Canadian Natural Resources Limited (TSX:CNQ) (NYSE:CNQ)
Commenting on third quarter results, Canadian Natural's
Vice-Chairman John Langille stated, "During the first nine months
of 2012 we effectively executed a balanced capital budget. Our
large proved plus probable reserve base (7.5 billion barrels of oil
equivalent) delivered $4.5 billion of cash flow ensuring we
maintain a strong balance sheet with debt to book capitalization at
26% and debt to EBITDA of 1.1 times. This strong financial position
supports our ability to drive effective capital allocation,
efficiently control costs and continue implementing our successful
strategy.
As part of our successful strategy we have sanctioned the North
West Redwater refinery project. This project strengthens our
position by not only providing a competitive return on investment
but also by adding 50,000 bbl/d of heavy crude oil conversion
capacity in Alberta which will help reduce volatility in pricing
all Western Canadian heavy crude oil."
Steve Laut, President of Canadian Natural continued, "We had a
solid operating quarter and we met or exceeded production guidance
in all areas of the business. The Company achieved strong
production volumes, up 9% from the third quarter of last year, due
to our successful heavy and light crude oil drilling programs and
our oil sands operations, both thermal in situ and Horizon mining.
This is impressive considering the Company deferred an additional
$230 million of capital this quarter, over and above the $680
million that was previously deferred, totalling $910 million of
reduced capital expenditures since mid-2012.
During the third quarter, we made substantial progress in
driving our mid and long term potential assets forward. The Horizon
expansion is making solid progress and tracking below cost
estimates. At Pelican Lake, we continue to roll out our leading
edge polymer flood and are seeing strong production response. We
achieved 67% construction completion at Kirby South Phase 1 and
target first steam in late 2013.
Additionally the Company has added 31,570 net acres of thermal
in situ lands contiguous to our Kirby land holdings. The additional
lands contain significant SAGD resource potential within the
McMurray reservoir creating long term value for the Company. It is
expected that these lands will increase overall production capacity
at our thermal in situ operations that currently is targeted to add
500,000 barrels per day of bitumen over the next fifteen years.
Canadian Natural is in an excellent position. We have a proven
strategy that works, and are focused on effective and efficient
operations in all areas. Our vast resource base, strong technical
expertise, and financial resources will facilitate our ability to
significantly grow cash flow and maximize returns for our
shareholders."
QUARTERLY HIGHLIGHTS
Three Months Ended Nine Months Ended
--------------------------------------------------
($ Millions, except per Sep 30 Jun 30 Sep 30 Sep 30 Sep 30
common share amounts) 2012 2012 2011 2012 2011
----------------------------------------------------------------------------
Net earnings $ 360 $ 753 $ 836 $ 1,540 $ 1,811
Per common share - basic $ 0.33 $ 0.68 $ 0.76 $ 1.40 $ 1.65
- diluted $ 0.33 $ 0.68 $ 0.76 $ 1.40 $ 1.64
Adjusted net earnings from
operations (1) $ 353 $ 606 $ 719 $ 1,259 $ 1,568
Per common share - basic $ 0.33 $ 0.55 $ 0.65 $ 1.15 $ 1.43
- diluted $ 0.32 $ 0.55 $ 0.65 $ 1.14 $ 1.42
Cash flow from operations
(2) $ 1,431 $ 1,754 $ 1,767 $ 4,465 $ 4,389
Per common share - basic $ 1.31 $ 1.60 $ 1.62 $ 4.07 $ 4.01
- diluted $ 1.30 $ 1.59 $ 1.60 $ 4.06 $ 3.98
Capital expenditures, net
of dispositions $ 1,621 $ 1,324 $ 1,406 $ 4,541 $ 4,505
Daily production, before
royalties
Natural gas (MMcf/d) 1,191 1,255 1,252 1,248 1,249
Crude oil and NGLs
(bbl/d) 469,168 470,523 403,900 445,140 370,439
Equivalent production
(BOE/d) (3) 667,616 679,607 612,575 653,220 578,618
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Adjusted net earnings from operations is a non-GAAP measure that the
Company utilizes to evaluate its performance. The derivation of this
measure is discussed in the Management's Discussion and Analysis
("MD&A").
(2) 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) 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.
- During Q3/12, the Company achieved quarterly production of
667,616 BOE/d, representing an increase of 9% over Q3/11, and met
or exceeded production guidance in all areas of the business.
- The Company's total crude oil and NGLs production during Q3/12
was 469,168 bbl/d, representing an increase of 16% over Q3/11 and
comparable to Q2/12. The increase from Q3/11 was primarily due to a
strong primary heavy crude oil drilling program, the timing of
production cycles in bitumen ("thermal in situ"), and safe, steady
and reliable operations at Horizon. Q3/12 production volumes
remained consistent with Q2/12 volumes and were primarily driven by
increased heavy crude oil production, increased Pelican Lake crude
oil production and increased thermal in situ production offset by
lower synthetic crude oil ("SCO") production.
- During Q3/12, total natural gas production for the Company was
1,191 MMcf/d representing a decrease of 5% from both Q3/11 and
Q2/12 levels. The decrease in production from Q3/11 and Q2/12 was
primarily a result of natural declines and 40 MMcf/d of cumulative
shut-in natural gas volumes reflecting the Company's strategic
decision to allocate capital to higher return crude oil projects
due to low natural gas prices.
- Canadian Natural generated quarterly cash flow of $1.43
billion, compared to $1.77 billion in Q3/11 and $1.75 billion in
Q2/12. Cash flow decreased from Q3/11 primarily resulting from
lower crude oil and NGLs and natural gas netbacks and lower SCO
pricing partially offset by higher crude oil and SCO sales volumes.
The decrease in cash flow from Q2/12 was primarily due to lower SCO
sales volumes and lower crude oil and NGLs netbacks. These factors,
along with the impact of a stronger Canadian dollar and
non-operational realized risk management losses were partially
offset by higher crude oil sales volumes in North America and
higher natural gas prices.
- Adjusted net earnings from operations for the quarter were
$353 million, compared with adjusted net earnings of $719 million
in Q3/11 and $606 million in Q2/12. Changes in adjusted net
earnings reflect the changes in cash flow from operations.
- The Company reduced targeted 2012 capital spending by an
additional $230 million in the quarter, resulting in total capital
spending reductions of $910 million or 12%, compared to the updated
capital budget announced in May 2012. At the same time, the
mid-point of total BOE production volume guidance has decreased
only 1% for 2012. This illustrates the strength of the Company's
asset base and ability to maintain capital flexibility while
allocating capital to the highest return projects.
- Operating highlights for Q3/12 include the following with
further details included in the Operations Review sections.
-- Primary heavy crude oil operations achieved production
volumes that totaled over 128,000 bbl/d, resulting in the seventh
consecutive quarter of record production. Production increased by
26% compared with Q3/11.
-- North America light crude oil and NGLs quarterly production
increased 15% from Q3/11.
-- Reservoir performance at Pelican Lake continues to be
positive as production volumes of approximately 41,000 bbl/d in
Q3/12 were achieved, an increase of 8% over Q3/11 volumes.
-- In Q3/12, thermal in situ production grew 8% from the
previous quarter to approximately 102,000 bbl/d.
-- Kirby South Phase 1 is progressing ahead of plan. All major
equipment and modules have been delivered and installed on site
with overall construction progress ahead of schedule.
-- In Q3/12, solid production volumes were achieved at Horizon
Oil Sands ("Horizon"), exceeding 99,200 bbl/d.
-- Canadian Natural's staged expansion to 250,000 bbl/d of SCO
production capacity at Horizon continues to progress on track.
- Subsequent to Q3/12, North West Redwater Partnership and its
owners (50% Canadian Natural) completed the sanctioning process for
the construction of a 50,000 bbl/d bitumen refinery.
Simultaneously, the feedstock providers (Canadian Natural for
12,500 bbl/d and Alberta Petroleum Marketing Commission for 37,500
bbl/d) approved the target toll amounts and have now committed to
the 30 year tolling agreement.
- To date in 2012, Canadian Natural has purchased 7,825,200
common shares for cancellation at a weighted average price of
$29.22 per common share.
- Declared a quarterly cash dividend on common shares of $0.105
per common share payable January 1, 2013.
- Canadian Natural will release its 2013 budget details on
Tuesday, December 4, 2012. The Company will provide forward looking
information on its 2013 operating year.
OPERATIONS REVIEW AND CAPITAL ALLOCATION
In order to facilitate efficient operations, Canadian Natural
focuses its activities in core regions where it can own a
substantial land base and associated infrastructure. Land
inventories are maintained to enable continuous exploitation of
play types and geological trends, greatly reducing overall
exploration risk. By owning associated infrastructure, the Company
is able to maximize utilization of its production facilities,
thereby increasing control over production costs. Further, the
Company maintains large project inventories and production
diversification among each of the commodities it produces; 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. A large diversified project
portfolio enables the effective allocation of capital to higher
return opportunities.
OPERATIONS REVIEW
Drilling activity (number of wells)
Nine Months Ended Sep 30
--------------------------------------
2012 2011
Gross Net Gross Net
----------------------------------------------------------------------------
Crude oil 952 909 816 773
Natural gas 37 32 68 56
Dry 14 14 32 31
----------------------------------------------------------------------------
Subtotal 1,003 955 916 860
Stratigraphic test / service wells 612 611 547 545
----------------------------------------------------------------------------
Total 1,615 1,566 1,463 1,405
----------------------------------------------------------------------------
Success rate (excluding stratigraphic
test / service wells) 99% 96%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
North America Exploration and Production
North America crude oil and NGLs
Three Months Ended Nine Months Ended
---------------------------------------------
Sep 30 Jun 30 Sep 30 Sep 30 Sep 30
2012 2012 2011 2012 2011
----------------------------------------------------------------------------
Crude oil and NGLs production
(bbl/d) 332,895 316,483 304,671 318,384 296,892
----------------------------------------------------------------------------
Net wells targeting crude oil 371 268 327 923 802
Net successful wells drilled 365 266 317 909 773
----------------------------------------------------------------------------
Success rate 98% 99% 97% 98% 96%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
- Production averaged 332,895 bbl/d in Q3/12 representing an
increase of 9% from Q3/11 and an increase of 5% from Q2/12. The
increase in production from Q3/11 was a result of a successful
primary heavy crude oil drilling program and the timing of thermal
in situ production cycles. The increase in production from Q2/12
was a result of strong heavy crude oil production, increased
Pelican Lake volumes and the continuing ramp up of thermal in situ
production as pads re-entered the production cycle.
- Primary heavy crude oil currently provides the highest return
on capital projects in Canadian Natural's portfolio. Primary heavy
crude oil operations achieved production volumes that totaled over
128,000 bbl/d, resulting in the seventh consecutive quarter of
record production. Production increased by 26% and 5% compared with
Q3/11 and Q2/12 levels respectively, primarily due to a successful
drilling program and strong production results from Woodenhouse, a
new non-traditional primary heavy crude oil area located 75
kilometers north of Pelican Lake.
-- The production profiles at Woodenhouse have been better than
anticipated. In October 2012, production averaged 9,300 bbl/d and
exit rate production for 2012 is targeted at approximately 12,600
bbl/d. In 2012, 71 wells have been drilled at Woodenhouse and the
Company targets to drill 15 additional wells by year-end.
-- Canadian Natural targets to drill 241 net primary heavy crude
oil wells (including Woodenhouse) in Q4/12 for a targeted record of
901 total net wells in 2012, 93 more net wells than the original
budget. The Company has further increased its targeted annual
production guidance by 5% to an increase of 22% over 2011
production volumes.
-- Canadian Natural continues to demonstrate efficient and
effective operations in primary heavy crude oil. Low quarterly
operating costs of $14.27/bbl were achieved in Q3/12 and continue
to result in high netbacks and high value production contributing
to the Company's significant cash flow.
- North America light crude oil and NGLs quarterly production
increased 15% from Q3/11 as a result of a successful light oil
drilling program and increased production from Septimus. North
America light crude oil and NGLs is a significant part of Canadian
Natural's balanced portfolio, averaging approximately 62,600 bbl/d
in the quarter.
- Reservoir performance at Pelican Lake continues to be positive
as production volumes of approximately 41,000 bbl/d in Q3/12 were
achieved, an increase of 8% over Q3/11 volumes.
-- The Company achieved over 37,000 bbl/d in Q2/12,
approximately 41,000 bbl/d in Q3/12 and exit rates for 2012 are
targeted to be approximately 43,000 bbl/d, a 16% increase from
Q2/12 production volumes.
-- Construction of the 25,000 bbl/d battery expansion is
targeted to be on stream by Q2/13 and will support production
growth to over 60,000 bbl/d targeted by 2015/16.
-- Pelican Lake continues to achieve low quarterly operating
costs at $10.69/bbl in Q3/12, which result in high netbacks and
high value production contributing to the Company's significant
cash flow.
-- Ultimate recovery from this world class pool is targeted to
be 561 million barrels (363 million barrels of proved plus probable
reserves and 198 million barrels of best estimate contingent
resources) of additional crude oil through a disciplined multi-year
expansion plan.
- Canadian Natural's robust portfolio of thermal in situ
projects is a significant part of the Company's defined plan to
transition to a longer-life, more sustainable asset base with the
ability to generate significant shareholder value for decades to
come. The Company targets to grow thermal in situ production to
approximately 500,000 bbl/d of capacity by delivering projects that
will add 40,000 bbl/d of production every two to three years.
-- In Q3/12, thermal in situ production grew 8% from the
previous quarter to approximately 102,000 bbl/d.
--- The Company achieved over 94,000 bbl/d in Q2/12,
approximately 102,000 bbl/d in Q3/12 and exit rates for 2012 are
targeted to be approximately 119,500 bbl/d, a 27% increase from
Q2/12 production volumes.
--- Total quarterly operating costs, including energy costs, for
the quarter were $8.84/bbl in Q3/12, which is industry leading for
thermal in situ and demonstrates the Company's commitment to
operational excellence. As a result, the Company achieves high
netbacks and high volume production contributing to the Company's
significant cash flow.
-- Kirby South Phase 1 is progressing ahead of plan. All major
equipment and modules have been delivered and installed on site
with overall construction progress ahead of schedule. An update to
the project at the end of Q3/12 is as follows:
--- Overall project is 67% complete.
--- Module assembly is 96% complete.
--- Overall construction is 58% complete.
--- Drilling is 73% complete. Drilling on the fourth of seven
pads was completed in Q3/12 and the fifth pad was rig released in
early Q4/12.
--- First steam-in is targeted for late 2013 and production is
targeted to ramp up to 40,000 bbl/d in 2014.
-- Over the past twelve months and through 3 separate
transactions, 31,570 net acres of additional leases adjacent to
Canadian Natural's Kirby In Situ Oil Sands Expansion Project
("Kirby Project") were acquired, adding best estimate contingent
resources of 340 million barrels of bitumen. The Company is in the
early stages of integrating the acquired lands into the development
plan and is expecting to increase production capacity for future
phases in Kirby North and Kirby South beyond current estimates. The
Company expects to gain significant capital and operating synergies
within the Kirby Project, which will create the potential to drive
exploitation opportunities similar to those seen at Primrose over
the last decade.
-- On Kirby North Phase 1, engineering design specifications are
complete and the transition to detailed engineering is now in
progress. Critical long lead items have been ordered and the
central plant site has been cleared. First steam-in is targeted for
early 2016.
-- At Grouse, engineering is on track. The design basis
memorandum engineering is complete and the transition to
engineering design specifications is now in progress. First
steam-in is targeted for late 2017.
- For Q4/12, the Company plans to drill 42 net thermal in situ
wells and 302 net crude oil wells, excluding strat test and service
wells.
- North America crude oil and NGLs quarterly operating costs
decreased to $12.52/bbl in Q3/12 from $13.10/bbl in Q2/12. The
decrease was primarily due to reduced primary heavy crude oil
operating costs as a result of strategic capital investments made
during the first half of 2012 and the timing of thermal in situ
production cycles.
North America natural gas
Three Months Ended Nine Months Ended
--------------------------------------------------
Sep 30 Jun 30 Sep 30 Sep 30 Sep 30
2012 2012 2011 2012 2011
----------------------------------------------------------------------------
Natural gas production
(MMcf/d) 1,169 1,230 1,226 1,226 1,223
----------------------------------------------------------------------------
Net wells targeting
natural gas 9 4 21 32 57
Net successful wells
drilled 9 4 21 32 56
----------------------------------------------------------------------------
Success rate 100% 100% 100% 100% 98%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
- North America natural gas production for the quarter averaged
1,169 MMcf/d representing a decrease of 5% from both Q3/11 and
Q2/12 production levels. The decrease in production levels was a
result of natural declines and 40 MMcf/d of cumulative shut-in
natural gas volumes reflecting the Company's strategic decision to
allocate capital to higher return crude oil projects.
- The Company reduced capital spending on natural gas by an
additional $45 million in the quarter, resulting in total capital
spending reductions of $345 million or 42% for 2012 compared to the
original capital budget while the mid-point of production volume
guidance decreased 6% in 2012 compared to the original capital
budget. This illustrates the strength of the Company's asset base
and ability to maintain capital flexibility and allocate capital to
the highest return projects.
- North America natural gas quarterly operating costs increased
to $1.28/Mcf in Q3/12 from $1.13/Mcf in Q2/12 as a result of
reduced volumes, seasonal maintenance activity, increased property
taxes and lease rentals.
- Canadian Natural is the second largest natural gas producer in
Canada and has an extensive land base where it demonstrates
efficient and effective operations. The Company's vast land base of
both conventional and unconventional natural gas assets and
ownership of infrastructure favorably positions the Company to
increase drilling activity and production volumes once gas prices
strengthen. Canadian Natural's significant unconventional assets
include approximately 1,044,000 net acres in the Montney and
approximately 500,000 net acres in the Duvernay.
International Exploration and Production
Three Months Ended Nine Months Ended
--------------------------------------------------
Sep 30 Jun 30 Sep 30 Sep 30 Sep 30
2012 2012 2011 2012 2011
----------------------------------------------------------------------------
Crude oil production
(bbl/d)
North Sea 19,502 17,619 26,350 20,054 31,077
Offshore Africa 17,566 20,598 22,525 19,618 23,105
----------------------------------------------------------------------------
Natural gas production
(MMcf/d)
North Sea 2 2 5 2 7
Offshore Africa 20 23 21 20 19
----------------------------------------------------------------------------
Net wells targeting crude
oil - - - - 0.9
Net successful wells
drilled - - - - 0.9
----------------------------------------------------------------------------
Success rate - - - - 100%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
- North Sea crude oil production averaged 19,502 bbl/d during
Q3/12 representing a decrease of 26% compared with Q3/11 and an
increase of 11% compared with Q2/12. The decrease from Q3/11 was
primarily due to suspended operations at Banff/Kyle, planned
maintenance on a third-party operated pipeline, and planned
maintenance turnarounds at the Ninian platforms that commenced late
in Q3/12. The increase from Q2/12 was primarily due to partial
recovery of production volumes following the unplanned shutdown of
the Ninian platforms in Q2/12 as a result of a third-party pipeline
outage.
- Production in Offshore Africa averaged 17,566 bbl/d during
Q3/12 representing a decrease of 22% compared with Q3/11 and a
decrease of 15% compared with Q2/12. The decrease from Q3/11 and
Q2/12 production volumes was primarily due to natural declines and
a planned 9 day turnaround at Baobab. A planned 15 day turnaround
at Espoir is scheduled in Q4/12.
- Canadian Natural's eight well infill drilling program at the
Espoir Field is progressing. The drilling rig has arrived in Cote
d'Ivoire and preparations are currently being undertaken to
commence drilling. The Company targets first oil in Q2/13 ramping
up to production of 6,500 BOE/d at the completion of the Espoir
drilling program, offsetting natural declines. The cost of this
program is targeted at $24,000 per flowing BOE.
- Conversion of the license of the Company's 100% working
interest block in South Africa has been completed and all
regulatory requirements to drill a well are complete. Targeted
drilling windows are from Q4/13 to Q1/14 and from Q4/14 to
Q1/15.
