Commenting on the Company's results, Steve Laut, Executive Vice
Chairman of Canadian Natural stated, "In 2017, Canadian Natural
continued to execute on its defined strategy and completed its
transition to a long life low decline asset base with the
completion and ramp-up of the Horizon Phase 3 expansion. The
Company's focus on balanced capital allocation was evident in 2017
as economic resource development, increased balance sheet strength,
execution on transformational acquisitions and free cash flow
generation combined with our ability to execute with excellence,
drove a strong year for the Company."
Canadian Natural's President, Tim McKay, added,
"Strong production of Synthetic Crude Oil ("SCO") is targeted from
our Oil Sands Mining and Upgrading operations with the midpoint of
guidance at 450,000 bbl/d of SCO in the first quarter of 2018. With
the completion of Phase 3 at Horizon, production has been strong
averaging over 247,000 bbl/d of SCO since December 1, 2017 and
operations at our Athabasca Oil Sands Project ("AOSP") continue to
perform as expected with integration continuing during the
Company's nine months of mine operations. The Company's Oil Sands
Mining and Upgrading segment, conventional light oil in Canada and
our international assets now make up over 50% of our corporate
liquids production mix, a significant increase from approximately
32% in 2016. These products provide significant value to the
Company as they are priced in close relation to the high value West
Texas Intermediate ("WTI") crude oil commodity price.
Our focus on effective and efficient operations
resulted in strong operating costs in 2017. Operating costs were
within or on the lower end of corporate guidance ranges.
Specifically, Horizon operating costs averaged $21.46/bbl of SCO in
2017, after adjusting for planned downtime, excellent results, with
the Company looking to capture additional saving opportunities in
2018.
In 2017, Canadian Natural continued its strong
track record of delivering excellent finding and development and
acquisition costs and reserve replacement ratios, reflecting the
strength of our assets and our ability to execute effectively and
efficiently. Our reserve additions in the year were strong with
gross proved crude oil, SCO, bitumen and NGL reserves increasing
59% to 7.74 billion barrels and proved natural gas reserves
increasing 2% to 6.77 trillion cubic feet. Total proved plus
probable BOE reserve life index of the Company is now 33.0 years,
with low finding, development and acquisition costs of $12.29/BOE
for proved reserves, including the change in future development
capital. Additionally, our execution delivered strong reserve
replacement ratios of 887% on proved developed producing reserves
and 927% on total proved reserves, driven by our low sustaining
capital requirement, resulting in significant free cash flow that
provides sustainability through any commodity price cycle."
Canadian Natural's Chief Financial Officer,
Corey Bieber, continued, "The financial strength of the Company was
displayed in 2017 as we were able to opportunistically acquire
accretive assets and bring the Horizon project to completion,
making the Company much more robust and sustainable. As a result,
annual funds flow and net earnings were significant at
approximately $7.3 billion and $2.4 billion respectively, all
achieved with an annual average WTI crude oil price under
US$51.00/bbl. The resulting free cash flow allowed the Company to
increase liquidity to $4.25 billion and reduce debt to annual
adjusted EBITDA to 2.7x at year end.
In Q4/17 funds flow reached approximately $2.3
billion, resulting in a Q4/17 ending debt reduction of
approximately $460 million, when compared to Q3/17 levels,
supporting our near term focus to strengthen our balance sheet.
Additionally, as of the April 1, 2018 dividend payment, the
Company's Board of Directors has increased our quarterly dividend
by 22% to $0.335 per share, reflecting the strength and robustness
of our assets and our ability to generate free cash flow. The
increase marks the 18th consecutive year of dividend increases, and
confirms our commitment to sustainable and increasing returns to
shareholders.”
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Year Ended |
|
|
|
|
|
|
|
|
|
|
|
|
($ millions, except per common share amounts) |
|
Dec 31 2017 |
|
|
Sept 302017 |
|
|
Dec 312016 |
|
|
|
Dec 31 2017 |
|
|
Dec 312016 |
|
Net
earnings (loss) |
|
$ |
396 |
|
|
$ |
684 |
|
|
$ |
566 |
|
|
|
$ |
2,397 |
|
|
$ |
(204 |
) |
Per
common share |
– basic |
|
$ |
0.32 |
|
|
$ |
0.56 |
|
|
$ |
0.51 |
|
|
|
$ |
2.04 |
|
|
$ |
(0.19 |
) |
|
– diluted |
|
$ |
0.32 |
|
|
$ |
0.56 |
|
|
$ |
0.51 |
|
|
|
$ |
2.03 |
|
|
$ |
(0.19 |
) |
Adjusted
net earnings (loss) from operations (1) |
|
$ |
565 |
|
|
$ |
229 |
|
|
$ |
439 |
|
|
|
$ |
1,403 |
|
|
$ |
(669 |
) |
Per
common share |
– basic |
|
$ |
0.46 |
|
|
$ |
0.19 |
|
|
$ |
0.40 |
|
|
|
$ |
1.19 |
|
|
$ |
(0.61 |
) |
|
– diluted |
|
$ |
0.46 |
|
|
$ |
0.19 |
|
|
$ |
0.40 |
|
|
|
$ |
1.19 |
|
|
$ |
(0.61 |
) |
Funds flow
from operations (2) |
|
$ |
2,307 |
|
|
$ |
1,675 |
|
|
$ |
1,677 |
|
|
|
$ |
7,347 |
|
|
$ |
4,293 |
|
Per
common share |
– basic |
|
$ |
1.89 |
|
|
$ |
1.38 |
|
|
$ |
1.52 |
|
|
|
$ |
6.25 |
|
|
$ |
3.90 |
|
|
– diluted |
|
$ |
1.88 |
|
|
$ |
1.37 |
|
|
$ |
1.50 |
|
|
|
$ |
6.21 |
|
|
$ |
3.89 |
|
Capital
expenditures, excluding AOSP acquisition costs (3) |
|
$ |
1,143 |
|
|
$ |
2,094 |
|
|
$ |
411 |
|
|
|
$ |
4,972 |
|
|
$ |
3,794 |
|
Total net capital expenditures (3) |
|
$ |
1,143 |
|
|
$ |
2,094 |
|
|
$ |
411 |
|
|
|
$ |
17,129 |
|
|
$ |
3,794 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Daily production, before royalties |
|
|
|
|
|
|
|
|
|
|
|
Natural gas (MMcf/d) |
|
1,656 |
|
|
1,664 |
|
|
1,646 |
|
|
|
1,662 |
|
|
1,691 |
|
Crude oil and NGLs (bbl/d) |
|
744,100 |
|
|
759,189 |
|
|
585,185 |
|
|
|
685,236 |
|
|
523,873 |
|
Equivalent production (BOE/d) (4) |
|
1,020,094 |
|
|
1,036,499 |
|
|
859,577 |
|
|
|
962,264 |
|
|
805,782 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
Adjusted net earnings (loss) 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 (formally cash 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. |
|
Annual Highlights
- Net earnings of $2,397 million were realized in 2017, resulting
in adjusted net earnings of $1,403 million, representing an
increase of $2,072 million in adjusted net earnings compared to
2016 levels.
- Funds flow generation increased significantly in 2017 with
annual funds flow from operations of $7,347 million, an increase of
71% or $3,054 million compared to 2016 levels of $4,293
million.
- Record annual production volumes of 962,264 BOE/d were achieved
in 2017, representing an increase of 19% from 2016 levels. The
increase was a result of the Company's liquids segment, with annual
crude oil and NGL production volumes reaching 685,236 bbl/d, an
increase of 31% from 2016 levels.
- Canadian Natural's balance of products has improved
significantly with current production mix on a BOE/d basis of 50%
light crude oil blends, 25% heavy crude oil blends and 25% natural
gas, based upon the mid-point of annual 2018 production guidance, a
significant change from 2016 when our production mix was
approximately 32% light crude oil blends, 33% heavy crude oil
blends and 35% natural gas.
- In 2017, the Company achieved annual natural gas production
volumes of 1,662 MMcf/d, consistent with 2016 levels. Natural gas
volumes were maintained as the Company made strategic, return based
capital allocation decisions to maintain the Company's natural gas
business.
- Canadian Natural is committed to reducing its environmental
footprint by leveraging technology, adopting innovation and
maintaining effective and efficient operations. The Company has
made significant gains in our environmental performance:
- Canadian Natural's greenhouse gas ("GHG") emissions intensity
decreased 16% from 2012 to 2016. Additionally methane emissions
from our Alberta heavy crude oil operations decreased 71% over the
same period.
- The Company has developed a pathway utilizing technology
advancements to reduce its oil sands GHG emissions intensity to be
equivalent with light crude oil in North America.
- Over 1.5 million tonnes of CO2 captured and sequestered at the
Company's Oil Sands Mining and Upgrading operations in 2017.
- When the North West Redwater Refinery is fully on-stream,
Canadian Natural targets to capture and sequester 2.7 million
tonnes of CO2 annually, the 4th largest of all industries
globally.
- The Company has a strong commitment to effective and efficient
water management with over 90% of water used in our Oil Sands
Mining and Upgrading operations being recycled water.
- Canadian Natural has invested over $500 million in Research and
Development in each of the last two years. In 2016 Canadian Natural
was the 4th largest Research and Development investor of all
industries in Canada.
- Environmental and safety performance are key metrics in our
compensation program, along with key operational metrics and
financial metrics such as total shareholder return, return on
capital, return on equity and debt metrics such as debt to EBITDA
and debt to book capitalization.
- At the Company's world class Oil Sands Mining and Upgrading
assets, the Athabasca Oil Sands Project ("AOSP") and Horizon Oil
Sands ("Horizon"), operations were strong in 2017, with annual and
Q4/17 production reaching 282,026 bbl/d and 321,496 bbl/d
respectively, of Synthetic Crude Oil ("SCO").
- During 2017, at Horizon, the Company successfully completed the
Phase 3 expansion, the final component of the Company's transition
to a long life low decline asset base. The completion of the
Horizon Phase 3 expansion has increased the output of fully
upgraded 34 degree API light sweet SCO, with December production
averaging 247,226 bbl/d of SCO. The resulting impact to operating
costs was significant, with December operating costs below
$20.00/bbl of SCO.
