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| Share Name | Share Symbol | Market | Type |
|---|---|---|---|
| TSXV:SCO | TSX Venture | Common Stock |
| Price Change | % Change | Share Price | Bid Price | Offer Price | High Price | Low Price | Open Price | Shares Traded | Last Trade | |
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Canadian Natural Resources Limited (TSX:CNQ) (NYSE:CNQ)
Commenting on second quarter results, Canadian Natural's Vice-Chairman John
Langille stated, "Our strategy to maintain a well balanced portfolio and
optimize capital allocation ensures we have the flexibility to maximize returns
on capital, generate significant cash flow and maintain a strong balance sheet
through commodity price cycles. We continue to deliver strong oil-weighted
production growth while preserving our vast natural gas asset base which will
provide significant upside when natural gas prices strengthen."
Steve Laut, President of Canadian Natural continued, "With our balanced and
diverse assets, complemented our proven and effective strategy as executed by
our strong teams, we delivered a very strong quarter. Overall production was up
and operating costs were down across the board in North America. In addition, we
have been nimble and effective in optimizing our capital allocation in the
quarter in response to market conditions. We have reduced capital spending in
2012 by approximately 10% and at the same time have slightly increased our BOE
and crude oil mid-point production guidance for 2012. This demonstrates the
strength of Canadian Natural's assets, our capital flexibility, the
effectiveness of our strategies and the ability of our teams to effectively
execute."
QUARTERLY HIGHLIGHTS
Three Months Ended Six Months Ended
--------------------------------------------
($ Millions, except per common Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
share amounts) 2012 2012 2011 2012 2011
----------------------------------------------------------------------------
Net earnings $ 753 $ 427 $ 929 $ 1,180 $ 975
Per common share - basic $ 0.68 $ 0.39 $ 0.85 $ 1.07 $ 0.89
- diluted $ 0.68 $ 0.39 $ 0.84 $ 1.07 $ 0.88
Adjusted net earnings from
operations (1) $ 606 $ 300 $ 621 $ 906 $ 849
Per common share - basic $ 0.55 $ 0.27 $ 0.57 $ 0.82 $ 0.78
- diluted $ 0.55 $ 0.27 $ 0.56 $ 0.82 $ 0.77
Cash flow from operations (2) $ 1,754 $ 1,280 $ 1,548 $ 3,034 $ 2,622
Per common share - basic $ 1.60 $ 1.16 $ 1.41 $ 2.76 $ 2.39
- diluted $ 1.59 $ 1.16 $ 1.40 $ 2.75 $ 2.37
Capital expenditures, net of
dispositions $ 1,324 $ 1,596 $ 1,405 $ 2,920 $ 3,099
Daily production, before
royalties
Natural gas (MMcf/d) 1,255 1,302 1,240 1,277 1,248
Crude oil and NGLs (bbl/d) 470,523 395,461 349,915 432,993 353,433
Equivalent production (BOE/d)
(3) 679,607 612,279 556,539 645,943 561,359
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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 is committed to operational excellence. In Q2/12 the Company
achieved record quarterly production of 679,607 BOE/d and met or exceeded
production guidance in all areas of our business.
- Total crude oil and NGLs achieved record quarterly production of 470,523 bbl/d
representing an increase of 34% and 19% over Q2/11 and Q1/12 levels
respectively. The increase in production from Q2/11 was primarily due to
efficient, effective and reliable operations achieved at Horizon and successful
results from a strong primary heavy crude oil drilling program. The increase in
production from Q1/12 was primarily due to improved reliability at Horizon and
the timing of steaming cycles in bitumen ("thermal in situ").
- Total natural gas production for Q2/12 was 1,255 MMcf/d representing an
increase of 1% over Q2/11 and a decrease of 4% from Q1/12. The increase in
production from Q2/11 reflects the impact of natural gas producing properties
acquired during 2011 and strong results from the Company's modest, liquids rich
drilling program. The decrease in production from Q1/12 was a result of natural
declines reflecting the Company's strategic decision to allocate capital to
higher return crude oil projects and 20 MMcf/d of shut-in natural gas volumes
year-to-date.
- Canadian Natural generated cash flow from operations for the quarter of $1.75
billion representing an increase of 13% and 37% compared with Q2/11 and Q1/12
cash flow levels respectively. The increase in cash flow was primarily related
to higher North America crude oil and synthetic crude oil ("SCO") sales volumes
partially offset by lower crude oil and NGLs and natural gas pricing.
- Adjusted net earnings from operations for the quarter were $606 million,
compared with adjusted net earnings of $621 million in Q2/11 and $300 million in
Q1/12. The decrease from Q2/11 was primarily due to lower crude oil and NGLs and
natural gas pricing partially offset by higher sales volumes from the Company's
North America crude oil and NGLs and oil sands mining operations. The increase
from Q1/12 was primarily related to higher North America crude oil and SCO sales
volumes partially offset by lower crude oil and NGLs and natural gas pricing.
- Primary heavy crude oil production achieved record quarterly production
exceeding 122,000 bbl/d representing an increase of 21% compared with Q2/11 and
an increase of 2% compared with Q1/12. Canadian Natural targets to drill 54
additional net primary heavy crude oil wells compared with the previous target,
for a targeted record of 872 net wells in 2012 and targets to increase annual
production by 21% over 2011. Primary heavy crude oil continues to provide the
highest return on capital projects in the portfolio.
- As expected, thermal in situ production averaged approximately 94,000 bbl/d in
Q2/12 as pads began to re-enter the production cycle. Production is targeted to
ramp up to facility capacity in Q4/12. Operating costs for the quarter were
$10.47/bbl as a result of solid production, modest natural gas prices and strong
operational performance. The Company targets to achieve full year operating
costs of approximately $9.00/bbl in this segment of the Company.
- Kirby South Phase 1 was 53% complete at the end of the second quarter. The
project remains on schedule with first steam-in targeted for Q4/13. Drilling is
nearing completion on the fourth of seven pads with wells confirming geological
expectations.
- Horizon demonstrated strong operational performance in the quarter. Production
averaged 115,823 bbl/d, highlighting the Company's commitment to safe, steady
and reliable operations and the positive impact of the third ore preparation
plant ("OPP") being fully operational. The third OPP has increased overall
reliability and improved steady operations in the upgrader.
- In response to the uncertain outlook on commodity prices, targeted capital
expenditures for 2012 are being re-allocated from natural gas to higher return
primary heavy crude oil projects and overall capital expenditures in 2012 are
being reduced by approximately $680 million while BOE and crude oil mid-point
production guidance was slightly increased. Capital allocation reductions were
primarily in the areas of Horizon oil sands expansion and North America natural
gas.
- To date in 2012, Canadian Natural has purchased 6,196,600 common shares for
cancellation at a weighted average price of $28.91 per common share.
- Declared a quarterly cash dividend on common shares of $0.105 per common share
payable October 1, 2012.
OPERATIONS REVIEW AND CAPITAL ALLOCATION
In order to facilitate efficient operations, Canadian Natural focuses its
activities in core regions where it can own a substantial land base and
associated infrastructure. Land inventories are maintained to enable continuous
exploitation of play types and geological trends, greatly reducing overall
exploration risk. By owning associated infrastructure, the Company is able to
maximize utilization of its production facilities, thereby increasing control
over production costs. Further, the Company maintains large project inventories
and production diversification among each of the commodities it produces; light
and medium crude oil, primary heavy crude oil, Pelican Lake heavy crude oil,
bitumen ("thermal in situ"), 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
----------------------------------------
2012 2011
Gross Net Gross Net
----------------------------------------------------------------------------
Crude oil 574 544 471 456
Natural gas 25 23 39 35
Dry 8 8 22 21
----------------------------------------------------------------------------
Subtotal 607 575 532 512
Stratigraphic test / service wells 589 589 521 520
----------------------------------------------------------------------------
Total 1,196 1,164 1,053 1,032
----------------------------------------------------------------------------
Success rate (excluding
stratigraphic test / service wells) 99% 96%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
North America Exploration and Production
North America crude oil and NGLs
Three Months Ended Six Months Ended
--------------------------------------------------
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
2012 2012 2011 2012 2011
----------------------------------------------------------------------------
Crude oil and NGLs
production (bbl/d) 316,483 305,613 295,715 311,048 292,938
----------------------------------------------------------------------------
Net wells targeting crude
oil 268 284 182 552 475
Net successful wells
drilled 266 278 177 544 456
----------------------------------------------------------------------------
Success rate 99% 98% 97% 99% 96%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
- Production averaged 316,483 bbl/d in Q2/12 representing an increase of 7% from
Q2/11 and an increase of 4% from Q1/12. The increase in production from Q2/11
was a result of successful primary heavy and light crude oil drilling programs
offset by the timing of thermal in situ steaming cycles. The increase in
production from Q1/12 was a result of the ramp up of thermal in situ production
as pads re-entered the production cycle.
- Primary heavy crude oil production achieved record quarterly production
exceeding 122,000 bbl/d representing an increase of 21% compared with Q2/11 and
an increase of 2% compared with Q1/12. Canadian Natural targets to drill 54
additional net primary heavy crude oil wells compared with the previous target,
for a targeted record of 872 net wells in 2012 and targets to increase annual
production by 21% over 2011. Primary heavy crude oil continues to provide the
highest return on capital projects in the portfolio.
- North America light crude oil and NGLs quarterly production increased 17% from
Q2/11 as a result of a successful light oil drilling program and increased
liquid recoveries from Septimus following the completion of a tie in to a deep
cut facility. North America light crude oil and NGLs is a significant part of
Canadian Natural's balanced portfolio, averaging approximately 62,500 bbl/d in
the quarter.
- At Pelican Lake, reservoir performance continues to be positive with July
production of approximately 40,000 bbl/d. The Company has commenced construction
of a 25,000 bbl/d battery to support targeted production growth from the polymer
flood and year-to-date has drilled 30 of the 72 net wells targeted for 2012.
Canadian Natural targets to ultimately recover 561 million barrels (363 million
barrels of proved plus probable reserves and 198 million barrels of contingent
resources) of additional crude oil through a disciplined multi-year expansion
plan.
- Canadian Natural's robust portfolio of thermal in situ projects is a
significant part of the Company's defined plan to transition to a longer-life,
more sustainable asset base with the ability to generate significant shareholder
value for decades to come. The Company targets to grow thermal in situ
production to approximately 500,000 bbl/d of capacity by delivering projects
that will add 40,000 bbl/d of production every two to three years.
-- As expected, thermal in situ production averaged approximately 94,000 bbl/d
in Q2/12 as pads began to re-enter the production cycle. Production is targeted
to ramp up to facility capacity in Q4/12. The Company targets to maximize steam
plant capacity through the completion of low cost pad-add projects at Primrose;
projects currently under construction are on schedule and on budget.
-- Thermal in situ operating costs for the quarter were $10.47/bbl as a result
of solid production, modest natural gas prices and strong operational
performance. The Company targets to achieve full year operating costs of
approximately $9.00/bbl in this segment of the Company.
-- Kirby South Phase 1 was 53% complete at the end of the second quarter. The
project remains on schedule with first steam-in targeted for Q4/13. Drilling is
nearing completion on the fourth of seven pads with wells confirming geological
expectations.
-- On Kirby North Phase 1, the 2012 statigraphic ("strat") test well drilling
program has been completed and procurement of long lead items is progressing.
First steam-in is targeted for early 2016.
-- At Grouse, design basis memorandum engineering is progressing on track with
completion targeted for 2012. First steam-in is targeted for late 2017.
- For Q3/12, the Company plans to drill 42 net thermal in situ wells and 290 net
crude oil wells, excluding strat test and service wells.
- As expected, North America crude oil and NGLs operating costs decreased to
$13.10/bbl in Q2/12 from $15.40/bbl in Q1/12. The decrease was primarily due to
reduced primary heavy crude oil operating costs as a result of strategic capital
investments made during the first half of 2012.
North America natural gas
Three Months Ended Six Months Ended
--------------------------------------------------
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
2012 2012 2011 2012 2011
----------------------------------------------------------------------------
Natural gas production
(MMcf/d) 1,230 1,281 1,218 1,255 1,221
----------------------------------------------------------------------------
Net wells targeting
natural gas 4 19 10 23 36
Net successful wells
drilled 4 19 10 23 35
----------------------------------------------------------------------------
Success rate 100% 100% 100% 100% 97%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
- North America natural gas production for the quarter averaged 1,230 MMcf/d
representing an increase of 1% from Q2/11 and a decrease of 4% from Q1/12. The
increase in production from Q2/11 reflects the impact of natural gas producing
properties acquired during 2011 and strong results from the Company's modest,
liquids rich drilling program. The decrease in production from Q1/12 was a
result of natural declines reflecting the Company's strategic decision to
allocate capital to higher return crude oil projects.
- Canadian Natural is the second largest producer of natural gas in Canada and
an industry leader in low natural gas operating costs. During 2012, the Company
has shut-in approximately 20 MMcf/d of natural gas in response to low natural
gas prices and currently has approximately 40 MMcf/d of natural gas shut-in.
- The continued weakness in natural gas prices has resulted in a further
reduction in capital allocated to natural gas. 2012 drilling has been reduced by
36 net wells compared with the original budget and the completion of 10 Septimus
wells has been deferred along with the facility expansion.
- As expected, North America natural gas operating costs decreased to $1.13/Mcf
in Q2/12 from $1.33/Mcf in Q1/12 as high operating cost properties acquired in
late 2011 were fully integrated with existing operations. Canadian Natural's
extensive infrastructure and land base combined with a disciplined approach is
what drives the Company's ability to create value in a modest commodity price
environment.
International Exploration and Production
Three Months Ended Six Months Ended
--------------------------------------------------
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
2012 2012 2011 2012 2011
----------------------------------------------------------------------------
Crude oil production
(bbl/d)
North Sea 17,619 23,046 32,866 20,333 33,480
Offshore Africa 20,598 20,712 21,334 20,655 23,400
----------------------------------------------------------------------------
Natural gas production
(MMcf/d)
North Sea 2 3 7 2 8
Offshore Africa 23 18 15 20 19
----------------------------------------------------------------------------
Net wells targeting crude
oil - - - - 0.9
Net successful wells
drilled - - - - 0.0
----------------------------------------------------------------------------
Success rate - - - - 0%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
- North Sea crude oil production averaged 17,619 bbl/d during Q2/12 representing
a decrease of 46% compared with Q2/11 and a decrease of 24% compared with Q1/12.
The decrease from Q2/11 was primarily a result of a 20 day shut-in of all Ninian
platforms and associated fields due to unplanned maintenance on a third party
pipeline and suspended operations at Banff/Kyle. In Q4/11 the Banff/Kyle
floating production storage offloading vessel ("FPSO") suffered damage from
severe storm conditions. The decrease from Q1/12 was primarily due to unplanned
maintenance on the third party pipeline that temporarily shut-in all Ninian
platforms and associated fields. Planned turnarounds at Ninian North and Ninian
Central and third party pipeline maintenance are scheduled for Q3/12.
- Production in Offshore Africa averaged 20,598 bbl/d during Q2/12 representing
a decrease of 3% compared with Q2/11 and a decrease of 1% compared with Q1/12.
The decrease from Q2/11 and Q1/12 was primarily a result of natural field
declines. The Company's eight well infill drilling program at the Espoir field
is targeted to commence in Q4/12. The Company targets additional production of
6,500 BOE/d at the completion of the Espoir drilling program.
- Conversion of the license of the Company's 100% working interest block in
South Africa was completed in the quarter and all regulatory requirements to
drill a well are complete. Targeted drilling windows are from Q4/13 to Q1/14 and
from Q4/14 to Q1/15.
North America Oil Sands Mining and Upgrading - Horizon
Three Months Ended Six Months Ended
--------------------------------------------------
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
2012 2012 2011 2012 2011
----------------------------------------------------------------------------
Synthetic crude oil
production
(bbl/d) 115,823 46,090 - 80,957 3,615
----------------------------------------------------------------------------
----------------------------------------------------------------------------
- Horizon demonstrated strong operational performance in the quarter. Production
averaged 115,823 bbl/d, highlighting the Company's commitment to safe, steady
and reliable operations and the positive impact of the third OPP being fully
operational. The third OPP has increased overall reliability and improved steady
operations in the upgrader.
- Enhanced operational discipline and focus on safe, steady and reliable
operations allows the Company to be proactive in planned maintenance activities.
Performance in Q2/12 along with proactive maintenance scheduled for Q3/12 gives
the Company confidence to increase full year mid-point guidance by 4% to 94,000
bbl/d for Horizon.
- As expected, operating costs for the quarter averaged $36.98/bbl. Through
future expansion, Canadian Natural targets to reduce operating costs per barrel
by increasing production disproportionately to largely fixed operating costs.
- Canadian Natural's staged expansion to 250,000 bbl/d of SCO production
capacity continues to progress on track. Thus far, several lump sum contracts
have been awarded and projects currently under construction are trending at or
below cost estimates. The Company's 100% working interest in this project allows
for significant capital flexibility; the 2012 project capital for Horizon was
reduced by $330 million to $1.55 billion. The decrease in 2012 capital is a
result of overall cost reductions and strategic deferrals to achieve greater
cost certainty.
