CALGARY, ALBERTA--(Marketwired - Aug. 3, 2017) - Commenting on second quarter 2017 results, Steve Laut,
President of Canadian Natural (TSX:CNQ)(NYSE:CNQ) stated, "Our balanced and diverse portfolio delivered strong results in the
second quarter of 2017. Funds flow from operations was significant at $1.7 billion, a strong result given the downward pressure
on crude oil prices throughout the quarter. The Horizon Phase 2B expansion and acquired Athabasca oil sands volumes drove 27%
growth in crude oil production volumes and 16% growth on a BOE basis, when compared with the second quarter of 2016.
In the quarter, Canadian Natural closed the transformational acquisition of the Athabasca Oil Sands Project ("AOSP"), as our
teams effectively and efficiently transitioned all assets and personnel to Canadian Natural. The closing went as expected as we
took over operatorship of the AOSP mines on June 1, 2017. In our first month of operating the mines results were strong, with
AOSP production of approximately 202,300 bbl/d net to Canadian Natural.
Based upon strong results in the first half of the year, the Company has increased the mid-point of its 2017 annual liquids
and BOE production guidance by 11,000 bbl/d and 3,000 BOE/d respectively, while decreasing its 2017 capital program by
approximately $180 million."
Canadian Natural's Chief Operating Officer, Tim McKay, added, "Results from our strong balanced asset base including
conventional, Horizon and AOSP helped us to achieve record monthly production of over 1,000,000 BOE/d in June 2017. At Horizon,
operations continue to be strong and disciplined, with second quarter production at roughly 191,000 bbl/d of synthetic crude oil
("SCO"), above our second quarter corporate guidance of 180,000 bbl/d to 188,000 bbl/d. Operating costs were once again lower
than targeted at just over $22.00/bbl of SCO, similar to the record levels achieved in the first quarter of 2017."
Canadian Natural's Chief Financial Officer, Corey Bieber, continued, "The Company had another strong quarter with net earnings
of approximately $1.1 billion, an increase of over $800 million from the first quarter of 2017. Year to date free cash flow was
significant, allowing Canadian Natural to reduce debt in the first half of 2017 by roughly $1.2 billion, excluding acquisition
related financing for AOSP and impacts of foreign exchange. We exited with strong liquidity of approximately $3.7 billion at the
end of the quarter.
In the next six months Canadian Natural will reach another inflection point with full periods of production from the Horizon
Phase 3 expansion and the AOSP operations, which will drive positive significant free cash flow growth and result in continued
debt reduction and a balanced capital allocation."
| |
QUARTERLY HIGHLIGHTS
|
| |
|
Three Months Ended |
|
Six Months Ended |
| ($ millions, except per common share amounts) |
|
Jun 30
2017 |
|
Mar 31
2017 |
|
Jun 30
2016 |
|
Jun 30
2017 |
|
Jun 30
2016 |
| Net earnings (loss) |
$ |
1,072 |
$ |
245 |
$ |
(339 |
) |
$ |
1,317 |
$ |
(444 |
) |
| |
Per common share |
- basic |
$ |
0.93 |
$ |
0.22 |
$ |
(0.31 |
) |
$ |
1.16 |
$ |
(0.41 |
) |
| |
|
- diluted |
$ |
0.93 |
$ |
0.22 |
$ |
(0.31 |
) |
$ |
1.16 |
$ |
(0.41 |
) |
| Adjusted net earnings (loss) from operations (1) |
$ |
332 |
$ |
277 |
$ |
(210 |
) |
$ |
609 |
$ |
(753 |
) |
| |
Per common share |
- basic |
$ |
0.29 |
$ |
0.25 |
$ |
(0.19 |
) |
$ |
0.54 |
$ |
(0.69 |
) |
| |
|
- diluted |
$ |
0.29 |
$ |
0.25 |
$ |
(0.19 |
) |
$ |
0.54 |
$ |
(0.69 |
) |
| Funds flow from operations (2) |
$ |
1,726 |
$ |
1,639 |
$ |
938 |
|
$ |
3,365 |
$ |
1,595 |
|
| |
Per common share |
- basic |
$ |
1.50 |
$ |
1.47 |
$ |
0.85 |
|
$ |
2.97 |
$ |
1.45 |
|
| |
|
- diluted |
$ |
1.49 |
$ |
1.46 |
$ |
0.85 |
|
$ |
2.95 |
$ |
1.45 |
|
| Capital expenditures, excluding AOSP acquisition costs (3) |
$ |
889 |
$ |
846 |
$ |
1,158 |
|
$ |
1,735 |
$ |
2,198 |
|
| Total net capital expenditures (3) |
$ |
13,046 |
$ |
846 |
$ |
1,158 |
|
$ |
13,892 |
$ |
2,198 |
|
| |
|
|
|
|
|
|
|
|
|
|
| Daily production, before royalties |
|
|
|
|
|
|
|
|
|
|
| |
Natural gas (MMcf/d) |
|
1,656 |
|
1,673 |
|
1,689 |
|
|
1,664 |
|
1,738 |
|
| |
Crude oil and NGLs (bbl/d) |
|
637,127 |
|
598,113 |
|
502,410 |
|
|
617,728 |
|
524,668 |
|
| |
Equivalent production (BOE/d) (4) |
|
913,171 |
|
876,907 |
|
783,988 |
|
|
895,139 |
|
814,259 |
|
(1) Adjusted net earnings (loss) from operations is a non-GAAP measure that the Company utilizes to evaluate its
performance. The derivation of this measure is discussed in the Management's Discussion and Analysis ("MD&A").
(2) Funds flow from operations (formally cash flow from operations) is a non-GAAP measure that the Company considers key
as it demonstrates the Company's ability to fund capital reinvestment and debt repayment. The derivation of this measure is
discussed in the MD&A.
(3) For additional information and details, refer to the net capital expenditures table in the Company's
MD&A.
(4) A barrel of oil equivalent ("BOE") is derived by converting six thousand cubic feet ("Mcf") of natural gas to one
barrel ("bbl") of crude oil (6 Mcf:1 bbl). This conversion may be misleading, particularly if used in isolation, since the 6
Mcf:1 bbl ratio is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent
a value equivalency at the wellhead. In comparing the value ratio using current crude oil prices relative to natural gas prices,
the 6 Mcf:1 bbl conversion ratio may be misleading as an indication of value.
