Commenting on the Company's 2019 results, Steve Laut, Executive
Vice-Chairman of Canadian Natural stated, "2019 marked the 30th
anniversary of Canadian Natural as an Exploration and Production
("E&P") company. Over the past 3 decades, our unwavering focus
on returns and free cash flow generating assets has driven
significant growth and high returns for our shareholders. Today, we
are set up better than ever with a large, diversified portfolio
underpinned by long life low decline assets that generate
significant and sustainable free cash flow throughout the business
cycles."
Canadian Natural's President, Tim McKay, added,
"In 2019, we demonstrated that Canadian Natural is truly a unique,
sustainable and robust company. Our unparalleled asset base
underpinned by our long life low decline assets combined with our
E&P assets generated record adjusted funds flow of
approximately $10.3 billion and delivered record free cash flow of
approximately $4.6 billion in 2019, excluding major acquisition
costs. The Company achieved record production totaling 1,098,957
BOE/d, delivering 2% production growth over 2018 levels in a
curtailed environment. Production per share growth in Q4/19 over
Q4/18 levels was significant at 8% per share.
Canadian Natural's strong team of employees and
corporate culture of leveraging technology, innovation and
continuous improvement drove significant value growth as the
Company captured approximately $550 million of annual incremental
margins in 2019. The Company's continued focus on delivering margin
growth through effective and efficient operations and cost control
resulted in annual E&P operating costs decreasing by 10% from
2018 levels to $11.49/BOE. The Company continues to capture margin
growth opportunities across our entire asset base delivering
significant and sustainable free cash flow in 2020 and beyond.
In 2019, Canadian Natural continued its strong
track record of delivering excellent finding, development and
acquisition ("FD&A") costs and reserves replacement ratios,
reflecting the strength of our mix of long life low decline assets
and effective and efficient operations. Company Gross proved
reserves increased 11% to 10.993 billion BOE, replacing 2019
production by 374% with a reserves life index of 27.8 years. Proved
FD&A costs, including changes in future development costs, were
$7.45/BOE.
Due to the volatile state of the current crude
oil price environment, Canadian Natural has reduced its 2020 Oil
Sands Mining and Upgrading capital budget by approximately $100
million, demonstrating the Company’s flexibility and ability to be
nimble. This reduction will have no impact on 2020 production
volumes. Total corporate capital expenditures in 2020 are now
targeted to be $3,950 million."
Canadian Natural's Chief Financial Officer, Mark
Stainthorpe, continued, "Throughout 2019, Canadian Natural's
financial strength was once again displayed by maintaining a strong
balance sheet while maximizing financial flexibility. In 2019, the
Company achieved record net earnings of approximately $5.4 billion
and adjusted net earnings of approximately $3.8 billion. At
December 31, 2019 long-term debt totaled $20,982 million,
comparable to Q1/19 levels prior to the Devon Canada asset
acquisition, and debt to book capitalization strengthened to 37.3%
from 39.1% at year end 2018 while debt to adjusted EBITDA improved
to 1.9x from 2.0x at year end 2018. Returns to shareholders were
significant, returning over $2.6 billion to shareholders through
dividends of approximately $1.7 billion and share repurchases of
approximately $0.9 billion. Looking forward to 2020, as we continue
to deliver on our financial plan, our defined free cash flow
allocation policy targets to further strengthen our balance sheet
along with increasing returns to our shareholders.
Subsequent to year end, the Company's Board of
Directors approved a quarterly dividend increase of 13% to $0.425
per share payable on April 1, 2020. The increase marks the 20th
consecutive year of dividend increases, and reflects the Board of
Directors' confidence in the strength and robustness of our assets
and our ability to generate significant and sustainable free cash
flow."
HIGHLIGHTS
| |
|
Three Months Ended |
|
|
Year Ended |
| |
|
|
|
|
|
|
|
|
|
|
|
| ($
millions, except per common share amounts) |
|
Dec 31 2019 |
|
Sep 30 2019 |
|
Dec 31 2018 |
|
|
Dec 31 2019 |
|
Dec 31 2018 |
| Net earnings |
|
$ |
597 |
|
|
$ |
1,027 |
|
|
$ |
(776 |
) |
|
|
$ |
5,416 |
|
|
$ |
2,591 |
|
|
Per common share |
–
basic |
|
$ |
0.50 |
|
|
$ |
0.87 |
|
|
$ |
(0.64 |
) |
|
|
$ |
4.55 |
|
|
$ |
2.13 |
|
| |
– diluted |
|
$ |
0.50 |
|
|
$ |
0.87 |
|
|
$ |
(0.64 |
) |
|
|
$ |
4.54 |
|
|
$ |
2.12 |
|
| Adjusted net
earnings from operations (1) |
|
$ |
686 |
|
|
$ |
1,229 |
|
|
$ |
(255 |
) |
|
|
$ |
3,795 |
|
|
$ |
3,263 |
|
|
Per common share |
– basic |
|
$ |
0.58 |
|
|
$ |
1.04 |
|
|
$ |
(0.21 |
) |
|
|
$ |
3.19 |
|
|
$ |
2.68 |
|
| |
– diluted |
|
$ |
0.58 |
|
|
$ |
1.04 |
|
|
$ |
(0.21 |
) |
|
|
$ |
3.18 |
|
|
$ |
2.67 |
|
| Cash flows from
operating activities |
|
$ |
2,454 |
|
|
$ |
2,518 |
|
|
$ |
1,397 |
|
|
|
$ |
8,829 |
|
|
$ |
10,121 |
|
| Adjusted funds
flow (2) |
|
$ |
2,494 |
|
|
$ |
2,881 |
|
|
$ |
1,229 |
|
|
|
$ |
10,267 |
|
|
$ |
9,088 |
|
|
Per common share |
– basic |
|
$ |
2.11 |
|
|
$ |
2.43 |
|
|
$ |
1.02 |
|
|
|
$ |
8.62 |
|
|
$ |
7.46 |
|
| |
– diluted |
|
$ |
2.10 |
|
|
$ |
2.43 |
|
|
$ |
1.02 |
|
|
|
$ |
8.61 |
|
|
$ |
7.43 |
|
| Cash
flows used in investing activities |
|
$ |
854 |
|
|
$ |
908 |
|
|
$ |
1,042 |
|
|
|
$ |
7,255 |
|
|
$ |
4,814 |
|
| Net
capital expenditures, excluding Devon Canada asset acquisition
costs (3) |
|
$ |
1,056 |
|
|
$ |
963 |
|
|
$ |
1,181 |
|
|
|
$ |
3,904 |
|
|
$ |
4,731 |
|
| Total
net capital expenditures, including Devon Canada asset acquisition
costs (3) |
|
$ |
1,056 |
|
|
$ |
963 |
|
|
$ |
1,181 |
|
|
|
$ |
7,121 |
|
|
$ |
4,731 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
| Daily
production, before royalties |
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (MMcf/d) |
|
1,455 |
|
|
1,469 |
|
|
1,488 |
|
|
|
1,491 |
|
|
1,548 |
|
|
Crude oil and NGLs (bbl/d) |
|
913,782 |
|
|
931,546 |
|
|
833,358 |
|
|
|
850,393 |
|
|
820,778 |
|
|
Equivalent production (BOE/d) (4) |
|
1,156,276 |
|
|
1,176,361 |
|
|
1,081,368 |
|
|
|
1,098,957 |
|
|
1,078,813 |
|
(1) Adjusted net earnings from operations is a non-GAAP measure
that the Company utilizes to evaluate its performance, as it
demonstrates the Company’s ability to generate after-tax operating
earnings from its core business areas. The derivation of this
measure is discussed in the "Advisory" section of this press
release.
(2) Adjusted funds flow (previously referred to as funds flow
from operations) is a non-GAAP measure that the Company considers
key to evaluate its performance as it demonstrates the Company’s
ability to generate the cash flow necessary to fund future growth
through capital investment and to repay debt. The derivation of
this measure is discussed in the "Advisory" section of this press
release.
(3) Net capital expenditures is a non-GAAP measure that the
Company considers a key measure as it provides an understanding of
the Company’s capital spending activities in comparison to the
Company's annual capital budget. For additional information and
details, refer to the net capital expenditures table in the
"Advisory" section of this press release.
(4) A barrel of oil equivalent (“BOE”) is derived by converting
six thousand cubic feet (“Mcf”) of natural gas to one barrel
(“bbl”) of crude oil (6 Mcf:1 bbl). This conversion may be
misleading, particularly if used in isolation, since the 6 Mcf:1
bbl ratio is based on an energy equivalency conversion method
primarily applicable at the burner tip and does not represent a
value equivalency at the wellhead. In comparing the value ratio
using current crude oil prices relative to natural gas prices, the
6 Mcf:1 bbl conversion ratio may be misleading as an indication of
value.
ANNUAL HIGHLIGHTS
- Net earnings of $5,416 million were realized in 2019, while
adjusted net earnings of $3,795 million were achieved in 2019, a
$532 million increase over 2018 levels.
- Cash flows from operating activities were $8,829 million in
2019, a decrease of $1,292 million compared to 2018 levels
primarily due to the impact of changes in non-cash working
capital.
- Canadian Natural generated record annual adjusted funds flow of
$10,267 million in 2019, an increase of 13% or $1,179 million over
2018 levels. The increase over 2018 was primarily due to higher
crude oil and NGL netbacks in the Company's Exploration and
Production ("E&P") segment and higher volumes in the Company's
thermal in situ and international areas.
- Cash flows used in investing activities were $7,255 million in
2019, an increase of $2,441 million compared to 2018 levels as a
result of the Devon Canada asset acquisition completed in 2019,
partially offset by lower capital expenditures in the year.
- Canadian Natural delivered record annual free cash flow of
$4,620 million after net capital expenditures of $3,904 million and
dividend requirements of $1,743 million, and excluding Devon Canada
asset acquisition costs, reflecting the strength of the Company's
long life low decline asset base and effective and efficient
operations.
- Balance sheet strength remains a focus as year end 2019
long-term debt totaled $20,982 million, comparable to Q1/19 levels
prior to the Devon Canada asset acquisition, and debt to book
capitalization strengthened to 37.3% from 39.1% at year end 2018
while debt to adjusted EBITDA improved to 1.9x from 2.0x at year
end 2018. During 2019, the Company executed on the following:
- The Company repaid $500 million of 3.05% notes and $500 million
of 2.60% notes in Q2/19 and Q4/19, respectively.
- The Company fully repaid and canceled the remaining balance of
the $1,800 million non-revolving term loan credit facility that was
used to finance the Athabasca Oil Sands Project ("AOSP")
acquisition, ahead of its maturity in May 2020.
- Additionally, the $2,200 million non-revolving term credit
facility, originally due in October 2020, was extended to February
2023 and increased by $450 million to $2,650 million.
- Canadian Natural is committed to returns to shareholders,
returning a total of $2,684 million to shareholders in 2019, $1,743
million by way of dividends and $941 million by way of share
repurchases.
- Share repurchases for cancellation totaled 25,900,000 common
shares at a weighted average share price of $36.32.