MARKETING
Three Months Ended Six Months Ended
--------------------------------------------------
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
2012 2012 2011 2012 2011
----------------------------------------------------------------------------
Crude oil and NGLs pricing
WTI benchmark price
(US$/bbl) (1) $ 93.50 $ 102.94 $ 102.55 $ 98.22 $ 98.42
WCS blend differential from
WTI (%) (2) 24% 21% 17% 23% 20%
SCO price (US$/bbl) $ 89.54 $ 98.11 $ 115.65 $ 93.82 $ 105.50
Average realized pricing
before risk management
(C$/bbl) (3) $ 69.99 $ 80.08 $ 82.58 $ 74.95 $ 75.25
Natural gas pricing
AECO benchmark price
(C$/GJ) $ 1.74 $ 2.39 $ 3.54 $ 2.06 $ 3.56
Average realized pricing
before risk management
(C$/Mcf) $ 1.90 $ 2.47 $ 3.83 $ 2.19 $ 3.83
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) West Texas Intermediate ("WTI").
(2) Western Canadian Select ("WCS").
(3) Excludes SCO.
- In Q2/12, WTI pricing decreased by 9% from Q2/11 and Q1/12 partially due to
supply and demand imbalances.
- The WCS heavy crude oil differential as a percent of WTI averaged 24% in
Q2/12, in line with the Company's long term expectations and well below
historical averages. The WCS heavy differential widened from Q1/12 as a result
of planned and unplanned maintenance at key refineries in the United States and
Canada. The Company anticipates volatility in the differential in 2012 and
narrowing of the differential thereafter as additional conversion and pipeline
capacity come on stream.
- During Q2/12, Canadian Natural contributed 154,000 bbl/d of its heavy crude
oil stream to the WCS blend. The Company is the largest contributor of the WCS
blend, accounting for 53%.
- AECO benchmark natural gas prices weakened in Q2/12 compared with Q2/11 and
Q1/12 due to supply and demand imbalances in North America. AECO has increased
from a low of $1.43/GJ in April primarily due to increased seasonal demand and
increased demand from the power generation sector.
REDWATER UPGRADING AND REFINING
Supporting and participating in projects that add incremental conversion
capacity is a key part of the Company's marketing strategy. Canadian Natural, in
a partnership agreement with North West Upgrading Inc., continues to move
forward with detailed engineering regarding the construction and operation of a
bitumen refinery near Redwater, Alberta. Project development is dependent upon
completion of detailed engineering and final project sanction by the partnership
and its partners and approval of the final tolls. Board sanction is currently
targeted in 2012.
FINANCIAL REVIEW
The financial position of Canadian Natural remains strong as the Company
continues to implement proven strategies and focuses on disciplined capital
allocation. Canadian Natural's cash flow generation, credit facilities, diverse
asset base and related capital expenditure programs, and commodity hedging
policy all support a flexible financial position and provide the right financial
resources for the near, mid and long term.
- The Company's strategy is to maintain a diverse portfolio balanced across
various commodity types. The Company achieved record production of 679,607 BOE/d
for the quarter with over 96% of production located in G8 countries.
- Canadian Natural has a strong balance sheet with debt to book capitalization
of 26% and debt to EBITDA of 1.0. At June 30, 2012, long-term debt amounted to
$8.5 billion compared with $8.6 billion at December 31, 2011.
- During the quarter, the Company issued $500 million of 3.05% medium-term
unsecured notes due June 2019 to Canadian investors and extended the $1.5
billion revolving syndicated credit facility to June 2016.
- Canadian Natural maintains significant financial stability and liquidity
represented by approximately $4.4 billion in available unused bank lines at the
end of the quarter.
- The Company's commodity hedging program protects investment returns, ensures
ongoing balance sheet strength and supports the Company's cash flow for its
capital expenditures programs. The Company has hedged approximately half of the
remaining crude oil volumes forecasted for 2012 through a combination of puts
and collars.
- In Q2/12, Toronto Stock Exchange accepted notice of Canadian Natural's renewal
of its Normal Course Issuer Bid through the facilities of Toronto Stock Exchange
and the New York Stock Exchange. The notice provides that Canadian Natural may,
during the 12 month period commencing April 9, 2012 and ending April 8, 2013,
purchase for cancellation on Toronto Stock Exchange and the New York Stock
Exchange up to 55,027,447 shares.
- To date in 2012, Canadian Natural has purchased 6,196,600 common shares for
cancellation at a weighted average price of $28.91 per common share.
- Declared a quarterly cash dividend on common shares of $0.105 per common share
payable October 1, 2012.
OUTLOOK
The Company forecasts 2012 production levels before royalties to average between
1,220 and 1,235 MMcf/d of natural gas and between 454,000 and 474,000 bbl/d of
crude oil and NGLs. Q3/12 production guidance before royalties is forecast to
average between 1,170 and 1,190 MMcf/d of natural gas and between 451,000 and
480,000 bbl/d of crude oil and NGLs. Detailed guidance on production levels,
capital allocation and operating costs can be found on the Company's website at
www.cnrl.com.
MANAGEMENT'S DISCUSSION AND ANALYSIS
Forward-Looking Statements
Certain statements relating to Canadian Natural Resources Limited (the
"Company") in this document or documents incorporated herein by reference
constitute forward-looking statements or information (collectively referred to
herein as "forward-looking statements") within the meaning of applicable
securities legislation. Forward-looking statements can be identified by the
words "believe", "anticipate", "expect", "plan", "estimate", "target",
"continue", "could", "intend", "may", "potential", "predict", "should", "will",
"objective", "project", "forecast", "goal", "guidance", "outlook", "effort",
"seeks", "schedule" or expressions of a similar nature suggesting future outcome
or statements regarding an outlook. Disclosure related to expected future
commodity pricing, forecast or anticipated production volumes and costs,
royalties, operating costs, capital expenditures, income tax expenses and other
guidance provided throughout this Management's Discussion and Analysis ("MD&A"),
constitute forward-looking statements. Disclosure of plans relating to and
expected results of existing and future developments, including but not limited
to the Horizon Oil Sands operations and future expansions, Primrose, Pelican
Lake, the Kirby Thermal Oil Sands Project, the Keystone XL Pipeline US Gulf
Coast expansion, and the construction and future operations of the North West
Redwater bitumen upgrader and refinery also constitute forward-looking
statements. This forward-looking information is based on annual budgets and
multi-year forecasts, and is reviewed and revised throughout the year as
necessary in the context of targeted financial ratios, project returns, product
pricing expectations and balance in project risk and time horizons. These
statements are not guarantees of future performance and are subject to certain
risks. The reader should not place undue reliance on these forward-looking
statements as there can be no assurances that the plans, initiatives or
expectations upon which they are based will occur.
In addition, statements relating to "reserves" are deemed to be forward-looking
statements as they involve the implied assessment based on certain estimates and
assumptions that the reserves described can be profitably produced in the
future. There are numerous uncertainties inherent in estimating quantities of
proved and proved plus probable crude oil and natural gas reserves and in
projecting future rates of production and the timing of development
expenditures. The total amount or timing of actual future production may vary
significantly from reserve and production estimates.
The forward-looking statements are based on current expectations, estimates and
projections about the Company and the industry in which the Company operates,
which speak only as of the date such statements were made or as of the date of
the report or document in which they are contained, and are subject to known and
unknown risks and uncertainties that could cause the actual results, performance
or achievements of the Company to be materially different from any future
results, performance or achievements expressed or implied by such
forward-looking statements. Such risks and uncertainties include, among others:
general economic and business conditions which will, among other things, impact
demand for and market prices of the Company's products; volatility of and
assumptions regarding crude oil and natural gas prices; fluctuations in currency
and interest rates; assumptions on which the Company's current guidance is
based; economic conditions in the countries and regions in which the Company
conducts business; political uncertainty, including actions of or against
terrorists, insurgent groups or other conflict including conflict between
states; industry capacity; ability of the Company to implement its business
strategy, including exploration and development activities; impact of
competition; the Company's defense of lawsuits; availability and cost of
seismic, drilling and other equipment; ability of the Company and its
subsidiaries to complete capital programs; the Company's and its subsidiaries'
ability to secure adequate transportation for its products; unexpected
disruptions or delays in the resumption of the mining, extracting or upgrading
of the Company's bitumen products; potential delays or changes in plans with
respect to exploration or development projects or capital expenditures; ability
of the Company to attract the necessary labour required to build its thermal and
oil sands mining projects; operating hazards and other difficulties inherent in
the exploration for and production and sale of crude oil and natural gas and in
mining, extracting or upgrading the Company's bitumen products; availability and
cost of financing; the Company's and its subsidiaries' success of exploration
and development activities and their ability to replace and expand crude oil and
natural gas reserves; timing and success of integrating the business and
operations of acquired companies; production levels; imprecision of reserve
estimates and estimates of recoverable quantities of crude oil, natural gas and
natural gas liquids ("NGLs") not currently classified as proved; actions by
governmental authorities; government regulations and the expenditures required
to comply with them (especially safety and environmental laws and regulations
and the impact of climate change initiatives on capital and operating costs);
asset retirement obligations; the adequacy of the Company's provision for taxes;
and other circumstances affecting revenues and expenses.
The Company's operations have been, and in the future may be, affected by
political developments and by federal, provincial and local laws and regulations
such as restrictions on production, changes in taxes, royalties and other
amounts payable to governments or governmental agencies, price or gathering rate
controls and environmental protection regulations. Should one or more of these
risks or uncertainties materialize, or should any of the Company's assumptions
prove incorrect, actual results may vary in material respects from those
projected in the forward-looking statements. The impact of any one factor on a
particular forward-looking statement is not determinable with certainty as such
factors are dependent upon other factors, and the Company's course of action
would depend upon its assessment of the future considering all information then
available.
Readers are cautioned that the foregoing list of factors is not exhaustive.
Unpredictable or unknown factors not discussed in this report could also have
material adverse effects on forward-looking statements. Although the Company
believes that the expectations conveyed by the forward-looking statements are
reasonable based on information available to it on the date such forward-looking
statements are made, no assurances can be given as to future results, levels of
activity and achievements. All subsequent forward-looking statements, whether
written or oral, attributable to the Company or persons acting on its behalf are
expressly qualified in their entirety by these cautionary statements. Except as
required by law, the Company assumes no obligation to update forward-looking
statements, whether as a result of new information, future events or other
factors, or the foregoing factors affecting this information, should
circumstances or Management's estimates or opinions change.
Management's Discussion and Analysis
This MD&A of the financial condition and results of operations of the Company
should be read in conjunction with the unaudited interim consolidated financial
statements for the three and six months ended June 30, 2012 and the MD&A and the
audited consolidated financial statements for the year ended December 31, 2011.
All dollar amounts are referenced in millions of Canadian dollars, except where
noted otherwise. The Company's consolidated financial statements for the period
ended June 30, 2012 and this MD&A have been prepared in accordance with
International Financial Reporting Standards ("IFRS"), as issued by the
International Accounting Standards Board. Unless otherwise stated, 2010
comparative figures have been restated in accordance with IFRS issued as at
December 31, 2011. This MD&A includes references to financial measures commonly
used in the crude oil and natural gas industry, such as adjusted net earnings
from operations, cash flow from operations, and cash production costs. These
financial measures are not defined by IFRS and therefore are referred to as
non-GAAP measures. The non-GAAP measures used by the Company may not be
comparable to similar measures presented by other companies. The Company uses
these non-GAAP measures to evaluate its performance. The non-GAAP measures
should not be considered an alternative to or more meaningful than net earnings,
as determined in accordance with IFRS, as an indication of the Company's
performance. The non-GAAP measures adjusted net earnings from operations and
cash flow from operations are reconciled to net earnings, as determined in
accordance with IFRS, in the "Financial Highlights" section of this MD&A. The
derivation of cash production costs is included in the "Operating Highlights -
Oil Sands Mining and Upgrading" section of this MD&A. The Company also presents
certain non-GAAP financial ratios and their derivation in the "Liquidity and
Capital Resources" section of this MD&A.
A Barrel of Oil Equivalent ("BOE") is derived by converting six thousand cubic
feet of natural gas to one barrel of crude oil (6 Mcf:1 bbl). This conversion
may be misleading, particularly if used in isolation, since the 6 Mcf:1 bbl
ratio is based on an energy equivalency conversion method primarily applicable
at the burner tip and does not represent a value equivalency at the wellhead. In
comparing the value ratio using current crude oil prices relative to natural gas
prices, the 6 Mcf:1 bbl conversion ratio may be misleading as an indication of
value. In addition, for the purposes of this MD&A, crude oil is defined to
include the following commodities: light and medium crude oil, primary heavy
crude oil, Pelican Lake heavy crude oil, bitumen (thermal oil), and synthetic
crude oil.
Production volumes and per unit statistics are presented throughout this MD&A on
a "before royalty" or "gross" basis, and realized prices are net of
transportation and blending costs and exclude the effect of risk management
activities. Production on an "after royalty" or "net" basis is also presented
for information purposes only.
The following discussion refers primarily to the Company's financial results for
the three and six months ended June 30, 2012 in relation to the comparable
periods in 2011 and the first quarter of 2012. The accompanying tables form an
integral part of this MD&A. This MD&A is dated August 8, 2012. Additional
information relating to the Company, including its Annual Information Form for
the year ended December 31, 2011, is available on SEDAR at www.sedar.com, and on
EDGAR at www.sec.gov.
FINANCIAL HIGHLIGHTS
($ millions, except per common share amounts)
Three Months Ended Six Months Ended
-------------------------------------------------
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
2012 2012 2011 2012 2011
----------------------------------------------------------------------------
Product sales $ 4,187 $ 3,971 $ 3,727 $ 8,158 $ 7,029
Net earnings $ 753 $ 427 $ 929 $ 1,180 $ 975
Per common share - basic $ 0.68 $ 0.39 $ 0.85 $ 1.07 $ 0.89
- diluted $ 0.68 $ 0.39 $ 0.84 $ 1.07 $ 0.88
Adjusted net earnings from
operations (1) $ 606 $ 300 $ 621 $ 906 $ 849
Per common share - basic $ 0.55 $ 0.27 $ 0.57 $ 0.82 $ 0.78
- diluted $ 0.55 $ 0.27 $ 0.56 $ 0.82 $ 0.77
Cash flow from operations
(2) $ 1,754 $ 1,280 $ 1,548 $ 3,034 $ 2,622
Per common share - basic $ 1.60 $ 1.16 $ 1.41 $ 2.76 $ 2.39
- diluted $ 1.59 $ 1.16 $ 1.40 $ 2.75 $ 2.37
Capital expenditures, net
of dispositions $ 1,324 $ 1,596 $ 1,405 $ 2,920 $ 3,099
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Adjusted net earnings from operations is a non-GAAP measure that
represents net earnings adjusted for certain items of a non-operational
nature. The Company evaluates its performance based on adjusted net
earnings from operations. The reconciliation "Adjusted Net Earnings from
Operations" presented below lists the after-tax effects of certain items
of a non-operational nature that are included in the Company's financial
results. Adjusted net earnings from operations may not be comparable to
similar measures presented by other companies.
(2) Cash flow from operations is a non-GAAP measure that represents net
earnings adjusted for non-cash items before working capital adjustments.
The Company evaluates its performance based on cash flow from
operations. The Company considers cash flow from operations a key
measure as it demonstrates the Company's ability to generate the cash
flow necessary to fund future growth through capital investment and to
repay debt. The reconciliation "Cash Flow from Operations" presented
lists certain non-cash items that are included in the Company's
financial results. Cash flow from operations may not be comparable to
similar measures presented by other companies.
Adjusted Net Earnings from Operations
Three Months Ended Six Months Ended
--------------------------------------------------
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
($ millions) 2012 2012 2011 2012 2011
----------------------------------------------------------------------------
Net earnings as reported $ 753 $ 427 $ 929 $ 1,180 $ 975
Share-based compensation
recovery, net of tax (1) (115) (107) (188) (222) (60)
Unrealized risk management
(gain) loss, net of tax
(2) (103) 40 (87) (63) (48)
Unrealized foreign
exchange loss (gain), net
of tax (3) 71 (60) (33) 11 (122)
Effect of statutory tax
rate and other
legislative changes on
deferred income
tax liabilities (4) - - - - 104
----------------------------------------------------------------------------
Adjusted net earnings from
operations $ 606 $ 300 $ 621 $ 906 $ 849
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) The Company's employee stock option plan provides for a cash payment
option. Accordingly, the fair value of the outstanding vested options is
recorded as a liability on the Company's balance sheets and periodic
changes in the fair value are recognized in net earnings or are
capitalized to Oil Sands Mining and Upgrading construction costs.
(2) Derivative financial instruments are recorded at fair value on the
balance sheets, with changes in fair value of non-designated hedges
recognized in net earnings. The amounts ultimately realized may be
materially different than reflected in the financial statements due to
changes in prices of the underlying items hedged, primarily crude oil
and natural gas.
(3) Unrealized foreign exchange gains and losses result primarily from the
translation of US dollar denominated long-term debt to period-end
exchange rates, partially offset by the impact of cross currency swaps,
and are recognized in net earnings.
(4) 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 first quarter of
2011, the UK government enacted an increase to the corporate income tax
rate charged on profits from UK North Sea crude oil and natural gas
production from 50% to 62%. The Company's deferred income tax liability
was increased by $104 million with respect to this tax rate change.