North America Oil Sands Mining and Upgrading - Horizon
Three Months Ended Nine Months Ended
--------------------------------------------------
Sep 30 Jun 30 Sep 30 Sep 30 Sep 30
2012 2012 2011 2012 2011
----------------------------------------------------------------------------
Synthetic crude oil
production (bbl/d) 99,205 115,823 50,354 87,084 19,365
----------------------------------------------------------------------------
----------------------------------------------------------------------------
- Horizon continued to demonstrate solid operational performance
in the quarter. Production averaged 99,205 bbl/d, representing a
97% increase from Q3/11 and a 14% decrease from Q2/12. The increase
from Q3/11 was due to improved steady operations at Horizon, and
the decrease from Q2/12 resulted from the Company's decision to
operate at restricted rates for a portion of Q3/12 to ensure safe,
steady and reliable operations in anticipation of the proactive
planned maintenance that was completed in Q4/12.
- Previously planned maintenance at Horizon originally scheduled
to occur in late Q3/12 was shifted into Q4/12 (October) to optimize
the benefit of the outage and address potential risks associated
with the winter season. The planned outage, scheduled for twelve
days in the month of October, was completed on schedule and on
cost. Production was returned to 115,000 bbl/d and then temporarily
reduced to proactively allow tank volumes and overall performance
to reach optimal levels not yet achieved following the ramp up. The
decision to temporarily reduce production reflects the Company's
commitment to increasing overall reliability going forward. Horizon
production guidance for 2012 has been reduced to range from 87,000
bbl/d to 89,000 bbl/d. However, overall long term production
volumes are expected to increase because of these proactive
actions.
- The Company's focus on operational discipline and proactive
maintenance activities will, over time, deliver increasing levels
of reliability resulting in more effective and efficient
operations, and lower operating costs at the plant. In Q3/12
quarterly operating costs averaged $42.69/bbl, which were primarily
a result of lower production volumes and one-time costs.
- Canadian Natural's staged expansion to 250,000 bbl/d of SCO
production capacity continues to progress on track. An update to
the expansion at the end of Q3/12 is as follows:
-- Overall Horizon expansion is 15% complete.
-- Reliability - Tranche 2 is 84% complete.
-- Directive 74 and Technology are 14% complete.
-- Phase 2A is 39% complete.
-- Phase 2B is 6% complete.
-- Phase 3 is 6% complete.
-- Thus far, four lump sum contracts have been awarded and
projects currently under construction are trending at or below cost
estimates.
MARKETING
Three Months Ended Nine Months Ended
--------------------------------------------------
Sep 30 Jun 30 Sep 30 Sep 30 Sep 30
2012 2012 2011 2012 2011
----------------------------------------------------------------------------
Crude oil and NGLs pricing
WTI benchmark price
(US$/bbl) (1) $ 92.19 $ 93.50 $ 89.81 $ 96.20 $ 95.52
WCS blend differential
from WTI (%) (2) 24% 24% 20% 23% 20%
SCO price (US$/bbl) $ 90.84 $ 89.54 $ 100.64 $ 92.82 $ 103.86
Average realized pricing
before risk management
(C$/bbl) (3) $ 67.59 $ 69.99 $ 73.80 $ 72.43 $ 74.77
Natural gas pricing
AECO benchmark price
(C$/GJ) $ 2.08 $ 1.74 $ 3.53 $ 2.07 $ 3.55
Average realized pricing
before risk management
(C$/Mcf) $ 2.28 $ 1.90 $ 3.76 $ 2.22 $ 3.81
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) West Texas Intermediate ("WTI").
(2) Western Canadian Select ("WCS").
(3) Excludes SCO.
- The WCS heavy crude oil differential as a percent of WTI was
seasonally normal, averaging 24% in Q3/12, and in line with the
Company's long term expectations and well below historical
averages. The WCS heavy differential remained unchanged from Q2/12.
The Company anticipates continued volatility in the differential in
Q4/12 and narrowing of the differential thereafter as additional
conversion and pipeline capacity come on stream.
- For December 2012, heavy crude oil currently trades at a
US$6.00 premium (7% premium) to WTI on the US Gulf Coast ("USGC")
and at a US$30.00 discount (35% discount) at Hardisty reflecting
the logistical constraints at Cushing, which are currently being
debottlenecked.
-- Canadian Natural ships approximately 20,000 bbl/d of heavy
crude oil via a combination of pipelines to USGC markets and
receives Mayan based pricing for these barrels.
-- Approximately 10,000 bbl/d of heavy crude oil is railed to
USGC markets and receives significantly higher netbacks than the
traditional heavy crude oil markets.
-- This highlights the strong demand for Gulf Coast refiners to
use heavy crude oil blends as feedstock, and the value to Canadian
producers reaching the Gulf Coast.
- During Q3/12, Canadian Natural contributed 155,000 bbl/d of
its heavy crude oil stream to the WCS blend. The Company is the
largest contributor of the WCS blend, accounting for 55%.
- Natural gas pricing remains weak as compared to previous year
pricing. In response, Canadian production has declined while US
production remains steady through 2012. AECO benchmark natural gas
prices strengthened in Q3/12 compared with Q2/12 due to increased
demand from the power generation sector and increased seasonal
demand.
NORTH WEST REDWATER UPGRADING AND REFINING
Subsequent to Q3/12, North West Redwater Partnership and its
owners (50% Canadian Natural) completed the sanctioning process for
the construction of a 50,000 bbl/d bitumen refinery.
Simultaneously, the feedstock providers (Canadian Natural for
12,500 bbl/d and Alberta Petroleum Marketing Commission for 37,500
bbl/d) approved the target toll amounts and have now committed to
the 30 year tolling agreement. Canadian Natural will earn a return
on the project of 10% on its equity investment, and additional
margin on any excess capacity available over design capacity. Based
on sanction capital for the project, the majority of equity has
already been contributed to the partnership. Target commencement of
deliveries is mid-2016.
The North West Redwater refinery project strengthens the
Company's position by not only providing a competitive return on
investment but by also adding 50,000 bbl/d of bitumen conversion
capacity in Alberta which will help reduce volatility in pricing
all Western Canadian heavy crude oil. There is potential to further
expand the downstream capacity of the North West Redwater refinery
project from its 50,000 bbl/d of bitumen facility capacity in Phase
1 to 150,000 bbl/d of bitumen facility capacity.
FINANCIAL REVIEW
The financial position of Canadian Natural remains strong as the
Company continues to implement proven strategies and focuses on
disciplined capital allocation. Canadian Natural's cash flow
generation, credit facilities, diverse asset base and related
capital expenditure programs, and commodity hedging policy all
support a flexible financial position and provide the right
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 of 667,616 BOE/d for the quarter with over 97% of
production located in G8 countries.
- Canadian Natural has a strong balance sheet with debt to book
capitalization of 26% and debt to EBITDA of 1.1x. At September 30,
2012, long-term debt amounted to $8.4 billion compared with $8.6
billion at December 31, 2011.
- Canadian Natural maintains significant financial stability and
liquidity represented by approximately $4.26 billion in available
unused bank lines at the end of the quarter.
- The Company's commodity hedging program protects investment
returns, ensures ongoing balance sheet strength and supports the
Company's cash flow for its capital expenditures programs. The
Company has hedged approximately 60% of the remaining crude oil
volumes forecasted for 2012, 150,000 bbl/d of crude oil volumes for
the first half of 2013, and 100,000 bbl/d of crude oil volumes for
the second half of 2013 through a combination of puts and
collars.
- To date in 2012, Canadian Natural has purchased 7,825,200
common shares for cancellation at a weighted average price of
$29.22 per common share.
- Declared a quarterly cash dividend on common shares of $0.105
per common share payable January 1, 2013.
OUTLOOK
The Company forecasts 2012 production levels before royalties to
average between 1,222 and 1,229 MMcf/d of natural gas and between
452,000 and 460,000 bbl/d of crude oil and NGLs. Q4/12 production
guidance before royalties is forecast to average between 1,145 and
1,165 MMcf/d of natural gas and between 467,000 and 495,000 bbl/d
of crude oil and NGLs. Detailed guidance on production levels,
capital allocation and operating costs can be found on the
Company's website at www.cnrl.com.
MANAGEMENT'S DISCUSSION AND ANALYSIS
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" 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 and costs, royalties, operating costs, capital
expenditures, income tax expenses and other guidance provided
throughout this 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, Primrose, Pelican Lake, the Kirby Thermal Oil
Sands Project, and the construction and future operations of the
North West Redwater bitumen upgrader and refinery 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 and natural gas 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 their ability to replace
and expand crude oil and natural gas reserves; timing and success
of integrating the business and operations of acquired companies;
production levels; imprecision of reserve estimates and estimates
of recoverable quantities of crude oil, natural gas and natural gas
liquids ("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.
Management's Discussion and Analysis
This MD&A of the financial condition and results of
operations of the Company should be read in conjunction with the
unaudited interim consolidated financial statements for the three
and nine months ended September 30, 2012 and the MD&A and the
audited consolidated financial statements for the year ended
December 31, 2011.
All dollar amounts are referenced in millions of Canadian
dollars, except where noted otherwise. The Company's consolidated
financial statements for the period ended September 30, 2012 and
this MD&A have been prepared in accordance with International
Financial Reporting Standards ("IFRS"), as issued by the
International Accounting Standards Board. Unless otherwise stated,
2010 comparative figures have been restated in accordance with IFRS
issued as at December 31, 2011. This MD&A includes references
to financial measures commonly used in the crude oil and natural
gas industry, such as adjusted net earnings from operations, cash
flow from operations, and 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, as determined
in accordance with IFRS, as an indication of the Company's
performance. The non-GAAP measures adjusted net earnings from
operations and cash flow from operations are reconciled to net
earnings, as determined in accordance with IFRS, in the "Financial
Highlights" section of this MD&A. The derivation of cash
production costs is included in the "Operating Highlights - Oil
Sands Mining and Upgrading" section of this MD&A. The Company
also presents certain non-GAAP financial ratios and their
derivation in the "Liquidity and Capital Resources" section of this
MD&A.
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. 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 synthetic
crude oil.
Production volumes and per unit statistics are presented
throughout this MD&A on a "before royalty" or "gross" basis,
and realized prices are net of transportation and 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.
The following discussion refers primarily to the Company's
financial results for the three and nine months ended September 30,
2012 in relation to the comparable periods in 2011 and the second
quarter of 2012. The accompanying tables form an integral part of
this MD&A. This MD&A is dated November 6, 2012. Additional
information relating to the Company, including its Annual
Information Form for the year ended December 31, 2011, is available
on SEDAR at www.sedar.com, and on EDGAR at www.sec.gov.
FINANCIAL HIGHLIGHTS
Three Months Ended Nine Months Ended
--------------------------------------------------
($ millions, except per Sep 30 Jun 30 Sep 30 Sep 30 Sep 30
common share amounts) 2012 2012 2011 2012 2011
----------------------------------------------------------------------------
Product sales $ 3,978 $ 4,187 $ 3,690 $ 12,136 $ 10,719
Net earnings $ 360 $ 753 $ 836 $ 1,540 $ 1,811
Per common share
- basic $ 0.33 $ 0.68 $ 0.76 $ 1.40 $ 1.65
- diluted $ 0.33 $ 0.68 $ 0.76 $ 1.40 $ 1.64
Adjusted net earnings from
operations (1) $ 353 $ 606 $ 719 $ 1,259 $ 1,568
Per common share
- basic $ 0.33 $ 0.55 $ 0.65 $ 1.15 $ 1.43
- diluted $ 0.32 $ 0.55 $ 0.65 $ 1.14 $ 1.42
Cash flow from operations
(2) $ 1,431 $ 1,754 $ 1,767 $ 4,465 $ 4,389
Per common share
- basic $ 1.31 $ 1.60 $ 1.62 $ 4.07 $ 4.01
- diluted $ 1.30 $ 1.59 $ 1.60 $ 4.06 $ 3.98
Capital expenditures, net
of dispositions $ 1,621 $ 1,324 $ 1,406 $ 4,541 $ 4,505
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(1) Adjusted net earnings from operations is a non-GAAP measure that
represents net earnings adjusted for certain items of a non-operational
nature. The Company evaluates its performance based on adjusted net
earnings from operations. The reconciliation "Adjusted Net Earnings from
Operations" presented below lists the after-tax effects of certain items
of a non-operational nature that are included in the Company's financial
results. Adjusted net earnings from operations may not be comparable to
similar measures presented by other companies.
(2) Cash flow from operations is a non-GAAP measure that represents net
earnings adjusted for non-cash items before working capital adjustments.
The Company evaluates its performance based on cash flow from
operations. The Company considers cash flow from operations 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 "Cash Flow from Operations" presented
lists certain non-cash items that are included in the Company's
financial results. Cash flow from operations may not be comparable to
similar measures presented by other companies.
Adjusted Net Earnings from Operations
Three Months Ended Nine Months Ended
--------------------------------------------------
Sep 30 Jun 30 Sep 30 Sep 30 Sep 30
($ millions) 2012 2012 2011 2012 2011
----------------------------------------------------------------------------
Net earnings as reported $ 360 $ 753 $ 836 $ 1,540 $ 1,811
Share-based compensation,
net of tax (1) 49 (115) (249) (173) (309)
Unrealized risk management
loss (gain), net of tax
(2) 22 (103) (97) (41) (145)
Unrealized foreign
exchange (gain) loss, net
of tax (3) (136) 71 454 (125) 332
Realized foreign exchange
gain on repayment of US
dollar debt securities
(4) - - (225) - (225)
Effect of statutory tax
rate and other
legislative changes on
deferred income
tax liabilities (5) 58 - - 58 104
----------------------------------------------------------------------------
Adjusted net earnings from
operations $ 353 $ 606 $ 719 $ 1,259 $ 1,568
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) The Company's employee stock option plan provides for a cash payment
option. Accordingly, the fair value of the outstanding vested options is
recorded as a liability on the Company's balance sheets and periodic
changes in the fair value are recognized in net earnings or are
capitalized to Oil Sands Mining and Upgrading construction costs.
(2) Derivative financial instruments are recorded at fair value on the
balance sheets, with changes in fair value of non-designated hedges
recognized in net earnings. The amounts ultimately realized may be
materially different than reflected in the financial statements due to
changes in prices of the underlying items hedged, primarily crude oil
and natural gas.
(3) Unrealized foreign exchange gains and losses result primarily from the
translation of US dollar denominated long-term debt to period-end
exchange rates, partially offset by the impact of cross currency swaps,
and are recognized in net earnings.
(4) During the third quarter of 2011, the Company repaid US$400 million of
US dollar debt securities bearing interest at 6.7%.
(5) All substantively enacted adjustments in applicable income tax rates and
other legislative changes are applied to underlying assets and
liabilities on the Company's balance sheets in determining deferred
income tax assets and liabilities. The impact of these tax rate and
other legislative changes is recorded in net earnings during the period
the legislation is substantively enacted. During the third quarter of
2012, the UK government enacted legislation to restrict the combined
corporate and supplementary income tax rate relief on decommissioning
expenditures to 50%, resulting in an increase in the Company's deferred
income tax liability of $58 million. During the first quarter of 2011,
the UK government enacted an increase to the corporate income tax rate
charged on profits from UK North Sea crude oil and natural gas
production from 50% to 62%. The Company's deferred income tax liability
was increased by $104 million with respect to this tax rate change.
Cash Flow from Operations
Three Months Ended Nine Months Ended
--------------------------------------------------
Sep 30 Jun 30 Sep 30 Sep 30 Sep 30
($ millions) 2012 2012 2011 2012 2011
----------------------------------------------------------------------------
Net earnings $ 360 $ 753 $ 836 $ 1,540 $ 1,811
Non-cash items:
Depletion, depreciation
and amortization 1,056 1,084 887 3,115 2,606
Share-based compensation 49 (115) (249) (173) (309)
Asset retirement
obligation accretion 38 38 33 113 97
Unrealized risk
management loss (gain) 34 (144) (122) (50) (186)
Unrealized foreign
exchange (gain) loss (136) 71 454 (125) 332
Realized foreign exchange
gain on repayment of US
dollar debt securities - - (225) - (225)
Equity loss from jointly
controlled entity 1 5 - 6 -
Deferred income tax
expense 29 62 153 39 263
Horizon asset impairment
provision - - - - 396
Insurance recovery -
property damage - - - - (396)
----------------------------------------------------------------------------
Cash flow from operations $ 1,431 $ 1,754 $ 1,767 $ 4,465 $ 4,389
----------------------------------------------------------------------------
----------------------------------------------------------------------------
SUMMARY OF CONSOLIDATED NET EARNINGS AND CASH FLOW FROM
OPERATIONS
Net earnings for the nine months ended September 30, 2012
amounted to $1,540 million compared with $1,811 million for the
nine months ended September 30, 2011. Net earnings for the nine
months ended September 30, 2012 included net after-tax income of
$281 million compared with net after-tax income of $243 million for
the nine months ended September 30, 2011 related to the effects of
share-based compensation, risk management activities, fluctuations
in foreign exchange rates, the impact of a realized foreign
exchange gain on repayment of long-term debt and the impact of
statutory tax rate and other legislative changes on deferred income
tax liabilities. Excluding these items, adjusted net earnings from
operations for the nine months ended September 30, 2012 were $1,259
million compared with $1,568 million for the nine months ended
September 30, 2011.
Net earnings for the third quarter of 2012 were $360 million
compared with $836 million for the third quarter of 2011 and $753
million for the second quarter of 2012. Net earnings for the third
quarter of 2012 included net after-tax income of $7 million
compared with $117 million for the third quarter of 2011 and $147
million for the second quarter of 2012 related to the effects of
share-based compensation, risk management activities, fluctuations
in foreign exchange rates, the impact of a realized foreign
exchange gain on repayment of long-term debt and the impact of
statutory tax rate and other legislative changes on deferred income
tax liabilities. Excluding these items, adjusted net earnings from
operations for the third quarter of 2012 were $353 million compared
with $719 million for the third quarter of 2011 and $606 million
for the second quarter of 2012.
The decrease in adjusted net earnings for the three and nine
months ended September 30, 2012 from the comparable periods in 2011
was primarily due to:
- lower crude oil and NGLs and natural gas netbacks;
- lower realized synthetic crude oil ("SCO") prices;
- higher depletion, depreciation and amortization expense;
and
- realized risk management losses;
partially offset by:
- higher crude oil and SCO sales volumes in the North America
and Oil Sands Mining and Upgrading segments; and
- the impact of a weaker Canadian dollar.
The decrease in adjusted net earnings for the third quarter of
2012 from the second quarter of 2012 was primarily due to:
- lower SCO sales volumes in the Oil Sands Mining and Upgrading
segment;
- lower crude oil and NGLs netbacks;
- the impact of a stronger Canadian dollar; and
- realized risk management losses;
partially offset by:
- higher crude oil sales volumes in the North America segment;
and
- lower depletion, depreciation and amortization expense.
The impacts of share-based compensation, risk management
activities and changes in foreign exchange rates are expected to
continue to contribute to quarterly volatility in consolidated net
earnings and are discussed in detail in the relevant sections of
this MD&A.
Cash flow from operations for the nine months ended September
30, 2012 was $4,465 million compared with $4,389 million for the
nine months ended September 30, 2011. Cash flow from operations for
the third quarter of 2012 was $1,431 million compared with $1,767
million for the third quarter of 2011 and $1,754 million for the
second quarter of 2012. The fluctuations in cash flow from
operations from the comparable periods was primarily due to the
factors noted above relating to the decrease in adjusted net
earnings, excluding depletion, depreciation and amortization
expense.
Total production before royalties for the nine months ended
September 30, 2012 increased 13% to 653,220 BOE/d from 578,618
BOE/d for the nine months ended September 30, 2011. Total
production before royalties for the third quarter of 2012 increased
9% to 667,616 BOE/d from 612,575 BOE/d for the third quarter of
2011, and decreased 2% from 679,607 BOE/d for the second quarter of
2012. Production for the third quarter of 2012 was within the
Company's previously issued guidance.
SUMMARY OF QUARTERLY RESULTS
The following is a summary of the Company's quarterly results
for the eight most recently completed quarters:
($ millions, except per common share Sep 30 Jun 30 Mar 31 Dec 31
amounts) 2012 2012 2012 2011
----------------------------------------------------------------------------
Product sales $ 3,978 $ 4,187 $ 3,971 $ 4,788
Net earnings (loss) $ 360 $ 753 $ 427 $ 832
Net earnings (loss) per common share
- basic $ 0.33 $ 0.68 $ 0.39 $ 0.76
- diluted $ 0.33 $ 0.68 $ 0.39 $ 0.76
----------------------------------------------------------------------------
----------------------------------------------------------------------------
($ millions, except per common share Sep 30 Jun 30 Mar 31 Dec 31
amounts) 2011 2011 2011 2010
----------------------------------------------------------------------------
Product sales $ 3,690 $ 3,727 $ 3,302 $ 3,787
Net earnings (loss) $ 836 $ 929 $ 46 $ (309)
Net earnings (loss) per common share
- basic $ 0.76 $ 0.85 $ 0.04 $ (0.28)
- diluted $ 0.76 $ 0.84 $ 0.04 $ (0.28)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Volatility in the quarterly net earnings (loss) over the eight
most recently completed quarters was primarily due to:
- Crude oil pricing - The impact of fluctuating demand,
inventory storage levels and geopolitical uncertainties on
worldwide benchmark pricing, the impact of the WCS Heavy
Differential from West Texas Intermediate ("WTI") in North America
and the impact of the differential between WTI and Dated Brent
benchmark pricing in the North Sea and Offshore Africa.
