling program in the North Sea, partially offset by natural
field declines.
- The 2018 drilling program in the North Sea was successfully
completed on time and on budget with 3.9 net production wells
drilled year to date. Current light crude oil production is
exceeding sanctioned expectations.
- In Q3/18, the Company successfully drilled the first of three
gross production wells at Baobab. Current light crude oil
production from the first well is exceeding sanctioned expectations
at approximately 2,200 bbl/d net. Subsequent to the quarter, the
second well came on production with initial rates at approximately
3,700 bbl/d net. The Company is targeting the third well to come on
production in Q4/18, and is on target to exceed the original
budgeted production adds for the program of 5,370 bbl/d net, and as
a result, Canadian Natural is currently evaluating the option to
drill an additional production well in 2019, extending the drilling
program at Baobab.
- Balance sheet strength and strong financial performance were
demonstrated in Q3/18 through reduced long-term debt and upgraded
credit ratings.
- In Q3/18, Moody's Investors Service, Inc. upgraded the
Company's senior unsecured rating to Baa2 from Baa3 and its short
term rating to P-2 from P-3 with a stable outlook.
- In Q3/18, Canadian Natural reduced long-term net debt by
approximately $1,780 million from Q2/18 levels.
- Canadian Natural maintains strong financial stability and
liquidity represented by cash balances and committed bank credit
facilities. At September 30, 2018 the Company had approximately
$5,350 million of available liquidity, including cash and cash
equivalents, an increase of approximately $550 million from
Q2/18.
- Due to current market conditions driven by lack of market
access for both oil and natural gas, regulatory uncertainty, and
lack of fiscal competitiveness, the Company continues to exercise
its capital flexibility along with proactive decisions to
strategically shift capital, curtail volumes, shut in production
and delay completion of recently drilled crude oil wells. These
factors will play a prominent role in 2019 and future capital
allocation decisions.
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 reserve replacement
cost, and effective and efficient operations means these assets
provide 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 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
|
Nine Months Ended Sep 30 |
|
|
|
|
2018 |
2017 |
(number of wells) |
Gross |
|
Net |
|
Gross |
|
Net |
|
Crude oil |
402 |
|
381 |
|
395 |
|
370 |
|
Natural gas |
19 |
|
15 |
|
19 |
|
19 |
|
Dry |
7 |
|
7 |
|
4 |
|
4 |
|
Subtotal |
428 |
|
403 |
|
418 |
|
393 |
|
Stratigraphic test / service wells |
617 |
|
524 |
|
238 |
|
238 |
|
Total |
1,045 |
|
927 |
|
656 |
|
631 |
|
Success rate (excluding stratigraphic test / service wells) |
|
98 |
% |
|
99 |
% |
- The Company's total crude oil and natural gas drilling program
of 403 net wells for the nine months ended September 30, 2018,
excluding strat/service wells, was an increase of 10 net wells from
the same period in 2017. The Company's drilling levels reflect 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 |
Nine Months Ended |
|
|
|
|
|
|
|
Sep 30 2018 |
|
Jun 30 2018 |
|
Sep 30 2017 |
|
Sep 30 2018 |
|
Sep 30 2017 |
|
Crude
oil and NGLs production (bbl/d) |
247,314 |
|
238,631 |
|
238,844 |
|
243,857 |
|
232,533 |
|
Net wells targeting crude
oil |
140 |
|
58 |
|
145 |
|
299 |
|
349 |
|
Net
successful wells drilled |
135 |
|
58 |
|
144 |
|
292 |
|
346 |
|
Success rate |
96 |
% |
100 |
% |
99 |
% |
98 |
% |
99 |
% |
- North America crude oil and NGLs averaged 247,314 bbl/d in
Q3/18, representing a 4% increase from both Q2/18 and Q3/17
levels. The volume increase from Q2/18 was primarily a result of
increased production in primary heavy crude oil due to the ramp up
of new wells previously curtailed and increased production in light
crude oil due to the additional capital allocated from primary
heavy crude oil, partially offset by curtailed primary heavy crude
oil production volumes. The increase from Q3/17 was mainly due to
the successful integration of acquired assets at Pelican Lake.