- Horizon, achieved record annual production of 170,089 bbl/d of
SCO in 2017, a 38% increase over 2016 levels, as a result of a full
year of Phase 2B production and the completion and tie-in of the
Horizon Phase 3 expansion.
- Operational performance has been strong after the ramp-up of
the Horizon Phase 3 expansion as production averaged over
247,000 bbl/d of SCO since December 1, 2017.
- Through safe, steady and reliable operations and a strong focus
on continuous improvement, after adjusting for planned downtime in
2017, the Company realized record low annual average operating
costs of $21.46/bbl of SCO at Horizon, a 15% reduction from 2016
levels. Including turnaround time, operating costs were $24.98/bbl
of SCO, a 13% reduction from 2016 levels.
- In 2017, Horizon project capital expenditures totaled $821
million, $89 million below the Company's 2017 corporate
guidance.
- At the AOSP, the Company operated the Albian mines for 7 months
in 2017 and achieved strong reliability and utilization. As a
result, the Company added 111,937 bbl/d and 180,221 bbl/d of AOSP
SCO in 2017 and Q4/17 respectively, net to Canadian Natural, both
above the midpoint of previously issued guidance. A combination of
strong production and modest integration gains resulted in
operating costs of $26.34/bbl for upgraded products, below the
Company's 2017 operating cost guidance of $27.00/bbl to
$31.00/bbl.
- The transition to a long life low decline asset base is
complete following the Horizon Phase 3 expansion. Canadian
Natural’s production is resilient as long life low decline assets
make up approximately 73% of 2018 liquids production guidance,
including AOSP, Horizon, Pelican Lake and Thermal in situ oil sands
assets.
- The Company’s 2017 drilling program consisted of 523 net wells,
excluding strat/service wells, a 333 net well increase over its
2016 drilling program. The Company continues to be prudent with its
capital allocation in a volatile commodity price environment,
maintaining significant capital flexibility in its 2018 budget that
is targeting 608 net producing wells over the year.
- Thermal in situ oil sands (“thermal in situ”) annual production
volumes reached 120,140 bbl/d, at the top end of 2017 guidance,
representing an 8% increase from 2016 levels.
- At Primrose, production was strong in 2017 with volumes
reaching 81,501 bbl/d, an increase of 11% from 2016 levels.
Operating costs in 2017 were $12.33/bbl, including energy costs,
slightly below 2016 costs.
- At Kirby South the Company's Steam Assisted Gravity Drainage
(“SAGD”) project, annual production volumes of 36,107 bbl/d were
achieved, a 4% decrease from 2016 levels, as the Company
successfully completed planned turnaround activities in the year.
- Including energy costs, Kirby South achieved annual operating
costs of $9.50/bbl, in-line with 2016 levels.
- Pelican Lake operations were strong with annual production of
51,743 bbl/d, an increase of 9% from 2016 levels. The increase was
a result of the Company's successful integration of the acquired
assets in Q4/17 and a modest drilling program. The acquired assets
are now fully integrated and the Company has begun to re-initiate
polymer flood conversions across portions of the acquired lands.
The conversions will continue throughout 2018 adding to Canadian
Natural's long life low decline asset mix.
- Record low annual operating costs of $6.42/bbl were achieved in
2017, a 3% reduction from 2016 levels.
- Primary heavy crude oil production decreased as expected to
95,530 bbl/d in 2017, following the Company's proactive decision to
reduce its primary heavy crude oil drilling program from peak
levels in 2014. Canadian Natural is an industry leading primary
heavy crude oil producer and continues to focus on optimization of
its assets.
- Operating costs of $15.71/bbl were realized in 2017 in primary
heavy crude oil.
- North America light crude oil and NGL production increased 5%
to 92,036 bbl/d in 2017 from 2016 levels, due to a modest drilling
program and minor property acquisitions. As a result, the Company's
conventional light crude oil and NGL production was approximately
equivalent to the Company's primary heavy crude oil production.
- Operating costs of $14.30/bbl were realized in 2017, in North
America light crude oil and NGL.
- North America natural gas production was 1,601 MMcf/d in 2017,
in-line with 2016 levels, after continued impacts of poor
reliability at a third party facility and the strategic decision to
maintain natural gas production.
- Operating costs in North America natural gas were within
guidance at $1.19/Mcf in 2017.
- International Exploration & Production (“E&P”) annual
production volumes were within production guidance and averaged
43,761 bbl/d.
- North Sea volumes of 23,426 bbl/d were realized in 2017,
consistent with 2016 levels, due to a modest drilling program in
the year partially offseting declines. Additionally, the Company's
continued focus on production enhancements, increased reliability
and water flood optimization in the North Sea resulted in annual
operating costs decreasing by 14% to $36.60/bbl, from 2016
levels.
- Offshore Africa’s production decreased by 22%, as expected to
20,335 bbl/d from 2016 levels, due to normal declines and planned
turnarounds in 2017. Operating costs in Côte d'Ivoire were strong
in 2017 at $12.41/bbl, within corporate guidance.
- Canadian Natural maintains significant financial stability and
liquidity represented in part by committed bank credit facilities.
As at December 31, 2017, the Company had $4.25 billion of available
liquidity, including cash and cash equivalents, an increase of
$1.21 billion from December 31, 2016. Year end 2017 debt to book
capitalization was 41% and debt to adjusted EBITDA strengthened to
2.7x.
- The Company remained focused on returns to shareholders in 2017
increasing dividends by approximately 17% to $1.10 per share.
Subsequent to year end the Company increased its quarterly dividend
by 22% to $0.335 per share payable on April 1, 2018. The increase
marks the 18th consecutive year that Canadian Natural has increased
its dividend, reflecting the Board of Director's confidence in the
Company's sustainability and robustness of the asset base driving
its ability to generate significant funds flow.
- Effective March 1, 2018, the Company promoted Tim McKay to
President and Mr. McKay has been appointed to the Company's Board
of Directors. Additionally, Steve Laut has assumed the role of
Executive Vice Chairman. The Company takes a very proactive and
disciplined approach to succession, with well-planned and very
successful transitions, ensuring we maintain our strong corporate
culture and top tier performance.
2017 Reserves Update
- Canadian Natural’s crude oil, SCO, bitumen, natural gas and NGL
reserves were evaluated and reviewed by Independent Qualified
Reserves Evaluators. The following highlights are based on the
Company’s reserves using forecast prices and costs as at December
31, 2017 (all reserve values are Company Gross unless stated
otherwise).
- Proved crude oil, SCO, bitumen and NGL reserves increased 59%
to 7.74 billion barrels. Proved natural gas reserves
increased 2% to 6.77 Tcf. Total proved reserves increased 49%
to 8.87 billion BOE. The increase is largely driven by the
Company’s acquisition of AOSP.
- Proved developed producing reserve additions and revisions are
3.024 billion barrels of crude oil, SCO, bitumen and NGL and 536
billion cubic feet of natural gas. The total proved developed
producing reserves replacement ratio is 887%.
- Proved reserve additions and revisions are 3.126 billion
barrels of crude oil, SCO, bitumen and NGL and 761 billion cubic
feet of natural gas. The total proved BOE reserve replacement
ratio is 927%. The total proved BOE reserve life index is 24.6
years.
- Proved plus probable crude oil, SCO, bitumen and NGL reserves
increased 34% to 10.26 billion barrels. Proved plus probable
natural gas reserves increased 6% to 9.62 Tcf. Total proved
plus probable reserves increased 29% to 11.87 billion BOE.
- Proved plus probable reserve additions and revisions are 2.846
billion barrels of crude oil, bitumen, SCO and NGL and 1.15
trillion cubic feet of natural gas. The total proved plus probable
BOE reserve replacement ratio is 866%. The total proved plus
probable BOE reserve life index is 33.0 years.
- Proved finding, development and acquisition (FD&A) cost,
excluding changes in future development capital (FDC), is strong at
$5.15/BOE. Proved plus probable FD&A is $5.52/BOE.
- Proved net present value of future net revenues, before income
tax, discounted at 10%, is $89.8 billion, a 30% increase from the
year end 2016 evaluation. Proved plus probable net present
value is $114.5 billion, a 24% increase from year end 2016.
Fourth Quarter Highlights
- Net earnings of $396 million and adjusted net earnings of $565
million were realized in Q4/17. Canadian Natural generated
significant funds flow from operations of $2,307 million in Q4/17,
increases of $632 million and $630 million over Q3/17 and Q4/16
levels, respectively.
- The Company's corporate production volumes averaged a record
1,020,094 BOE/d in Q4/17, in-line with Q3/17 levels and a 19%
increase from Q4/16 levels.
- Canadian Natural’s corporate crude oil and NGL production
volumes averaged 744,100 bbl/d, a decrease of 2% from Q3/17 due to
Horizon planned downtime for turnaround and tie-in activities.
Crude oil and NGL production volumes increased from Q4/16 by 27%
primarily as a result of high reliability and strong production
from the Horizon Phase 2B and Phase 3 expansions and a full quarter
of production from the AOSP.
- At the Company's world class Oil Sands Mining and Upgrading
assets, the AOSP and Horizon, operations were strong in Q4/17 with
quarterly production reaching 321,496 bbl/d of SCO.
- At Horizon, the Phase 3 expansion was completed in Q4/17,
marking the completion of the Company's transition to a long life
low decline asset base.
- Q4/17 production of 141,275 bbl/d of SCO was realized as the
Company completed turnaround and tie-in activities for the Horizon
Phase 3 expansion. As a result of the majority of the planned
downtime coming in Q4/17, production in the quarter decreased from
Q3/17 levels by 10%. The ramp-up of the Phase 3 expansion performed
better than originally targeted, with December 2017 production
averaging approximately 247,226 bbl/d of SCO, approximately 7,200
bbl/d of SCO greater than originally targeted.
- Through safe, steady and reliable operations and a strong focus
on continuous improvement, the Company realized average unadjusted
operating costs of $32.29/bbl in Q4/17, a strong result given 33
days of planned downtime in the quarter as part of the 52 day
turnaround and tie-in related to the Phase 3 expansion. After
normalizing for planned downtime, quarterly operating costs were
strong at $21.13/bbl of SCO in Q4/17.
- At the AOSP in Q4/17, the Company's second full quarter of
operations, production was 180,221 bbl/d of AOSP SCO, net to
Canadian Natural, strong results given planned pitstops at the
Jackpine and Muskeg River mines in the quarter. Including the
impact of planned pit stops, operating costs of $27.95/bbl were
achieved, an increase of 14% from Q3/17 levels.