Cash Flow from Operations
Three Months Ended Six Months Ended
--------------------------------------------------
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
($ millions) 2012 2012 2011 2012 2011
----------------------------------------------------------------------------
Net earnings $ 753 $ 427 $ 929 $ 1,180 $ 975
Non-cash items:
Depletion, depreciation
and amortization 1,084 975 870 2,059 1,719
Share-based compensation
recovery (115) (107) (188) (222) (60)
Asset retirement
obligation accretion 38 37 31 75 64
Unrealized risk
management (gain) loss (144) 60 (118) (84) (64)
Unrealized foreign
exchange loss (gain) 71 (60) (33) 11 (122)
Deferred income tax
expense (recovery) 62 (52) 57 10 110
Horizon asset impairment
provision - - - - 396
Equity loss from jointly
controlled entity 5 - - 5 -
Insurance recovery -
property damage - - - - (396)
----------------------------------------------------------------------------
Cash flow from operations $ 1,754 $ 1,280 $ 1,548 $ 3,034 $ 2,622
----------------------------------------------------------------------------
----------------------------------------------------------------------------
SUMMARY OF CONSOLIDATED NET EARNINGS AND CASH FLOW FROM OPERATIONS
Net earnings for the six months ended June 30, 2012 were $1,180 million compared
with $975 million for the six months ended June 30, 2011. Net earnings for the
six months ended June 30, 2012 included net unrealized after-tax income of $274
million compared with net unrealized after-tax income of $126 million for the
six months ended June 30, 2011 related to the effects of share-based
compensation, risk management activities, fluctuations in foreign exchange
rates, 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, 2012 were $906 million
compared with $849 million for the six months ended June 30, 2011.
Net earnings for the second quarter of 2012 were $753 million compared with $929
million for the second quarter of 2011 and $427 million for the first quarter of
2012. Net earnings for the second quarter of 2012 included net unrealized
after-tax income of $147 million compared with $308 million for the second
quarter of 2011 and $127 million for the first quarter of 2012 related to the
effects of share-based compensation, risk management activities and fluctuations
in foreign exchange rates. Excluding these items, adjusted net earnings from
operations for the second quarter of 2012 were $606 million compared with $621
million for the second quarter of 2011 and $300 million for the first quarter of
2012.
The increase in adjusted net earnings for the six months ended June 30, 2012
from the comparable period in 2011 was primarily due to:
- higher crude oil and synthetic crude oil ("SCO") sales volumes in the North
America and Oil Sands Mining and Upgrading segments;
- the impact of a weaker Canadian dollar; and
- fluctuations in realized risk management gains and losses;
partially offset by:
- lower crude oil and NGLs and natural gas netbacks;
- lower SCO prices; and
- higher depletion, depreciation and amortization expense.
The decrease in adjusted net earnings for the second quarter of 2012 from the
comparable period of 2011 was primarily due to:
- lower crude oil and NGLs and natural gas netbacks; and
- higher depletion, depreciation and amortization expense;
partially offset by:
- higher crude oil and SCO sales volumes in the North America and Oil Sands
Mining and Upgrading segments;
- higher natural gas sales volumes;
- the impact of a weaker Canadian dollar; and
- fluctuations in realized risk management gains and losses.
The increase in adjusted net earnings for the second quarter of 2012 from the
first quarter of 2012 was primarily due to:
- higher crude oil and SCO sales volumes in the North America and Oil Sands
Mining and Upgrading segments;
- the impact of a weaker Canadian dollar; and
- fluctuations in realized risk management gains and losses;
partially offset by:
- lower crude oil and NGLs and natural gas netbacks;
- lower SCO prices; and
- higher depletion, depreciation and amortization expense.
The impacts of share-based compensation, risk management activities and changes
in foreign exchange rates are expected to continue to contribute to quarterly
volatility in consolidated net earnings and are discussed in detail in the
relevant sections of this MD&A.
Cash flow from operations for the six months ended June 30, 2012 was $3,034
million compared with $2,622 million for the six months ended June 30, 2011.
Cash flow from operations for the second quarter of 2012 was $1,754 million
compared with $1,548 million for the second quarter of 2011 and $1,280 million
for the first quarter of 2012. The increase in cash flow from operations from
the comparable periods was primarily due to the factors noted above relating to
the fluctuations in adjusted net earnings, excluding depletion, depreciation and
amortization expense.
Total production before royalties for the six months ended June 30, 2012
increased 15% to 645,943 BOE/d from 561,359 BOE/d for the six months ended June
30, 2011. Total production before royalties for the second quarter of 2012
increased 22% to a record 679,607 BOE/d from 556,539 BOE/d for the second
quarter of 2011 and 11% from 612,279 BOE/d for the first quarter of 2012.
Production for the second quarter of 2012 was within the Company's previously
issued guidance.
SUMMARY OF QUARTERLY RESULTS
The following is a summary of the Company's quarterly results for the eight most
recently completed quarters:
($ millions, except per Jun 30 Mar 31 Dec 31 Sep 30
common share amounts) 2012 2012 2011 2011
----------------------------------------------------------------------------
Product sales $ 4,187 $ 3,971 $ 4,788 $ 3,690
Net earnings (loss) $ 753 $ 427 $ 832 $ 836
Net earnings (loss) per
common share
- basic $ 0.68 $ 0.39 $ 0.76 $ 0.76
- diluted $ 0.68 $ 0.39 $ 0.76 $ 0.76
----------------------------------------------------------------------------
----------------------------------------------------------------------------
($ millions, except per Jun 30 Mar 31 Dec 31 Sep 30
common share amounts) 2011 2011 2010 2010
----------------------------------------------------------------------------
Product sales $ 3,727 $ 3,302 $ 3,787 $ 3,341
Net earnings (loss) $ 929 $ 46 $ (309) $ 596
Net earnings (loss) per
common share
- basic $ 0.85 $ 0.04 $ (0.28) $ 0.54
- diluted $ 0.84 $ 0.04 $ (0.28) $ 0.54
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Volatility in the quarterly net earnings (loss) over the eight most recently
completed quarters was primarily due to:
- Crude oil pricing - The impact of fluctuating demand, inventory storage levels
and geopolitical uncertainties on worldwide benchmark pricing, the impact of the
WCS Heavy Differential from 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, as well as fluctuations in imports of liquefied natural
gas into 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, a record heavy oil drilling
program, and the impact of the suspension and recommencement of production at
Horizon. Sales volumes also reflected fluctuations due to timing of liftings and
maintenance activities in the North Sea and Offshore Africa, and payout of the
Baobab field in May 2011.
- Natural gas sales volumes - Fluctuations in production due to the Company's
strategic decision to reduce natural gas drilling activity in North America and
the allocation of capital to higher return crude oil projects, as well as
natural decline rates and the impact and timing of acquisitions.
- Production expense - Fluctuations primarily due to the impact of the demand
for services, fluctuations in product mix, the impact of seasonal costs that are
dependent on weather, production and cost optimizations in North America,
acquisitions of natural gas producing properties that have higher operating
costs per Mcf than the Company's existing properties, and the suspension and
recommencement of production at Horizon.
- Depletion, depreciation and amortization - Fluctuations due to changes in
sales volumes, proved reserves, finding and development costs associated with
crude oil and natural gas exploration, estimated future costs to develop the
Company's proved undeveloped reserves, the impact of the suspension and
recommencement of production at Horizon and the impact of impairments at the
Olowi field in offshore Gabon.
- Share-based compensation - Fluctuations due to the determination of fair
market value based on the Black-Scholes valuation model of the Company's
share-based compensation liability.
- Risk management - Fluctuations due to the recognition of gains and losses from
the mark-to-market and subsequent settlement of the Company's risk management
activities.
- Foreign exchange rates - Changes in the Canadian dollar relative to the US
dollar that impacted the realized price the Company received for its crude oil
and natural gas sales, as sales prices are based predominately on US dollar
denominated benchmarks. Fluctuations in realized and unrealized foreign exchange
gains and losses are recorded with respect to US dollar denominated debt,
partially offset by the impact of cross currency swap hedges.
- Income tax expense - Fluctuations in income tax expense include statutory tax
rate and other legislative changes substantively enacted in the various periods.
BUSINESS ENVIRONMENT
Three Months Ended Six Months Ended
--------------------------------------------------
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
2012 2012 2011 2012 2011
----------------------------------------------------------------------------
WTI benchmark price
(US$/bbl) (1) $ 93.50 $ 102.94 $ 102.55 $ 98.22 $ 98.42
Dated Brent benchmark
price (US$/bbl) $ 108.21 $ 118.47 $ 117.33 $ 113.34 $ 111.20
WCS blend differential
from WTI (US$/bbl) $ 22.83 $ 21.47 $ 17.62 $ 22.15 $ 20.17
WCS blend differential
from WTI (%) 24% 21% 17% 23% 20%
SCO price (US$/bbl) (2) $ 89.54 $ 98.11 $ 115.65 $ 93.82 $ 105.50
Condensate benchmark price
(US$/bbl) $ 99.49 $ 110.05 $ 112.48 $ 104.77 $ 105.56
NYMEX benchmark price
(US$/MMBtu) $ 2.26 $ 2.77 $ 4.36 $ 2.52 $ 4.24
AECO benchmark price
(C$/GJ) $ 1.74 $ 2.39 $ 3.54 $ 2.06 $ 3.56
US/Canadian dollar average
exchange rate (US$) $ 0.9897 $ 0.9989 $ 1.0331 $ 0.9943 $ 1.0238
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) West Texas Intermediate ("WTI")
(2) Synthetic Crude Oil ("SCO")
Commodity Prices
Crude oil sales contracts in the North America segment are typically based on
WTI benchmark pricing. WTI averaged US$98.22 per bbl for the six months ended
June 30, 2012 and was comparable with the six months ended June 30, 2011. WTI
averaged US$93.50 per bbl for the second quarter of 2012, a decrease of 9% from
US$102.55 per bbl for the second quarter of 2011 and US$102.94 per bbl for the
first quarter of 2012. WTI pricing was reflective of the political instability
in the Middle East offset by declining optimism in the United States economy,
the European debt crisis, and lower than expected growth in Asian demand.
Crude oil sales contracts for the Company's North Sea and Offshore Africa
segments are typically based on Dated Brent ("Brent") pricing, which is
representative of international markets and overall world supply and demand.
Brent averaged US$113.34 per bbl for the six months ended June 30, 2012, an
increase of 2% compared with US$111.20 per bbl for the six months ended June 30,
2011. Brent averaged US$108.21 per bbl for the second quarter of 2012, a
decrease of 8% compared with US$117.33 per bbl for the second quarter of 2011
and a decrease of 9% from US$118.47 per bbl for the first quarter of 2012. The
higher Brent pricing relative to WTI was due to logistical constraints and high
inventory levels of crude oil at Cushing.
The WCS Heavy Differential averaged 23% for the six months ended June 30, 2012
compared with 20% for the six months ended June 30, 2011. The WCS Heavy
Differential averaged 24% for the second quarter of 2012 compared with 17% in
the second quarter of 2011, and 21% for the first quarter of 2012. The WCS Heavy
Differential widened in the second quarter of 2012, relative to the comparable
periods, as a result of planned and unplanned maintenance at key refineries
accessible by Canadian crude oil.
The Company uses condensate as a blending diluent for heavy crude oil pipeline
shipments. During the second quarter of 2012, condensate prices continued to
trade at a premium to WTI, similar to prior periods, reflecting normal
seasonality.
The Company anticipates continued volatility in crude oil pricing benchmarks due
to supply and demand factors, geopolitical events, and the timing and extent of
the continuing economic recovery. The WCS Heavy Differential is expected to
continue to reflect seasonal demand fluctuations, changes in transportation
logistics, and refinery utilization and shutdowns.
NYMEX natural gas prices averaged US$2.52 per MMBtu for the six months ended
June 30, 2012, a decrease of 41% from US$4.24 per MMBtu for the six months ended
June 30, 2011. NYMEX natural gas prices averaged US$2.26 per MMBtu for the
second quarter of 2012, a decrease of 48% from US$4.36 per MMBtu for the second
quarter of 2011, and a decrease of 18% from US$2.77 per MMBtu for the first
quarter of 2012.
AECO natural gas prices for the six months ended June 30, 2012 averaged $2.06
per GJ, a decrease of 42% from $3.56 per GJ for the six months ended June 30,
2011. AECO natural gas prices for the second quarter of 2012 averaged $1.74 per
GJ, a decrease of 51% from $3.54 per GJ for the second quarter of 2011, and a
decrease of 27% from $2.39 per GJ for the first quarter of 2012.
During the second quarter of 2012, natural gas prices continued to be weak in
response to the strong North America supply position, primarily from the highly
productive shale areas. However, the AECO natural gas price has increased from
its low of $1.43 per GJ in April 2012 due to higher weather related gas demand
resulting from warmer than normal spring and summer temperatures, together with
a shift to higher utilization of gas fired electric generators due to the low
natural gas prices.
DAILY PRODUCTION, before royalties
Three Months Ended Six Months Ended
--------------------------------------------------
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
2012 2012 2011 2012 2011
----------------------------------------------------------------------------
Crude oil and NGLs (bbl/d)
North America -
Exploration and
Production 316,483 305,613 295,715 311,048 292,938
North America - Oil Sands
Mining and Upgrading 115,823 46,090 - 80,957 3,615
North Sea 17,619 23,046 32,866 20,333 33,480
Offshore Africa 20,598 20,712 21,334 20,655 23,400
----------------------------------------------------------------------------
470,523 395,461 349,915 432,993 353,433
----------------------------------------------------------------------------
Natural gas (MMcf/d)
North America 1,230 1,281 1,218 1,255 1,221
North Sea 2 3 7 2 8
Offshore Africa 23 18 15 20 19
----------------------------------------------------------------------------
1,255 1,302 1,240 1,277 1,248
----------------------------------------------------------------------------
Total barrels of oil
equivalent (BOE/d) 679,607 612,279 556,539 645,943 561,359
----------------------------------------------------------------------------
Product mix
Light and medium crude oil
and NGLs 15% 18% 20% 15% 20%
Pelican Lake heavy crude
oil 5% 6% 6% 6% 6%
Primary heavy crude oil 18% 20% 18% 19% 18%
Bitumen (thermal oil) 14% 13% 19% 14% 18%
Synthetic crude oil 17% 8% - 13% 1%
Natural gas 31% 35% 37% 33% 37%
----------------------------------------------------------------------------
Percentage of product
sales (1) (excluding
midstream revenue)
Crude oil and NGLs 93% 91% 85% 92% 84%
Natural gas 7% 9% 15% 8% 16%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Net of transportation and blending costs and excluding risk management
activities.
DAILY PRODUCTION, net of royalties
Three Months Ended Six Months Ended
--------------------------------------------------
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
2012 2012 2011 2012 2011
----------------------------------------------------------------------------
Crude oil and NGLs (bbl/d)
North America -
Exploration and
Production 272,089 253,951 243,943 263,020 238,777
North America - Oil Sands
Mining and Upgrading 109,569 43,599 - 76,584 3,324
North Sea 17,578 22,986 32,793 20,282 33,397
Offshore Africa 15,051 17,497 21,196 16,274 22,199
----------------------------------------------------------------------------
414,287 338,033 297,932 376,160 297,697
----------------------------------------------------------------------------
Natural gas (MMcf/d)
North America 1,218 1,277 1,146 1,247 1,171
North Sea 2 3 7 2 8
Offshore Africa 19 15 13 17 16
----------------------------------------------------------------------------
1,239 1,295 1,166 1,266 1,195
----------------------------------------------------------------------------
Total barrels of oil
equivalent (BOE/d) 620,700 553,752 492,250 587,226 496,909
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The Company's business approach is to maintain large project inventories and
production diversification among each of the commodities it produces; namely
natural gas, light and medium crude oil and NGLs, Pelican Lake heavy crude oil,
primary heavy crude oil, bitumen (thermal oil) and SCO.
Crude oil and NGLs production for the six months ended June 30, 2012 increased
23% to 432,993 bbl/d from 353,433 bbl/d for the six months ended June 30, 2011.
Crude oil and NGLs production for the second quarter of 2012 increased 34% to
470,523 bbl/d from 349,915 bbl/d for the second quarter of 2011 and increased
19% from 395,461 bbl/d for the first quarter of 2012. The increase in production
from the comparable periods was primarily related to increased production at
Horizon, the impact of a strong heavy crude oil drilling program, and the cyclic
nature of the Company's thermal operations. Crude oil and NGLs production in the
second quarter of 2012 was within the Company's previously issued guidance of
453,000 to 482,000 bbl/d.
Natural gas production for the six months ended June 30, 2012 increased by 2% to
1,277 MMcf/d from 1,248 MMcf/d for the six months ended June 30, 2011. Natural
gas production for the second quarter of 2012 increased by 1% to 1,255 MMcf/d
from 1,240 MMcf/d from the second quarter of 2011 and decreased by 4% from 1,302
MMcf/d for the first quarter of 2012. The increase in natural gas production
from the comparable periods in 2011 reflects the impact of natural gas producing
properties acquired during 2011. The decrease in natural gas production for the
second quarter of 2012 from the first quarter of 2012 was primarily a result of
expected production declines due to the allocation of capital to higher return
crude oil projects, which continue to result in a strategic reduction of natural
gas drilling activity. The Company shut in approximately 20 MMcf/d of natural
gas production in 2012 and overall has shut in 40 MMcf/d due to the decrease in
natural gas prices. Natural gas production in the second quarter of 2012 was
within the Company's previously issued guidance of 1,250 to 1,270 MMcf/d.