- Due to widening price differentials driven by market access
restrictions, the Company made the proactive and strategic decision
to shut in, curtail and reduce activity on heavy crude oil
production resulting in production impacts of approximately 10,000
bbl/d to 15,000 bbl/d in October and approximately 45,000 bbl/d to
55,000 bbl/d targeted for November and December.
- Canadian Natural's primary heavy crude oil production averaged
91,631 bbl/d in Q3/18, an 8% increase from Q2/18 levels primarily
due to ramp up of new wells previously curtailed along with a full
quarter of production at the Company's Smith primary heavy crude
oil play.
- In Q3/18, to maximize value as a result of widening price
differentials, Canadian Natural continued to implement and execute
proactive decisions and strategic actions to allocate more capital
from primary heavy crude oil assets to light crude oil assets. As a
result, the Company drilled 63 less net wells in Q3/18, with a year
to date impact of 83 less net primary heavy crude oil wells in the
year than originally budgeted. Additionally, in Q3/18, the Company
delayed completion on 33 net primary heavy crude oil wells as well
as shut in production. The Company targets to bring on the delayed
and shut in production when primary heavy crude oil netbacks
improve.
- At the Company's Smith primary heavy crude oil play, production
results continue to be strong from the 6 net multilateral wells on
production with current rates of approximately 300 bbl/d per well,
which are exceeding original production expectations of 171 bbl/d
from sanction. Additionally, actual decline rates are coming in
significantly lower than sanctioned rates. 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.
- Controlling costs remains a focus with operating costs of
$15.58/bbl in Q3/18, an 8% decrease from Q2/18 levels, due to
increased volumes from previously curtailed primary heavy crude oil
production.
- North America light crude oil and NGL quarterly production
averaged 92,956 bbl/d, an increase of 3% from Q2/18 levels and
comparable to Q3/17 levels. The increase from Q2/18 is primarily as
a result of a successful drilling program and increased production
in light crude oil due to the additional capital allocated from
primary heavy crude oil, partially offset by natural declines.
- The Company successfully drilled 27 net light crude oil wells
in Q3/18, 19 net wells above the original plan as the Company
reallocated capital from primary heavy crude oil to light crude
oil. Highlights from wells coming on production to date are as
follows:
- At Wembley, production remains strong at approximately 500
bbl/d per well from wells drilled earlier in 2018. With this
success, an additional 4 net wells were drilled in Q3/18 with
production targeted to come on in Q4/18. The Company has 77 net
Montney sections of lands in the area with greater than 175
potential premium light crude oil well locations.
- Including the greater Wembley area, the Company has an
additional 54 net Montney sections and over 125 incremental
potential premium light crude oil well locations.
- In Southeast Saskatchewan, the Company drilled 9 net light
crude oil wells in Q3/18 with some wells on production late in the
quarter and the remaining wells are targeting to come on production
in Q4/18. These light crude oil wells were drilled as a result of
the strategic decision to shift capital to light crude oil and were
not originally budgeted. Additionally, production from these
Saskatchewan wells are less impacted by the apportionment issues
and price differentials experienced in Alberta.
- At the Company's light crude oil development at Tower,
operations are currently ramping up with 6 out of 7 net wells on
production, and current facility constrained production averaging
approximately 5,500 BOE/d due to gas handling at capacity at the
facility. With the positive results on the first wells, the Company
has 11 net sections with the potential for an additional 41 net
wells that would leverage off the existing facility over time,
adding significant value.
- Operating costs of $15.51/bbl were realized in Q3/18, a
decrease of 2% from Q2/18 levels in the Company's light crude oil
and NGL areas.
- Pelican Lake quarterly production averaged 62,727 bbl/d,
comparable with Q2/18 levels and an increase of 32% from Q3/17
levels. The increase from Q3/17 was as a result of the Company's
successful integration of acquired assets in late 2017.
- Polymer flood restoration for 2018 on the acquired lands was
completed ahead of schedule, where approximately 62% 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.
- Strong operating costs of $6.43/bbl were achieved in Q3/18, an
8% decrease from Q2/18 levels and a 9% decrease from Q1/18
levels.