- Canadian Natural generated funds flow from operations of $1,726 million in Q2/17, an increase of $87 million and $788
million over Q1/17 and Q2/16 levels respectively.
- The Company generated significant free cash flow in Q2/17 of approximately $840 million after net capital expenditures
excluding the Athabasca Oil Sands Project ("AOSP") acquisition expenditures. After further adjusting for quarterly dividend
requirements, approximately $530 million of free cash flow was realized in the quarter, which was largely used to reduce the
Company's debt levels.
- For Q2/17, the Company had net earnings of $1,072 million compared to net earnings of $245 million in Q1/17 and a net loss
of $339 million in Q2/16. The adjusted net earnings from operations was $332 million in Q2/17, an increase of 20% compared to
adjusted net earnings of $277 million in Q1/17 and an increase of $542 million from the adjusted net loss of $210 million in
Q2/16.
- Canadian Natural's corporate crude oil and NGLs production volumes averaged a record 637,127 bbl/d representing 7% and 27%
increases from Q1/17 and Q2/16 levels respectively. Crude oil and NGL production volume increases were primarily due to high
reliability and strong production from the Horizon Phase 2B expansion and one month of production from AOSP in the quarter.
- The Company's corporate production volumes averaged a record 913,171 BOE/d in Q2/17, representing 4% and 16% increases
from Q1/17 and Q2/16 levels, despite continued reliability issues at a third party natural gas facility experienced in the
quarter. The Company achieved record production of approximately 1,063,300 BOE/d in June 2017.
-- A reflection of the Company's continued focus of enhancing returns on capital is evident by the 20% increase in Q2/17
adjusted net earnings over Q1/17, while production increased only 4% over the same period.
-- Based upon strong results in the first half of the year, the Company has increased the mid-point of its 2017 annual liquids
and BOE production guidance by 11,000 bbl/d and 3,000 BOE/d respectively, while decreasing its 2017 capital program by
approximately $180 million.
- Canadian Natural continues to focus on safe, reliable, effective and efficient operations while minimizing the Company's
environmental footprint. Canadian Natural is committed to reducing its GHG emissions. Since 2012 the Company has reduced its
methane emissions by 35%. In addition, Canadian Natural has invested significant capital to capture and sequester CO2. The
Company has carbon capture and sequestration facilities at Horizon, a 70% working interest in the Quest Carbon Capture and
Storage project at Scotford and has carbon capture facilities at its 50% interest in the NWR Refinery targeted for startup in
2018. As a result Canadian Natural will be capturing approximately 1.6 million tonnes of CO2 a year, the equivalent of taking
330,000 motor vehicles off the road annually, making Canadian Natural one of the largest capturer and sequesterer of CO2 of all
crude oil and natural gas producers in the world.
- On May 31, 2017, the Company successfully closed the acquisition of a direct and indirect 70% working interest in the AOSP
and 100% working interest in other heavy crude oil and thermal in situ assets. In total approximately 2,800 employees were
successfully transitioned to Canadian Natural.
-- In May 2017 the Company successfully executed on its funding plan for the AOSP acquisition through accessing debt capital
markets and a syndicated $3.0 billion 3 year term loan facility. Approximately $5.8 billion was raised in the Canadian and US
debt capital markets, with tenors ranging from 3 to 30 years, and a weighted average interest rate of approximately 3.56%, with a
weighted average tenor of approximately 12 years.
-- During Canadian Natural's first month of AOSP ownership, operations were transitioned safely and high reliability was
achieved, resulting in strong production that reached approximately 289,000 bbl/d (202,300 bbl/d net) of AOSP synthetic crude oil
("SCO") in June 2017. A combination of higher production and modest integration savings resulted in operating costs of $27.50/bbl
of upgraded products.
- At Horizon, Q2/17 production was 190,837 bbl/d of SCO, over 6,000 bbl/d of SCO above the midpoint of the Company's
previously issued quarterly guidance, representing an increase of 60% over Q2/16 levels.
-- Through safe, steady and reliable operations and a strong focus on continuous improvement, the Company realized quarterly
average operating costs at Horizon of $22.09/bbl of SCO in Q2/17, consistent with record low operating costs of $22.08/bbl of SCO
in Q1/17 and an 18% reduction from Q2/16 levels.
-- During Q2/17, Canadian Natural continued to advance the Horizon Phase 3 expansion. The expansion is currently ahead of
schedule and costs are trending at the Company's 2017 estimates. Phase 3 reached 96% physical completion as at June 30, 2017 and
will be mechanically complete and ready for tie-in and commissioning with the planned September turnaround.
-- The Company has deferred approximately $315 million of Horizon project capital into 2018 to better plan and execute the
Company's mature fines tailings project, at which time it is expected that learnings and synergies can be leveraged between the
Horizon and AOSP mines to capture potential cost savings.
-- The Company previously announced a potential debottleneck at the fractionation tower after startup of Horizon Phase 2B. The
fractionation tower was identified as a limiting component in exceeding the targeted capacity of 250,000 bbl/d of SCO. It has now
been determined that the capacity of the vacuum distillate unit ("VDU") and diluent recovery unit ("DRU") furnaces will also be
limiting components in exceeding the targeted capacity.
--- A significant amount of process engineering to determine the capacity outcomes of all the critical components of the
upgrading operation was completed at various confidence levels. As a result it is not prudent at present to predict with
confidence, that Horizon will be able to deliver production levels exceeding 250,000 bbl/d of SCO until the Company has actual
throughput through the upgrader and the actual reliability is determined once Phase 3 is operational.
--- The Company is confident that increased reliability and creep capacity volumes will be attainable if work is undertaken on
the fractionator and furnaces and therefore will be undertaking this planned work during the September turnaround, extending the
turnaround from 24 days to 45 days.
--- The total additional work is targeted to require capital of approximately $170 million for Optimization and Reliability
enhancements.
--- The Company's annual 2017 production guidance at Horizon remains unchanged at 170,000 - 184,000 bbl/d, despite the
increase in planned downtime by 21 days. This is due to the strong production results in the first half of 2017.
