Canadian Natural Resources Limited (TSX:CNQ) (NYSE:CNQ)
"Canadian Natural achieved in the second quarter of 2013 strong
quarterly production from our balanced and diverse asset base,"
commented Steve Laut, President of Canadian Natural. "On a per
barrel of oil equivalent basis, our overall Exploration and
Production operating costs decreased from last quarter resulting in
excellent overall netbacks. This, along with strong WTI benchmark
pricing, tighter WCS to WTI differentials and better natural gas
pricing helped the Company generate solid cash flow in the
quarter.
At Kirby South, we are in the final stages of commissioning.
Steam injection is expected to commence in late August or early
September 2013, approximately three months ahead of the original
schedule. Project costs remain within
our targeted budget. By the fourth quarter of 2014, thermal in
situ production at Kirby South is targeted to grow to 40,000
bbl/d.
Horizon reliability continues to improve after the completion of
our first major maintenance turnaround of the plant in May 2013. We
continue to achieve safe, steady and reliable operations. In June
and July 2013, synthetic crude oil production was 101,000 bbl/d and
110,000 bbl/d, respectively.
During the second quarter, our North America Exploration and
Production crude oil and NGL assets, excluding thermal in situ oil
sands, achieved record quarterly production of approximately
241,000 bbl/d. These volumes were driven by record quarterly
production at our primary heavy crude oil and Pelican Lake
operations. This quarter marks the tenth consecutive quarter that
our heavy crude oil assets have achieved record production and
demonstrates the strong performance ability of the Pelican Lake
pool.
As we move into the third quarter of 2013, we expect production
volumes to grow in the quarter. Higher production volumes from
thermal in situ operations, increased reliability at Horizon Oil
Sands Mining operations and continued strong production performance
from all other operating areas of the Company are anticipated. We
will continue to operate efficiently and effectively to ensure
industry competitive operating costs."
Corey Bieber, Canadian Natural's Chief Financial Officer,
stated, "We are in an excellent position to realize strong cash
flow metrics over the last half of 2013. Midpoint guidance for
crude oil production in Q3/13 reflects an increase of approximately
19% over Q2/13 volumes. Furthermore, heavy oil differentials have
narrowed as expected. At the same time, benchmark North American
crude oil pricing has increased and condensate premium costs have
reduced. We target very robust netbacks in the last half of 2013,
which ultimately results in debt levels reflective of 2012, making
our balance sheet even stronger, despite substantial capital
investments of approximately $2.075 billion in the calendar year of
2013 on the Horizon Project Phase 2/3 expansion."
QUARTERLY HIGHLIGHTS
Three Months Ended Six Months Ended
----------- -----------
($ Millions, except
per common share Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
amounts) 2013 2013 2012 2013 2012
----------------------------------------------------------------------------
Net earnings $ 476 $ 213 $ 753 $ 689 $ 1,180
Per common share
- basic $ 0.44 $ 0.19 $ 0.68 $ 0.63 $ 1.07
- diluted $ 0.44 $ 0.19 $ 0.68 $ 0.63 $ 1.07
Adjusted net earnings
from operations (1) $ 462 $ 401 $ 606 $ 863 $ 906
Per common share
- basic $ 0.42 $ 0.37 $ 0.55 $ 0.79 $ 0.82
- diluted $ 0.42 $ 0.37 $ 0.55 $ 0.79 $ 0.82
Cash flow from
operations (2) $ 1,670 $ 1,571 $ 1,754 $ 3,241 $ 3,034
Per common share
- basic $ 1.53 $ 1.44 $ 1.60 $ 2.97 $ 2.76
- diluted $ 1.53 $ 1.44 $ 1.59 $ 2.97 $ 2.75
Capital expenditures,
net of dispositions $ 1,792 $ 1,736 $ 1,324 $ 3,528 $ 2,920
Daily production,
before royalties
Natural gas (MMcf/d) 1,122 1,150 1,255 1,136 1,277
Crude oil and NGLs
(bbl/d) 436,363 489,157 470,523 462,615 432,993
Equivalent
production (BOE/d)
(3) 623,315 680,844 679,607 651,921 645,943
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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.
- Canadian Natural generated cash flow from operations of
approximately $1.67 billion in Q2/13 compared to approximately
$1.57 billion in Q1/13 and approximately $1.75 billion in Q2/12.
The increase from Q1/13 reflects higher crude oil and NGLs and
natural gas netbacks and higher realized synthetic crude oil
("SCO") pricing partially offset by lower crude oil and SCO sales
volumes in the North America and Oil Sands Mining and Upgrading
segments. The cash flow variance from Q2/12 reflects higher crude
oil and NGLs sales volumes, higher natural gas netbacks, higher
realized SCO pricing and the impact of a weaker Canadian dollar
offset by expected lower SCO sales volumes in the Oil Sands Mining
and Upgrading segment and expected lower natural gas sales
volumes.
- Adjusted net earnings from operations in Q2/13 were $462
million compared to $401 million in Q1/13 and $606 million in
Q2/12. Changes in adjusted net earnings primarily reflect the
changes in cash flow from operations.
- Total production for Q2/13 averaged 623,315 BOE/d, within the
Company's previously announced corporate guidance, which ranged
from 617,000 BOE/d to 646,000 BOE/d. As expected, production
volumes varied from Q2/12 and Q1/13 levels primarily as a result of
expected lower volumes in the Oil Sands Mining and Upgrading
segment due to the Company's first major maintenance turnaround at
Horizon Oil Sands ("Horizon") and in the Thermal In Situ Oil Sands
segment due to production cycle timing.
- In Q2/13, primary heavy crude oil operations achieved record
quarterly production of approximately 136,000 bbl/d, representing
the Company's tenth consecutive quarter of record primary heavy
crude oil production. Primary heavy crude oil production increased
2% and 11% from Q1/13 and Q2/12, respectively. The Company expects
continued strong performance from its primary heavy crude oil
assets during the second half of 2013, which are targeted to
deliver a 13% production increase over 2012 levels.
- In mid-May 2013, facility constraints at Pelican Lake were
alleviated with the completion of a new battery. Both Pelican Lake
and Woodenhouse production volumes ramped up soon afterward. In
Q2/13, Pelican Lake operations achieved record quarterly production
volumes of approximately 42,000 bbl/d, 10% higher than Q1/13
volumes. In June and July 2013, monthly average production
increased to between 45,000 bbl/d and 46,000 bbl/d, demonstrating
the reservoir's continued strong performance. Further production
volume increases are expected through the second half of 2013, with
targeted exit volumes for 2013 of approximately 50,000 bbl/d.
- Kirby South, the next step in the Company's well defined
thermal growth plan, is now in the final stages of commissioning,
with first steam-in expected in late August or early September
2013, three months ahead of schedule. Production is targeted to
ramp up to 40,000 bbl/d of bitumen by Q4/14.
- During May 2013, the first major maintenance turnaround at
Horizon was completed with no major changes to the scope. The
sequential start-up of the operation was executed as planned. Q3/13
Horizon SCO production is targeted to increase to between 110,000
bbl/d and 115,000 bbl/d as greater reliability and consistent
production is realized after the turnaround. Safe, steady, and
reliable operations continue to be a priority at Horizon. Annual
SCO production is unchanged and is targeted to range from 100,000
bbl/d to 108,000 bbl/d in 2013.
- At Septimus, the Company's liquids rich natural gas Montney
play, the plant expansion was completed and expanded production
volumes were achieved in July 2013. At the end of July, total
production at Septimus reached approximately 90 MMcf/d of natural
gas and approximately 8,600 bbl/d of liquids. During Q2/13,
Canadian Natural drilled 6 net wells at Septimus and targets to
drill 7 additional net wells in Q3/13. By early September 2013,
production is targeted to grow to plant expansion capacity of 125
MMcf/d of natural gas sales, yielding approximately 12,200 bbl/d of
liquids, through the plant and deep cut facilities.
- Subsequent to Q2/13, Canadian Natural announced the
acquisition of Barrick Energy Inc. The production and undeveloped
land base is complementary to Canadian Natural's existing assets
and is concentrated in light oil weighted assets with strong
netbacks and a long reserve life. This acquisition adds
approximately 4,200 bbl/d of light crude oil and NGLs and 4.4
MMcf/d of natural gas production.
- Subsequent to Q2/13, TransCanada Corporation announced a
successful open season on its Energy East Pipeline project which is
anticipated to add 1.1 MMbbl/d of incremental pipeline capacity to
the east coast of Canada. Canadian Natural is a strong supporter of
this project and has made commitments of 80,000 bbl/d of crude oil.
This commitment is in addition to previously announced commitments
of crude oil to Keystone XL and Trans Mountain Expansion of 120,000
bbl/d and 75,000 bbl/d respectively.
----------------------------------------------------------------
SCO Dated Brent Condensate
WTI WCS Blend Differential Differential Differential
Benchmark Pricing Differential from WTI from WTI from WTI
Pricing (US$/bbl) from WTI (%) (US$/bbl) (US$/bbl) (US$/bbl)
----------------------------------------------------------------------------
2013
April $ 92.07 25% $ 6.14 $ 9.85 $ 10.00
May $ 94.80 15% $ 8.33 $ 7.69 $ 6.92
June $ 95.80 21% $ 0.02 $ 7.11 $ 4.91
July $ 104.70 14% $ 5.98 $ 3.25 $ 1.60
August (i) $ 104.74 15% $ 3.20 $ 3.13 $ (2.78)
September
(i) $ 103.84 20% $ 2.27 $ 3.21 $ (4.45)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(i) Based on current indicative pricing as at July 31, 2013.
- As expected, heavy crude oil differentials narrowed during the
second quarter, resulting in more favorable price realizations for
the Company. The WCS heavy crude oil differential ("WCS
differential") as a percent of WTI averaged 20% in Q2/13 compared
to 34% in Q1/13 and 24% in Q2/12. In July, August and September
2013, the WCS differential, based on current indicative pricing,
narrowed to 14%, 15% and 20%, respectively.
- The Company uses condensate as a blending diluent for heavy
crude oil pipeline shipments. During Q2/13, condensate price
premiums to WTI narrowed to US$7.27/bbl in Q2/13 compared to
US$12.84/bbl in Q1/13. Lower condensate price premiums are expected
to continue in the second half of 2013 resulting in higher netbacks
for the Company's heavy crude oil sales volumes.
- As expected, the Dated Brent to WTI differential narrowed to
US$8.21/bbl in Q2/13 compared to US$18.09/bbl in Q1/13 and
US$14.71/bbl in Q2/12. Overall pricing relative to Dated Brent
pricing for Canadian Natural's North American crude oil production
continues to improve as a result of this narrowing.
- SCO pricing improved in Q2/13 to US$99.10/bbl compared to
US$95.24/bbl in Q1/13 and US$89.54/bbl in Q2/12 resulting in more
favorable price realizations for the Company.
- Q3/13 production volumes are expected to be strong and will be
driven by increased production volumes from Primrose, strong SCO
production due to improved Horizon reliability, and continued solid
performance from the Company's remaining operating areas. Combining
this strong production performance with favorable WTI pricing,
narrow heavy oil differentials, and strong SCO premiums should
result in a strong third quarter performance for the Company.
- Year to date, Canadian Natural has purchased for cancellation
6,937,500 common shares at a weighted average price of $30.86 per
common share.
- Canadian Natural declared a quarterly cash dividend on common
shares of C$0.125 per share payable on October 1, 2013.
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 and operating 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)
Six Months Ended Jun 30
-------------------------------------------
2013 2012
Gross Net Gross Net
----------------------------------------------------------------------------
Crude oil 471 459 574 544
Natural gas 29 23 25 23
Dry 10 10 8 8
----------------------------------------------------------------------------
Subtotal 510 492 607 575
Stratigraphic test / service
wells 321 321 589 589
----------------------------------------------------------------------------
Total 831 813 1,196 1,164
----------------------------------------------------------------------------
Success rate (excluding
stratigraphic test / service
wells) 98% 99%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
North America Exploration and Production
Crude oil and NGLs - excluding Thermal In Situ Oil Sands
Three Months Ended Six Months Ended
----------- -----------
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
2013 2013 2012 2013 2012
----------------------------------------------------------------------------
Crude oil and NGLs
production (bbl/d) 241,402 236,600 222,127 239,014 223,707
----------------------------------------------------------------------------
Net wells targeting
crude oil 136 271 231 407 472
Net successful wells
drilled 131 267 229 398 464
----------------------------------------------------------------------------
Success rate 96% 99% 99% 98% 98%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
- North America crude oil and NGLs operations achieved record
quarterly production of 241,402 bbl/d in Q2/13, an increase of 9%
and 2% from Q2/12 and Q1/13 levels respectively.
- Canadian Natural drilled 121 net primary heavy crude oil wells
in Q2/13. Canadian Natural's primary heavy crude oil continues to
provide strong netbacks and a high return on capital in the
Company's portfolio of diverse and balanced assets. In Q2/13
primary heavy crude oil operations achieved record production
volumes of approximately 136,000 bbl/d, resulting in the tenth
consecutive quarter of record primary heavy crude oil production
volumes, contributing to the targeted 13% primary heavy crude oil
production growth in 2013. The Company is targeting to drill
another 255 net primary heavy crude oil wells in Q3/13.
- Production volumes at Woodenhouse during Q2/13 averaged
approximately 13,500 bbl/d, representing an increase of 13% from
Q1/13 levels of approximately 12,000 bbl/d. Current production from
Woodenhouse is approximately 15,000 bbl/d.
- During Q2/13, reservoir performance from Canadian Natural's
industry leading Pelican Lake polymer flood remained strong. Ten
net horizontal production wells were drilled during the quarter and
13 net horizontal production wells are targeted in Q3/13.
Construction of the new battery at Pelican Lake was successfully
completed in mid-May 2013. Facility constraints that began in Q4/12
have been alleviated by the expansion and as a result, production
volumes at Pelican Lake and Woodenhouse have increased. Pelican
Lake operations achieved record quarterly crude oil production of
approximately 42,000 bbl/d in Q2/13, representing a 10% increase
from Q1/13 and a 12% increase from Q2/12.
- North America light crude oil and NGLs Q2/13 production
decreased 2% from Q1/13 due to downtime as a result of expansion
activities at Septimus and Wembley, spring break-up activities and
planned turnarounds. The Company drilled 5 net light crude oil
wells in Q2/13 and targets to drill 29 additional net wells in
Q3/13. Canadian Natural's light crude oil drilling program will
continue to utilize and advance horizontal multi-frac well
technology to access new reserves in pools across the Company's
land base.
- Total planned drilling activity for Q3/13 includes 297 net
crude oil wells, excluding stratigraphic ("strat") and service
wells.
Thermal In Situ Oil Sands
Three Months Ended Six Months Ended
----------- -----------
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
2013 2013 2012 2013 2012
----------------------------------------------------------------------------
Bitumen production
(bbl/d) 90,051 108,889 94,356 99,419 87,341
----------------------------------------------------------------------------
Net wells targeting
crude oil 27 33 37 60 80
Net successful wells
drilled 27 33 37 60 80
----------------------------------------------------------------------------
Success rate 100% 100% 100% 100% 100%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
- Q2/13 thermal in situ oil sands ("thermal in situ") production
volumes averaged approximately 90,000 bbl/d due to the timing of
steaming and production cycles.
- During the second quarter of 2013, bitumen emulsion was
discovered at surface at four separate locations in the Company's
Primrose development area. The bitumen emulsion seepage has been
controlled to specific containment areas totaling 13.5 hectares
where it is effectively recovered as it reaches the surface. The
rate of bitumen emulsion seepage in all four locations has declined
as expected and currently totals less than 20 bbl/d. Canadian
Natural believes the cause of the bitumen emulsion seepage is
mechanical failures of wellbores in the vicinity of the impacted
locations. A complete review is ongoing and Canadian Natural has a
specialized team focused on investigating wells in the impacted
areas for potential required remediation work.
- The Company's near term steaming plan at Primrose has been
modified, with restrictions on steaming in some areas until the
investigation with the Alberta Energy Regulator is complete.
Canadian Natural's July 2013 production was approximately 120,000
bbl/d with an additional 20,000 bbl/d of production capacity that
was restricted due to available plant capacity. The Company targets
2013 thermal in situ production to range from 100,000 bbl/d to
107,000 bbl/d. For 2014, even with these modified steaming
strategies, the Company anticipates thermal in situ production,
excluding Kirby South, to range from 100,000 bbl/d to 110,000
bbl/d, approximately 10,000 bbl/d less than originally targeted.
The Company is of the view that reserves recovered from the
Primrose area over its life cycle will be substantially
unchanged.
- Kirby South remains ahead of plan and on budget. Drilling was
successfully completed on the seventh and final pad in Q2/13.
Commissioning is nearing completion with first steam-in expected in
late August or early September 2013, ahead of the originally
scheduled steam-in date of November 2013. Production is targeted to
grow to 40,000 bbl/d by Q4/14.
- Detailed engineering is progressing for Kirby North Phase 1.
As of June 30, 2013, the engineering portion was 64% complete.
Construction of the main access road has been completed and site
preparation will continue into Q3/13.
- Kirby South and Kirby North Phase 1 will contribute to a
targeted staged expansion of production volumes from the greater
Kirby area over time to 140,000 bbl/d, with the overall thermal in
situ development plan targeted to increase to 510,000 bbl/d of
production capacity.
- Planned drilling activity for Q3/13 includes 47 net thermal in
situ wells, excluding strat and service wells.
Natural Gas
Three Months Ended Six Months Ended
----------- -----------
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
2013 2013 2012 2013 2012
----------------------------------------------------------------------------
Natural gas
production (MMcf/d) 1,092 1,125 1,230 1,108 1,255
----------------------------------------------------------------------------
Net wells targeting
natural gas 8 16 4 24 23
Net successful wells
drilled 8 15 4 23 23
----------------------------------------------------------------------------
Success rate 100% 94% 100% 96% 100%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
- During Q2/13, North America natural gas production averaged
1,092 MMcf/d, representing a 11% decrease from Q2/12 levels and a
3% decrease from Q1/13 levels. The decrease in production levels
year over year was due to expected production declines, reflecting
Canadian Natural's strategic decision to allocate capital to higher
return crude oil projects. Q3/13 production volumes are targeted to
increase to 1,135 MMcf/d to 1,155 MMcf/d.
- At Septimus, the Company's liquids rich natural gas Montney
play, the plant expansion was completed and first production was
achieved in July 2013. At the end of July, total production at
Septimus reached approximately 90 MMcf/d of natural gas and
approximately 8,600 bbl/d of liquids. During Q2/13, Canadian
Natural drilled 6 net wells at Septimus and targets to drill 7
additional net wells in Q3/13. By early September 2013, production
is targeted to grow to plant expansion capacity of 125 MMcf/d of
natural gas sales, yielding 12,200 bbl/d of liquids, through the
plant and deep cut facilities.