- Thermal in situ operations were strong in Q4/17, with
production averaging 124,121 bbl/d, in-line with Q3/17 and a 4%
decrease from Q4/16 levels.
- Primrose production was strong in Q4/17 averaging 84,834 bbl/d,
an increase of 5% from Q3/17. Including energy costs, operating
costs of $11.16/bbl were achieved in the quarter.
- Kirby South, the Company's SAGD project achieved production of
35,320 bbl/d in Q4/17.
- Including energy costs, strong operating costs of $9.74/bbl
were achieved in the quarter. Kirby South's Steam to Oil Ratio
("SOR") was 2.9 in Q4/17, as the Company began steam circulation of
new well pairs drilled in Q4/17. Normalized to exclude wells in
circulation, the SOR was 2.7 in Q4/17.
- Pelican Lake heavy crude oil production of 65,654 bbl/d in
Q4/17 increased by 38% from both Q3/17 and Q4/16 levels, as a
result of a full quarter of production of the fully integrated,
recently acquired assets. Operations continued to be optimized in
the quarter, resulting in favorable operating costs of $6.81/bbl in
Q4/17, increases of 14% and 4% from Q3/17 and Q4/16 levels
respectively, due to the integration of acquired assets.
- Primary heavy crude oil production averaged 99,326 bbl/d in
Q4/17, in-line with Q3/17, as a result of the Company's successful
drilling program.
- North America light crude oil and NGL quarterly production
averaged 94,437 bbl/d, representing 2% and 8% increases from Q3/17
and Q4/16 levels respectively, as a result of a successful drilling
program.
- The Company's North America natural gas production in Q4/17
averaged 1,596 MMcf/d, in-line with Q3/17 and Q4/16 levels.
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 Horizon mining and upgrading and the AOSP
mining and upgrading, thermal in situ oil sands and Pelican Lake
heavy crude oil assets. The combination of low decline, low
reserve replacement costs, and effective and efficient operations
means these assets provide substantial and sustainable cash 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
|
|
|
Year Ended Dec 31 |
|
|
|
|
2017 |
2016 |
(number
of wells) |
Gross |
|
Net |
|
Gross |
|
Net |
|
Crude oil |
529 |
|
495 |
|
188 |
|
174 |
|
Natural gas |
27 |
|
21 |
|
11 |
|
9 |
|
Dry |
7 |
|
7 |
|
7 |
|
7 |
|
Subtotal |
563 |
|
523 |
|
206 |
|
190 |
|
Stratigraphic test / service wells |
289 |
|
289 |
|
268 |
|
268 |
|
Total |
852 |
|
812 |
|
474 |
|
458 |
|
Success rate (excluding stratigraphic test / service wells) |
|
99 |
% |
|
96 |
% |
|
|
|
|
|
|
|
- The Company's total crude oil and natural gas drilling program
was 523 net wells for the year ended December 31, 2017, excluding
strat/service wells, an increase of 333 net wells from the same
period in 2016. The change in drilling reflects the flexibility of
Canadian Natural's resource development program and the Company's
disciplined capital allocation process.
North America Exploration and Production
|
Crude oil
and NGLs – excluding Thermal In Situ Oil Sands |
|
Three Months Ended |
Year Ended |
|
|
|
|
|
|
|
Dec 31 2017 |
|
Sept 30 2017 |
|
Dec 31 2016 |
|
Dec 31 2017 |
|
Dec 31 2016 |
|
Crude oil and NGLs production (bbl/d) |
259,416 |
|
238,844 |
|
232,019 |
|
239,309 |
|
239,912 |
|
Net wells
targeting crude oil |
123 |
|
145 |
|
75 |
|
472 |
|
170 |
|
Net successful wells drilled |
120 |
|
144 |
|
72 |
|
466 |
|
163 |
|
Success rate |
98 |
% |
99 |
% |
96 |
% |
99 |
% |
96 |
% |
|
|
|
|
|
|
|
|
|
|
|
- Annual production volumes of North America crude oil and NGLs
averaged 239,309 bbl/d in 2017, in-line with 2016 levels and within
the Company's annual production guidance.
- Pelican Lake operations were strong with annual production of
51,743 bbl/d, an increase of 9% from 2016 levels. The increase was
as a result of the Company's successful integration of the acquired
assets in Q4/17 and a modest drilling program. The acquired assets
are now fully integrated and the Company has begun to re-initiate
polymer flood conversions across portions of the acquired lands.
The conversions will continue throughout 2018 adding to Canadian
Natural's long life low decline asset mix.
- Record low annual operating costs of $6.42/bbl were achieved in
2017, a 3% reduction from 2016 levels.
- Overall 56% of the Pelican Lake pool is under polymer flood on
an area basis. Canadian Natural is targeting to ultimately convert
approximately 70% of the pool to polymer flood.
- Primary heavy crude oil production decreased as expected to
95,530 bbl/d in 2017, following the Company's proactive decision to
reduce its primary heavy crude oil drilling program from peak
levels in 2014. Canadian Natural is the industry leading primary
heavy crude oil producer and continues to focus on optimization of
the assets.
- Operating costs of $15.71/bbl were realized in 2017.
- Drilling continued in primary heavy crude oil in 2017 with 415
net wells drilled, an increase of 255 wells from 2016 levels.
- North America light crude oil and NGL production increased 5%
to 92,036 bbl/d in 2017 from 2016 levels, due to a modest drilling
program and minor property acquisitions. As a result, our
conventional light crude oil and NGL production was approximately
equivalent to the Company's primary heavy crude oil production.
- Operating costs of $14.30/bbl were realized in 2017.
- 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 |
Year Ended |
|
|
|
|
|
|
|
Dec 31 2017 |
|
Sept 30 2017 |
|
Dec 31 2016 |
|
Dec 31 2017 |
|
Dec 31 2016 |
|
Bitumen production (bbl/d) |
124,121 |
|
122,372 |
|
129,329 |
|
120,140 |
|
111,046 |
|
Net wells
targeting bitumen |
5 |
|
10 |
|
8 |
|
27 |
|
9 |
|
Net successful wells drilled |
5 |
|
10 |
|
8 |
|
27 |
|
9 |
|
Success rate |
100 |
% |
100 |
% |
100 |
% |
100 |
% |
100 |
% |
|
|
|
|
|
|
|
|
|
|
|
- Thermal in situ annual production volumes reached 120,140
bbl/d, at the top end of 2017 guidance, representing an 8% increase
from 2016 levels.
- At Primrose, production was strong in 2017 with volumes
reaching 81,501 bbl/d, an increase of 11% from 2016 levels.
Operating costs were maintained in the year at $12.33/bbl,
including energy costs, slightly below 2016 costs.
- Additionally, strong results from the Company's low pressure
steamflood continue at Primrose. The 2017 annual production under
steamflood averaged 39,300 bbl/d, an increase from 2016 average
levels of approximately 10,900 bb/d.
- At Kirby South, the Company's SAGD project, the Company
achieved annual production volumes of 36,107 bbl/d, a 4% decrease
from 2016 levels, as a result of planned turnaround activities in
the year.
- Including energy costs, Kirby South achieved annual operating
costs of $9.50/bbl, in-line with 2016 levels. Annual SOR at Kirby
South was 2.8 in 2017.
- Kirby North, the Company's targeted 40,000 bbl/d SAGD project
with targeted first oil in Q1/20 continues to be trending slightly
ahead of schedule and cost performance is trending on budget. Civil
works and tank contracts at the plant site have been completed with
building and equipment modules set at the plant site. The
construction and drilling workforce is currently at 740 people,
including satellite module yards.
- 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.
|
Natural
Gas |
|
Three Months Ended |
Year Ended |
|
|
|
|
|
|
|
Dec 31 2017 |
|
Sept 30 2017 |
|
Dec 31 2016 |
|
Dec 31 2017 |
|
Dec 31 2016 |
|
Natural gas production (MMcf/d) |
1,596 |
|
1,593 |
|
1,578 |
|
1,601 |
|
1,622 |
|
Net wells
targeting natural gas |
2 |
|
3 |
|
4 |
|
22 |
|
9 |
|
Net successful wells drilled |
2 |
|
3 |
|
4 |
|
21 |
|
9 |
|
Success rate |
100 |
% |
100 |
% |
100 |
% |
95 |
% |
100 |
% |
|
|
|
|
|
|
|
|
|
|
|
- North America natural gas production was 1,601 MMcf/d in 2017,
in-line with 2016 levels, after continued impacts of poor
reliability at a third party facility and the strategic decision to
maintain natural gas production.
- Operating costs in North America natural gas were within
guidance at $1.19/Mcf in 2017.
- Production in Q4/17 was below corporate guidance primarily due
to a proactive decision to shut-in production volumes of
approximately 24 MMcf/d related to low natural gas prices and 39
MMcf/d related to the impact of reliability issues at a third party
facility.
- The Company uses approximately 32% of its total equivalent gas
production internally in its operations providing a natural hedge
from the challenging Western Canadian natural gas price
environment. Approximately 29% of the natural gas production is
exported to other North American markets or sold internationally,
with the remaining 39% of the Company's production being exposed to
AECO/Station 2 pricing.
- The Company’s 2018 total natural gas annual production guidance
remains unchanged and is targeted to range from 1,650 MMcf/d -
1,710 MMcf/d.
International Exploration and
Production
|
|
|
|
Three Months Ended |
Year Ended |
|
|
|
|
|
|
|
Dec 31 2017 |
|
Sept 30 2017 |
|
Dec 31 2016 |
|
Dec 31 2017 |
|
Dec 31 2016 |
|
Crude oil
production (bbl/d) |
|
|
|
|
|
North Sea |
19,548 |
|
24,832 |
|
24,085 |
|
23,426 |
|
23,554 |
|
Offshore Africa |
19,519 |
|
18,776 |
|
21,689 |
|
20,335 |
|
26,096 |
|
Natural gas
production (MMcf/d) |
|
|
|
|
|
North Sea |
37 |
|
46 |
|
44 |
|
39 |
|
38 |
|
Offshore Africa |
23 |
|
25 |
|
24 |
|
22 |
|
31 |
|
Net wells
targeting crude oil |
— |
|
— |
|
0.9 |
|
1.8 |
|
2.1 |
|
Net successful wells drilled |
— |
|
— |
|
0.9 |
|
1.8 |
|
2.1 |
|
Success rate |
— |
|
— |
|
100 |
% |
100 |
% |
100 |
% |
|
|
|
|
|
|
|
|
|
|
|
- International E&P annual production volumes were within
production guidance and reached 43,761 bbl/d.