- Subsequent to year end, up to and including March 4, 2020, the
Company executed on additional share repurchases for cancellation
of 6,600,000 common shares at a weighted average share price of
$39.41.
- Returns to shareholders have been significant as Canadian
Natural returned approximately $6.2 billion by way of dividends and
share repurchases between January 1, 2018 and March 4, 2020.
- 2019 dividends increased 12% from 2018 levels to $1.50 per
share. Subsequent to year end, the Company declared a quarterly
dividend increase of 13% to $0.425 per share, payable on April 1,
2020. The increase marks the 20th consecutive year that the Company
has increased its dividend, reflecting the Board of Directors'
confidence in Canadian Natural's strength and robustness
of the Company's assets and its ability to generate significant and
sustainable free cash flow.
- Canadian Natural's strong team of employees and corporate
culture of leveraging technology, innovation and continuous
improvement drove significant value growth as the Company captured
approximately $550 million of annual incremental margin in 2019,
some of the key achievements are identified as follows:
- Canadian Natural's continued focus on delivering margin growth
through effective and efficient operations, execution on the
Company's curtailment optimization strategy and cost control was
demonstrated as the Company's E&P annual operating costs were
$11.49/BOE in 2019, representing a 10% decrease or approximately
$310 million of margin improvement from 2018 levels.
- Pelican Lake annual operating costs decreased by 7% to
$6.22/bbl from 2018 levels.
- Thermal in situ annual operating costs decreased by 18% to
$10.83/bbl from 2018 levels.
- North America natural gas annual operating costs decreased by
7% to $1.16/Mcf from 2018 levels.
- Oil Sands Mining and Upgrading annual operating costs,
excluding energy costs, decreased $91 million or 3% from 2018
levels.
- As part of Canadian Natural's natural gas marketing strategy,
the Company has continued to diversify its natural gas sales
points, equating to approximately $115 million of additional margin
in 2019.
- The Company has identified approximately $900 million of
additional annual margin growth opportunities of which
approximately $180 million are targeted to be captured in
2020.
- The Company achieved record annual production volumes of
1,098,957 BOE/d in 2019, an increase of 2% over 2018 levels,
primarily due to production from the acquisition of thermal in situ
and primary heavy crude oil assets from Devon Canada and execution
of the Company's curtailment optimization strategy, offsetting the
impact of a proactive piping replacement in one of the hydrogen
units at Horizon, together with the unplanned maintenance at the
non-operated Scotford Upgrader and at Horizon in the first half of
the year.
- Production per share growth was significant at approximately 8%
from Q4/18 to Q4/19, as a result of accretive acquisitions,
effective and efficient operations and execution on the Company's
free cash flow allocation policy.
- The Company achieved record annual liquids production volumes
of 850,393 bbl/d in 2019, an increase of 4% over 2018 levels.
- The Company continues to execute operational flexibility
through its curtailment optimization strategy as follows:
- Increasing crude oil production from the Company's balanced
asset base to mitigate production impacts during periods of planned
and unplanned downtime.
- Modified timing of the Company's planned turnaround activities
to target its monthly curtailment allowable production
volumes.
- Maximizing value through production optimization of higher
netback assets.
- Allowing the Company to execute on proactive maintenance
activities to enhance long-term reliability.
- Thermal in situ oil sands production volumes were strong in
2019, averaging a record 167,942 bbl/d, a 56% increase over 2018
levels, primarily as a result of the Jackfish acquisition and
increased production from Kirby North and pad additions at
Primrose, reflecting the successful execution of the Company's
curtailment optimization strategy.
- At Kirby North, production ramp up continues to be strong,
exceeding expectations as a result of top tier execution and
productivity, with a December 2019 exit rate of approximately
26,500 bbl/d. As a result of improved well design, high plant
reliability and effective and efficient operations, the project now
targets to reach peak overall capacity of 40,000 bbl/d in early
Q3/20, ahead of schedule, driving additional margins in 2020.
- High return, drill to fill pad additions at Primrose came on
ahead of schedule and on budget with strong production averaging
approximately 32,000 bbl/d in Q4/19. As previously announced, these
pad additions are targeted to add approximately 26,000 bbl/d in the
first 12 months of production.
- At Jackfish, the Company successfully completed tie in
activities in Q4/19 on the previously drilled pad additions that
have production capability of 21,000 bbl/d for minimal capital of
approximately $8 million. Production from these pads is targeted to
reach overall peak production in early 2022 and is targeted to
offset conventional production declines with long life low decline
thermal in situ production as the Company manages within its
curtailment optimization strategy.
- At the Company's world class Oil Sands Mining and Upgrading
assets, annual production volumes averaged 395,133 bbl/d of
Synthetic Crude Oil ("SCO") in 2019, a decrease of 7% from 2018
levels, reflecting the proactive piping replacement in one of the
hydrogen units at Horizon, together with the unplanned maintenance
at the non-operated Scotford Upgrader and at Horizon in the first
half of the year.
- At AOSP, through increased reliability, process improvements
and optimization projects, Canadian Natural increased gross
production capacity at the Albian mines by approximately 40,000
bbl/d to approximately 320,000 bbl/d, representing a 14% increase
in capacity while reducing AOSP operating costs by approximately
34% or $10.00/bbl since the announcement of the acquisition in
2017.
- As part of the Company's overall strategy to maximize value and
enhance margins, the Scotford Upgrader is targeting to increase
capacity to approximately 320,000 bbl/d in Q3/20. This additional
capacity at AOSP will allow for increased flexibility, margin
improvements and can be managed through the Company's curtailment
optimization strategy.
- International E&P crude oil production volumes were strong
in 2019, averaging 49,290 bbl/d, an increase of 13% over 2018
levels. The increase over 2018 was primarily due to strong
performance from wells drilled in the North Sea and at Baobab,
partially offset by natural field declines.
- The Company now targets approximately $190 million in annual
operating costs savings from assets acquired from Devon Canada, $55
million in excess of its initially identified targeted annual
operating cost savings of $135 million.
- Due to the volatile state of the current crude oil price
environment, Canadian Natural has reduced its 2020 Oil Sands Mining
and Upgrading capital budget by approximately $100 million,
demonstrating the Company’s flexibility and ability to be nimble.
This reduction will have no impact on 2020 production
volumes. Total corporate capital expenditures in 2020 are now
targeted to be $3,950 million.
- In Q2/19, the Government of Alberta enacted a series of tax
rate reductions which will decrease the provincial corporate income
tax rate from 12% to 8% by 2022. As a result of this reduction,
Canadian Natural estimates current tax savings of approximately $15
million in 2019 and approximately $30 million in 2020. As
previously disclosed, these current tax savings coupled with the
elimination of curtailment for certain conventional drilling in
Alberta resulted in the Company increasing its 2020 E&P capital
budget by approximately $250 million over 2019 levels, targeting 60
additional drilling locations across Alberta.
- In accordance with International Financial Reporting Standards,
the Company recorded a non-cash accounting reduction in its
deferred tax liability of $1,618 million in Q2/19. Over the next
several decades, the Company is expected to continue to realize
current tax savings resulting from the tax rate reductions.
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 at December 31,
2019 (all reserves values are Company Gross unless stated
otherwise).
- Canadian Natural’s 2019 performance has resulted in another
year of excellent finding and development costs:
- Finding, Development and Acquisition ("FD&A") costs,
excluding changes in Future Development Costs ("FDC"), are
$4.52/BOE for proved reserves and $5.34/BOE for proved plus
probable reserves.
- FD&A costs, including changes in FDC, are $7.45/BOE for
proved reserves and $5.75/BOE for proved plus probable
reserves.
- Proved reserves increased 11% to 10.993 billion BOE with
reserves additions and revisions of 1.501 billion BOE. Proved plus
probable reserves increased 6% to 14.252 billion BOE with reserves
additions and revisions of 1.271 billion BOE.
- Proved reserves additions and revisions replaced 2019
production by 374%. Proved plus probable reserves additions and
revisions replaced 2019 production by 317%.
- The proved BOE reserves life index is 27.8 years and the proved
plus probable BOE reserves life index is 36.0 years.
- Proved developed producing reserves additions and revisions are
0.778 billion BOE, replacing 2019 production by 194%. The total
proved developed producing BOE reserves life index is 20.2
years.
- The net present value of future net revenues, before income
tax, discounted at 10%, increased 1% to $107.6 billion for proved
reserves and decreased 2% to $127.8 billion for proved plus
probable reserves. The net present value for proved developed
producing reserves is relatively unchanged at $84.3 billion.
MARKETING UPDATE
- Mainline enhancements of approximately 100,000 bbl/d of
capacity were completed in December 2019, increasing pipeline
capacity out of the Western Canadian Sedimentary Basin
("WCSB").
- Additional pipeline egress of approximately 190,000 bbl/d to
move incremental crude oil production out of the WCSB is targeted
to be added by industry over the near term, providing opportunities
for the Company before new export pipelines are constructed:
- Additional Mainline enhancements of 50,000 bbl/d of capacity
are targeted in 2020.
- Express pipeline optimization expansion is targeted to add
approximately 50,000 bbl/d of capacity in 2020.
- The North West Redwater Refinery ("NWR") is targeted to add
approximately 40,000 bbl/d of incremental crude oil conversion
capacity. Upon start-up of the Gasifier and LC Finer units, the
refinery will process a total of approximately 80,000 bbl/d of
diluted bitumen, increasing effective takeaway capacity out of the
WCSB.
- Base Keystone export pipeline optimization expansion of
approximately 50,000 bbl/d was recently announced. In Q3/19,
Canadian Natural committed to approximately 10,000 bbl/d of the
expansion, which is targeted to be available in 2020.
- Crude by rail volumes continue to be strong at approximately
350,000 bbl/d for the month of December 2019.
ENVIRONMENTAL HIGHLIGHTS
- Canadian Natural is committed to achieving its aspirational
goal of net zero Oil Sands emissions through its leading
environmental performance and technology, innovation and continuous
improvement potential pathways, which are listed on the Company's
website at
https://www.cnrl.com/corporate-responsibility/advancements-in-technology/.
- As part of Canadian Natural's commitment to its aspirational
goal of net zero Oil Sands emissions, the Company announced the
following environmental targets at its Investor Day in December
2019:
- Reduction of Oil Sands greenhouse gas ("GHG") emissions
intensity by 25% by 2025, from a 2016 baseline.
- Reduction of methane emissions in its North America E&P
operations by 20% by 2025, from a 2016 baseline.
- Reduction in water intensity in its in situ operations by 50%
by 2022, from a 2012 baseline.
- Reduction of Oil Sands mining fresh river water intensity by
30% by 2022, from a 2012 baseline.
- At the end of 2019, highlights from the Company's environmental
performance are as follows:
- As part of Canadian Natural's industry leading reclamation and
proactive liability management program, the Company achieved the
following reclamation success in 2019:
- In the Company's North America E&P segment, Canadian
Natural proactively abandoned 2,035 wells, an increase of 57% over
2018 levels, as well as submitted 912 reclamation certificate
applications and received 893 reclamation certificates during the
year.
- In Alberta, Canadian Natural received 850 reclamation
certificates which is the largest number of certificates received
by an operator and represents 18% of the total certificates
issued.