-- Q2/17 Horizon project capital expenditures were $182 million. The Company has reduced the Horizon 2017 project capital by
$315 million and incorporated $170 million for Optimization and Reliability enhancements to take place during the Q3/17
turnaround. Total annual 2017 Horizon project capital is now targeted to be $910 million and is forecasted to be approximately
$145 million lower than the previously issued 2017 capital guidance. Start-up of Phase 3 is targeted for Q4/17 and is targeted to
bring total Horizon production volumes to 250,000 bbl/d of SCO, which will result in a further step change towards sustainable
funds flow and lower operating costs.
- Thermal in situ operations were strong in Q2/17 with production averaging 105,719 bbl/d, representing a 13% increase from
Q2/16 levels and above the Company's previously issued quarterly guidance. Results were strong given planned turnaround
activities in the quarter at both Primrose and Kirby South.
-- Kirby South, the Company's Steam Assisted Gravity Drainage ("SAGD") project achieved production of 34,649 bbl/d in
Q2/17, despite planned downtime for turnaround activities.
--- Including energy costs, operating costs of $10.28/bbl were achieved in the quarter at Kirby South, in-line with Q2/16
levels and were supported by a strong Steam to Oil Ratio ("SOR") of 2.6.
-- Primrose production was 71,070 bbl/d in Q2/17, despite planned downtime for turnaround activities.
--- The Company's low pressure steamflood at Primrose East continues to be strong, with June 2017 production under steamflood
averaging approximately 32,000 bbl/d.
- Pelican Lake heavy crude oil production of 46,932 bbl/d in Q2/17 was in line with Q1/17 and Q2/16 levels. Operations
continued to be optimized in the quarter, resulting in industry leading operating costs of $6.38/bbl in Q2/17, flat from Q1/17
and a 6% decrease from Q2/16 levels.
- Primary heavy crude oil production averaged 89,345 bbl/d in Q2/17. The Company's proactive decision to reduce its primary
heavy crude oil drilling program in 2015 and the first half of 2016 resulted in production volumes of primary heavy crude oil
declining 14% from Q2/16 levels.
- North America light crude oil and NGL quarterly production averaged 90,806 bbl/d, 1% and 8% increases from Q1/17 and Q2/16
levels respectively. Quarterly operating costs of $13.98/bbl were realized in Q2/17, in line with Q1/17 levels.
- Within the Company's North America natural gas assets, operations continued to be optimized during the quarter with Q2/17
production of 1,603 MMcf/d. Operating costs of $1.17/Mcf were achieved in the quarter, a decrease of 3% from Q1/17 levels.
Production was lower than expected in the quarter due to continued reliability issues at a third party natural gas facility.
During the quarter, the Company averaged production of approximately 52 MMcf/d from this facility, 36 MMcf/d less than the
estimate that was incorporated in the Company's Q2/17 production guidance, and well below both the Q1/17 volumes of approximately
100 MMcf/d and Canadian Natural's productive capability for the plant, which currently exceeds 170 MMcf/d.
- International quarterly crude oil production volumes were within the Company's production guidance and averaged 46,784 bbl/d
in Q2/17, an increase of 2% from Q1/17 levels.
- Canadian Natural maintains significant financial stability and liquidity represented in part by committed bank credit
facilities. In Q2/17 the Company increased its previously existing bank credit facilities by $0.7 billion and at June 30, 2017
had in place $3.7 billion of liquidity.
-- Canadian Natural continues to have significant support from its large and diverse banking group as indicated by extensions
and credit facility increases during the quarter. In Q2/17, the Company's $1.5 billion non-revolving facility was increased to
$2.2 billion and extended from April 2018 to October 2019. Additionally, the Company extended $2.095 billion of the $2.425
billion revolving syndicated credit facility originally maturing in June 2019 to June 2021. The remaining $330 million will
mature in June 2019.
- Canadian Natural declared a quarterly cash dividend on common shares of C$0.275 per share payable on October 1,
2017.
OPERATIONS REVIEW AND CAPITAL ALLOCATION
Canadian Natural has a balanced and diverse portfolio of assets, primarily Canadian-based, with international exposure in the
UK sector of the North Sea and Offshore Africa. Canadian Natural's production is well balanced between light and medium
crude oil, primary heavy crude oil, Pelican Lake heavy crude oil, bitumen and SCO (herein collectively referred to as "crude
oil"), natural gas and NGLs. This balance provides optionality for capital investments, facilitating improved value for the
Company's shareholders.
Underpinning this asset base is long-life, low decline production from Horizon Oil Sands and the AOSP mining and upgrading,
thermal in situ oil sands and Pelican Lake heavy crude oil assets. The combination of low decline, low reserve replacement
costs, and effective and efficient operations means these assets provide substantial and sustainable cash flow throughout the
commodity price cycle.
Augmenting this, Canadian Natural maintains a substantial inventory of low capital exposure projects within its conventional
asset base. These projects can be executed quickly, and, with the right economic conditions, can provide excellent returns and
maximize value for shareholders. Supporting these projects is the Company's undeveloped land base which enables large, repeatable
drilling programs; programs that can be optimized over time. Additionally, by owning and operating most of the related
infrastructure, Canadian Natural is able to control a major component of its operating cost and minimize production commitments.
Low capital exposure projects can typically be easily stopped or started depending upon success, market conditions, or corporate
needs.
Canadian Natural's balanced portfolio, built with both long-life, low decline assets and low capital exposure assets, enables
effective capital allocation, production growth and value creation.
Drilling Activity
|
| |
Six Months Ended June 30 |
| |
2017 |
2016 |
| (number of wells) |
Gross |
Net |
Gross |
Net |
| Crude oil |
236 |
216 |
|
11 |
8 |
|
| Natural gas |
16 |
16 |
|
6 |
5 |
|
| Dry |
3 |
3 |
|
- |
- |
|
| Subtotal |
255 |
235 |
|
17 |
13 |
|
| Stratigraphic test / service wells |
232 |
232 |
|
200 |
200 |
|
| Total |
487 |
467 |
|
217 |
213 |
|
| |
Success rate (excluding stratigraphic test / service wells) |
|
99 |
% |
|
100 |
% |
- The Company's total Q2/17 crude oil and natural gas drilling program of 68 net wells, excluding strat/service wells, was a
significant increase from the 1 net well drilled in Q2/16. The change in drilling reflects the flexibility of Canadian
Natural's resource development program and the Company's disciplined capital allocation process.