For 2012, annual production guidance is targeted to average between 454,000 and
474,000 bbl/d of crude oil and NGLs and between 1,220 and 1,235 MMcf/d of
natural gas. Third quarter 2012 production guidance is targeted to average
between 451,000 and 480,000 bbl/d of crude oil and NGLs and between 1,170 and
1,190 MMcf/d of natural gas.
North America - Exploration and Production
North America crude oil and NGLs production for the six months ended June 30,
2012 increased 6% to average 311,048 bbl/d from 292,938 bbl/d for the six months
ended June 30, 2011. For the second quarter of 2012, crude oil and NGLs
production increased 7% to average 316,483 bbl/d compared with 295,715 bbl/d for
the second quarter of 2011 and increased 4% from 305,613 bbl/d for the first
quarter of 2012. Increases in crude oil and NGLs production from comparable
periods were primarily due to the impact of a strong heavy crude oil drilling
program. The increase in crude oil production for the second quarter was also
impacted by the cyclic nature of the Company's thermal operations. Production of
crude oil and NGLs was within the Company's previously issued guidance of
312,000 bbl/d to 325,000 bbl/d for the second quarter of 2012. Third quarter
2012 production guidance is targeted to average between 322,000 and 335,000
bbl/d of crude oil and NGLs.
Natural gas production for the six months ended June 30, 2012 increased 3% to
1,255 MMcf/d compared with 1,221 MMcf/d for the six months ended June 30, 2011.
Natural gas production increased 1% to 1,230 MMcf/d for the second quarter of
2012 compared with 1,218 MMcf/d in the second quarter of 2011 and decreased 4%
compared with 1,281 MMcf/d in the first quarter of 2012. Natural gas production
for the six months ended June 30, 2012 increased from the comparable period in
2011 due to the impact of natural gas producing properties acquired during 2011.
The decrease in natural gas production for the second quarter of 2012 from the
first quarter of 2012 was primarily a result of expected production declines due
to the allocation of capital to higher return crude oil projects, which continue
to result in a strategic reduction of natural gas drilling activity. The Company
has reduced its drilling activities and shut in approximately 40 MMcf/d of gas
volumes due to the decline in natural gas prices.
North America - Oil Sands Mining and Upgrading
Production averaged 80,957 bbl/d for the six months ended June 30, 2012 from
3,615 bbl/d for the six months ended June 30, 2011. For the second quarter of
2012, SCO production averaged a record 115,823 bbl/d compared with no production
for the second quarter of 2011 and 46,090 bbl/d for the first quarter of 2012,
related to suspension of production during these periods.
On March 13, 2012 the Company successfully and safely completed the unplanned
maintenance on the fractionating unit in the primary upgrading facility. The
positive impact of the third ore preparation plant ("OPP") and continued
emphasis on safe, steady and reliable operations resulted in strong operational
performance across Horizon, with production exceeding the Company's previously
issued guidance of between 105,000 and 115,000 bbl/d of SCO for the second
quarter of 2012.
North Sea
North Sea crude oil production for the six months ended June 30, 2012 decreased
39% to 20,333 bbl/d from 33,480 bbl/d for the six months ended June 30, 2011.
Second quarter 2012 North Sea crude oil production decreased 46% to 17,619 bbl/d
from 32,866 bbl/d for the second quarter of 2011, and decreased 24% from 23,046
bbl/d for the first quarter of 2012. The decrease in production volumes from the
comparable periods in 2011 was primarily due to a 20- day shut in of the
third-party operated pipeline to Sullom Voe for unplanned maintenance, which
caused all Ninian and associated fields to be shut in, the suspension of
production at Banff/Kyle, and natural field declines due to curtailment of
development activities in the North Sea as a result of corporate tax increases
that were enacted in 2011. The decrease in production volumes from the first
quarter of 2012 was the result of the temporary shut in of the third-party
operated pipeline. In December 2011, the Banff Floating Production, Storage and
Offloading Vessel ("FPSO") and subsea infrastructure suffered storm damage.
Operations at Banff/Kyle, with combined net production of approximately 3,500
bbl/d, were suspended and appropriate shut-down procedures were activated. The
FPSO and associated floating storage unit have subsequently been removed from
the field. The extent of the damage, including associated costs and related
property damage, are not expected to be significant. The timing of returning to
the field is currently being assessed.
Offshore Africa
Offshore Africa crude oil production decreased 12% to 20,655 bbl/d for the six
months ended June 30, 2012 from 23,400 bbl/d for the six months ended June 30,
2011. Second quarter crude oil production averaged 20,598 bbl/d, decreasing 3%
from 21,334 bbl/d for the second quarter of 2011, and was comparable to 20,712
bbl/d in the first quarter of 2012. The decrease in production volumes from the
comparable periods in 2011 was due to natural field declines.
International Guidance
The Company's North Sea and Offshore Africa second quarter 2012 crude oil and
NGLs production was within the Company's previously issued guidance of 36,000 to
42,000 bbl/d. Third quarter 2012 production guidance is targeted to average
between 34,000 and 40,000 bbl/d of crude oil.
Crude Oil Inventory Volumes
The Company recognizes revenue on its crude oil production when title transfers
to the customer and delivery has taken place. Revenue has not been recognized on
crude oil volumes that were stored in various tanks, pipelines, or floating
production, storage and offloading vessels, as follows:
------------------------------
Jun 30 Mar 31 Dec 31
(bbl) 2012 2012 2011
----------------------------------------------------------------------------
North America - Exploration and Production 587,765 621,277 557,475
North America - Oil Sands Mining and Upgrading
(SCO) 1,077,734 1,053,025 1,021,236
North Sea - 84,112 286,633
Offshore Africa 678,540 853,074 527,312
----------------------------------------------------------------------------
2,344,039 2,611,488 2,392,656
----------------------------------------------------------------------------
----------------------------------------------------------------------------
OPERATING HIGHLIGHTS - EXPLORATION AND PRODUCTION
Three Months Ended Six Months Ended
-------------------------------------------------
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
2012 2012 2011 2012 2011
----------------------------------------------------------------------------
Crude oil and NGLs ($/bbl)
(1)
Sales price (2) $ 69.99 $ 80.08 $ 82.58 $ 74.95 $ 75.25
Royalties 9.18 13.08 11.62 11.10 11.03
Production expense 16.66 16.78 15.38 16.72 14.84
----------------------------------------------------------------------------
Netback $ 44.15 $ 50.22 $ 55.58 $ 47.13 $ 49.38
----------------------------------------------------------------------------
Natural gas ($/Mcf) (1)
Sales price (2) $ 1.90 $ 2.47 $ 3.83 $ 2.19 $ 3.83
Royalties 0.05 0.05 0.24 0.05 0.19
Production expense 1.15 1.34 1.11 1.25 1.14
----------------------------------------------------------------------------
Netback $ 0.70 $ 1.08 $ 2.48 $ 0.89 $ 2.50
----------------------------------------------------------------------------
Barrels of oil equivalent
($/BOE) (1)
Sales price (2) $ 49.17 $ 55.21 $ 60.77 $ 52.18 $ 56.04
Royalties 5.93 8.23 7.83 7.08 7.35
Production expense 13.06 13.43 12.12 13.24 11.85
----------------------------------------------------------------------------
Netback $ 30.18 $ 33.55 $ 40.82 $ 31.86 $ 36.84
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts expressed on a per unit basis are based on sales volumes.
(2) Net of transportation and blending costs and excluding risk management
activities.
PRODUCT PRICES - EXPLORATION AND PRODUCTION
Three Months Ended Six Months Ended
-------------------------------------------------
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
2012 2012 2011 2012 2011
----------------------------------------------------------------------------
Crude oil and NGLs ($/bbl)
(1)(2)
North America $ 65.10 $ 74.27 $ 77.62 $ 69.60 $ 69.92
North Sea $ 108.22 $ 117.03 $ 112.32 $ 113.24 $ 107.75
Offshore Africa $ 106.30 $ 128.94 $ 110.42 $ 116.09 $ 102.56
Company average $ 69.99 $ 80.08 $ 82.58 $ 74.95 $ 75.25
Natural gas ($/Mcf) (1)(2)
North America $ 1.73 $ 2.36 $ 3.76 $ 2.05 $ 3.76
North Sea $ 3.98 $ 4.11 $ 5.19 $ 4.07 $ 4.29
Offshore Africa $ 10.54 $ 9.85 $ 8.83 $ 10.24 $ 7.94
Company average $ 1.90 $ 2.47 $ 3.83 $ 2.19 $ 3.83
Company average ($/BOE)
(1)(2) $ 49.17 $ 55.21 $ 60.77 $ 52.18 $ 56.04
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts expressed on a per unit basis are based on sales volumes.
(2) Net of transportation and blending costs and excluding risk management
activities.
North America
North America realized crude oil prices averaged $69.60 per bbl for the six
months ended June 30, 2012 and were comparable with $69.92 per bbl for the six
months ended June 30, 2011. North America realized crude oil prices averaged
$65.10 per bbl for the second quarter of 2012, a decrease of 16% compared with
$77.62 per bbl for the second quarter of 2011 and a decrease of 12% compared
with $74.27 per bbl for the first quarter of 2012. The decrease in prices for
the second quarter of 2012 from the comparable periods was primarily a result of
lower benchmark WTI pricing and the widening of the WCS Heavy Differential,
partially offset by the impact of a 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 2012 contributed approximately 154,000
bbl/d of heavy crude oil blends to the WCS stream.
In the first quarter of 2011, the Company announced that it had entered into a
partnership agreement with North West Upgrading Inc. to move forward with
detailed engineering regarding the construction and operation of a bitumen
upgrader refinery near Redwater, Alberta. In addition, the partnership has
entered into a 30 year fee-for-service tolling agreement to process bitumen
supplied by the Company and the Government of Alberta under the Bitumen Royalty
In Kind initiative. Project development is dependent upon completion of detailed
engineering and final project sanction by the partnership and its partners and
approval of the final tolls. Board sanction is currently targeted in 2012.
North America realized natural gas prices decreased 45% to average $2.05 per Mcf
for the six months ended June 30, 2012 from $3.76 per Mcf for the six months
ended June 30, 2011. North America realized natural gas prices decreased 54% to
average $1.73 per Mcf for the second quarter of 2012 compared with $3.76 per Mcf
in the second quarter of 2011, and decreased 27% compared with $2.36 per Mcf for
the first quarter of 2012. The decrease in natural gas prices from the
comparable periods was primarily due to lower NYMEX and AECO benchmark pricing
related to the impact of strong supply from US shale projects and the effects of
a warmer than normal winter.
Comparisons of the prices received in North America Exploration and Production
by product type were as follows:
------------------------------
Jun 30 Mar 31 Jun 30
(Quarterly Average) 2012 2012 2011
----------------------------------------------------------------------------
Wellhead Price(1) (2)
Light and medium crude oil and NGLs ($/bbl) $ 69.75$ 76.34$ 86.49
Pelican Lake heavy crude oil ($/bbl) $ 63.07$ 74.16$ 74.95
Primary heavy crude oil ($/bbl) $ 63.69$ 72.84$ 75.85
Bitumen (thermal oil) ($/bbl) $ 64.65$ 74.76$ 75.73
Natural gas ($/Mcf) $ 1.73$ 2.36$ 3.76
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts expressed on a per unit basis are based on sales volumes.
(2) Net of transportation and blending costs and excluding risk management
activities.
North Sea
North Sea realized crude oil prices increased 5% to average $113.24 per bbl for
the six months ended June 30, 2012 from $107.75 per bbl for the six months ended
June 30, 2011. Realized crude oil prices averaged $108.22 per bbl for the second
quarter of 2012, a decrease of 4% from $112.32 per bbl for the second quarter of
2011, and 8% from $117.03 per bbl for the first quarter of 2012. The increase in
realized crude oil prices in the North Sea for the six months ended June 30,
2012 from the comparable period in 2011 was primarily the result of higher Brent
benchmark pricing and fluctuations in the Canadian dollar. The decreases in
realized crude oil prices in the North Sea for the three months ended June 30,
2012 from the comparable periods were primarily the result of lower Brent
benchmark pricing and the timing of liftings, partially offset by the weaker
Canadian dollar.
Offshore Africa
Offshore Africa realized crude oil prices increased 13% to average $116.09 per
bbl for the six months ended June 30, 2012 from $102.56 per bbl for the six
months ended June 30, 2011. Realized crude oil prices decreased 4% to average
$106.30 per bbl for the second quarter of 2012 from $110.42 per bbl for the
second quarter of 2011, and 18% from $128.94 per bbl for the first quarter of
2012. The increase in realized crude oil prices in Offshore Africa for the six
months ended June 30, 2012 from the comparable period in 2011 was primarily the
result of higher Brent benchmark pricing and the timing of liftings, together
with the impact of fluctuations in the Canadian dollar. The decreases in
realized crude oil prices in Offshore Africa for the three months ended June 30,
2012 from the comparable periods were primarily the result of lower Brent
benchmark pricing, partially offset by the weaker Canadian dollar.
ROYALTIES - EXPLORATION AND PRODUCTION
Three Months Ended Six Months Ended
-------------------------------------------------
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
2012 2012 2011 2012 2011
----------------------------------------------------------------------------
Crude oil and NGLs ($/bbl)
(1)
North America $ 8.33 $ 13.75 $ 13.53 $ 10.99 $ 12.57
North Sea $ 0.26 $ 0.30 $ 0.25 $ 0.28 $ 0.26
Offshore Africa $ 28.63 $ 20.01 $ 0.71 $ 24.90 $ 5.40
Company average $ 9.18 $ 13.08 $ 11.62 $ 11.10 $ 11.03
Natural gas ($/Mcf) (1)
North America $ 0.02 $ 0.03 $ 0.23 $ 0.02 $ 0.18
Offshore Africa $ 1.86 $ 1.53 $ 1.07 $ 1.72 $ 1.01
Company average $ 0.05 $ 0.05 $ 0.24 $ 0.05 $ 0.19
Company average ($/BOE)
(1) $ 5.93 $ 8.23 $ 7.83 $ 7.08 $ 7.35
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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, 2012 compared with the six months ended June 30, 2011 reflected decreases in
benchmark commodity prices.
Crude oil and NGLs royalties averaged approximately 13% of product sales for the
second quarter of 2012 compared with 17% for the second quarter of 2011 and 19%
for the first quarter of 2012. The decrease in royalties from the comparable
periods was due to lower bitumen prices. Crude oil and NGLs royalties per bbl
are anticipated to average 15% to 17% of product sales for 2012.
Natural gas royalties averaged approximately 1% of product sales for the first
and second quarters of 2012 compared with 6% for the second quarter of 2011. The
decrease in natural gas royalty rates from the second quarter of 2011 was due to
the decline in realized natural gas prices. Natural gas royalties are
anticipated to average 1% to 2% of product sales for 2012.
Offshore Africa
Under the terms of the various Production Sharing Contracts, royalty rates
fluctuate based on realized commodity pricing, capital costs, the status of
payouts, and the timing of liftings from each field.
Royalty rates as a percentage of product sales averaged approximately 26% for
the second quarter of 2012 compared with 1% for the second quarter of 2011 and
16% for the first quarter of 2012. The increase in royalty rates from the
comparable periods was due to higher crude oil prices during the year,
adjustments to royalties and the payout of the Baobab field in May 2011.
Offshore Africa royalty rates are anticipated to average 20% to 25% of product
sales for 2012.
PRODUCTION EXPENSE - EXPLORATION AND PRODUCTION
Three Months Ended Six Months Ended
-------------------------------------------------
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
2012 2012 2011 2012 2011
----------------------------------------------------------------------------
Crude oil and NGLs ($/bbl)
(1)
North America $ 13.10 $ 15.40 $ 12.86 $ 14.23 $ 12.57
North Sea $ 68.32 $ 36.53 $ 34.20 $ 50.21 $ 32.46
Offshore Africa $ 22.94 $ 12.17 $ 21.36 $ 18.29 $ 20.04
Company average $ 16.66 $ 16.78 $ 15.38 $ 16.72 $ 14.84
Natural gas ($/Mcf) (1)
North America $ 1.13 $ 1.33 $ 1.09 $ 1.24 $ 1.12
North Sea $ 3.89 $ 3.98 $ 2.61 $ 3.94 $ 2.63
Offshore Africa $ 1.78 $ 1.76 $ 2.35 $ 1.77 $ 1.69
Company average $ 1.15 $ 1.34 $ 1.11 $ 1.25 $ 1.14
Company average ($/BOE)
(1) $ 13.06 $ 13.43 $ 12.12 $ 13.24 $ 11.85
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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, 2012 increased 13% to $14.23 per bbl from $12.57 per bbl for the six
months ended June 30, 2011. North America crude oil and NGLs production expense
for the second quarter of 2012 increased 2% to $13.10 per bbl from $12.86 per
bbl for the second quarter of 2011 and decreased 15% from $15.40 per bbl for the
first quarter of 2012. The increase in production expense for the three and six
months ended June 30, 2012 from the comparable periods in 2011 was a result of
higher overall service costs relating to heavy crude oil production. The
decrease in production expense from the first quarter of 2012 was a result of
lower primary heavy oil costs and the timing of thermal steam cycles, together
with lower normal seasonal costs. North America crude oil and NGLs production
expense is anticipated to average $11.00 to $13.00 per bbl for 2012.