- The Company’s 2018 North America E&P crude oil and NGL
annual production guidance is targeted to range between 240,000
bbl/d - 246,000 bbl/d.
Thermal In Situ
Oil Sands |
|
|
|
Three Months Ended |
Nine Months Ended |
|
|
|
|
|
|
|
Sep 30 2018 |
|
Jun 30 2018 |
|
Sep 30 2017 |
|
Sep 30 2018 |
|
Sep 30 2017 |
|
Bitumen
production (bbl/d) |
112,542 |
|
104,907 |
|
122,372 |
|
109,769 |
|
118,798 |
|
Net wells targeting
bitumen |
41 |
|
21 |
|
10 |
|
84 |
|
22 |
|
Net
successful wells drilled |
41 |
|
21 |
|
10 |
|
84 |
|
22 |
|
Success rate |
100 |
% |
100 |
% |
100 |
% |
100 |
% |
100 |
% |
- Thermal in situ quarterly production volumes exceeded Q3/18
guidance, averaging 112,542 bbl/d, resulting in an increase of 7%
from Q2/18 levels. The increase was primarily due to the cyclical
nature of steaming cycles and from production resuming following
the completion of planned maintenance in Q2/18 and proactive and
strategic decisions to curtail production earlier in the year.
- At Primrose, Q3/18 production volumes averaged 72,500 bbl/d, an
increase of 7% from Q2/18 levels, primarily as a result of the
timing of cyclical steaming where additional wells entered the
production cycle. Including energy costs, operating costs were
strong at $11.80/bbl in Q3/18, a decrease of 20% from Q2/18 levels.
- Pad additions at Primrose are ahead of schedule and on budget
with initial production targeted to add an approximate 10,000 bbl/d
in Q4/19 and the total program is targeted to add approximately
32,000 bbl/d in 2020. These pad additions are high return
activities as the Company targets to utilize available excess oil
processing and steam capacity at Primrose.
- At Kirby South, SAGD production volumes of 35,839 bbl/d were
achieved in Q3/18, comparable to Q2/18 and a 4% decrease from Q3/17
levels. Including energy costs, Kirby South achieved strong Q3/18
operating costs of $9.14/bbl, comparable to Q2/18 and a 2% increase
from Q3/17 levels.
- At Kirby North, top tier execution and strong productivity has
resulted in the project progressing ahead of the sanctioned
schedule. Cost performance remains on budget with 80% of the
Central Processing Facility complete and SAGD drilling nearing 70%
completion. Kirby North targets to add 40,000 bbl/d of SAGD
production with first oil targeted for Q4/19, one quarter earlier
than originally planned.
- 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 |
Nine Months Ended |
|
|
|
|
|
|
|
Sep 30 2018 |
|
Jun 30 2018 |
|
Sep 30 2017 |
|
Sep 30 2018 |
|
Sep 30 2017 |
|
Natural
gas production (MMcf/d) |
1,489 |
|
1,485 |
|
1,593 |
|
1,506 |
|
1,602 |
|
Net wells targeting natural
gas |
6 |
|
4 |
|
3 |
|
15 |
|
20 |
|
Net
successful wells drilled |
6 |
|
4 |
|
3 |
|
15 |
|
19 |
|
Success rate |
100 |
% |
100 |
% |
100 |
% |
100 |
% |
95 |
% |
- North America natural gas production was as expected at 1,489
MMcf/d in Q3/18, comparable to Q2/18 and a decrease of 7% from
Q3/17 levels. The decrease from Q3/17 was primarily due to
strategic decisions made to reduce drilling and development
activities and shut in production as a result of low natural gas
prices and third party facility constraints.
- Operating costs of $1.20/Mcf were realized in Q3/18, a decrease
of 6% from Q2/18 levels, strong results given lower natural gas
production volumes due to the Company's proactive decision to shut
in volumes and delay activity on certain natural gas assets.
- In 2018, the Company continues to make proactive and strategic
decisions to maximize value in the Company's natural gas assets and
as a result, Q3/18 production volumes were reduced by approximately
146 MMcf/d due to the following:
- Deferred capital and development activity including
recompletions and workovers of certain natural gas assets along
with production shut ins, resulted in a production impact of
approximately 96 MMcf/d in Q3/18. The Company targets to
re-evaluate these development activities when natural gas prices
improve.