- The Company reclaimed 3,118 hectares of land in 2019 in the
Company's North America E&P segment, a 125% increase over 2018
levels.
- In the Oil Sands Mining and Upgrading segment, water use
intensity decreased in 2019 by 17% from 2018 levels.
- The Company reduced its fresh water usage by 28%, sourcing
approximately 82% from recycled produced water at Primrose in
2019.
- The Company confirms that 100% of direct emissions from its
Alberta Oil Sands in situ and mining operations were third party
verified in 2018 and the verification process is underway for 2019
emissions. The verification is completed by a third party
professional engineering firm.
- Canadian Natural has invested approximately $3.4 billion in
research and development from 2009 to 2018 and continues to invest
in technology to unlock reserves, become more effective and
efficient, increase production and reduce the Company's
environmental footprint. Canadian Natural's culture of continuous
improvement leverages the use of technology and innovation to drive
sustainable operations and long-term value for shareholders.
- Canadian Natural has invested significant capital to capture
and sequester CO2, making the Company one of the largest CO2
capturers and sequesterers for the oil and natural gas sector
globally. 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 in the NWR refinery when on stream.
As a result, Canadian Natural targets capacity to capture and
sequester 2.7 million tonnes of CO2 annually, equivalent to taking
576,000 vehicles off the road per year.
- Canadian Natural's commitment to leverage technology, adopting
innovation and continuous improvement is evidenced by projects
described in its Creating Value through Technology and Innovation
Case Studies published in December 2019, which is available on the
Company's website at
https://www.cnrl.com/upload/media_element/1279/05/technology-and-innovation-case-studies-web.pdf.
Highlights from the publication are as follows:
- The In Pit Extraction Process ("IPEP") pilot at Horizon will
determine the feasibility of producing stackable dry tailings. The
project has the potential to reduce the Company's bitumen
production GHG emissions by approximately 40% and lower the
Company's environmental footprint by decreased material handling,
reducing the distance driven by its fleet of haul trucks,
decreasing the size and need for tailings ponds and accelerating
site reclamation. In addition, this process has the potential to
reduce capital and operating costs.
- Results from the initial testing phase for the Company's IPEP
pilot have been positive, with excellent recovery rates and
evidence of stackable tailings. The Company is implementing
enhancements to improve overall operability in 2020.
- Solvent Enhanced Oil Recovery technology is being tested at the
Company's in situ operations to increase crude oil recovery, reduce
steam-to-oil ratios ("SOR") by up to 50%, translating into GHG
intensity reduction of up to 50%. To date, the Company has seen
increases in crude oil production, lower SOR and high solvent
recovery at its Kirby South operations. In addition, the Company is
planning commercial scale demonstration tests to verify economics
and execution details are being refined through 2020. This
technology has the potential for application throughout the
Company's extensive thermal in situ asset base.
- Methane emission reduction projects will reduce the Company's
emissions through focusing on operational practices and innovative
technologies. Through the Company's pneumatic retrofit program
which began in 2018, the Company reduced approximately 400,000
tonnes of CO2 equivalent per year by completing approximately 4,000
controller retrofits by the end of 2019. In 2020, the Company is
targeting an additional 1,300 controller retrofits, a reduction of
approximately 130,000 tonnes of CO2 equivalent per year.
FOURTH QUARTER HIGHLIGHTS
- Net earnings of $597 million were realized in Q4/19, while
adjusted net earnings of $686 million were achieved in Q4/19, a
$543 million decrease from Q3/19 levels.
- Cash flows from operating activities were $2,454 million in
Q4/19, a decrease of $64 million compared to Q3/19 levels.
- Canadian Natural generated quarterly adjusted funds flow of
$2,494 million in Q4/19, a decrease of 13% or $387 million from
Q3/19 levels, primarily due to lower SCO volumes in the Oil Sands
Mining and Upgrading segment and lower E&P crude oil and NGL
netbacks driven largely by lower crude oil pricing, partially
offset by lower E&P operating costs, higher North America crude
oil and NGL production volumes and higher natural gas prices.
- Canadian Natural's continued focus on delivering effective and
efficient operations and cost control was demonstrated as the
Company's E&P Q4/19 operating costs were $10.79/BOE, 3% and 20%
reductions from Q3/19 and Q4/18 levels respectively.
- Cash flows used in investing activities were $854 million in
Q4/19.
- Canadian Natural delivered strong quarterly free cash flow of
$994 million after net capital expenditures of $1,056 million and
dividend requirements of $444 million in Q4/19, reflecting the
strength of the Company's long life low decline asset base and
effective and efficient operations.
- Balance sheet strength remains a focus as long-term debt
decreased by $1,507 million from Q3/19 levels to $20,982 million at
December 31, 2019. Debt to book capitalization strengthened to
37.3% from 39.1% and debt to adjusted EBITDA improved to 1.9x from
2.6x quarter over quarter.
- In Q4/19, Canadian Natural repaid $500 million of 2.60% notes
and fully repaid and canceled the $1,000 million remaining balance
on the non-revolving term loan credit facility that was used to
finance the AOSP acquisition, ahead of its maturity in May
2020.
- Canadian Natural is committed to returns to shareholders,
returning a total of $584 million to shareholders in Q4/19, $444
million by way of dividends and $140 million by way of share
repurchases.
- The Company achieved quarterly production volumes of 1,156,276
BOE/d in Q4/19, a 7% increase and 2% decrease from Q4/18 and Q3/19
levels respectively. The increase over Q4/18 primarily reflected
production from the acquisition of thermal in situ and primary
heavy crude oil assets from Devon Canada, offsetting the impact of
the completion of the planned turnaround and a proactive piping
replacement at Horizon in Q4/19. The decrease from Q3/19 primarily
reflected the proactive piping replacement at Horizon in Q4/19
partially offset by the Company's execution of its curtailment
optimization strategy.
- Canadian Natural's North America E&P crude oil and NGLs
production volumes, excluding thermal in situ, averaged 247,184
bbl/d in Q4/19, comparable to Q3/19 and a 3% increase over Q4/18
levels. The increase over Q4/18 was primarily due to production
from primary heavy crude oil assets acquired from Devon
Canada.
- Thermal in situ oil sands production volumes were strong in the
quarter, averaging a record 259,387 bbl/d, a 26% increase and 154%
increase over Q3/19 and Q4/18 levels respectively. The increase
over Q3/19, primarily reflected the successful execution of the
Company's curtailment optimization strategy as production ramped up
from Kirby North and Primrose pad additions and increased
production at Jackfish. The increase over Q4/18 primarily reflected
production volumes from the Devon Canada asset acquisition,
together with new production from Kirby North and pad additions at
Primrose, reflecting optimization of curtailment volumes across the
Company's asset base.
- Thermal in situ operating costs were strong in Q4/19 at
$8.65/bbl, reductions of 11% and 35% from Q3/19 and Q4/18 levels
respectively, primarily as a result of higher production volumes
and synergies captured to date from the Devon Canada asset
acquisition, partially offset by higher fuel costs.
- At the Albian mines, top tier operations combined with
optimization of facilities resulted in record gross bitumen
production averaging approximately 306,000 bbl/d in Q4/19, forming
a part of the Company’s curtailment optimization strategy during
the turnaround and the proactive piping replacement at
Horizon.
- In Q4/19 at Horizon, as a result of Canadian Natural's industry
leading integrity program, the Company identified the need to
replace piping on one of the hydrogen manufacturing units during
post turnaround start-up. To ensure increased reliability of
operations and as part of the Company's curtailment optimization
strategy, the Company made the proactive decision to replace the
piping, at which time Horizon ran at restricted rates of
approximately 170,500 bbl/d, and production impacts were managed as
part of the Company's curtailment optimization strategy. The
proactive piping replacement was completed for approximately $65
million and production resumed to full rates on January 19, 2020.
- Record monthly production of approximately 262,600 bbl/d of SCO
was achieved at Horizon in February 2020 as a result of continued
high utilization, safe, steady and reliable operations.
- International E&P crude oil production volumes averaged
49,355 bbl/d, in-line with Q3/19 and an increase of 14% over Q4/18
levels. The increase from Q4/18 was primarily as a result of strong
volumes from wells drilled at Baobab and in the North Sea.
OPERATIONS REVIEW AND CAPITAL ALLOCATION
Canadian Natural has a balanced and diverse
portfolio of assets, primarily Canadian-based, with international
exposure in the UK section of the North Sea and Offshore Africa.
Canadian Natural’s production is well balanced between light crude
oil, medium crude oil, primary heavy crude oil, Pelican Lake heavy
crude oil, thermal in situ crude oil, bitumen and SCO (herein
collectively referred to as “crude oil”), natural gas and NGLs.
This balance provides optionality for capital investments,
maximizing value for the Company’s shareholders.
Underpinning this asset base is long life low
decline production from the Company's Oil Sands Mining and
Upgrading, thermal in situ oil sands and Pelican Lake heavy crude
oil assets. The combination of long life low decline, low reserves
replacement cost, and effective and efficient operations results in
substantial and sustainable adjusted funds flow throughout the
commodity price cycle.
Augmenting this, Canadian Natural maintains a
substantial inventory of low capital exposure projects within the
Company's conventional asset base. These projects can be executed
quickly and with the right economic conditions, can provide
excellent returns and maximize value for shareholders. Supporting
these projects is the Company’s undeveloped land base which enables
large, repeatable drilling programs which can be optimized over
time. Additionally, by owning and operating most of the related
infrastructure, Canadian Natural is able to control major
components of the Company's operating costs and minimize production
commitments. Low capital exposure projects can be quickly stopped
or started depending upon success, market conditions, or corporate
needs.
Canadian Natural’s balanced portfolio, built
with both long life low decline assets and low capital exposure
assets, enables effective capital allocation, production growth and
value creation.
Drilling Activity
| |
Year Ended Dec 31 |
| |
|
|
| |
2019 |
2018 |
| (number
of wells) |
Gross |
Net |
Gross |
Net |
|
Crude oil |
96 |
|
86 |
|
513 |
|
483 |
|
| Natural gas |
30 |
|
19 |
|
25 |
|
18 |
|
|
Dry |
3 |
|
3 |
|
9 |
|
9 |
|
| Subtotal |
129 |
|
108 |
|
547 |
|
510 |
|
|
Stratigraphic test / service wells |
519 |
|
447 |
|
717 |
|
615 |
|
|
Total |
648 |
|
555 |
|
1,264 |
|
1,125 |
|
|
Success rate (excluding stratigraphic test / service wells) |
|
97 |
% |
|
98 |
% |
- The Company's total crude oil and natural gas drilling program
of 108 net wells for the year
ended
December 31, 2019, excluding strat/service wells, represents a
decrease of 402 net wells from the same period in 2018. The
Company's drilling levels primarily reflect the impacts of reduced
capital allocation as a result of Alberta curtailments and
execution of the Company's curtailment optimization strategy.