- Natural gas pricing - The impact of fluctuations in both the
demand for natural gas and inventory storage levels, and the impact
of increased shale gas production in the US.
- Crude oil and NGLs sales volumes - Fluctuations in production
due to the cyclic nature of the Company's Primrose thermal
projects, the results from the Pelican Lake water and polymer flood
projects, the record heavy oil drilling program, and the impact of
the suspension and recommencement of production at Horizon. Sales
volumes also reflected fluctuations due to timing of liftings and
maintenance activities in the North Sea and Offshore Africa, and
payout of the Baobab field in May 2011.
- Natural gas sales volumes - Fluctuations in production due to
the Company's strategic decision to reduce natural gas drilling
activity in North America and the allocation of capital to higher
return crude oil projects, as well as natural decline rates and the
impact and timing of acquisitions.
- Production expense - Fluctuations primarily due to the impact
of the demand for services, fluctuations in product mix, the impact
of seasonal costs that are dependent on weather, production and
cost optimizations in North America, acquisitions of natural gas
producing properties that had higher operating costs per Mcf than
the Company's existing properties, and the suspension and
recommencement of production at Horizon.
- Depletion, depreciation and amortization - Fluctuations due to
changes in sales volumes, proved reserves, finding and development
costs associated with crude oil and natural gas exploration,
estimated future costs to develop the Company's proved undeveloped
reserves, the impact of the suspension and recommencement of
production at Horizon and the impact of impairments at the Olowi
field in offshore Gabon.
- Share-based compensation - Fluctuations due to the
determination of fair market value based on the Black-Scholes
valuation model of the Company's share-based compensation
liability.
- Risk management - Fluctuations due to the recognition of gains
and losses from the mark-to-market and subsequent settlement of the
Company's risk management activities.
- Foreign exchange rates - Changes in the Canadian dollar
relative to the US dollar that impacted the realized price the
Company received for its crude oil and natural gas sales, as sales
prices are based predominately on US dollar denominated benchmarks.
Fluctuations in realized and unrealized foreign exchange gains and
losses are recorded with respect to US dollar denominated debt,
partially offset by the impact of cross currency swap hedges.
- Income tax expense - Fluctuations in income tax expense
include statutory tax rate and other legislative changes
substantively enacted in the various periods.
BUSINESS ENVIRONMENT
Three Months Ended Nine Months Ended
--------------------------------------------------
Sep 30 Jun 30 Sep 30 Sep 30 Sep 30
2012 2012 2011 2012 2011
----------------------------------------------------------------------------
WTI benchmark price
(US$/bbl) $ 92.19 $ 93.50 $ 89.81 $ 96.20 $ 95.52
Dated Brent benchmark
price (US$/bbl) $ 109.57 $ 108.21 $ 113.46 $ 112.07 $ 111.96
WCS blend differential
from WTI (US$/bbl) $ 21.78 $ 22.83 $ 17.66 $ 22.03 $ 19.32
WCS blend differential
from WTI (%) 24% 24% 20% 23% 20%
SCO price (US$/bbl) $ 90.84 $ 89.54 $ 100.64 $ 92.82 $ 103.86
Condensate benchmark price
(US$/bbl) $ 96.09 $ 99.49 $ 101.73 $ 101.85 $ 104.27
NYMEX benchmark price
(US$/MMBtu) $ 2.82 $ 2.26 $ 4.19 $ 2.62 $ 4.23
AECO benchmark price
(C$/GJ) $ 2.08 $ 1.74 $ 3.53 $ 2.07 $ 3.55
US/Canadian dollar average
exchange rate (US$) $ 1.0047 $ 0.9897 $ 1.0197 $ 0.9977 $ 1.0224
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Commodity Prices
Crude oil sales contracts in the North America segment are
typically based on WTI benchmark pricing. WTI averaged US$96.20 per
bbl for the nine months ended September 30, 2012 and was comparable
with the nine months ended September 30, 2011. WTI averaged
US$92.19 per bbl for the third quarter of 2012, an increase of 3%
from US$89.81 per bbl for the third quarter of 2011 and was
comparable with the second quarter of 2012. WTI pricing was
reflective of the political instability in the Middle East with
growing tensions between Israel and Iran creating instability in
the crude price; partially offset by declining optimism in the
United States economy, the European debt crisis, and lower than
expected growth in Asian demand.
Crude oil sales contracts for the Company's North Sea and
Offshore Africa segments are typically based on Dated Brent
("Brent") pricing, which is representative of international markets
and overall world supply and demand. Brent averaged US$112.07 per
bbl for the nine months ended September 30, 2012 and was comparable
with the nine months ended September 30, 2011. Brent averaged
US$109.57 per bbl for the third quarter of 2012, a decrease of 3%
compared with US$113.46 per bbl for the third quarter of 2011 and
was comparable with the second quarter of 2012. The higher Brent
pricing relative to WTI was due to logistical constraints and high
inventory levels of crude oil at Cushing. The differential is
expected to narrow with the expansion of the Seaway pipeline in the
first quarter of 2013.
The WCS Heavy Differential averaged 23% for the nine months
ended September 30, 2012 compared with 20% for the nine months
ended September 30, 2011. The WCS Heavy Differential averaged 24%
for the second and third quarters of 2012 compared with 20% in the
third quarter of 2011. The WCS Heavy Differential widened from the
comparable periods in 2011 as a result of planned and unplanned
maintenance at key refineries accessible by Canadian crude oil.
The Company uses condensate as a blending diluent for heavy
crude oil pipeline shipments. During the third quarter of 2012,
condensate prices continued to trade at a premium to WTI, similar
to prior periods, reflecting normal seasonality.
The Company anticipates continued volatility in crude oil
pricing benchmarks due to supply and demand factors, geopolitical
events, and the timing and extent of the economic recovery. The WCS
Heavy Differential is expected to continue to reflect seasonal
demand fluctuations, changes in transportation logistics, and
refinery utilization and shutdowns.
NYMEX natural gas prices averaged US$2.62 per MMBtu for the nine
months ended September 30, 2012, a decrease of 38% from US$4.23 per
MMBtu for the nine months ended September 30, 2011. NYMEX natural
gas prices averaged US$2.82 per MMBtu for the third quarter of
2012, a decrease of 33% from US$4.19 per MMBtu for the third
quarter of 2011, and an increase of 25% from US$2.26 per MMBtu for
the second quarter of 2012.
AECO natural gas prices for the nine months ended September 30,
2012 averaged $2.07 per GJ, a decrease of 42% from $3.55 per GJ for
the nine months ended September 30, 2011. AECO natural gas prices
for the third quarter of 2012 averaged $2.08 per GJ, a decrease of
41% from $3.53 per GJ for the third quarter of 2011, and an
increase of 20% from $1.74 per GJ for the second quarter of
2012.
During the third quarter of 2012, natural gas prices continued
to be weak. While Canadian production has declined in response to
low prices, US production has held steady during 2012. The AECO
natural gas price has increased from the second quarter of 2012 as
a result of a shift to higher utilization of gas fired electric
generators supported by the low natural gas prices, and higher
weather related gas demand resulting from warmer than normal summer
temperatures.
DAILY PRODUCTION, before royalties
Three Months Ended Nine Months Ended
--------------------------------------------------
Sep 30 Jun 30 Sep 30 Sep 30 Sep 30
2012 2012 2011 2012 2011
----------------------------------------------------------------------------
Crude oil and NGLs (bbl/d)
North America -
Exploration and
Production 332,895 316,483 304,671 318,384 296,892
North America - Oil Sands
Mining and Upgrading 99,205 115,823 50,354 87,084 19,365
North Sea 19,502 17,619 26,350 20,054 31,077
Offshore Africa 17,566 20,598 22,525 19,618 23,105
----------------------------------------------------------------------------
469,168 470,523 403,900 445,140 370,439
----------------------------------------------------------------------------
Natural gas (MMcf/d)
North America 1,169 1,230 1,226 1,226 1,223
North Sea 2 2 5 2 7
Offshore Africa 20 23 21 20 19
----------------------------------------------------------------------------
1,191 1,255 1,252 1,248 1,249
----------------------------------------------------------------------------
Total barrels of oil
equivalent (BOE/d) 667,616 679,607 612,575 653,220 578,618
----------------------------------------------------------------------------
Product mix
Light and medium crude oil
and NGLs 15% 15% 17% 16% 19%
Pelican Lake heavy crude
oil 6% 5% 6% 6% 6%
Primary heavy crude oil 19% 18% 17% 19% 18%
Bitumen (thermal oil) 15% 14% 18% 14% 18%
Synthetic crude oil 15% 17% 8% 13% 3%
Natural gas 30% 31% 34% 32% 36%
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Percentage of product
sales (1) (excluding
midstream revenue)
Crude oil and NGLs 92% 93% 85% 92% 85%
Natural gas 8% 7% 15% 8% 15%
----------------------------------------------------------------------------
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(1) Net of transportation and blending costs and excluding risk management
activities.
DAILY PRODUCTION, net of royalties
Three Months Ended Nine Months Ended
--------------------------------------------------
Sep 30 Jun 30 Sep 30 Sep 30 Sep 30
2012 2012 2011 2012 2011
----------------------------------------------------------------------------
Crude oil and NGLs (bbl/d)
North America -
Exploration and
Production 261,655 272,089 251,909 262,561 243,202
North America - Oil Sands
Mining and Upgrading 95,704 109,569 48,509 83,004 18,648
North Sea 19,441 17,578 26,284 20,000 31,000
Offshore Africa 11,662 15,051 18,452 14,726 20,936
----------------------------------------------------------------------------
388,462 414,287 345,154 380,291 313,786
----------------------------------------------------------------------------
Natural gas (MMcf/d)
North America 1,159 1,218 1,189 1,218 1,177
North Sea 2 2 5 2 7
Offshore Africa 16 19 17 17 16
----------------------------------------------------------------------------
1,177 1,239 1,211 1,237 1,200
----------------------------------------------------------------------------
Total barrels of oil
equivalent (BOE/d) 584,577 620,700 546,861 586,337 513,839
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The Company's business approach is to maintain large project
inventories and production diversification among each of the
commodities it produces; namely natural gas, light and medium crude
oil and NGLs, Pelican Lake heavy crude oil, primary heavy crude
oil, bitumen (thermal oil) and SCO.
Crude oil and NGLs production for the nine months ended
September 30, 2012 increased 20% to 445,140 bbl/d from 370,439
bbl/d for the nine months ended September 30, 2011. Crude oil and
NGLs production for the third quarter of 2012 increased 16% to
469,168 bbl/d from 403,900 bbl/d for the third quarter of 2011 and
was comparable with the second quarter of 2012. The increase in
production from the comparable periods in 2011 was primarily
related to increased production at Horizon, the impact of a strong
heavy crude oil drilling program, and the cyclic nature of the
Company's thermal operations. Crude oil and NGLs production in the
third quarter of 2012 was within the Company's previously issued
guidance of 451,000 to 480,000 bbl/d.
Natural gas production for the nine months ended September 30,
2012 averaged 1,248 MMcf/d and was comparable with the nine months
ended September 30, 2011. Natural gas production for the third
quarter of 2012 decreased by 5% to 1,191 MMcf/d from 1,252 MMcf/d
from the third quarter of 2011 and decreased by 5% from 1,255
MMcf/d for the second quarter of 2012. The decrease in natural gas
production for the third quarter of 2012 from the comparable
periods was primarily a result of expected production declines due
to the allocation of capital to higher return crude oil projects,
which continue to result in a strategic reduction of natural gas
drilling activity. The Company shut in approximately 20 MMcf/d of
natural gas production in 2012 and overall has shut in
approximately 40 MMcf/d due to the decrease in natural gas prices.
Natural gas production in the third quarter of 2012 slightly
exceeded the Company's previously issued guidance of 1,170 to 1,190
MMcf/d.
For 2012, annual production guidance is targeted to average
between 452,000 and 460,000 bbl/d of crude oil and NGLs and between
1,222 and 1,229 MMcf/d of natural gas. Fourth quarter 2012
production guidance is targeted to average between 467,000 and
495,000 bbl/d of crude oil and NGLs and between 1,145 and 1,165
MMcf/d of natural gas.
North America - Exploration and Production
North America crude oil and NGLs production for the nine months
ended September 30, 2012 increased 7% to average 318,384 bbl/d from
296,892 bbl/d for the nine months ended September 30, 2011. For the
third quarter of 2012, crude oil and NGLs production increased 9%
to average 332,895 bbl/d compared with 304,671 bbl/d for the third
quarter of 2011 and increased 5% from 316,483 bbl/d for the second
quarter of 2012. Increases in crude oil and NGLs production from
comparable periods were primarily due to the impact of a strong
heavy crude oil drilling program and the cyclic nature of the
Company's thermal operations. Production of crude oil and NGLs was
at the upper end of the Company's previously issued guidance of
322,000 bbl/d to 335,000 bbl/d for the third quarter of 2012.
Fourth quarter 2012 production guidance is targeted to average
between 350,000 and 365,000 bbl/d of crude oil and NGLs.
Natural gas production for the nine months ended September 30,
2012 averaged 1,226 MMcf/d and was comparable with the nine months
ended September 30, 2011. Natural gas production decreased 5% to
1,169 MMcf/d for the third quarter of 2012 compared with 1,226
MMcf/d in the third quarter of 2011 and 1,230 MMcf/d in the second
quarter of 2012. Natural gas production for the third quarter of
2012 decreased from the comparable periods primarily as a result of
expected production declines due to the allocation of capital to
higher return crude oil projects, which continue to result in a
strategic reduction of natural gas drilling activity. The Company
has reduced its drilling activities and shut in approximately 40
MMcf/d of natural gas production due to the decline in natural gas
prices.
North America - Oil Sands Mining and Upgrading
Production averaged 87,084 bbl/d for the nine months ended
September 30, 2012 compared with 19,365 bbl/d for the nine months
ended September 30, 2011. For the third quarter of 2012, SCO
production averaged 99,205 bbl/d compared with 50,354 bbl/d for the
third quarter of 2011 and 115,823 bbl/d for the second quarter of
2012. Production for the three and nine months ended September 30,
2012 increased from the comparable periods in 2011 as production
volumes in 2011 reflected the suspension of production due to the
coker fire incident. Third quarter production in 2012 decreased
from the second quarter as the Company operated at restricted rates
for a portion of the third quarter to ensure safe, steady, reliable
operations in anticipation of the proactive planned 12 day outage
in the fourth quarter. Production of SCO remained within the
Company's previously issued guidance of 95,000 to 105,000 bbl/d for
the third quarter of 2012.
Subsequent to September 30, 2012 the Company completed the 12
day planned maintenance outage followed by a return to full
production. Full year production guidance for 2012 has been revised
to 87,000 bbl/d to 89,000 bbl/d.
North Sea
North Sea crude oil production for the nine months ended
September 30, 2012 decreased 35% to 20,054 bbl/d from 31,077 bbl/d
for the nine months ended September 30, 2011. For the third quarter
of 2012, North Sea crude oil production decreased 26% to 19,502
bbl/d from 26,350 bbl/d for the third quarter of 2011, and
increased 11% from 17,619 bbl/d for the second quarter of 2012. The
decrease in production volumes for the three and nine months ended
September 30, 2012 from the comparable periods in 2011 was
primarily due to temporary shut ins of the third-party operated
pipeline to Sullom Voe for unplanned maintenance, which caused all
Ninian and associated fields to be shut in, planned turnaround
activity, the suspension of production at Banff/Kyle, and natural
field declines due to curtailment of development activities in the
North Sea as a result of corporate tax increases that were enacted
in 2011. The increase in production volumes for the third quarter
of 2012 from the second quarter of 2012 was due to the temporary
reinstatement of the third-party operated pipeline to Sullom Voe,
which was subsequently shut in again in late September 2012, and
the timing of planned turnaround activity. In December 2011, the
Banff Floating Production, Storage and Offloading Vessel ("FPSO")
and subsea infrastructure suffered storm damage. Operations at
Banff/Kyle, with combined net production of approximately 3,500
bbl/d, were suspended and appropriate shut-down procedures were
activated. The FPSO and associated floating storage unit have
subsequently been removed from the field. The extent of the damage,
including associated costs and related property damage, are not
expected to be significant. The timing of returning to the field is
currently being assessed.
Offshore Africa
Offshore Africa crude oil production decreased 15% to 19,618
bbl/d for the nine months ended September 30, 2012 from 23,105
bbl/d for the nine months ended September 30, 2011. Third quarter
crude oil production averaged 17,566 bbl/d, decreasing 22% from
22,525 bbl/d for the third quarter of 2011 and decreasing 15% from
20,598 bbl/d in the second quarter of 2012. The decrease in
production volumes from the comparable periods was due to natural
field declines and the shut in of approximately 1,500 bbl/d of
production at the Olowi field, Gabon as a result of a second
failure in the midwater arch. The Company is currently assessing
the operability of the midwater arch.
International Guidance
The Company's North Sea and Offshore Africa third quarter 2012
crude oil and NGLs production was within the Company's previously
issued guidance of 34,000 to 40,000 bbl/d. Fourth quarter 2012
production guidance is targeted to average between 32,000 and
38,000 bbl/d of crude oil.
Crude Oil Inventory Volumes
The Company recognizes revenue on its crude oil production when
title transfers to the customer and delivery has taken place.
Revenue has not been recognized on crude oil volumes that were
stored in various tanks, pipelines, or floating production, storage
and offloading vessels, as follows:
---------------------------------------------
Sep 30 Jun 30 Dec 31
(bbl) 2012 2012 2011
----------------------------------------------------------------------------
North America - Exploration and
Production 656,340 587,765 557,475
North America - Oil Sands
Mining and Upgrading (SCO) 888,442 1,077,734 1,021,236
North Sea 150,269 - 286,633
Offshore Africa 1,058,992 678,540 527,312
----------------------------------------------------------------------------
2,754,043 2,344,039 2,392,656
----------------------------------------------------------------------------
----------------------------------------------------------------------------
OPERATING HIGHLIGHTS - EXPLORATION AND PRODUCTION
Three Months Ended Nine Months Ended
--------------------------------------------------
Sep 30 Jun 30 Sep 30 Sep 30 Sep 30
2012 2012 2011 2012 2011
----------------------------------------------------------------------------
Crude oil and NGLs ($/bbl)
(1)
Sales price (2) $ 67.59 $ 69.99 $ 73.80 $ 72.43 $ 74.77
Royalties 12.08 9.18 11.52 11.44 11.19
Production expense 15.79 16.66 16.42 16.40 15.37
----------------------------------------------------------------------------
Netback $ 39.72 $ 44.15 $ 45.86 $ 44.59 $ 48.21
----------------------------------------------------------------------------
Natural gas ($/Mcf) (1)
Sales price (2) $ 2.28 $ 1.90 $ 3.76 $ 2.22 $ 3.81
Royalties 0.05 0.05 0.17 0.05 0.18
Production expense 1.30 1.15 1.15 1.27 1.15
----------------------------------------------------------------------------
Netback $ 0.93 $ 0.70 $ 2.44 $ 0.90 $ 2.48
----------------------------------------------------------------------------
Barrels of oil equivalent
($/BOE) (1)
Sales price (2) $ 49.08 $ 49.17 $ 55.19 $ 51.15 $ 55.76
Royalties 7.94 5.93 7.59 7.37 7.43
Production expense 12.97 13.06 12.83 13.15 12.18
----------------------------------------------------------------------------
Netback $ 28.17 $ 30.18 $ 34.77 $ 30.63 $ 36.15
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts expressed on a per unit basis are based on sales volumes.
(2) Net of transportation and blending costs and excluding risk management
activities.