- North Sea volumes of 23,426 bbl/d were realized in 2017,
consistent with 2016 levels, due to a modest drilling program in
the year helping to offset declines. Additionally, the Company's
continued focus on production enhancements, increased reliability
and water flood optimization in the North Sea resulted in annual
operating costs decreasing by 14% to $36.60/bbl, from 2016 levels.
- In 2018, the Company is targeting to drill 4.6 net producing
wells and 0.9 net injector wells in the North Sea, scheduled to
commence in Q1/18. The program targets to add average net
production of approximately 3,000 bbl/d in
Q4/18.
- Offshore Africa’s production decreased by 22%, as expected to
20,335 bbl/d from 2016 levels, after a successful infill drilling
program in early 2016 and no drilling in 2017. Operating costs in
Côte d'Ivoire were strong in 2017 at $12.41/bbl, within corporate
guidance.
- In 2018, the Company is targeting to drill 1.7 net producing
wells and 1.2 net injector wells at Baobab which are scheduled to
commence in Q2/18. The program targets to add average net
production of approximately 5,700 bbl/d in
Q4/18.
- 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 –
Horizon
|
|
|
|
Three Months Ended |
Year Ended |
|
|
|
|
|
|
|
Dec 31 2017 |
|
Sept 30 2017 |
|
Dec 31 2016 |
|
Dec 31 2017 |
|
Dec 31 2016 |
|
Synthetic crude oil production (bbl/d) (1) |
141,275 |
|
156,465 |
|
178,063 |
|
170,089 |
|
123,265 |
|
|
|
|
|
|
|
|
|
|
|
|
(1) Q4/17
SCO production before royalties excludes 1,730 bbl/d of SCO
consumed internally as diesel (Q3/17 – 0 bbl/d; Q4/16 – 1,619
bbl/d; year ended December 31, 2017 – 651 bbl/d; year ended
December 31, 2016 – 1,966 bbl/d). |
|
- During 2017 at Horizon, the Company successfully completed the
Phase 3 expansion, the final component of the Company's transition
to a long life low decline asset base. The completion of the
Horizon Phase 3 expansion has increased the output of fully
upgraded 34 degree API light sweet SCO, with December production
averaging 247,226 bbl/d of SCO. The resulting impact to operating
costs was significant, with December operating costs below
$20.00/bbl of SCO.
- Horizon achieved record annual production of 170,089 bbl/d of
SCO in 2017, a 38% increase over 2016 levels, as a result of a full
year of Phase 2B production and the completion and tie-in of the
Horizon Phase 3 expansion.
- Operational performance has been strong after the ramp-up of
the Horizon Phase 3 expansion as production has averaged over
247,000 bbl/d of SCO since December 1, 2017.
- Through safe, steady and reliable operations and a strong focus
on continuous improvement, after adjusting for planned downtime in
2017, the Company realized record low annual average operating
costs of $21.46/bbl of SCO at Horizon, a 15% reduction from 2016
levels. Including planned downtime, operating costs were $24.98/bbl
of SCO, a 13% reduction from 2016 levels.
- In 2017, Horizon project capital expenditures totaled $821
million, $89 million below the Company's 2017 corporate
guidance.
- The engineering and design work is proceeding as planned on the
potential Paraffinic and VGO expansions at Horizon and will
continue throughout 2018.
- Ongoing work is proceeding to define if incremental capacity is
attainable at Horizon and is targeted to be identified in
Q2/18.
- Directive 85 (formerly Directive 74) implementation at Horizon
remains on track and was 74% physically complete as at December 31,
2017. This project includes research into tailings management and
investments in technological advancements for the cessation of the
use of traditional tailings ponds.
North America Oil Sands Mining and Upgrading –
AOSP
|
|
|
|
Three Months Ended |
Year Ended |
|
|
|
|
|
|
|
Dec 31 2017 |
|
Sept 30 2017 |
|
Dec 31 2016 |
|
Dec 31 2017 |
|
Dec 31 2016 |
|
Synthetic crude oil production (bbl/d) (1) |
180,221 |
|
197,900 |
|
— |
|
111,937 |
|
— |
|
|
|
|
|
|
|
|
|
|
|
|
(1)
Consists of heavy and light synthetic crude oil products. |
|
|
|
|
|
|
|
|
|
|
|
- At the AOSP, the Company operated the Albian mines for 7 months
in 2017 and strong reliability and utilization were achieved. As a
result the Company added 111,937 bbl/d of AOSP SCO, net to Canadian
Natural in 2017, above the midpoint of previously issued guidance.
A combination of strong production and modest integration gains
resulted in operating costs of $26.34/bbl for upgraded products,
below the Company's 2017 operating cost guidance of $27.00/bbl to
$31.00/bbl.
- In early Q4/17, Canadian Natural successfully completed planned
pit stops at both the Jackpine and Muskeg River mines.
- The Company will continue to operate in the most effective and
efficient manner and will continue to be diligent in order to
identify additional synergies.
- The Company's 2018 Oil Sands Mining and Upgrading annual
production guidance remains unchanged and is targeted to range from
415,000 bbl/d - 450,000 bbl/d of upgraded products.
MARKETING
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Year Ended |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dec 31 2017 |
|
|
|
Sept 30 2017 |
|
|
|
Dec 31 2016 |
|
|
|
|
Dec 31 2017 |
|
|
|
Dec 31 2016 |
|
Crude oil and NGLs
pricing |
|
|
|
|
|
|
|
|
|
|
|
WTI
benchmark price (US$/bbl) (1) |
|
$ |
55.39 |
|
|
$ |
48.19 |
|
|
$ |
49.33 |
|
|
|
$ |
50.93 |
|
|
$ |
43.37 |
|
WCS blend
differential from WTI (%) (2) |
|
22 |
% |
|
21 |
% |
|
30 |
% |
|
|
23 |
% |
|
32 |
% |
SCO price
(US$/bbl) |
|
$ |
58.64 |
|
|
$ |
48.83 |
|
|
$ |
48.91 |
|
|
|
$ |
52.20 |
|
|
$ |
43.94 |
|
Condensate benchmark pricing (US$/bbl) |
|
$ |
57.96 |
|
|
$ |
47.96 |
|
|
$ |
48.37 |
|
|
|
$ |
51.65 |
|
|
$ |
42.51 |
|
Average
realized pricing before risk management (C$/bbl) (3) |
|
$ |
53.42 |
|
|
$ |
46.33 |
|
|
$ |
45.00 |
|
|
|
$ |
48.57 |
|
|
$ |
36.93 |
|
Natural gas
pricing |
|
|
|
|
|
|
|
|
|
|
|
AECO
benchmark price (C$/GJ) |
|
$ |
1.85 |
|
|
$ |
1.94 |
|
|
$ |
2.67 |
|
|
|
$ |
2.30 |
|
|
$ |
1.98 |
|
Average realized pricing before risk management (C$/Mcf) |
|
$ |
2.55 |
|
|
$ |
2.29 |
|
|
$ |
3.14 |
|
|
|
$ |
2.76 |
|
|
$ |
2.32 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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. |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
- WTI averaged US$50.93/bbl in 2017, an increase of 17% from
US$43.37/bbl in 2016. WTI averaged US$55.39/bbl for Q4/17, an
increase of 12% from US$49.33/bbl in Q4/16, and an increase of 15%
from US$48.19/bbl for Q3/17. WTI pricing for Q4/17 and annual 2017
has increased from the comparable periods due to declines in global
crude oil inventories as a result of OPEC’s adherence to previously
announced production cuts, together with larger than anticipated
increases in global demand for crude oil. Going forward, the
Company expects WTI pricing to continue to reflect volatility in
supply and demand factors and geopolitical events.
- The WCS Heavy Differential averaged US$11.97/bbl in 2017 from
US$13.91/bbl in 2016, representing a 14% decrease. The WCS Heavy
Differential averaged US$12.28/bbl for Q4/17 , a decrease of 16%
from US$14.59/bbl for Q4/16 , and an increase of 24% from
US$9.94/bbl for Q3/17. The WCS Heavy Differential reflects US Gulf
Coast pricing, adjusted for transportation costs. Subsequent to
quarter end, the WCS Heavy Differential widened due to third party
pipeline outages and timing of access to rail for industry to move
the incremental barrels.
- Canadian Natural contributed approximately 190,000 bbl/d of its
heavy crude oil stream to the WCS blend in Q4/17. The Company
remains the largest contributor to the WCS blend, accounting for
48% of the total blend.
- The SCO price averaged US$52.20/bbl in 2017, an increase of 19%
from US$43.94/bbl in 2016. The SCO price averaged US$58.64/bbl for
Q4/17, an increase of 20% from US$48.91/bbl in Q4/16, and an
increase of 20% from US$48.83/bbl for Q3/17. The increase in SCO
pricing for Q4/17 and 2017 from the comparable periods was
primarily due to changes in WTI benchmark.
- AECO natural gas prices averaged $2.30/GJ in 2017 from $1.98/GJ
in 2016, representing an increase of 16%. AECO natural gas prices
averaged $1.85/GJ for Q4/17, a decrease of 31% from $2.67/GJ in
Q4/16, and a decrease of 5% from $1.94/GJ in Q3/17. The increase in
natural gas prices in 2017 compared with 2016 primarily reflected
the rebalancing of natural gas storage inventory to historically
normal levels. The decrease in AECO natural gas prices in Q4/17
compared with Q4/16 and Q3/17 continued to reflect third party
pipeline constraints limiting flow of natural gas to discretionary
storage and export markets as well as increased natural gas
production in the basin.
- The North West Redwater refinery, upon completion, will
strengthen the Company’s position by providing a competitive return
on investment and by adding 50,000 bbl/d of bitumen conversion
capacity in Alberta and create demand for 79,000 bbl/d of dilbit
that will not require export pipelines, which will help reduce
pricing volatility in all Western Canadian heavy crude oil. The
Company has a 50% interest in the North West Redwater Partnership.