North America Exploration and Production
| Crude oil and NGLs
– excluding Thermal In Situ Oil Sands |
|
|
|
|
Three Months Ended |
Year Ended |
| |
|
|
|
|
|
|
|
Dec 31 2019 |
Sep 30 2019 |
Dec 31 2018 |
Dec 31 2019 |
Dec 31 2018 |
|
Crude oil and NGLs production (bbl/d) |
247,184 |
|
244,267 |
|
240,942 |
|
238,028 |
|
243,122 |
|
| Net wells targeting crude
oil |
9 |
|
33 |
|
62 |
|
79 |
|
361 |
|
| Net successful wells
drilled |
9 |
|
33 |
|
61 |
|
77 |
|
353 |
|
|
Success rate |
100 |
% |
100 |
% |
98 |
% |
97 |
% |
98 |
% |
- Canadian Natural's North America E&P crude oil and NGL
production volumes, excluding thermal in situ, averaged 238,028
bbl/d in 2019, a 2% decrease from 2018 levels, primarily reflecting
natural field declines and the Company's strategic decision to
reduce activity due to mandatory production curtailments in
Alberta, partially offset by the acquisition of primary heavy crude
oil assets from Devon Canada.
- Canadian Natural's primary heavy crude oil production averaged
82,189 bbl/d in 2019, a 5% decrease from 2018 levels as a result of
the Company's strategic decision to reduce activity due to
mandatory production curtailments in Alberta, partially offset by
additional volumes from the Devon Canada asset acquisition.
- Strong operating costs of $16.66/bbl were achieved in the
Company's primary heavy crude oil operations in 2019, comparable to
2018 levels, impressive results given lower production volumes and
the Company's continued focus on capturing synergies and margin
improvements.
- Pelican Lake annual production averaged 58,855 bbl/d in 2019, a
decrease of 7% from 2018 levels, reflecting natural field declines
and the Company's strategic decision to reduce activity due to
mandatory production curtailments in Alberta.
- At Pelican Lake, the Company continues to demonstrate effective
and efficient operations as annual operating costs decreased by 7%
from 2018 levels, averaging $6.22/bbl in 2019, as a result of the
Company's focus on cost control. As part of Canadian Natural's
margin enhancement opportunities, the Company is targeting to
achieve approximately $10 million in incremental cost savings at
Pelican Lake in 2020.
- North American light crude oil and NGL production averaged
96,984 bbl/d in 2019, a 3% increase from 2018 levels primarily as a
result of the Company's strategic decision to reallocate capital to
non-curtailed light crude oil in Saskatchewan and liquids rich
natural gas areas, combined with the execution of the Company's
curtailment optimization strategy and continued strong production
from 2018 and 2019 drilling in the Greater Wembley and Karr areas.
- In 2019, operating costs were $15.21/bbl in the Company's North
America light crude oil and NGL areas, comparable to 2018
levels.
| Thermal In Situ
Oil Sands |
|
|
|
|
Three Months Ended |
Year Ended |
| |
|
|
|
|
|
|
|
Dec 31 2019 |
Sep 30 2019 |
Dec 31 2018 |
Dec 31 2019 |
Dec 31 2018 |
|
Bitumen production (bbl/d) |
259,387 |
|
206,395 |
|
102,112 |
|
167,942 |
|
107,839 |
|
| Net wells targeting
bitumen |
3 |
|
— |
|
41 |
|
3 |
|
125 |
|
| Net successful wells
drilled |
3 |
|
— |
|
40 |
|
3 |
|
124 |
|
|
Success rate |
100 |
% |
— |
|
98 |
% |
100 |
% |
99 |
% |
- Thermal in situ oil sands production volumes were strong in
2019, averaging a record 167,942 bbl/d, a 56% increase over 2018
levels, primarily as a result of the Jackfish acquisition and
increased production from Kirby North and pad additions at
Primrose, reflecting the successful execution of the Company's
curtailment optimization strategy.
- Thermal in situ operating costs were strong in 2019, a decrease
of 18% from 2018 levels, averaging $10.83/bbl, primarily as a
result of higher production volumes, synergies captured to date
from the Devon Canada asset acquisition and the Company's continued
focus on cost control, partially offset by higher energy
costs.
- At Primrose, 2019 production volumes averaged 78,606 bbl/d, an
increase of 12% over 2018 levels, primarily due to new production
from pad additions that came on in late Q3/19, together with
execution of the Company's curtailment optimization strategy.
- High return, drill to fill pad additions at Primrose came on
ahead of schedule and on budget with strong production averaging
approximately 32,000 bbl/d in Q4/19. As previously announced, these
pad additions are targeted to add approximately 26,000 bbl/d in the
first 12 months of production.
- At Kirby, which now includes both Kirby South and Kirby North,
SAGD production volumes averaged 34,094 bbl/d in 2019, a 3%
decrease from 2018 levels due to natural field declines at Kirby
South as a result of the Company's capital allocation decisions due
to mandatory production curtailments in Alberta, offsetting the
ramp up of Kirby North production.
- At Kirby North, production ramp up continues to be strong,
exceeding expectations as a result of top tier execution and
productivity, with a December 2019 exit rate of approximately
26,500 bbl/d. As a result of improved well design, high plant
reliability and effective and efficient operations, the project now
targets to reach peak overall capacity of 40,000 bbl/d in early
Q3/20, ahead of schedule, driving additional margins in 2020.
- Results from the Company's solvent enhanced SAGD pilot that
began in late Q2/19 at Kirby South continue to be positive,
indicating that targeted SOR reductions of 30% to 50% remain
achievable. If success continues during the two year pilot,
learnings from this pilot have the potential for application
throughout the Company's extensive thermal in situ asset base,
significantly reducing the Company's GHG intensity by up to 50% and
at the same time significantly reducing operating costs.
- At Jackfish, SAGD production volumes averaged 102,106 bbl/d in
Q4/19, a 5% increase over Q3/19 levels, reflecting execution on the
Company's curtailment optimization strategy. The Company has
successfully integrated the assets and captured synergies to date.
The Company targets go forward operating costs based on current
strip estimates, including energy costs, to be approximately $8.00
- $9.00/bbl. This represents a $3.50/bbl reduction
at the midpoint or approximately 30% lower than operating cost
indications for the asset at the time of acquisition.
- At Jackfish, the Company successfully completed tie in
activities in Q4/19 on the previously drilled pad additions that
have production capability of 21,000 bbl/d for minimal capital of
approximately $8 million. Production from these pads is targeted to
reach overall peak production in early 2022 and is targeted to
offset conventional production declines with long life low decline
thermal in situ production as the Company manages within its
curtailment optimization strategy.
- The Company is targeting planned turnaround activity in late
Q1/20 at Jackfish. Production impacts are reflected in annual
guidance and will be managed as part of the Company's curtailment
optimization strategy.
| North America
Natural Gas |
|
|
| |
Three Months Ended |
Year Ended |
| |
|
|
|
|
|
| |
Dec 31 2019 |
Sep 30 2019 |
Dec 31 2018 |
Dec 31 2019 |
Dec 31 2018 |
|
Natural gas production (MMcf/d) |
1,411 |
|
1,425 |
|
1,441 |
|
1,443 |
|
1,490 |
|
| Net wells targeting natural
gas |
4 |
|
5 |
|
3 |
|
20 |
|
18 |
|
| Net successful wells
drilled |
4 |
|
5 |
|
3 |
|
19 |
|
18 |
|
|
Success rate |
100 |
% |
100 |
% |
100 |
% |
95 |
% |
100 |
% |
- North America natural gas production was 1,443 MMcf/d in 2019,
a decrease of 3% from 2018 levels, reflecting natural field
declines, together with the strategic reduction of capital
allocated to natural gas activities due to low natural gas
prices.
- Natural gas operating costs were strong in 2019, a decrease of
7% from 2018 levels to $1.16/Mcf, given the Company's strategic
decision to allocate capital to other areas and let production
decline. These results demonstrate the strength of the Company's
strategy to own and control its infrastructure, continued focus on
cost control and achieving efficiencies across the entire asset
base.
- At the Company's high value Septimus Montney liquids rich area,
operating costs were strong in 2019, a 6% decrease from 2018
levels, averaging $0.30/Mcfe in 2019.
- The Company's Liquids Enhancement and Gas Storage ("LEGS")
pilot at Septimus began in Q2/19 and has the potential to
materially increase liquids recovery while storing natural gas in
the reservoir, preserving the value of the natural gas for periods
with higher market prices.
- The Company completed two injection and production cycles at
Septimus in 2019 and initial results are positive, indicating
incremental liquids recovery within the expected range of 1.3x to
1.7x primary recovery. A third production cycle commenced in
February 2020 and is proceeding as expected. Given the
opportunities for this process across Canadian Natural's vast
liquids rich Montney land base, the Company is executing on a
second pilot site within the Company's Greater Wembley area and is
targeting first injection in late Q2/20.
- Following the acquisition of the Pine River plant in Q2/19, the
Company successfully completed a planned plant turnaround in Q4/19
designed to improve plant efficiency, run time, lower operating
costs, and improve plant capability. Following the turnaround,
plant capability has improved to 120 MMcf/d from previous levels of
95 MMcf/d.
- In 2019, Canadian Natural used the equivalent of approximately
44% of corporate annual natural gas production within its
operations, providing a natural hedge from the challenging Western
Canadian natural gas price environment. Approximately 34% of the
Company's 2019 natural gas production was exported to other North
American markets and sold internationally, while the remaining 22%
of the Company's 2019 natural gas production was exposed to
AECO/Station 2 pricing.
International Exploration and
Production
| |
Three Months Ended |
Year Ended |
| |
|
|
|
|
|
| |
Dec 31 2019 |
Sep 30 2019 |
Dec 31 2018 |
Dec 31 2019 |
Dec 31 2018 |
|
Crude oil production (bbl/d) |
|
|
|
|
|
|
North Sea |
30,860 |
|
27,454 |
|
21,071 |
|
27,919 |
|
23,965 |
|
|
Offshore Africa |
18,495 |
|
21,227 |
|
22,185 |
|
21,371 |
|
19,662 |
|
| Natural gas production
(MMcf/d) |
|
|
|
|
|
|
North Sea |
25 |
|
20 |
|
22 |
|
24 |
|
32 |
|
|
Offshore Africa |
19 |
|
24 |
|
25 |
|
24 |
|
26 |
|
| Net wells targeting crude
oil |
— |
|
3.0 |
|
1.1 |
|
5.5 |
|
5.6 |
|
| Net successful wells
drilled |
— |
|
3.0 |
|
1.1 |
|
5.5 |
|
5.6 |
|
|
Success rate |
— |
|
100 |
% |
100 |
% |
100 |
% |
100 |
% |
- International E&P crude oil production volumes were strong
in 2019, averaging 49,290 bbl/d, an increase of 13% over 2018
levels. The increase over 2018 was primarily due to strong
performance from wells drilled in the North Sea and at Baobab,
partially offset by natural field declines.
- International production volumes benefit from premium Brent
pricing, generating significant free cash flow for the Company.
- In the North Sea, crude oil production volumes of 27,919 bbl/d
were achieved in 2019, a 16% increase over 2018 levels, reflecting
volumes from new wells after a successful 2019 drilling program of
5 gross (4.9 net) wells.
- 2019 operating costs in the North Sea decreased by 9% from 2018
levels, averaging $36.39/bbl (£21.27/bbl), reflecting increased
production volumes, together with fluctuations in the Canadian
dollar.