- Q3/18 production was impacted by approximately 8 MMcf/d related
to solution gas associated with the curtailment of primary heavy
crude oil production.
- Additionally, the Company's natural gas production capability
was reduced by approximately 42 MMcf/d in Q3/18 due to restrictions
at the Pine River plant, operated by a third party. The third party
completed the planned four week turnaround from mid-September to
mid-October, but due to additional integrity issues, the plant is
now targeting to start up in mid-November. During the turnaround,
Canadian Natural was able to assess the potential for the plant to
be restored to match the field capacity of 145 MMcf/d. The Company
is evaluating the work that would be required and will decide on an
investment decision as part of its 2019 budget process. As
previously announced, Canadian Natural agreed to acquire the
facility from the third party and is waiting for regulatory
approval.
- In Q3/18, Canadian Natural used natural gas in its operations
representing approximately 37% of its total equivalent gas
production providing a natural hedge from the challenging Western
Canadian natural gas price environment. Approximately 28% of the
total natural gas production is exported to other North American
markets at an average Q3/18 price of $3.26/GJ or sold
internationally at a Q3/18 average price of $11.31/GJ. The
remaining 35% of the Company's production is exposed to
AECO/Station 2 pricing.
- The Company’s 2018 corporate natural gas annual production
guidance remains unchanged and is targeted to range between 1,550
MMcf/d - 1,600 MMcf/d.
International Exploration and
Production
|
Three Months Ended |
Nine Months Ended |
|
|
|
|
|
|
|
Sep 30 2018 |
|
Jun 30 2018 |
|
Sep 30 2017 |
|
Sep 30 2018 |
|
Sep 30 2017 |
|
Crude oil production
(bbl/d) |
|
|
|
|
|
North Sea |
28,702 |
|
24,456 |
|
24,832 |
|
24,940 |
|
24,733 |
|
Offshore Africa |
18,802 |
|
18,201 |
|
18,776 |
|
18,812 |
|
20,610 |
|
Natural gas production
(MMcf/d) |
|
|
|
|
|
North Sea |
38 |
|
30 |
|
46 |
|
35 |
|
40 |
|
Offshore Africa |
26 |
|
24 |
|
25 |
|
27 |
|
22 |
|
Net wells targeting crude
oil |
1.6 |
|
1.9 |
|
- |
|
4.5 |
|
1.8 |
|
Net
successful wells drilled |
1.6 |
|
1.9 |
|
- |
|
4.5 |
|
1.8 |
|
Success rate |
100 |
% |
100 |
% |
- |
|
100 |
% |
100 |
% |
- International E&P quarterly production volumes were strong
in Q3/18, exceeding quarterly production guidance and reaching
47,504 bbl/d which receives Brent pricing that averaged
US$75.46/bbl in Q3/18, generating significant adjusted funds flow.
The increase in production of 11% and 9% from Q2/18 and Q3/17
levels respectively, was primarily due to a successful drilling
program in the North Sea, partially offset by natural field
declines.
- In the North Sea, production volumes of 28,702 bbl/d were
achieved in Q3/18, an increase of 17% and 16% over Q2/18 and Q3/17
levels respectively, primarily due to the successful drilling
program completed in 2018 and partially offset by planned
maintenance activities at Ninian South during the quarter.
- The 2018 drilling program in the North Sea was successfully
completed on time and on budget with 3.9 net producer wells drilled
year to date. Current light crude oil production is exceeding
sanctioned expectations.
- The Company's continued focus on production enhancements,
increased reliability and water flood optimization in the North Sea
resulted in Q3/18 operating costs of $37.32/bbl.
- For Q4/18, the Company has planned turnaround and maintenance
activities in the North Sea at Ninian Central and Tiffany.
- Offshore Africa production volumes in Q3/18 averaged 18,802
bbl/d, an increase of 3% from Q2/18 and comparable to Q2/17 levels.