North America Exploration and Production
| Crude oil and NGLs - excluding Thermal In Situ Oil Sands |
| |
Three Months Ended |
Six Months Ended |
| |
Jun 30
2017 |
Mar 31
2017 |
Jun 30
2016 |
Jun 30
2017 |
Jun 30
2016 |
| Crude oil and NGLs production (bbl/d) |
227,083 |
|
231,591 |
|
235,468 |
229,325 |
|
243,705 |
|
| Net wells targeting crude oil |
57 |
|
147 |
|
- |
204 |
|
7 |
|
| Net successful wells drilled |
55 |
|
147 |
|
- |
202 |
|
7 |
|
| Success rate |
96 |
% |
100 |
% |
- |
99 |
% |
100 |
% |
- Quarterly production volumes of North America crude oil and NGLs averaged 227,083 bbl/d in Q2/17, within quarterly corporate
guidance and comparable to Q1/17 levels. Q2/17 production volumes represent a decrease of 4% from Q2/16 levels as a result of
limited drilling activity in 2016.
- Pelican Lake heavy crude oil production of 46,932 bbl/d in Q2/17 was in line with Q1/17 and Q2/16 levels. Operations
continued to be optimized in the quarter, resulting in industry leading operating costs of $6.38/bbl in Q2/17 flat from Q1/17
levels and a 6% decrease from Q2/16 levels.
- Primary heavy crude oil production averaged 89,345 bbl/d in Q2/17. The Company's proactive decision to reduce its primary
heavy crude oil drilling program in 2015 and the first half of 2016 resulted in production volumes declining 14% from Q2/16
levels.
- North America light crude oil and NGL quarterly production averaged 90,806 bbl/d, 1% and 8% increases from Q1/17 and Q2/16
levels respectively. Strong quarterly operating costs of $13.98/bbl were realized in Q2/17, in line with Q1/17 levels.
- The Company's 2017 North America E&P crude oil and NGL annual production guidance remains unchanged and is targeted to
range from 236,000 bbl/d - 246,000 bbl/d.
| Thermal In Situ Oil Sands |
| |
Three Months Ended |
Six Months Ended |
| |
Jun 30
2017 |
|
Mar 31
2017 |
|
Jun 30
2016 |
Jun 30
2017 |
|
Jun 30
2016 |
| Bitumen production (bbl/d) |
105,719 |
|
128,372 |
|
93,213 |
116,983 |
|
105,629 |
| Net wells targeting bitumen |
4 |
|
8 |
|
- |
12 |
|
- |
| Net successful wells drilled |
4 |
|
8 |
|
- |
12 |
|
- |
| |
Success rate |
100 |
% |
100 |
% |
- |
100 |
% |
- |
| |
|
|
|
|
|
|
|
|
- Thermal in situ operations were strong in Q2/17 with production averaging 105,719 bbl/d, representing a 13% increase from
Q2/16 levels and above the Company's previously issued quarterly guidance. Results were strong given planned turnaround
activities in the quarter at both Primrose and Kirby South.
-- Kirby South, the Company's SAGD project achieved production of 34,649 bbl/d in Q2/17, despite planned downtime for
turnaround activities. Including energy costs, operating costs of $10.28/bbl were achieved in the quarter, in-line with Q2/16
levels, supported by a strong Steam to Oil Ratio ("SOR") of 2.6.
-- Primrose production was 71,070 bbl/d in Q2/17, after planned downtime for turnaround activities. Including energy costs,
operating costs of $15.87/bbl were realized in Q2/17, a strong result given the planned downtime for turnaround
activities and steam generation work in the quarter.
--- Strong results from the Company's low pressure steamflood at Primrose continue to be achieved, with June 2017 production
under steamflood averaging approximately 32,000 bbl/d.
- Kirby North, the Company's second SAGD project targeted to add 40,000 bbl/d, continues to be on track as civil and cement
foundation work has commenced at the plant site. As previously announced, the remaining project capital is targeted to be
approximately $650 million, with steam-in targeted for late 2019 and first production targeted in early 2020.
- The Company's 2017 thermal in situ annual production guidance has been increased and is targeted to range from 112,000 bbl/d
- 122,000 bbl/d.
| Natural Gas |
| |
Three Months Ended |
Six Months Ended |
| |
Jun 30
2017 |
|
Mar 31
2017 |
|
Jun 30
2016 |
|
Jun 30
2017 |
|
Jun 30
2016 |
|
| Natural gas production (MMcf/d) |
1,603 |
|
1,613 |
|
1,620 |
|
1,607 |
|
1,672 |
|
| Net wells targeting natural gas |
5 |
|
12 |
|
1 |
|
17 |
|
5 |
|
| Net successful wells drilled |
5 |
|
11 |
|
1 |
|
16 |
|
5 |
|
| |
Success rate |
100 |
% |
92 |
% |
100 |
% |
94 |
% |
100 |
% |
| |
|
|
|
|
|
|
|
|
|
|
- North America natural gas production volumes averaged 1,603 MMcf/d in Q2/17, in line with Q1/17 and Q2/16. Production was
lower than expected due to the continued reliability issues at a third party natural gas facility. The third party facility was
down from June 6, 2017 to July 28, 2017 and is now running at partial capacity. However it is not expected to have reliable
production until after a planned turnaround in September. This further impacts Q3/17 and annual 2017 volumes, resulting in the
Company lowering its annual production guidance. Canadian Natural's current production capability through this facility is in
excess of 170 MMcf/d.
- The Company's North America natural gas operations achieved operating costs of $1.17/Mcf in Q2/17, a decrease of 3% from
Q1/17.
- The Company's 2017 total natural gas annual production guidance has been changed and is now targeted to range from 1,655
MMcf/d - 1,705 MMcf/d to reflect the poor reliability of a third party natural gas facility for the first half of the year and
additional unplanned and planned downtime in the second half of the year.