- The North Sea 2020 drilling program, targeting 6 gross (5.9
net) producer and 2 gross (1.9 net) injector wells, commenced in
Q1/20 at Ninian.
- Offshore Africa crude oil production volumes in 2019 averaged
21,371 bbl/d, a 9% increase over 2018 levels, primarily as a result
of production from wells drilled in late 2018 and early 2019 at
Baobab, partially offset by natural field declines.
- Côte d'Ivoire crude oil operating costs decreased 16% from 2018
levels, averaging $11.21/bbl (US$8.45/bbl) in 2019, primarily due
to timing of liftings from various fields that have different cost
structures.
- The Company is targeting planned turnaround activities at
Espoir in Q1/20 and at Baobab in Q2/20.
- Following the previously announced discovery of significant gas
condensate in South Africa, where Canadian Natural has a 20%
working interest, the operator commenced a comprehensive 3D and 2D
seismic acquisition program in Q4/19, with targeted completion in
Q2/20.
- The operator has contracted a rig with targeted spud of an
exploration well in Q2/20. Depending on the results of this
well, the operator may drill an additional well in 2020 to further
define volumes and deliverability.
- Canadian Natural is carried to a maximum gross cost of
approximately US$300 million.
North America Oil Sands Mining and
Upgrading
| |
Three Months Ended |
Year Ended |
| |
|
|
|
|
|
| |
Dec 31 2019 |
Sep 30 2019 |
Dec 31 2018 |
Dec 31 2019 |
Dec 31 2018 |
|
Synthetic crude oil production (bbl/d) (1) (2) |
357,856 |
|
432,203 |
|
447,048 |
|
395,133 |
|
426,190 |
|
(1) SCO production before royalties and excludes volumes
consumed internally as diesel.
(2) Consists of heavy and light synthetic crude oil
products.
- At the Company's world class Oil Sands Mining and Upgrading
assets, annual production volumes averaged 395,133 bbl/d of SCO in
2019, a decrease of 7% from 2018 levels, reflecting the proactive
piping replacement in one of the hydrogen units at Horizon,
together with the unplanned maintenance at the non-operated
Scotford Upgrader and at Horizon in the first half of the year.
- Effective and efficient operations resulted in annual operating
costs, excluding energy costs, of $3,276 million, a $91 million or
3% decrease from 2018 levels.
- Industry leading annual operating costs averaged $22.56/bbl of
SCO, a 4% increase from 2018 levels primarily reflecting reduced
production volumes together with increased natural gas costs.
- At AOSP, through increased reliability, process improvements
and optimization projects, Canadian Natural increased gross
production capacity at the Albian mines by approximately 40,000
bbl/d to approximately 320,000 bbl/d, representing a 14% increase
in capacity while reducing AOSP operating costs by approximately
34% or $10.00/bbl since the announcement of the acquisition in
2017.
- As part of the Company's overall strategy to maximize value and
enhance margins, the Scotford Upgrader is targeting to increase
capacity to approximately 320,000 bbl/d in Q3/20. This additional
capacity at AOSP will allow for increased flexibility, margin
improvements and can be managed through the Company's curtailment
optimization strategy.
- At the Albian mines, top tier operations combined with
optimization of facilities resulted in record gross bitumen
production averaging approximately 306,000 bbl/d in Q4/19, forming
a part of the Company’s curtailment optimization strategy during
the turnaround and the proactive piping replacement at
Horizon.
- In Q4/19 at Horizon, as a result of Canadian Natural's industry
leading integrity program, the Company identified the need to
replace piping on one of the hydrogen manufacturing units during
post turnaround start-up. To ensure increased reliability of
operations and as part of the Company's curtailment optimization
strategy, the Company made the proactive decision to replace the
piping, at which time Horizon ran at restricted rates of
approximately 170,500 bbl/d, and production impacts were managed as
part of the Company's curtailment optimization strategy. The
proactive piping replacement was completed for approximately $65
million and production resumed to full rates on January 19, 2020.
- Record monthly production of approximately 262,600 bbl/d of SCO
was achieved at Horizon in February 2020 as a result of continued
high utilization, safe, steady and reliable operations.
- At the non-operated Scotford Upgrader, a planned 55 day
turnaround is targeted to start in April 2020, at which time the
Upgrader will run at gross restricted rates of approximately
160,000 bbl/d of SCO. Timing of planned pit stop activities at the
AOSP mines is aligned with the planned turnaround at the Scotford
Upgrader. Production impacts are reflected in the Company's annual
2020 guidance and will be managed as part of the Company's
curtailment optimization strategy.
- The Company continues to progress engineering work on a prudent
basis for potential expansion opportunities at Horizon to increase
reliability and lower costs, targeting to add production of 75,000
bbl/d to 95,000 bbl/d. The final investment decision on these
opportunities will not be made until there is greater clarity on
market access.
MARKETING
| |
|
Three Months Ended |
|
|
Year Ended |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dec 31 2019 |
|
Sep 30 2019 |
|
Dec 31 2018 |
|
|
Dec 31 2019 |
|
Dec 31 2018 |
| Crude oil and NGLs
pricing |
|
|
|
|
|
|
|
|
|
|
|
|
WTI benchmark price (US$/bbl) (1) |
|
$ |
56.96 |
|
|
$ |
56.45 |
|
|
$ |
58.83 |
|
|
|
$ |
57.04 |
|
|
$ |
64.78 |
|
|
WCS heavy differential as a percentage of WTI (%) (2) |
|
28 |
% |
|
22 |
% |
|
67 |
% |
|
|
22 |
% |
|
41 |
% |
|
SCO price (US$/bbl) |
|
$ |
56.32 |
|
|
$ |
56.87 |
|
|
$ |
37.48 |
|
|
|
$ |
56.35 |
|
|
$ |
58.62 |
|
|
Condensate benchmark pricing (US$/bbl) |
|
$ |
52.99 |
|
|
$ |
52.00 |
|
|
$ |
45.27 |
|
|
|
$ |
52.84 |
|
|
$ |
60.98 |
|
|
Average realized pricing before risk management (C$/bbl) (3) |
|
$ |
49.60 |
|
|
$ |
55.19 |
|
|
$ |
25.95 |
|
|
|
$ |
55.08 |
|
|
$ |
46.92 |
|
| Natural gas pricing |
|
|
|
|
|
|
|
|
|
|
|
|
AECO benchmark price (C$/GJ) |
|
$ |
2.21 |
|
|
$ |
0.99 |
|
|
$ |
1.80 |
|
|
|
$ |
1.54 |
|
|
$ |
1.45 |
|
|
Average realized pricing before risk management (C$/Mcf) |
|
$ |
2.64 |
|
|
$ |
1.64 |
|
|
$ |
3.46 |
|
|
|
$ |
2.34 |
|
|
$ |
2.61 |
|
(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.
- Mainline enhancements of approximately 100,000 bbl/d of
capacity were completed in December 2019, increasing pipeline
capacity out of the WCSB.
- Additional pipeline egress of approximately 190,000 bbl/d to
move incremental crude oil production out of the WCSB is targeted
to be added by industry over the near term, providing opportunities
for the Company before new export pipelines are constructed:
- Additional Mainline enhancements of 50,000 bbl/d of capacity is
targeted in 2020.
- Express pipeline optimization expansion is targeted to add
approximately 50,000 bbl/d of capacity in 2020.
- The NWR Refinery is targeted to add approximately 40,000 bbl/d
of incremental crude oil conversion capacity. Upon start-up of the
Gasifier and LC Finer units, the refinery will process a total of
approximately 80,000 bbl/d of diluted bitumen, increasing effective
takeaway capacity out of the WCSB.
- The Company has a 50% interest in the NWR Partnership. For
updates on the project, please refer to:
https://nwrsturgeonrefinery.com/whats-happening/news/.
- Base Keystone export pipeline optimization expansion of
approximately 50,000 bbl/d was recently announced. In Q3/19,
Canadian Natural committed to approximately 10,000 bbl/d of the
expansion, which is targeted to be available in 2020.
- Crude by rail volumes continue to be strong at approximately
350,000 bbl/d for the month of December 2019.
- 2019 differentials between WCS and WTI benchmark pricing
narrowed from 2018 levels following the Government of Alberta's
announcement of mandatory curtailments of crude oil production that
came into effect January 1, 2019.
- AECO natural gas prices increased in Q4/19 from Q3/19 and Q4/18
levels, reflecting additional egress capability, seasonal demand
factors and the impact of the TC Energy Temporary Service Protocol
in Q4/19.
GOVERNANCE
- As part of the Company's ongoing Governance process, Steve W.
Laut, who was appointed Executive Vice-Chairman in March 2018 after
serving as President for the previous 13 years, has decided to step
back from the day to day operations of the Company at or before the
Company's Annual General Meeting ("AGM") in May 2020. Mr. Laut will
remain on the Board of Directors (the "Board") and stand for
re-election at the 2020 AGM.
- As previously announced Dr. M. Elizabeth Cannon was appointed
to the Board effective November 5, 2019 and will stand for election
at the 2020 AGM. Dr. Cannon has many significant accomplishments
with the most recent being President Emerita and Professor of
Engineering at the University of Calgary having previously served
at the University of Calgary as Dean of the Schulich School of
Engineering from 2006-2010, President and Vice Chancellor from 2010
to 2018.
- Timothy W. Faithfull will be stepping down from the Board in
accordance with the Company's mandatory retirement policy. Mr.
Faithfull has been a valued member of the Board of Directors,
serving as a member since November 2010.
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 1,098,957 BOE/d in 2019, with approximately
98% of total production located in G7 countries.
- Canadian Natural maintains a balance of products with 2019
production mix on a BOE/d basis of 49% light crude oil and SCO
blends, 28% heavy crude oil blends and 23% natural gas.
- Canadian Natural delivered record annual free cash flow of
$4,620 million after net capital expenditures of $3,904 million and
dividend requirements of $1,743 million, and excluding Devon Canada
asset acquisition costs, reflecting the strength of the Company's
long life low decline asset base and effective and efficient
operations.
- Balance sheet strength remains a focus as year end 2019
long-term debt totaled $20,982 million, comparable to Q1/19 levels
prior to the Devon Canada asset acquisition, and debt to book
capitalization strengthened to 37.3% from 39.1% at year end 2018
while debt to adjusted EBITDA improved to 1.9x from 2.0x at year
end 2018. During 2019, the Company executed on the following:
- The Company repaid $500 million of 3.05% notes and $500 million
of 2.60% notes in Q2/19 and Q4/19, respectively.
- The Company fully repaid and cancelled the remaining balance of
the $1,800 million non-revolving term loan credit facility that was
used to finance the AOSP acquisition, ahead of its maturity in May
2020.
- In Q4/19, the Company extended the $2,425 million revolving
syndicated credit facility scheduled to mature in June 2021 to June
2023. Additionally, the $2,200 million non-revolving term credit
facility, originally due in October 2020, was extended to February
2023 and increased by $450 million to $2,650 million.