PRODUCT PRICES - EXPLORATION AND PRODUCTION
Three Months Ended Nine Months Ended
--------------------------------------------------
Sep 30 Jun 30 Sep 30 Sep 30 Sep 30
2012 2012 2011 2012 2011
----------------------------------------------------------------------------
Crude oil and NGLs ($/bbl)
(1)(2)
North America $ 63.73 $ 65.10 $ 67.81 $ 67.54 $ 69.21
North Sea $ 106.68 $ 108.22 $ 109.28 $ 111.38 $ 108.18
Offshore Africa $ 112.59 $ 106.30 $ 114.44 $ 115.19 $ 106.93
Company average $ 67.59 $ 69.99 $ 73.80 $ 72.43 $ 74.77
Natural gas ($/Mcf) (1)(2)
North America $ 2.15 $ 1.73 $ 3.67 $ 2.09 $ 3.73
North Sea $ 3.65 $ 3.98 $ 3.26 $ 3.93 $ 4.05
Offshore Africa $ 9.95 $ 10.54 $ 9.38 $ 10.15 $ 8.46
Company average $ 2.28 $ 1.90 $ 3.76 $ 2.22 $ 3.81
Company average ($/BOE)
(1)(2) $ 49.08 $ 49.17 $ 55.19 $ 51.15 $ 55.76
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts expressed on a per unit basis are based on sales volumes.
(2) Net of transportation and blending costs and excluding risk management
activities.
North America
North America realized crude oil prices decreased 2% to average
$67.54 per bbl for the nine months ended September 30, 2012 from
$69.21 per bbl for the nine months ended September 30, 2011. North
America realized crude oil prices averaged $63.73 per bbl for the
third quarter of 2012, a decrease of 6% compared with $67.81 per
bbl for the third quarter of 2011 and a decrease of 2% compared
with $65.10 per bbl for the second quarter of 2012. The decrease in
prices for the three and nine months ended September 30, 2012 from
the comparable periods in 2011 was primarily a result of the
widening of the WCS Heavy Differential; partially offset by the
fluctuations in the Canadian dollar relative to the US dollar. The
Company continues to focus on its crude oil blending marketing
strategy, and in the third quarter of 2012 contributed
approximately 155,000 bbl/d of heavy crude oil blends to the WCS
stream.
In the first quarter of 2011, the Company announced that it had
entered into a partnership agreement with North West Upgrading Inc.
to move forward with detailed engineering regarding the
construction and operation of a bitumen upgrader and refinery ("the
Project") near Redwater, Alberta. In addition, the partnership has
entered into processing agreements that target to process bitumen
for the Company and the Government of Alberta under a 30 year
fee-for-service tolling agreement under the Bitumen Royalty In Kind
initiative. Subsequent to September 30, 2012, the Project was
sanctioned by the Board of Directors of each partner of the North
West Redwater Partnership ("Redwater"), and the associated target
toll amounts were agreed to by Redwater, the Company and the
Government of Alberta.
North America realized natural gas prices decreased 44% to
average $2.09 per Mcf for the nine months ended September 30, 2012
from $3.73 per Mcf for the nine months ended September 30, 2011.
North America realized natural gas prices decreased 41% to average
$2.15 per Mcf for the third quarter of 2012 compared with $3.67 per
Mcf in the third quarter of 2011, and increased 24% compared with
$1.73 per Mcf for the second quarter of 2012. The decrease in
natural gas prices for the three and nine months ended September
30, 2012 from the comparable periods in 2011 was primarily due to
lower NYMEX and AECO benchmark pricing related to the impact of
strong supply from US shale projects. The increase in natural gas
prices for the third quarter of 2012 from the second quarter of
2012 was primarily due to higher NYMEX and AECO benchmark pricing
related to a shift to higher utilization of gas fired electric
generators and higher weather related gas demand resulting from
warmer than normal summer temperatures.
Comparisons of the prices received in North America Exploration
and Production by product type were as follows:
---------------------------------------------
Sep 30 Jun 30 Sep 30
(Quarterly Average) 2012 2012 2011
----------------------------------------------------------------------------
Wellhead Price(1) (2)
Light and medium crude oil and
NGLs ($/bbl) $ 67.33 $ 69.75 $ 78.54
Pelican Lake heavy crude oil
($/bbl) $ 63.03 $ 63.07 $ 66.33
Primary heavy crude oil ($/bbl) $ 61.54 $ 63.69 $ 65.08
Bitumen (thermal oil) ($/bbl) $ 64.56 $ 64.65 $ 65.31
Natural gas ($/Mcf) $ 2.15 $ 1.73 $ 3.67
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts expressed on a per unit basis are based on sales volumes.
(2) Net of transportation and blending costs and excluding risk management
activities.
North Sea
North Sea realized crude oil prices increased 3% to average
$111.38 per bbl for the nine months ended September 30, 2012 from
$108.18 per bbl for the nine months ended September 30, 2011.
Realized crude oil prices averaged $106.68 per bbl for the third
quarter of 2012, a decrease of 2% from $109.28 per bbl for the
third quarter of 2011, and a decrease 1% from $108.22 per bbl for
the second quarter of 2012. The fluctuations in realized crude oil
prices in the North Sea from the comparable periods were primarily
the result of fluctuations in Brent benchmark pricing and the
Canadian dollar, and the timing of liftings.
Offshore Africa
Offshore Africa realized crude oil prices increased 8% to
average $115.19 per bbl for the nine months ended September 30,
2012 from $106.93 per bbl for the nine months ended September 30,
2011. Realized crude oil prices decreased 2% to average $112.59 per
bbl for the third quarter of 2012 from $114.44 per bbl for the
third quarter of 2011, and increased 6% from $106.30 per bbl for
the second quarter of 2012. The fluctuations in realized crude oil
prices in Offshore Africa from the comparable periods were
primarily the result of fluctuations in Brent benchmark pricing and
the Canadian dollar, and the timing of liftings.
ROYALTIES - EXPLORATION AND PRODUCTION
Three Months Ended Nine Months Ended
--------------------------------------------------
Sep 30 Jun 30 Sep 30 Sep 30 Sep 30
2012 2012 2011 2012 2011
----------------------------------------------------------------------------
Crude oil and NGLs ($/bbl)
(1)
North America $ 11.65 $ 8.33 $ 11.78 $ 11.22 $ 12.31
North Sea $ 0.33 $ 0.26 $ 0.27 $ 0.30 $ 0.27
Offshore Africa $ 37.84 $ 28.63 $ 20.69 $ 28.20 $ 11.02
Company average $ 12.08 $ 9.18 $ 11.52 $ 11.44 $ 11.19
Natural gas ($/Mcf) (1)
North America $ 0.02 $ 0.02 $ 0.15 $ 0.02 $ 0.17
Offshore Africa $ 1.89 $ 1.86 $ 1.90 $ 1.78 $ 1.33
Company average $ 0.05 $ 0.05 $ 0.17 $ 0.05 $ 0.18
Company average ($/BOE)
(1) $ 7.94 $ 5.93 $ 7.59 $ 7.37 $ 7.43
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts expressed on a per unit basis are based on sales volumes.
North America
North America crude oil and natural gas royalties for the nine
months ended September 30, 2012 compared with the nine months ended
September 30, 2011 reflected benchmark commodity prices.
Crude oil and NGLs royalties averaged approximately 18% of
product sales for the third quarter of 2012 compared with 17% for
the third quarter of 2011 and 13% for the second quarter of 2012.
The increase in royalties from the second quarter of 2012 was the
result of fluctuating pricing related to production from Oil Sands
Royalty projects. Crude oil and NGLs royalties per bbl are
anticipated to average 16% to 18% of product sales for 2012.
Natural gas royalties averaged approximately 1% of product sales
for the second and third quarters of 2012 compared with 4% for the
third quarter of 2011. The decrease in natural gas royalty rates
from the third quarter of 2011 was due to lower realized natural
gas prices. Natural gas royalties are anticipated to average 1% to
2% of product sales for 2012.
Offshore Africa
Under the terms of the various Production Sharing Contracts,
royalty rates fluctuate based on realized commodity pricing,
capital costs, the status of payouts, and the timing of liftings
from each field.
Royalty rates as a percentage of product sales averaged
approximately 32% for the third quarter of 2012 compared with 18%
for the third quarter of 2011 and 26% for the second quarter of
2012. The increase in royalty rates from the comparable periods was
due to higher crude oil prices during the year, adjustments to
royalties on liftings, and the payout of the Baobab field in May
2011.
Offshore Africa royalty rates are anticipated to average 23% to
28% of product sales for 2012.
PRODUCTION EXPENSE - EXPLORATION AND PRODUCTION
Three Months Ended Nine Months Ended
--------------------------------------------------
Sep 30 Jun 30 Sep 30 Sep 30 Sep 30
2012 2012 2011 2012 2011
----------------------------------------------------------------------------
Crude oil and NGLs ($/bbl)
(1)
North America $ 12.52 $ 13.10 $ 13.38 $ 13.63 $ 12.84
North Sea $ 60.94 $ 68.32 $ 49.72 $ 53.25 $ 37.26
Offshore Africa $ 38.34 $ 22.94 $ 19.91 $ 23.40 $ 19.99
Company average $ 15.79 $ 16.66 $ 16.42 $ 16.40 $ 15.37
Natural gas ($/Mcf) (1)
North America $ 1.28 $ 1.13 $ 1.13 $ 1.25 $ 1.13
North Sea $ 3.44 $ 3.89 $ 2.68 $ 3.78 $ 2.64
Offshore Africa $ 2.37 $ 1.78 $ 2.16 $ 1.97 $ 1.86
Company average $ 1.30 $ 1.15 $ 1.15 $ 1.27 $ 1.15
Company average ($/BOE)
(1) $ 12.97 $ 13.06 $ 12.83 $ 13.15 $ 12.18
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts expressed on a per unit basis are based on sales volumes.
North America
North America crude oil and NGLs production expense for the nine
months ended September 30, 2012 increased 6% to $13.63 per bbl from
$12.84 per bbl for the nine months ended September 30, 2011. North
America crude oil and NGLs production expense for the third quarter
of 2012 decreased 6% to $12.52 per bbl from $13.38 per bbl for the
third quarter of 2011 and decreased 4% from $13.10 per bbl for the
second quarter of 2012. The increase in production expense for the
nine months ended September 30, 2012 from the comparable period in
2011 was a result of higher overall service costs relating to heavy
crude oil production. The decrease in production expense for the
three months ended September 30, 2012 from the comparable period in
2011 was a result of the timing of thermal steam cycles and lower
servicing costs in Pelican and light oil areas. The decrease in
production expense from the second quarter of 2012 was a result of
lower primary heavy oil costs and the timing of thermal steam
cycles. North America crude oil and NGLs production expense is
anticipated to average $12.75 to $13.25 per bbl for 2012.
North America natural gas production expense for the nine months
ended September 30, 2012 increased 11% to $1.25 per Mcf from $1.13
per Mcf for the nine months ended September 30, 2011. North America
natural gas production expense for the third quarter of 2012
increased 13% to $1.28 per Mcf from $1.13 per Mcf for the
comparable periods. Natural gas production expense for the three
and nine months ended September 30, 2012 increased from the
comparable periods in 2011 due to the impact of shut-in production
and lower production volumes related to the curtailment of capital
expenditures related to gas activity. Natural gas production
expense increased in the third quarter of 2012 compared to the
second quarter of 2012 due to seasonal maintenance activity. North
America natural gas production expense is anticipated to average
$1.22 to $1.26 per Mcf for 2012.
North Sea
North Sea crude oil production expense for the nine months ended
September 30, 2012 increased 43% to $53.25 per bbl from $37.26 per
bbl for the nine months ended September 30, 2011. North Sea crude
oil production expense for the third quarter of 2012 increased 23%
to $60.94 per bbl from $49.72 per bbl for the third quarter of
2011, and decreased 11% from $68.32 per bbl for the second quarter
of 2012. Production expense increased on a per barrel basis for the
three and nine months ended September 30, 2012 from the comparable
periods in 2011 due to the impact of production declines on
relatively fixed costs, temporary shut ins of the third-party
operated pipeline to Sullom Voe, and higher maintenance costs
related to turnaround activity completed during the quarter.
Production expense decreased for the third quarter of 2012 from the
second quarter of 2012 due to higher production volumes on
relatively fixed costs. North Sea crude oil production expense is
anticipated to average $52.00 to $53.00 per bbl for 2012.
Offshore Africa
Offshore Africa crude oil production expense increased 17% to
$23.40 per bbl from $19.99 per bbl for the nine months ended
September 30, 2012. Offshore Africa crude oil production expense
for the third quarter of 2012 averaged $38.34 per bbl, an increase
of 93% compared with $19.91 per bbl for the third quarter of 2011
and an increase of 67% compared with $22.94 per bbl for the second
quarter of 2012. Production expense for the three and nine months
ended September 30, 2012 fluctuated from the comparable periods as
a result of the timing of liftings from various fields, which have
different cost structures. Annual Offshore Africa crude oil
production expense is anticipated to average $24.50 to $25.50 per
bbl for 2012.
DEPLETION, DEPRECIATION AND AMORTIZATION - EXPLORATION AND
PRODUCTION
Three Months Ended Nine Months Ended
--------------------------------------------------
Sep 30 Jun 30 Sep 30 Sep 30 Sep 30
2012 2012 2011 2012 2011
----------------------------------------------------------------------------
Expense ($ millions) $ 931 $ 936 $ 809 $ 2,777 $ 2,468
$/BOE (1) $ 18.00 $ 18.13 $ 15.96 $ 17.96 $ 16.29
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts expressed on a per unit basis are based on sales volumes.
Depletion, depreciation and amortization expense increased for
the nine months ended September 30, 2012 compared with 2011 due to
higher production volumes in North America associated with heavy
oil drilling and the impact of higher future development costs.
ASSET RETIREMENT OBLIGATION ACCRETION - EXPLORATION AND
PRODUCTION
Three Months Ended Nine Months Ended
--------------------------------------------------
Sep 30 Jun 30 Sep 30 Sep 30 Sep 30
2012 2012 2011 2012 2011
----------------------------------------------------------------------------
Expense ($ millions) $ 30 $ 30 $ 28 $ 89 $ 82
$/BOE (1) $ 0.59 $ 0.59 $ 0.54 $ 0.58 $ 0.54
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts expressed on a per unit basis are based on sales volumes.
Asset retirement obligation accretion expense represents the
increase in the carrying amount of the asset retirement obligation
due to the passage of time.
OPERATING HIGHLIGHTS - OIL SANDS MINING AND UPGRADING
OPERATIONS UPDATE
On March 13, 2012 the Company successfully and safely completed
the unplanned maintenance on the fractionating unit in the primary
upgrading facility. The positive impact of the third ore
preparation plant ("OPP") and continued emphasis on safe, steady
and reliable operations resulted in production of 99,205 bbl/d of
SCO in the third quarter of 2012, within the Company's previously
issued guidance of 95,000 to 105,000 bbl/d of SCO.
PRODUCT PRICES AND ROYALTIES - OIL SANDS MINING AND
UPGRADING
Three Months Ended Nine Months Ended
--------------------------------------------------
Sep 30 Jun 30 Sep 30 Sep 30 Sep 30
($/bbl) (1) 2012 2012 2011 2012 2011
----------------------------------------------------------------------------
SCO sales price (2) $ 87.40 $ 88.11 $ 96.19 $ 89.39 $ 92.45
Bitumen value for royalty
purposes (3) $ 57.40 $ 59.83 $ 56.54 $ 60.53 $ 59.18
Bitumen royalties (4) $ 3.45 $ 5.20 $ 3.48 $ 4.52 $ 3.60
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts expressed on a per unit basis are based on sales volumes
excluding the period during suspension of production.
(2) Net of transportation.
(3) Calculated as the simple average of the monthly bitumen valuation
methodology price.
(4) Calculated based on actual bitumen royalties expensed during the period;
divided by the corresponding SCO sales volumes.
Realized SCO sales prices averaged $89.39 per bbl for the nine
months ended September 30, 2012, a decrease of 3% compared to
$92.45 per bbl for the nine months ended September 30, 2011.
Realized SCO sales prices averaged $87.40 per bbl for the third
quarter of 2012, a decrease of 9% compared with $96.19 per bbl for
the third quarter of 2011 and a decrease of 1% compared with $88.11
per bbl for the second quarter of 2012, reflecting benchmark
pricing.
PRODUCTION COSTS - OIL SANDS MINING AND UPGRADING
The following tables are reconciled to the Oil Sands Mining and
Upgrading production costs disclosed in the Company's unaudited
interim consolidated financial statements.
Three Months Ended Nine Months Ended
--------------------------------------------------
Sep 30 Jun 30 Sep 30 Sep 30 Sep 30
($ millions) 2012 2012 2011 2012 2011
----------------------------------------------------------------------------
Cash production costs $ 398 $ 388 $ 306 $ 1,132 $ 783
Less: costs incurred
during the period of
suspension of production - - (151) (154) (581)
----------------------------------------------------------------------------
Adjusted cash production
costs $ 398 $ 388 $ 155 $ 978 $ 202
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Adjusted cash production
costs, excluding natural
gas costs $ 373 $ 362 $ 144 $ 912 $ 186
Adjusted natural gas costs 25 26 11 66 16
----------------------------------------------------------------------------
Adjusted cash production
costs $ 398 $ 388 $ 155 $ 978 $ 202
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three Months Ended Nine Months Ended
--------------------------------------------------
Sep 30 Jun 30 Sep 30 Sep 30 Sep 30
($/bbl) (1) 2012 2012 2011 2012 2011
----------------------------------------------------------------------------
Adjusted cash production
costs, excluding natural
gas costs $ 40.03 $ 34.45 $ 33.13 $ 38.05 $ 34.70
Adjusted natural gas costs 2.66 2.53 2.72 2.75 3.02
----------------------------------------------------------------------------
Adjusted cash production
costs $ 42.69 $ 36.98 $ 35.85 $ 40.80 $ 37.72
----------------------------------------------------------------------------
Sales (bbl/d) 101,263 115,552 47,218 87,569 19,663
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts expressed on a per unit basis are based on sales volumes
excluding the period during suspension of production.
Adjusted cash production costs averaged $40.80 per bbl for the
nine months ended September 30, 2012, an increase of 8% compared
with $37.72 per bbl for the nine months ended September 30, 2011.
Adjusted cash production costs for the third quarter of 2012
averaged $42.69 per bbl, an increase of 15% compared with $36.98
per bbl for the second quarter of 2012, primarily due to reduced
production levels. Horizon operated at restricted rates for a
portion of the third quarter of 2012 to ensure safe, steady,
reliable operations in anticipation of the 12 day proactive planned
maintenance outage in the fourth quarter of 2012.
DEPLETION, DEPRECIATION AND AMORTIZATION - OIL SANDS MINING AND
UPGRADING
Three Months Ended Nine Months Ended
--------------------------------------------------
Sep 30 Jun 30 Sep 30 Sep 30 Sep 30
($ millions) 2012 2012 2011 2012 2011
----------------------------------------------------------------------------
Depletion, depreciation
and amortization $ 124 $ 146 $ 77 $ 333 $ 133
Less: depreciation
incurred during the
period of suspension of
production - - (21) (6) (64)
----------------------------------------------------------------------------
Adjusted depletion,
depreciation and
amortization $ 124 $ 146 $ 56 $ 327 $ 69
----------------------------------------------------------------------------
$/bbl (1) $ 13.31 $ 13.84 $ 13.00 $ 13.63 $ 12.88
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts expressed on a per unit basis are based on sales volumes
excluding the period during suspension of production.
Depletion, depreciation and amortization expense for the three
and nine months ended September 30, 2012 increased from the
comparable periods in 2011 primarily due to higher sales
volumes.
ASSET RETIREMENT OBLIGATION ACCRETION - OIL SANDS MINING AND
UPGRADING
Three Months Ended Nine Months Ended
--------------------------------------------------
Sep 30 Jun 30 Sep 30 Sep 30 Sep 30
($ millions) 2012 2012 2011 2012 2011
----------------------------------------------------------------------------
Expense $ 8 $ 8 $ 5 $ 24 $ 15
$/bbl (1) $ 0.85 $ 0.76 $ 1.14 $ 0.99 $ 2.77
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts expressed on a per unit basis are based on sales volumes.
Asset retirement obligation accretion expense represents the
increase in the carrying amount of the asset retirement obligation
due to the passage of time.