For project updates, please refer to:
https://nwrsturgeonrefinery.com/whats-happening/news/.
- The North West Redwater refinery began processing light crude
oil late in November 2017, and continues to progress with its
planned ramp-up schedule.
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 1,020,094 BOE/d in Q4/17, with approximately
98% of total production located in G7 countries.
- Canadian Natural's balance of products has improved
significantly with current product mix on a BOE/d basis of 50%
light crude oil blends, 25% heavy crude oil blends and 25% natural
gas, based upon the mid-point of annual 2018 production guidance, a
significant change from 2016 when our product mix was approximately
32% light crude oil blends, 33% heavy crude oil blends and 35%
natural gas.
- The transition to a long life low decline asset base is
complete following the Horizon Phase 3 expansion. Canadian
Natural’s production is resilient as long life low decline assets
makes up approximately 73% of 2018 liquids production guidance,
when including the AOSP, Horizon, Pelican Lake and Thermal in situ
oil sands assets.
- Canadian Natural maintains significant financial stability and
liquidity represented in part by committed bank credit facilities.
As at December 31, 2017, the Company had $4.25 billion of available
liquidity, including cash and cash equivalents, an increase of
$1.21 billion from December 31, 2016.
- Important metrics improved in Q4/17, with debt to book
capitalization at 41% and debt to adjusted EBITDA strengthening to
2.7x, as at December 31, 2017.
- Balance sheet strength continues to be a focus of the Company
and strong financial performance in the quarter resulted in a Q4/17
ending debt reducing approximately $460 million from Q3/17 levels,
while liquidity increased by approximately $300 million, over the
same period.
- Subsequent to December 31, 2017, the Company repaid US$600
million of 1.75% notes and US$400 million of 5.90% notes from funds
flow from operations.
- As at December 31, 2017, the Company's $3,000 million
non-revolving term loan facility which it entered into during Q2/17
to finance the acquisition of AOSP and other assets was fully
drawn. Subsequent to December 31, 2017, the Company repaid and
canceled $150 million of the outstanding facility from funds flow
from operations, leaving $2,850 million outstanding.
- Subsequent to December 31, 2017, the Company fully repaid and
canceled the $125 million non-revolving credit facility from funds
flow from operations.
- Subsequent to December 31, 2017, the Company extended the $750
million non-revolving credit facility originally due February 2019
to February 2021.
- 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 December 31, 2017, these financial levers include
the Company’s third party equity investments of approximately $893
million.
- The Company remained focused on returns to shareholders in 2017
increasing dividends by approximately 17% to $1.10 per share.
Subsequent to year end the Company increased its quarterly dividend
by 22% to $0.335 per share payable on April 1, 2018. The increase
marks the 18th consecutive year that Canadian Natural has increased
its dividend, reflecting the Board of Director's confidence in the
Company's sustainability and robustness of the asset base driving
the ability to generate significant funds flow.
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 1,650 and 1,710 MMcf/d of natural gas, before
royalties. Q1/18 production guidance before royalties is forecast
to average between 821,000 and 869,000 bbl/d of crude oil and NGLs
and between 1,600 and 1,650 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 $4.3 billion.
2017 YEAR-END RESERVES
Determination of Reserves
For the year ended December 31, 2017, the
Company retained Independent Qualified Reserves Evaluators (IQREs),
Sproule Associates Limited, Sproule International Limited and GLJ
Petroleum Consultants Limited, to evaluate and review all of the
Company’s proved and proved plus probable reserves. The IQREs
conducted the evaluation and review in accordance with the
standards contained in the Canadian Oil and Gas Evaluation
Handbook. The reserves disclosure is presented in accordance with
NI 51-101 requirements using forecast prices and escalated
costs.
The Reserves Committee of the Company’s Board of
Directors has met with and carried out independent due diligence
procedures with the IQREs as to the Company’s reserves. All
reserves values are Company Gross unless stated otherwise.
Corporate Total
- Canadian Natural’s 2017 performance has resulted in another
year of excellent finding and development costs:
- Finding, Development and Acquisition ("FD&A") costs,
excluding the change in Future Development Capital ("FDC"), are
$5.15/BOE for proved reserves and $5.52/BOE for proved plus
probable reserves.
- FD&A costs, including the change in FDC, are $12.29/BOE for
proved reserves and $12.17/BOE for proved plus probable
reserves.
- Proved reserve additions and revisions replaced 2017 production
by 927%. Proved plus probable reserve additions and revisions
replaced 2017 production by 866%.
- Proved reserves increased 49% to 8.871 billion BOE with reserve
additions and revisions of 3.253 billion BOE. Proved plus probable
reserves increased 29% to 11.866 billion BOE with reserve additions
and revisions of 3.038 billion BOE.
- The proved BOE reserve life index is 24.6 years and the proved
plus probable BOE reserve life index is 33.0 years.
- Recycle ratios are 4.5 times and 4.2 times for proved and
proved plus probable reserves respectively, excluding the change in
FDC. Including the change in FDC, recycle ratios are 1.9 times for
both proved and proved plus probable reserves.
- The net present value of future net revenues, before income
tax, discounted at 10%, increased 30% to $89.8 billion for proved
reserves and increased 24% to $114.5 billion for proved plus
probable reserves. The net present value for proved developed
producing reserves increased 46% to $68.1 billion reflecting the
completion of Horizon Phase 3 and the acquisition of AOSP.
North America Exploration and
Production
- Canadian Natural’s North America conventional and thermal
assets delivered strong reserves results in 2017:
- FD&A costs, excluding the change in FDC, are $6.81/BOE for
proved reserves and $5.57/BOE for proved plus probable
reserves.
- FD&A costs, including the change in FDC, are $11.31/BOE for
proved reserves and $9.96/BOE for proved plus probable
reserves.
- Proved reserve additions and revisions replaced 196% of 2017
production. Proved plus probable reserve additions and revisions
replaced 240% of 2017 production.
- Proved reserves increased 7% to 3.397 billion BOE. This is
comprised of 2.275 billion bbl of crude oil, bitumen, and NGL
reserves and 6.730 Tcf of natural gas reserves.
- Proved plus probable reserves increased 6% to 5.482 billion
BOE. This is comprised of 3.895 billion bbl of crude oil, bitumen,
and NGL reserves and 9.520 Tcf of natural gas reserves.
- Proved reserves additions and revisions are 320 million bbl of
crude oil, bitumen and NGL and 770 Bcf of natural gas. Proved plus
probable reserve additions and revisions are 349 million bbl of
crude oil, bitumen and NGL and 1,194 Bcf of natural gas.
- The proved BOE reserve life index is 16.2 years and the proved
plus probable BOE reserve life index is 26.2 years.
North America Oil Sands Mining and
Upgrading
- Canadian Natural’s Horizon and AOSP oil sands mining and
upgrading delivered strong reserves results in 2017:
- FD&A costs, excluding the change in FDC, are $4.78/bbl for
proved reserves and $5.24/bbl for proved plus probable
reserves.
- FD&A costs, including the change in FDC, are $12.58/bbl for
proved reserves and $12.78/bbl for proved plus probable
reserves.
- Proved Synthetic Crude Oil ("SCO") reserves increased 106% to
5.264 billion bbl. Proved plus probable SCO reserves increased 68%
to 6.063 billion bbl.
- SCO proved developed producing reserves increased 107% to 5.264
billion bbl reflecting the completion of Phase 3 at Horizon and the
acquisition of AOSP.
- SCO reserves account for 59% of the Company’s proved BOE
reserves and 51% of the proved plus probable BOE reserves.
International Exploration and
Production
- North Sea proved reserves decreased 12% to 124 million BOE and
proved plus probable reserves decreased 31% to 185 million
BOE.
- Offshore Africa proved reserves decreased 7% to 86 million BOE
and proved plus probable reserves decreased 7% to 136 million
BOE.