- Canadian Natural maintains strong financial stability and
liquidity represented by cash balances, and committed and demand
bank credit facilities. At December 31, 2019, the Company had
approximately $4,876 million of available liquidity, including cash
and cash equivalents, an increase of approximately $52 million and
$196 million over 2018 and Q3/19 levels respectively.
- Canadian Natural is committed to returns to shareholders,
returning a total of $2,684 million to shareholders in 2019, $1,743
million by way of dividends and $941 million by way of share
repurchases.
- Share repurchases for cancellation totaled 25,900,000 common
shares at a weighted average share price of $36.32.
- Subsequent to year end, up to and including March 4, 2020, the
Company executed on additional share repurchases for cancellation
of 6,600,000 common shares at a weighted average share price of
$39.41.
- Returns to shareholders have been significant as Canadian
Natural returned approximately $6.2 billion by way of dividends and
share repurchases between January 1, 2018 and March 4, 2020.
- 2019 dividends increased 12% from 2018 levels to $1.50 per
share. Subsequent to year end, the Company declared a quarterly
dividend increase of 13% to $0.425 per share, payable on April 1,
2020. The increase marks the 20th consecutive year that the Company
has increased its dividend, reflecting the Board of Directors'
confidence in Canadian Natural's strength and robustness of
the Company's assets and its ability to generate significant and
sustainable free cash flow.
- In addition to the Company's 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 December 31, 2019, these
financial levers include the Company’s third party equity
investments of $490 million, and cross currency swaps with a total
value of $290 million.
OUTLOOK
The Company targets annual 2020 production
levels to average between 910,000 bbl/d and 970,000 bbl/d of crude
oil and NGLs and between 1,360 MMcf/d and 1,420 MMcf/d of natural
gas, before royalties. 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 2020 capital
expenditures are targeted to be approximately $3.95 billion.
2019 YEAR-END RESERVES
Determination of Reserves
For the year ended December 31, 2019, 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 evaluation
and review was conducted and prepared 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.
Summary of Company Gross Reserves
As of December 31, 2019 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 |
97 |
|
103 |
|
235 |
|
653 |
|
6,219 |
|
3,150 |
|
92 |
|
7,925 |
|
|
Developed Non-Producing |
12 |
|
14 |
|
— |
|
14 |
|
— |
|
162 |
|
6 |
|
72 |
|
|
Undeveloped |
56 |
|
85 |
|
58 |
|
1,771 |
|
133 |
|
3,083 |
|
177 |
|
2,794 |
|
| Total
Proved |
165 |
|
202 |
|
293 |
|
2,438 |
|
6,352 |
|
6,395 |
|
275 |
|
10,791 |
|
|
Probable |
64 |
|
91 |
|
132 |
|
1,670 |
|
545 |
|
3,118 |
|
133 |
|
3,156 |
|
|
Total Proved plus Probable |
229 |
|
293 |
|
425 |
|
4,108 |
|
6,897 |
|
9,513 |
|
408 |
|
13,947 |
|
| |
|
|
|
|
|
|
|
|
|
North Sea |
|
|
|
|
|
|
|
|
|
Proved |
|
|
|
|
|
|
|
|
|
Developed Producing |
37 |
|
|
|
|
|
10 |
|
|
39 |
|
|
Developed Non-Producing |
4 |
|
|
|
|
|
1 |
|
|
4 |
|
|
Undeveloped |
68 |
|
|
|
|
|
5 |
|
|
69 |
|
| Total
Proved |
109 |
|
|
|
|
|
16 |
|
|
112 |
|
|
Probable |
67 |
|
|
|
|
|
5 |
|
|
68 |
|
|
Total Proved plus Probable |
176 |
|
|
|
|
|
21 |
|
|
179 |
|
| |
|
|
|
|
|
|
|
|
|
Offshore Africa |
|
|
|
|
|
|
|
|
|
Proved |
|
|
|
|
|
|
|
|
|
Developed Producing |
32 |
|
|
|
|
|
29 |
|
|
37 |
|
|
Developed Non-Producing |
12 |
|
|
|
|
|
6 |
|
|
13 |
|
|
Undeveloped |
39 |
|
|
|
|
|
13 |
|
|
41 |
|
| Total
Proved |
83 |
|
|
|
|
|
48 |
|
|
91 |
|
|
Probable |
31 |
|
|
|
|
|
24 |
|
|
35 |
|
|
Total Proved plus Probable |
114 |
|
|
|
|
|
72 |
|
|
126 |
|
| |
|
|
|
|
|
|
|
|
|
Total Company |
|
|
|
|
|
|
|
|
|
Proved |
|
|
|
|
|
|
|
|
|
Developed Producing |
166 |
|
103 |
|
235 |
|
653 |
|
6,219 |
|
3,189 |
|
92 |
|
8,001 |
|
|
Developed Non-Producing |
28 |
|
14 |
|
— |
|
14 |
|
— |
|
169 |
|
6 |
|
90 |
|
|
Undeveloped |
163 |
|
85 |
|
58 |
|
1,771 |
|
133 |
|
3,101 |
|
177 |
|
2,903 |
|
| Total
Proved |
357 |
|
202 |
|
293 |
|
2,438 |
|
6,352 |
|
6,460 |
|
275 |
|
10,993 |
|
|
Probable |
162 |
|
91 |
|
132 |
|
1,670 |
|
545 |
|
3,147 |
|
133 |
|
3,258 |
|
|
Total Proved plus Probable |
519 |
|
293 |
|
425 |
|
4,108 |
|
6,897 |
|
9,607 |
|
408 |
|
14,252 |
|
Reconciliation of Company Gross Reserves
As of December 31, 2019 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, 2018 |
194 |
|
182 |
|
305 |
|
1,540 |
|
6,091 |
|
6,597 |
|
267 |
|
9,679 |
|
| Discoveries |
— |
|
— |
|
— |
|
— |
|
— |
|
— |
|
— |
|
— |
|
| Extensions |
3 |
|
6 |
|
— |
|
17 |
|
385 |
|
112 |
|
11 |
|
440 |
|
| Infill Drilling |
5 |
|
5 |
|
— |
|
— |
|
— |
|
206 |
|
8 |
|
52 |
|
| Improved Recovery |
— |
|
— |
|
— |
|
237 |
|
— |
|
2 |
|
— |
|
238 |
|
| Acquisitions |
2 |
|
46 |
|
— |
|
769 |
|
— |
|
35 |
|
1 |
|
823 |
|
| Dispositions |
— |
|
— |
|
— |
|
— |
|
— |
|
— |
|
— |
|
— |
|
| Economic Factors |
(3 |
) |
(3 |
) |
(3 |
) |
— |
|
— |
|
(228 |
) |
(5 |
) |
(53 |
) |
| Technical Revisions |
(16 |
) |
(3 |
) |
12 |
|
(64 |
) |
20 |
|
198 |
|
11 |
|
(8 |
) |
| Production |
(19 |
) |
(30 |
) |
(21 |
) |
(61 |
) |
(144 |
) |
(527 |
) |
(16 |
) |
(380 |
) |
| December 31,
2019 |
165 |
|
202 |
|
293 |
|
2,438 |
|
6,352 |
|
6,395 |
|
275 |
|
10,791 |
|
| |
|
|
|
|
|
|
|
|
| North Sea |
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
| December 31, 2018 |
119 |
|
|
|
|
|
27 |
|
|
124 |
|
| Discoveries |
— |
|
|
|
|
|
— |
|
|
— |
|
| Extensions |
— |
|
|
|
|
|
— |
|
|
— |
|
| Infill Drilling |
— |
|
|
|
|
|
— |
|
|
— |
|
| Improved Recovery |
— |
|
|
|
|
|
— |
|
|
— |
|
| Acquisitions |
— |
|
|
|
|
|
— |
|
|
— |
|
| Dispositions |
— |
|
|
|
|
|
— |
|
|
— |
|
| Economic Factors |
(2 |
) |
|
|
|
|
— |
|
|
(2 |
) |
| Technical Revisions |
2 |
|
|
|
|
|
(2 |
) |
|
2 |
|
| Production |
(10 |
) |
|
|
|
|
(9 |
) |
|
(12 |
) |
| December 31,
2019 |
109 |
|
|
|
|
|
16 |
|
|
112 |
|
| |
|
|
|
|
|
|
|
|
| Offshore Africa |
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
| December 31, 2018 |
86 |
|
|
|
|
|
28 |
|
|
90 |
|
| Discoveries |
— |
|
|
|
|
|
— |
|
|
— |
|
| Extensions |
— |
|
|
|
|
|
— |
|
|
— |
|
| Infill Drilling |
— |
|
|
|
|
|
— |
|
|
— |
|
| Improved Recovery |
— |
|
|
|
|
|
— |
|
|
— |
|
| Acquisitions |
— |
|
|
|
|
|
— |
|
|
— |
|
| Dispositions |
— |
|
|
|
|
|
— |
|
|
— |
|
| Economic Factors |
— |
|
|
|
|
|
— |
|
|
— |
|
| Technical Revisions |
5 |
|
|
|
|
|
29 |
|
|
10 |
|
| Production |
(8 |
) |
|
|
|
|
(9 |
) |
|
(9 |
) |
| December 31,
2019 |
83 |
|
|
|
|
|
48 |
|
|
91 |
|
| |
|
|
|
|
|
|
|
|
| Total Company |
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
| December 31, 2018 |
399 |
|
182 |
|
305 |
|
1,540 |
|
6,091 |
|
6,652 |
|
267 |
|
9,893 |
|
| Discoveries |
— |
|
— |
|
— |
|
— |
|
— |
|
— |
|
— |
|
— |
|
| Extensions |
3 |
|
6 |
|
— |
|
17 |
|
385 |
|
112 |
|
11 |
|
440 |
|
| Infill Drilling |
5 |
|
5 |
|
— |
|
— |
|
— |
|
206 |
|
8 |
|
52 |
|
| Improved Recovery |
— |
|
— |
|
— |
|
237 |
|
— |
|
2 |
|
— |
|
238 |
|
| Acquisitions |
2 |
|
46 |
|
— |
|
769 |
|
— |
|
35 |
|
1 |
|
823 |
|
| Dispositions |
— |
|
— |
|
— |
|
— |
|
— |
|
— |
|
— |
|
— |
|
| Economic Factors |
(5 |
) |
(3 |
) |
(3 |
) |
— |
|
— |
|
(228 |
) |
(5 |
) |
(54 |
) |
| Technical Revisions |
(9 |
) |
(3 |
) |
12 |
|
(64 |
) |
20 |
|
225 |
|
11 |
|
3 |
|
| Production |
(37 |
) |
(30 |
) |
(21 |
) |
(61 |
) |
(144 |
) |
(544 |
) |
(16 |
) |
(401 |
) |
| December 31,
2019 |
357 |
|
202 |
|
293 |
|
2,438 |
|
6,352 |
|
6,460 |
|
275 |
|
10,993 |
|
Reconciliation of Company Gross Reserves
As of December 31, 2019 Forecast Prices and
Costs
PROVED PLUS PROBABLE
| 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, 2018 |
268 |
|
252 |
|
445 |
|
3,059 |
|
7,032 |
|
9,633 |
|
397 |
|
13,058 |
|
| Discoveries |
— |
|
— |
|
— |
|
— |
|
— |
|
— |
|
— |
|
— |
|
| Extensions |
4 |
|
12 |
|
— |
|
26 |
|
— |
|
177 |
|
17 |
|
89 |
|
| Infill Drilling |
6 |
|
7 |
|
— |
|
— |
|
— |
|
476 |
|
15 |
|
108 |
|
| Improved Recovery |
— |
|
— |
|
— |
|
329 |
|
— |
|
3 |
|
— |
|
329 |
|
| Acquisitions |
2 |
|
68 |
|
— |
|
955 |
|
— |
|
42 |
|
1 |
|
1,033 |
|
| Dispositions |
— |
|
— |
|
— |
|
— |
|
— |
|
— |
|
— |
|
— |
|
| Economic Factors |
(4 |
) |
(3 |
) |
(3 |
) |
— |
|
— |
|
(266 |
) |
(6 |
) |
(60 |
) |
| Technical Revisions |
(29 |
) |
(12 |
) |
4 |
|
(198 |
) |
9 |
|
(26 |
) |
(1 |
) |
(230 |
) |
| Production |
(19 |
) |
(30 |
) |
(21 |
) |
(61 |
) |
(144 |
) |
(527 |
) |
(16 |
) |
(380 |
) |
| December 31,
2019 |
229 |
|
293 |
|
425 |
|
4,108 |
|
6,897 |