- Canadian Natural has a dominant Montney land position with
over one million high quality net acres, the largest in the
industry. In Q1/13, the Company commenced the process to monetize
approximately 243,000 net acres (approximately 380 net sections) of
its Montney land base in the liquids rich fairway in the Graham
Kobes area of Northeast British Columbia. In Q2/13, the Information
Memorandum was completed. The Company targets to open the
associated data room in mid to late August 2013 and conduct
presentations in September 2013.
International Exploration and Production
Three Months Ended Six Months Ended
----------- -----------
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
2013 2013 2012 2013 2012
----------------------------------------------------------------------------
Crude oil production
(bbl/d)
North Sea 18,901 18,774 17,619 18,838 20,333
Offshore Africa 18,055 16,112 20,598 17,089 20,655
----------------------------------------------------------------------------
Natural gas
production (MMcf/d)
North Sea 4 1 2 3 2
Offshore Africa 26 24 23 25 20
----------------------------------------------------------------------------
Net wells targeting
crude oil 1.0 - - 1.0 -
Net successful wells
drilled 1.0 - - 1.0 -
----------------------------------------------------------------------------
Success rate 100% - - 100% -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
- International crude oil production averaged 36,956 bbl/d
during the quarter. The 6% increase in production from Q1/13 was
primarily due to the stabilization of the midwater arch which
resulted in a reinstatement of production at the Olowi Field in
Gabon in late Q1/13. Crude oil production volumes declined 3% from
Q2/12 as a result of natural field declines and the cessation of
North Sea drilling activity following an increase in the
Supplementary Charge Tax Rate in 2011.
- In Q2/13, the Company received a second Brownfield Allowance
("BFA") approval for its Ninian Field development plan which
includes four new production wells, four injectors and two well
upgrades. The Company received its first BFA approval in Q1/13 for
its Tiffany field development plan of a two well infill drilling
program which achieved first oil in May 2013. In September 2012,
the UK government announced the implementation of the BFA, which
allows for a property development allowance on qualifying
preapproved field developments. This allowance partially mitigates
the impact of previous tax increases.
- The light crude oil infill drilling program at Espoir, Côte
d'Ivoire, originally targeted to commence in late Q2/13, has been
delayed as the Company is demobilizing the current drilling rig due
to ongoing operational and safety issues with the drilling
contractor. Canadian Natural is currently re-assessing its drilling
options at Espoir, where the Company expects to undertake an 8-well
drilling program.
- During Q2/13, Canadian Natural acquired operatorship and a 60%
working interest of Block 12 in Côte d'Ivoire, located
approximately 35 km west of the Company's current production at
Espoir and Baobab. The Company plans to commence new 3D seismic
acquisition in Q4/13. Potential exploration drilling is targeted
for 2015 to evaluate deepwater channel/fan structures similar to
the Jubilee crude oil discoveries in Ghana and plays elsewhere in
offshore Africa.
- Exploration work on Block 514 in Cote d'Ivoire, in which
Canadian Natural has a 36% working interest, is underway and a
seismic program has been completed. Drilling is targeted to
commence in the first half of 2014. The Company believes this block
is also prospective for deepwater channel/fan structures similar to
Jubilee.
- A partner has been selected to jointly conduct exploratory
drilling on Canadian Natural's prospective offshore South Africa
property. The Company will provide further details on the
partnership terms upon receipt of regulatory approval. Targeted
drilling windows are from Q4/13 to Q1/14 and from Q4/14 to Q1/15
and the necessary long-lead equipment has been ordered.
North America Oil Sands Mining and Upgrading - Horizon
Three Months Ended Six Months Ended
----------- -----------
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
2013 2013 2012 2013 2012
----------------------------------------------------------------------------
Synthetic crude oil
production (bbl/d) 67,954 108,782 115,823 88,255 80,957
----------------------------------------------------------------------------
----------------------------------------------------------------------------
- During Q2/13, SCO production averaged 67,954 bbl/d at Horizon
Oil Sands. Production volumes were lower than Q1/13 and Q2/12
levels due to the completion of the Company's first major
maintenance turnaround in May 2013. Horizon SCO production averaged
approximately 101,000 bbl/d in June 2013, approximately 110,000
bbl/d in July 2013 and Q3/13 production guidance is targeted to
range from 110,000 bbl/d to 115,000 bbl/d. 2013 annual guidance
remains unchanged at 100,000 bbl/d to 108,000 bbl/d of SCO
production.
- Canadian Natural's staged expansion to 250,000 bbl/d of SCO
production capacity continues to progress on track. Capital
expenditures to date on Phase 2/3 expansion are at or below cost
estimates as the Company executes its cost focused strategy.
Expansion work at Horizon will ultimately add an additional 140,000
bbl/d of SCO production in a staged, disciplined manner. Horizon
provides high quality, long life SCO production without decline for
decades.
- An update to the staged Phase 2/3 expansion on an Engineering,
Procurement and Construction basis at the end of Q2/13 is as
follows:
-- Overall Horizon Phase 2/3 expansion is 24% complete.
-- Reliability - Tranche 2 is 90% complete. An additional 5,000
bbl/d of production capacity is targeted to be added in 2014.
-- Directive 74 includes technological investment and research
into tailings management. This project remains on track and is
currently 18% complete.
-- Phase 2A is a coker expansion. The expansion is 62% complete,
and is targeted to add 10,000 bbl/d of production capacity in
2015.
-- Phase 2B is 15% complete. This phase includes lump sum
contracts for major components such as gas/oil hydrotreatment,
froth treatment and a hydrogen plant. This phase is targeted to add
another 45,000 bbl/d of production capacity in 2016.
-- Phase 3 is on track and engineering is underway. This phase
is 15% complete, and includes the addition of supplementary
extraction trains. This phase is targeted to increase production
capacity by 80,000 bbl/d in 2017.
-- The projects which are currently under construction continue
to trend at or below cost estimates.
- Total capital budgeted for the Horizon Phase 2/3 expansion in
2013 is $2.075 billion. Canadian Natural continues to be
disciplined and cost driven in the Horizon Phase 2/3 expansion to
ensure the expansion continues effectively and efficiently.
MARKETING
Three Months Ended Six Months Ended
----------- -----------
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
2013 2013 2012 2013 2012
----------------------------------------------------------------------------
Crude oil and NGLs
pricing
WTI benchmark price
(US$/bbl) (1) $ 94.23 $ 94.34 $ 93.50 $ 94.28 $ 98.22
WCS blend
differential from
WTI (%) (2) 20% 34% 24% 27% 23%
SCO price (US$/bbl) $ 99.10 $ 95.24 $ 89.54 $ 97.18 $ 93.82
Condensate
benchmark pricing
(US$/bbl) $ 101.50 $ 107.18 $ 99.49 $ 104.32 $ 104.77
Average realized
pricing before
risk management
(C$/bbl) (3) $ 75.10 $ 60.87 $ 72.12 $ 67.94 $ 77.14
Natural gas pricing
AECO benchmark
price (C$/GJ) $ 3.41 $ 2.92 $ 1.74 $ 3.16 $ 2.06
Average realized
pricing before
risk management
(C$/Mcf) $ 4.05 $ 3.51 $ 2.15 $ 3.78 $ 2.44
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) West Texas Intermediate ("WTI").
(2) Western Canadian Select ("WCS").
(3) Average crude oil and NGLs pricing excludes SCO. Pricing is
net of blending costs and excluding risk management activities.
----------------------------------------------------------------
SCO Dated Brent Condensate
WTI WCS Blend Differential Differential Differential
Benchmark Pricing Differential from WTI from WTI from WTI
Pricing (US$/bbl) from WTI (%) (US$/bbl) (US$/bbl) (US$/bbl)
----------------------------------------------------------------------------
2013
April $ 92.07 25% $ 6.14 $ 9.85 $ 10.00
May $ 94.80 15% $ 8.33 $ 7.69 $ 6.92
June $ 95.80 21% $ 0.02 $ 7.11 $ 4.91
July $ 104.70 14% $ 5.98 $ 3.25 $ 1.60
August (i) $ 104.74 15% $ 3.20 $ 3.13 $ (2.78)
September
(i) $ 103.84 20% $ 2.27 $ 3.21 $ (4.45)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(i) Based on current indicative pricing as at July 31, 2013.
- As expected, heavy crude oil differentials narrowed during the
second quarter, resulting in more favorable price realizations for
the Company. The WCS differential averaged 20% in Q2/13 compared to
34% in Q1/13 and 24% in Q2/12. The differential narrowed during
Q2/13 compared to Q1/13 due to increased seasonal demand for heavy
crude oil, increased pipeline capacity resulting from improved
pipeline reliability, and lower unplanned maintenance activity at
refineries accessible to Canadian heavy crude oil. In July, August
and September 2013, the WCS differential, based on current
indicative pricing, narrowed to 14%, 15% and 20%, respectively.
- Canadian Natural contributed over 172,000 bbl/d of its heavy
crude oil blends to the WCS blend in Q2/13. The Company remains the
largest contributor to the WCS blend, accounting for over 62% of
the total blend this quarter.
- The Company uses condensate as a blending diluent for heavy
crude oil pipeline shipments. Condensate price premiums to WTI
narrowed to US$7.27/bbl in Q2/13 compared to US$12.84/bbl in Q1/13,
reflecting normal seasonality. Lower condensate price premiums are
expected to continue in the second half of 2013 resulting in higher
netbacks for the Company's heavy crude oil sales volumes.
- As expected, the Dated Brent to WTI differential narrowed to
US$8.21/bbl in Q2/13 compared to US$18.09/bbl in Q1/13 and
US$14.71/bbl in Q2/12, reflecting continued debottlenecking of the
logistical constraints between Cushing and the Gulf Coast as
incremental pipeline capacity continued to grow. Overall pricing
relative to Dated Brent pricing for Canadian Natural's North
American crude oil production continues to improve as a result of
this narrowing.
- SCO pricing averaged US$99.10/bbl during Q2/13, representing a
4% and 11% increase from Q1/13 and Q2/12 pricing, respectively.
Pricing increases from Q1/13 and Q2/12 reflect planned and
unplanned supply disruptions in Northern Alberta and overall higher
diesel demand and result in more favorable price realizations for
the Company.
NORTH WEST REDWATER UPGRADING AND REFINING
In Q2/13 work continued on the North West Redwater refinery and
completion is targeted for mid-2016. The North West Redwater
refinery asset strengthens the Company's position by providing a
competitive return on investment and by adding 50,000 bbl/d of
bitumen conversion capacity in Alberta which will help reduce
volatility in pricing all Western Canadian heavy crude oil.
FINANCIAL REVIEW
The Company continues to implement proven strategies and its
disciplined approach to capital allocation. As a result, the
financial position of Canadian Natural remains strong. Canadian
Natural's cash flow generation, credit facilities, 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 623,315 BOE/d for Q2/13 with approximately 96% of
production located in G8 countries.
- Subsequent to Q2/13, the Company increased its forecasted 2013
capital spending as a result of the Cold Lake pipeline expansion,
the Barrick Energy Inc. acquisition and a minor increase in capital
allocated to Exploration and Production.
- Canadian Natural has a strong balance sheet with debt to book
capitalization of 29% and debt to EBITDA of 1.4x at June 30,
2013.
- During Q2/13, Canadian Natural's $3,000 million revolving
syndicated credit facility was extended to June 2017. Additionally,
the Company issued $500 million of 2.89% medium-term notes due
August 2020. Proceeds from the securities issued were used to repay
bank indebtedness and for general corporate purposes.
- In Q2/13, the Company completed a full quarter of its US
commercial paper program. Borrowings of up to a maximum of US$1,500
million are authorized. The program further diversifies the
Company's borrowing base and has been well received.
- Canadian Natural maintains significant financial stability and
liquidity represented by approximately $2.4 billion of available
credit under its bank credit facilities, net of commercial paper
issued.
- The Company's commodity hedging program protects investment
returns, ensures ongoing balance sheet strength and supports the
Company's cash flow for its capital expenditure programs.
Approximately 58% of forecasted 2013 crude oil volumes are
currently hedged using price collars and physical crude oil sales
contracts with fixed WCS differentials. Through the use of collars,
the Company has hedged approximately 300,000 bbl/d of crude oil
volumes in the second half of 2013, and approximately 150,000 bbl/d
of crude oil volumes in 2014. To partially mitigate its exposure to
widening heavy crude oil differentials, the Company has entered
into physical crude oil sales contracts with weighted average fixed
WCS differentials as follows:
Term Volume Weighted average price
----------------------------------------------------------------------------
Jul 2013 - Sep 2013 20,000 bbl/d US$21.27/bbl
Oct 2013 - Dec 2013 17,000 bbl/d US$21.49/bbl
Jan 2014 - Mar 2014 8,000 bbl/d US$21.89/bbl
Apr 2014 - Jun 2014 9,000 bbl/d US$21.93/bbl
Jul 2014 - Sep 2014 10,000 bbl/d US$20.81/bbl
Oct 2014 - Dec 2014 10,000 bbl/d US$20.81/bbl
----------------------------------------------------------------------------
Details of the Company's commodity hedging program can be found
on the Company's website at www.cnrl.com.
- Year to date, Canadian Natural has purchased for cancellation
6,937,500 common shares at a weighted average price of $30.86 per
common share.
- Canadian Natural declared a quarterly cash dividend on common
shares of C$0.125 per share payable on October 1, 2013.
OUTLOOK
The Company forecasts 2013 production levels before royalties to
average between 482,000 and 513,000 bbl/d of crude oil and NGLs and
between 1,085 and 1,145 MMcf/d of natural gas. Q3/13 production
guidance before royalties is forecast to average between 506,000
and 529,000 bbl/d of crude oil and NGLs and between 1,135 and 1,155
MMcf/d of natural gas. Detailed guidance on production levels,
capital allocation and operating costs can be found on the
Company's website at www.cnrl.com.
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",
"proposed" or expressions of a similar nature suggesting future
outcome or statements regarding an outlook. Disclosure related to
expected future commodity pricing, forecast or anticipated
production volumes, royalties, operating costs, capital
expenditures, income tax expenses and other guidance provided
throughout 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 thermal projects, Pelican Lake water
and polymer flood project, the Kirby Thermal Oil Sands Project,
construction of the proposed Keystone XL Pipeline from Hardisty,
Alberta to the US Gulf Coast, construction of the proposed Energy
East pipeline to transport crude oil from Alberta to Quebec and New
Brunswick, the proposed Kinder Morgan Trans Mountain pipeline
expansion from Edmonton, Alberta to Vancouver, British Columbia,
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, natural gas and natural gas
liquids ("NGLs") reserves and in projecting future rates of
production and the timing of development expenditures. The total
amount or timing of actual future production may vary significantly
from reserve and production estimates.
The forward-looking statements are based on current
expectations, estimates and projections about the Company and the
industry in which the Company operates, which speak only as of the
date such statements were made or as of the date of the report or
document in which they are contained, and are subject to known and
unknown risks and uncertainties that could cause the actual
results, performance or achievements of the Company to be
materially different from any future results, performance or
achievements expressed or implied by such forward-looking
statements. Such risks and uncertainties include, among others:
general economic and business conditions which will, among other
things, impact demand for and market prices of the Company's
products; volatility of and assumptions regarding crude oil and
natural gas prices; fluctuations in currency and interest rates;
assumptions on which the Company's current guidance is based;
economic conditions in the countries and regions in which the
Company conducts business; political uncertainty, including actions
of or against terrorists, insurgent groups or other conflict
including conflict between states; industry capacity; ability of
the Company to implement its business strategy, including
exploration and development activities; impact of competition; the
Company's defense of lawsuits; availability and cost of seismic,
drilling and other equipment; ability of the Company and its
subsidiaries to complete capital programs; the Company's and its
subsidiaries' ability to secure adequate transportation for its
products; unexpected disruptions or delays in the resumption of the
mining, extracting or upgrading of the Company's bitumen products;
potential delays or changes in plans with respect to exploration or
development projects or capital expenditures; ability of the
Company to attract the necessary labour required to build its
thermal and oil sands mining projects; operating hazards and other
difficulties inherent in the exploration for and production and
sale of crude oil and natural gas and in mining, extracting or
upgrading the Company's bitumen products; availability and cost of
financing; the Company's and its subsidiaries' success of
exploration and development activities and 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 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 six months ended June 30, 2013 and the MD&A and the audited
consolidated financial statements for the year ended December 31,
2012.
All dollar amounts are referenced in millions of Canadian
dollars, except where noted otherwise. The Company's consolidated
financial statements for the period ended June 30, 2013 and this
MD&A have been prepared in accordance with International
Financial Reporting Standards ("IFRS") as issued by the
International Accounting Standards Board. 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 ("Mcf") of natural gas to one barrel ("bbl") of
crude oil (6 Mcf:1 bbl). This conversion may be misleading,
particularly if used in isolation, since the 6 Mcf:1 bbl ratio is
based on an energy equivalency conversion method primarily
applicable at the burner tip and does not represent a value
equivalency at the wellhead. In comparing the value ratio using
current crude oil prices relative to natural gas prices, the 6
Mcf:1 bbl conversion ratio may be misleading as an indication of
value. In addition, for the purposes of this MD&A, crude oil is
defined to include the following commodities: light and medium
crude oil, primary heavy crude oil, Pelican Lake heavy crude oil,
bitumen (thermal oil), and 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 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 six months ended June 30, 2013
in relation to the comparable periods in 2012 and the first quarter
of 2013. The accompanying tables form an integral part of this
MD&A. Additional information relating to the Company, including
its Annual Information Form for the year ended December 31, 2012,
is available on SEDAR at www.sedar.com, and on EDGAR at
www.sec.gov. This MD&A is dated August 7, 2013.