The increase from Q2/18 was primarily as a result of production
resuming following the planned maintenance activities completed
during Q2/18, together with new production from the first of three
gross production wells planned at Baobab.
- Côte d'Ivoire crude oil operating costs in Q3/18 were strong at
$13.94/bbl, a 15% decrease from Q2/18 levels.
- In Q3/18, the Company successfully drilled the first of three
gross production wells at Baobab. Current light crude oil
production from the first well is exceeding sanctioned expectations
at approximately 2,200 bbl/d net. Subsequent to the quarter, the
second well came on production with initial rates at approximately
3,700 bbl/d net. The Company is targeting the third well to come on
production in Q4/18, and is on target to exceed the original
budgeted production adds for the program of 5,370 bbl/d net, and as
a result, Canadian Natural is currently evaluating the option to
drill an additional production well in 2019, extending the drilling
program at Baobab.
- In Q4/18, the Company has planned maintenance activities in
Côte d'Ivoire at the Espoir Floating Production Storage and
Offloading vessel.
- Subsequent to the quarter, the Company farmed out a 25% working
interest in the Exploration Right relating to Block 11B/12B located
offshore South Africa. The Operator has secured a drilling unit to
re-enter an exploration well on the Block with drilling operations
targeted to commence during the first quarter of 2019.
- As part of the farm out, Canadian Natural received an up front
cash consideration and will also receive a material financial carry
on the exploration well costs and subsequent operations. Subject to
there being a commercial discovery, the Company will receive
further bonus payments.
- The transaction was completed on October 29. Canadian Natural's
working interest in the Block is now 25%.
- 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 |
Nine Months Ended |
|
|
|
|
|
|
|
Sep 30 2018 |
Jun 30 2018 |
Sep 30 2017 |
Sep 30 2018 |
Sep 30 2017 |
Synthetic crude oil production (bbl/d) (1) (2) |
394,382 |
407,704 |
354,365 |
419,161 |
268,725 |
- Q3/18 SCO production before royalties excludes 2,758 bbl/d of
SCO consumed internally as diesel (Q2/18 – 3,026 bbl/d; Q3/17 – 0
bbl/d).
- Consists of heavy and light synthetic crude oil products.
- At the Company's world class Oil Sands Mining and Upgrading
assets, operations were strong and above the midpoint of guidance
in Q3/18 with quarterly production of 394,382 bbl/d of SCO, a
decrease of 3% from Q2/18 levels, as planned pit stop activities at
the AOSP and a major planned turnaround at Horizon were
successfully completed in the quarter. Quarterly production
increased from Q3/17 levels by 11% mainly due to the production
from the Horizon Phase 3 expansion.
- Through safe, steady and reliable operations, high utilization,
and leveraging expertise to capture synergies, the Company realized
average unadjusted operating costs of $22.90/bbl (US$17.52/bbl) of
SCO in Q3/18, an impressive result given the planned downtime at
Horizon in the quarter. After normalizing for planned turnaround
downtime, operating costs reached $19.95/bbl (US$15.26/bbl) of SCO
in Q3/18.
- At Horizon, during the planned turnaround, optimization and
reliability work on the VDU furnaces and coker train was completed
under budget and the units ramped up on schedule.
- The Company continues to evaluate the previously announced
potential expansion opportunities at Horizon to increase
reliability, lower costs and potentially add targeted production of
75,000 bbl/d to 95,000 bbl/d. The engineering and design
specification work is on track, targeting to be substantially
completed by year end.
- The Company's 2018 Oil Sands Mining and Upgrading capital
guidance is targeted to be $200 million less than previously
announced. The reduction in capital in 2018 is primarily due to
deferral of capital spend and achieved cost savings related to
strategic capital projects.
- The Company's 2018 Oil Sands Mining and Upgrading annual
production guidance remains unchanged and is targeted to
range between 415,000 bbl/d - 450,000 bbl/d of upgraded
products.