2017 FD&A Costs excluding change in
FDC
|
|
|
|
|
Proved($/BOE) |
|
Proved PlusProbable($/BOE) |
North America
E&P |
$ |
6.81 |
|
$ |
5.57 |
Oil Sands Mining and
Upgrading |
$ |
4.78 |
|
$ |
5.24 |
Total
Canadian Natural |
$ |
5.15 |
|
$ |
5.52 |
|
|
|
|
|
|
2017 FD&A Costs including change in
FDC
|
|
|
|
|
Proved($/BOE) |
|
Proved PlusProbable($/BOE) |
North America
E&P |
$ |
11.31 |
|
$ |
9.96 |
Oil Sands Mining and
Upgrading |
$ |
12.58 |
|
$ |
12.78 |
Total
Canadian Natural |
$ |
12.29 |
|
$ |
12.17 |
|
|
|
|
|
|
Corporate Total
2017 Reserve Replacement
|
|
Reserves Category |
% of 2017 Production Replaced |
Proved developed
producing |
887% |
Proved |
927% |
Proved
plus probable |
866% |
|
|
Company Gross Reserves
|
|
|
|
Reserves Category |
2016(MMBOE) |
2017(MMBOE) |
Increase |
Proved developed
producing |
4,145 |
6,908 |
67% |
Proved |
5,969 |
8,871 |
49% |
Proved
plus probable |
9,179 |
11,866 |
29% |
|
|
|
|
|
2017 Recycle Ratios
|
|
Reserves Category |
Excluding change in FDC |
Proved |
4.5
x |
Proved
plus probable |
4.2 x |
|
|
|
|
Reserves Category |
Including change in FDC |
Proved |
1.9
x |
Proved
plus probable |
1.9 x |
|
|
Net Present Value of Future Net Revenues, before income
tax, discounted at 10%
|
|
|
|
|
Reserves Category |
2016($ billion) |
2017($ billion) |
Increase |
Proved developed
producing |
46.7 |
68.1 |
46% |
Proved |
69.3 |
89.8 |
30% |
Proved
plus probable |
92.3 |
114.5 |
24% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Summary of Company Gross
Reserves |
As of December 31, 2017
Forecast Prices and Costs |
|
|
|
|
|
|
|
|
|
|
Light and Medium Crude Oil (MMbbl) |
|
Primary Heavy Crude Oil (MMbbl) |
|
Pelican Lake Heavy Crude Oil (MMbbl) |
|
Bitumen (Thermal Oil) (MMbbl) |
|
Synthetic Crude Oil (MMbbl) |
|
Natural Gas (Bcf) |
|
Natural Gas Liquids (MMbbl) |
|
Barrels of Oil Equivalent (MMBOE) |
|
North America |
|
|
|
|
|
|
|
|
Proved |
|
|
|
|
|
|
|
|
Developed Producing |
114 |
|
108 |
|
266 |
|
322 |
|
5,264 |
|
4,029 |
|
102 |
|
6,848 |
|
Developed
Non-Producing |
11 |
|
15 |
|
— |
|
34 |
|
— |
|
347 |
|
8 |
|
126 |
|
Undeveloped |
46 |
|
75 |
|
61 |
|
994 |
|
— |
|
2,354 |
|
119 |
|
1,687 |
|
Total
Proved |
171 |
|
198 |
|
327 |
|
1,350 |
|
5,264 |
|
6,730 |
|
229 |
|
8,661 |
|
Probable |
68 |
|
74 |
|
142 |
|
1,230 |
|
799 |
|
2,790 |
|
106 |
|
2,884 |
|
Total Proved plus Probable |
239 |
|
272 |
|
469 |
|
2,580 |
|
6,063 |
|
9,520 |
|
335 |
|
11,545 |
|
|
|
|
|
|
|
|
|
|
North Sea |
|
|
|
|
|
|
|
|
Proved |
|
|
|
|
|
|
|
|
Developed Producing |
25 |
|
|
|
|
|
17 |
|
|
28 |
|
Developed Non-Producing |
4 |
|
|
|
|
|
— |
|
|
4 |
|
Undeveloped |
91 |
|
|
|
|
|
4 |
|
|
92 |
|
Total
Proved |
120 |
|
|
|
|
|
21 |
|
|
124 |
|
Probable |
60 |
|
|
|
|
|
11 |
|
|
61 |
|
Total Proved plus Probable |
180 |
|
|
|
|
|
32 |
|
|
185 |
|
|
|
|
|
|
|
|
|
|
Offshore Africa |
|
|
|
|
|
|
|
|
Proved |
|
|
|
|
|
|
|
|
Developed Producing |
30 |
|
|
|
|
|
12 |
|
|
32 |
|
Developed Non-Producing |
2 |
|
|
|
|
|
— |
|
|
2 |
|
Undeveloped |
51 |
|
|
|
|
|
8 |
|
|
52 |
|
Total
Proved |
83 |
|
|
|
|
|
20 |
|
|
86 |
|
Probable |
42 |
|
|
|
|
|
47 |
|
|
50 |
|
Total Proved plus Probable |
125 |
|
|
|
|
|
67 |
|
|
136 |
|
|
|
|
|
|
|
|
|
|
Total Company |
|
|
|
|
|
|
|
|
Proved |
|
|
|
|
|
|
|
|
Developed Producing |
169 |
|
108 |
|
266 |
|
322 |
|
5,264 |
|
4,058 |
|
102 |
|
6,908 |
|
Developed Non-Producing |
17 |
|
15 |
|
— |
|
34 |
|
— |
|
347 |
|
8 |
|
132 |
|
Undeveloped |
188 |
|
75 |
|
61 |
|
994 |
|
— |
|
2,366 |
|
119 |
|
1,831 |
|
Total
Proved |
374 |
|
198 |
|
327 |
|
1,350 |
|
5,264 |
|
6,771 |
|
229 |
|
8,871 |
|
Probable |
170 |
|
74 |
|
142 |
|
1,230 |
|
799 |
|
2,848 |
|
106 |
|
2,995 |
|
Total Proved plus Probable |
544 |
|
272 |
|
469 |
|
2,580 |
|
6,063 |
|
9,619 |
|
335 |
|
11,866 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Summary of Company Net Reserves |
As of December 31, 2017
Forecast Prices and Costs |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Light and Medium Crude Oil (MMbbl) |
|
Primary Heavy Crude Oil (MMbbl) |
|
Pelican Lake Heavy Crude Oil (MMbbl) |
|
Bitumen (Thermal Oil) (MMbbl) |
|
Synthetic Crude Oil (MMbbl) |
|
Natural Gas (Bcf) |
|
Natural Gas Liquids (MMbbl) |
|
Barrels of Oil Equivalent (MMBOE) |
|
North America |
|
|
|
|
|
|
|
|
Proved |
|
|
|
|
|
|
|
|
Developed Producing |
103 |
|
91 |
|
207 |
|
262 |
|
4,552 |
|
3,654 |
|
80 |
|
5,904 |
|
Developed
Non-Producing |
10 |
|
13 |
|
— |
|
28 |
|
— |
|
312 |
|
6 |
|
109 |
|
Undeveloped |
39 |
|
65 |
|
50 |
|
825 |
|
(9 |
) |
2,066 |
|
101 |
|
1,415 |
|
Total
Proved |
152 |
|
169 |
|
257 |
|
1,115 |
|
4,543 |
|
6,032 |
|
187 |
|
7,428 |
|
Probable |
58 |
|
61 |
|
101 |
|
971 |
|
653 |
|
2,422 |
|
86 |
|
2,334 |
|
Total Proved plus Probable |
210 |
|
230 |
|
358 |
|
2,086 |
|
5,196 |
|
8,454 |
|
273 |
|
9,762 |
|
|
|
|
|
|
|
|
|
|
North Sea |
|
|
|
|
|
|
|
|
Proved |
|
|
|
|
|
|
|
|
Developed Producing |
25 |
|
|
|
|
|
17 |
|
|
28 |
|
Developed Non-Producing |
4 |
|
|
|
|
|
— |
|
|
4 |
|
Undeveloped |
91 |
|
|
|
|
|
4 |
|
|
92 |
|
Total
Proved |
120 |
|
|
|
|
|
21 |
|
|
124 |
|
Probable |
60 |
|
|
|
|
|
11 |
|
|
61 |
|
Total Proved plus Probable |
180 |
|
|
|
|
|
32 |
|
|
185 |
|
|
|
|
|
|
|
|
|
|
Offshore Africa |
|
|
|
|
|
|
|
|
Proved |
|
|
|
|
|
|
|
|
Developed Producing |
27 |
|
|
|
|
|
9 |
|
|
29 |
|
Developed Non-Producing |
2 |
|
|
|
|
|
— |
|
|
2 |
|
Undeveloped |
41 |
|
|
|
|
|
6 |
|
|
42 |
|
Total
Proved |
70 |
|
|
|
|
|
15 |
|
|
73 |
|
Probable |
32 |
|
|
|
|
|
32 |
|
|
37 |
|
Total Proved plus Probable |
102 |
|
|
|
|
|
47 |
|
|
110 |
|
|
|
|
|
|
|
|
|
|
Total Company |
|
|
|
|
|
|
|
|
Proved |
|
|
|
|
|
|
|
|
Developed Producing |
155 |
|
91 |
|
207 |
|
262 |
|
4,552 |
|
3,680 |
|
80 |
|
5,961 |
|
Developed Non-Producing |
16 |
|
13 |
|
— |
|
28 |
|
— |
|
312 |
|
6 |
|
115 |
|
Undeveloped |
171 |
|
65 |
|
50 |
|
825 |
|
(9 |
) |
2,076 |
|
101 |
|
1,549 |
|
Total
Proved |
342 |
|
169 |
|
257 |
|
1,115 |
|
4,543 |
|
6,068 |
|
187 |
|
7,625 |
|
Probable |
150 |
|
61 |
|
101 |
|
971 |
|
653 |
|
2,465 |
|
86 |
|
2,432 |
|
Total Proved plus Probable |
492 |
|
230 |
|
358 |
|
2,086 |
|
5,196 |
|
8,533 |
|
273 |
|
10,057 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reconciliation of Company Gross
Reserves |
As of December 31, 2017
Forecast Prices and Costs |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
PROVED |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
North
America |
Light and Medium Crude Oil (MMbbl) |
|
Primary Heavy Crude Oil (MMbbl) |
|
Pelican Lake Heavy Crude Oil (MMbbl) |
|
Bitumen (Thermal Oil) (MMbbl) |
|
Synthetic Crude Oil (MMbbl) |
|
Natural Gas (Bcf) |
|
Natural Gas Liquids (MMbbl) |
|
Barrels of Oil Equivalent (MMBOE) |
|
December 31, 2016 |
168 |
|
187 |
|
264 |
|
1,269 |
|
2,559 |
|
6,545 |
|
198 |
|
5,736 |
|
Discoveries |
— |
|
— |
|
— |
|
— |
|
— |
|
— |
|
— |
|
— |
|
Extensions |
4 |
|
14 |
|
— |
|
20 |
|
— |
|
276 |
|
15 |
|
99 |
|
Infill Drilling |
4 |
|
7 |
|
— |
|
— |
|
— |
|
191 |
|
17 |
|
60 |
|
Improved Recovery |
— |
|
1 |
|
1 |
|
— |
|
— |
|
1 |
|
— |
|
2 |
|
Acquisitions |
6 |
|
20 |
|
76 |
|
23 |
|
2,321 |
|
116 |
|
1 |
|
2,467 |
|
Dispositions |
— |
|
— |
|
— |
|
— |
|
— |
|
— |
|
— |
|
— |
|
Economic Factors |
— |
|
— |
|
— |
|
— |
|
— |
|
(25 |
) |
— |
|
(4 |
) |
Technical
Revisions |
7 |
|
4 |
|
5 |
|
82 |
|
487 |
|
211 |
|
13 |
|
633 |
|
Production |
(18 |
) |
(35 |
) |
(19 |
) |
(44 |
) |
(103 |
) |
(585 |
) |
(15 |
) |
(332 |
) |
December 31, 2017 |
171 |
|
198 |
|
327 |
|
1,350 |
|
5,264 |
|
6,730 |
|
229 |
|
8,661 |
|
|
|
|
|
|
|
|
|
|
North
Sea |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December