North America natural gas production expense for the six months ended June 30,
2012 increased 11% to $1.24 per Mcf from $1.12 per Mcf for the six months ended
June 30, 2011. North America natural gas production expense for the second
quarter of 2012 increased 4% to $1.13 per Mcf from $1.09 per Mcf for the second
quarter of 2011, and decreased 15% from $1.33 per Mcf for the first quarter of
2012. Natural gas production expense for the three and six months ended June 30,
2012 increased from the comparable periods in 2011 due to the impact of shut-in
production and the acquisitions of natural gas producing properties that have
higher operating costs per Mcf than the Company's existing properties. These
acquisitions closed late in the fourth quarter of 2011 and costs are expected to
decline once the acquisitions are fully integrated into the Company's
operations. Natural gas production expense decreased in the second quarter of
2012 compared to the prior quarter due to normal seasonality. North America
natural gas production expense is anticipated to average $1.15 to $1.20 per Mcf
for 2012.
North Sea
North Sea crude oil production expense for the six months ended June 30, 2012
increased 55% to $50.21 per bbl from $32.46 per bbl for the six months ended
June 30, 2011. North Sea crude oil production expense for the second quarter of
2012 increased to $68.32 per bbl from $34.20 per bbl for the second quarter of
2011, and increased 87% from $36.53 per bbl the first quarter of 2012.
Production expense increased on a per barrel basis from the comparable periods
due to lower production volumes on relatively fixed costs, partially related to
the 20 day shut in of the third-party operated pipeline to Sullom Voe, and
higher maintenance costs. North Sea crude oil production expense is anticipated
to average $48.00 to $52.00 per bbl for 2012.
Offshore Africa
Offshore Africa crude oil production expense decreased 9% to $18.29 per bbl from
$20.04 per bbl for the six months ended June 30, 2012. Offshore Africa crude oil
production expense for the second quarter of 2012 averaged $22.94 per bbl, an
increase of 7% compared with $21.36 per bbl for the second quarter of 2011 and
an increase of 88% compared with $12.17 per bbl for the first quarter of 2012.
Production expense for the three and six months ended June 30, 2012 fluctuated
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 $26.50 to $28.50 per bbl for 2012.
DEPLETION, DEPRECIATION AND AMORTIZATION - EXPLORATION AND PRODUCTION
Three Months Ended Six Months Ended
-------------------------------------------------
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
2012 2012 2011 2012 2011
----------------------------------------------------------------------------
Expense ($ millions) $ 936 $ 910 $ 835 $ 1,846 $ 1,659
$/BOE (1) $ 18.13 $ 17.73 $ 16.60 $ 17.93 $ 16.46
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts expressed on a per unit basis are based on sales volumes.
Depletion, depreciation and amortization expense increased for the six months
ended June 30, 2012 compared with 2011 due to higher sales volumes in North
America associated with heavy oil drilling and the impact of higher future
development costs.
ASSET RETIREMENT OBLIGATION ACCRETION - EXPLORATION AND PRODUCTION
Three Months Ended Six Months Ended
-------------------------------------------------
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
2012 2012 2011 2012 2011
----------------------------------------------------------------------------
Expense ($ millions) $ 30 $ 29 $ 26 $ 59 $ 54
$/BOE (1) $ 0.59 $ 0.56 $ 0.52 $ 0.58 $ 0.54
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts expressed on a per unit basis are based on sales volumes.
Asset retirement obligation accretion expense represents the increase in the
carrying amount of the asset retirement obligation due to the passage of time.
OPERATING HIGHLIGHTS - OIL SANDS MINING AND UPGRADING
OPERATIONS UPDATE
On March 13, 2012 the Company successfully and safely completed the unplanned
maintenance on the fractionating unit in the primary upgrading facility. The
positive impact of the third OPP and continued emphasis on safe, steady and
reliable operations resulted in strong operational performance across Horizon,
with production exceeding the Company's previously issued guidance of between
105,000 and 115,000 bbl/d of SCO.
PRODUCT PRICES AND ROYALTIES - OIL SANDS MINING AND UPGRADING
Three Months Ended Six Months Ended
-------------------------------------------------
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
($/bbl) (1) 2012 2012 2011 2012 2011
----------------------------------------------------------------------------
SCO sales price (2) $ 88.11 $ 97.09 $ - $ 91.84 $ 82.93
Bitumen value for royalty
purposes (3) $ 59.83 $ 64.37 $ 69.88 $ 62.10 $ 60.50
Bitumen royalties (4) $ 5.20 $ 5.16 $ - $ 5.19 $ 4.14
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts expressed on a per unit basis are based on sales volumes
excluding the period during suspension of production.
(2) Net of transportation.
(3) Calculated as the simple average of the monthly bitumen valuation
methodology price.
(4) Calculated based on actual bitumen royalties expensed during the period;
divided by the corresponding SCO sales volumes.
Realized SCO sales prices averaged $91.84 per bbl for the six months ended June
30, 2012. Realized SCO sales prices averaged $88.11 per bbl for the second
quarter of 2012, a decrease of 9% compared with $97.09 per bbl for the first
quarter of 2012, reflecting the relative changes in WTI and Brent benchmark
pricing.
PRODUCTION COSTS - OIL SANDS MINING AND UPGRADING
The following tables are reconciled to the Oil Sands Mining and Upgrading
production costs disclosed in the Company's unaudited interim consolidated
financial statements.
Three Months Ended Six Months Ended
-------------------------------------------------
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
($ millions) 2012 2012 2011 2012 2011
----------------------------------------------------------------------------
Cash production costs $ 388 $ 346 $ 221 $ 734 $ 477
Less: costs incurred
during the period of
suspension of production - (154) (221) (154) (430)
----------------------------------------------------------------------------
Adjusted cash production
costs $ 388 $ 192 $ - $ 580 $ 47
----------------------------------------------------------------------------
Adjusted cash production
costs, excluding natural
gas costs $ 362 $ 177 $ - $ 539 $ 42
Adjusted natural gas costs 26 15 - 41 5
----------------------------------------------------------------------------
Adjusted cash production
costs $ 388 $ 192 $ - $ 580 $ 47
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Three Months Ended Six Months Ended
-------------------------------------------------
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
($/bbl) (1) 2012 2012 2011 2012 2011
----------------------------------------------------------------------------
Adjusted cash production
costs, excluding natural
gas costs $ 34.45 $ 42.70 $ - $ 36.79 $ 41.38
Adjusted natural gas costs 2.53 3.54 - 2.82 4.31
----------------------------------------------------------------------------
Adjusted cash production
costs $ 36.98 $ 46.24 $ - $ 39.61 $ 45.69
----------------------------------------------------------------------------
Sales (bbl/d) 115,552 45,741 - 80,646 5,657
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts expressed on a per unit basis are based on sales volumes
excluding the period during suspension of production.
Adjusted cash production costs averaged $39.61 per bbl for the six months ended
June 30, 2012 compared with $45.69 per bbl for the six months ended June 30,
2011. Cash production costs for the second quarter of 2012 averaged $36.98 per
bbl, a decrease of 20% compared with adjusted cash production costs of $46.24
per bbl in the first quarter of 2012. The decrease in cash production costs per
bbl from the comparable periods was primarily due to steady and reliable
production during the second quarter of 2012.
DEPLETION, DEPRECIATION AND AMORTIZATION - OIL SANDS MINING AND UPGRADING
Three Months Ended Six Months Ended
-------------------------------------------------
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
($ millions) 2012 2012 2011 2012 2011
----------------------------------------------------------------------------
Depletion, depreciation
and amortization $ 146 $ 63 $ 33 $ 209 $ 56
Less: depreciation
incurred during the
period of suspension of
production - (6) (33) (6) (43)
----------------------------------------------------------------------------
Adjusted depletion,
depreciation and
amortization $ 146 $ 57 $ - $ 203 $ 13
----------------------------------------------------------------------------
$/bbl (1) $ 13.84 $ 13.81 $ - $ 13.83 $ 12.37
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts expressed on a per unit basis are based on sales volumes
excluding the period during suspension of production.
Depletion, depreciation and amortization expense for the three and six months
ended June 30, 2012 increased from the comparable periods primarily due to
higher 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) 2012 2012 2011 2012 2011
----------------------------------------------------------------------------
Expense $ 8 $ 8 $ 5 $ 16 $ 10
$/bbl (1) $ 0.76 $ 1.91 $ - $ 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) 2012 2012 2011 2012 2011
----------------------------------------------------------------------------
Revenue $ 22 $ 21 $ 21 $ 43 $ 43
Production expense 7 7 5 14 12
----------------------------------------------------------------------------
Midstream cash flow 15 14 16 29 31
Depreciation 2 2 2 4 4
----------------------------------------------------------------------------
Segment earnings before
taxes $ 13 $ 12 $ 14 $ 25 $ 27
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Midstream operating results were consistent with the comparable periods.
ADMINISTRATION EXPENSE
Three Months Ended Six Months Ended
-------------------------------------------------
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
($ millions) 2012 2012 2011 2012 2011
----------------------------------------------------------------------------
Expense $ 77 $ 65 $ 69 $ 142 $ 123
$/BOE (1) $ 1.24 $ 1.17 $ 1.38 $ 1.20 $ 1.21
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts expressed on a per unit basis are based on sales volumes.
Administration expense for the three and six months ended June 30, 2012
increased from the comparable periods primarily due to higher staffing related
costs.
SHARE-BASED COMPENSATION
Three Months Ended Six Months Ended
-------------------------------------------------
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
($ millions) 2012 2012 2011 2012 2011
----------------------------------------------------------------------------
Recovery $ (115) $ (107) $ (188) $ (222) $ (60)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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 $222 million share-based compensation recovery for the
six months ended June 30, 2012, primarily as a result of remeasurement of the
fair value of outstanding stock options at the end of the period related to a
decrease in the Company's share price, offset by normal course graded vesting of
stock options granted in prior periods and the impact of vested stock options
exercised or surrendered during the period. For the six months ended June 30,
2012, a $15 million recovery was recognized in respect of capitalized
share-based compensation to Oil Sands Mining and Upgrading (June 30, 2011 - $2
million recovery).
For the six months ended June 30, 2012, the Company paid $7 million for stock
options surrendered for cash settlement (June 30, 2011 - $11 million).
INTEREST AND OTHER FINANCING COSTS
Three Months Ended Six Months Ended
-------------------------------------------------
($ millions, except per Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
BOE amounts) 2012 2012 2011 2012 2011
----------------------------------------------------------------------------
Expense, gross $ 114 $ 114 $ 112 $ 228 $ 217
Less: capitalized interest 21 18 13 39 24
----------------------------------------------------------------------------
Expense, net $ 93 $ 96 $ 99 $ 189 $ 193
$/BOE (1) $ 1.50 $ 1.72 $ 1.97 $ 1.61 $ 1.90
Average effective interest
rate 4.8% 4.8% 4.7% 4.8% 4.7%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts expressed on a per unit basis are based on sales volumes.
Gross interest and other financing costs for the six months ended June 30, 2012
increased compared with 2011 due to higher average US dollar debt levels and the
impact of a weaker Canadian dollar related to US dollar interest, partially
offset by lower average interest rates on fixed rate debt. Gross interest and
other financing costs for the three months ended June 30, 2012 was comparable to
prior periods. Capitalized interest for the six months ended June 30, 2012
related to Horizon Phase 2/3 expansions and the Kirby Projects.
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) 2012 2012 2011 2012 2011
----------------------------------------------------------------------------
Crude oil and NGLs
financial instruments $ 19 $ 9 $ 37 $ 28 $ 64
Foreign currency contracts
and interest rate swaps (80) 85 (3) 5 40
----------------------------------------------------------------------------
Realized (gain) loss (61) 94 34 33 104
----------------------------------------------------------------------------
Crude oil and NGLs
financial instruments (180) 96 (135) (84) (68)
Foreign currency contracts
and interest rate swaps 36 (36) 17 - 4
----------------------------------------------------------------------------
Unrealized (gain) loss (144) 60 (118) (84) (64)
----------------------------------------------------------------------------
Net (gain) loss $ (205) $ 154 $ (84) $ (51) $ 40
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Complete details related to outstanding derivative financial instruments at June
30, 2012 are disclosed in note 13 to the Company's unaudited interim
consolidated financial statements.
The Company recorded a net unrealized gain of $84 million ($63 million
after-tax) on its risk management activities for the six months ended June 30,
2012, including an unrealized gain of $144 million ($103 million after-tax) for
the second quarter of 2012 (March 31, 2012 - unrealized loss of $60 million; $40
million after-tax; June 30, 2011 - unrealized gain of $118 million; $87 million
after-tax), primarily due to changes in crude oil forward pricing and the
reversal of prior period unrealized gains and losses related to crude oil and
foreign currency contracts.
FOREIGN EXCHANGE
Three Months Ended Six Months Ended
-------------------------------------------------
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
($ millions) 2012 2012 2011 2012 2011
----------------------------------------------------------------------------
Net realized (gain) loss $ (9) $ 6 $ (4) $ (3) $ 18
Net unrealized loss (gain)
(1) 71 (60) (33) 11 (122)
----------------------------------------------------------------------------
Net loss (gain) $ 62 $ (54) $ (37) $ 8 $ (104)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Amounts are reported net of the hedging effect of cross currency swaps.
The net realized foreign exchange loss for the six months ended June 30, 2012
was primarily due to foreign exchange rate fluctuations on settlement of working
capital items denominated in US dollars or UK pounds sterling. The net
unrealized foreign exchange loss for the six months ended June 30, 2012 was
primarily related to the weakening of the Canadian dollar with respect to US
dollar debt. The net unrealized loss (gain) for each of the periods presented
included the impact of cross currency swaps (six months ended June 30, 2012 -
unrealized gain of $5 million; March 31, 2012 - unrealized loss of $42 million;
six months ended June 30, 2011 - unrealized loss of $64 million). The Canadian
dollar ended the second quarter at US$0.9813 (March 31, 2012 - US$1.0009; June
30, 2011 - US$1.0370).
INCOME TAXES
Three Months Ended Six Months Ended
------------------------------------------------
($ millions, except income Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
tax rates) 2012 2012 2011 2012 2011
----------------------------------------------------------------------------
North America (1) $ 124 $ 113 $ 79 $ 237 $ 170
North Sea 19 45 70 64 116
Offshore Africa 64 36 24 100 44
PRT expense - North Sea 1 31 46 32 54
Other taxes 5 6 6 11 12
----------------------------------------------------------------------------
Current income tax 213 231 225 444 396
----------------------------------------------------------------------------
Deferred income tax expense
(recovery) 59 (48) 55 11 98
Deferred PRT expense
(recovery) - North Sea 3 (4) 2 (1) 12
----------------------------------------------------------------------------
Deferred income tax expense
(recovery) 62 (52) 57 10 110
----------------------------------------------------------------------------
275 179 282 454 506
Income tax rate and other
legislative changes (2) - - - - (104)
----------------------------------------------------------------------------
$ 275 $ 179 $ 282 $ 454 $ 402
----------------------------------------------------------------------------
Effective income tax rate
on adjusted net earnings
from operations (3) 27.1% 35.6% 24.1% 30.1% 26.6%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Includes North America Exploration and Production, Midstream, and Oil
Sands Mining and Upgrading segments.
(2) Deferred income tax expense in the first quarter of 2011 included a
charge of $104 million related to enacted changes in the UK to increase
the corporate income tax rate charged on profits from UK North Sea crude
oil and natural gas production from 50% to 62%.
(3) Excludes the impact of current and deferred PRT expense and other
current income tax expense.
The fluctuations in the effective income tax rate on adjusted net earnings for
the three and six months ended June 30, 2012 from the comparable periods was
primarily due to the impact of the temporary suspension and subsequent
reinstatement of production at Horizon in the first quarter of 2012.
During 2011, the Canadian Federal government enacted legislation to implement
several taxation changes. These changes include a requirement that, beginning in
2012, partnership income must be included in the taxable income of each
corporate partner based on the tax year of the partner, rather than the fiscal
year of the partnership. The legislation includes a five-year transition
provision and has no impact on net earnings.
During the first quarter of 2011, the UK government enacted an increase to the
supplementary income tax rate charged on profits from UK North Sea crude oil and
natural gas production, increasing the combined corporate and supplementary
income tax rate from 50% to 62%. As a result of the income tax rate change, the
Company's deferred income tax liability was increased by $104 million as at
March 31, 2011.
Subsequent to June 30, 2012, the UK government enacted legislation to restrict
the combined corporate and supplementary income tax rate relief on
decommissioning expenditures to 50%. This income tax rate change will result in
an increase in the Company's deferred income tax liability of approximately $58
million.
The Company files income tax returns in the various jurisdictions in which it
operates. These tax returns are subject to periodic examinations in the normal
course by the applicable tax authorities. The tax returns as prepared may
include filing positions that could be subject to differing interpretations of
applicable tax laws and regulations, which may take several years to resolve.
The Company does not believe the ultimate resolution of these matters will have
a material impact upon the Company's results of operations, financial position
or liquidity.
For 2012, based on budgeted prices and the current availability of tax pools,
the Company expects to incur current income tax expense of $515 million to $615
million in Canada and $240 million to $340 million in the North Sea and Offshore
Africa.