FINANCIAL HIGHLIGHTS
($ millions, except per common share amounts)
Three Months Ended Six Months Ended
----------- -----------
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
2013 2013 2012 2013 2012
----------------------------------------------------------------------------
Product sales $ 4,230 $ 4,101 $ 4,187 $ 8,331 $ 8,158
Net earnings $ 476 $ 213 $ 753 $ 689 $ 1,180
Per common share
- basic $ 0.44 $ 0.19 $ 0.68 $ 0.63 $ 1.07
- diluted $ 0.44 $ 0.19 $ 0.68 $ 0.63 $ 1.07
Adjusted net earnings
from operations (1) $ 462 $ 401 $ 606 $ 863 $ 906
Per common share
- basic $ 0.42 $ 0.37 $ 0.55 $ 0.79 $ 0.82
- diluted $ 0.42 $ 0.37 $ 0.55 $ 0.79 $ 0.82
Cash flow from
operations (2) $ 1,670 $ 1,571 $ 1,754 $ 3,241 $ 3,034
Per common share
- basic $ 1.53 $ 1.44 $ 1.60 $ 2.97 $ 2.76
- diluted $ 1.53 $ 1.44 $ 1.59 $ 2.97 $ 2.75
Capital expenditures,
net of dispositions $ 1,792 $ 1,736 $ 1,324 $ 3,528 $ 2,920
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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" presents 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" presents 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 Six Months Ended
----------- -----------
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
($ millions) 2013 2013 2012 2013 2012
----------------------------------------------------------------------------
Net earnings as
reported $ 476 $ 213 $ 753 $ 689 $ 1,180
Share-based
compensation, net of
tax (1) (49) 71 (115) 22 (222)
Unrealized risk
management (gain)
loss, net of tax (2) (92) 51 (103) (41) (63)
Unrealized foreign
exchange loss, net
of tax (3) 112 78 71 190 11
Realized foreign
exchange gain on
repayment of US
dollar debt
securities (4) - (12) - (12) -
Effect of statutory
tax rate and other
legislative changes
on deferred income
tax liabilities (5) 15 - - 15 -
----------------------------------------------------------------------------
Adjusted net earnings
from operations $ 462 $ 401 $ 606 $ 863 $ 906
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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 the 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 first quarter of 2013, the Company repaid US$400
million of 5.15% unsecured notes.
(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 second quarter of 2013, the government of
British Columbia substantively enacted legislation to increase its
provincial corporate income tax rate effective April 1, 2013,
resulting in an increase in the Company's deferred income tax
liability of $15 million.
Cash Flow from Operations
Three Months Ended Six Months Ended
----------- -----------
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
($ millions) 2013 2013 2012 2013 2012
----------------------------------------------------------------------------
Net earnings $ 476 $ 213 $ 753 $ 689 $ 1,180
Non-cash items:
Depletion,
depreciation and
amortization 1,172 1,142 1,084 2,314 2,059
Share-based
compensation (49) 71 (115) 22 (222)
Asset retirement
obligation
accretion 42 42 38 84 75
Unrealized risk
management (gain)
loss (114) 62 (144) (52) (84)
Unrealized foreign
exchange loss 112 78 71 190 11
Realized foreign
exchange gain on
repayment of US
dollar debt
securities - (12) - (12) -
Equity loss from
jointly controlled
entity - 2 5 2 5
Deferred income tax
expense (recovery) 31 (27) 62 4 10
----------------------------------------------------------------------------
Cash flow from
operations $ 1,670 $ 1,571 $ 1,754 $ 3,241 $ 3,034
----------------------------------------------------------------------------
----------------------------------------------------------------------------
SUMMARY OF CONSOLIDATED NET EARNINGS AND CASH FLOW FROM
OPERATIONS
Net earnings for the six months ended June 30, 2013 were $689
million compared with $1,180 million for the six months ended June
30, 2012. Net earnings for the six months ended June 30, 2013
included net after-tax expenses of $174 million compared with net
after-tax income of $274 million for the six months ended June 30,
2012 related to the effects of share-based compensation, risk
management activities, fluctuations in foreign exchange rates
including 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 six months ended June 30, 2013 were $863 million compared with
$906 million for the six months ended June 30, 2012.
Net earnings for the second quarter of 2013 were $476 million
compared with $753 million for the second quarter of 2012 and $213
million for the first quarter of 2013. Net earnings for the second
quarter of 2013 included net after-tax income of $14 million
compared with $147 million for the second quarter of 2012 and net
after-tax expenses of $188 million for the first quarter of 2013
related to the effects of share-based compensation, risk management
activities, fluctuations in foreign exchange rates including 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 second
quarter of 2013 were $462 million compared with $606 million for
the second quarter of 2012 and $401 million for the first quarter
of 2013.
The decrease in adjusted net earnings for the six months ended
June 30, 2013 from the comparable period in 2012 was primarily due
to:
- lower crude oil and NGLs netbacks;
- lower natural gas sales volumes; and
- higher depletion, depreciation and amortization expense;
partially offset by:
- higher crude oil and synthetic crude oil ("SCO") sales volumes
in the North America and Oil Sands Mining and Upgrading
segments;
- higher realized natural gas netbacks;
- higher realized SCO prices;
- higher realized risk management gains; and
- the impact of a weaker Canadian dollar.
The decrease in adjusted net earnings for the second quarter of
2013 from the comparable period in 2012 was primarily due to:
- lower SCO sales volumes in the Oil Sands Mining and Upgrading
segment due to the May 2013 turnaround;
- lower natural gas sales volumes;
- lower realized risk management gains; and
- higher depletion, depreciation and amortization expense;
partially offset by:
- higher crude oil and NGLs sales volumes;
- higher natural gas netbacks;
- higher realized SCO prices; and
- the impact of a weaker Canadian dollar.
The increase in adjusted net earnings for the second quarter of
2013 from the first quarter of 2013 was primarily due to:
- higher crude oil and NGLs and natural gas netbacks;
- higher realized SCO prices; and
- the impact of a weaker Canadian dollar;
partially offset by:
- lower crude oil and SCO sales volumes in the North America and
Oil Sands Mining and Upgrading segments; and
- lower realized risk management gains.
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 six months ended June 30, 2013
was $3,241 million compared with $3,034 million for the six months
ended June 30, 2012. Cash flow from operations for the second
quarter of 2013 was $1,670 million compared with $1,754 million for
the second quarter of 2012 and $1,571 million for the first quarter
of 2013. The fluctuations in cash flow from operations from the
comparable periods were primarily due to the factors noted above
relating to the fluctuations in adjusted net earnings, excluding
depletion, depreciation and amortization expense, as well as due to
the impact of cash taxes.
Total production before royalties for the six months ended June
30, 2013 increased 1% to 651,921 BOE/d from 645,943 BOE/d for the
six months ended June 30, 2012. Total production before royalties
for the second quarter of 2013 decreased 8% to 623,315 BOE/d from
679,607 BOE/d for the second quarter of 2012 and 680,844 BOE/d for
the first quarter of 2013.
SUMMARY OF QUARTERLY RESULTS
The following is a summary of the Company's quarterly results
for the eight most recently completed quarters:
($ millions, except per common Jun 30 Mar 31 Dec 31 Sep 30
share amounts) 2013 2013 2012 2012
----------------------------------------------------------------------------
Product sales $ 4,230 $ 4,101 $ 4,059 $ 3,978
Net earnings $ 476 $ 213 $ 352 $ 360
Net earnings per common share
- basic $ 0.44 $ 0.19 $ 0.32 $ 0.33
- diluted $ 0.44 $ 0.19 $ 0.32 $ 0.33
----------------------------------------------------------------------------
----------------------------------------------------------------------------
($ millions, except per common Jun 30 Mar 31 Dec 31 Sep 30
share amounts) 2012 2012 2011 2011
----------------------------------------------------------------------------
Product sales $ 4,187 $ 3,971 $ 4,788 $ 3,690
Net earnings $ 753 $ 427 $ 832 $ 836
Net earnings per common share
- basic $ 0.68 $ 0.39 $ 0.76 $ 0.76
- diluted $ 0.68 $ 0.39 $ 0.76 $ 0.76
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Volatility in the quarterly net earnings 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 reference location at
Cushing, Oklahoma ("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 crude oil drilling program, and the
impact of the turnaround/suspension and subsequent 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.
- 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,
shut-in natural gas production due to pricing 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 in 2011 that had higher operating costs per
Mcf than the Company's existing properties, and the
turnaround/suspension and subsequent recommencement of production
at Horizon.
- Depletion, depreciation and amortization - Fluctuations due to
changes in sales volumes, proved reserves, asset retirement
obligations, finding and development costs associated with crude
oil and natural gas exploration, estimated future costs to develop
the Company's proved undeveloped reserves, and the impact of the
turnaround/suspension and subsequent recommencement of production
at Horizon.
- 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 also 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 Six Months Ended
----------- -----------
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
2013 2013 2012 2013 2012
----------------------------------------------------------------------------
WTI benchmark price
(US$/bbl) $ 94.23 $ 94.34 $ 93.50 $ 94.28 $ 98.22
Dated Brent benchmark
price (US$/bbl) $ 102.44 $ 112.43 $ 108.21 $ 107.41 $ 113.34
WCS blend
differential from
WTI (US$/bbl) $ 19.10 $ 31.79 $ 22.83 $ 25.41 $ 22.15
WCS blend
differential from
WTI (%) 20% 34% 24% 27% 23%
SCO price (US$/bbl) $ 99.10 $ 95.24 $ 89.54 $ 97.18 $ 93.82
Condensate benchmark
price (US$/bbl) $ 101.50 $ 107.18 $ 99.49 $ 104.32 $ 104.77
NYMEX benchmark price
(US$/MMBtu) $ 4.09 $ 3.35 $ 2.26 $ 3.72 $ 2.52
AECO benchmark price
(C$/GJ) $ 3.41 $ 2.92 $ 1.74 $ 3.16 $ 2.06
US/Canadian dollar
average exchange
rate (US$) $ 0.9774 $ 0.9917 $ 0.9897 $ 0.9844 $ 0.9943
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Commodity Prices
Crude oil sales contracts in the North America segment are
typically based on WTI benchmark pricing. WTI averaged US$94.28 per
bbl for the six months ended June 30, 2013, a decrease of 4% from
US$98.22 per bbl for the six months ended June 30, 2012. WTI
averaged US$94.23 per bbl for the second quarter of 2013 and was
consistent with the comparative periods.
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$107.41 per
bbl for the six months ended June 30, 2013, a decrease of 5% from
US$113.34 per bbl for the six months ended June 30, 2012. Brent
averaged US$102.44 per bbl for the second quarter of 2013, a
decrease of 5% from US$108.21 per bbl for the second quarter of
2012, and a decrease of 9% from US$112.43 per bbl for the first
quarter of 2013.
The Brent differential from WTI tightened for the three and six
months ended June 30, 2013 from the comparable periods due to
incremental pipeline capacity reflecting a continued
debottlenecking of logistical constraints from Cushing to the US
Gulf Coast.
The WCS Heavy Differential averaged 27% for the six months ended
June 30, 2013 compared with 23% for the six months ended June 30,
2012. The WCS Heavy Differential averaged 20% for the second
quarter of 2013 compared with 24% for the second quarter of 2012,
and 34% for the first quarter of 2013. The WCS Heavy Differential
tightened in the second quarter of 2013 from the comparable periods
as a result of increased seasonal heavy oil demand and increased
pipeline capacity as pipeline reliability in the second quarter of
2013 improved. The WCS Heavy Differential per barrel tightened in
July 2013 to average US$14.20 per bbl and in August 2013 to average
US$15.57 per bbl. To partially mitigate its exposure to widening
heavy crude oil differentials, as at June 30, 2013, the Company has
entered into physical crude oil sales contracts with weighted
average fixed WCS differentials as follows: 20,000 bbl/d in the
third quarter of 2013 at US$21.27 per bbl; 15,000 bbl/d in the
fourth quarter of 2013 at US$21.52 per bbl; 8,000 bbl/d in the
first quarter of 2014 at US$21.89 per bbl; 9,000 bbl/d in the
second quarter of 2014 at US$21.93 per bbl; and 10,000 bbl/d in the
third and fourth quarters of 2014 at US$20.81.
The SCO price averaged US$97.18 per bbl for the six months ended
June 30, 2013, an increase of 4% from US$93.82 per bbl for the six
months ended June 30, 2012. The SCO price averaged US$99.10 per bbl
for the second quarter of 2013, an increase of 11% from US$89.54
per bbl for the second quarter of 2012, and an increase of 4% from
US$95.24 per bbl for the first quarter of 2013. The increase in SCO
pricing for the three and six months ended June 30, 2013 from the
comparable periods was due to planned and unplanned shutdowns of
various upgrading facilities in Northern Alberta.
The Company uses condensate as a blending diluent for heavy
crude oil pipeline shipments. During the second quarter of 2013,
condensate price premiums to WTI narrowed, 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$3.72 per MMBtu for the six
months ended June 30, 2013, an increase of 48% from US$2.52 per
MMBtu for the six months ended June 30, 2012. NYMEX natural gas
prices averaged US$4.09 per MMBtu for the second quarter of 2013,
an increase of 81% from US$2.26 per MMBtu for the second quarter of
2012, and an increase of 22% from US$3.35 per MMBtu for the first
quarter of 2013.
AECO natural gas prices for the six months ended June 30, 2013
averaged $3.16 per GJ, an increase of 53% from $2.06 per GJ for the
six months ended June 30, 2012. AECO natural gas prices for the
second quarter of 2013 averaged $3.41 per GJ, an increase of 96%
from $1.74 per GJ for the second quarter of 2012, and an increase
of 17% from $2.92 per GJ for the first quarter of 2013.
During the second quarter of 2013, natural gas prices continued
to recover from the low pricing levels in 2012. A steady North
America production supply forecast and a return to normal winter
weather in North America in 2013 has allowed natural gas
inventories to return to seasonal levels.
The Company continues to focus on its crude oil marketing
strategy including a blending strategy that expands markets within
current pipeline infrastructure, supporting pipeline projects that
provide crude oil transportation to new markets, and supporting
incremental heavy crude oil conversion capacity. Subsequent to June
30, 2013, the Company entered into a 20 year transportation
agreement to ship 80,000 bbl/d of crude oil on the proposed Energy
East pipeline, subject to regulatory approval.
DAILY PRODUCTION, before royalties
Three Months Ended Six Months Ended
----------- -----------
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
2013 2013 2012 2013 2012
----------------------------------------------------------------------------
Crude oil and NGLs
(bbl/d)
North America -
Exploration and
Production 331,453 345,489 316,483 338,433 311,048
North America - Oil
Sands Mining and
Upgrading 67,954 108,782 115,823 88,255 80,957
North Sea 18,901 18,774 17,619 18,838 20,333
Offshore Africa 18,055 16,112 20,598 17,089 20,655
----------------------------------------------------------------------------
436,363 489,157 470,523 462,615 432,993
----------------------------------------------------------------------------
Natural gas (MMcf/d)
North America 1,092 1,125 1,230 1,108 1,255
North Sea 4 1 2 3 2
Offshore Africa 26 24 23 25 20
----------------------------------------------------------------------------
1,122 1,150 1,255 1,136 1,277
----------------------------------------------------------------------------
Total barrels of oil
equivalent (BOE/d) 623,315 680,844 679,607 651,921 645,943
----------------------------------------------------------------------------
Product mix
Light and medium
crude oil and NGLs 16% 15% 15% 15% 15%
Pelican Lake heavy
crude oil 7% 5% 5% 6% 6%
Primary heavy crude
oil 22% 20% 18% 21% 19%
Bitumen (thermal oil) 14% 16% 14% 15% 14%
Synthetic crude oil 11% 16% 17% 14% 13%
Natural gas 30% 28% 31% 29% 33%
----------------------------------------------------------------------------
Percentage of product
sales (1) (2)
(excluding midstream
revenue)
Crude oil and NGLs 88% 89% 93% 89% 92%
Natural gas 12% 11% 7% 11% 8%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Net of blending costs and excluding risk management
activities.
(2) Comparative figures have been adjusted to reflect realized
product prices before transportation costs.
DAILY PRODUCTION, net of royalties
Three Months Ended Six Months Ended
----------- -----------
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
2013 2013 2012 2013 2012
----------------------------------------------------------------------------
Crude oil and NGLs
(bbl/d)
North America -
Exploration and
Production 274,850 289,992 272,089 282,379 263,020
North America - Oil
Sands Mining and
Upgrading 65,077 104,203 109,569 84,532 76,584
North Sea 18,839 18,706 17,578 18,773 20,282
Offshore Africa 14,974 13,603 15,051 14,292 16,274
----------------------------------------------------------------------------
373,740 426,504 414,287 399,976 376,160
----------------------------------------------------------------------------
Natural gas (MMcf/d)
North America 1,016 1,092 1,218 1,054 1,247
North Sea 4 1 2 3 2
Offshore Africa 22 20 19 21 17
----------------------------------------------------------------------------
1,042 1,113 1,239 1,078 1,266
----------------------------------------------------------------------------
Total barrels of oil
equivalent (BOE/d) 547,330 612,062 620,700 579,600 587,226
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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, primary heavy crude oil, Pelican Lake heavy crude
oil, bitumen (thermal oil) and SCO.
Crude oil and NGLs production for the six months ended June 30,
2013 increased 7% to 462,615 bbl/d from 432,993 bbl/d for the six
months ended June 30, 2012. Crude oil and NGLs production for the
second quarter of 2013 decreased 7% to 436,363 bbl/d from 470,523
bbl/d for the second quarter of 2012 and decreased 11% from 489,157
bbl/d for the first quarter of 2013. The increase in production for
the six months ended June 30, 2013 from the comparable period in
2012 was primarily due to the impact of a strong heavy crude oil
drilling program, and the increased production from the Company's
cyclic thermal operations and Horizon. The decrease in production
for the second quarter of 2013 from the comparable periods was
primarily due to the decrease in production volumes resulting from
Horizon's planned maintenance turnaround in May 2013 and from
fluctuations in the Company's cyclic thermal operations, partially
offset by the impact of a strong heavy crude oil drilling program.
Crude oil and NGLs production in the second quarter of 2013 was
within the Company's previously issued guidance of 435,000 to
461,000 bbl/d.
Natural gas production for the six months ended June 30, 2013
decreased 11% to 1,136 MMcf/d from 1,277 MMcf/d for the six months
ended June 30, 2012. Natural gas production for the second quarter
of 2013 decreased 11% to 1,122 MMcf/d from 1,255 MMcf/d for the
second quarter of 2012 and decreased 2% from 1,150 MMcf/d for the
first quarter of 2013. The decrease in natural gas production for
the three and six months ended June 30, 2013 from the comparable
periods was primarily a result of a strategic reduction of natural
gas drilling as the Company allocated capital to higher return
crude oil projects, as well as expected production declines.
Natural gas production in the second quarter of 2013 exceeded the
Company's previously issued guidance of 1,090 to 1,110 MMcf/d.
For 2013, annual production guidance is targeted to average
between 482,000 and 513,000 bbl/d of crude oil and NGLs and between
1,085 and 1,145 MMcf/d of natural gas. Third quarter 2013
production guidance is targeted to average between 506,000 and
529,000 bbl/d of crude oil and NGLs and between 1,135 and 1,155
MMcf/d of natural gas.