MIDSTREAM
Three Months Ended Nine Months Ended
--------------------------------------------------
Sep 30 Jun 30 Sep 30 Sep 30 Sep 30
($ millions) 2012 2012 2011 2012 2011
----------------------------------------------------------------------------
Revenue $ 24 $ 22 $ 23 $ 67 $ 66
Production expense 7 7 7 21 19
----------------------------------------------------------------------------
Midstream cash flow 17 15 16 46 47
Depreciation 1 2 1 5 5
----------------------------------------------------------------------------
Segment earnings before
taxes $ 16 $ 13 $ 15 $ 41 $ 42
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Midstream operating results were consistent with the comparable
periods.
ADMINISTRATION EXPENSE
Three Months Ended Nine Months Ended
--------------------------------------------------
Sep 30 Jun 30 Sep 30 Sep 30 Sep 30
($ millions) 2012 2012 2011 2012 2011
----------------------------------------------------------------------------
Expense $ 64 $ 77 $ 65 $ 206 $ 188
$/BOE (1) $ 1.05 $ 1.24 $ 1.17 $ 1.15 $ 1.20
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts expressed on a per unit basis are based on sales volumes.
Administration expense for the nine months ended September 30,
2012 increased from the comparable period primarily due to higher
staffing related costs and general corporate costs. Administration
expense for the third quarter of 2012 decreased from the second
quarter of 2012 due to increased overhead recoveries associated
with the capital programs.
SHARE-BASED COMPENSATION
Three Months Ended Nine Months Ended
--------------------------------------------------
Sep 30 Jun 30 Sep 30 Sep 30 Sep 30
($ millions) 2012 2012 2011 2012 2011
----------------------------------------------------------------------------
Expense (recovery) $ 49 $ (115) $ (249) $ (173) $ (309)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The Company's stock option plan provides current employees with
the right to receive common shares or a direct cash payment in
exchange for stock options surrendered.
The Company recorded a $173 million share-based compensation
recovery for the nine months ended September 30, 2012, primarily as
a result of remeasurement of the fair value of outstanding stock
options at the end of the period related to a decrease in the
Company's share price, offset by normal course graded vesting of
stock options granted in prior periods and the impact of vested
stock options exercised or surrendered during the period. For the
nine months ended September 30, 2012, a $9 million recovery was
recognized in respect of capitalized share-based compensation to
Oil Sands Mining and Upgrading (September 30, 2011 - $19 million
recovery).
For the nine months ended September 30, 2012, the Company paid
$7 million for stock options surrendered for cash settlement
(September 30, 2011 - $12 million).
INTEREST AND OTHER FINANCING COSTS
Three Months Ended Nine Months Ended
--------------------------------------------------
($ millions, except per Sep 30 Jun 30 Sep 30 Sep 30 Sep 30
BOE amounts) 2012 2012 2011 2012 2011
----------------------------------------------------------------------------
Expense, gross $ 119 $ 114 $ 113 $ 347 $ 330
Less: capitalized interest 27 21 16 66 40
----------------------------------------------------------------------------
Expense, net $ 92 $ 93 $ 97 $ 281 $ 290
$/BOE (1) $ 1.51 $ 1.50 $ 1.75 $ 1.57 $ 1.85
Average effective interest
rate 4.9% 4.8% 4.6% 4.8% 4.7%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts expressed on a per unit basis are based on sales volumes.
Gross interest and other financing costs for the three and nine
months ended September 30, 2012 increased compared with 2011 due to
higher average US dollar debt levels, higher variable interest
rates, and the impact of a weaker Canadian dollar on US dollar
denominated debt; partially offset by lower Canadian dollar
denominated debt levels. Gross interest and other financing costs
for the third quarter of 2012 increased from the second quarter of
2012 due to higher variable interest rates; partially offset by the
impact of a stronger Canadian dollar on US dollar denominated debt.
Capitalized interest of $66 million for the nine months ended
September 30, 2012 related to Horizon Phase 2/3 expansions and the
Kirby Project.
RISK MANAGEMENT ACTIVITIES
The Company utilizes various derivative financial instruments to
manage its commodity price, foreign currency and interest rate
exposures. These derivative financial instruments are not intended
for trading or speculative purposes.
Three Months Ended Nine Months Ended
--------------------------------------------------
Sep 30 Jun 30 Sep 30 Sep 30 Sep 30
($ millions) 2012 2012 2011 2012 2011
----------------------------------------------------------------------------
Crude oil and NGLs
financial instruments $ 18 $ 19 $ 26 $ 46 $ 90
Foreign currency contracts
and interest rate swaps 119 (80) (49) 124 (9)
----------------------------------------------------------------------------
Realized loss (gain) $ 137 $ (61) $ (23) $ 170 $ 81
----------------------------------------------------------------------------
Crude oil and NGLs
financial instruments $ 58 $ (180) $ (71) $ (26) $ (139)
Foreign currency contracts
and interest rate swaps (24) 36 (51) (24) (47)
----------------------------------------------------------------------------
Unrealized loss (gain) $ 34 $ (144) $ (122) $ (50) $ (186)
----------------------------------------------------------------------------
Net loss (gain) $ 171 $ (205) $ (145) $ 120 $ (105)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Complete details related to outstanding derivative financial
instruments at September 30, 2012 are disclosed in note 13 to the
Company's unaudited interim consolidated financial statements.
The Company recorded a net unrealized gain of $50 million ($41
million after-tax) on its risk management activities for the nine
months ended September 30, 2012, including an unrealized loss of
$34 million ($22 million after-tax) for the third quarter of 2012
(June 30, 2012 - unrealized gain of $144 million; $103 million
after-tax; September 30, 2011 - unrealized gain of $122 million;
$97 million after-tax), primarily due to changes in crude oil
forward pricing and the fluctuations of unrealized gains and losses
related to crude oil and foreign currency contracts.
FOREIGN EXCHANGE
Three Months Ended Nine Months Ended
--------------------------------------------------
Sep 30 Jun 30 Sep 30 Sep 30 Sep 30
($ millions) 2012 2012 2011 2012 2011
----------------------------------------------------------------------------
Net realized loss (gain) $ 21 $ (9) $ (243) $ 18 $ (225)
Net unrealized (gain) loss
(1) (136) 71 454 (125) 332
----------------------------------------------------------------------------
Net (gain) loss $ (115) $ 62 $ 211 $ (107) $ 107
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts are reported net of the hedging effect of cross currency swaps.
The net realized foreign exchange loss for the nine months ended
September 30, 2012 was primarily due to foreign exchange rate
fluctuations on settlement of working capital items denominated in
US dollars or UK pounds sterling. The net unrealized foreign
exchange gain for the nine months ended September 30, 2012 was
primarily related to the strengthening of the Canadian dollar with
respect to US dollar debt. The net unrealized loss (gain) for each
of the periods presented included the impact of cross currency
swaps (three months ended September 30, 2012 - unrealized loss of
$85 million; June 30, 2012 - unrealized gain of $47 million;
September 30, 2011 - unrealized gain of $150 million; nine months
ended September 30, 2012 - unrealized loss of $80 million;
September 30, 2011 - unrealized gain of $84 million). The Canadian
dollar ended the third quarter at US$1.0166 (June 30, 2012 -
US$0.9813; September 30, 2011 - US$0.9626).
INCOME TAXES
Three Months Ended Nine Months Ended
-------------------------------------------------
($ millions, except income Sep 30 Jun 30 Sep 30 Sep 30 Sep 30
tax rates) 2012 2012 2011 2012 2011
----------------------------------------------------------------------------
North America (1) $ 61 $ 124 $ 26 $ 298 $ 196
North Sea 22 19 45 86 161
Offshore Africa 50 64 46 150 90
PRT (recovery) expense -
North Sea (19) 1 42 13 96
Other taxes - 5 6 11 18
----------------------------------------------------------------------------
Current income tax 114 213 165 558 561
----------------------------------------------------------------------------
Deferred income tax expense 23 59 157 34 255
Deferred PRT expense
(recovery) - North Sea 6 3 (4) 5 8
----------------------------------------------------------------------------
Deferred income tax expense 29 62 153 39 263
----------------------------------------------------------------------------
143 275 318 597 824
Income tax rate and other
legislative changes (58) - - (58) (104)
----------------------------------------------------------------------------
$ 85 $ 275 $ 318 $ 539 $ 720
----------------------------------------------------------------------------
Effective income tax rate
on adjusted net earnings
from operations (2) 23.8% 27.1% 25.7% 28.5% 26.2%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Includes North America Exploration and Production, Midstream, and Oil
Sands Mining and Upgrading segments.
(2) Excludes the impact of current and deferred PRT expense and other
current income tax expense.
During 2011, the Canadian federal government enacted legislation
to implement several taxation changes. These changes include a
requirement that, beginning in 2012, partnership income must be
included in the taxable income of each corporate partner based on
the tax year of the partner, rather than the fiscal year of the
partnership. The legislation includes a five-year transition
provision and has no impact on net earnings.
During the first quarter of 2011, the UK government enacted an
increase to the supplementary income tax rate charged on profits
from UK North Sea crude oil and natural gas production, increasing
the combined corporate and supplementary income tax rate from 50%
to 62%. As a result of the income tax rate change, the Company's
deferred income tax liability was increased by $104 million as at
March 31, 2011.
During the third quarter of 2012, the UK government enacted
legislation to restrict the combined corporate and supplementary
income tax relief on decommissioning expenditures to 50%. As a
result of the income tax rate change, the Company's deferred income
tax liability was increased by $58 million.
The Company files income tax returns in the various
jurisdictions in which it operates. These tax returns are subject
to periodic examinations in the normal course by the applicable tax
authorities. The tax returns as prepared may include filing
positions that could be subject to differing interpretations of
applicable tax laws and regulations, which may take several years
to resolve. The Company does not believe the ultimate resolution of
these matters will have a material impact upon the Company's
results of operations, financial position or liquidity.
For 2012, based on budgeted prices and the current availability
of tax pools, the Company expects to incur current income tax
expense of $440 million to $480 million in Canada and $300 million
to $350 million in the North Sea and Offshore Africa.
NET CAPITAL EXPENDITURES (1)
Three Months Ended Nine Months Ended
--------------------------------------------------
Sep 30 Jun 30 Sep 30 Sep 30 Sep 30
($ millions) 2012 2012 2011 2012 2011
----------------------------------------------------------------------------
Exploration and Evaluation
Net expenditures $ 59 $ 32 $ 85 $ 299 $ 200
----------------------------------------------------------------------------
Property, Plant and
Equipment
Net property acquisitions 23 7 127 68 616
Well drilling, completion
and equipping 485 352 437 1,336 1,293
Production and related
facilities 533 445 415 1,483 1,210
Capitalized interest and
other (2) 28 30 28 88 78
----------------------------------------------------------------------------
Net expenditures 1,069 834 1,007 2,975 3,197
----------------------------------------------------------------------------
Total Exploration and
Production 1,128 866 1,092 3,274 3,397
----------------------------------------------------------------------------
Oil Sands Mining and
Upgrading
Horizon Phases 2/3
construction costs 354 346 126 892 331
Sustaining capital 41 51 52 129 126
Turnaround costs 11 3 - 16 79
Capitalized interest and
other (2) 24 5 (3) 32 15
----------------------------------------------------------------------------
Total Oil Sands Mining and
Upgrading 430 405 175 1,069 551
----------------------------------------------------------------------------
Horizon coker rebuild and
collateral damage costs
(3) - - 80 - 389
Midstream 5 4 1 10 5
Abandonments (4) 48 39 54 163 147
Head office 10 10 4 25 16
----------------------------------------------------------------------------
Total net capital
expenditures $ 1,621 $ 1,324 $ 1,406 $ 4,541 $ 4,505
----------------------------------------------------------------------------
----------------------------------------------------------------------------
By segment
North America $ 1,029 $ 788 $ 1,045 $ 3,040 $ 3,190
North Sea 79 66 46 199 156
Offshore Africa 20 12 1 35 51
Oil Sands Mining and
Upgrading 430 405 255 1,069 940
Midstream 5 4 1 10 5
Abandonments (4) 48 39 54 163 147
Head office 10 10 4 25 16
----------------------------------------------------------------------------
Total $ 1,621 $ 1,324 $ 1,406 $ 4,541 $ 4,505
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) The net capital expenditures exclude adjustments related to differences
between carrying amounts and tax values, and other fair value
adjustments.
(2) Capitalized interest and other includes expenditures related to land
acquisition and retention, seismic, and other adjustments.
(3) During 2011, the Company recognized $393 million of property damage
insurance recoveries (see note 7 to the interim consolidated financial
statements), offsetting the costs incurred related to the coker rebuild
and collateral damage costs.
(4) Abandonments represent expenditures to settle asset retirement
obligations and have been reflected as capital expenditures in this
table.
The Company's strategy is focused on building a diversified
asset base that is balanced among various products. In order to
facilitate efficient operations, the Company concentrates its
activities in core areas. The Company focuses on maintaining its
land inventories to enable the continuous exploitation of play
types and geological trends, greatly reducing overall exploration
risk. By owning associated infrastructure, the Company is able to
maximize utilization of its production facilities, thereby
increasing control over production costs.
Net capital expenditures for the nine months ended September 30,
2012 were $4,541 million, comparable with $4,505 million for the
nine months ended September 30, 2011. Net capital expenditures for
the third quarter of 2012 were $1,621 million compared with $1,406
million for the third quarter of 2011 and $1,324 million for the
second quarter of 2012.
Excluding the Horizon coker rebuild and collateral damage costs
incurred in 2011, the increase in capital expenditures for the
three and nine months ended September 30, 2012 from 2011 was
primarily due to the ramp up of Horizon field construction
activity, partially offset by lower net property acquisition costs.
The increase in capital expenditures for the three months ended
September 30, 2012 from the second quarter of 2012 was primarily
due to an increase in well drilling and completion activities
related to the primary heavy oil drilling program.
Drilling Activity (number of wells)
Three Months Ended Nine Months Ended
--------------------------------------------------
Sep 30 Jun 30 Sep 30 Sep 30 Sep 30
2012 2012 2011 2012 2011
----------------------------------------------------------------------------
Net successful natural gas
wells 9 4 21 32 56
Net successful crude oil
wells (1) 365 266 317 909 773
Dry wells 6 2 10 14 31
Stratigraphic test /
service wells 22 5 25 611 545
----------------------------------------------------------------------------
Total 402 277 373 1,566 1,405
Success rate (excluding
stratigraphic test /
service wells) 99% 99% 97% 99% 96%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Includes bitumen wells.
North America
North America, excluding Oil Sands Mining and Upgrading,
accounted for approximately 71% of the total capital expenditures
for the nine months ended September 30, 2012 compared with
approximately 74% for the nine months ended September 30, 2011.
During the third quarter of 2012, the Company targeted 9 net
natural gas wells, including 2 wells in Northeast British Columbia
and 7 wells in Northwest Alberta. The Company also targeted 371 net
crude oil wells. The majority of these wells were concentrated in
the Company's Northern Plains region where 267 primary heavy crude
oil wells, 20 Pelican Lake heavy crude oil wells, 1 light crude oil
well and 43 bitumen (thermal oil) wells were drilled. Another 40
wells targeting light crude oil were drilled outside the Northern
Plains region.
Overall Primrose thermal production for the third quarter of
2012 averaged approximately 102,000 bbl/d compared with
approximately 110,000 bbl/d for the third quarter of 2011 and
approximately 94,000 bbl/d for the second quarter of 2012.
Production volumes were in line with expectations due to the cyclic
nature of thermal production at Primrose. As part of the phased
expansion of its in situ Oil Sands assets, the Company is
continuing to develop its Primrose thermal projects. Additional pad
drilling was completed and drilled on budget, with these wells
coming on production in 2013.
The next planned phase of the Company's in situ Oil Sands assets
expansion is the Kirby South Phase 1 Project. As at September 30,
2012, the overall project was 67% complete, drilling was completed
on the fourth of seven pads and first steam is targeted for 2013.
The Company has acquired approximately 49 sections (12,630
hectares) of additional Oil Sands rights immediately adjacent to
the Kirby in situ Oil Sands expansion project.
Development of the tertiary recovery conversion projects at
Pelican Lake continued and 20 horizontal wells were drilled during
the quarter. Pelican Lake production averaged approximately 41,000
bbl/d for the third quarter of 2012 compared with 38,000 bbl/d for
the third quarter of 2011 and 37,000 bbl/d for the second quarter
of 2012.
For the fourth quarter of 2012, the Company's overall planned
drilling activity in North America is expected to be 302 net crude
oil wells, 42 net bitumen wells and 3 net natural gas wells,
excluding stratigraphic and service wells.
Oil Sands Mining and Upgrading
Phase 2/3 expansion activity in the third quarter of 2012 was
focused on the field construction of the gas recovery unit, sulphur
recovery unit, butane treatment unit, coker expansion, and
extraction trains 3 and 4, along with engineering related to the
hydrogen unit, vacuum distillation unit and distillation recovery
unit.
North Sea
In December 2011, the Banff FPSO and subsea infrastructure
suffered storm damage. Operations at Banff/Kyle, with combined net
production of approximately 3,500 bbl/d, were suspended. The FPSO
and associated floating storage unit were subsequently removed from
the field. All personnel on board the FPSO were safe and accounted
for. The extent of the damage, including associated costs and
related property damage, are not expected to be significant. The
timing of returning to the field is currently being assessed.
In March 2011, the UK government enacted an increase to the
corporate income tax rate charged on profits from UK North Sea
crude oil and natural gas production from 50% to 62%. As a result
of the increase in the corporate income tax rate, the Company's
development activities in the North Sea were reduced. The Company
is continuing to high grade all North Sea prospects for potential
development opportunities in 2012 and future years.
In September 2012, the UK government announced the
implementation of the Brownfield Allowance which allows for an
agreed allowance related to property development for certain
pre-approved qualifying field developments. This allowance
partially mitigates the impact of previous tax increases. The
Company is currently assessing the impact of this initiative on its
future capital programs.
Offshore Africa
During the fourth quarter of 2011, the Company sanctioned an 8
well drilling program at the Espoir field in Cote d'Ivoire.
Preparations are ongoing, targeting commencement of drilling
operations in the fourth quarter of 2012. At the Olowi field in
Gabon, approximately 1,500 bbl/d of production was shut in due to a
second failure in the midwater arch. The Company is currently
assessing the operability of the midwater arch.
LIQUIDITY AND CAPITAL RESOURCES
----------------------------------------
Sep 30 Jun 30 Dec 31 Sep 30
($ millions, except ratios) 2012 2012 2011 2011
----------------------------------------------------------------------------
Working capital (deficit) (1) $ (1,002) $ (732) $ (894) $ (213)
Long-term debt (2) (3) $ 8,416 $ 8,522 $ 8,571 $ 9,327
Share capital $ 3,691 $ 3,670 $ 3,507 $ 3,431
Retained earnings 20,383 20,193 19,365 18,642
Accumulated other comprehensive
income 46 59 26 71
----------------------------------------------------------------------------
Shareholders' equity $ 24,120 $ 23,922 $ 22,898 $ 22,144
Debt to book capitalization (3) (4) 26% 26% 27% 30%
Debt to market capitalization (3)
(5) 20% 22% 17% 22%
After-tax return on average common
shareholders' equity (6) 10% 12% 12% 7%
After-tax return on average capital
employed (3) (7) 8% 10% 10% 6%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Calculated as current assets less current liabilities, excluding the
current portion of long-term debt.
(2) Includes the current portion of long-term debt.
(3) Long-term debt is stated at its carrying value, net of fair value
adjustments, original issue discounts and transaction costs.
(4) Calculated as current and long-term debt; divided by the book value of
common shareholders' equity plus current and long-term debt.
(5) Calculated as current and long-term debt; divided by the market value of
common shareholders' equity plus current and long-term debt.
(6) Calculated as net earnings for the twelve month trailing period; as a
percentage of average common shareholders' equity for the period.
(7) Calculated as net earnings plus after-tax interest and other financing
costs for the twelve month trailing period; as a percentage of average
capital employed for the period.
At September 30, 2012, the Company's capital resources consisted
primarily of cash flow from operations, available bank credit
facilities and access to debt capital markets. Cash flow from
operations and the Company's ability to renew existing bank credit
facilities and raise new debt is dependent on factors discussed in
the "Risks and Uncertainties" section of the Company's December 31,
2011 annual MD&A. In addition, the Company's ability to renew
existing bank credit facilities and raise new debt is also
dependent upon maintaining an investment grade debt rating and the
condition of capital and credit markets. The Company continues to
believe that its internally generated cash flow from operations
supported by the implementation of its ongoing hedge policy, the
flexibility of its capital expenditure programs supported by its
multi-year financial plans, its existing bank credit facilities,
and its ability to raise new debt on commercially acceptable terms
will provide sufficient liquidity to sustain its operations in the
short, medium and long term and support its growth strategy. At
September 30, 2012, the Company had $4,261 million of available
credit under its bank credit facilities.