International Exploration and Production
|
| |
Three Months Ended |
Six Months Ended |
| |
Jun 30
2017 |
Mar 31
2017 |
Jun 30
2016 |
Jun 30
2017 |
Jun 30
2016 |
| Crude oil production (bbl/d) |
|
|
|
|
|
| |
North Sea |
26,304 |
|
23,042 |
23,360 |
24,682 |
|
23,338 |
|
| |
Offshore Africa |
20,480 |
|
22,616 |
30,858 |
21,542 |
|
28,286 |
|
| Natural gas production (MMcf/d) |
|
|
|
|
|
| |
North Sea |
37 |
|
37 |
30 |
37 |
|
29 |
|
| |
Offshore Africa |
16 |
|
23 |
39 |
20 |
|
37 |
|
| Net wells targeting crude oil |
1.8 |
|
- |
- |
1.8 |
|
1.2 |
|
| Net successful wells drilled |
1.8 |
|
- |
- |
1.8 |
|
1.2 |
|
| |
Success rate |
100 |
% |
- |
- |
100 |
% |
100 |
% |
| |
|
|
|
|
|
|
|
|
- International quarterly crude oil production volumes were within the Company's production guidance and averaged 46,784 bbl/d
in Q2/17, an increase of 2% from Q1/17.
-- In the North Sea, the Company's continued focus on production enhancements, increased reliability and water flood
optimization, and a modest drilling program of 1.8 net wells resulted in average production volumes of 26,304 bbl/d in Q2/17, an
increase of 14% and 13% from Q1/17 and Q2/16 levels respectively.
-- North Sea quarterly crude oil operating costs decreased to $28.86/bbl, representing reductions of 22% and 39% from Q1/17
and Q2/16 levels respectively.
--- The Company successfully decommissioned the Murchison platform in Q2/17, on time and on budget.
--- The Company commenced its first step in the decommissioning and abandonment of the Ninian North platform with cessation of
production on May 18, 2017. Well abandonment activities are currently underway.
-- Offshore Africa production volumes averaged 20,480 bbl/d in Q2/17, a 9% decrease from Q1/17 levels. Production expense of
$17.27/bbl was achieved, related to the Baobab and Espoir fields in Cote d'Ivoire in Q2/17. After incorporating production from
the Olowi field in Gabon, production expense was $32.39/bbl.
--- Canadian Natural completed a planned turnaround in Q2/17 at Espoir.
--- The Company also completed a planned turnaround at Baobab in Q3/17, which is reflected in Q3/17 production guidance.
- The Company's 2017 International annual production guidance remains unchanged and is targeted to range from 43,000 bbl/d -
49,000 bbl/d.
North America Oil Sands Mining and Upgrading - Horizon
|
| |
Three Months Ended |
Six Months Ended |
| |
Jun 30
2017 |
Mar 31
2017 |
Jun 30
2016 |
Jun 30
2017 |
Jun 30
2016 |
| Synthetic crude oil production (bbl/d) (1) |
190,837 |
192,491 |
119,511 |
191,660 |
123,710 |
| |
|
|
|
|
|
(1) Second quarter 2017 SCO production before royalties excludes 438 bbl/d of SCO consumed internally as diesel (first
quarter 2017 - 428 bbl/d; second quarter 2016 - 2,227 bbl/d; six months ended June 30, 2017 - 433 bbl/d; six months ended June
30, 2016 - 2,394 bbl/d).
- At Horizon, Q2/17 production was 190,837 bbl/d of SCO, over 6,000 bbl/d of SCO above the midpoint of the Company's
previously issued quarterly guidance, representing an increase of 60% over Q2/16 levels.
-- Through safe, steady and reliable operations and a strong focus on continuous improvement, the Company realized quarterly
average operating costs at Horizon of $22.09/bbl of SCO in Q2/17, consistent with record low operating costs of $22.08/bbl of SCO
in Q1/17 and an 18% reduction from Q2/16 levels.
-- During Q2/17, Canadian Natural continued to advance the Horizon Phase 3 expansion. The expansion is currently ahead of
schedule and costs are trending at the Company's 2017 estimates. Phase 3 reached 96% physical completion as at June 30, 2017 and
will be mechanically complete and ready for tie-in and commissioning with the planned September turnaround.
-- The Company has deferred approximately $315 million of Horizon project capital into 2018 to better plan and execute the
Company's mature fines tailings project, at which time it is expected that learnings and synergies can be leveraged between the
Horizon and AOSP mines to capture potential cost savings.
-- The Company previously announced a potential debottleneck at the fractionation tower after startup of Horizon Phase 2B. The
fractionation tower was identified as a limiting component in exceeding the targeted capacity of 250,000 bbl/d of SCO. It has now
been determined that the capacity of the VDU and DRU furnaces will also be limiting components in exceeding the targeted
capacity.
--- A significant amount of process engineering to determine the capacity outcomes of all the critical components of the
upgrading operation was completed at various confidence levels. As a result it is not prudent at present to predict with
confidence, that Horizon will be able to deliver production levels exceeding 250,000 bbl/d of SCO until the Company has actual
throughput through the upgrader and the actual reliability is determined once Phase 3 is operational.
--- The Company is confident that increased reliability and creep capacity volumes will be attainable if work is undertaken on
the fractionator and furnaces and therefore will be undertaking this planned work during the September turnaround, extending the
turnaround from 24 days to 45 days.
--- The total additional work is targeted to require capital of approximately $170 million for Optimization and Reliability
enhancements.
-- Q2/17 Horizon project capital expenditures were $182 million. The Company has reduced the Horizon 2017 project capital by
$315 million and incorporated $170 million for Optimization and Reliability enhancements to take place during the Q3/17
turnaround. Total annual 2017 Horizon project capital is now targeted to be $910 million and is forecasted to be approximately
$145 million lower than the previously issued 2017 capital guidance. Start-up of Phase 3 is targeted for Q4/17 and is targeted to
bring total Horizon production volumes to 250,000 bbl/d of SCO, which will result in a further step change towards sustainable
funds flow and lower operating costs.
- Directive 85 (formerly Directive 74) implementation at the Horizon project remains on track and was 71% physically complete
as at June 30, 2017. This project includes research into tailings management and investments in technological advancements to
advance the cessation of the use of traditional tailings ponds.