North America - Exploration and Production
North America crude oil and NGLs production for the six months
ended June 30, 2013 increased 9% to average 338,433 bbl/d from
311,048 bbl/d for the six months ended June 30, 2012. For the
second quarter of 2013, crude oil and NGLs production increased 5%
to average 331,453 bbl/d compared with 316,483 bbl/d for the second
quarter of 2012 and decreased 4% from 345,489 bbl/d for the first
quarter of 2013. The increase in crude oil and NGLs production for
the three and six months ended June 30, 2013 from the comparable
periods in 2012 was primarily due to the impact of a strong heavy
crude oil drilling program. The decrease for the second quarter of
2013 from the first quarter of 2013 was primarily due to the
decrease in production from the Company's cyclic thermal
operations. Second quarter 2013 production of crude oil and NGLs
was within the Company's previously issued guidance of 326,000 to
342,000 bbl/d. Third quarter 2013 production guidance is targeted
to average between 365,000 and 380,000 bbl/d for crude oil and
NGLs.
Natural gas production for the six months ended June 30, 2013
decreased 12% to 1,108 MMcf/d compared with 1,255 MMcf/d for the
six months ended June 30, 2012. Natural gas production decreased
11% to 1,092 MMcf/d for the second quarter of 2013 compared with
1,230 MMcf/d in the second quarter of 2012 and decreased 3% from
1,125 MMcf/d for the first quarter of 2013. The decrease in natural
gas production for the three and six months ended June 30, 2013
from the comparable periods was primarily a result of a strategic
reduction of natural gas drilling as the Company allocated capital
to higher return crude oil projects, as well as expected production
declines.
North America - Oil Sands Mining and Upgrading
Production averaged 88,255 bbl/d for the six months ended June
30, 2013 compared with 80,957 bbl/d for the six months ended June
30, 2012. For the second quarter of 2013, SCO production averaged
67,954 bbl/d compared with 115,823 bbl/d for the second quarter of
2012 and 108,782 bbl/d for the first quarter of 2013. Production
increased for the six months ended June 30, 2013 from the
comparable period due to the unplanned maintenance completed during
the first quarter of 2012. Second quarter 2013 production reflected
the impact of the planned maintenance turnaround. Due to a 6 day
extension of the planned turnaround to 30 days from the 24 days
originally forecasted, SCO production was below the Company's
previously issued guidance of 77,000 to 83,000 bbl/d for the second
quarter of 2013. Third quarter 2013 production guidance is targeted
to average between 110,000 and 115,000 bbl/d. Annual 2013
production guidance remains unchanged and is targeted to average
between 100,000 and 108,000 bbl/d.
North Sea
North Sea crude oil production for the six months ended June 30,
2013 decreased 7% to 18,838 bbl/d from 20,333 bbl/d for the six
months ended June 30, 2012. Second quarter 2013 North Sea crude oil
production increased 7% to 18,901 bbl/d compared with 17,619 bbl/d
for the second quarter of 2012, and was comparable with the first
quarter of 2013. The decrease in production for the six months
ended June 30, 2013 from the comparable period was primarily due to
natural field declines and a reduction in drilling activities as a
result of an increase in the UK corporate income tax rate in 2011.
The increase in production for the second quarter of 2013 from the
second quarter of 2012 was primarily due to higher production from
both the Tiffany and Ninian fields in 2013, as well as the
temporary shut in of the third-party operated pipeline to Sullom
Voe for unplanned maintenance for a portion of 2012, which caused
all Ninian and associated fields to be shut in.
The Company received approval for the Brownfield Allowance for
the Tiffany field in January 2013 and as a result, during the
second quarter the Company drilled one injector well and one
additional production well, which came on at Tiffany with
production of approximately 1,500 bbl/d, exceeding original
forecasted volumes. During the second quarter of 2013, the Company
also completed its consolidation of a working interest in a
satellite field at the Ninian hub.
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. The FPSO and associated
floating storage unit were subsequently removed from the field and
the FPSO is currently undergoing repairs and is targeted to be back
in the field in the first half of 2014. The associated repair
costs, net of insurance recoveries, are not expected to be
significant.
Offshore Africa
Offshore Africa crude oil production decreased 17% to 17,089
bbl/d for the six months ended June 30, 2013 from 20,655 bbl/d for
the six months ended June 30, 2012. Second quarter 2013 crude oil
production averaged 18,055 bbl/d, decreasing 12% from 20,598 bbl/d
for the second quarter of 2012 and increasing 12% from 16,112 bbl/d
for the first quarter of 2013. The decrease in production volumes
for the three and six months ended June 30, 2013 from the
comparable periods in 2012 was due to natural field declines and
lower production from Gabon. The increase in production volumes for
the second quarter of 2013 from the first quarter of 2013 was due
to the stabilization of the midwater arch and the reinstatement of
production at the Olowi field in Gabon late in the first quarter of
2013. The final repairs and assessment have been made and issues
relating to the long-term operability of the midwater arch have
been resolved.
International Guidance
The Company's North Sea and Offshore Africa second quarter 2013
crude oil and NGLs production exceeded the Company's previously
issued guidance of 32,000 to 36,000 bbl/d. Third quarter 2013
production guidance is targeted to average between 31,000 and
34,000 bbl/d of crude oil and NGLs.
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 FPSOs, as follows:
-----------
Jun 30 Mar 31 Dec 31
(bbl) 2013 2013 2012
----------------------------------------------------------------------------
North America - Exploration and Production 691,583 811,181 643,758
North America - Oil Sands Mining and
Upgrading (SCO) 1,061,417 1,334,054 993,627
North Sea 583,227 409,333 77,018
Offshore Africa 811,742 829,793 1,036,509
----------------------------------------------------------------------------
3,147,969 3,384,361 2,750,912
----------------------------------------------------------------------------
----------------------------------------------------------------------------
OPERATING HIGHLIGHTS - EXPLORATION AND PRODUCTION
Three Months Ended Six Months Ended
----------- -----------
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
2013 2013 2012 2013 2012
----------------------------------------------------------------------------
Crude oil and NGLs
($/bbl) (1)
Sales price (2) (3) $ 75.10 $ 60.87 $ 72.12 $ 67.94 $ 77.14
Transportation 2.32 2.37 2.13 2.34 2.19
----------------------------------------------------------------------------
Realized sales price,
net of
transportation 72.78 58.50 69.99 65.60 74.95
Royalties 11.60 8.76 9.18 10.17 11.10
Production expense 16.51 17.56 16.66 17.04 16.72
----------------------------------------------------------------------------
Netback $ 44.67 $ 32.18 $ 44.15 $ 38.39 $ 47.13
----------------------------------------------------------------------------
Natural gas ($/Mcf)
(1)
Sales price (2) (3) $ 4.05 $ 3.51 $ 2.15 $ 3.78 $ 2.44
Transportation 0.29 0.29 0.25 0.29 0.25
----------------------------------------------------------------------------
Realized sales price,
net of
transportation 3.76 3.22 1.90 3.49 2.19
Royalties 0.28 0.12 0.05 0.20 0.05
Production expense 1.41 1.53 1.15 1.48 1.25
----------------------------------------------------------------------------
Netback $ 2.07 $ 1.57 $ 0.70 $ 1.81 $ 0.89
----------------------------------------------------------------------------
Barrels of oil
equivalent ($/BOE)
(1)
Sales price (2) (3) $ 58.49 $ 47.90 $ 51.14 $ 53.16 $ 54.19
Transportation 2.18 2.21 1.97 2.20 2.01
----------------------------------------------------------------------------
Realized sales price,
net of
transportation 56.31 45.69 49.17 50.96 52.18
Royalties 8.29 6.05 5.93 7.16 7.08
Production expense 13.81 14.74 13.06 14.28 13.24
----------------------------------------------------------------------------
Netback $ 34.21 $ 24.90 $ 30.18 $ 29.52 $ 31.86
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts expressed on a per unit basis are based on sales
volumes.
(2) Net of blending costs and excluding risk management
activities.
(3) Comparative figures have been adjusted to reflect realized
product prices before transportation costs.
PRODUCT PRICES - EXPLORATION AND PRODUCTION
Three Months Ended Six Months Ended
----------- -----------
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
2013 2013 2012 2013 2012
----------------------------------------------------------------------------
Crude oil and NGLs
($/bbl) (1)(2) (3)
North America $ 71.81 $ 55.68 $ 67.44 $ 63.66 $ 71.99
North Sea $ 104.47 $ 114.28 $ 109.60 $ 109.05 $ 114.53
Offshore Africa $ 107.71 $ 113.70 $ 106.30 $ 110.70 $ 116.09
Company average $ 75.10 $ 60.87 $ 72.12 $ 67.94 $ 77.14
Natural gas ($/Mcf)
(1)(2) (3)
North America $ 3.90 $ 3.37 $ 1.99 $ 3.63 $ 2.32
North Sea $ 7.03 $ 3.65 $ 5.41 $ 6.15 $ 5.19
Offshore Africa $ 10.02 $ 10.24 $ 10.68 $ 10.13 $ 10.39
Company average $ 4.05 $ 3.51 $ 2.15 $ 3.78 $ 2.44
Company average
($/BOE) (1)(2) (3) $ 58.49 $ 47.90 $ 51.14 $ 53.16 $ 54.19
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts expressed on a per unit basis are based on sales
volumes.
(2) Net of blending costs and excluding risk management
activities.
(3) Comparative figures have been adjusted to reflect realized
product prices before transportation costs.
North America
North America realized crude oil prices decreased 12% to average
$63.66 per bbl for the six months ended June 30, 2013 from $71.99
per bbl for the six months ended June 30, 2012. North America
realized crude oil prices averaged $71.81 per bbl for the second
quarter of 2013, an increase of 6% compared with $67.44 per bbl for
the second quarter of 2012 and an increase of 29% compared with
$55.68 per bbl for the first quarter of 2013. The decrease in
realized crude oil prices for the six months ended June 30, 2013
from the comparable period was due to the widening of the WCS Heavy
Differential, lower WTI benchmark pricing, and higher diluent
blending costs, partially offset by the impact of a weaker Canadian
dollar relative to the US dollar. The increase in realized crude
oil prices for the second quarter of 2013 from the comparable
periods was due to the impact of the tightening of the WCS Heavy
Differential and the weaker Canadian dollar relative to the US
dollar. The Company continues to focus on its crude oil blending
marketing strategy and in the second quarter of 2013 contributed
approximately 172,000 bbl/d of heavy crude oil blends to the WCS
stream.
North America realized natural gas prices increased 56% to
average $3.63 per Mcf for the six months ended June 30, 2013 from
$2.32 per Mcf for the six months ended June 30, 2012. North America
realized natural gas prices increased 96% to average $3.90 per Mcf
for the second quarter of 2013 compared with $1.99 per Mcf in the
second quarter of 2012, and increased 16% compared with $3.37 per
Mcf for the first quarter of 2013. The increase in realized natural
gas prices for the three and six months ended June 30, 2013 from
the comparable periods was primarily due to higher AECO benchmark
pricing related to the impact of a steady North America production
supply forecast and a return to normal winter weather in North
America in 2013, that has allowed natural gas inventories to return
to seasonal levels.
Comparisons of the prices received in North America Exploration
and Production by product type were as follows:
-----------
Jun 30 Mar 31 Jun 30
(Quarterly Average) 2013 2013 2012
----------------------------------------------------------------------------
Wellhead Price(1) (2) (3)
Light and medium crude oil and NGLs ($/bbl) $ 78.15 $ 73.77 $ 71.56
Pelican Lake heavy crude oil ($/bbl) $ 75.17 $ 54.41 $ 66.13
Primary heavy crude oil ($/bbl) $ 71.75 $ 51.45 $ 66.15
Bitumen (thermal oil) ($/bbl) $ 65.99 $ 50.42 $ 66.88
Natural gas ($/Mcf) $ 3.90 $ 3.37 $ 1.99
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts expressed on a per unit basis are based on sales
volumes.
(2) Net of blending costs and excluding risk management
activities.
(3) Comparative figures have been adjusted to reflect realized
product prices before transportation costs.
North Sea
North Sea realized crude oil prices decreased 5% to average
$109.05 per bbl for the six months ended June 30, 2013 from $114.53
per bbl for the six months ended June 30, 2012. Realized crude oil
prices decreased 5% to average $104.47 per bbl for the second
quarter of 2013 from $109.60 per bbl for the second quarter of
2012, and decreased 9% from $114.28 per bbl for the first quarter
of 2013. The fluctuations in realized crude oil prices for the
three and six months ended June 30, 2013 from the comparable
periods reflected movements in Brent benchmark pricing, the timing
of liftings, and the weakening of the Canadian dollar.
Offshore Africa
Offshore Africa realized crude oil prices decreased 5% to
average $110.70 per bbl for the six months ended June 30, 2013 from
$116.09 per bbl for the six months ended June 30, 2012. Realized
crude oil prices increased 1% to average $107.71 per bbl for the
second quarter of 2013 from $106.30 per bbl for the second quarter
of 2012, and decreased 5% from $113.70 per bbl for the first
quarter of 2013. The fluctuations in realized crude oil prices for
the three and six months ended June 30, 2013 from the comparable
periods reflected movements in Brent benchmark pricing, the timing
of liftings, and the weakening of the Canadian dollar.
ROYALTIES - EXPLORATION AND PRODUCTION
Three Months Ended Six Months Ended
----------- -----------
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
2013 2013 2012 2013 2012
----------------------------------------------------------------------------
Crude oil and NGLs
($/bbl) (1)
North America $ 11.81 $ 8.65 $ 8.33 $ 10.21 $ 10.99
North Sea $ 0.34 $ 0.41 $ 0.26 $ 0.37 $ 0.28
Offshore Africa $ 18.38 $ 17.71 $ 28.63 $ 18.05 $ 24.90
Company average $ 11.60 $ 8.76 $ 9.18 $ 10.17 $ 11.10
Natural gas ($/Mcf)
(1)
North America $ 0.25 $ 0.09 $ 0.02 $ 0.17 $ 0.02
Offshore Africa $ 1.68 $ 1.57 $ 1.86 $ 1.63 $ 1.72
Company average $ 0.28 $ 0.12 $ 0.05 $ 0.20 $ 0.05
Company average
($/BOE) (1) $ 8.29 $ 6.05 $ 5.93 $ 7.16 $ 7.08
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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 six
months ended June 30, 2013 compared with the six months ended June
30, 2012 reflected movements in benchmark commodity prices and the
fluctuations of the WCS Heavy Differential.
Crude oil and NGLs royalties averaged approximately 17% of
product sales for the second quarter of 2013 compared with 13% for
the second quarter of 2012 and 16% for the first quarter of 2013.
The increase in royalties from the second quarter of 2012 was
primarily due to the increase in realized crude oil and NGLs
prices. Crude oil and NGLs royalties per bbl are anticipated to
average 16% to 18% of product sales for 2013.
Natural gas royalties averaged approximately 7% of product sales
for the second quarter of 2013 compared with 1% for the second
quarter of 2012 and 3% for the first quarter of 2013. The increase
in natural gas royalty rates from the second quarter of 2012 was
primarily the result of the increase in realized natural gas
prices. The increase from the first quarter of 2013 was primarily
the result of the increase in realized natural gas prices, as well
as gas cost allowance adjustments in the first quarter of 2013.
Natural gas royalties are anticipated to average 4% to 6% of
product sales for 2013.
Offshore Africa
Under the terms of the various Production Sharing Contracts,
royalty rates fluctuate based on realized commodity pricing,
capital and operating costs, the status of payouts, and the timing
of liftings from each field.
Royalty rates as a percentage of product sales averaged
approximately 17% for the second quarter of 2013 compared with 26%
for the second quarter of 2012 and 16% for the first quarter of
2013. The decrease in royalties from the second quarter of 2012 was
due to adjustments to royalties on liftings during 2012.
Offshore Africa royalty rates are anticipated to average 12% to
14% of product sales for 2013.
PRODUCTION EXPENSE - EXPLORATION AND PRODUCTION
Three Months Ended Six Months Ended
----------- -----------
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
2013 2013 2012 2013 2012
----------------------------------------------------------------------------
Crude oil and NGLs
($/bbl) (1)
North America $ 14.83 $ 14.61 $ 13.10 $ 14.72 $ 14.23
North Sea $ 47.85 $ 74.65 $ 68.32 $ 60.38 $ 50.21
Offshore Africa $ 17.98 $ 25.72 $ 22.94 $ 21.84 $ 18.29
Company average $ 16.51 $ 17.56 $ 16.66 $ 17.04 $ 16.72
Natural gas ($/Mcf)
(1)
North America $ 1.38 $ 1.52 $ 1.13 $ 1.45 $ 1.24
North Sea $ 3.53 $ 3.77 $ 3.89 $ 3.59 $ 3.94
Offshore Africa $ 2.34 $ 2.24 $ 1.78 $ 2.30 $ 1.77
Company average $ 1.41 $ 1.53 $ 1.15 $ 1.48 $ 1.25
Company average
($/BOE) (1) $ 13.81 $ 14.74 $ 13.06 $ 14.28 $ 13.24
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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 six
months ended June 30, 2013 increased 3% to $14.72 per bbl from
$14.23 per bbl for the six months ended June 30, 2012. North
America crude oil and NGLs production expense for the second
quarter of 2013 increased 13% to $14.83 per bbl from $13.10 per bbl
for the second quarter of 2012 and increased 2% from $14.61 per bbl
for the first quarter of 2013. The increase in production expense
for the three and six months ended June 30, 2013 from the
comparable periods in 2012 was primarily the result of higher
electricity costs, as well as higher trucking costs related to
extended seasonal conditions in heavy oil production. The increase
in production expense for the second quarter of 2013 from the first
quarter of 2013 was primarily a result of higher electricity costs
and extended spring season conditions. North America crude oil and
NGLs production expense guidance remains unchanged from the
previously issued guidance of $12.00 to $14.00 per bbl for
2013.
North America natural gas production expense for the six months
ended June 30, 2013 increased 17% to $1.45 per Mcf from $1.24 per
Mcf for the six months ended June 30, 2012. North America natural
gas production expense for the second quarter of 2013 increased 22%
to $1.38 per Mcf from $1.13 per Mcf for the second quarter of 2012
and decreased 9% from $1.52 per Mcf for the first quarter of 2013.
Natural gas production expense increased for the three and six
months ended June 30, 2013 from the comparable periods in 2012
primarily due to higher electricity costs along with lower
production volumes related to the reduction in natural gas
activity. Natural gas production expense decreased for the second
quarter of 2013 from the first quarter of 2013 due to normal
seasonality. North America natural gas production expense is
anticipated to average $1.35 to $1.40 per Mcf for 2013.