MARKETING
|
Three Months Ended |
|
|
Nine Months Ended |
|
|
|
|
|
|
|
|
|
|
|
|
|
Sep 30 2018 |
|
|
|
Jun 30 2018 |
|
|
|
Sep 30 2017 |
|
|
|
|
Sep 30 2018 |
|
|
|
Sep 30 2017 |
|
Crude oil and
NGLs pricing |
|
|
|
|
|
|
|
|
|
|
WTI benchmark price (US$/bbl) (1) |
$ |
69.50 |
|
|
$ |
67.90 |
|
|
$ |
48.19 |
|
|
|
$ |
66.79 |
|
|
$ |
49.43 |
|
WCS heavy differential as a percentage of WTI (%) (2) |
32 |
% |
|
28 |
% |
|
21 |
% |
|
|
33 |
% |
|
24 |
% |
SCO price (US$/bbl) |
$ |
68.44 |
|
|
$ |
67.27 |
|
|
$ |
48.83 |
|
|
|
$ |
65.75 |
|
|
$ |
50.03 |
|
Condensate benchmark pricing (US$/bbl) |
$ |
66.82 |
|
|
$ |
68.85 |
|
|
$ |
47.96 |
|
|
|
$ |
66.28 |
|
|
$ |
49.52 |
|
Average realized pricing before risk management (C$/bbl) (3) |
$ |
57.89 |
|
|
$ |
61.14 |
|
|
$ |
46.33 |
|
|
|
$ |
54.26 |
|
|
$ |
46.82 |
|
Natural gas
pricing |
|
|
|
|
|
|
|
|
|
|
AECO benchmark price (C$/GJ) |
$ |
1.28 |
|
|
$ |
0.97 |
|
|
$ |
1.94 |
|
|
|
$ |
1.33 |
|
|
$ |
2.45 |
|
Average realized pricing before risk management (C$/Mcf) |
$ |
2.32 |
|
|
$ |
1.95 |
|
|
$ |
2.29 |
|
|
|
$ |
2.34 |
|
|
$ |
2.83 |
|
- 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.
- In Q3/18, the WCS heavy differential widened as a result of a
shortage of export pipeline capacity out of the Western Canadian
Sedimentary Basin resulting in higher apportionment on the Enbridge
Mainline system.
- 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 Q3/18 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 increase
in natural gas prices for Q3/18 from Q2/18 levels reflected the
easing of third party pipeline constraints as well as seasonal
demand factors.
- 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 in November 2017 and commissioning continues for the start up
of bitumen processing in Q4/18.
- 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
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 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 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 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.
- Initial results from the Company's IPEP pilot have been
positive with excellent recovery rates and evidence of stackable
tailings. As a result, the Company will continue running the pilot
through the winter.
- 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 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 1,060,629 BOE/d in Q3/18, 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 72% of 2018 liquids production
guidance, including the AOSP, Horizon, Pelican Lake and thermal in
situ oil sands assets.
- In Q3/18, Canadian Natural delivered significant adjusted funds
flow in excess of net capital expenditures,of approximately $1,360
million, including deferred purchase consideration. In the first
nine months of 2018, adjusted funds flow in excess of net capital
expenditures was approximately $4,310 million, including deferred
purchase consideration.
- Balance sheet strength and strong financial performance were
demonstrated in Q3/18 through reduced long-term debt and upgraded
credit ratings.
- Overall Canadian Natural reduced long-term net debt by
approximately $1,780 million from Q2/18 levels and approximately
$3,170 million from Q3/17 levels.
- In Q3/18, Moody's Investors Service, Inc. upgraded the
Company's senior unsecured rating to Baa2 from Baa3 and its short
term rating to P-2 from P-3 with a stable outlook.
- In Q3/18, the Company utilized adjusted funds flow to repay and
cancel $1,050 million of the $2,850 million non-revolving term loan
facility; $1,800 million remains outstanding and fully drawn.
- Canadian Natural maintains strong financial stability and
liquidity represented by cash balances, and committed and
demand bank credit facilities. At September 30, 2018 the Company
had approximately $5,350 million of available liquidity, including
cash and cash equivalents, an increase of approximately $550
million from Q2/18.
- As at September 30, 2018, debt to book capitalization improved
to 36.8% from 39.6% in Q2/18 and debt to adjusted EBITDA
strengthened to 1.7x from 2.1x in Q2/18.