|
9,513 |
|
408 |
|
13,947 |
|
| |
|
|
|
|
|
|
|
|
| North Sea |
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
| December 31, 2018 |
186 |
|
|
|
|
|
38 |
|
|
193 |
|
| Discoveries |
— |
|
|
|
|
|
— |
|
|
— |
|
| Extensions |
— |
|
|
|
|
|
— |
|
|
— |
|
| Infill Drilling |
— |
|
|
|
|
|
— |
|
|
— |
|
| Improved Recovery |
— |
|
|
|
|
|
— |
|
|
— |
|
| Acquisitions |
— |
|
|
|
|
|
— |
|
|
— |
|
| Dispositions |
— |
|
|
|
|
|
— |
|
|
— |
|
| Economic Factors |
— |
|
|
|
|
|
— |
|
|
— |
|
| Technical Revisions |
— |
|
|
|
|
|
(9 |
) |
|
(2 |
) |
| Production |
(10 |
) |
|
|
|
|
(9 |
) |
|
(12 |
) |
| December 31,
2019 |
176 |
|
|
|
|
|
21 |
|
|
179 |
|
| |
|
|
|
|
|
|
|
|
| Offshore Africa |
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
| December 31, 2018 |
121 |
|
|
|
|
|
63 |
|
|
131 |
|
| Discoveries |
— |
|
|
|
|
|
— |
|
|
— |
|
| Extensions |
— |
|
|
|
|
|
— |
|
|
— |
|
| Infill Drilling |
— |
|
|
|
|
|
— |
|
|
— |
|
| Improved Recovery |
— |
|
|
|
|
|
— |
|
|
— |
|
| Acquisitions |
— |
|
|
|
|
|
— |
|
|
— |
|
| Dispositions |
— |
|
|
|
|
|
— |
|
|
— |
|
| Economic Factors |
— |
|
|
|
|
|
— |
|
|
— |
|
| Technical Revisions |
— |
|
|
|
|
|
18 |
|
|
3 |
|
| Production |
(8 |
) |
|
|
|
|
(9 |
) |
|
(9 |
) |
| December 31,
2019 |
114 |
|
|
|
|
|
72 |
|
|
126 |
|
| |
|
|
|
|
|
|
|
|
| Total Company |
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
| December 31, 2018 |
575 |
|
252 |
|
445 |
|
3,059 |
|
7,032 |
|
9,734 |
|
397 |
|
13,382 |
|
| Discoveries |
— |
|
— |
|
— |
|
— |
|
— |
|
— |
|
— |
|
— |
|
| Extensions |
4 |
|
12 |
|
— |
|
26 |
|
— |
|
177 |
|
17 |
|
89 |
|
| Infill Drilling |
6 |
|
7 |
|
— |
|
— |
|
— |
|
476 |
|
15 |
|
108 |
|
| Improved Recovery |
— |
|
— |
|
— |
|
329 |
|
— |
|
3 |
|
— |
|
329 |
|
| Acquisitions |
2 |
|
68 |
|
— |
|
955 |
|
— |
|
42 |
|
1 |
|
1,033 |
|
| Dispositions |
— |
|
— |
|
— |
|
— |
|
— |
|
— |
|
— |
|
— |
|
| Economic Factors |
(4 |
) |
(3 |
) |
(3 |
) |
— |
|
— |
|
(266 |
) |
(6 |
) |
(60 |
) |
| Technical Revisions |
(28 |
) |
(12 |
) |
4 |
|
(198 |
) |
9 |
|
(16 |
) |
(1 |
) |
(228 |
) |
| Production |
(37 |
) |
(30 |
) |
(21 |
) |
(61 |
) |
(144 |
) |
(544 |
) |
(16 |
) |
(401 |
) |
| December 31,
2019 |
519 |
|
293 |
|
425 |
|
4,108 |
|
6,897 |
|
9,607 |
|
408 |
|
14,252 |
|
NOTES TO RESERVES:
- Company Gross reserves are working interest share before
deduction of royalties and excluding any royalty interests.
- Information in the reserves data tables may not add due to
rounding. BOE values and oil and gas metrics may not calculate
exactly due to rounding.
- Forecast pricing assumptions utilized by the Independent
Qualified Reserves Evaluators in the reserves estimates were
provided by Sproule Associates Limited:
|
|
2020 |
2021 |
2022 |
2023 |
2024 |
| Crude oil and
NGL |
|
|
|
|
|
|
WTI at Cushing (US$/bbl) |
61.00 |
|
65.00 |
|
67.00 |
|
68.34 |
|
69.71 |
|
|
Western Canada Select (C$/bbl) |
59.81 |
|
63.98 |
|
63.77 |
|
65.04 |
|
66.34 |
|
|
Canadian Light Sweet (C$/bbl) |
73.84 |
|
78.51 |
|
78.73 |
|
80.30 |
|
81.91 |
|
|
Cromer LSB (C$/bbl) |
73.84 |
|
77.51 |
|
77.73 |
|
79.30 |
|
80.91 |
|
|
Edmonton Pentanes+ (C$/bbl) |
76.32 |
|
80.52 |
|
80.00 |
|
81.68 |
|
83.38 |
|
|
North Sea Brent (US$/bbl) |
65.00 |
|
68.00 |
|
70.00 |
|
71.40 |
|
72.83 |
|
|
Natural gas |
|
|
|
|
|
|
AECO (C$/MMBtu) |
2.04 |
|
2.27 |
|
2.81 |
|
2.89 |
|
2.98 |
|
|
BC Westcoast Station 2 (C$/MMBtu) |
1.54 |
|
1.87 |
|
2.41 |
|
2.49 |
|
2.58 |
|
|
Henry Hub (US$/MMBtu) |
2.80 |
|
3.00 |
|
3.25 |
|
3.32 |
|
3.38 |
|
All prices increase
at a rate of 2%/year after 2024.A foreign exchange rate of 0.7600
US$/C$ for 2020, 0.7700 US$/C$ for 2021 and 0.8000 US$/C$ after
2021 was used in the 2019 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.
- Oil and gas metrics included herein are commonly used in the
crude 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.
- Reserves additions and revisions are comprised of all
categories of Company Gross reserves changes, exclusive of
production.
- Reserves replacement or Production replacement ratio is the
Company Gross reserves additions and revisions, for the relevant
reserves category, divided by the Company Gross production in the
same period.
- Reserves Life Index is based on the amount for the relevant
reserves category divided by the 2020 proved developed producing
production forecast prepared by the Independent Qualified Reserves
Evaluators.
- Finding, Development and Acquisition ("FD&A") costs
excluding changes in Future Development Costs ("FDC") are
calculated by dividing the sum of total exploration, development
and acquisition capital costs incurred in 2019 by the sum of total
additions and revisions for the relevant reserves category.
- FD&A costs including changes in FDC are calculated by
dividing the sum of total exploration, development and acquisition
capital costs incurred in 2019 and net changes in FDC from December
31, 2018 to December 31, 2019 by the sum of total additions and
revisions for the relevant reserves category. FDC excludes all
abandonment, decommissioning and reclamation costs.
- Abandonment, decommissioning and reclamation ("ADR") costs
included in the calculation of the Future Net Revenue (FNR) for
2019 consist of both the Company's total Asset Retirement
Obligation ("ARO"), before inflation and discounting, for
development existing as at December 31, 2019 and forecast estimates
of ADR costs attributable to future development activity.
ADVISORY
Special Note Regarding Forward-Looking
Statements
Certain statements relating to Canadian Natural
Resources Limited (the "Company") in this document or documents
incorporated herein by reference constitute forward-looking
statements or information (collectively referred to herein as
"forward-looking statements") within the meaning of applicable
securities legislation. Forward-looking statements can be
identified by the words "believe", "anticipate", "expect", "plan",
"estimate", "target", "continue", "could", "intend", "may",
"potential", "predict", "should", "will", "objective", "project",
"forecast", "goal", "guidance", "outlook", "effort", "seeks",
"schedule", "proposed" or expressions of a similar nature
suggesting future outcome or statements regarding an outlook.
Disclosure related to expected future commodity pricing, forecast
or anticipated production volumes, royalties, production expenses,
capital expenditures, income tax expenses and other guidance
provided throughout this press release and the Company's
Management’s Discussion and Analysis ("MD&A") of the financial
condition and results of operations of the Company, constitute
forward-looking statements. Disclosure of plans relating to and
expected results of existing and future developments, including but
not limited to the Horizon Oil Sands ("Horizon"), the Athabasca Oil
Sands Project ("AOSP"), Primrose thermal projects, the Pelican Lake
water and polymer flood project, the Kirby Thermal Oil Sands
Project, the Jackfish Thermal Oil Sands Project, the timing and
future operations of the North West Redwater bitumen upgrader and
refinery, construction by third parties of new, or expansion of
existing pipeline capacity or other means of transportation of
bitumen, crude oil, natural gas, natural gas liquids ("NGLs") or
synthetic crude oil ("SCO") that the Company may be reliant upon to
transport its products to market, and the development and
deployment of technology and technological innovations also
constitute forward-looking statements. These forward-looking
statements are based on annual budgets and multi-year forecasts,
and are reviewed and revised throughout the year as necessary in
the context of targeted financial ratios, project returns, product
pricing expectations and balance in project risk and time horizons.
These statements are not guarantees of future performance and are
subject to certain risks. The reader should not place undue
reliance on these forward-looking statements as there can be no
assurances that the plans, initiatives or expectations upon which
they are based will occur.
In addition, statements relating to "reserves"
are deemed to be forward-looking statements as they involve the
implied assessment based on certain estimates and assumptions that
the reserves described can be profitably produced in the future.
There are numerous uncertainties inherent in estimating quantities
of proved and proved plus probable crude oil, natural gas and NGLs
reserves and in projecting future rates of production and the
timing of development expenditures. The total amount or timing of
actual future production may vary significantly from reserves and
production estimates.