North Sea
North Sea crude oil production expense for the six months ended
June 30, 2013 increased 20% to $60.38 per bbl from $50.21 per bbl
for the six months ended June 30, 2012. North Sea crude oil
production expense for the second quarter of 2013 decreased 30% to
$47.85 per bbl from $68.32 per bbl for the second quarter of 2012
and decreased 36% from $74.65 per bbl for the first quarter of
2013. Production expense increased on a per barrel basis for the
six months ended June 30, 2013 from the comparable period due to
the impact of production declines on relatively fixed costs as well
as higher maintenance activity and increased fuel costs. Production
expense decreased for the second quarter of 2013 from the
comparable periods due to increased production volumes on
relatively fixed costs and the timing of liftings from various
fields, which have different cost structures. North Sea crude oil
production expense is anticipated to average $62.00 to $66.00 per
bbl for 2013 due to natural declines on a relatively fixed cost
structure.
Offshore Africa
Offshore Africa crude oil production expense for the six months
ended June 30, 2013 increased 19% to $21.84 per bbl from $18.29 per
bbl for the six months ended June 30, 2012. Offshore Africa crude
oil production expense for the second quarter of 2013 averaged
$17.98 per bbl, a decrease of 22% from $22.94 per bbl for the
second quarter of 2012, and a decrease of 30% from $25.72 per bbl
for the first quarter of 2013. Production expense fluctuated for
the three and six months ended June 30, 2013 from the comparable
periods as a result of the timing of liftings from various fields,
which have different cost structures. Offshore Africa crude oil
production expense is anticipated to average $30.00 to $34.00 per
bbl for 2013 due to timing of liftings from various fields, which
have different cost structures.
DEPLETION, DEPRECIATION AND AMORTIZATION - EXPLORATION AND
PRODUCTION
Three Months Ended Six Months Ended
----------- -----------
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
2013 2013 2012 2013 2012
----------------------------------------------------------------------------
Expense ($ millions) $ 1,009 $ 1,023 $ 936 $ 2,032 $ 1,846
$/BOE (1) $ 19.97 $ 19.99 $ 18.13 $ 19.98 $ 17.93
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts expressed on a per unit basis are based on sales
volumes.
Depletion, depreciation and amortization expense increased for
the three and six months ended June 30, 2013 compared with 2012 due
to higher sales volumes in North America associated with heavy oil
drilling and higher overall future development costs. The decrease
in depletion, depreciation and amortization expense for the second
quarter of 2013 from the first quarter of 2013 was primarily due to
lower sales volumes in North America.
ASSET RETIREMENT OBLIGATION ACCRETION - EXPLORATION AND
PRODUCTION
Three Months Ended Six Months Ended
----------- -----------
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
2013 2013 2012 2013 2012
----------------------------------------------------------------------------
Expense ($ millions) $ 33 $ 34 $ 30 $ 67 $ 59
$/BOE (1) $ 0.65 $ 0.66 $ 0.59 $ 0.65 $ 0.58
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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
The Company continues to focus on efficient and effective
operations at Horizon and place emphasis on safe, steady, reliable
operations. In May 2013, the Company successfully completed a
planned maintenance turnaround. During the outage, all major scopes
of work were completed including the change out of the catalysts in
the hydro-treating units. Repairs to certain equipment extended
slightly beyond the original forecasted timeframe. The impact of
the turnaround has been reflected in the Company's 2013 production,
cash production cost and capital expenditure guidance.
PRODUCT PRICES, ROYALTIES AND TRANSPORTATION - OIL SANDS MINING
AND UPGRADING
Three Months Ended Six Months Ended
----------- -----------
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
($/bbl) (1) 2013 2013 2012 2013 2012
----------------------------------------------------------------------------
SCO sales price (2) $ 99.63 $ 96.19 $ 89.76 $ 97.58 $ 93.62
Bitumen value for
royalty purposes (3) $ 61.08 $ 60.47 $ 59.83 $ 60.71 $ 62.10
Bitumen royalties (4) $ 4.41 $ 3.81 $ 5.20 $ 4.05 $ 5.19
Transportation $ 1.72 $ 1.58 $ 1.65 $ 1.64 $ 1.78
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts expressed on a per unit basis are based on sales
volumes excluding the period of turnaround/suspension of
production.
(2) Comparative figures have been adjusted to reflect realized
product prices before transportation costs.
(3) Calculated as the quarterly average of the 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 $97.58 per bbl for the six
months ended June 30, 2013, an increase of 4% compared with $93.62
per bbl for six months ended June 30, 2012. Realized SCO sales
prices averaged $99.63 per bbl for the second quarter of 2013, an
increase of 11% compared with $89.76 per bbl for the second quarter
of 2012 and an increase of 4% compared with $96.19 per bbl for the
first quarter of 2013, reflecting benchmark pricing and prevailing
differentials.
CASH PRODUCTION COSTS - OIL SANDS MINING AND UPGRADING
The following tables are reconciled to the Oil Sands Mining and
Upgrading production costs disclosed in the Company's unaudited
interim consolidated financial statements.
Three Months Ended Six Months Ended
-----------------------------------------------------
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
($ millions) 2013 2013 2012 2013 2012
----------------------------------------------------------------------------
Cash production costs $ 394 $ 377 $ 388 $ 771 $ 734
Less: costs incurred
during the period of
turnaround/suspension
of production (104) - - (104) (154)
----------------------------------------------------------------------------
Adjusted cash
production costs $ 290 $ 377 $ 388 $ 667 $ 580
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Adjusted cash
production costs,
excluding natural gas
costs $ 268 $ 349 $ 362 $ 617 $ 539
Adjusted natural gas
costs 22 28 26 50 41
----------------------------------------------------------------------------
Adjusted cash
production costs $ 290 $ 377 $ 388 $ 667 $ 580
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three Months Ended Six Months Ended
----------- -----------
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
($/bbl) (1) 2013 2013 2012 2013 2012
----------------------------------------------------------------------------
Adjusted cash
production costs,
excluding natural
gas costs $ 41.53 $ 36.95 $ 34.45 $ 38.81 $ 36.79
Adjusted natural gas
costs 3.41 2.98 2.53 3.15 2.82
----------------------------------------------------------------------------
Adjusted cash
production costs $ 44.94 $ 39.93 $ 36.98 $ 41.96 $ 39.61
----------------------------------------------------------------------------
Sales (bbl/d) (2) 70,950 105,000 115,552 87,881 80,646
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Adjusted cash production costs on a per unit basis were
based on sales volumes excluding the period of
turnaround/suspension of production.
(2) Sales volumes include the period of turnaround/suspension of
production.
Adjusted cash production costs averaged $41.96 per bbl for the
six months ended June 30, 2013, an increase of 6% compared with
$39.61 per bbl for the six months ended June 30, 2012. Adjusted
cash production costs for the second quarter of 2013 averaged
$44.94 per bbl, an increase of 22% compared with $36.98 per bbl for
the second quarter of 2012 and an increase of 13% compared with
$39.93 per bbl for the first quarter of 2013 primarily due to lower
production volumes excluding the period of turnaround. Cash
production costs are anticipated to average $38.00 to $41.00 per
bbl for 2013.
DEPLETION, DEPRECIATION AND AMORTIZATION - OIL SANDS MINING AND
UPGRADING
Three Months Ended Six Months Ended
-----------------------------------------------------
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
($ millions) 2013 2013 2012 2013 2012
----------------------------------------------------------------------------
Depletion,
depreciation and
amortization $ 161 $ 117 $ 146 $ 278 $ 209
Less: depreciation
incurred during the
period of
turnaround/suspension
of production (79) - - (79) (6)
----------------------------------------------------------------------------
Adjusted depletion,
depreciation and
amortization $ 82 $ 117 $ 146 $ 199 $ 203
----------------------------------------------------------------------------
$/bbl (1) $ 12.70 $ 12.35 $ 13.84 $ 12.49 $ 13.83
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts expressed on a per unit basis are based on sales
volumes excluding the period of turnaround/suspension of
production.
Depletion, depreciation and amortization expense reflected the
impact of fluctuations in sales volumes.
ASSET RETIREMENT OBLIGATION ACCRETION - OIL SANDS MINING AND
UPGRADING
Three Months Ended Six Months Ended
----------- -----------
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
($ millions) 2013 2013 2012 2013 2012
----------------------------------------------------------------------------
Expense $ 9 $ 8 $ 8 $ 17 $ 16
$/bbl (1) $ 1.32 $ 0.90 $ 0.76 $ 1.07 $ 1.08
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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 Six Months Ended
----------- -----------
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
($ millions) 2013 2013 2012 2013 2012
----------------------------------------------------------------------------
Revenue $ 29 $ 27 $ 22 $ 56 $ 43
Production expense 9 8 7 17 14
----------------------------------------------------------------------------
Midstream cash flow 20 19 15 39 29
Depreciation 2 2 2 4 4
Equity loss from
jointly controlled
entity - 2 5 2 5
----------------------------------------------------------------------------
Segment earnings
before taxes $ 18 $ 15 $ 8 $ 33 $ 20
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Midstream operating results were consistent with the comparable
periods.
The Company has a 50% interest in the North West Redwater
Partnership ("Redwater"). Redwater has entered into agreements to
construct and operate a 50,000 barrel per day bitumen upgrader and
refinery (the "Project") under processing agreements that target to
process 12,500 barrels per day of bitumen feedstock for the Company
and 37,500 barrels per day of bitumen feedstock for the Alberta
Petroleum Marketing Commission, an agent of the Government of
Alberta, under a 30 year fee-for-service tolling agreement. During
2012, the Project received board sanction from Redwater and its
partners.
ADMINISTRATION EXPENSE
Three Months Ended Six Months Ended
------------ ------------
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
($ millions) 2013 2013 2012 2013 2012
----------------------------------------------------------------------------
Expense $ 81 $ 79 $ 77 $ 160 $ 142
$/BOE (1) $ 1.43 $ 1.30 $ 1.24 $ 1.36 $ 1.20
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts expressed on a per unit basis are based on sales
volumes.
Administration expense for the three and six months ended June
30, 2013 increased from the comparable periods primarily due to
higher staffing related costs and general corporate costs.
SHARE-BASED COMPENSATION
Three Months Ended Six Months Ended
------------ ------------
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
($ millions) 2013 2013 2012 2013 2012
----------------------------------------------------------------------------
(Recovery)
expense $ (49) $ 71 $ (115) $ 22 $ (222)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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 $22 million share-based compensation
expense for the six months ended June 30, 2013, primarily as a
result of remeasurement of the fair value of outstanding stock
options at the end of the period related to an increase in the
Company's share price, together with the impact of 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 six months ended June 30, 2013, the Company
capitalized $5 million in respect of share-based compensation
expense to Oil Sands Mining and Upgrading (June 30, 2012 - $15
million recovery).
For the six months ended June 30, 2013, the Company paid $1
million for stock options surrendered for cash settlement (June 30,
2012 - $7 million).
INTEREST AND OTHER FINANCING COSTS
Three Months Ended Six Months Ended
------------ -- ------------
($ millions,
except per BOE Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
amounts) 2013 2013 2012 2013 2012
----------------------------------------------------------------------------
Expense, gross $ 112 $ 113 $ 114 $ 225 $ 228
Less:
capitalized
interest 40 36 21 76 39
----------------------------------------------------------------------------
Expense, net $ 72 $ 77 $ 93 $ 149 $ 189
$/BOE (1) $ 1.26 $ 1.27 $ 1.50 $ 1.27 $ 1.61
Average
effective
interest rate 4.3% 4.5% 4.8% 4.4% 4.8%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts expressed on a per unit basis are based on sales
volumes.
Gross interest and other financing costs for the three and six
months ended June 30, 2013 were consistent with the comparable
periods. Capitalized interest of $76 million for the six months
ended June 30, 2013 was related to the Horizon Phase 2/3 expansion
and the Kirby Thermal Oil Sands Project, which includes the Kirby
South Project.
The Company's average effective interest rate for the three and
six months ended June 30, 2013 decreased from the comparable
periods in 2012 primarily due to the repayment of $400 million of
4.50% medium-term notes and US$400 million of 5.15% unsecured notes
during the first quarter of 2013 and US$350 million of 5.45%
unsecured notes in the fourth quarter of 2012. This indebtedness
was retired utilizing cash flow from operations generated in excess
of capital expenditures and available bank credit facilities, while
maintaining the ongoing dividend program. The Company's average
effective interest rate for the second quarter of 2013 decreased
from the first quarter of 2013 primarily due to an increase in the
utilization of the US commercial paper program during the second
quarter of 2013.
RISK MANAGEMENT ACTIVITIES
The Company utilizes various derivative financial instruments to
manage its commodity price, foreign currency and interest rate
exposures. These derivative financial instruments are not intended
for trading or speculative purposes.
Three Months Ended Six Months Ended
------------ ------------
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
($ millions) 2013 2013 2012 2013 2012
----------------------------------------------------------------------------
Crude oil and
NGLs financial
instruments $ - $ - $ 19 $ - $ 28
Foreign currency
contracts (19) (83) (80) (102) 5
----------------------------------------------------------------------------
Realized (gain)
loss (19) (83) (61) (102) 33
----------------------------------------------------------------------------
Crude oil and
NGLs financial
instruments (54) 24 (180) (30) (84)
Foreign currency
contracts (60) 38 36 (22) -
----------------------------------------------------------------------------
Unrealized
(gain) loss (114) 62 (144) (52) (84)
----------------------------------------------------------------------------
Net gain $ (133) $ (21) $ (205) $ (154) $ (51)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Complete details related to outstanding derivative financial
instruments at June 30, 2013 are disclosed in note 13 to the
Company's unaudited interim consolidated financial statements.
The Company recorded a net unrealized gain of $52 million ($41
million after-tax) on its risk management activities for the six
months ended June 30, 2013, including an unrealized gain of $114
million ($92 million after-tax) for the second quarter of 2013
(March 31, 2013 - unrealized loss of $62 million; $51 million
after-tax; June 30, 2012 - unrealized gain of $144 million; $103
million after-tax).
FOREIGN EXCHANGE
Three Months Ended Six Months Ended
----------- ------------
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
($ millions) 2013 2013 2012 2013 2012
----------------------------------------------------------------------------
Net realized loss
(gain) $ 1 $ (32) $ (9) $ (31) $ (3)
Net unrealized
loss (1) 112 78 71 190 11
----------------------------------------------------------------------------
Net loss $ 113 $ 46 $ 62 $ 159 $ 8
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts are reported net of the hedging effect of cross
currency swaps.
The net realized foreign exchange gain for the six months ended
June 30, 2013 was primarily due to foreign exchange rate
fluctuations on settlement of working capital items denominated in
US dollars or UK pounds sterling and the repayment of US$400
million of 5.15% unsecured notes in the first quarter of 2013. The
net unrealized foreign exchange loss for the six months ended June
30, 2013 was primarily related to the impact of the weakening of
the Canadian dollar with respect to remaining US dollar debt and
the reversal of the life-to-date unrealized foreign exchange gain
on the repayment of US$400 million of 5.15% unsecured notes in the
first quarter of 2013. The net unrealized (gain) loss for each of
the periods presented included the impact of cross currency swaps
(three months ended June 30, 2013 - unrealized gain of $86 million,
March 31, 2013 - unrealized gain of $49 million, June 30, 2012 -
unrealized gain of $47 million; six months ended June 30, 2013 -
unrealized gain of $135 million; June 30, 2012 - unrealized gain of
$5 million). The US/Canadian dollar exchange rate ended the second
quarter of 2013 at US$0.9513 (March 31, 2013 - US$0.9846; December
31, 2012 - US$1.0051; June 30, 2012 - US$0.9813).
INCOME TAXES
Three Months Ended Six Months Ended
------------ ------------
($ millions,
except income Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
tax rates) 2013 2013 2012 2013 2012
----------------------------------------------------------------------------
North America
(1) $ 111 $ 122 $ 124 $ 233 $ 237
North Sea 25 (7) 19 18 64
Offshore Africa 36 35 64 71 100
PRT (recovery)
expense - North
Sea (33) (13) 1 (46) 32
Other taxes 6 4 5 10 11
----------------------------------------------------------------------------
Current income
tax expense 145 141 213 286 444
----------------------------------------------------------------------------
Deferred income
tax expense
(recovery) 44 (4) 59 40 11
Deferred PRT
(recovery)
expense - North
Sea (13) (23) 3 (36) (1)
----------------------------------------------------------------------------
Deferred income
tax expense
(recovery) 31 (27) 62 4 10
----------------------------------------------------------------------------
176 114 275 290 454
Income tax rate
and other
legislative
changes (15) - - (15) -
----------------------------------------------------------------------------
$ 161 $ 114 $ 275 $ 275 $ 454
----------------------------------------------------------------------------
Effective income
tax rate on
adjusted net
earnings from
operations (2) 27.9% 28.1% 27.1% 28.0% 30.1%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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.
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.
During the second quarter of 2013, the government of British
Columbia substantively enacted legislation to increase its
provincial corporate income tax rate effective April 1, 2013. As a
result of the income tax rate change, the Company's deferred income
tax liability was increased by $15 million.
For 2013, based on budgeted prices and the current availability
of tax pools, the Company expects to incur current income tax
expense of $600 million to $700 million in Canada and $40 million
to $100 million in the North Sea and Offshore Africa.