- The Company's 2017 Horizon annual production guidance remains unchanged and is targeted to range from 170,000 bbl/d -
184,000 bbl/d of SCO.
North America Oil Sands Mining and Upgrading - AOSP
|
| |
Three Months Ended |
Six Months Ended |
| |
Jun 30
2017 |
Mar 31
2017 |
Jun 30
2016 |
Jun 30
2017 |
Jun 30
2016 |
| Synthetic crude oil production (bbl/d) (1) |
66,704 |
- |
- |
33,536 |
- |
| |
|
|
|
|
|
(1) Consists of heavy and light synthetic crude oil products.
- At AOSP, Canadian Natural's 70% working interest in this world class oil sands mining and upgrading operation, strong
monthly net production of 202,300 bbl/d of AOSP SCO was achieved in June 2017. As such, Q2/17 production was 66,704 bbl/d of
upgraded product, above the top end of the Company's previously issued guidance of 57,000 - 63,000 bbl/d.
-- On May 31, 2017, the Company successfully closed the acquisition of a direct and indirect 70% working interest in the AOSP
and 100% working interest in other heavy crude oil and thermal in situ assets. In total approximately 2,800 employees were
successfully transitioned to Canadian Natural.
- A combination of higher production and modest integration savings resulted in low operating costs in the quarter of
$27.50/bbl of upgraded product.
- The Company's 2017 AOSP annual production guidance has been increased and is now targeted to range from 102,000 bbl/d -
116,000 bbl/d of AOSP SCO.
| MARKETING |
|
|
|
|
|
|
|
|
|
|
| |
| |
Three Months Ended |
Six Months Ended |
| |
|
Jun 30 |
|
Mar 31 |
|
Jun 30 |
|
Jun 30 |
|
Jun 30 |
| |
|
2017 |
|
2017 |
|
2016 |
|
2017 |
|
2016 |
| Crude oil and NGL pricing |
|
|
|
|
|
|
|
|
|
|
| |
WTI benchmark price (US$/bbl) (1) |
$ |
48.29 |
$ |
51.86 |
|
$45.60 |
$ |
50.07 |
$ |
39.56 |
| |
WCS blend differential from WTI (%) (2) |
|
23% |
|
28% |
|
29% |
|
26% |
|
35% |
| |
SCO price (US$/bbl) |
$ |
49.83 |
$ |
51.45 |
$ |
47.39 |
$ |
50.63 |
$ |
40.58 |
| |
Condensate benchmark pricing (US$/bbl) |
$ |
48.44 |
$ |
52.21 |
$ |
44.10 |
$ |
50.31 |
$ |
39.28 |
| |
Average realized pricing before risk management (C$/bbl) (3) |
$ |
47.12 |
$ |
47.05 |
$ |
39.98 |
$ |
47.08 |
$ |
31.40 |
| Natural gas pricing |
|
|
|
|
|
|
|
|
|
|
| |
AECO benchmark price (C$/GJ) |
$ |
2.63 |
$ |
2.79 |
$ |
1.18 |
$ |
2.71 |
$ |
1.59 |
| |
Average realized pricing before risk management (C$/Mcf) |
$ |
2.97 |
$ |
3.25 |
$ |
1.50 |
$ |
3.11 |
$ |
1.88 |
(1) West Texas Intermediate ("WTI").
(2) Western Canadian Select ("WCS").
(3) Average crude oil and NGL pricing excludes SCO. Pricing is net of blending costs and excluding risk management
activities.
- WTI averaged US$48.29/bbl in Q2/17, an increase of 6% from US$45.60/bbl in Q2/16, and a decrease of 7% from $51.86/bbl in
Q1/17.
- Crude oil sales contracts for the Company's North Sea and Offshore Africa segments are typically based on Brent pricing,
which is representative of international markets and overall world supply and demand. Brent averaged US$50.24/bbl in Q2/17, an
increase of 10% from US$45.80/bbl in Q2/16, and a decrease of 7% from $54.05/bbl in Q1/17.
- WTI and Brent pricing continued to reflect volatility in supply and demand factors and geopolitical events. Benchmark
pricing continued to reflect the OPEC decision in November 2016 to implement a production cut effective January 1, 2017 followed
by additional production cuts by certain non-OPEC countries. The decrease in benchmark pricing in Q2/17 from Q1/17 reflects
increased production in certain non-OPEC countries.
- The WCS Heavy Differential averaged US$11.11/bbl in Q2/17, a decrease of 17% from US$13.31/bbl in Q2/16, and a decrease of
24% from $14.58/bbl in Q1/17. The WCS Heavy Differential largely reflects US Gulf Coast pricing, adjusted for transportation
costs. The narrowing of the differential in Q2/17 compared with Q1/17 primarily reflects seasonality.
- Canadian Natural contributed approximately 203,000 bbl/d of its heavy crude oil stream to the WCS blend in Q2/17. The
Company remains the largest contributor to the WCS blend, accounting for 44% of the total blend.
- The SCO price averaged US$49.83/bbl in Q2/17, an increase of 5% from $47.39/bbl in Q2/16, and a decrease of 3% from
US$51.45/bbl in Q1/17. The fluctuations in SCO pricing from the comparable periods were primarily due to changes in WTI benchmark
pricing and the impact of unplanned third party oil sands production outages.
- AECO natural gas prices averaged $2.63/GJ in Q2/17, an increase of 123% from $1.18/GJ in Q2/16, and a decrease of 6% from
$2.79/GJ in Q1/17. The increase in natural gas prices in Q2/17 compared with Q2/16 primarily reflected the rebalancing of natural
gas storage inventory to historically normal levels, primarily due to reduced drilling activity in 2016, resulting in lower US
natural gas production. Additionally, pricing reflected colder weather in the 2016/2017 winter season as compared with the
previous year. The decrease in natural gas prices compared with the Q1/17 primarily reflected seasonal demand factors.
- The North West Redwater refinery, upon completion, will strengthen the Company's position by providing a competitive return
on investment and by adding 50,000 bbl/d of bitumen conversion capacity in Alberta which will help reduce pricing volatility in
all Western Canadian heavy crude oil. The Company has a 50% interest in the North West Redwater Partnership. For project updates,
please refer to: https://nwrsturgeonrefinery.com/whats-happening/news/.