31, 2016 |
134 |
|
|
|
|
|
41 |
|
|
141 |
|
Discoveries |
— |
|
|
|
|
|
— |
|
|
— |
|
Extensions |
— |
|
|
|
|
|
— |
|
|
— |
|
Infill Drilling |
— |
|
|
|
|
|
— |
|
|
— |
|
Improved Recovery |
— |
|
|
|
|
|
— |
|
|
— |
|
Acquisitions |
— |
|
|
|
|
|
— |
|
|
— |
|
Dispositions |
— |
|
|
|
|
|
— |
|
|
— |
|
Economic Factors |
4 |
|
|
|
|
|
(5 |
) |
|
3 |
|
Technical
Revisions |
(9 |
) |
|
|
|
|
(1 |
) |
|
(9 |
) |
Production |
(9 |
) |
|
|
|
|
(14 |
) |
|
(11 |
) |
December 31, 2017 |
120 |
|
|
|
|
|
21 |
|
|
124 |
|
|
|
|
|
|
|
|
|
|
Offshore
Africa |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December
31, 2016 |
87 |
|
|
|
|
|
31 |
|
|
92 |
|
Discoveries |
— |
|
|
|
|
|
— |
|
|
— |
|
Extensions |
— |
|
|
|
|
|
— |
|
|
— |
|
Infill Drilling |
— |
|
|
|
|
|
— |
|
|
— |
|
Improved Recovery |
— |
|
|
|
|
|
— |
|
|
— |
|
Acquisitions |
— |
|
|
|
|
|
— |
|
|
— |
|
Dispositions |
— |
|
|
|
|
|
— |
|
|
— |
|
Economic Factors |
— |
|
|
|
|
|
— |
|
|
— |
|
Technical
Revisions |
3 |
|
|
|
|
|
(3 |
) |
|
2 |
|
Production |
(7 |
) |
|
|
|
|
(8 |
) |
|
(8 |
) |
December 31, 2017 |
83 |
|
|
|
|
|
20 |
|
|
86 |
|
|
|
|
|
|
|
|
|
|
Total
Company |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December
31, 2016 |
389 |
|
187 |
|
264 |
|
1,269 |
|
2,559 |
|
6,617 |
|
198 |
|
5,969 |
|
Discoveries |
— |
|
— |
|
— |
|
— |
|
— |
|
— |
|
— |
|
— |
|
Extensions |
4 |
|
14 |
|
— |
|
20 |
|
— |
|
276 |
|
15 |
|
99 |
|
Infill Drilling |
4 |
|
7 |
|
— |
|
— |
|
— |
|
191 |
|
17 |
|
60 |
|
Improved Recovery |
— |
|
1 |
|
1 |
|
— |
|
— |
|
1 |
|
— |
|
2 |
|
Acquisitions |
6 |
|
20 |
|
76 |
|
23 |
|
2,321 |
|
116 |
|
1 |
|
2,467 |
|
Dispositions |
— |
|
— |
|
— |
|
— |
|
— |
|
— |
|
— |
|
— |
|
Economic Factors |
4 |
|
— |
|
— |
|
— |
|
— |
|
(30 |
) |
— |
|
(1 |
) |
Technical
Revisions |
1 |
|
4 |
|
5 |
|
82 |
|
487 |
|
207 |
|
13 |
|
626 |
|
Production |
(34 |
) |
(35 |
) |
(19 |
) |
(44 |
) |
(103 |
) |
(607 |
) |
(15 |
) |
(351 |
) |
December 31, 2017 |
374 |
|
198 |
|
327 |
|
1,350 |
|
5,264 |
|
6,771 |
|
229 |
|
8,871 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reconciliation of Company Gross
Reserves |
As of December 31, 2017
Forecast Prices and Costs |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
PROBABLE |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
North
America |
Light andMediumCrude Oil(MMbbl) |
|
PrimaryHeavy Crude Oil (MMbbl) |
|
Pelican Lake Heavy Crude Oil (MMbbl) |
|
Bitumen (Thermal Oil) (MMbbl) |
|
SyntheticCrude Oil(MMbbl) |
|
Natural Gas (Bcf) |
|
Natural Gas Liquids(MMbbl) |
|
Barrels of OilEquivalent (MMBOE) |
|
December 31, 2016 |
65 |
|
72 |
|
120 |
|
1,248 |
|
1,045 |
|
2,366 |
|
86 |
|
3,030 |
|
Discoveries |
— |
|
— |
|
— |
|
— |
|
— |
|
— |
|
— |
|
— |
|
Extensions |
4 |
|
8 |
|
— |
|
19 |
|
— |
|
278 |
|
10 |
|
88 |
|
Infill Drilling |
2 |
|
3 |
|
— |
|
— |
|
— |
|
104 |
|
9 |
|
31 |
|
Improved Recovery |
— |
|
— |
|
1 |
|
— |
|
— |
|
— |
|
— |
|
1 |
|
Acquisitions |
2 |
|
6 |
|
23 |
|
27 |
|
175 |
|
29 |
|
— |
|
237 |
|
Dispositions |
— |
|
— |
|
— |
|
— |
|
— |
|
(1 |
) |
— |
|
— |
|
Economic Factors |
1 |
|
— |
|
— |
|
— |
|
— |
|
(4 |
) |
— |
|
1 |
|
Technical
Revisions |
(6 |
) |
(15 |
) |
(2 |
) |
(64 |
) |
(421 |
) |
18 |
|
1 |
|
(504 |
) |
Production |
— |
|
— |
|
— |
|
— |
|
— |
|
— |
|
— |
|
— |
|
December 31, 2017 |
68 |
|
74 |
|
142 |
|
1,230 |
|
799 |
|
2,790 |
|
106 |
|
2,884 |
|
|
|
|
|
|
|
|
|
|
North
Sea |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December
31, 2016 |
119 |
|
|
|
|
|
44 |
|
|
126 |
|
Discoveries |
— |
|
|
|
|
|
— |
|
|
— |
|
Extensions |
— |
|
|
|
|
|
— |
|
|
— |
|
Infill Drilling |
1 |
|
|
|
|
|
— |
|
|
1 |
|
Improved Recovery |
— |
|
|
|
|
|
— |
|
|
— |
|
Acquisitions |
— |
|
|
|
|
|
— |
|
|
— |
|
Dispositions |
— |
|
|
|
|
|
— |
|
|
— |
|
Economic Factors |
(4 |
) |
|
|
|
|
5 |
|
|
(3 |
) |
Technical
Revisions |
(56 |
) |
|
|
|
|
(38 |
) |
|
(63 |
) |
Production |
— |
|
|
|
|
|
— |
|
|
— |
|
December 31, 2017 |
60 |
|
|
|
|
|
11 |
|
|
61 |
|
|
|
|
|
|
|
|
|
|
Offshore
Africa |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December
31, 2016 |
46 |
|
|
|
|
|
49 |
|
|
54 |
|
Discoveries |
— |
|
|
|
|
|
— |
|
|
— |
|
Extensions |
— |
|
|
|
|
|
— |
|
|
— |
|
Infill Drilling |
— |
|
|
|
|
|
— |
|
|
— |
|
Improved Recovery |
— |
|
|
|
|
|
— |
|
|
— |
|
Acquisitions |
— |
|
|
|
|
|
— |
|
|
— |
|
Dispositions |
— |
|
|
|
|
|
— |
|
|
— |
|
Economic Factors |
— |
|
|
|
|
|
— |
|
|
— |
|
Technical
Revisions |
(4 |
) |
|
|
|
|
(2 |
) |
|
(4 |
) |
Production |
— |
|
|
|
|
|
— |
|
|
— |
|
December 31, 2017 |
42 |
|
|
|
|
|
47 |
|
|
50 |
|
|
|
|
|
|
|
|
|
|
Total
Company |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December
31, 2016 |
230 |
|
72 |
|
120 |
|
1,248 |
|
1,045 |
|
2,459 |
|
86 |
|
3,210 |
|
Discoveries |
— |
|
— |
|
— |
|
— |
|
— |
|
— |
|
— |
|
— |
|
Extensions |
4 |
|
8 |
|
— |
|
19 |
|
— |
|
278 |
|
10 |
|
88 |
|
Infill Drilling |
3 |
|
3 |
|
— |
|
— |
|
— |
|
104 |
|
9 |
|
32 |
|
Improved Recovery |
— |
|
— |
|
1 |
|
— |
|
— |
|
— |
|
— |
|
1 |
|
Acquisitions |
2 |
|
6 |
|
23 |
|
27 |
|
175 |
|
29 |
|
— |
|
237 |
|
Dispositions |
— |
|
— |
|
— |
|
— |
|
— |
|
(1 |
) |
— |
|
— |
|
Economic Factors |
(3 |
) |
— |
|
— |
|
— |
|
— |
|
1 |
|
— |
|
(2 |
) |
Technical
Revisions |
(66 |
) |
(15 |
) |
(2 |
) |
(64 |
) |
(421 |
) |
(22 |
) |
1 |
|
(571 |
) |
Production |
— |
|
— |
|
— |
|
— |
|
— |
|
— |
|
— |
|
— |
|
December 31, 2017 |
170 |
|
74 |
|
142 |
|
1,230 |
|
799 |
|
2,848 |
|
106 |
|
2,995 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reconciliation of Company Gross
Reserves |
As of December 31, 2017
Forecast Prices and Costs |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
PROVED PLUS PROBABLE |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
North
America |
Light andMediumCrude Oil(MMbbl) |
|
PrimaryHeavy Crude Oil (MMbbl) |
|
Pelican Lake Heavy Crude Oil (MMbbl) |
|
Bitumen (Thermal Oil) (MMbbl) |
|
SyntheticCrude Oil(MMbbl) |
|
NaturalGas (Bcf) |
|
Natural Gas Liquids(MMbbl) |
|
Barrels of OilEquivalent(MMBOE) |
|
December 31, 2016 |
233 |
|
259 |
|
384 |
|
2,517 |
|
3,604 |
|
8,911 |
|
284 |
|
8,766 |
|
Discoveries |
— |
|
— |
|
— |
|
— |
|
— |
|
— |
|
— |
|
— |
|
Extensions |
8 |
|
22 |
|
— |
|
39 |
|
— |
|
554 |
|
25 |
|
187 |
|
Infill Drilling |
6 |
|
10 |
|
— |
|
— |
|
— |
|
295 |
|
26 |
|
91 |
|
Improved Recovery |
— |
|
1 |
|
2 |
|
— |
|
— |
|
1 |
|
— |
|
3 |
|
Acquisitions |
8 |
|
26 |
|
99 |
|
50 |
|
2,496 |
|
145 |
|
1 |
|
2,704 |
|
Dispositions |
— |
|
— |
|
— |
|
— |
|
— |
|
(1 |
) |
— |
|
— |
|
Economic Factors |
1 |
|
— |
|
— |
|
— |
|
— |
|
(29 |
) |
— |
|
(3 |
) |
Technical
Revisions |
1 |
|
(11 |
) |
3 |
|
18 |
|
66 |
|
229 |
|
14 |
|
129 |
|
Production |
(18 |
) |
(35 |
) |
(19 |
) |
(44 |
) |
(103 |
) |
(585 |
) |
(15 |
) |
(332 |
) |
December 31, 2017 |
239 |
|
272 |
|
469 |
|
2,580 |
|
6,063 |
|
9,520 |
|
335 |
|
11,545 |
|
|
|
|
|
|
|
|
|
|
North
Sea |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December
31, 2016 |
253 |
|
|
|
|
|
85 |
|
|
267 |
|
Discoveries |
— |
|
|
|
|
|
— |
|
|
— |
|
Extensions |
— |
|
|
|
|
|
— |
|
|
— |
|
Infill Drilling |
1 |
|
|
|
|
|
— |
|
|
1 |
|
Improved Recovery |
— |
|
|
|
|
|
— |
|
|
— |
|
Acquisitions |
— |
|
|
|
|
|
— |
|
|
— |
|
Dispositions |
— |
|
|
|
|
|
— |
|
|
— |
|
Economic Factors |
— |
|
|
|
|
|
— |
|
|
— |
|
Technical
Revisions |
(65 |
) |
|
|
|
|
(39 |
) |
|
(72 |
) |
Production |
(9 |
) |
|
|
|
|
(14 |
) |
|
(11 |
) |
December 31, 2017 |
180 |
|
|
|
|
|
32 |
|
|
185 |
|
|
|
|
|
|
|
|
|
|
Offshore
Africa |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December
31, 2016 |
133 |
|
|
|
|
|
80 |
|
|
146 |
|