NET CAPITAL EXPENDITURES (1)
Three Months Ended Six Months Ended
----------- -----------
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
($ millions) 2013 2013 2012 2013 2012
-----------------------------------------------------------------------
Exploration and
Evaluation
Net expenditures $ 10 $ 77 $ 32 $ 87 $ 240
-----------------------------------------------------------------------
Property, Plant
and Equipment
Net property
acquisitions - 11 7 11 45
Well drilling,
completion and
equipping 419 555 352 974 851
Production and
related
facilities 466 537 445 1,003 950
Capitalized
interest and
other (2) 29 28 30 57 60
-----------------------------------------------------------------------
Net expenditures 914 1,131 834 2,045 1,906
-----------------------------------------------------------------------
Total
Exploration and
Production 924 1,208 866 2,132 2,146
-----------------------------------------------------------------------
Oil Sands Mining
and Upgrading
Horizon Phases
2/3
construction
costs 555 355 346 910 538
Sustaining
capital 158 51 51 209 88
Turnaround costs 80 17 3 97 5
Capitalized
interest and
other (2) 22 38 5 60 8
-----------------------------------------------------------------------
Total Oil Sands
Mining and
Upgrading 815 461 405 1,276 639
-----------------------------------------------------------------------
Midstream 4 5 4 9 5
Abandonments (3) 37 55 39 92 115
Head office 12 7 10 19 15
-----------------------------------------------------------------------
Total net
capital
expenditures $ 1,792 $ 1,736 $ 1,324 $ 3,528 $ 2,920
-----------------------------------------------------------------------
-----------------------------------------------------------------------
By segment
North America $ 826 $ 1,093 $ 788 $ 1,919 $ 2,011
North Sea 62 85 66 147 120
Offshore Africa 36 30 12 66 15
Oil Sands Mining
and Upgrading 815 461 405 1,276 639
Midstream 4 5 4 9 5
Abandonments (3) 37 55 39 92 115
Head office 12 7 10 19 15
-----------------------------------------------------------------------
Total $ 1,792 $ 1,736 $ 1,324 $ 3,528 $ 2,920
-----------------------------------------------------------------------
-----------------------------------------------------------------------
(1) 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) 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 six months ended June 30, 2013
were $3,528 million compared with $2,920 million for the six months
ended June 30, 2012. Net capital expenditures for the second
quarter of 2013 were $1,792 million compared with $1,324 million
for the second quarter of 2012 and $1,736 million for the first
quarter of 2013.
The increase in capital expenditures for the three and six
months ended June 30, 2013 from the comparable periods was
primarily due to the ramp up of Horizon site construction activity
and the increase in Horizon turnaround and sustaining capital costs
resulting from the planned maintenance turnaround in May 2013.
Subsequent to June 30, 2013, the Company acquired all of the
issued and outstanding common shares of Barrick Energy Inc. ("BEI")
for total cash consideration of approximately $173 million. BEI's
assets include working interests in producing crude oil and natural
gas properties and undeveloped land.
Drilling Activity (number of wells)
Three Months Ended Six Months Ended
----------- -----------
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
2013 2013 2012 2013 2012
----------------------------------------------------------------------------
Net successful
natural gas wells 8 15 4 23 23
Net successful crude
oil wells (1) 159 300 266 459 544
Dry wells 5 5 2 10 8
Stratigraphic test /
service wells 16 305 5 321 589
----------------------------------------------------------------------------
Total 188 625 277 813 1,164
Success rate
(excluding
stratigraphic test /
service wells) 97% 98% 99% 98% 99%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Includes bitumen wells.
North America
North America, excluding Oil Sands Mining and Upgrading,
accounted for approximately 57% of the total capital expenditures
for the six months ended June 30, 2013 compared with approximately
73% for the six months ended June 30, 2012.
During the second quarter of 2013, the Company targeted 8 net
natural gas wells, including 6 wells in Northeast British Columbia
and 2 wells in Northwest Alberta. The Company also targeted 163 net
crude oil wells. The majority of these wells were concentrated in
the Company's Northern Plains region where 121 primary heavy crude
oil wells, 10 Pelican Lake heavy crude oil wells, and 27 bitumen
(thermal oil) wells were drilled. Another 5 wells targeting light
crude oil were drilled outside the Northern Plains region.
Overall Primrose thermal production for the second quarter of
2013 averaged approximately 90,000 bbl/d compared with
approximately 94,000 bbl/d for the second quarter of 2012 and
approximately 109,000 bbl/d for the first quarter of 2013.
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 late 2013.
In the second quarter of 2013, the Company discovered bitumen
emulsion at surface in areas of the Primrose field. The Company's
view is that the cause of the occurrence is mechanical in nature
and is working collaboratively with the regulators in the
investigation and remediation plans. To minimize the risk of any
future occurrences while the investigation is being conducted,
adjustments were immediately made to the current steaming strategy
and monitoring programs. The Company does not currently expect a
change in thermal in situ 2013 annual production guidance.
The next planned phase of the Company's in situ Oil Sands assets
expansion is the Kirby South Project. As at June 30, 2013, the
overall project was 98% complete, drilling was complete on all
seven pads, and first steam is targeted for the third quarter of
2013.
Development of the tertiary recovery conversion projects at
Pelican Lake continued and 10 horizontal wells were drilled during
the second quarter of 2013. Pelican Lake production averaged
approximately 42,000 bbl/d for the second quarter of 2013 compared
with 37,000 bbl/d for the second quarter of 2012 and 38,000 bbl/d
for the first quarter of 2013. The new 20,000 bbl/d battery was
completed in mid-May, alleviating the previous facility constraints
at Pelican Lake and Woodenhouse. Field production is currently
being optimized at both Woodenhouse and Pelican Lake.
For the third quarter of 2013, the Company's overall planned
drilling activity in North America is expected to be 297 net crude
oil wells, 47 net bitumen wells and 9 net natural gas wells,
excluding stratigraphic and service wells.
Oil Sands Mining and Upgrading
Phase 2/3 expansion activity in the second quarter of 2013 was
focused on field construction of the gas recovery unit, sulphur
recovery unit, butane treatment unit, coker expansion, tank farms,
tailings, hydrotransport and extraction trains 3 and 4, along with
engineering related to the froth treatment plants, hydrogen unit,
hydrotreater 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 and the FPSO is currently undergoing repairs and is
targeted to be back in the field in the first half of 2014. The
associated repair costs, net of insurance recoveries, are not
expected to be significant.
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 received approval for the Brownfield Allowance for the
Tiffany field in January 2013 and as a result, has commenced
drilling additional production wells. During the second quarter of
2013, the Company drilled one injector well and one additional
production well which came on at Tiffany, with production of
approximately 1,500 bbl/d, exceeding original forecasted volumes.
In May 2013, the Company received approval for the Ninian field
Brownfield Allowance and will commence drilling the second platform
in the third quarter of 2013.
During the second quarter of 2013, the Company also completed
its consolidation of a working interest in a satellite field at the
Ninian hub.
The Company currently plans to decommission the Murchison
platform in the North Sea commencing in 2014 and estimates the
decommissioning efforts will continue for approximately 5
years.
Offshore Africa
During the fourth quarter of 2011, the Company sanctioned an 8
well drilling program at the Espoir field in Cote d'Ivoire. Due to
ongoing operational and safety issues with the drilling contractor,
the drilling rig currently on site is being de-mobilized and the
Company is assessing its drilling options at Espoir.
The midwater arch at the Olowi field in Gabon was stabilized and
production was reinstated in late March 2013. The final repairs and
assessment have been made and issues relating to the long-term
operability of the midwater arch have been resolved.
LIQUIDITY AND CAPITAL RESOURCES
-------------
($ millions, except Jun 30 Mar 31 Dec 31 Jun 30
ratios) 2013 2013 2012 2012
----------------------------------------------------------------------------
Working capital deficit
(1) $ 948 $ 1,178 $ 1,264 $ (732)
Long-term debt (2) (3) $ 10,033 $ 9,322 $ 8,736 $ 8,522
Share capital $ 3,736 $ 3,742 $ 3,709 $ 3,670
Retained earnings 20,748 20,564 20,516 20,193
Accumulated other
comprehensive income 67 68 58 59
----------------------------------------------------------------------------
Shareholders' equity $ 24,551 $ 24,374 $ 24,283 $ 23,922
Debt to book
capitalization (3) (4) 29% 28% 26% 26%
Debt to market
capitalization (3) (5) 24% 21% 22% 22%
After-tax return on
average common
shareholders' equity
(6) 6% 7% 8% 12%
After-tax return on
average capital
employed (3) (7) 5% 6% 7% 10%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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 June 30, 2013, 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,
2012 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.
The Company established a US commercial paper program in the
first quarter of 2013. Borrowings of up to a maximum US$1,500
million are authorized. The Company reserves capacity under its
bank credit facilities for amounts outstanding under this
program.
At June 30, 2013, the Company had $2,384 million of available
credit under its bank credit facilities, net of commercial paper
issuances of $263 million.
During the first quarter of 2013, the Company repaid $400
million of 4.50% medium-term notes and US$400 million of 5.15%
unsecured notes. The Company retired this indebtedness utilizing
cash flow from operations generated in excess of capital
expenditures and available bank credit facilities, while
maintaining the ongoing dividend program.
During the second quarter of 2013, the $3,000 million revolving
syndicated credit facility was extended to June 2017. Additionally,
the Company issued $500 million of 2.89% medium-term notes due
August 2020. Proceeds from the securities issued were used to repay
bank indebtedness and for general corporate purposes. After issuing
these securities, the Company has $2,000 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.
Long-term debt was $10,033 million at June 30, 2013, resulting
in a debt to book capitalization ratio of 29% (March 31, 2013 -
28%; December 31, 2012 - 26%; June 30, 2012 - 26%). This ratio is
within the 25% 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 2013 and 2014 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 June 30, 2013 are discussed in note 6
to the Company's unaudited interim consolidated financial
statements.
The Company's commodity hedge policy reduces the risk of
volatility in commodity prices and supports the Company's cash flow
for its capital expenditure 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 August 7,
2013, approximately 58% of currently forecasted 2013 crude oil
volumes were hedged using price collars and physical crude oil
sales contracts with fixed WCS differentials. Further details
related to the Company's commodity related derivative financial
instruments outstanding at June 30, 2013 are discussed in note 13
to the Company's unaudited interim consolidated financial
statements.
Share Capital
As at June 30, 2013, there were 1,086,969,000 common shares
outstanding (June 30, 2012 - 1,096,497,000 common shares) and
67,463,000 stock options outstanding. As at August 6, 2013, the
Company had 1,087,477,000 common shares outstanding and 66,328,000
stock options outstanding.
On March 6, 2013, the Company's Board of Directors approved an
increase in the annual dividend to be paid by the Company to $0.50
per common share for 2013. The increase represents an approximately
19% increase from 2012, recognizing the stability of the Company's
cash flow and providing a return to shareholders. The dividend
policy undergoes periodic review by the Board of Directors and is
subject to change.
In April 2013, 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 2013 and ending April 2014, up to
54,635,116 common shares. The Company's Normal Course Issuer Bid
announced in 2012 expired April 2013.
For the six months ended June 30, 2013, the Company purchased
6,707,500 common shares at a weighted average price of $30.86 per
common share, for a total cost of $207 million. Retained earnings
were reduced by $184 million, representing the excess of the
purchase price of common shares over their average carrying value.
Subsequent to June 30, 2013, the Company purchased 230,000 common
shares at a weighted average price of $30.98 per common share for a
total cost of $7 million.
COMMITMENTS AND OFF BALANCE SHEET ARRANGEMENTS
In the normal course of business, the Company has entered into
various commitments that will have an impact on the Company's
future operations. The following table summarizes the Company's
commitments as at June 30, 2013:
Remaining
($ millions) 2013 2014 2015 2016 2017 Thereafter
----------------------------------------------------------------------------
Product
transportation
and pipeline $ 117 $ 225 $ 209 $ 138 $ 118 $ 795
Offshore
equipment
operating leases $ 65 $ 128 $ 110 $ 80 $ 60 $ 71
Long-term debt
(1) $ 263 $ 894 $ 400 $ 830 $ 2,551 $ 5,153
Interest and
other financing
costs (2) $ 226 $ 452 $ 417 $ 400 $ 328 $ 4,026
Office leases $ 16 $ 34 $ 32 $ 33 $ 35 $ 262
Other $ 97 $ 99 $ 86 $ 15 $ 2 $ 6
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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 June 30, 2013.
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.
CHANGES IN ACCOUNTING POLICIES
For the impact of new accounting standards, refer to the
unaudited interim consolidated financial statements for the six
months ended June 30, 2013.
CRITICAL ACCOUNTING ESTIMATES
The preparation of financial statements requires the Company to
make estimates, assumptions and judgments 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 critical accounting estimates is
contained in the MD&A and the audited consolidated financial
statements for the year ended December 31, 2012.
CONSOLIDATED BALANCE SHEETS
------------
As at Jun 30 Dec 31
(millions of Canadian dollars, unaudited) Note 2013 2012
----------------------------------------------------------------------------
ASSETS
Current assets
Cash and cash equivalents $ 17 $ 37
Accounts receivable 1,614 1,197
Inventory 656 554
Prepaids and other 213 126
Current portion of other long-term assets 5 35 -
----------------------------------------------------------------------------
2,535 1,914
Exploration and evaluation assets 3 2,655 2,611
Property, plant and equipment 4 45,251 44,028
Other long-term assets 5 369 427
----------------------------------------------------------------------------
$ 50,810 $ 48,980
----------------------------------------------------------------------------
----------------------------------------------------------------------------
LIABILITIES
Current liabilities
Accounts payable $ 667 $ 465
Accrued liabilities 2,451 2,273
Current income tax liabilities 212 285
Current portion of long-term debt 6 263 798
Current portion of other long-term
liabilities 7 153 155
----------------------------------------------------------------------------
3,746 3,976
Long-term debt 6 9,770 7,938
Other long-term liabilities 7 4,513 4,609
Deferred income tax liabilities 8,230 8,174
----------------------------------------------------------------------------
26,259 24,697
----------------------------------------------------------------------------
SHAREHOLDERS' EQUITY
Share capital 9 3,736 3,709
Retained earnings 20,748 20,516
Accumulated other comprehensive income 10 67 58
----------------------------------------------------------------------------
24,551 24,283
----------------------------------------------------------------------------
$ 50,810 $ 48,980
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Commitments and contingencies (note 14).
Approved by the Board of Directors on August 7, 2013
CONSOLIDATED STATEMENTS OF EARNINGS
Three Months Ended Six Months Ended
------------ ------------
(millions of
Canadian dollars,
except per common
share amounts, Jun 30 Jun 30 Jun 30 Jun 30
unaudited) Note 2013 2012 2013 2012
----------------------------------------------------------------------------
Product sales $ 4,230 $ 4,187 $ 8,331 $ 8,158
Less: royalties (446) (361) (792) (805)
----------------------------------------------------------------------------
Revenue 3,784 3,826 7,539 7,353
----------------------------------------------------------------------------
Expenses
Production 1,096 1,068 2,231 2,106
Transportation and
blending 738 691 1,593 1,408
Depletion,
depreciation and
amortization 4 1,172 1,084 2,314 2,059
Administration 81 77 160 142
Share-based
compensation 7 (49) (115) 22 (222)
Asset retirement
obligation
accretion 7 42 38 84 75
Interest and other
financing costs 72 93 149 189
Risk management
activities 13 (133) (205) (154) (51)
Foreign exchange
loss 113 62 159 8
Equity loss from
jointly controlled
entity 5 - 5 2 5
----------------------------------------------------------------------------
3,132 2,798 6,560 5,719
----------------------------------------------------------------------------
Earnings before
taxes 652 1,028 979 1,634
Current income tax
expense 8 145 213 286 444
Deferred income tax
expense 8 31 62 4 10
----------------------------------------------------------------------------
Net earnings $ 476 $ 753 $ 689 $ 1,180
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net earnings per
common share
Basic 12 $ 0.44 $ 0.68 $ 0.63 $ 1.07
Diluted 12 $ 0.44 $ 0.68 $ 0.63 $ 1.07
----------------------------------------------------------------------------
----------------------------------------------------------------------------
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Three Months Ended Six Months Ended
------------------------- -------------------------
(millions of Canadian Jun 30 Jun 30 Jun 30 Jun 30
dollars, unaudited) 2013 2012 2013 2012
----------------------------------------------------------------------------
Net earnings $ 476 $ 753 $ 689 $ 1,180
----------------------------------------------------------------------------
Items that may be
reclassified
subsequently to net
earnings
Net change in
derivative financial
instruments designated
as cash flow hedges
Unrealized income
during the period,
net of taxes of
$1 million (2012 - $1
million) - three
months ended;
$3 million (2012 - $5
million) - six months
ended 6 10 22 34
Reclassification to
net earnings, net of
taxes of
$nil (2012 - $nil) -
three months ended;
$nil (2012 - $nil) -
six months ended (1) (2) (2) (1)
----------------------------------------------------------------------------
5 8 20 33
Foreign currency
translation adjustment
Translation of net
investment (6) (8) (11) -
----------------------------------------------------------------------------
Other comprehensive
(loss) income, net of
taxes (1) - 9 33
----------------------------------------------------------------------------
Comprehensive income $ 475 $ 753 $ 698 $ 1,213
----------------------------------------------------------------------------
----------------------------------------------------------------------------
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
Six Months Ended
-------------
(millions of Canadian dollars, Jun 30 Jun 30
unaudited) Note 2013 2012
----------------------------------------------------------------------------
Share capital 9
Balance - beginning of period $ 3,709 $ 3,507
Issued upon exercise of stock options 39 140
Previously recognized liability on stock
options exercised for common shares 11 39
Purchase of common shares under Normal
Course Issuer Bid (23) (16)
----------------------------------------------------------------------------
Balance - end of period 3,736 3,670
----------------------------------------------------------------------------
Retained earnings
Balance - beginning of period 20,516 19,365
Net earnings 689 1,180
Purchase of common shares under Normal
Course Issuer Bid 9 (184) (121)
Dividends on common shares 9 (273) (231)
----------------------------------------------------------------------------
Balance - end of period 20,748 20,193
----------------------------------------------------------------------------
Accumulated other comprehensive income 10
Balance - beginning of period 58 26
Other comprehensive income, net of taxes 9 33
----------------------------------------------------------------------------
Balance - end of period 67 59
----------------------------------------------------------------------------
Shareholders' equity $ 24,551 $ 23,922
----------------------------------------------------------------------------
----------------------------------------------------------------------------
CONSOLIDATED STATEMENTS OF CASH FLOWS
Three Months Ended Six Months Ended
------------ ------------
(millions of
Canadian dollars, Jun 30 Jun 30 Jun 30 Jun 30
unaudited) Note 2013 2012 2013 2012
----------------------------------------------------------------------------
Operating
activities
Net earnings $ 476 $ 753 $ 689 $ 1,180
Non-cash items
Depletion,
depreciation and
amortization 1,172 1,084 2,314 2,059
Share-based
compensation (49) (115) 22 (222)
Asset retirement
obligation
accretion 42 38 84 75
Unrealized risk
management gain (114) (144) (52) (84)
Unrealized foreign
exchange loss 112 71 190 11
Realized foreign
exchange gain on
repayment of US
dollar debt
securities - - (12) -
Equity loss from
jointly
controlled entity - 5 2 5
Deferred income
tax expense 31 62 4 10
Other 18 17 56 40
Abandonment
expenditures (37) (39) (92) (115)
Net change in non-
cash working
capital 87 (117) (302) 113
----------------------------------------------------------------------------
1,738 1,615 2,903 3,072
----------------------------------------------------------------------------
Financing
activities
(Repayment) issue
of bank credit
facilities and
commercial paper,
net (5) (352) 1,251 (559)
Issue of medium-
term notes, net 6 498 498 98 498
Repayment of US
dollar debt
securities - - (398) -
Issue of common
shares on exercise
of stock options 9 9 39 140
Purchase of common
shares under
Normal Course
Issuer Bid (175) (114) (207) (137)
Dividends on common
shares (136) (115) (251) (214)
Net change in non-
cash working
capital (5) (13) (11) (16)
----------------------------------------------------------------------------
186 (87) 521 (288)
----------------------------------------------------------------------------
Investing
activities
Expenditures on
exploration and
evaluation assets
and property,
plant and
equipment (1,755) (1,285) (3,436) (2,805)
Investment in other
long-term assets - 2 - 2
Net change in non-
cash working
capital (170) (248) (8) (5)
----------------------------------------------------------------------------
(1,925) (1,531) (3,444) (2,808)
----------------------------------------------------------------------------
Decrease in cash
and cash
equivalents (1) (3) (20) (24)
Cash and cash
equivalents -
beginning of
period 18 13 37 34
----------------------------------------------------------------------------
Cash and cash
equivalents - end
of period $ 17 $ 10 $ 17 $ 10
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Interest paid $ 97 $ 93 $ 239 $ 226
Income taxes paid $ 71 $ 170 $ 284 $ 435
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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, an electricity
co-generation system and an investment in the North West Redwater
Partnership ("Redwater").