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 cash flow generation, credit facilities, US
commercial paper program, diverse asset base and related flexible capital expenditure programs all support a flexible financial
position and provide the appropriate financial resources for the near-, mid- and long-term.
- The Company's strategy is to maintain a diverse portfolio balanced across various commodity types. The Company achieved
record production levels of 913,171 BOE/d in Q2/17, with approximately 97% of total production located in G7 countries. During
the month of June 2017, total company production averaged approximately 1,063,300 BOE/d.
- The Company generated significant free cash flow in Q2/17 of approximately $840 million after net capital expenditures and
excluding AOSP acquisition expenditures. After further adjusting for quarterly dividend requirements, approximately $530 million
of free cash flow was realized in the quarter, which was largely used to reduce the Company's debt levels.
- In May 2017 the Company successfully executed on its funding plan for the acquisition through accessing debt capital markets
and a syndicated $3.0 billion 3 year term loan facility. Approximately $5.8 billion was raised in the Canadian and US debt
capital markets with tenors ranging from 3 to 30 years and a weighted average interest rate of approximately 3.56% with a
weighted average tenor of approximately 12 years.
- Canadian Natural maintains significant financial stability and liquidity represented in part by committed bank credit
facilities. In Q2/17 the Company increased its previously existing bank credit facilities by $0.7 billion and at June 30, 2017
had in place $3.7 billion of liquidity.
-- Canadian Natural continues to have significant support from its large and diverse banking group as indicated by extensions
and credit facility increases during the quarter. The company's $1.5 billion non-revolving facility was increased to $2.2 billion
and extended from April 2018 to October 2019. Additionally, the Company extended $2.095 billion of the $2.425 billion revolving
syndicated credit facility originally maturing in June 2019 to June 2021. The remaining $330 million will mature in June
2019.
- During Q2/17, the Company repaid US$1.1 billion of 5.70% notes which was fully hedged using a cross currency swap, resulting
in a payment on settlement of $1.287 billion.
- Balance sheet strength continues to be a focus of the Company, with debt to book capitalization of 43% at June 30, 2017,
within the Company's targeted operating range.
- In addition to its strong cash flow, capital flexibility and access to debt capital markets, Canadian Natural has additional
financial levers at its disposal to effectively manage its liquidity. As at June 30, 2017, these financial levers include the
Company's third party investments of approximately $832 million.
- At June 30, 2017, 50,000 GJ/d of natural gas volumes were hedged using AECO swaps through to October 2017. Additionally,
67,000 bbl/d of crude oil volumes were hedged through to December 2017 using WTI costless collars with a floor of US$50.00. For
full hedging disclosure please see the Company's website.
- Canadian Natural declared a quarterly cash dividend on common shares of C$0.275 per share payable on October 1,
2017.
OUTLOOK
The Company forecasts annual 2017 production levels to average between 663,000 and 717,000 bbl/d of crude oil and NGLs
and between 1,655 and 1,705 MMcf/d of natural gas, before royalties. Q3/17 production guidance before royalties is forecast to
average between 740,000 and 778,000 bbl/d of crude oil and NGLs and between 1,650 and 1,710 MMcf/d of natural gas. Detailed
guidance on production levels, capital allocation and operating costs can be found on the Company's website at www.cnrl.com.
Canadian Natural's annual 2017 capital expenditures are targeted to be approximately $3.9 billion.
Forward-Looking Statements
Certain statements relating to Canadian Natural Resources Limited (the "Company") in this document or documents incorporated
herein by reference constitute forward-looking statements or information (collectively referred to herein as "forward-looking
statements") within the meaning of applicable securities legislation. Forward-looking statements can be identified by the words
"believe", "anticipate", "expect", "plan", "estimate", "target", "continue", "could", "intend", "may", "potential", "predict",
"should", "will", "objective", "project", "forecast", "goal", "guidance", "outlook", "effort", "seeks", "schedule", "proposed" or
expressions of a similar nature suggesting future outcome or statements regarding an outlook. Disclosure related to expected
future commodity pricing, forecast or anticipated production volumes, royalties, operating costs, capital expenditures, income
tax expenses and other guidance provided throughout the Company's Management's Discussion and Analysis ("MD&A"), constitute
forward-looking statements. Disclosure of plans relating to and expected results of existing and future developments, including
but not limited to the Horizon Oil Sands operations and future expansions, the Athabasca Oil Sands Project ("AOSP"), Primrose
thermal projects, Pelican Lake water and polymer flood project, the Kirby Thermal Oil Sands Project, the construction and future
operations of the North West Redwater bitumen upgrader and refinery, and construction by third parties of new or expansion of
existing pipeline capacity or other means of transportation of bitumen, crude oil, natural gas or synthetic crude oil ("SCO")
that the Company may be reliant upon to transport its products to market also constitute forward-looking statements. This
forward-looking information is based on annual budgets and multi-year forecasts, and is reviewed and revised throughout the year
as necessary in the context of targeted financial ratios, project returns, product pricing expectations and balance in project
risk and time horizons. These statements are not guarantees of future performance and are subject to certain risks. The reader
should not place undue reliance on these forward-looking statements as there can be no assurances that the plans, initiatives or
expectations upon which they are based will occur.
In addition, statements relating to "reserves" are deemed to be forward-looking statements as they involve the implied
assessment based on certain estimates and assumptions that the reserves described can be profitably produced in the future. There
are numerous uncertainties inherent in estimating quantities of proved and proved plus probable crude oil, natural gas and
natural gas liquids ("NGLs") reserves and in projecting future rates of production and the timing of development expenditures.
The total amount or timing of actual future production may vary significantly from reserve and production estimates.
The forward-looking statements are based on current expectations, estimates and projections about the Company and the industry
in which the Company operates, which speak only as of the date such statements were made or as of the date of the report or
document in which they are contained, and are subject to known and unknown risks and uncertainties that could cause the actual
results, performance or achievements of the Company to be materially different from any future results, performance or
achievements expressed or implied by such forward-looking statements.