Discoveries |
— |
|
|
|
|
|
— |
|
|
— |
|
Extensions |
— |
|
|
|
|
|
— |
|
|
— |
|
Infill Drilling |
— |
|
|
|
|
|
— |
|
|
— |
|
Improved Recovery |
— |
|
|
|
|
|
— |
|
|
— |
|
Acquisitions |
— |
|
|
|
|
|
— |
|
|
— |
|
Dispositions |
— |
|
|
|
|
|
— |
|
|
— |
|
Economic Factors |
— |
|
|
|
|
|
— |
|
|
— |
|
Technical
Revisions |
(1 |
) |
|
|
|
|
(5 |
) |
|
(2 |
) |
Production |
(7 |
) |
|
|
|
|
(8 |
) |
|
(8 |
) |
December 31, 2017 |
125 |
|
|
|
|
|
67 |
|
|
136 |
|
|
|
|
|
|
|
|
|
|
Total
Company |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December
31, 2016 |
619 |
|
259 |
|
384 |
|
2,517 |
|
3,604 |
|
9,076 |
|
284 |
|
9,179 |
|
Discoveries |
— |
|
— |
|
— |
|
— |
|
— |
|
— |
|
— |
|
— |
|
Extensions |
8 |
|
22 |
|
— |
|
39 |
|
— |
|
554 |
|
25 |
|
187 |
|
Infill Drilling |
7 |
|
10 |
|
— |
|
— |
|
— |
|
295 |
|
26 |
|
92 |
|
Improved Recovery |
— |
|
1 |
|
2 |
|
— |
|
— |
|
1 |
|
— |
|
3 |
|
Acquisitions |
8 |
|
26 |
|
99 |
|
50 |
|
2,496 |
|
145 |
|
1 |
|
2,704 |
|
Dispositions |
— |
|
— |
|
— |
|
— |
|
— |
|
(1 |
) |
— |
|
— |
|
Economic Factors |
1 |
|
— |
|
— |
|
— |
|
— |
|
(29 |
) |
— |
|
(3 |
) |
Technical
Revisions |
(65 |
) |
(11 |
) |
3 |
|
18 |
|
66 |
|
185 |
|
14 |
|
55 |
|
Production |
(34 |
) |
(35 |
) |
(19 |
) |
(44 |
) |
(103 |
) |
(607 |
) |
(15 |
) |
(351 |
) |
December 31, 2017 |
544 |
|
272 |
|
469 |
|
2,580 |
|
6,063 |
|
9,619 |
|
335 |
|
11,866 |
|
Reserves Notes:
- Company Gross reserves are working interest share before
deduction of royalties and excluding any royalty interests.
- Company Net reserves are working interest share after deduction
of royalties and including any royalty interests.
- BOE values may not calculate due to rounding.
- Forecast pricing assumptions utilized by the Independent
Qualified Reserves Evaluators in the reserve estimates were
provided by Sproule Associates Limited:
|
2018 |
|
2019 |
|
2020 |
|
2021 |
|
2022 |
|
Averageannual increasethereafter |
Crude oil and
NGL |
|
|
|
|
|
|
WTI at
Cushing (US$/bbl) |
$ |
55.00 |
|
$ |
65.00 |
|
$ |
70.00 |
|
$ |
73.00 |
|
$ |
74.46 |
|
2.00% |
Western
Canada Select (C$/bbl) |
$ |
51.05 |
|
$ |
59.61 |
|
$ |
64.94 |
|
$ |
68.43 |
|
$ |
69.80 |
|
2.00% |
Canadian
Light Sweet (C$/bbl) |
$ |
65.44 |
|
$ |
74.51 |
|
$ |
78.24 |
|
$ |
82.45 |
|
$ |
84.10 |
|
2.00% |
Cromer
LSB (C$/bbl) |
$ |
64.44 |
|
$ |
73.51 |
|
$ |
77.24 |
|
$ |
81.45 |
|
$ |
83.10 |
|
2.00% |
Edmonton
Pentanes+ (C$/bbl) |
$ |
67.72 |
|
$ |
75.61 |
|
$ |
78.82 |
|
$ |
82.35 |
|
$ |
84.07 |
|
2.00% |
North Sea
Brent (US$/bbl) |
$ |
58.00 |
|
$ |
67.00 |
|
$ |
72.00 |
|
$ |
75.00 |
|
$ |
76.50 |
|
2.00% |
Natural gas |
|
|
|
|
|
|
AECO
(C$/MMBtu) |
$ |
2.85 |
|
$ |
3.11 |
|
$ |
3.65 |
|
$ |
3.80 |
|
$ |
3.95 |
|
2.00% |
BC
Westcoast Station 2 (C$/MMBtu) |
$ |
2.45 |
|
$ |
2.71 |
|
$ |
3.25 |
|
$ |
3.40 |
|
$ |
3.55 |
|
2.00% |
Henry Hub (US$/MMBtu) |
$ |
3.25 |
|
$ |
3.50 |
|
$ |
4.00 |
|
$ |
4.08 |
|
$ |
4.16 |
|
2.00% |
Note: A foreign exchange rate of 0.7900 US$/C$
for 2018, 0.8200 US$/C$ for 2019, and 0.8500 US$/C$ after 2019 was
used in the 2017 evaluation.
- A barrel of oil equivalent (“BOE”) is derived by
converting six thousand cubic feet of natural gas to one barrel 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.
- Metrics included herein are commonly used in the oil and
natural gas industry and are determined by Canadian Natural as set
out in the notes below. These metrics do not have
standardized meanings and may not be comparable to similar measures
presented by other companies and may be misleading when making
comparisons. Management uses these metrics to evaluate
Canadian Natural’s performance over time. However, such
measures are not reliable indicators of Canadian Natural’s future
performance and future performance may vary.
- Reserve additions and revisions are comprised of all categories
of Company Gross reserve changes, exclusive of production.
- Reserve replacement or Production replacement ratio is the
Company Gross reserve additions and revisions, for the relevant
reserve category, divided by the Company Gross production in the
same period.
- Reserve Life Index is based on the amount for the relevant
reserve category divided by the 2018 proved developed producing
production forecast prepared by the Independent Qualified Reserve
Evaluators.
- Finding, Development and Acquisition ("FD&A") costs are
calculated by dividing the sum of total exploration, development
and acquisition capital costs incurred in 2017 by the sum of total
additions and revisions for the relevant reserve category.
- FD&A costs including change in Future Development Capital
("FDC") are calculated by dividing the sum of total exploration,
development and acquisition capital costs incurred in 2017 and net
change in FDC from December 31, 2016 to December 31, 2017 by the
sum of total additions and revisions for the relevant reserve
category. FDC excludes all abandonment and reclamation
costs.
- Recycle Ratio is the operating netback ($23.40/BOE for 2017)
divided by the FD&A (in $/BOE). Operating netback is
production revenues, excluding realized gains and losses on
commodity hedging, less royalties, transportation and production
expenses, calculated on a per BOE basis.
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, operating costs,
capital expenditures, income tax expenses and other guidance
provided throughout the Company's Management’s Discussion and
Analysis (“MD&A”), 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 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 of construction and future operations of the North West
Redwater bitumen upgrader and refinery, and 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 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, including the interests in AOSP as well as additional
working interests in certain other producing and non-producing oil
and gas properties (the "other assets"), acquired by the Company on
May 31, 2017; 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 and operating costs); 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 report 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 Management’s estimates or opinions change.
Special Note Regarding Currency, Production and Non-GAPP
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 three months and year ended December 31, 2017
and the MD&A and the audited consolidated financial statements
for the year ended December 31, 2016.
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 December 31, 2017 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 (loss) from operations,
funds flow from operations (previously referred to as cash flow
from operations), and adjusted cash production costs. 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
(loss) 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 (loss)
from operations and funds flow from operations are reconciled to
net earnings (loss), 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, 2016, 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, March 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, March 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 9424719.
The conference call will also be Webcast live
and may be accessed on the home page of our website at
www.cnrl.com.
For further information, please contact:
CANADIAN NATURAL RESOURCES
LIMITED 2100, 855 - 2nd Street S.W.
Calgary, Alberta, T2P4J8 T: 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. STAINTHORPEDirector, Treasury and Investor Relations
Trading Symbol - CNQToronto Stock ExchangeNew York Stock
Exchange |
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