Over the next 12 months, the Company has maturities of long-term
debt aggregating $1,138 million (US$350 million due October 2012,
$400 million due January 2013 and US$400 million due February
2013). It is the Company's intention to retire this indebtedness
utilizing cash flow from operations generated in excess of capital
expenditures and available bank credit facilities as necessary,
while maintaining the ongoing dividend program. On a pro forma
basis, reflecting the retirement of this indebtedness, the
available credit under its bank credit facilities at September 30,
2012 would amount to $3,123 million.
During the second quarter of 2012, the $1,500 million revolving
syndicated credit facility was extended to June 2016. Additionally,
the Company issued $500 million of 3.05% medium-term notes due June
2019. Proceeds from the securities issued were used to repay bank
indebtedness and for general corporate purposes. After issuing
these securities, the Company has $2,500 million remaining on its
outstanding $3,000 million base shelf prospectus that allows for
the issue of medium-term notes in Canada, which expires in November
2013. If issued, these securities will bear interest as determined
at the date of issuance.
The Company has US$2,000 million remaining on its outstanding
US$3,000 million base shelf prospectus that allows for the issue of
US dollar debt securities in the United States, which expires in
November 2013. If issued, these securities will bear interest as
determined at the date of issuance. Subsequent to September 30,
2012, US$350 million of US dollar denominated debt securities
bearing interest at 5.45% were repaid.
Long-term debt was $8,416 million at September 30, 2012,
resulting in a debt to book capitalization ratio of 26% (June 30,
2012 - 26%; September 30, 2011 - 30%). This ratio is below the 35%
to 45% internal range utilized by management. This range may be
exceeded in periods when a combination of capital projects,
acquisitions, or lower commodity prices occurs. The Company may be
below the low end of the targeted range when cash flow from
operating activities is greater than current investment activities.
The Company remains committed to maintaining a strong balance
sheet, adequate available liquidity and a flexible capital
structure. The Company has hedged a portion of its crude oil
production for 2012 and 2013 at prices that protect investment
returns to ensure ongoing balance sheet strength and the completion
of its capital expenditure programs. Further details related to the
Company's long-term debt at September 30, 2012 are discussed in
note 5 to the Company's unaudited interim consolidated financial
statements.
The Company's commodity hedging policy reduces the risk of
volatility in commodity prices and supports the Company's cash flow
for its capital expenditures programs. This policy currently allows
for the hedging of up to 60% of the near 12 months budgeted
production and up to 40% of the following 13 to 24 months estimated
production. For the purpose of this policy, the purchase of put
options is in addition to the above parameters. As at November 6,
2012, approximately 60% of currently forecasted fourth quarter 2012
crude oil volumes were hedged using collars and puts. Further
details related to the Company's commodity related derivative
financial instruments outstanding at September 30, 2012 are
discussed in note 13 to the Company's unaudited interim
consolidated financial statements.
Share Capital
As at September 30, 2012, there were 1,095,134,000 common shares
outstanding and 66,029,000 stock options outstanding. As at
November 5, 2012, the Company had 1,094,484,000 common shares
outstanding and 65,435,000 stock options outstanding.
During the second quarter of 2012, the Company amended its
Articles by special resolution of the Shareholders, changing the
designation of its Class 1 preferred shares to "Preferred Shares"
which may be issuable in series. If issued, the number of shares in
each series, and the designation, rights, privileges, restrictions
and conditions attached to the shares will be determined by the
Board of Directors of the Company.
On March 6, 2012, the Company's Board of Directors approved an
increase in the annual dividend to be paid by the Company to $0.42
per common share for 2012. The increase represents an approximately
17% increase from 2011, recognizing the stability of the Company's
cash flow and providing a return to shareholders. The dividend
policy undergoes a periodic review by the Board of Directors and is
subject to change.
In April 2012, the Company announced a Normal Course Issuer Bid
to purchase, through the facilities of the Toronto Stock Exchange
("TSX") and the New York Stock Exchange ("NYSE"), during the twelve
month period commencing April 9, 2012 and ending April 8, 2013, up
to 55,027,447 common shares.
On March 31, 2011, the Company announced a Normal Course Issuer
Bid to purchase, through the facilities of the TSX and the NYSE,
during the twelve month period commencing April 6, 2011 and ending
April 5, 2012, up to 27,406,131 common shares of the Company.
As at September 30, 2012, 6,876,200 common shares (June 30, 2012
- 4,621,600 common shares; March 31, 2012 - 692,200 common shares)
had been purchased for cancellation at a weighted average price of
$29.10 per common share (June 30, 2012 - $29.63 per common share;
March 31, 2012 - $33.11 per common share), for a total cost of $200
million (June 30, 2012 - $137 million; March 31, 2012 - $23
million). Subsequent to September 30, 2012, the Company purchased
949,000 common shares at a weighted average price of $30.18 per
common share for a total cost of $29 million.
COMMITMENTS AND OFF BALANCE SHEET ARRANGEMENTS
In the normal course of business, the Company has entered into
various commitments that will have an impact on the Company's
future operations. As at September 30, 2012, no entities were
consolidated under the Standing Interpretations Committee ("SIC")
12, "Consolidation - Special Purpose Entities". The following table
summarizes the Company's commitments as at September 30, 2012:
Remaining
($ millions) 2012 2013 2014 2015 2016 Thereafter
----------------------------------------------------------------------------
Product transportation
and pipeline $ 58 $ 213 $ 204 $ 192 $ 126 $ 889
Offshore equipment
operating leases and
offshore drilling $ 43 $ 153 $ 120 $ 103 $ 75 $ 121
Long-term debt (1) $ 344 $ 794 $ 836 $ 437 $ 589 $ 5,468
Interest and other
financing costs (2) $ 103 $ 397 $ 377 $ 343 $ 329 $ 3,997
Office leases $ 8 $ 32 $ 35 $ 33 $ 34 $ 309
Other $ 76 $ 169 $ 95 $ 42 $ 10 $ 8
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Long-term debt represents principal repayments only and does not reflect
fair value adjustments, original issue discounts or transaction costs.
(2) Interest and other financing cost amounts represent the scheduled fixed
rate and variable rate cash interest payments related to long-term debt.
Interest on variable rate long-term debt was estimated based upon
prevailing interest rates and foreign exchange rates as at September 30,
2012.
In addition to the commitments disclosed above, the Company has
entered into various agreements related to the engineering,
procurement and construction of subsequent phases of Horizon. These
contracts can be cancelled by the Company upon notice without
penalty, subject to the costs incurred up to and in respect of the
cancellation.
LEGAL PROCEEDINGS AND OTHER CONTINGENCIES
The Company is a defendant and plaintiff in a number of legal
actions arising in the normal course of business. In addition, the
Company is subject to certain contractor construction claims. The
Company believes that any liabilities that might arise pertaining
to any such matters would not have a material effect on its
consolidated financial position.
ACCOUNTING STANDARDS ISSUED BUT NOT YET APPLIED
For the impact of new accounting standards, refer to the
MD&A and the audited consolidated financial statements for the
year ended December 31, 2011.
CRITICAL ACCOUNTING ESTIMATES AND CHANGE IN ACCOUNTING
POLICIES
The preparation of financial statements requires the Company to
make estimates, assumptions and judgements in the application of
IFRS that have a significant impact on the financial results of the
Company. Actual results could differ from estimated amounts, and
those differences may be material. A comprehensive discussion of
the Company's significant accounting policies is contained in the
MD&A and the audited consolidated financial statements for the
year ended December 31, 2011.
Consolidated Balance Sheets
------------------------------
As at
(millions of Canadian dollars, Sep 30 Dec 31
unaudited) Note 2012 2011
----------------------------------------------------------------------------
ASSETS
Current assets
Cash and cash equivalents $ 21 $ 34
Accounts receivable 1,365 2,077
Inventory 570 550
Prepaids and other 191 120
----------------------------------------------------------------------------
2,147 2,781
Exploration and evaluation assets 2 2,660 2,475
Property, plant and equipment 3 42,724 41,631
Other long-term assets 4 338 391
----------------------------------------------------------------------------
$ 47,869 $ 47,278
----------------------------------------------------------------------------
----------------------------------------------------------------------------
LIABILITIES
Current liabilities
Accounts payable $ 525 $ 526
Accrued liabilities 2,218 2,347
Current income tax liabilities 232 347
Current portion of long-term debt 5 1,138 359
Current portion of other long-term
liabilities 6 174 455
----------------------------------------------------------------------------
4,287 4,034
Long-term debt 5 7,278 8,212
Other long-term liabilities 6 3,954 3,913
Deferred income tax liabilities 8,230 8,221
----------------------------------------------------------------------------
23,749 24,380
----------------------------------------------------------------------------
SHAREHOLDERS' EQUITY
Share capital 9 3,691 3,507
Retained earnings 20,383 19,365
Accumulated other comprehensive income 10 46 26
----------------------------------------------------------------------------
24,120 22,898
----------------------------------------------------------------------------
$ 47,869 $ 47,278
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Commitments and contingencies (note 14).
Approved by the Board of Directors on November 6, 2012
Consolidated Statements of Earnings
Three Months Ended Nine Months Ended
----------------------------------------
(millions of Canadian dollars,
except per common share Sep 30 Sep 30 Sep 30 Sep 30
amounts, unaudited) Note 2012 2011 2012 2011
----------------------------------------------------------------------------
Product sales $ 3,978 $ 3,690 $ 12,136 $ 10,719
Less: royalties (442) (400) (1,247) (1,145)
----------------------------------------------------------------------------
Revenue 3,536 3,290 10,889 9,574
----------------------------------------------------------------------------
Expenses
Production 1,071 959 3,177 2,637
Transportation and blending 606 459 2,014 1,745
Depletion, depreciation and
amortization 3 1,056 887 3,115 2,606
Administration 64 65 206 188
Share-based compensation 6 49 (249) (173) (309)
Asset retirement obligation
accretion 6 38 33 113 97
Interest and other financing
costs 92 97 281 290
Risk management activities 13 171 (145) 120 (105)
Foreign exchange (gain) loss (115) 211 (107) 107
Horizon asset impairment
provision 7 - - - 396
Insurance recovery - property
damage 7 - - - (396)
Insurance recovery - business
interruption 7 - (181) - (317)
Equity loss from jointly
controlled entity 4 1 - 6 -
----------------------------------------------------------------------------
3,033 2,136 8,752 6,939
----------------------------------------------------------------------------
Earnings before taxes 503 1,154 2,137 2,635
Current income tax expense 8 114 165 558 561
Deferred income tax expense 8 29 153 39 263
----------------------------------------------------------------------------
Net earnings $ 360 $ 836 $ 1,540 $ 1,811
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net earnings per common share
Basic 12 $ 0.33 $ 0.76 $ 1.40 $ 1.65
Diluted 12 $ 0.33 $ 0.76 $ 1.40 $ 1.64
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Consolidated Statements of Comprehensive Income
Three Months Ended Nine Months Ended
----------------------------------------
(millions of Canadian dollars, Sep 30 Sep 30 Sep 30 Sep 30
unaudited) 2012 2011 2012 2011
----------------------------------------------------------------------------
Net earnings $ 360 $ 836 $ 1,540 $ 1,811
----------------------------------------------------------------------------
Net change in derivative financial
instruments designated as cash flow
hedges
Unrealized (loss) income during the
period, net of taxes of
$3 million (2011 - $6 million) -
three months ended;
$2 million (2011 - $5 million) -
nine months ended (20) 46 14 44
Reclassification to net earnings,
net of taxes of
$nil (2011 - $4 million) - three
months ended;
$nil (2011 - $13 million) - nine
months ended (3) 12 (4) 41
----------------------------------------------------------------------------
(23) 58 10 85
Foreign currency translation
adjustment
Translation of net investment 10 (25) 10 (23)
----------------------------------------------------------------------------
Other comprehensive (loss) income,
net of taxes (13) 33 20 62
----------------------------------------------------------------------------
Comprehensive income $ 347 $ 869 $ 1,560 $ 1,873
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Consolidated Statements of Changes in Equity
Nine Months Ended
--------------------------------
(millions of Canadian dollars, Sep 30 Sep 30
unaudited) Note 2012 2011
----------------------------------------------------------------------------
Share capital 9
Balance - beginning of period $ 3,507 $ 3,147
Issued upon exercise of stock options 164 192
Previously recognized liability on stock
options exercised for common shares 43 100
Purchase of common shares under Normal
Course Issuer Bid (23) (8)
----------------------------------------------------------------------------
Balance - end of period 3,691 3,431
----------------------------------------------------------------------------
Retained earnings
Balance - beginning of period 19,365 17,212
Net earnings 1,540 1,811
Purchase of common shares under Normal
Course Issuer Bid 9 (177) (84)
Dividends on common shares 9 (345) (297)
----------------------------------------------------------------------------
Balance - end of period 20,383 18,642
----------------------------------------------------------------------------
Accumulated other comprehensive income 10
Balance - beginning of period 26 9
Other comprehensive income, net of taxes 20 62
----------------------------------------------------------------------------
Balance - end of period 46 71
----------------------------------------------------------------------------
Shareholders' equity $ 24,120 $ 22,144
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Consolidated Statements of Cash Flows
Three Months Ended Nine Months Ended
----------------------------------------
(millions of Canadian dollars, Sep 30 Sep 30 Sep 30 Sep 30
unaudited) Note 2012 2011 2012 2011
----------------------------------------------------------------------------
Operating activities
Net earnings $ 360 $ 836 $ 1,540 $ 1,811
Non-cash items
Depletion, depreciation and
amortization 1,056 887 3,115 2,606
Share-based compensation 49 (249) (173) (309)
Asset retirement obligation
accretion 38 33 113 97
Unrealized risk management loss
(gain) 34 (122) (50) (186)
Unrealized foreign exchange
(gain) loss (136) 454 (125) 332
Realized foreign exchange gain
on repayment of US dollar debt
securities - (225) - (225)
Equity loss from jointly
controlled entity 4 1 - 6 -
Deferred income tax expense 29 153 39 263
Horizon asset impairment
provision 7 - - - 396
Insurance recovery - property
damage 7 - - - (396)
Other 7 9 47 (9)
Abandonment expenditures (48) (54) (163) (147)
Net change in non-cash working
capital 132 (469) 245 (303)
----------------------------------------------------------------------------
1,522 1,253 4,594 3,930
----------------------------------------------------------------------------
Financing activities
Issue (repayment) of bank credit
facilities, net 139 652 (420) 985
Repayment of US dollar debt
securities - (390) - (390)
Issue of medium-term notes, net - - 498 -
Issue of common shares on
exercise of stock options 24 11 164 192
Purchase of common shares under
Normal Course Issuer Bid (63) (92) (200) (92)
Dividends on common shares (115) (99) (329) (279)
Net change in non-cash working
capital (13) (5) (29) (10)
----------------------------------------------------------------------------
(28) 77 (316) 406
----------------------------------------------------------------------------
Investing activities
Expenditures on exploration and
evaluation assets and property,
plant and equipment (1,573) (1,352) (4,378) (4,358)
Investment in other long-term
assets - - 2 (346)
Net change in non-cash working
capital 90 34 85 364
----------------------------------------------------------------------------
(1,483) (1,318) (4,291) (4,340)
----------------------------------------------------------------------------
Increase (decrease) in cash and
cash equivalents 11 12 (13) (4)
Cash and cash equivalents -
beginning of period 10 6 34 22
----------------------------------------------------------------------------
Cash and cash equivalents - end
of period $ 21 $ 18 $ 21 $ 18
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Interest paid $ 134 $ 151 $ 360 $ 376
Income taxes paid $ 99 $ 141 $ 534 $ 516
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Notes to the Consolidated Financial Statements
(tabular amounts in millions of Canadian dollars, unless
otherwise stated, unaudited)
1. ACCOUNTING POLICIES
Canadian Natural Resources Limited (the "Company") is a senior
independent crude oil and natural gas exploration, development and
production company. The Company's exploration and production
operations are focused in North America, largely in Western Canada;
the United Kingdom ("UK") portion of the North Sea; and Cote
d'Ivoire, Gabon, and South Africa in Offshore Africa.
The Horizon Oil Sands Mining and Upgrading segment ("Horizon")
produces synthetic crude oil through bitumen mining and upgrading
operations.
Within Western Canada, the Company maintains certain midstream
activities that include pipeline operations and an electricity
co-generation system.
The Company was incorporated in Alberta, Canada. The address of
its registered office is 2500, 855-2 Street S.W., Calgary,
Alberta.
These interim consolidated financial statements have been
prepared in accordance with International Financial Reporting
Standards ("IFRS") as issued by the International Accounting
Standards Board, applicable to the preparation of interim financial
statements, including International Accounting Standard ("IAS") 34,
"Interim Financial Reporting", following the same accounting
policies as the audited consolidated financial statements of the
Company as at December 31, 2011. These interim consolidated
financial statements contain disclosures that are supplemental to
the Company's annual audited consolidated financial statements.
Certain disclosures that are normally required to be included in
the notes to the annual audited consolidated financial statements
have been condensed. These interim consolidated financial
statements should be read in conjunction with the Company's audited
consolidated financial statements and notes thereto for the year
ended December 31, 2011.
2. EXPLORATION AND EVALUATION ASSETS
Oil Sands
Mining
and
Exploration and Production Upgrading Total
----------------------------------------------------------------------------
North Offshore
America North Sea Africa
----------------------------------------------------------------------------
Cost
At December 31, 2011 $ 2,442 $ - $ 33 $ - $ 2,475
Additions 294 - 5 - 299
Transfers to property,
plant and equipment (114) - - - (114)
----------------------------------------------------------------------------
At September 30, 2012 $ 2,622 $ - $ 38 $ - $ 2,660
----------------------------------------------------------------------------
----------------------------------------------------------------------------
3. PROPERTY, PLANT AND EQUIPMENT
Oil Sands
Mining
and
Exploration and Production Upgrading
----------------------------------------------------------------------------
North Offshore
America North Sea Africa
----------------------------------------------------------------------------
Cost
At December 31, 2011 $ 46,120 $ 4,147 $ 3,044 $ 15,211
Additions 2,787 205 32 1,108
Transfers from E&E assets 114 - - -
Disposals/ derecognitions (84) (39) (8) (5)
Foreign exchange adjustments and
other - (139) (101) -
----------------------------------------------------------------------------
At September 30, 2012 $ 48,937 $ 4,174 $ 2,967 $ 16,314
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Accumulated depletion and depreciation
At December 31, 2011 $ 21,721 $ 2,512 $ 2,152 $ 776
Expense 2,438 220 107 333
Disposals/ derecognitions (84) (39) (6) (5)
Foreign exchange adjustments and
other - (86) (62) (21)
----------------------------------------------------------------------------
At September 30, 2012 $ 24,075 $ 2,607 $ 2,191 $ 1,083
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net book value
- at September 30, 2012 $ 24,862 $ 1,567 $ 776 $ 15,231
- at December 31, 2011 $ 24,399 $ 1,635 $ 892 $ 14,435
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Midstream Head Office Total
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Cost
At December 31, 2011 $ 298 $ 234 $ 69,054
Additions 10 25 4,167
Transfers from E&E assets - - 114
Disposals/ derecognitions - - (136)
Foreign exchange adjustments and
other - - (240)
----------------------------------------------------------------------------
At September 30, 2012 $ 308 $ 259 $ 72,959
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Accumulated depletion and
depreciation
At December 31, 2011 $ 96 $ 166 $ 27,423
Expense 5 12 3,115
Disposals/ derecognitions - - (134)
Foreign exchange adjustments and
other - - (169)
----------------------------------------------------------------------------
At September 30, 2012 $ 101 $ 178 $ 30,235
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net book value
- at September 30, 2012 $ 207 $ 81 $ 42,724
- at December 31, 2011 $ 202 $ 68 $ 41,631
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Development projects not subject to depletion
----------------------------------------------------------------------------
At September 30, 2012 $ 1,669
At December 31, 2011 $ 1,443
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The Company acquired a number of producing crude oil and natural
gas assets in the North America Exploration and Production segment
for total cash consideration of $67 million during the nine months
ended September 30, 2012 (year ended December 31, 2011 - $1,012
million), net of associated asset retirement obligations of $4
million (year ended December 31, 2011 - $79 million). Interests in
jointly controlled assets were acquired with full tax basis. No
working capital or debt obligations were assumed.