NET CAPITAL EXPENDITURES (1)
Three Months Ended Six Months Ended
-------------------------------------------------
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
($ millions) 2012 2012 2011 2012 2011
----------------------------------------------------------------------------
Exploration and Evaluation
Net expenditures $ 32 $ 208 $ 41 $ 240 $ 115
----------------------------------------------------------------------------
Property, Plant and
Equipment
Net property acquisitions 7 38 265 45 489
Well drilling, completion
and equipping 352 499 284 851 856
Production and related
facilities 445 505 379 950 795
Capitalized interest and
other (2) 30 30 30 60 50
----------------------------------------------------------------------------
Net expenditures 834 1,072 958 1,906 2,190
----------------------------------------------------------------------------
Total Exploration and
Production 866 1,280 999 2,146 2,305
----------------------------------------------------------------------------
Oil Sands Mining and
Upgrading
Horizon Phases 2/3
construction costs 346 192 115 538 205
Sustaining capital 51 37 50 88 74
Turnaround costs 3 2 24 5 79
Capitalized interest and
other (2) 5 3 (2) 8 18
----------------------------------------------------------------------------
Total Oil Sands Mining and
Upgrading 405 234 187 639 376
----------------------------------------------------------------------------
Horizon coker rebuild and
collateral damage costs
(3) - - 183 - 309
Midstream 4 1 1 5 4
Abandonments (4) 39 76 29 115 93
Head office 10 5 6 15 12
----------------------------------------------------------------------------
Total net capital
expenditures $ 1,324 $ 1,596 $ 1,405 $ 2,920 $ 3,099
----------------------------------------------------------------------------
----------------------------------------------------------------------------
By segment
North America $ 788 $ 1,223 $ 913 $ 2,011 $ 2,145
North Sea 66 54 69 120 110
Offshore Africa 12 3 17 15 50
Oil Sands Mining and
Upgrading 405 234 370 639 685
Midstream 4 1 1 5 4
Abandonments (4) 39 76 29 115 93
Head office 10 5 6 15 12
----------------------------------------------------------------------------
Total $ 1,324 $ 1,596 $ 1,405 $ 2,920 $ 3,099
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) The net capital expenditures exclude adjustments related to differences
between carrying amounts and tax values, and other fair value
adjustments.
(2) Capitalized interest and other includes expenditures related to land
acquisition and retention, seismic, and other adjustments.
(3) During 2011, the Company recognized $393 million of property damage
insurance recoveries (see note 7 to the interim consolidated financial
statements), offsetting the costs incurred related to the coker rebuild
and collateral damage costs.
(4) Abandonments represent expenditures to settle asset retirement
obligations and have been reflected as capital expenditures in this
table.
The Company's strategy is focused on building a diversified asset base that is
balanced among various products. In order to facilitate efficient operations,
the Company concentrates its activities in core areas. The Company focuses on
maintaining its land inventories to enable the continuous exploitation of play
types and geological trends, greatly reducing overall exploration risk. By
owning associated infrastructure, the Company is able to maximize utilization of
its production facilities, thereby increasing control over production costs.
Net capital expenditures for the six months ended June 30, 2012 were $2,920
million compared with $3,099 million for the six months ended June 30, 2011. Net
capital expenditures for the second quarter of 2012 were $1,324 million compared
with $1,405 million for the second quarter of 2011 and $1,596 million for the
first quarter of 2012.
Excluding the Horizon coker rebuild and collateral damage costs incurred in
2011, the increase in capital expenditures for the six months ended June 30,
2012 from 2011 was primarily due to the ramp up of Horizon field construction
activity, partially offset by lower net property acquisition costs. The decrease
in capital expenditures for the three months ended June 30, 2012 from the first
quarter of 2012 was primarily due to lower stratigraphic well drilling and
decreased natural gas well drilling and completion costs, as well as lower
equipping costs related to the primary heavy oil drilling program. These
decreases were partially offset by the ramp up of Horizon field construction
activity.
Drilling Activity (number of wells)
Three Months Ended Six Months Ended
--------------------------------------------------
Jun 30 Mar 31 Jun 30 Jun 30 Jun 30
2012 2012 2011 2012 2011
----------------------------------------------------------------------------
Net successful natural gas
wells 4 19 10 23 35
Net successful crude oil
wells (1) 266 278 177 544 456
Dry wells 2 6 5 8 21
Stratigraphic test /
service wells 5 584 19 589 520
----------------------------------------------------------------------------
Total 277 887 211 1,164 1,032
Success rate (excluding
stratigraphic test /
service wells) 99% 98% 97% 99% 96%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Includes bitumen wells.
North America
North America, excluding Oil Sands Mining and Upgrading, accounted for
approximately 73% of the total capital expenditures for the six months ended
June 30, 2012, and 2011.
During the second quarter of 2012, the Company targeted 4 net natural gas wells,
including 3 wells in Northeast British Columbia and 1 well in Northwest Alberta.
The Company also targeted 268 net crude oil wells. The majority of these wells
were concentrated in the Company's Northern Plains region where 186 primary
heavy crude oil wells, 29 Pelican Lake heavy crude oil wells and 37 bitumen
(thermal oil) wells were drilled. Another 16 wells targeting light crude oil
were drilled outside the Northern Plains region.
Overall Primrose thermal production for the second quarter of 2012 averaged
approximately 94,000 bbl/d compared with approximately 106,000 bbl/d for the
second quarter of 2011 and approximately 80,000 bbl/d for the first quarter of
2012. Production volumes were in line with expectations due to the cyclic nature
of thermal production at Primrose. As part of the phased expansion of its in
situ Oil Sands assets, the Company is continuing to develop its Primrose thermal
projects. Additional pad drilling was completed and drilled on budget, with
these wells coming on production in 2012.
The next planned phase of the Company's in situ Oil Sands assets expansion is
the Kirby South Phase 1 Project. During the third quarter of 2010, the Company
received final regulatory approval for Phase 1 of the Project. During the fourth
quarter of 2010, the Company's Board of Directors sanctioned Kirby South Phase
1. Construction has commenced, with first steam targeted in 2013. Drilling has
been completed on the third of seven pads and is progressing on the fourth pad.
Development of the tertiary recovery conversion projects at Pelican Lake
continued and 29 horizontal wells were drilled during the quarter. Pelican Lake
production averaged approximately 37,000 bbl/d for the second quarter of 2012
compared with 35,000 bbl/d for the second quarter of 2011 and 39,000 bbl/d for
the first quarter of 2012.
For the third quarter of 2012, the Company's overall planned drilling activity
in North America is expected to be 290 net crude oil wells, 42 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 2012 was focused on the
field construction of the gas recovery unit, sulphur recovery unit, butane
treatment unit, coker expansion, and extraction trains 3 and 4. Engineering
related to the hydrogen unit, vacuum distillation unit, distillation recovery
unit, and permanent camp commenced in the second quarter of 2012. Key contracts
awarded in the second quarter of 2012 were related to the vacuum distillation
unit, distillation recovery unit and permanent camp.
North Sea
In December 2011, the Banff FPSO and subsea infrastructure suffered storm
damage. Operations at Banff/Kyle, with combined net production of approximately
3,500 bbl/d, were suspended. The FPSO and associated floating storage unit were
subsequently removed from the field. All personnel on board the FPSO were safe
and accounted for. The extent of the damage, including associated costs and
related property damage, are not expected to be significant. The timing of
returning to the field is currently being assessed.
In March 2011, the UK government enacted an increase to the corporate income tax
rate charged on profits from UK North Sea crude oil and natural gas production
from 50% to 62%. As a result of the increase in the corporate income tax rate,
the Company's development activities in the North Sea were reduced. The Company
is continuing to high grade all North Sea prospects for potential development
opportunities in 2012 and future years.
Offshore Africa
During the fourth quarter of 2011, the Company sanctioned an 8 well drilling
program at the Espoir field in Cote d'Ivoire. Preparations are ongoing,
targeting commencement of drilling operations in the fourth quarter of 2012.
LIQUIDITY AND CAPITAL RESOURCES
-------------------------------------------
Jun 30 Mar 31 Dec 31 Jun 30
($ millions, except ratios) 2012 2012 2011 2011
----------------------------------------------------------------------------
Working capital (deficit) (1) $ (732) $ (1,304) $ (894) $ (1,032)
Long-term debt (2) (3) $ 8,522 $ 8,241 $ 8,571 $ 8,624
Share capital $ 3,670 $ 3,674 $ 3,507 $ 3,425
Retained earnings 20,193 19,656 19,365 17,989
Accumulated other comprehensive
income 59 59 26 38
----------------------------------------------------------------------------
Shareholders' equity $ 23,922 $ 23,389 $ 22,898 $ 21,452
Debt to book capitalization (3)
(4) 26% 26% 27% 29%
Debt to market capitalization
(3) (5) 22% 19% 17% 16%
After-tax return on average
common shareholders' equity (6) 12% 14% 12% 6%
After-tax return on average
capital employed (3) (7) 10% 11% 10% 5%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(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, 2012, the Company's capital resources consisted primarily of cash
flow from operations, available bank credit facilities and access to debt
capital markets. Cash flow from operations and the Company's ability to renew
existing bank credit facilities and raise new debt is dependent on factors
discussed in the "Risks and Uncertainties" section of the Company's December 31,
2011 annual MD&A. In addition, the Company's ability to renew existing bank
credit facilities and raise new debt is also dependent upon maintaining an
investment grade debt rating and the condition of capital and credit markets.
The Company continues to believe that its internally generated cash flow from
operations supported by the implementation of its ongoing hedge policy, the
flexibility of its capital expenditure programs supported by its multi-year
financial plans, its existing bank credit facilities, and its ability to raise
new debt on commercially acceptable terms will provide sufficient liquidity to
sustain its operations in the short, medium and long term and support its growth
strategy. At June 30, 2012, the Company had $4,401 million of available credit
under its bank credit facilities.
Over the next 12 months, the Company has maturities of long-term debt
aggregating $1,165 million (US$350 million due October 2012, $400 million due
January 2013 and US$400 million due February 2013). It is the Company's
intention to retire this indebtedness utilizing cash flow from operations
generated in excess of capital expenditures and available bank credit facilities
as necessary, while maintaining the ongoing dividend program. On a pro forma
basis, reflecting the retirement of this indebtedness, the available credit
under its bank credit facilities at June 30, 2012 would amount to $3,236
million.
During the second quarter of 2012, the $1,500 million revolving syndicated
credit facility was extended to June 2016. Additionally, the Company issued $500
million of 3.05% medium-term unsecured notes due June 2019. Proceeds from the
securities issued were used to repay bank indebtedness and for general corporate
purposes. After issuing these securities, the Company has $2,500 million
remaining on its outstanding $3,000 million base shelf prospectus that allows
for the issue of medium-term notes in Canada, which expires in November 2013. If
issued, these securities will bear interest as determined at the date of
issuance.
The Company has US$2,000 million remaining on its outstanding US$3,000 million
base shelf prospectus that allows for the issue of US dollar debt securities in
the United States, which expires in November 2013. If issued, these securities
will bear interest as determined at the date of issuance.
Long-term debt was $8,522 million at June 30, 2012, resulting in a debt to book
capitalization ratio of 26% (March 31, 2012 - 26%; June 30, 2011 - 29%). This
ratio is below the 35% to 45% internal range utilized by management. This range
may be exceeded in periods when a combination of capital projects, acquisitions,
or lower commodity prices occurs. The Company may be below the low end of the
targeted range when cash flow from operating activities is greater than current
investment activities. The Company remains committed to maintaining a strong
balance sheet, adequate available liquidity and a flexible capital structure.
The Company has hedged a portion of its crude oil production for 2012 and 2013
at prices that protect investment returns to ensure ongoing balance sheet
strength and the completion of its capital expenditure programs. Further details
related to the Company's long-term debt at June 30, 2012 are discussed in note 5
to the Company's unaudited interim consolidated financial statements.
The Company's commodity hedging policy reduces the risk of volatility in
commodity prices and supports the Company's cash flow for its capital
expenditures programs. This policy currently allows for the hedging of up to 60%
of the near 12 months budgeted production and up to 40% of the following 13 to
24 months estimated production. For the purpose of this policy, the purchase of
put options is in addition to the above parameters. As at August 8, 2012,
approximately 50% of currently forecasted 2012 crude oil volumes were hedged
using collars and puts. Further details related to the Company's commodity
related derivative financial instruments outstanding at June 30, 2012 are
discussed in note 13 to the Company's unaudited interim consolidated financial
statements.
Share Capital
As at June 30, 2012, there were 1,096,497,000 common shares outstanding and
66,073,000 stock options outstanding. As at August 7, 2012, the Company had
1,095,069,000 common shares outstanding and 65,409,000 stock options
outstanding.
During the second quarter of 2012, the Company amended its Articles by special
resolution of the Shareholders, changing the designation of its Class 1
preferred shares to "Preferred Shares" which may be issuable in series. If
issued, the number of shares in each series, and the designation, rights,
privileges, restrictions and conditions attached to the shares will be
determined by the Board of Directors of the Company.
On March 6, 2012, the Company's Board of Directors approved an increase in the
annual dividend to be paid by the Company to $0.42 per common share for 2012.
The increase represents an approximately 17% increase from 2011, recognizing the
stability of the Company's cash flow and providing a return to shareholders. The
dividend policy undergoes a periodic review by the Board of Directors and is
subject to change.
In April 2012, the Company announced a Normal Course Issuer Bid to purchase,
through the facilities of the Toronto Stock Exchange ("TSX") and the New York
Stock Exchange ("NYSE"), during the twelve month period commencing April 9, 2012
and ending April 8, 2013, up to 55,027,447 common shares.
On March 31, 2011, the Company announced a Normal Course Issuer Bid to purchase,
through the facilities of the TSX and the NYSE, during the twelve month period
commencing April 6, 2011 and ending April 5, 2012, up to 27,406,131 common
shares of the Company.
As at June 30, 2012, 4,621,600 common shares (March 31, 2012 - 692,200 common
shares) had been purchased for cancellation at a weighted average price of
$29.63 per common share (March 31, 2012 - $33.11 per common share), for a total
cost of $137 million (March 31, 2012 - $23 million). Subsequent to June 30,
2012, the Company purchased 1,575,000 common shares at a weighted average price
of $26.81 per common share for a total cost of $42 million.
COMMITMENTS AND OFF BALANCE SHEET ARRANGEMENTS
In the normal course of business, the Company has entered into various
commitments that will have an impact on the Company's future operations. As at
June 30, 2012, no entities were consolidated under the Standing Interpretations
Committee ("SIC") 12, "Consolidation - Special Purpose Entities". The following
table summarizes the Company's commitments as at June 30, 2012:
Remaining
($ millions) 2012 2013 2014 2015 2016 Thereafter
----------------------------------------------------------------------------
Product transportation and
pipeline $ 119 $ 212 $ 201 $ 189 $ 125 $ 889
Offshore equipment operating
leases and offshore drilling $ 76 $ 135 $ 100 $ 83 $ 53 $ 119
Long-term debt (1) $ 357 $ 808 $ 866 $ 507 $ 388 $ 5,646
Interest and other financing
costs (2) $ 234 $ 406 $ 387 $ 351 $ 338 $ 4,151
Office leases $ 15 $ 33 $ 34 $ 32 $ 33 $ 304
Other $ 150 $ 170 $ 96 $ 34 $ 2 $ 8
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Long-term debt represents principal repayments only and does not reflect
fair value adjustments, original issue discounts or transaction costs.
(2) Interest and other financing cost amounts represent the scheduled fixed
rate and variable rate cash interest payments related to long-term debt.
Interest on variable rate long-term debt was estimated based upon
prevailing interest rates and foreign exchange rates as at June 30,
2012.
In addition to the commitments disclosed above, the Company has entered into
various agreements related to the engineering, procurement and construction of
subsequent phases of Horizon. These contracts can be cancelled by the Company
upon notice without penalty, subject to the costs incurred up to and in respect
of the cancellation.
LEGAL PROCEEDINGS AND OTHER CONTINGENCIES
The Company is a defendant and plaintiff in a number of legal actions arising in
the normal course of business. In addition, the Company is subject to certain
contractor construction claims. The Company believes that any liabilities that
might arise pertaining to any such matters would not have a material effect on
its consolidated financial position.
ACCOUNTING STANDARDS ISSUED BUT NOT YET APPLIED
For the impact of new accounting standards, refer to the MD&A and the audited
consolidated financial statements for the year ended December 31, 2011.
CRITICAL ACCOUNTING ESTIMATES AND CHANGE IN ACCOUNTING POLICIES
The preparation of financial statements requires the Company to make estimates,
assumptions and judgements in the application of IFRS that have a significant
impact on the financial results of the Company. Actual results could differ from
estimated amounts, and those differences may be material. A comprehensive
discussion of the Company's significant accounting policies is contained in the
MD&A and the audited consolidated financial statements for the year ended
December 31, 2011.
Consolidated Balance Sheets
-----------------------
Jun 30 Dec 31
As at(millions of Canadian dollars, unaudited) Note 2012 2011
----------------------------------------------------------------------------
ASSETS
Current assets
Cash and cash equivalents $ 10 $ 34
Accounts receivable 1,527 2,077
Inventory 593 550
Prepaids and other 133 120
Current portion of other long-term assets 4 41 -
----------------------------------------------------------------------------
2,304 2,781
Exploration and evaluation assets 2 2,639 2,475
Property, plant and equipment 3 42,292 41,631
Other long-term assets 4 347 391
----------------------------------------------------------------------------
$ 47,582 $ 47,278
----------------------------------------------------------------------------
----------------------------------------------------------------------------
LIABILITIES
Current liabilities
Accounts payable $ 415 $ 526
Accrued liabilities 2,196 2,347
Current income tax liabilities 281 347
Current portion of long-term debt 5 1,165 359
Current portion of other long-term
liabilities 6 144 455
----------------------------------------------------------------------------
4,201 4,034
Long-term debt 5 7,357 8,212
Other long-term liabilities 6 3,864 3,913
Deferred income tax liabilities 8,238 8,221
----------------------------------------------------------------------------
23,660 24,380
----------------------------------------------------------------------------
SHAREHOLDERS' EQUITY
Share capital 9 3,670 3,507
Retained earnings 20,193 19,365
Accumulated other comprehensive income 10 59 26
----------------------------------------------------------------------------
23,922 22,898
----------------------------------------------------------------------------
$ 47,582 $ 47,278
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Commitments and contingencies (note 14).