The Company was incorporated in Alberta, Canada. The address of
its registered office is 2500, 855-2 Street S.W., Calgary, Alberta,
Canada.
These interim consolidated financial statements and the related
notes have been prepared in accordance with International Financial
Reporting Standards ("IFRS") as issued by the International
Accounting Standards Board ("IASB"), 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, 2012, except as
discussed in note 2. 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, 2012.
2. CHANGES IN ACCOUNTING POLICIES
Effective January 1, 2013, the Company adopted the following new
accounting standards issued by the IASB:
(a) - IFRS 10 "Consolidated Financial Statements" replaced IAS
27 "Consolidated and Separate Financial Statements" (IAS 27 still
contains guidance for Separate Financial Statements) and Standing
Interpretations Committee ("SIC") 12 "Consolidation - Special
Purpose Entities". IFRS 10 establishes the principles for the
presentation and preparation of consolidated financial statements.
The standard defines the principle of control and establishes
control as the basis for consolidation, as well as providing
guidance on applying the control principle to determine whether an
investor controls an investee.
- IFRS 11 "Joint Arrangements" replaced IAS 31 "Interests in
Joint Ventures" and SIC 13 "Jointly Controlled Entities -
Non-Monetary Contributions by Venturers". The new standard defines
two types of joint arrangements, joint operations and joint
ventures. In a joint operation, the parties with joint control have
rights to the assets and obligations for the liabilities of the
joint arrangement and are required to recognize their proportionate
interest in the assets, liabilities, revenues and expenses of the
joint arrangement. In a joint venture, the parties have an interest
in the net assets of the arrangement and are required to apply the
equity method of accounting.
- IFRS 12 "Disclosure of Interests in Other Entities". The
standard includes disclosure requirements for investments in
subsidiaries, joint arrangements, associates and unconsolidated
structured entities.
- The Company adopted these standards retrospectively.
(b) IFRS 13 "Fair Value Measurement" provides guidance on
applying fair value where its use is already required or permitted
by other standards within IFRS. The standard includes a definition
of fair value and a single source of fair value measurement and
disclosure requirements for use across all IFRSs that require or
permit the use of fair value. IFRS 13 was adopted prospectively. As
a result of adoption of this standard, the Company has included its
own credit risk in measuring the carrying amount of a risk
management liability.
(c) Amendments to IAS 1 "Presentation of Financial Statements"
require items of other comprehensive income that may be
reclassified to net earnings to be grouped together. The amendments
also require that items in other comprehensive income and net
earnings be presented as either a single statement or two
consecutive statements. Adoption of this amended standard impacted
presentation only.
(d) IFRS Interpretation Committee ("IFRIC") 20 "Stripping Costs
in the Production Phase of a Surface Mine" requires overburden
removal costs during the production phase to be capitalized and
depreciated if the Company can demonstrate that probable future
economic benefits will be realized, the costs can be reliably
measured, and the Company can identify the component of the ore
body for which access has been improved.
Adoption of these standards did not have a material impact on
the Company's consolidated financial statements.
3. EXPLORATION AND EVALUATION ASSETS
Oil Sands
Mining and
Exploration and Production Upgrading Total
----------------------------------------------------------------------------
North Offshore
America North Sea Africa
----------------------------------------------------------------------------
Cost
At December
31, 2012 $ 2,564 $ - $ 47 $ - $ 2,611
Additions 80 - 7 - 87
Transfers to
property,
plant and
equipment (45) - - - (45)
Foreign
exchange
adjustments - - 2 - 2
----------------------------------------------------------------------------
At June 30,
2013 $ 2,599 $ - $ 56 $ - $ 2,655
----------------------------------------------------------------------------
----------------------------------------------------------------------------
4. PROPERTY, PLANT AND EQUIPMENT
Oil Sands
Mining and
Exploration and Production Upgrading
----------------------------------------------------------------------------
North Offshore
America North Sea Africa
----------------------------------------------------------------------------
Cost
At December 31, 2012 $ 50,324 $ 4,574 $ 3,045 $ 16,963
Additions 1,846 147 59 1,276
Transfers from E&E assets 45 - - -
Disposals/derecognitions (100) - - (317)
Foreign exchange
adjustments and other - 267 176 -
----------------------------------------------------------------------------
At June 30, 2013 $ 52,115 $ 4,988 $ 3,280 $ 17,922
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Accumulated depletion and depreciation
At December 31, 2012 $ 24,991 $ 2,709 $ 2,273 $ 1,202
Expense 1,718 224 80 278
Disposals/derecognitions (100) - - (317)
Foreign exchange
adjustments and other - 173 134 -
----------------------------------------------------------------------------
At June 30, 2013 $ 26,609 $ 3,106 $ 2,487 $ 1,163
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net book value- at June
30, 2013 $ 25,506 $ 1,882 $ 793 $ 16,759
- at December 31, 2012 $ 25,333 $ 1,865 $ 772 $ 15,761
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Midstream Head Office Total
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Cost
At December 31, 2012 $ 312 $ 270 $ 75,488
Additions 9 19 3,356
Transfers from E&E assets - - 45
Disposals/derecognitions - - (417)
Foreign exchange
adjustments and other - - 443
----------------------------------------------------------------------------
At June 30, 2013 $ 321 $ 289 $ 78,915
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Accumulated depletion and
depreciation
At December 31, 2012 $ 103 $ 182 $ 31,460
Expense 4 10 2,314
Disposals/derecognitions - - (417)
Foreign exchange
adjustments and other - - 307
----------------------------------------------------------------------------
At June 30, 2013 $ 107 $ 192 $ 33,664
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net book value- at June
30, 2013 $ 214 $ 97 $ 45,251
- at December 31, 2012 $ 209 $ 88 $ 44,028
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Horizon project costs not subject to depletion
----------------------------------------------------------------------------
At June 30, 2013 $ 3,022
At December 31, 2012 $ 2,066
----------------------------------------------------------------------------
----------------------------------------------------------------------------
In addition, the Company has capitalized costs to date of $1,320
million (December 31, 2012 - $1,021 million) related to the
development of the Kirby Thermal Oil Sands Project which are not
subject to depletion.
The Company acquired a number of producing crude oil and natural
gas assets in the North American and North Sea Exploration and
Production segments for total cash consideration of $11 million
during the six months ended June 30, 2013 (year ended December 31,
2012 - $144 million), net of associated asset retirement
obligations of $10 million (year ended December 31, 2012 - $12
million). Interests in jointly controlled assets were acquired with
full tax basis. No working capital or debt obligations were
assumed.
Subsequent to June 30, 2013, the Company acquired all of the
issued and outstanding common shares of Barrick Energy Inc. ("BEI")
for total cash consideration of approximately $173 million. BEI's
assets include working interests in producing crude oil and natural
gas properties and undeveloped land. Due to the timing of the close
of the acquisition, the purchase accounting and related disclosures
have not been finalized.
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 six months
ended June 30, 2013, pre-tax interest of $76 million (June 30, 2012
- $39 million) was capitalized to property, plant and equipment
using a capitalization rate of 4.4% (June 30, 2012 - 4.8%).
5. OTHER LONG-TERM ASSETS
------------
Jun 30 Dec 31
2013 2012
----------------------------------------------------------------------------
Investment in North West Redwater Partnership $ 308 $ 310
Risk management (note 13) 35 -
Other 61 117
----------------------------------------------------------------------------
404 427
Less: current portion 35 -
----------------------------------------------------------------------------
$ 369 $ 427
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Other long-term assets include an investment in the 50% owned
Redwater. The investment is accounted for using the equity method.
Redwater has entered into agreements to construct and operate a
50,000 barrel per day bitumen upgrader and refinery (the "Project")
under processing agreements that target to process 12,500 barrels
per day of bitumen feedstock for the Company and 37,500 barrels per
day of bitumen feedstock for the Alberta Petroleum Marketing
Commission, an agent of the Government of Alberta, under a 30 year
fee-for-service tolling agreement. During 2012, the Project
received board sanction from Redwater and its partners.
As at June 30, 2013, Redwater had interim borrowings of $353
million under credit facilities totaling $600 million which mature
no later than December 2017. These facilities are secured by a
floating charge on the assets of Redwater with a mandatory
repayment required from future financing proceeds. At maturity,
under its processing agreement, the Company would be obligated to
pay its 25% pro rate share of any shortfall.
Redwater has entered into various agreements related to the
engineering and procurement of the Project. These contracts can be
cancelled by Redwater upon notice without penalty, subject to the
costs incurred up to and in respect of the cancellation.
6. LONG-TERM DEBT
-------------
Jun 30 Dec 31
2013 2012
----------------------------------------------------------------------------
Canadian dollar denominated debt
Bank credit facilities $ 1,963 $ 971
Medium-term notes 1,400 1,300
----------------------------------------------------------------------------
3,363 2,271
----------------------------------------------------------------------------
US dollar denominated debt
Commercial paper (June 30, 2013 - US$250 million;
December 31, 2012 - US$nil) 263 -
US dollar debt securities (June 30, 2013 -
US$6,150 million; December 31, 2012 - US$6,550
million) 6,465 6,517
Less: original issue discount on US dollar debt
securities (1) (19) (20)
----------------------------------------------------------------------------
6,709 6,497
Fair value impact of interest rate swaps on US
dollar debt securities (2) 14 19
----------------------------------------------------------------------------
6,723 6,516
----------------------------------------------------------------------------
Long-term debt before transaction costs 10,086 8,787
Less: transaction costs (1) (3) (53) (51)
----------------------------------------------------------------------------
10,033 8,736
Less: current portion of commercial paper 263 -
----------------------------------------------------------------------------
current portion of other long-term debt (1) - 798
$ 9,770 $ 7,938
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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 amount of US$350 million of 4.90% unsecured
notes due December 2014 was adjusted by $14 million (December 31,
2012 - $19 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.
Bank Credit Facilities and Commercial Paper
As at June 30, 2013, 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 2017;
- 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 2013, the $3,000 million revolving
syndicated credit facility was extended to June 2017. 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 established a US commercial paper program in the
first quarter of 2013. Borrowings of up to a maximum US$1,500
million are authorized. The Company reserves capacity under its
bank credit facilities for amounts outstanding under this
program.
The Company's weighted average interest rate on bank credit
facilities and commercial paper outstanding as at June 30, 2013,
was 2.1% (June 30, 2012 - 1.9%), and on long-term debt outstanding
for the six months ended June 30, 2013 was 4.4% (June 30, 2012 -
4.8%).
In addition to the outstanding debt, letters of credit and
financial guarantees aggregating $560 million, including a $77
million financial guarantee related to Horizon and $358 million of
letters of credit related to North Sea operations, were outstanding
at June 30, 2013.
Medium-Term Notes
During the first quarter of 2013, the Company repaid $400
million of 4.50% medium-term notes.
During the second quarter of 2013, the Company issued $500
million of 2.89% medium-term notes due August 2020. Proceeds from
the securities issued were used to repay bank indebtedness and for
general corporate purposes. After issuing these securities, the
Company has $2,000 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
During the first quarter of 2013, the Company repaid US$400
million of 5.15% unsecured notes.
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.
7. OTHER LONG-TERM LIABILITIES
------------
Jun 30 Dec 31
2013 2012
----------------------------------------------------------------------------
Asset retirement obligations $ 4,340 $ 4,266
Share-based compensation 169 154
Risk management (note 13) 80 257
Other 77 87
----------------------------------------------------------------------------
4,666 4,764
Less: current portion 153 155
----------------------------------------------------------------------------
$ 4,513 $ 4,609
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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
4.3% (December 31, 2012 - 4.3%). A reconciliation of the discounted
asset retirement obligations is as follows:
------------
Jun 30 Dec 31
2013 2012
----------------------------------------------------------------------------
Balance - beginning of period $ 4,266 $ 3,577
Liabilities incurred 27 51
Liabilities acquired 10 12
Liabilities settled (92) (204)
Asset retirement obligation accretion 84 151
Revision of estimates (27) 384
Change in discount rate - 315
Foreign exchange 72 (20)
----------------------------------------------------------------------------
Balance - end of period $ 4,340 $ 4,266
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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.
-------------
Jun 30 Dec 31
2013 2012
----------------------------------------------------------------------------
Balance - beginning of period $ 154 $ 432
Share-based compensation expense (recovery) 22 (214)
Cash payment for stock options surrendered (1) (7)
Transferred to common shares (11) (45)
Capitalized to (recovered from) Oil Sands Mining
and Upgrading 5 (12)
----------------------------------------------------------------------------
Balance - end of period 169 154
Less: current portion 131 129
----------------------------------------------------------------------------
$ 38 $ 25
----------------------------------------------------------------------------
----------------------------------------------------------------------------
8. INCOME TAXES
The provision for income tax is as follows:
Three Months Ended Six Months Ended
------------- -------------
Jun 30 Jun 30 Jun 30 Jun 30
2013 2012 2013 2012
----------------------------------------------------------------------------
Current corporate income
tax - North America $ 111 $ 124 $ 233 $ 237
Current corporate income
tax - North Sea 25 19 18 64
Current corporate income
tax - Offshore Africa 36 64 71 100
Current PRT (1)
(recovery) expense -
North Sea (33) 1 (46) 32
Other taxes 6 5 10 11
----------------------------------------------------------------------------
Current income tax
expense 145 213 286 444
----------------------------------------------------------------------------
Deferred corporate income
tax expense 44 59 40 11
Deferred PRT (1)
(recovery) expense -
North Sea (13) 3 (36) (1)
----------------------------------------------------------------------------
Deferred income tax
expense 31 62 4 10
----------------------------------------------------------------------------
Income tax expense $ 176 $ 275 $ 290 $ 454
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Petroleum Revenue Tax.
During the second quarter of 2013, the government of British
Columbia substantively enacted legislation to increase its
provincial corporate income tax rate effective April 1, 2013. As a
result of the income tax rate change, the Company's deferred income
tax liability was increased by $15 million.
9. SHARE CAPITAL
Authorized
Preferred shares issuable in a series.
Unlimited number of common shares without par value.
----------------------------------
Six Months Ended Jun 30, 2013
Number of shares
Issued common shares (thousands) Amount
----------------------------------------------------------------------------
Balance - beginning of period 1,092,072 $ 3,709
Issued upon exercise of stock options 1,605 39
Previously recognized liability on stock
options exercised for common shares - 11
Purchase of common shares under Normal
Course Issuer Bid (6,708) (23)
----------------------------------------------------------------------------
Balance - end of period 1,086,969 $ 3,736
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Dividend Policy
The Company has paid regular quarterly dividends in January,
April, July, and October of each year since 2001. The dividend
policy undergoes periodic review by the Board of Directors and is
subject to change.
On March 6, 2013, the Board of Directors set the regular
quarterly dividend at $0.125 per common share (2012 - $0.105 per
common share).
Normal Course Issuer Bid
In April 2013, 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 2013 and ending April 2014, up to 54,635,116
common shares. The Company's Normal Course Issuer Bid announced in
2012 expired April 2013.
For the six months ended June 30, 2013, the Company purchased
6,707,500 common shares at a weighted average price of $30.86 per
common share, for a total cost of $207 million. Retained earnings
were reduced by $184 million, representing the excess of the
purchase price of common shares over their average carrying value.
Subsequent to June 30, 2013, the Company purchased 230,000 common
shares at a weighted average price of $30.98 per common share for a
total cost of $7 million.
Stock Options
The following table summarizes information relating to stock
options outstanding at June 30, 2013:
-----------------------
Six Months Ended Jun
30, 2013
----------------------------------------------------------------------------
Weighted
Stock average
options exercise
(thousands) price
----------------------------------------------------------------------------
Outstanding - beginning of period 73,747 $ 34.13
Granted 5,809 $ 29.82
Surrendered for cash settlement (133) $ 23.52
Exercised for common shares (1,605) $ 24.86
Forfeited (10,355) $ 35.08
----------------------------------------------------------------------------
Outstanding - end of period 67,463 $ 33.84
----------------------------------------------------------------------------
Exercisable - end of period 21,106 $ 34.13
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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:
-------------
Jun 30 Jun 30
2013 2012
----------------------------------------------------------------------------
Derivative financial instruments designated as
cash flow hedges $ 106 $ 95
Foreign currency translation adjustment (39) (36)
----------------------------------------------------------------------------
$ 67 $ 59
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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 25% 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 June 30, 2013, the ratio was within the target range at 29%.
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.
-------------
Jun 30 Dec 31
2013 2012
----------------------------------------------------------------------------
Long-term debt (1) $ 10,033 $ 8,736
Total shareholders' equity $ 24,551 $ 24,283
Debt to book capitalization 29% 26%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Includes the current portion of long-term debt.