Such risks and uncertainties include, among others: general economic and business conditions which will, among other things,
impact demand for and market prices of the Company's products; volatility of and assumptions regarding crude oil and natural gas
prices; fluctuations in currency and interest rates; assumptions on which the Company's current guidance is based; economic
conditions in the countries and regions in which the Company conducts business; political uncertainty, including actions of or
against terrorists, insurgent groups or other conflict including conflict between states; industry capacity; ability of the
Company to implement its business strategy, including exploration and development activities; impact of competition; the
Company's defense of lawsuits; availability and cost of seismic, drilling and other equipment; ability of the Company and its
subsidiaries to complete capital programs; the Company's and its subsidiaries' ability to secure adequate transportation for its
products; unexpected disruptions or delays in the resumption of the mining, extracting or upgrading of the Company's bitumen
products; potential delays or changes in plans with respect to exploration or development projects or capital expenditures;
ability of the Company to attract the necessary labour required to build its thermal and oil sands mining projects; operating
hazards and other difficulties inherent in the exploration for and production and sale of crude oil and natural gas and in
mining, extracting or upgrading the Company's bitumen products; availability and cost of financing; the Company's and its
subsidiaries' success of exploration and development activities and its ability to replace and expand crude oil and natural gas
reserves; timing and success of integrating the business and operations of acquired companies and assets, including the interests
in AOSP as well as additional working interests in certain other producing and non-producing oil and gas properties (the "other
assets"), acquired by the Company on May 31, 2017; production levels; imprecision of reserve estimates and estimates of
recoverable quantities of crude oil, natural gas and NGLs not currently classified as proved; actions by governmental
authorities; government regulations and the expenditures required to comply with them (especially safety and environmental laws
and regulations and the impact of climate change initiatives on capital and operating costs); asset retirement obligations; the
adequacy of the Company's provision for taxes; and other circumstances affecting revenues and expenses.
The Company's operations have been, and in the future may be, affected by political developments and by federal, provincial
and local laws and regulations such as restrictions on production, changes in taxes, royalties and other amounts payable to
governments or governmental agencies, price or gathering rate controls and environmental protection regulations. Should one or
more of these risks or uncertainties materialize, or should any of the Company's assumptions prove incorrect, actual results may
vary in material respects from those projected in the forward-looking statements. The impact of any one factor on a particular
forward-looking statement is not determinable with certainty as such factors are dependent upon other factors, and the Company's
course of action would depend upon its assessment of the future considering all information then available.
Readers are cautioned that the foregoing list of factors is not exhaustive. Unpredictable or unknown factors not discussed in
this report could also have material adverse effects on forward-looking statements. Although the Company believes that the
expectations conveyed by the forward-looking statements are reasonable based on information available to it on the date such
forward-looking statements are made, no assurances can be given as to future results, levels of activity and achievements. All
subsequent forward-looking statements, whether written or oral, attributable to the Company or persons acting on its behalf are
expressly qualified in their entirety by these cautionary statements. Except as required by law, the Company assumes no
obligation to update forward-looking statements, whether as a result of new information, future events or other factors, or the
foregoing factors affecting this information, should circumstances or Management's estimates or opinions change.
Special Note Regarding Currency, Production and Non-GAPP Financial Measures
This release should be read in conjunction with the Management's Discussion and Analysis ("MD&A") and the unaudited
interim Consolidated Financial Statements for the three months and six months ended June 30, 2017 and the MD&A and the
audited consolidated financial statements for the year ended December 31, 2016.
All dollar amounts are referenced in millions of Canadian dollars, except where noted otherwise. The Company's unaudited
interim consolidated financial statements for the period ended June 30, 2017 and MD&A have been prepared in accordance
with International Financial Reporting Standards ("IFRS") as issued by the International Accounting Standards Board. This release
includes references to financial measures commonly used in the crude oil and natural gas industry, such as adjusted net earnings
(loss) from operations, funds flow from operations (previously referred to as cash flow from operations), and adjusted cash
production costs. These financial measures are not defined by IFRS and therefore are referred to as non-GAAP measures. The
non-GAAP measures used by the Company may not be comparable to similar measures presented by other companies. The Company uses
these non-GAAP measures to evaluate its performance. The non-GAAP measures should not be considered an alternative to or more
meaningful than net earnings (loss) and cash flows from operating activities, as determined in accordance with IFRS, as an
indication of the Company's performance. The non-GAAP measures adjusted net earnings (loss) from operations and funds flow from
operations are reconciled to net earnings (loss), as determined in accordance with IFRS, in the "Financial Highlights" section of
the Company's MD&A. The non-GAAP measure funds flow from operations is also reconciled to cash flows from operating
activities. The derivation of adjusted cash production costs and adjusted depreciation, depletion and amortization are included
in the "Operating Highlights – Oil Sands Mining and Upgrading" section of the Company's MD&A. The Company also presents
certain non-GAAP financial ratios and their derivation in the "Liquidity and Capital Resources" section of the Company's
MD&A.
A Barrel of Oil Equivalent ("BOE") is derived by converting six thousand cubic feet ("Mcf") of natural gas to one barrel
("bbl") of crude oil (6 Mcf:1 bbl). This conversion may be misleading, particularly if used in isolation, since the 6 Mcf:1 bbl
ratio is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value
equivalency at the wellhead. In comparing the value ratio using current crude oil prices relative to natural gas prices, the 6
Mcf:1 bbl conversion ratio may be misleading as an indication of value. In addition, for the purposes of the Company's MD&A,
crude oil is defined to include the following commodities: light and medium crude oil, primary heavy crude oil, Pelican Lake
heavy crude oil, bitumen (thermal oil), and SCO.
Production volumes and per unit statistics are presented throughout this release on a "before royalty" or "gross" basis, and
realized prices are net of blending costs and exclude the effect of risk management activities. Production on an "after royalty"
or "net" basis is also presented for information purposes only 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, August 3, 2017.
The North American conference call number is 1-866-521-4909 and the outside North American conference call number is
001-647-427-2311. Please call in 10 minutes prior to the call starting time.
An archive of the broadcast will be available until 6:00 p.m. Mountain Time, Thursday, August 17, 2017. 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 21866168.
The conference call will also be Webcast live on the internet and may be accessed on the home page our website at www.cnrl.com.