The forward-looking statements are based on
current expectations, estimates and projections about the Company
and the industry in which the Company operates, which speak only as
of the date such statements were made or as of the date of the
report or document in which they are contained, and are subject to
known and unknown risks and uncertainties that could cause the
actual results, performance or achievements of the Company to be
materially different from any future results, performance or
achievements expressed or implied by such forward-looking
statements. Such risks and uncertainties include, among others:
general economic and business conditions which will, among other
things, impact demand for and market prices of the Company’s
products; volatility of and assumptions regarding crude oil and
natural gas prices; fluctuations in currency and interest rates;
assumptions on which the Company’s current guidance is based;
economic conditions in the countries and regions in which the
Company conducts business; political uncertainty, including actions
of or against terrorists, insurgent groups or other conflict
including conflict between states; industry capacity; ability of
the Company to implement its business strategy, including
exploration and development activities; impact of competition; the
Company’s defense of lawsuits; availability and cost of seismic,
drilling and other equipment; ability of the Company and its
subsidiaries to complete capital programs; the Company’s and its
subsidiaries’ ability to secure adequate transportation for its
products; unexpected disruptions or delays in the 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 and
maintain its thermal and oil sands mining projects; operating
hazards and other difficulties inherent in the exploration for and
production and sale of crude oil and natural gas and in mining,
extracting or upgrading the Company’s bitumen products;
availability and cost of financing; the Company’s and its
subsidiaries’ success of exploration and development activities and
its ability to replace and expand crude oil and natural gas
reserves; timing and success of integrating the business and
operations of acquired companies and assets; production levels;
imprecision of reserves estimates and estimates of recoverable
quantities of crude oil, natural gas and NGLs not currently
classified as proved; actions by governmental authorities
(including production curtailments mandated by the Government of
Alberta); government regulations and the expenditures required to
comply with them (especially safety and environmental laws and
regulations and the impact of climate change initiatives on capital
expenditures and production expenses); asset retirement
obligations; the adequacy of the Company’s provision for taxes; and
other circumstances affecting revenues and expenses.
The Company’s operations have been, and in the
future may be, affected by political developments and by national,
federal, provincial, state and local laws and regulations such as
restrictions on production, changes in taxes, royalties and other
amounts payable to governments or governmental agencies, price or
gathering rate controls and environmental protection regulations.
Should one or more of these risks or uncertainties materialize, or
should any of the Company’s assumptions prove incorrect, actual
results may vary in material respects from those projected in the
forward-looking statements. The impact of any one factor on a
particular forward-looking statement is not determinable with
certainty as such factors are dependent upon other factors, and the
Company’s course of action would depend upon its assessment of the
future considering all information then available.
Readers are cautioned that the foregoing list of
factors is not exhaustive. Unpredictable or unknown factors not
discussed in this press release or the Company's MD&A could
also have adverse effects on forward-looking statements. Although
the Company believes that the expectations conveyed by the
forward-looking statements are reasonable based on information
available to it on the date such forward-looking statements are
made, no assurances can be given as to future results, levels of
activity and achievements. All subsequent forward-looking
statements, whether written or oral, attributable to the Company or
persons acting on its behalf are expressly qualified in their
entirety by these cautionary statements. Except as required by
applicable law, the Company assumes no obligation to update
forward-looking statements in this press release or the Company's
MD&A, whether as a result of new information, future events or
other factors, or the foregoing factors affecting this information,
should circumstances or the Company’s estimates or opinions
change.
Special Note Regarding non-GAAP Financial
Measures
This press release includes references to
financial measures commonly used in the crude oil and natural gas
industry, such as: adjusted net earnings (loss) from operations;
adjusted funds flow (previously referred to as funds flow from
operations) and net capital expenditures. These financial measures
are not defined by International Financial Reporting Standards
("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), cash flows from operating
activities, and cash flows used in investing activities, as
determined in accordance with IFRS, as an indication of the
Company's performance.
Adjusted net earnings (loss) from operations is
a non-GAAP measure that represents net earnings (loss) as presented
in the Company's consolidated Statements of Earnings (Loss),
adjusted for the after-tax effects of certain items of a non-
operational nature. The Company considers adjusted net earnings
(loss) from operations a key measure in evaluating its performance,
as it demonstrates the Company's ability to generate after-tax
operating earnings from its core business areas. The reconciliation
“Adjusted Net Earnings (Loss) from Operations, as Reconciled to Net
Earnings (Loss)" is presented in the Company’s MD&A.
Adjusted funds flow (previously referred to as
funds flow from operations) is a non-GAAP measure that represents
cash flows from operating activities as presented in the Company's
consolidated Statements of Cash Flows, adjusted for the net change
in non-cash working capital, abandonment expenditures and movements
in other long-term assets, including the unamortized cost of the
share bonus program and prepaid cost of service tolls. The
Company considers adjusted funds flow a key measure as it
demonstrates the Company’s ability to generate the cash flow
necessary to fund future growth through capital investment and to
repay debt. The reconciliation “Adjusted Funds Flow, as Reconciled
to Cash Flows from Operating Activities” is presented in the
Company’s MD&A.
Net capital expenditures is a non-GAAP measure
that represents cash flows used in investing activities as
presented in the Company's consolidated Statements of Cash Flows,
adjusted for the net change in non-cash working capital, investment
in other long-term assets, share consideration in business
acquisitions and abandonment expenditures. The Company considers
net capital expenditures a key measure as it provides an
understanding of the Company’s capital spending activities in
comparison to the Company's annual capital budget. The
reconciliation “Net Capital Expenditures, as Reconciled to Cash
Flows used in Investing Activities” is presented in the Net Capital
Expenditures section of the Company’s MD&A.
Free cash flow is a non-GAAP measure that
represents cash flows from operating activities as presented in the
Company's consolidated Statements of Cash Flows, adjusted for the
net change in non-cash working capital from operating activities,
abandonment, certain movements in other long-term assets, less net
capital expenditures and dividends on common shares. The Company
considers free cash flow a key measure in demonstrating the
Company’s ability to generate cash flow to fund future growth
through capital investment, pay returns to shareholders, and to
repay debt.
Adjusted EBITDA is a non-GAAP measure that
represents net earnings (loss) as presented in the Company's
consolidated Statements of Earnings (Loss), adjusted for interest,
taxes, depletion, depreciation and amortization, stock based
compensation expense (recovery), unrealized risk management
gains (losses), unrealized foreign exchange gains (losses), and
accretion of the Company’s asset retirement obligation. The Company
considers adjusted EBITDA a key measure in evaluating its operating
profitability by excluding non-cash items.
Debt to adjusted EBITDA is a non-GAAP measure
that is derived as the current and long-term portions of long-term
debt, divided by the 12 month trailing Adjusted EBITDA, as defined
above. The Company considers this ratio to be a key measure in
evaluating the Company's ability to pay off its debt.
Debt to book capitalization is a non-GAAP
measure that is derived as net current and long-term debt, divided
by the book value of common shareholders' equity plus net current
and long-term debt. The Company considers this ratio to be a key
measure in evaluating the Company's ability to pay off its
debt.
Available liquidity is a non-GAAP measure that
is derived as cash and cash equivalents, total bank and term credit
facilities, less amounts drawn on the bank and credit facilities
including under the commercial paper program. The Company considers
available liquidity a key measure in evaluating the sustainability
of the Company’s operations and ability to fund future growth. See
note 8 - Long-term Debt in the Company’s consolidated financial
statements.
Special Note Regarding Currency, Financial Information
and Production
This press release should be read in conjunction
with the Company's MD&A and unaudited interim consolidated
financial statements for the three months and year ended
December 31, 2019 and the MD&A and the audited
consolidated financial statements of the Company for the year ended
December 31, 2018. All dollar amounts are referenced in
millions of Canadian dollars, except where noted otherwise. The
Company’s unaudited interim consolidated financial statements for
the three months and year ended December 31, 2019 and the
Company's MD&A have been prepared in accordance with IFRS as
issued by the International Accounting Standards Board ("IASB").
Changes in the Company's accounting policies in accordance with
IFRS, including the adoption of IFRS 16 "Leases" on January 1,
2019, are discussed in the "Changes in Accounting Policies" section
of the Company's MD&A. In accordance with the new IFRS 16
"Leases" standard, comparative period balances in 2018 reported in
the Company's MD&A have not been restated.
Production volumes and per unit statistics are
presented throughout the Company's MD&A on a "before royalties"
or "company gross" basis, and realized prices are net of blending
and feedstock costs and exclude the effect of risk management
activities. In addition, reference is made to crude oil and natural
gas in common units called barrel of oil equivalent ("BOE"). A BOE
is derived by converting six thousand cubic feet ("Mcf") of natural
gas to one barrel ("bbl") of crude oil (6 Mcf:1 bbl). This
conversion may be misleading, particularly if used in isolation,
since the 6 Mcf:1 bbl ratio is based on an energy equivalency
conversion method primarily applicable at the burner tip and does
not represent a value equivalency at the wellhead. In comparing the
value ratio using current crude oil prices relative to natural gas
prices, the 6 Mcf:1 bbl conversion ratio may be misleading as an
indication of value. In addition, for the purposes of this
MD&A, crude oil is defined to include the following
commodities: light and medium crude oil, primary heavy crude oil,
Pelican Lake heavy crude oil, bitumen (thermal oil), and SCO.
Production on an "after royalties" or "company net" basis is also
presented in the Company's MD&A for information purposes
only.
Additional information relating to the Company,
including its Annual Information Form for the year ended
December 31, 2018, is available on SEDAR at www.sedar.com, and
on EDGAR at www.sec.gov. Detailed guidance on production levels,
capital expenditures and production expenses can be found on the
Company's website at www.cnrl.com. Information on the Company's
website, including such guidance, does not form part of and is not
incorporated by reference in the Company's MD&A.
CONFERENCE CALL
A conference call will be held at 9:00 a.m.
Mountain Time, 11:00 a.m. Eastern Time on Thursday, March 5,
2020.
The North American conference call number is
1-866-521-4909 and the outside North American conference call
number is 001-647-427-2311. Please call in 10 minutes prior to the
call starting time.
An archive of the broadcast will be available
until 6:00 p.m. Mountain Time, Thursday, March 19, 2020. To access
the rebroadcast in North America, dial 1-800-585-8367. Those
outside of North America, dial 001-416-621-4642. The conference
archive ID number is 2279046.
The conference call will also be webcast live
and can be accessed on the home page of our website at
www.cnrl.com.
Canadian Natural is a senior oil and natural gas
production company, with continuing operations in its core areas
located in Western Canada, the U.K. portion of the North Sea and
Offshore Africa.
CANADIAN NATURAL RESOURCES LIMITED
2100, 855 - 2nd Street S.W. Calgary, Alberta, T2P4J8
Phone: 403-514-7777 Email: ir@cnrl.com
www.cnrl.com
STEVE W. LAUT
Executive Vice-Chairman
TIM S. MCKAY
President
MARK A. STAINTHORPE
Chief Financial Officer and Senior Vice-President, Finance
Trading Symbol - CNQ
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