12. NET EARNINGS PER COMMON SHARE
Three Months Ended Six Months Ended
------------ ------------
Jun 30 Jun 30 Jun 30 Jun 30
2013 2012 2013 2012
----------------------------------------------------------------------------
Weighted average common
shares outstanding - basic
(thousands of shares) 1,089,302 1,099,046 1,090,858 1,099,600
Effect of dilutive stock
options (thousands of
shares) 1,719 2,055 1,896 3,131
----------------------------------------------------------------------------
Weighted average common
shares outstanding -
diluted (thousands of
shares) 1,091,021 1,101,101 1,092,754 1,102,731
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net earnings $ 476 $ 753 $ 689 $ 1,180
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net earnings per common
share - basic $ 0.44 $ 0.68 $ 0.63 $ 1.07
- diluted $ 0.44 $ 0.68 $ 0.63 $ 1.07
----------------------------------------------------------------------------
----------------------------------------------------------------------------
13. FINANCIAL INSTRUMENTS
The carrying amounts of the Company's financial instruments by
category were as follows:
-------------------------------------------------------------
Jun 30, 2013
-------------------------------------------------------------
Loans and Fair Financial
receivables value liabilities
at through Derivatives at
Asset amortized profit used for amortized
(liability) cost or loss hedging cost Total
----------------------------------------------------------------------------
Accounts
receivable $ 1,614 $ - $ - $ - $ 1,614
Other long-term
assets - 32 3 - 35
Accounts
payable - - - (667) (667)
Accrued
liabilities - - - (2,451) (2,451)
Other long-term
liabilities - 20 (100) (68) (148)
Long-term debt
(1) - - - (10,033) (10,033)
----------------------------------------------------------------------------
$ 1,614 $ 52 $ (97) $ (13,219) $(11,650)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Dec 31, 2012
----------------------------------------------------------------------------
Loans and Financial
receivables Fair value liabilities
at through Derivatives at
Asset amortized profit or used for amortized
(liability) cost loss hedging cost Total
----------------------------------------------------------------------------
Accounts
receivable $ 1,197 $ - $ - $ - $ 1,197
Accounts
payable - - - (465) (465)
Accrued
liabilities - - - (2,273) (2,273)
Other long-
term
liabilities - 4 (261) (79) (336)
Long-term
debt (1) - - - (8,736) (8,736)
----------------------------------------------------------------------------
$ 1,197 $ 4 $ (261) $ (11,553) $(10,613)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Includes the current portion of long-term debt.
The carrying amounts 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:
---------------------------------------
Jun 30, 2013
----------------------------------------------------------------------------
Carrying
amount Fair value
----------------------------------------------------------------------------
Asset (liability) (1) Level 1 Level 2
----------------------------------------------------------------------------
Other long-term assets $ 35 $ - $ 35
Other long-term liabilities (80) - (80)
Fixed rate long-term debt (2) (3) (4) (7,807) (8,591) -
----------------------------------------------------------------------------
$ (7,852) $ (8,591) $ (45)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Dec 31, 2012
----------------------------------------------------------------------------
Carrying
amount Fair value
----------------------------------------------------------------------------
Asset (liability) (1) Level 1 Level 2
----------------------------------------------------------------------------
Other long-term liabilities $ (257) $ - $ (257)
Fixed rate long-term debt (2) (3) (4) (7,765) (9,118) -
----------------------------------------------------------------------------
$ (8,022) $ (9,118) $ (257)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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 amount of US$350 million of 4.90% unsecured
notes due December 2014 was adjusted by $14 million (December 31,
2012 - $19 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 fixed rate 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) Jun 30, 2013 Dec 31, 2012
----------------------------------------------------------------------------
Derivatives held for trading
Crude oil price collars $ 14 $ (16)
Foreign currency forward contracts 38 20
Cash flow hedges
Foreign currency forward contracts 2 -
Cross currency swaps (99) (261)
----------------------------------------------------------------------------
$ (45) $ (257)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Included within:
Current portion of other long-term assets
(liabilities) $ 35 $ (4)
Other long-term liabilities (80) (253)
----------------------------------------------------------------------------
$ (45) $ (257)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
For the six months ended June 30, 2013 the Company recognized a
gain of $3 million (December 31, 2012 - gain of $1 million) related
to ineffectiveness arising from cash flow hedges.
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 the risk management asset (liability) were
recognized in the financial statements as follows:
---------------
Six Months
Ended Year Ended
Asset (liability) Jun 30, 2013 Dec 31, 2012
----------------------------------------------------------------------------
Balance - beginning of period $ (257) $ (274)
Net change in fair value of outstanding
derivative financial instruments attributable
to:
Risk management activities 52 42
Foreign exchange 137 (53)
Other comprehensive income 23 28
----------------------------------------------------------------------------
Balance - end of period (45) (257)
Less: current portion 35 (4)
----------------------------------------------------------------------------
$ (80) $ (253)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net (gains) losses from risk management activities were as
follows:
Three Months Ended Six Months Ended
------------- -------------
Jun 30 Jun 30 Jun 30 Jun 30
2013 2012 2013 2012
----------------------------------------------------------------------------
Net realized risk
management (gain) loss $ (19) $ (61) $ (102) $ 33
Net unrealized risk
management gain (114) (144) (52) (84)
----------------------------------------------------------------------------
$ (133) $ (205) $ (154) $ (51)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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 June 30, 2013, the
Company had the following derivative financial instruments
outstanding to manage its commodity price risk:
Sales contracts
Weighted average
Remaining term Volume price Index
----------------------------------------------------------------------------
Crude oil
Price collars 50,000
(1) Jul 2013 - Dec 2013 bbl/d US$80.00 - US$135.59 Brent
50,000
Jul 2013 - Dec 2013 bbl/d US$80.00 - US$132.18 Brent
50,000
Jan 2014 - Dec 2014 bbl/d US$75.00 - US$121.57 Brent
50,000
Jul 2013 - Dec 2013 bbl/d US$80.00 - US$97.73 WTI
50,000
Jul 2013 - Dec 2013 bbl/d US$80.00 - US$110.34 WTI
50,000
Jul 2013 - Dec 2013 bbl/d US$80.00 - US$111.05 WTI
50,000
Jan 2014 - Dec 2014 bbl/d US$75.00 - US$105.54 WTI
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Subsequent to June 30, 2013, the Company entered into an
additional 50,000 bbl/d of US$80.00 - US$118.26 WTI collars for the
period August to December 2013 and an additional 50,000 bbl/d of
US$80.00 - US$120.17 Brent collars for the period January to
December 2014.
The Company's outstanding commodity derivative financial
instruments are expected to be settled monthly based on the
applicable index pricing for the respective contract month.
Interest rate risk management
The Company is exposed to interest rate price risk on its fixed
rate long-term debt and to interest rate cash flow risk on its
floating rate long-term debt. The Company periodically enters into
interest rate swap contracts to manage its fixed to floating
interest rate mix on long-term debt. The interest rate swap
contracts require the periodic exchange of payments without the
exchange of the notional principal amounts on which the payments
are based. At June 30, 2013, the Company had no interest rate swap
contracts outstanding.
Foreign currency exchange rate risk management
The Company is exposed to foreign currency exchange rate risk in
Canada primarily related to its US dollar denominated long-term
debt, commercial paper and working capital. The Company is also
exposed to foreign currency exchange rate risk on transactions
conducted in other currencies in its subsidiaries and in the
carrying value of its foreign subsidiaries. The Company
periodically enters into cross currency swap contracts and foreign
currency forward contracts to manage known currency exposure on US
dollar denominated debt, commercial paper and working capital. The
cross currency swap contracts require the periodic exchange of
payments with the exchange at maturity of notional principal
amounts on which the payments are based. At June 30, 2013, the
Company had the following cross currency swap contracts
outstanding:
Exchange
rate Interest Interest
Remaining term Amount (US$/C$) rate (US$) rate (C$)
----------------------------------------------------------------------------
Cross
currency
Swaps Jul 2013 - Aug 2016 US$250 1.116 6.00% 5.40%
Jul 2013 - May 2017 US$1,100 1.170 5.70% 5.10%
Jul 2013 - Nov 2021 US$500 1.022 3.45% 3.96%
Jul 2013 - Mar 2038 US$550 1.170 6.25% 5.76%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
All cross currency swap derivative financial instruments
designated as hedges at June 30, 2013, were classified as cash flow
hedges.
In addition to the cross currency swap contracts noted above, at
June 30, 2013, the Company had US$2,643 million of foreign currency
forward contracts outstanding, with terms of approximately 30 days
or less, including US$250 million designated as cash flow
hedges.
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
June 30, 2013, 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
June 30, 2013, the Company had net risk management assets of $29
million with specific counterparties related to derivative
financial instruments (December 31, 2012 - $18 million).
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, commercial paper 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 than
1 year 2 years 5 years Thereafter
----------------------------------------------------------------------------
Accounts payable $ 667 $ - $ - $ -
Accrued liabilities $ 2,451 $ - $ - $ -
Risk management $ - $ 9 $ 53 $ 18
Other long-term liabilities $ 22 $ 46 $ - $ -
Long-term debt (1) $ 263 $ 1,294 $ 3,802 $ 4,732
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Long-term debt represents principal repayments only and does
not reflect fair value adjustments, interest, original issue
discounts or transaction costs.
14. COMMITMENTS AND CONTINGENCIES
The Company has committed to certain payments as follows:
Remaining
2013 2014 2015 2016 2017 Thereafter
----------------------------------------------------------------------------
Product transportation and
pipeline $ 117 $ 225 $ 209 $ 138 $ 118 $ 795
Offshore equipment operating
leases $ 65 $ 128 $ 110 $ 80 $ 60 $ 71
Office leases $ 16 $ 34 $ 32 $ 33 $ 35 $ 262
Other $ 97 $ 99 $ 86 $ 15 $ 2 $ 6
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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
Three Six Three Six
Months Months Months Months
Ended Ended Ended Ended
(millions of Canadian
dollars, unaudited) Jun 30 Jun 30 Jun 30 Jun 30
----------------------------------------------------------------------------
2013 2012 2013 2012 2013 2012 2013 2012
----------------------------------------------------------------------------
Segmented product sales 3,189 2,757 5,997 5,815 187 236 364 515
Less: royalties (384) (244) (660) (632) - - (1) (1)
----------------------------------------------------------------------------
Segmented revenue 2,805 2,513 5,337 5,183 187 236 363 514
----------------------------------------------------------------------------
Segmented expenses
Production 588 505 1,193 1,087 75 119 177 204
Transportation and blending 735 683 1,590 1,398 1 3 3 6
Depletion, depreciation and
amortization 855 811 1,726 1,609 114 75 226 159
Asset retirement obligation
accretion 23 21 46 42 8 7 17 14
Realized risk management
activities (19) (61) (102) 33 - - - -
Equity loss from jointly
controlled entity - - - - - - - -
----------------------------------------------------------------------------
Total segmented expenses 2,182 1,959 4,453 4,169 198 204 423 383
----------------------------------------------------------------------------
Segmented earnings (loss)
before the following 623 554 884 1,014 (11) 32 (60) 131
----------------------------------------------------------------------------
Non-segmented expenses
Administration
Share-based compensation
Interest and other financing
costs
Unrealized risk management
activities
Foreign exchange loss
----------------------------------------------------------------------------
Total non-segmented expenses
----------------------------------------------------------------------------
Earnings before taxes
Current income tax expense
Deferred income tax expense
----------------------------------------------------------------------------
Net earnings
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Total Exploration and
Offshore Africa Production
Three Six Three Six
Months Months Months Months
Ended Ended Ended Ended
(millions of Canadian
dollars, unaudited) Jun 30 Jun 30 Jun 30 Jun 30
----------------------------------------------------------------------------
2013 2012 2013 2012 2013 2012 2013 2012
----------------------------------------------------------------------------
Segmented product sales 206 240 414 457 3,582 3,233 6,775 6,787
Less: royalties (34) (62) (67) (96) (418) (306) (728) (729)
----------------------------------------------------------------------------
Segmented revenue 172 178 347 361 3,164 2,927 6,047 6,058
----------------------------------------------------------------------------
Segmented expenses
Production 36 51 83 73 699 675 1,453 1,364
Transportation and blending 1 1 1 1 737 687 1,594 1,405
Depletion, depreciation and
amortization 40 50 80 78 1,009 936 2,032 1,846
Asset retirement obligation
accretion 2 2 4 3 33 30 67 59
Realized risk management
activities - - - - (19) (61) (102) 33
Equity loss from jointly
controlled entity - - - - - - - -
----------------------------------------------------------------------------
Total segmented expenses 79 104 168 155 2,459 2,267 5,044 4,707
----------------------------------------------------------------------------
Segmented earnings (loss)
before the following 93 74 179 206 705 660 1,003 1,351
----------------------------------------------------------------------------
Non-segmented expenses
Administration
Share-based compensation
Interest and other financing
costs
Unrealized risk management
activities
Foreign exchange loss
----------------------------------------------------------------------------
Total non-segmented expenses
----------------------------------------------------------------------------
Earnings before taxes
Current income tax expense
Deferred income tax expense
----------------------------------------------------------------------------
Net earnings
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Oil Sands Mining and
Upgrading Midstream
Three Six Three Six
Months Months Months Months
Ended Ended Ended Ended
(millions of Canadian
dollars, unaudited) Jun 30 Jun 30 Jun 30 Jun 30
------------------------------------------------
2013 2012 2013 2012 2013 2012 2013 2012
----------------------------------------------------------------------------
Segmented product sales 643 951 1,552 1,365 29 22 56 43
Less: royalties (28) (55) (64) (76) - - - -
----------------------------------------------------------------------------
Segmented revenue 615 896 1,488 1,289 29 22 56 43
----------------------------------------------------------------------------
Segmented expenses
Production 394 388 771 734 9 7 17 14
Transportation and blending 18 18 33 30 - - - -
Depletion, depreciation and
amortization 161 146 278 209 2 2 4 4
Asset retirement obligation
accretion 9 8 17 16 - - - -
Realized risk management
activities - - - - - - - -
Equity loss from jointly
controlled entity - - - - - 5 2 5
----------------------------------------------------------------------------
Total segmented expenses 582 560 1,099 989 11 14 23 23
----------------------------------------------------------------------------
Segmented earnings (loss)
before the following 33 336 389 300 18 8 33 20
----------------------------------------------------------------------------
Non-segmented expenses
Administration
Share-based compensation
Interest and other financing
costs
Unrealized risk management
activities
Foreign exchange loss
----------------------------------------------------------------------------
Total non-segmented expenses
----------------------------------------------------------------------------
Earnings before taxes
Current income tax expense
Deferred income tax expense
----------------------------------------------------------------------------
Net earnings
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Inter-segment
elimination and other Total
Three Six Three Six
Months Months Months Months
Ended Ended Ended Ended
(millions of Canadian
dollars, unaudited) Jun 30 Jun 30 Jun 30 Jun 30
------------------------------------------------
2013 2012 2013 2012 2013 2012 2013 2012
----------------------------------------------------------------------------
Segmented product sales (24) (19) (52) (37)4,230 4,187 8,331 8,158
Less: royalties - - - - (446) (361) (792) (805)
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Segmented revenue (24) (19) (52) (37)3,784 3,826 7,539 7,353
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Segmented expenses
Production (6) (2) (10) (6)1,096 1,068 2,231 2,106
Transportation and blending (17) (14) (34) (27) 738 691 1,593 1,408
Depletion, depreciation and
amortization - - - - 1,172 1,084 2,314 2,059
Asset retirement obligation
accretion - - - - 42 38 84 75
Realized risk management
activities - - - - (19) (61) (102) 33
Equity loss from jointly
controlled entity - - - - - 5 2 5
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Total segmented expenses (23) (16) (44) (33)3,029 2,825 6,122 5,686
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Segmented earnings (loss)
before the following (1) (3) (8) (4) 755 1,001 1,417 1,667
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Non-segmented expenses
Administration 81 77 160 142
Share-based compensation (49) (115) 22 (222)
Interest and other financing
costs 72 93 149 189
Unrealized risk management
activities (114) (144) (52) (84)
Foreign exchange loss 113 62 159 8
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Total non-segmented expenses 103 (27) 438 33
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Earnings before taxes 652 1,028 979 1,634
Current income tax expense 145 213 286 444
Deferred income tax expense 31 62 4 10
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Net earnings 476 753 689 1,180
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Capital Expenditures (1)
Six Months Ended
---------------------------------------------
Jun 30, 2013
----------------------------------------------------------------------------
Non cash
and fair
Net value Capitalized
expenditures changes(2) costs
----------------------------------------------------------------------------
Exploration and evaluation
assets
Exploration and Production
North America $ 80 $ (45) $ 35
North Sea - - -
Offshore Africa 7 - 7
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$ 87 $ (45) $ 42
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Property, plant and equipment
Exploration and Production
North America $ 1,839 $ (48) $ 1,791
North Sea 147 - 147
Offshore Africa 59 - 59
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2,045 (48) 1,997
Oil Sands Mining and Upgrading
(3) 1,276 (317) 959
Midstream 9 - 9
Head office 19 - 19
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$ 3,349 $ (365) $ 2,984
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Six Months Ended
---------------------------------------------
Jun 30, 2012
----------------------------------------------------------------------------
Non cash
and fair
Net value Capitalized
expenditures changes(2) costs
----------------------------------------------------------------------------
Exploration and evaluation
assets
Exploration and Production
North America $ 239 $ (76) $ 163
North Sea - - -
Offshore Africa 1 - 1
----------------------------------------------------------------------------
$ 240 $ (76) $ 164
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Property, plant and equipment
Exploration and Production
North America $ 1,772 $ 59 $ 1,831
North Sea 120 (36) 84
Offshore Africa 14 (6) 8
----------------------------------------------------------------------------
1,906 17 1,923
Oil Sands Mining and Upgrading
(3) 639 35 674
Midstream 5 - 5
Head office 15 - 15
----------------------------------------------------------------------------
$ 2,565 $ 52 $ 2,617
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(1) This table provides a reconciliation of capitalized costs
including derecognitions and does not include the impact of foreign
exchange adjustments.
(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.
Segmented Assets
Total Assets
--------------
Jun 30 Dec 31
2013 2012
----------------------------------------------------------------------------
Exploration and Production
North America $ 29,515 $ 29,012
North Sea 2,094 1,993
Offshore Africa 1,016 924
Other 29 36
Oil Sands Mining and Upgrading 17,408 16,291
Midstream 651 636
Head office 97 88
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$ 50,810 $ 48,980
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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 June
30, 2013:
----------------------------------------------------------------------------
Interest coverage (times)
Net earnings (1) 5.1x
Cash flow from operations (2) 15.6x
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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, August 8, 2013. The North American
conference call number is 1-866-225-2055 and the outside North
American conference call number is 001-416-340-8410. 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, August 15, 2013. 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.
Contacts: Steve W. Laut President Douglas A. Proll Executive
Vice-President Corey B. Bieber Chief Financial Officer & Senior
Vice-President, Finance Canadian Natural Resources Limited 2500,
855 - 2nd Street S.W. Calgary, Alberta, T2P 4J8 Canada Phone: (403)
514-7777 (403) 514-7888 (FAX)ir@cnrl.com www.cnrl.com
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