- Returns to shareholders remain a key focus for Canadian Natural
as the Company has returned approximately $2,030 million by way of
dividends of $1,156 million and share purchases of $874 million in
the first nine months of 2018.
- Share purchases for cancellation totaled 9,872,600 common
shares in the quarter at a weighted average share price of
$43.81.
- In the first nine months of 2018, share purchases totaled
20,012,727 common shares at a weighted average share price of
$43.66.
- Subsequent to quarter end and up to October 31, 2018, the
Company had additional share purchases of 6,900,000 common shares
for cancellation at a weighted average share price of $38.66.
- Based on the significant progress made to date in strengthening
the Company's balance sheet as well as the sustainability of
Canadian Natural's free cash flow, the Board of Directors has
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. At present, this policy is expected to be in place
until at least until the Company's NCIB renewal in May 2019,
subject to quarterly review by the Board of Directors. This policy
is effective November 1, 2018.
- 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 September 30, 2018, these financial
levers include the Company’s third party equity investments of
approximately $658 million.
- Subsequent to quarter end, Canadian Natural declared a
quarterly cash dividend on common shares of $0.335 per share
payable on January 1, 2019.
CORPORATE UPDATE
- One of Canadian Natural’s many strengths is the depth and
strength of our management team and our ability to develop people
and execute succession plans. Subject to Board of Directors
approval, it is anticipated that, effective March 31, 2019, the
following changes will take effect:
- Corey B. Bieber Senior Vice-President Finance and Chief
Financial Officer will become Executive Advisor, Finance. Corey
will remain on the Management Committee and continue to work
together with the Finance, Investor Relations, Information Systems,
Legal and International teams.
- In recognition of the fact that Canadian Natural has grown
significantly and the business environment has become more complex,
in addition to maintaining the office of the Chief Financial
Officer, Management believes it is appropriate to add the role of
Principal Accounting Officer. This will facilitate even stronger
leadership, depth of expertise and financial discipline.
- Mark Stainthorpe, Vice President – Capital Markets, will assume
the role of Chief Financial Officer and Senior Vice President,
Finance and will join the Management Committee. Mark has
accumulated over 16 years of experience at Canadian Natural with
progressive responsibilities in various accounting departments,
Treasury and Investor Relations. Mark will have overall
responsibility for the finance functions at Canadian Natural.
- Ron Kim, Vice President, Finance – Corporate will assume
the role of Principal Accounting Officer and Vice President,
Finance, reporting to Mark Stainthorpe. Ron joined Canadian Natural
in 2006 and has held various roles and progressive
responsibilities. Ron’s most recent responsibilities included
oversight of taxation, corporate accounting and financial
reporting. Ron will be responsible for overseeing accounting
policy, processes and financial reporting of the Company.
OUTLOOK
The Company forecasts annual 2018 production
levels to average between 802,000 and 868,000 bbl/d of crude oil
and NGLs and between 1,550 and 1,600 MMcf/d of natural gas, before
royalties. Q4/18 production guidance before royalties is forecast
to average between 801,000 and 849,000 bbl/d of crude oil and NGLs
and between 1,480 and 1,510 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 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") 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, development and deployment of technology and technological
innovations 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 the Company's 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
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 Currency, Production and Non-GAAP
Financial Measures
The Company's MD&A should be read in
conjunction with the unaudited interim consolidated financial
statements for the three and nine months ended September 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 three
and nine months ended September 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 ("IASB"). 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; adjusted funds flow (previously referred
to as funds flow from operations); net capital expenditures;
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, cash flows from operating activities,
and cash flows from investing activities as determined in
accordance with IFRS, as an indication of the Company's
performance. The non-GAAP measure adjusted net earnings from
operations is 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 adjusted funds flow is
reconciled to cash flows from operating activities, as determined
in accordance with IFRS, in the "Financial Highlights" section of
the Company's MD&A. The non-GAAP measure net capital
expenditures is reconciled to cash flows from investing activities,
as determined in accordance with IFRS, in the “Net capital
expenditures” section of the Company's MD&A. 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, November 1,
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, November 15, 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 5558647.
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:
403-514-7777 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
|
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