Approved by the Board of Directors on August 8, 2012
Consolidated Statements of Earnings
Three Months Six Months
Ended Ended
------------------------------------
(millions of Canadian dollars,
except per common share amounts, Jun 30 Jun 30 Jun 30 Jun 30
unaudited) Note 2012 2011 2012 2011
----------------------------------------------------------------------------
Product sales $ 4,187 $ 3,727 $ 8,158 $ 7,029
Less: royalties (361) (394) (805) (745)
----------------------------------------------------------------------------
Revenue 3,826 3,333 7,353 6,284
----------------------------------------------------------------------------
Expenses
Production 1,068 833 2,106 1,678
Transportation and blending 691 665 1,408 1,286
Depletion, depreciation and
amortization 3 1,084 870 2,059 1,719
Administration 77 69 142 123
Share-based compensation 6 (115) (188) (222) (60)
Asset retirement obligation
accretion 6 38 31 75 64
Interest and other financing costs 93 99 189 193
Risk management activities 13 (205) (84) (51) 40
Foreign exchange loss (gain) 62 (37) 8 (104)
Horizon asset impairment provision 7 - - - 396
Insurance recovery - property
damage 7 - - - (396)
Insurance recovery - business
interruption 7 - (136) - (136)
Equity loss from jointly
controlled entity 4 5 - 5 -
----------------------------------------------------------------------------
2,798 2,122 5,719 4,803
----------------------------------------------------------------------------
Earnings before taxes 1,028 1,211 1,634 1,481
Current income tax expense 8 213 225 444 396
Deferred income tax expense 8 62 57 10 110
----------------------------------------------------------------------------
Net earnings $ 753 $ 929 $ 1,180 $ 975
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net earnings per common share
Basic 12 $ 0.68 $ 0.85 $ 1.07 $ 0.89
Diluted 12 $ 0.68 $ 0.84 $ 1.07 $ 0.88
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Consolidated Statements of Comprehensive Income
Three Months Ended Six Months Ended
----------------------------------------
(millions of Canadian dollars, Jun 30 Jun 30 Jun 30 Jun 30
unaudited) 2012 2011 2012 2011
----------------------------------------------------------------------------
Net earnings $ 753 $ 929 $ 1,180 $ 975
----------------------------------------------------------------------------
Net change in derivative financial
instruments designated as cash flow
hedges
Unrealized income (loss) during the
period, net of taxes of
$1 million (2011 - $4 million) -
three months ended;
$5 million (2011 - $1 million) - six
months ended 10 (20) 34 (2)
Reclassification to net earnings,
net of taxes of
$nil (2011 - $5 million) - three
months ended;
$nil (2011 - $9 million) - six
months ended (2) 18 (1) 29
----------------------------------------------------------------------------
8 (2) 33 27
Foreign currency translation
adjustment
Translation of net investment (8) (3) - 2
----------------------------------------------------------------------------
Other comprehensive income (loss),
net of taxes - (5) 33 29
----------------------------------------------------------------------------
Comprehensive income $ 753 $ 924 $ 1,213 $ 1,004
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Consolidated Statements of Changes in Equity
Six Months Ended
---------------------
Jun 30 Jun 30
(millions of Canadian dollars, unaudited) Note 2012 2011
----------------------------------------------------------------------------
Share capital 9
Balance - beginning of period $ 3,507 $ 3,147
Issued upon exercise of stock options 140 181
Previously recognized liability on stock options
exercised for common shares 39 97
Purchase of common shares under Normal Course
Issuer Bid (16) -
----------------------------------------------------------------------------
Balance - end of period 3,670 3,425
----------------------------------------------------------------------------
Retained earnings
Balance - beginning of period 19,365 17,212
Net earnings 1,180 975
Purchase of common shares under Normal Course
Issuer Bid 9 (121) -
Dividends on common shares 9 (231) (198)
----------------------------------------------------------------------------
Balance - end of period 20,193 17,989
----------------------------------------------------------------------------
Accumulated other comprehensive income 10
Balance - beginning of period 26 9
Other comprehensive income, net of taxes 33 29
----------------------------------------------------------------------------
Balance - end of period 59 38
----------------------------------------------------------------------------
Shareholders' equity $ 23,922 $ 21,452
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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 2012 2011 2012 2011
----------------------------------------------------------------------------
Operating activities
Net earnings $ 753 $ 929 $ 1,180 $ 975
Non-cash items
Depletion, depreciation and
amortization 1,084 870 2,059 1,719
Share-based compensation (115) (188) (222) (60)
Asset retirement obligation
accretion 38 31 75 64
Unrealized risk management gain (144) (118) (84) (64)
Unrealized foreign exchange loss
(gain) 71 (33) 11 (122)
Deferred income tax expense 62 57 10 110
Equity loss from jointly
controlled entity 4 5 - 5 -
Horizon asset impairment
provision 7 - - - 396
Insurance recovery - property
damage 7 - - - (396)
Other 17 11 40 (18)
Abandonment expenditures (39) (29) (115) (93)
Net change in non-cash working
capital (117) (98) 113 166
----------------------------------------------------------------------------
1,615 1,432 3,072 2,677
----------------------------------------------------------------------------
Financing activities
(Repayment) issue of bank credit
facilities, net (352) 205 (559) 333
Issue of medium-term notes, net 498 - 498 -
Issue of common shares on exercise
of stock options 9 19 140 181
Purchase of common shares under
Normal Course Issuer Bid (114) - (137) -
Dividends on common shares (115) (98) (214) (180)
Net change in non-cash working
capital (13) (5) (16) (5)
----------------------------------------------------------------------------
(87) 121 (288) 329
----------------------------------------------------------------------------
Investing activities
Expenditures on exploration and
evaluation assets and property,
plant and equipment (1,285) (1,376) (2,805) (3,006)
Investment in other long-term
assets 2 - 2 (346)
Net change in non-cash working
capital (248) (221) (5) 330
----------------------------------------------------------------------------
(1,531) (1,597) (2,808) (3,022)
----------------------------------------------------------------------------
Decrease in cash and cash
equivalents (3) (44) (24) (16)
Cash and cash equivalents -
beginning of period 13 50 34 22
----------------------------------------------------------------------------
Cash and cash equivalents -
end of period $ 10 $ 6 $ 10 $ 6
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Interest paid $ 93 $ 78 $ 226 $ 225
Income taxes paid $ 170 $ 93 $ 435 $ 375
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Notes to the Consolidated Financial Statements
(tabular amounts in millions of Canadian dollars, unless otherwise stated,
unaudited)
1. ACCOUNTING POLICIES
Canadian Natural Resources Limited (the "Company") is a senior independent crude
oil and natural gas exploration, development and production company. The
Company's exploration and production operations are focused in North America,
largely in Western Canada; the United Kingdom ("UK") portion of the North Sea;
and Cote d'Ivoire, Gabon, and South Africa in Offshore Africa.
The Horizon Oil Sands Mining and Upgrading segment ("Horizon") produces
synthetic crude oil through bitumen mining and upgrading operations.
Within Western Canada, the Company maintains certain midstream activities that
include pipeline operations and an electricity co-generation system.
The Company was incorporated in Alberta, Canada. The address of its registered
office is 2500, 855-2 Street S.W., Calgary, Alberta.
These interim consolidated financial statements have been prepared in accordance
with International Financial Reporting Standards ("IFRS") as issued by the
International Accounting Standards Board, applicable to the preparation of
interim financial statements, including International Accounting Standard
("IAS") 34, "Interim Financial Reporting", following the same accounting
policies as the audited consolidated financial statements of the Company as at
December 31, 2011. These interim consolidated financial statements contain
disclosures that are supplemental to the Company's annual audited consolidated
financial statements. Certain disclosures that are normally required to be
included in the notes to the annual audited consolidated financial statements
have been condensed. These interim consolidated financial statements should be
read in conjunction with the Company's audited consolidated financial statements
and notes thereto for the year ended December 31, 2011.
2. EXPLORATION AND EVALUATION ASSETS
Oil Sands
Mining and
Exploration and Production Upgrading Total
----------------------------------------------------------------------------
North North Offshore
America Sea Africa
----------------------------------------------------------------------------
Cost
At December 31, 2011$ 2,442 $ - $ 33 $ - $ 2,475
Additions 239 - 1 - 240
Transfers to
property, plant and
equipment (76) - - - (76)
----------------------------------------------------------------------------
At June 30, 2012 $ 2,605 $ - $ 34 $ - $ 2,639
----------------------------------------------------------------------------
----------------------------------------------------------------------------
3. PROPERTY, PLANT AND EQUIPMENT
Oil Sands
Mining and
Exploration and Production Upgrading
----------------------------------------------------------------------------
North Offshore
America North Sea Africa
----------------------------------------------------------------------------
Cost
At December 31,
2011 $ 46,120 $ 4,147 $ 3,044 $ 15,211
Additions 1,794 123 16 679
Transfers from E&E
assets 76 - - -
Disposals/
derecognitions (39) (39) (8) (5)
Foreign exchange
adjustments and
other - 11 7 -
----------------------------------------------------------------------------
At June 30, 2012 $ 47,951 $ 4,242 $ 3,059 $ 15,885
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Accumulated
depletion and
depreciation
At December 31,
2011 $ 21,721 $ 2,512 $ 2,152 $ 776
Expense 1,602 158 78 209
Disposals/
derecognitions (39) (39) (6) (4)
Foreign exchange
adjustments and
other - (2) 11 (6)
----------------------------------------------------------------------------
At June 30, 2012 $ 23,284 $ 2,629 $ 2,235 $ 975
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net book value
- at June 30, 2012 $ 24,667 $ 1,613 $ 824 $ 14,910
- at December 31,
2011 $ 24,399 $ 1,635 $ 892 $ 14,435
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Midstream Head Office Total
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Cost
At December 31,
2011 $ 298 $ 234 $ 69,054
Additions 5 15 2,632
Transfers from E&E
assets - - 76
Disposals/
derecognitions - - (91)
Foreign exchange
adjustments and
other - - 18
----------------------------------------------------------------------------
At June 30, 2012 $ 303 $ 249 $ 71,689
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Accumulated
depletion and
depreciation
At December 31,
2011 $ 96 $ 166 $ 27,423
Expense 4 8 2,059
Disposals/
derecognitions - - (88)
Foreign exchange
adjustments and
other - - 3
----------------------------------------------------------------------------
At June 30, 2012 $ 100 $ 174 $ 29,397
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net book value
- at June 30, 2012 $ 203 $ 75 $ 42,292
- at December 31,
2011 $ 202 $ 68 $ 41,631
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Development projects not subject to depletion
----------------------------------------------------------------------------
At June 30, 2012 $ 1,294
At December 31, 2011 $ 1,443
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The Company acquired a number of producing crude oil and natural gas assets in
the North America Exploration and Production segment for total cash
consideration of $45 million during the six months ended June 30, 2012 (year
ended December 31, 2011 - $1,012 million), net of associated asset retirement
obligations of $4 million (year ended December 31, 2011 - $79 million).
Interests in jointly controlled assets were acquired with full tax basis. No
working capital or debt obligations were assumed.
The Company capitalizes construction period interest for qualifying assets based
on costs incurred and the Company's cost of borrowing. Interest capitalization
to a qualifying asset ceases once construction is substantially complete. For
the six months ended June 30, 2012, pre-tax interest of $39 million was
capitalized to property, plant and equipment (June 30, 2011 - $24 million) using
a capitalization rate of 4.8% (June 30, 2011 - 4.7%).
4. OTHER LONG-TERM ASSETS
-----------------------
Jun 30 Dec 31
2012 2011
----------------------------------------------------------------------------
Investment in North West Redwater Partnership $ 314 $ 321
Risk management (note 13) 41 -
Other 33 70
----------------------------------------------------------------------------
388 391
Less: current portion 41 -
----------------------------------------------------------------------------
$ 347 $ 391
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Other long-term assets include an investment in the 50% owned North West
Redwater Partnership ("Redwater"). The investment is accounted for using the
equity method. Redwater has entered into an agreement to construct and operate a
bitumen upgrader and refinery, which targets to process bitumen for the Company
and the Government of Alberta under a 30 year fee-for-service tolling agreement.
Project development is dependent upon completion of detailed engineering and
final project sanction by Redwater and its partners, and approval of the final
tolls.
5. LONG-TERM DEBT
-----------------------
Jun 30 Dec 31
2012 2011
----------------------------------------------------------------------------
Canadian dollar denominated debt
Bank credit facilities $ 240 $ 796
Medium-term notes 1,300 800
----------------------------------------------------------------------------
1,540 1,596
----------------------------------------------------------------------------
US dollar denominated debt
US dollar debt securities (US$6,900 million) 7,032 7,017
Less: original issue discount on US dollar debt
securities (1) (21) (21)
----------------------------------------------------------------------------
7,011 6,996
Fair value impact of interest rate swaps on US dollar
debt securities (2) 25 31
----------------------------------------------------------------------------
7,036 7,027
----------------------------------------------------------------------------
Long-term debt before transaction costs 8,576 8,623
Less: transaction costs (1) (3) (54) (52)
----------------------------------------------------------------------------
8,522 8,571
Less: current portion (1) (2) 1,165 359
----------------------------------------------------------------------------
$ 7,357 $ 8,212
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) The Company has included unamortized original issue discounts and
directly attributable transaction costs in the carrying amount of the
outstanding debt.
(2) The carrying amounts of US$350 million of 5.45% notes due October 2012
and US$350 million of 4.90% notes due December 2014 were adjusted by $25
million (December 2011 - $31 million) to reflect the fair value impact
of hedge accounting.
(3) Transaction costs primarily represent underwriting commissions charged
as a percentage of the related debt offerings, as well as legal, rating
agency and other professional fees.
Bank Credit Facilities
As at June 30, 2012, the Company had in place unsecured bank credit facilities
of $4,724 million, comprised of:
- a $200 million demand credit facility;
- a revolving syndicated credit facility of $3,000 million maturing June 2015;
- a revolving syndicated credit facility of $1,500 million maturing June 2016; and
- a GBP 15 million demand credit facility related to the Company's North Sea
operations.
During the second quarter of 2012, the $1,500 million revolving syndicated
credit facility was extended to June 2016. Each of the $3,000 million and $1,500
million facilities is extendible annually for one-year periods at the mutual
agreement of the Company and the lenders. If the facilities are not extended,
the full amount of the outstanding principal would be repayable on the maturity
date. Borrowings under these facilities may be made by way of pricing referenced
to Canadian dollar or US dollar bankers' acceptances, or LIBOR, US base rate or
Canadian prime loans.
The Company's weighted average interest rate on bank credit facilities
outstanding as at June 30, 2012, was 1.9% (June 30, 2011 - 2.8%), and on
long-term debt outstanding for the six months ended June 30, 2012 was 4.8% (June
30, 2011 - 4.7%).
In addition to the outstanding debt, letters of credit and financial guarantees
aggregating $463 million, including $105 million related to Horizon and $273
million related to North Sea operations, were outstanding at June 30, 2012.
Subsequent to June 30, 2012, the financial guarantee related to Horizon was
reduced to $95 million. The Company also issued a financial guarantee for $100
million supporting a revolving credit facility in the 50% owned North West
Redwater Partnership.
Medium-Term Notes
During the second quarter of 2012, the Company issued $500 million of 3.05%
medium-term unsecured notes due June 2019. Proceeds from the securities issued
were used to repay bank indebtedness and for general corporate purposes. After
issuing these securities, the Company has $2,500 million remaining on its
outstanding $3,000 million base shelf prospectus that allows for the issue of
medium-term notes in Canada, which expires in November 2013. If issued, these
securities will bear interest as determined at the date of issuance.
US Dollar Debt Securities
The Company has US$2,000 million remaining on its outstanding US$3,000 million
base shelf prospectus that allows for the issue of US dollar debt securities in
the United States, which expires in November 2013. If issued, these securities
will bear interest as determined at the date of issuance.
6. OTHER LONG-TERM LIABILITIES
-----------------------
Jun 30 Dec 31
2012 2011
----------------------------------------------------------------------------
Asset retirement obligations $ 3,564 $ 3,577
Share-based compensation 149 432
Risk management (note 13) 188 274
Other 107 85
----------------------------------------------------------------------------
4,008 4,368
Less: current portion 144 455
----------------------------------------------------------------------------
$ 3,864 $ 3,913
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Asset retirement obligations
The Company's asset retirement obligations are expected to be settled on an
ongoing basis over a period of approximately 60 years and have been discounted
using a weighted average discount rate of 4.6% (December 31, 2011 - 4.6%). A
reconciliation of the discounted asset retirement obligations is as follows:
-----------------------
Jun 30 Dec 31
2012 2011
----------------------------------------------------------------------------
Balance - beginning of period $ 3,577 $ 2,624
Liabilities incurred 18 12
Liabilities acquired 4 79
Liabilities settled (115) (213)
Asset retirement obligation accretion 75 130
Revision of estimates 3 924
Foreign exchange 2 21
----------------------------------------------------------------------------
Balance - end of period $ 3,564 $ 3,577
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Share-based compensation
As the Company's Option Plan provides current employees with the right to elect
to receive common shares or a cash payment in exchange for stock options
surrendered, a liability for potential cash settlements is recognized. The
current portion represents the maximum amount of the liability payable within
the next twelve month period if all vested stock options are surrendered for
cash settlement.