The Company capitalizes construction period interest for
qualifying assets based on costs incurred and the Company's cost of
borrowing. Interest capitalization to a qualifying asset ceases
once construction is substantially complete. For the nine months
ended September 30, 2012, pre-tax interest of $66 million was
capitalized to property, plant and equipment (September 30, 2011 -
$40 million) using a capitalization rate of 4.8% (September 30,
2011 - 4.7%).
4. OTHER LONG-TERM ASSETS
------------------------------
Sep 30 Dec 31
2012 2011
----------------------------------------------------------------------------
Investment in North West Redwater Partnership $ 313 $ 321
Other 25 70
----------------------------------------------------------------------------
$ 338 $ 391
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Other long-term assets include an investment in the 50% owned
North West Redwater Partnership ("Redwater"). The investment is
accounted for using the equity method. Redwater has committed to
construct and operate a bitumen upgrader and refinery (the
"Project") under processing agreements that target to process
bitumen for the Company and the Government of Alberta under a 30
year fee-for-service tolling agreement. Subsequent to September 30,
2012, the Project was sanctioned by the Board of Directors of each
partner of Redwater, and the associated target toll amounts were
agreed to by Redwater, the Company and the Government of
Alberta.
5. LONG-TERM DEBT
------------------------------
Sep 30 Dec 31
2012 2011
----------------------------------------------------------------------------
Canadian dollar denominated debt
Bank credit facilities $ 380 $ 796
Medium-term notes 1,300 800
----------------------------------------------------------------------------
1,680 1,596
----------------------------------------------------------------------------
US dollar denominated debt
US dollar debt securities (US$6,900 million) 6,788 7,017
Less: original issue discount on US dollar
debt securities (1) (21) (21)
----------------------------------------------------------------------------
6,767 6,996
Fair value impact of interest rate swaps on US
dollar debt securities (2) 21 31
----------------------------------------------------------------------------
6,788 7,027
----------------------------------------------------------------------------
Long-term debt before transaction costs 8,468 8,623
Less: transaction costs (1) (3) (52) (52)
----------------------------------------------------------------------------
8,416 8,571
Less: current portion (1) (2) (4) 1,138 359
----------------------------------------------------------------------------
$ 7,278 $ 8,212
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) The Company has included unamortized original issue discounts and
directly attributable transaction costs in the carrying amount of the
outstanding debt.
(2) The carrying amounts of US$350 million of 5.45% notes due October 2012
and US$350 million of 4.90% notes due December 2014 were adjusted by $21
million (December 31, 2011 - $31 million) to reflect the fair value
impact of hedge accounting.
(3) Transaction costs primarily represent underwriting commissions charged
as a percentage of the related debt offerings, as well as legal, rating
agency and other professional fees.
(4) Subsequent to September 30, 2012, US$350 million of US dollar
denominated debt securities bearing interest at 5.45% were repaid.
Bank Credit Facilities
As at September 30, 2012, the Company had in place unsecured
bank credit facilities of $4,724 million, comprised of:
- a $200 million demand credit facility;
- a revolving syndicated credit facility of $3,000 million
maturing June 2015;
- a revolving syndicated credit facility of $1,500 million
maturing June 2016; and
- a GBP 15 million demand credit facility related to the
Company's North Sea operations.
During the second quarter of 2012, the $1,500 million revolving
syndicated credit facility was extended to June 2016. Each of the
$3,000 million and $1,500 million facilities is extendible annually
for one-year periods at the mutual agreement of the Company and the
lenders. If the facilities are not extended, the full amount of the
outstanding principal would be repayable on the maturity date.
Borrowings under these facilities may be made by way of pricing
referenced to Canadian dollar or US dollar bankers' acceptances, or
LIBOR, US base rate or Canadian prime loans.
The Company's weighted average interest rate on bank credit
facilities outstanding as at September 30, 2012, was 2.0%
(September 30, 2011 - 2.3%), and on long-term debt outstanding for
the nine months ended September 30, 2012 was 4.8% (September 30,
2011 - 4.7%).
In addition to the outstanding debt, letters of credit and
financial guarantees aggregating $561 million, including $95
million related to Horizon and $271 million related to North Sea
operations, were outstanding at September 30, 2012. During the
third quarter of 2012, the Company issued a financial guarantee for
$100 million supporting a revolving credit facility in the 50%
owned North West Redwater Partnership.
Subsequent to September 30, 2012, the financial guarantee
related to Horizon was reduced to $87 million and the financial
guarantee related to Redwater was increased by $25 million to $125
million.
Medium-Term Notes
During the second quarter of 2012, the Company issued $500
million of 3.05% medium-term unsecured notes due June 2019. After
issuing these securities, the Company has $2,500 million remaining
on its outstanding $3,000 million base shelf prospectus that allows
for the issue of medium-term notes in Canada, which expires in
November 2013. If issued, these securities will bear interest as
determined at the date of issuance.
US Dollar Debt Securities
The Company has US$2,000 million remaining on its outstanding
US$3,000 million base shelf prospectus that allows for the issue of
US dollar debt securities in the United States, which expires in
November 2013. If issued, these securities will bear interest as
determined at the date of issuance.
6. OTHER LONG-TERM LIABILITIES
------------------------------
Sep 30 Dec 31
2012 2011
----------------------------------------------------------------------------
Asset retirement obligations $ 3,544 $ 3,577
Share-based compensation 200 432
Risk management (note 13) 292 274
Other 92 85
----------------------------------------------------------------------------
4,128 4,368
Less: current portion 174 455
----------------------------------------------------------------------------
$ 3,954 $ 3,913
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Asset retirement obligations
The Company's asset retirement obligations are expected to be
settled on an ongoing basis over a period of approximately 60 years
and have been discounted using a weighted average discount rate of
4.6% (December 31, 2011 - 4.6%). A reconciliation of the discounted
asset retirement obligations is as follows:
------------------------------
Sep 30 Dec 31
2012 2011
----------------------------------------------------------------------------
Balance - beginning of period $ 3,577 $ 2,624
Liabilities incurred 37 12
Liabilities acquired 4 79
Liabilities settled (163) (213)
Asset retirement obligation accretion 113 130
Revision of estimates 5 924
Foreign exchange (29) 21
----------------------------------------------------------------------------
Balance - end of period $ 3,544 $ 3,577
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Share-based compensation
As the Company's Option Plan provides current employees with the
right to elect to receive common shares or a cash payment in
exchange for stock options surrendered, a liability for potential
cash settlements is recognized. The current portion represents the
maximum amount of the liability payable within the next twelve
month period if all vested stock options are surrendered for cash
settlement.
------------------------------
Sep 30 Dec 31
2012 2011
----------------------------------------------------------------------------
Balance - beginning of period $ 432 $ 663
Share-based compensation recovery (173) (102)
Cash payment for stock options surrendered (7) (14)
Transferred to common shares (43) (115)
Capitalized to (recovered from) Oil Sands
Mining and Upgrading (9) -
----------------------------------------------------------------------------
Balance - end of period 200 432
Less: current portion 143 384
----------------------------------------------------------------------------
$ 57 $ 48
----------------------------------------------------------------------------
----------------------------------------------------------------------------
7. HORIZON ASSET IMPAIRMENT PROVISION AND INSURANCE RECOVERY
In 2011, the Company recognized an asset impairment provision in
the Oil Sands Mining and Upgrading segment of $396 million, net of
accumulated depletion and amortization, related to the property
damage resulting from a fire in the Horizon primary upgrading
coking plant. The Company also recorded final property damage
insurance recoveries of $393 million and business interruption
insurance recoveries of $333 million in 2011. In the first quarter
of 2012, upon final settlement of its insurance claims, all
outstanding insurance proceeds were collected.
8. INCOME TAXES
The provision for income tax is as follows:
Three Months Ended Nine Months Ended
----------------------------------------
Sep 30 Sep 30 Sep 30 Sep 30
2012 2011 2012 2011
----------------------------------------------------------------------------
Current corporate income tax - North
America $ 61 $ 26 $ 298 $ 196
Current corporate income tax - North
Sea 22 45 86 161
Current corporate income tax -
Offshore Africa 50 46 150 90
Current PRT (1) (recovery) expense -
North Sea (19) 42 13 96
Other taxes - 6 11 18
----------------------------------------------------------------------------
Current income tax expense 114 165 558 561
----------------------------------------------------------------------------
Deferred corporate income tax
expense 23 157 34 255
Deferred PRT (1) expense (recovery)
- North Sea 6 (4) 5 8
----------------------------------------------------------------------------
Deferred income tax expense 29 153 39 263
----------------------------------------------------------------------------
Income tax expense $ 143 $ 318 $ 597 $ 824
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Petroleum Revenue Tax.
During 2011, the Canadian federal government enacted legislation
to implement several taxation changes. These changes include a
requirement that, beginning in 2012, partnership income must be
included in the taxable income of each corporate partner based on
the tax year of the partner, rather than the fiscal year of the
partnership. The legislation includes a five-year transition
provision and has no impact on net earnings.
During the first quarter of 2011, the UK government enacted an
increase to the supplementary income tax rate charged on profits
from UK North Sea crude oil and natural gas production, increasing
the combined corporate and supplementary income tax rate from 50%
to 62%. As a result of the income tax rate change, the Company's
deferred income tax liability was increased by $104 million as at
March 31, 2011.
During the third quarter of 2012, the UK government enacted
legislation to restrict the combined corporate and supplementary
income tax relief on decommissioning expenditures to 50%. As a
result of the income tax rate change, the Company's deferred income
tax liability was increased by $58 million.
9. SHARE CAPITAL
Authorized
Preferred shares issuable in a series.
Unlimited number of common shares without par value.
-------------------------------
Nine Months Ended Sep 30, 2012
Number of
shares
Issued common shares (thousands) Amount
----------------------------------------------------------------------------
Balance - beginning of period 1,096,460 $ 3,507
Issued upon exercise of stock options 5,550 164
Previously recognized liability on stock
options exercised for common shares - 43
Purchase of common shares under Normal Course
Issuer Bid (6,876) (23)
----------------------------------------------------------------------------
Balance - end of period 1,095,134 $ 3,691
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Preferred Shares
During the second quarter of 2012, the Company amended its
Articles by special resolution of the Shareholders, changing the
designation of its Class 1 preferred shares to "Preferred Shares"
which may be issuable in series. If issued, the number of shares in
each series, and the designation, rights, privileges, restrictions
and conditions attached to the shares will be determined by the
Board of Directors of the Company.
Dividend Policy
On March 6, 2012, the Board of Directors set the regular
quarterly dividend at $0.105 per common share (2011 - $0.09 per
common share). The Company has paid regular quarterly dividends in
January, April, July, and October of each year since 2001. The
dividend policy undergoes a periodic review by the Board of
Directors and is subject to change.
Normal Course Issuer Bid
The Company's Normal Course Issuer Bid announced in 2011 expired
April 5, 2012. In April 2012, the Company announced a Normal Course
Issuer Bid to purchase through the facilities of the Toronto Stock
Exchange and the New York Stock Exchange, during the twelve month
period commencing April 9, 2012 and ending April 8, 2013, up to
55,027,447 common shares.
For the nine months ended September 30, 2012, the Company
purchased 6,876,200 common shares at a weighted average price of
$29.10 per common share, for a total cost of $200 million. Retained
earnings were reduced by $177 million, representing the excess of
the purchase price of common shares over their average carrying
value. Subsequent to September 30, 2012, the Company purchased
949,000 common shares at a weighted average price of $30.18 per
common share for a total cost of $29 million.
Stock Options
The following table summarizes information relating to stock
options outstanding at September 30, 2012:
--------------------------------
Nine Months Ended Sep 30, 2012
----------------------------------------------------------------------------
Weighted
Stock options average
(thousands) exercise price
----------------------------------------------------------------------------
Outstanding - beginning of period 73,486 $ 34.85
Granted 4,949 $ 31.80
Surrendered for cash settlement (853) $ 30.17
Exercised for common shares (5,550) $ 29.52
Forfeited (6,003) $ 36.92
----------------------------------------------------------------------------
Outstanding - end of period 66,029 $ 34.94
----------------------------------------------------------------------------
Exercisable - end of period 21,090 $ 32.93
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The Option Plan is a "rolling 9%" plan, whereby the aggregate
number of common shares that may be reserved for issuance under the
plan shall not exceed 9% of the common shares outstanding from time
to time.
10. ACCUMULATED OTHER COMPREHENSIVE INCOME
The components of accumulated other comprehensive income, net of
taxes, were as follows:
------------------------------
Sep 30 Sep 30
2012 2011
----------------------------------------------------------------------------
Derivative financial instruments designated as
cash flow hedges $ 72 $ 118
Foreign currency translation adjustment (26) (47)
----------------------------------------------------------------------------
$ 46 $ 71
----------------------------------------------------------------------------
----------------------------------------------------------------------------
11. CAPITAL DISCLOSURES
The Company does not have any externally imposed regulatory
capital requirements for managing capital. The Company has defined
its capital to mean its long-term debt and consolidated
shareholders' equity, as determined at each reporting date.
The Company's objectives when managing its capital structure are
to maintain financial flexibility and balance to enable the Company
to access capital markets to sustain its on-going operations and to
support its growth strategies. The Company primarily monitors
capital on the basis of an internally derived financial measure
referred to as its "debt to book capitalization ratio", which is
the arithmetic ratio of current and long-term debt divided by the
sum of the carrying value of shareholders' equity plus current and
long-term debt. The Company's internal targeted range for its debt
to book capitalization ratio is 35% to 45%. This range may be
exceeded in periods when a combination of capital projects,
acquisitions, or lower commodity prices occurs. The Company may be
below the low end of the targeted range when cash flow from
operating activities is greater than current investment activities.
At September 30, 2012, the ratio was below the target range at
26%.
Readers are cautioned that the debt to book capitalization ratio
is not defined by IFRS and this financial measure may not be
comparable to similar measures presented by other companies.
Further, there are no assurances that the Company will continue to
use this measure to monitor capital or will not alter the method of
calculation of this measure in the future.
--------------------------------
Sep 30 Dec 31
2012 2011
----------------------------------------------------------------------------
Long-term debt (1) $ 8,416 $ 8,571
Total shareholders' equity $ 24,120 $ 22,898
Debt to book capitalization 26% 27%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Includes the current portion of long-term debt.
12. NET EARNINGS PER COMMON SHARE
Three Months Ended Nine Months Ended
------------------------------------------------
Sep 30 Sep 30 Sep 30 Sep 30
2012 2011 2012 2011
----------------------------------------------------------------------------
Weighted average common
shares outstanding - basic
(thousands of shares) 1,095,267 1,096,750 1,098,145 1,095,753
Effect of dilutive stock
options (thousands of
shares) 1,856 4,673 2,725 8,103
----------------------------------------------------------------------------
Weighted average common
shares outstanding -
diluted (thousands of
shares) 1,097,123 1,101,423 1,100,870 1,103,856
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net earnings $ 360 $ 836 $ 1,540 $ 1,811
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net earnings per common
share
- basic $ 0.33 $ 0.76 $ 1.40 $ 1.65
- diluted $ 0.33 $ 0.76 $ 1.40 $ 1.64
----------------------------------------------------------------------------
----------------------------------------------------------------------------
13. FINANCIAL INSTRUMENTS
The carrying amounts of the Company's financial instruments by
category were as follows:
----------------------------------------------------------
Sep 30, 2012
----------------------------------------------------------------------------
Fair
Loans and value Financial
receivables through Derivatives liabilities
at amortized profit or used for at amortized
Asset (liability) cost loss hedging cost Total
----------------------------------------------------------------------------
Accounts
receivable $ 1,365 $ - $ - $ - $ 1,365
Accounts payable - - - (525) (525)
Accrued
liabilities - - - (2,218) (2,218)
Other long-term
liabilities - 12 (304) (85) (377)
Long-term debt (1) - - - (8,416) (8,416)
----------------------------------------------------------------------------
$ 1,365 $ 12 $ (304) $ (11,244) $(10,171)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Dec 31, 2011
----------------------------------------------------------------------------
Fair
Loans and value Financial
receivables through Derivatives liabilities
at amortized profit or used for at amortized
Asset (liability) cost loss hedging cost Total
----------------------------------------------------------------------------
Accounts
receivable $ 2,077 $ - $ - $ - $ 2,077
Accounts payable - - - (526) (526)
Accrued
liabilities - - - (2,347) (2,347)
Other long-term
liabilities - (38) (236) (75) (349)
Long-term debt (1) - - - (8,571) (8,571)
----------------------------------------------------------------------------
$ 2,077 $ (38) $ (236) $ (11,519) $ (9,716)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Includes the current portion of long-term debt.
The carrying amount of the Company's financial instruments
approximates their fair value, except for fixed rate long-term debt
as noted below. The fair values of the Company's other long-term
liabilities and fixed rate long-term debt are outlined below:
---------------------------------------------------
Sep 30, 2012
----------------------------------------------------------------------------
Carrying
amount Fair value
----------------------------------------------------------------------------
Asset (liability) (1) Level 1 Level 2
----------------------------------------------------------------------------
Other long-term
liabilities $ (292) $ - $ (292)
Fixed rate long-term debt
(2) (3) (4) (8,036) (9,466) -
----------------------------------------------------------------------------
$ (8,328) $ (9,466) $ (292)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Dec 31, 2011
----------------------------------------------------------------------------
Carrying
amount Fair value
----------------------------------------------------------------------------
Asset (liability) (1) Level 1 Level 2
----------------------------------------------------------------------------
Other long-term
liabilities $ (274) $ - $ (274)
Fixed rate long-term debt
(2) (3) (4) (7,775) (9,120) -
----------------------------------------------------------------------------
$ (8,049) $ (9,120) $ (274)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Excludes financial assets and liabilities where the carrying amount
approximates fair value due to the liquid nature of the asset or
liability (cash and cash equivalents, accounts receivable, accounts
payable and accrued liabilities).
(2) The carrying amounts of US$350 million of 5.45% notes due October 2012
and US$350 million of 4.90% notes due December 2014 have been adjusted
by $21 million (December 31, 2011 - $31 million) to reflect the fair
value impact of hedge accounting.
(3) The fair value of fixed rate long-term debt has been determined based on
quoted market prices.
(4) Includes the current portion of long-term debt.
The following provides a summary of the carrying amounts of
derivative contracts held and a reconciliation to the Company's
consolidated balance sheets.
----------------------------------
Asset (liability) Sep 30, 2012 Dec 31, 2011
----------------------------------------------------------------------------
Derivatives held for trading
Crude oil price collars $ 26 $ (13)
Crude oil put options, net of put
premium financing obligations (13) -
Foreign currency forward contracts (1) (25)
Cash flow hedges
Cross currency swaps (304) (236)
----------------------------------------------------------------------------
$ (292) $ (274)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Included within:
Current portion of other long-term
liabilities $ (7) $ (43)
Other long-term liabilities (285) (231)
----------------------------------------------------------------------------
$ (292) $ (274)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Ineffectiveness arising from cash flow hedges recognized in net
earnings for the nine months ended September 30, 2012 resulted in
no gain or loss (December 31, 2011 - loss of $2 million).
Risk Management
The Company uses derivative financial instruments to manage its
commodity price, foreign currency and interest rate exposures.
These financial instruments are entered into solely for hedging
purposes and are not used for speculative purposes.
The estimated fair value of derivative financial instruments has
been determined based on appropriate internal valuation
methodologies and/or third party indications. Fair values
determined using valuation models require the use of assumptions
concerning the amount and timing of future cash flows and discount
rates. In determining these assumptions, the Company primarily
relied on external, readily-observable market inputs including
quoted commodity prices and volatility, interest rate yield curves,
and foreign exchange rates. The resulting fair value estimates may
not necessarily be indicative of the amounts that could be realized
or settled in a current market transaction and these differences
may be material.
The changes in estimated fair values of derivative financial
instruments included in risk management assets (liabilities) were
recognized in the financial statements as follows:
----------------------------------
Nine Months
Ended Year Ended
Asset (liability) Sep 30, 2012 Dec 31, 2011
----------------------------------------------------------------------------
Balance - beginning of period $ (274) $ (485)
Net cost of outstanding put options 18 -
Net change in fair value of outstanding
derivative financial instruments
attributable to:
Risk management activities 50 128
Foreign exchange (80) 42
Other comprehensive income 12 41
----------------------------------------------------------------------------
(274) (274)
Add: put premium financing obligations (1) (18) -
----------------------------------------------------------------------------
Balance - end of period (292) (274)
Less: current portion (7) (43)
----------------------------------------------------------------------------
$ (285) $ (231)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) The Company has negotiated payment of put option premiums with various
counterparties at the time of actual settlement of the respective
options. These obligations are reflected in the net risk management
asset (liability).
Net losses (gains) from risk management activities were as
follows:
Three Months Ended Nine Months Ended
-------------------------------------------
Sep 30 Sep 30 Sep 30 Sep 30
2012 2011 2012 2011
----------------------------------------------------------------------------
Net realized risk management loss
(gain) $ 137 $ (23) $ 170 $ 81
Net unrealized risk management
loss (gain) 34 (122) (50) (186)
----------------------------------------------------------------------------
$ 171 $ (145) $ 120 $ (105)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Financial Risk Factors
a) Market risk
Market risk is the risk that the fair value or future cash flows
of a financial instrument will fluctuate because of changes in
market prices. The Company's market risk is comprised of commodity
price risk, interest rate risk, and foreign currency exchange
risk.
Commodity price risk management
The Company periodically uses commodity derivative financial
instruments to manage its exposure to commodity price risk
associated with the sale of its future crude oil and natural gas
production and with natural gas purchases. At September 30, 2012,
the Company had the following derivative financial instruments
outstanding to manage its commodity price risks:
Sales contracts
Weighted average
Remaining term Volume price Index
----------------------------------------------------------------------------
Crude oil
Crude oil price collars 50,000
Oct 2012-Dec 2012 bbl/d US$80.00-US$134.87 Brent
50,000
Oct 2012-Dec 2012 bbl/d US$80.00-US$136.06 Brent
50,000
Oct 2012-Dec 2012 bbl/d US$80.00-US$113.62 WTI
50,000
Oct 2012-Jun 2013 bbl/d US$80.00-US$145.07 Brent
50,000
Jan 2013-Dec 2013 bbl/d US$80.00-US$110.34 WTI
50,000
Jan 2013-Dec 2013 bbl/d US$80.00-US$135.59 Brent
Crude oil puts 100,000
Oct 2012-Dec 2012 bbl/d US$80.00 WTI
----------------------------------------------------------------------------
----------------------------------------------------------------------------
During the fourth quarter of 2012, US$19 million of put option
costs will be settled.
The Company's outstanding commodity derivative financial
instruments are expected to be settled monthly based on the
applicable index pricing for the respective contract month.
Interest rate risk management
The Company is exposed to interest rate price risk on its fixed
rate long-term debt and to interest rate cash flow risk on its
floating rate long-term debt. The Company periodically enters into
interest rate swap contracts to manage its fixed to floating
interest rate mix on long-term debt. The interest rate swap
contracts require the periodic exchange of payments without the
exchange of the notional principal amounts on which the payments
are based. At September 30, 2012, the Company had no interest rate
swap contracts outstanding.
Foreign currency exchange rate risk management
The Company is exposed to foreign currency exchange rate risk in
Canada primarily related to its US dollar denominated long-term
debt and working capital. The Company is also exposed to foreign
currency exchange rate risk on transactions conducted in other
currencies in its subsidiaries and in the carrying value of its
foreign subsidiaries. The Company periodically enters into cross
currency swap contracts and foreign currency forward contracts to
manage known currency exposure on US dollar denominated long-term
debt and working capital. The cross currency swap contracts require
the periodic exchange of payments with the exchange at maturity of
notional principal amounts on which the payments are based. At
September 30, 2012, the Company had the following cross currency
swap contracts outstanding:
Exchange
rate Interest Interest
Remaining term Amount (US$/C$) rate (US$) rate (C$)
----------------------------------------------------------------------------
Cross currency
Swaps Oct 2012 - Aug 2016 US$250 1.116 6.00% 5.40%
Oct 2012 - May 2017 US$1,100 1.170 5.70% 5.10%
Oct 2012 - Nov 2021 US$500 1.022 3.45% 3.96%
Oct 2012 - Mar 2038 US$550 1.170 6.25% 5.76%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
All cross currency swap derivative financial instruments
designated as hedges at September 30, 2012, were classified as cash
flow hedges.
In addition to the cross currency swap contracts noted above, at
September 30, 2012, the Company had US$2,881 million of foreign
currency forward contracts outstanding, with terms of approximately
30 days or less.
b) Credit Risk
Credit risk is the risk that a party to a financial instrument
will cause a financial loss to the Company by failing to discharge
an obligation.
Counterparty credit risk management
The Company's accounts receivable are mainly with customers in
the crude oil and natural gas industry and are subject to normal
industry credit risks. The Company manages these risks by reviewing
its exposure to individual companies on a regular basis and where
appropriate, ensures that parental guarantees or letters of credit
are in place to minimize the impact in the event of default. At
September 30, 2012, substantially all of the Company's accounts
receivable were due within normal trade terms.
The Company is also exposed to possible losses in the event of
nonperformance by counterparties to derivative financial
instruments; however, the Company manages this credit risk by
entering into agreements with counterparties that are substantially
all investment grade financial institutions and other entities. At
September 30, 2012, the Company had net risk management assets of
$10 million with specific counterparties related to derivative
financial instruments (December 31, 2011 - $nil).
c) Liquidity Risk
Liquidity risk is the risk that the Company will encounter
difficulty in meeting obligations associated with financial
liabilities.
Management of liquidity risk requires the Company to maintain
sufficient cash and cash equivalents, along with other sources of
capital, consisting primarily of cash flow from operating
activities, available credit facilities, and access to debt capital
markets, to meet obligations as they become due. The Company
believes it has adequate bank credit facilities to provide
liquidity to manage fluctuations in the timing of the receipt
and/or disbursement of operating cash flows.
The maturity dates for financial liabilities are as follows:
1 to less 2 to less
Less than than 2 than
1 year years 5 years Thereafter
----------------------------------------------------------------------------
Accounts payable $ 525 $ - $ - $ -
Accrued liabilities $ 2,218 $ - $ - $ -
Risk management $ 7 $ 45 $ 142 $ 98
Other long-term liabilities $ 24 $ 23 $ 38 $ -
Long-term debt (1) $ 1,138 $ - $ 2,944 $ 4,386
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Long-term debt represents principal repayments only and does not reflect
fair value adjustments, original issue discounts or transaction costs.
14. COMMITMENTS AND CONTINGENCIES
The Company has committed to certain payments as follows:
Remaining
2012 2013 2014 2015 2016 Thereafter
----------------------------------------------------------------------------
Product
transportation and
pipeline $ 58 $ 213 $ 204 $ 192 $ 126 $ 889
Offshore equipment
operating leases
and offshore
drilling $ 43 $ 153 $ 120 $ 103 $ 75 $ 121
Office leases $ 8 $ 32 $ 35 $ 33 $ 34 $ 309
Other $ 76 $ 169 $ 95 $ 42 $ 10 $ 8
----------------------------------------------------------------------------
----------------------------------------------------------------------------
In addition to the commitments disclosed above, the Company has
entered into various agreements related to the engineering,
procurement and construction of subsequent phases of Horizon. These
contracts can be cancelled by the Company upon notice without
penalty, subject to the costs incurred up to and in respect of the
cancellation.
The Company is a defendant and plaintiff in a number of legal
actions arising in the normal course of business. In addition, the
Company is subject to certain contractor construction claims. The
Company believes that any liabilities that might arise pertaining
to any such matters would not have a material effect on its
consolidated financial position.
15. SEGMENTED INFORMATION
Exploration and Production
North America North Sea
(millions of Three Months Nine Months Three Months Nine Months
Canadian dollars, Ended Ended Ended Ended
unaudited) Sep 30 Sep 30 Sep 30 Sep 30
---------------------------------------------------------
2012 2011 2012 2011 2012 2011 2012 2011
----------------------------------------------------------------------------
Segmented product
sales 2,786 2,730 8,601 8,643 198 276 713 907
Less: royalties (359) (339) (991) (1,056) (1) - (2) (2)
----------------------------------------------------------------------------
Segmented revenue 2,427 2,391 7,610 7,587 197 276 711 905
----------------------------------------------------------------------------
Segmented expenses
Production 521 493 1,608 1,417 98 114 302 309
Transportation and
blending 602 454 2,000 1,726 2 3 8 10
Depletion,
depreciation and
amortization 839 714 2,448 2,114 63 51 222 184
Asset retirement
obligation
accretion 22 18 64 53 6 8 20 24
Realized risk
management
activities 137 (23) 170 81 - - - -
Horizon asset
impairment
provision - - - - - - - -
Insurance recovery
- property damage
(note 7) - - - - - - - -
Insurance recovery
- business
interruption (note
7) - - - - - - - -
Equity loss from
jointly controlled
entity 1 - 6 - - - - -
----------------------------------------------------------------------------
Total segmented
expenses 2,122 1,656 6,296 5,391 169 176 552 527
----------------------------------------------------------------------------
Segmented earnings
(loss) before the
following 305 735 1,314 2,196 28 100 159 378
----------------------------------------------------------------------------
Non-segmented
expenses
Administration
Share-based
compensation
Interest and other
financing costs
Unrealized risk
management
activities
Foreign exchange
(gain) loss
----------------------------------------------------------------------------
Total non-segmented
expenses
----------------------------------------------------------------------------
Earnings before
taxes
Current income tax
expense
Deferred income tax
expense
----------------------------------------------------------------------------
Net earnings
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Exploration and Production
Total Exploration and
Offshore Africa Production
(millions of Three Months Nine Months Three Months Nine Months
Canadian dollars, Ended Ended Ended Ended
unaudited) Sep 30 Sep 30 Sep 30 Sep 30
---------------------------------------------------------
2012 2011 2012 2011 2012 2011 2012 2011
----------------------------------------------------------------------------
Segmented product
sales 158 250 615 638 3,142 3,256 9,929 10,188
Less: royalties (50) (46) (146) (68) (410) (385)(1,139)(1,126)
----------------------------------------------------------------------------
Segmented revenue 108 204 469 570 2,732 2,871 8,790 9,062
----------------------------------------------------------------------------
Segmented expenses
Production 51 45 124 120 670 652 2,034 1,846
Transportation and
blending - 1 1 1 604 458 2,009 1,737
Depletion,
depreciation and
amortization 29 44 107 170 931 809 2,777 2,468
Asset retirement
obligation
accretion 2 2 5 5 30 28 89 82
Realized risk
management
activities - - - - 137 (23) 170 81
Horizon asset
impairment
provision - - - - - - - -
Insurance recovery
- property damage
(note 7) - - - - - - - -
Insurance recovery
- business
interruption (note
7) - - - - - - - -
Equity loss from
jointly controlled
entity - - - - 1 - 6 -
----------------------------------------------------------------------------
Total segmented
expenses 82 92 237 296 2,373 1,924 7,085 6,214
----------------------------------------------------------------------------
Segmented earnings
(loss) before the
following 26 112 232 274 359 947 1,705 2,848
----------------------------------------------------------------------------
Non-segmented
expenses
Administration
Share-based
compensation
Interest and other
financing costs
Unrealized risk
management
activities
Foreign exchange
(gain) loss
----------------------------------------------------------------------------
Total non-segmented
expenses
----------------------------------------------------------------------------
Earnings before
taxes
Current income tax
expense
Deferred income tax
expense
----------------------------------------------------------------------------
Net earnings
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Oil Sands Mining and
Upgrading Midstream
(millions of Three Months Nine Months Three Months Nine Months
Canadian dollars, Ended Ended Ended Ended
unaudited) Sep 30 Sep 30 Sep 30 Sep 30
---------------------------------------------------------
2012 2011 2012 2011 2012 2011 2012 2011
----------------------------------------------------------------------------
Segmented product
sales 831 427 2,196 516 24 23 67 66
Less: royalties (32) (15) (108) (19) - - - -
----------------------------------------------------------------------------
Segmented revenue 799 412 2,088 497 24 23 67 66
----------------------------------------------------------------------------
Segmented expenses
Production 398 306 1,132 783 7 7 21 19
Transportation and
blending 16 15 46 46 - - - -
Depletion,
depreciation and
amortization 124 77 333 133 1 1 5 5
Asset retirement
obligation
accretion 8 5 24 15 - - - -
Realized risk
management
activities - - - - - - - -
Horizon asset
impairment
provision - - - 396 - - - -
Insurance recovery
- property damage
(note 7) - - - (396) - - - -
Insurance recovery
- business
interruption (note
7) - (181) - (317) - - - -
Equity loss from
jointly controlled
entity - - - - - - - -
----------------------------------------------------------------------------
Total segmented
expenses 546 222 1,535 660 8 8 26 24
----------------------------------------------------------------------------
Segmented earnings
(loss) before the
following 253 190 553 (163) 16 15 41 42
----------------------------------------------------------------------------
Non-segmented
expenses
Administration
Share-based
compensation
Interest and other
financing costs
Unrealized risk
management
activities
Foreign exchange
(gain) loss
----------------------------------------------------------------------------
Total non-segmented
expenses
----------------------------------------------------------------------------
Earnings before
taxes
Current income tax
expense
Deferred income tax
expense
----------------------------------------------------------------------------
Net earnings
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Inter-segment elimination
and other Total
(millions of Three Months Nine Months Three Months Nine Months
Canadian dollars, Ended Ended Ended Ended
unaudited) Sep 30 Sep 30 Sep 30 Sep 30
---------------------------------------------------------
2012 2011 2012 2011 2012 2011 2012 2011
----------------------------------------------------------------------------
Segmented product
sales (19) (16) (56) (51) 3,978 3,690 12,136 10,719
Less: royalties - - - - (442) (400) (1,247) (1,145)
----------------------------------------------------------------------------
Segmented revenue (19) (16) (56) (51) 3,536 3,290 10,889 9,574
----------------------------------------------------------------------------
Segmented expenses
Production (4) (6) (10) (11) 1,071 959 3,177 2,637
Transportation and
blending (14) (14) (41) (38) 606 459 2,014 1,745
Depletion,
depreciation and
amortization - - - - 1,056 887 3,115 2,606
Asset retirement
obligation
accretion - - - - 38 33 113 97
Realized risk
management
activities - - - - 137 (23) 170 81
Horizon asset
impairment
provision - - - - - - - 396
Insurance recovery
- property damage
(note 7) - - - - - - - (396)
Insurance recovery
- business
interruption (note
7) - - - - - (181) - (317)
Equity loss from
jointly controlled
entity - - - - 1 - 6 -
----------------------------------------------------------------------------
Total segmented
expenses (18) (20) (51) (49) 2,909 2,134 8,595 6,849
----------------------------------------------------------------------------
Segmented earnings
(loss) before the
following (1) 4 (5) (2) 627 1,156 2,294 2,725
----------------------------------------------------------------------------
Non-segmented
expenses
Administration 64 65 206 188
Share-based
compensation 49 (249) (173) (309)
Interest and other
financing costs 92 97 281 290
Unrealized risk
management
activities 34 (122) (50) (186)
Foreign exchange
(gain) loss (115) 211 (107) 107
----------------------------------------------------------------------------
Total non-segmented
expenses 124 2 157 90
----------------------------------------------------------------------------
Earnings before
taxes 503 1,154 2,137 2,635
Current income tax
expense 114 165 558 561
Deferred income tax
expense 29 153 39 263
----------------------------------------------------------------------------
Net earnings 360 836 1,540 1,811
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Capital Expenditures (1)
Nine Months Ended
-------------------------------------------------
Sep 30, 2012
---------------------------------------------------------------------------
Non cash
and fair value Capitalized
Net expenditures changes(2) costs
---------------------------------------------------------------------------
Exploration and evaluation
assets
Exploration and Production
North America $ 294 $ (114) $ 180
North Sea - - -
Offshore Africa 5 - 5
---------------------------------------------------------------------------
$ 299 $ (114) $ 185
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Property, plant and
equipment
Exploration and Production
North America $ 2,746 $ 71 $ 2,817
North Sea 199 (33) 166
Offshore Africa 30 (6) 24
---------------------------------------------------------------------------
2,975 32 3,007
Oil Sands Mining and
Upgrading (3) (4) 1,069 34 1,103
Midstream 10 - 10
Head office 25 - 25
---------------------------------------------------------------------------
$ 4,079 $ 66 $ 4,145
---------------------------------------------------------------------------
---------------------------------------------------------------------------
Nine Months Ended
--------------------------------------------------
Sep 30, 2011
----------------------------------------------------------------------------
Non cash and
fair value Capitalized
Net expenditures changes(2) costs
----------------------------------------------------------------------------
Exploration and evaluation
assets
Exploration and Production
North America $ 199 $ (225) $ (26)
North Sea - (4) (4)
Offshore Africa 1 - 1
----------------------------------------------------------------------------
$ 200 $ (229) $ (29)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Property, plant and
equipment
Exploration and Production
North America $ 2,991 $ 255 $ 3,246
North Sea 156 4 160
Offshore Africa 50 (29) 21
----------------------------------------------------------------------------
3,197 230 3,427
Oil Sands Mining and
Upgrading (3) (4) 940 (406) 534
Midstream 5 - 5
Head office 16 - 16
----------------------------------------------------------------------------
$ 4,158 $ (176) $ 3,982
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) This table provides a reconciliation of capitalized costs and does not
include the impact of foreign exchange adjustments and accumulated
depletion and depreciation.
(2) Asset retirement obligations, deferred income tax adjustments related to
differences between carrying amounts and tax values, transfers of
exploration and evaluation assets, and other fair value adjustments.
(3) Net expenditures for Oil Sands Mining and Upgrading also include
capitalized interest and share-based compensation.
(4) During the first quarter of 2011, the Company derecognized certain
property, plant and equipment related to the coker fire at Horizon in
the amount of $411 million. This amount was included in non cash and
fair value changes.
Segmented Assets
Total Assets
----------------------------------
Sep 30 Dec 31
2012 2011
----------------------------------------------------------------------------
Exploration and Production
North America $ 29,028 $ 28,554
North Sea 1,652 1,809
Offshore Africa 898 1,070
Other 44 23
Oil Sands Mining and Upgrading 15,825 15,433
Midstream 341 321
Head office 81 68
----------------------------------------------------------------------------
$ 47,869 $ 47,278
----------------------------------------------------------------------------
----------------------------------------------------------------------------
SUPPLEMENTARY INFORMATION
INTEREST COVERAGE RATIOS
The following financial ratios are provided in connection with
the Company's continuous offering of medium-term notes pursuant to
the short form prospectus dated October 2011. These ratios are
based on the Company's interim consolidated financial statements
that are prepared in accordance with accounting principles
generally accepted in Canada.
Interest coverage ratios for the twelve month period ended
September 30, 2012:
----------------------------------------------------------------------------
Interest coverage (times)
Net earnings (1) 8.3x
Cash flow from operations (2) 17.3x
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Net earnings plus income taxes and interest expense excluding current
and deferred PRT expense and other taxes; divided by the sum of interest
expense and capitalized interest.
(2) Cash flow from operations plus current income taxes and interest expense
excluding current PRT expense and other taxes; divided by the sum of
interest expense and capitalized interest.
CONFERENCE CALL
A conference call will be held at 9:00 a.m. Mountain Time, 11:00
a.m. Eastern Time on Thursday, November 8, 2012.
The North American conference call number is 1-800-952-6845 and
the outside North American conference call number is
001-416-695-7848. Please call in about 10 minutes before the
starting time in order to be patched into the call.
A taped rebroadcast will be available until 6:00 p.m. Mountain
Time, Thursday, November 15, 2012. To access the rebroadcast in
North America, dial 1-800-408-3053. Those outside of North America,
dial 001-905-694-9451. The pass code to use is 6854115.
WEBCAST
The conference call will also be broadcast live on the internet
and may be accessed through the Canadian Natural website at
www.cnrl.com.
2013 BUDGET DETAILS
Canadian Natural will release its 2013 budget details on
Tuesday, December 4, 2012. The news release will provide forward
looking information on the Company's 2013 operating year.
A conference call and webcast, which will include presentation
slides, will be held on the same day at 9:00 am MT (11:00 am ET).
Presentation slides will be available shortly before the conference
call. Conference call information and presentation can be accessed
on the homepage of Canadian Natural's website at: www.cnrl.com
under Upcoming Events and News.
Contacts: John G. Langille Vice-Chairman Steve W. Laut President
Corey B. Bieber Vice-President, Finance & Investor Relations
Canadian Natural Resources Limited 2500, 855 2nd Street S.W.
Calgary, Alberta, T2P 4J8 Canada Phone: (403) 514-7777ir@cnrl.com
www.cnrl.com
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