-----------------------
Jun 30 Dec 31
2012 2011
----------------------------------------------------------------------------
Balance - beginning of period $ 432 $ 663
Share-based compensation recovery (222) (102)
Cash payment for stock options surrendered (7) (14)
Transferred to common shares (39) (115)
Capitalized to (recovered from) Oil Sands Mining
and Upgrading (15) -
----------------------------------------------------------------------------
Balance - end of period 149 432
Less: current portion 113 384
----------------------------------------------------------------------------
$ 36 $ 48
----------------------------------------------------------------------------
----------------------------------------------------------------------------
7. HORIZON ASSET IMPAIRMENT PROVISION AND INSURANCE RECOVERY
In 2011, the Company recognized an asset impairment provision in the Oil Sands
Mining and Upgrading segment of $396 million, net of accumulated depletion and
amortization, related to the property damage resulting from a fire in the
Horizon primary upgrading coking plant. The Company also recorded final property
damage insurance recoveries of $393 million and business interruption insurance
recoveries of $333 million in 2011. In the first quarter of 2012, upon final
settlement of its insurance claims, all outstanding insurance proceeds were
collected.
8. INCOME TAXES
The provision for income tax is as follows:
Three Months Ended Six Months Ended
-----------------------------------------------
Jun 30 Jun 30 Jun 30 Jun 30
2012 2011 2012 2011
----------------------------------------------------------------------------
Current corporate income tax
- North America $ 124 $ 79 $ 237 $ 170
Current corporate income tax
- North Sea 19 70 64 116
Current corporate income tax
- Offshore Africa 64 24 100 44
Current PRT(1) expense -
North Sea 1 46 32 54
Other taxes 5 6 11 12
----------------------------------------------------------------------------
Current income tax expense 213 225 444 396
----------------------------------------------------------------------------
Deferred corporate income
tax expense 59 55 11 98
Deferred PRT(1) expense
(recovery) - North Sea 3 2 (1) 12
----------------------------------------------------------------------------
Deferred income tax expense 62 57 10 110
----------------------------------------------------------------------------
Income tax expense $ 275 $ 282 $ 454 $ 506
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Petroleum Revenue Tax.
During 2011, the Canadian Federal government enacted legislation to implement
several taxation changes. These changes include a requirement that, beginning in
2012, partnership income must be included in the taxable income of each
corporate partner based on the tax year of the partner, rather than the fiscal
year of the partnership. The legislation includes a five-year transition
provision and has no impact on net earnings.
During the first quarter of 2011, the UK government enacted an increase to the
supplementary income tax rate charged on profits from UK North Sea crude oil and
natural gas production, increasing the combined corporate and supplementary
income tax rate from 50% to 62%. As a result of the income tax rate change, the
Company's deferred income tax liability was increased by $104 million as at
March 31, 2011.
Subsequent to June 30, 2012, the UK government enacted legislation to restrict
the combined corporate and supplementary income tax relief on decommissioning
expenditures to 50%. This income tax rate change will result in an increase in
the Company's deferred income tax liability of approximately $58 million.
9. SHARE CAPITAL
Authorized
Preferred shares issuable in a series.
Unlimited number of common shares without par value.
--------------------------------
Six Months Ended Jun 30, 2012
Number of
shares
Issued common shares (thousands) Amount
----------------------------------------------------------------------------
Balance - beginning of period 1,096,460 $ 3,507
Issued upon exercise of stock options 4,659 140
Previously recognized liability on stock
options exercised for common shares - 39
Purchase of common shares under Normal
Course Issuer Bid (4,622) (16)
----------------------------------------------------------------------------
Balance - end of period 1,096,497 $ 3,670
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Preferred Shares
During the second quarter of 2012, the Company amended its Articles by special
resolution of the Shareholders, changing the designation of its Class 1
preferred shares to "Preferred Shares" which may be issuable in series. If
issued, the number of shares in each series, and the designation, rights,
privileges, restrictions and conditions attached to the shares will be
determined by the Board of Directors of the Company.
Dividend Policy
On March 6, 2012, the Board of Directors set the regular quarterly dividend at
$0.105 per common share (2011 - $0.09 per common share). The Company has paid
regular quarterly dividends in January, April, July, and October of each year
since 2001. The dividend policy undergoes a periodic review by the Board of
Directors and is subject to change.
Normal Course Issuer Bid
The Company's Normal Course Issuer Bid announced in 2011 expired April 5, 2012.
In April 2012, the Company announced a Normal Course Issuer Bid to purchase
through the facilities of the Toronto Stock Exchange and the New York Stock
Exchange, during the twelve month period commencing April 9, 2012 and ending
April 8, 2013, up to 55,027,447 common shares.
For the six months ended June 30, 2012, the Company purchased 4,621,600 common
shares at a weighted average price of $29.63 per common share, for a total cost
of $137 million. Retained earnings were reduced by $121 million, representing
the excess of the purchase price of common shares over their average carrying
value. Subsequent to June 30, 2012, the Company purchased 1,575,000 common
shares at a weighted average price of $26.81 per common share for a total cost
of $42 million.
Stock Options
The following table summarizes information relating to stock options outstanding
at June 30, 2012:
-------------------------------
Six Months Ended Jun 30, 2012
----------------------------------------------------------------------------
Weighted
Stock options average
(thousands) exercise price
----------------------------------------------------------------------------
Outstanding - beginning of period 73,486 $ 34.85
Granted 2,726 $ 33.15
Surrendered for cash settlement (753) $ 30.63
Exercised for common shares (4,659) $ 30.05
Forfeited (4,727) $ 36.77
----------------------------------------------------------------------------
Outstanding - end of period 66,073 $ 35.02
----------------------------------------------------------------------------
Exercisable - end of period 21,449 $ 32.67
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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
2012 2011
----------------------------------------------------------------------------
Derivative financial instruments designated as cash
flow hedges $ 95 $ 60
Foreign currency translation adjustment (36) (22)
----------------------------------------------------------------------------
$ 59 $ 38
----------------------------------------------------------------------------
----------------------------------------------------------------------------
11. CAPITAL DISCLOSURES
The Company does not have any externally imposed regulatory capital requirements
for managing capital. The Company has defined its capital to mean its long-term
debt and consolidated shareholders' equity, as determined at each reporting
date.
The Company's objectives when managing its capital structure are to maintain
financial flexibility and balance to enable the Company to access capital
markets to sustain its on-going operations and to support its growth strategies.
The Company primarily monitors capital on the basis of an internally derived
financial measure referred to as its "debt to book capitalization ratio", which
is the arithmetic ratio of current and long-term debt divided by the sum of the
carrying value of shareholders' equity plus current and long-term debt. The
Company's internal targeted range for its debt to book capitalization ratio is
35% to 45%. This range may be exceeded in periods when a combination of capital
projects, acquisitions, or lower commodity prices occurs. The Company may be
below the low end of the targeted range when cash flow from operating activities
is greater than current investment activities. At June 30, 2012, the ratio was
below the target range at 26%.
Readers are cautioned that the debt to book capitalization ratio is not defined
by IFRS and this financial measure may not be comparable to similar measures
presented by other companies. Further, there are no assurances that the Company
will continue to use this measure to monitor capital or will not alter the
method of calculation of this measure in the future.
-----------------------
Jun 30 Dec 31
2012 2011
----------------------------------------------------------------------------
Long-term debt (1) $ 8,522 $ 8,571
Total shareholders' equity $ 23,922 $ 22,898
Debt to book capitalization 26% 27%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Includes the current portion of long-term debt.
12. NET EARNINGS PER COMMON SHARE
Three Months Ended Six Months Ended
-----------------------------------------------
Jun 30 Jun 30 Jun 30 Jun 30
2012 2011 2012 2011
----------------------------------------------------------------------------
Weighted average common
shares outstanding
- basic(thousands of shares) 1,099,046 1,096,784 1,099,600 1,095,243
Effect of dilutive stock
options (thousands of
shares) 2,055 8,521 3,131 10,261
----------------------------------------------------------------------------
Weighted average common
shares outstanding
- diluted (thousands of
shares) 1,101,101 1,105,305 1,102,731 1,105,504
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net earnings $ 753 $ 929 $ 1,180 $ 975
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net earnings per common
share - basic $ 0.68 $ 0.85 $ 1.07 $ 0.89
- diluted $ 0.68 $ 0.84 $ 1.07 $ 0.88
----------------------------------------------------------------------------
----------------------------------------------------------------------------
13. FINANCIAL INSTRUMENTS
The carrying amounts of the Company's financial instruments by category were as
follows:
-----------------------------------------------------------
Jun 30, 2012
----------------------------------------------------------------------------
Fair Financial
Loans and value liabilities
receivables through Derivatives at
at amortized profit or used for amortized
Asset (liability) cost loss hedging cost Total
----------------------------------------------------------------------------
Accounts
receivable $ 1,527 $ - $ - $ - $ 1,527
Other long-term
assets - 45 (4) - 41
Accounts payable - - - (415) (415)
Accrued
liabilities - - - (2,196) (2,196)
Other long-term
liabilities - - (188) (98) (286)
Long-term debt
(1) - - - (8,522) (8,522)
----------------------------------------------------------------------------
$ 1,527 $ 45 $ (192)$ (11,231)$ (9,851)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Dec 31, 2011
----------------------------------------------------------------------------
Fair
Loans and value Financial
receivables through Derivatives liabilities
at amortized profit used for at amortized
Asset (liability) cost or loss hedging cost Total
----------------------------------------------------------------------------
Accounts
receivable $ 2,077 $ - $ - $ - $ 2,077
Accounts payable - - - (526) (526)
Accrued
liabilities - - - (2,347) (2,347)
Other long-term
liabilities - (38) (236) (75) (349)
Long-term debt
(1) - - - (8,571) (8,571)
----------------------------------------------------------------------------
$ 2,077 $ (38)$ (236)$ (11,519)$ (9,716)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Includes the current portion of long-term debt.
The carrying amount of the Company's financial instruments approximates their
fair value, except for fixed rate long-term debt as noted below. The fair values
of the Company's other long-term liabilities and fixed rate long-term debt are
outlined below:
--------------------------------------
Jun 30, 2012
----------------------------------------------------------------------------
Carrying
amount Fair value
----------------------------------------------------------------------------
Asset (liability) (1) Level 1 Level 2
----------------------------------------------------------------------------
Other long-term assets $ 41 $ - $ 41
Other long-term liabilities (188) - (188)
Fixed rate long-term debt (2) (3) (4) (8,282) (9,450) -
----------------------------------------------------------------------------
$ (8,429) $ (9,450) $ (147)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Dec 31, 2011
----------------------------------------------------------------------------
Carrying
amount Fair value
----------------------------------------------------------------------------
Asset (liability) (1) Level 1 Level 2
----------------------------------------------------------------------------
Other long-term liabilities $ (274) $ - $ (274)
Fixed rate long-term debt (2) (3) (4) (7,775) (9,120) -
----------------------------------------------------------------------------
$ (8,049) $ (9,120) $ (274)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Excludes financial assets and liabilities where the carrying amount
approximates fair value due to the liquid nature of the asset or
liability (cash and cash equivalents, accounts receivable, accounts
payable and accrued liabilities).
(2) The carrying amounts of US$350 million of 5.45% notes due October 2012
and US$350 million of 4.90% notes due December 2014 have been adjusted
by $25 million (December 31, 2011 - $31 million) to reflect the fair
value impact of hedge accounting.
(3) The fair value of fixed rate long-term debt has been determined based on
quoted market prices.
(4) Includes the current portion of long-term debt.
The following provides a summary of the carrying amounts of derivative contracts
held and a reconciliation to the Company's consolidated balance sheets.
-----------------------
Asset (liability) Jun 30, Dec 31,
2012 2011
----------------------------------------------------------------------------
Derivatives held for trading
Crude oil price collars $ 57 $ (13)
Crude oil put options, net of put premium financing
obligations 14 -
Foreign currency forward contracts (26) (25)
Cash flow hedges
Cross currency swaps (192) (236)
----------------------------------------------------------------------------
$ (147) $ (274)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Included within:
Current portion of other long-term assets
(liabilities) $ 41 $ (43)
Other long-term liabilities (188) (231)
----------------------------------------------------------------------------
$ (147) $ (274)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Ineffectiveness arising from cash flow hedges recognized in net earnings for the
six months ended June 30, 2012 resulted in a gain of $1 million (December 31,
2011 - loss of $2 million).
Risk Management
The Company uses derivative financial instruments to manage its commodity price,
foreign currency and interest rate exposures. These financial instruments are
entered into solely for hedging purposes and are not used for speculative
purposes.
The estimated fair value of derivative financial instruments has been determined
based on appropriate internal valuation methodologies and/or third party
indications. Fair values determined using valuation models require the use of
assumptions concerning the amount and timing of future cash flows and discount
rates. In determining these assumptions, the Company primarily relied on
external, readily-observable market inputs including quoted commodity prices and
volatility, interest rate yield curves, and foreign exchange rates. The
resulting fair value estimates may not necessarily be indicative of the amounts
that could be realized or settled in a current market transaction and these
differences may be material.
The changes in estimated fair values of derivative financial instruments
included in risk management assets (liabilities) were recognized in the
financial statements as follows:
-------------------------------------
Six Months Ended Year Ended
Asset (liability) Jun 30, 2012 Dec 31, 2011
----------------------------------------------------------------------------
Balance - beginning of period $ (274) $ (485)
Net cost of outstanding put options 38 -
Net change in fair value of outstanding
derivative financial instruments
attributable to:
Risk management activities 84 128
Foreign exchange 5 42
Other comprehensive income 38 41
----------------------------------------------------------------------------
(109) (274)
Add: put premium financing obligations
(1) (38) -
----------------------------------------------------------------------------
Balance - end of period (147) (274)
Less: current portion 41 (43)
----------------------------------------------------------------------------
$ (188) $ (231)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) The Company has negotiated payment of put option premiums with various
counterparties at the time of actual settlement of the respective
options. These obligations are reflected in the net risk management
asset (liability).
Net (gains) losses from risk management activities were as follows:
Three Months Ended Six Months Ended
-----------------------------------------------
Jun 30 Jun 30 Jun 30 Jun 30
2012 2011 2012 2011
----------------------------------------------------------------------------
Net realized risk management
(gain) loss $ (61) $ 34 $ 33 $ 104
Net unrealized risk
management gain (144) (118) (84) (64)
----------------------------------------------------------------------------
$ (205) $ (84) $ (51) $ 40
----------------------------------------------------------------------------
----------------------------------------------------------------------------
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, 2012, the Company had the following derivative financial instruments
outstanding to manage its commodity price risks:
Sales contracts
Weighted
Remaining term Volume average price Index
----------------------------------------------------------------------------
Crude oil
Crude oil price US$80.00 -
collars Jul 2012 - Dec 2012 50,000 bbl/d US$134.87 Brent
US$80.00 -
Jul 2012 - Dec 2012 50,000 bbl/d US$136.06 Brent
US$80.00 -
Jul 2012 - Jun 2013 50,000 bbl/d US$145.07 Brent
Crude oil puts Jul 2012 - Dec 2012 100,000 bbl/d US$80.00 WTI
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The cost of outstanding put options and their respective periods of settlement
are as follows:
Q3 2012 Q4 2012
----------------------------------------------------------------------------
Cost ($ millions) US$19 US$19
----------------------------------------------------------------------------
----------------------------------------------------------------------------
The Company's outstanding commodity derivative financial instruments are
expected to be settled monthly based on the applicable index pricing for the
respective contract month.
Interest rate risk management
The Company is exposed to interest rate price risk on its fixed rate long-term
debt and to interest rate cash flow risk on its floating rate long-term debt.
The Company periodically enters into interest rate swap contracts to manage its
fixed to floating interest rate mix on long-term debt. The interest rate swap
contracts require the periodic exchange of payments without the exchange of the
notional principal amounts on which the payments are based. At June 30, 2012,
the Company had no interest rate swap contracts outstanding.
Foreign currency exchange rate risk management
The Company is exposed to foreign currency exchange rate risk in Canada
primarily related to its US dollar denominated long-term debt and working
capital. The Company is also exposed to foreign currency exchange rate risk on
transactions conducted in other currencies in its subsidiaries and in the
carrying value of its foreign subsidiaries. The Company periodically enters into
cross currency swap contracts and foreign currency forward contracts to manage
known currency exposure on US dollar denominated long-term debt and working
capital. The cross currency swap contracts require the periodic exchange of
payments with the exchange at maturity of notional principal amounts on which
the payments are based. At June 30, 2012, the Company had the following cross
currency swap contracts outstanding:
Exchange
rate Interest Interest
Remaining term Amount (US$/C$) rate (US$) rate (C$)
----------------------------------------------------------------------------
Cross currency
Swaps Jul 2012 - Aug 2016 US$250 1.116 6.00% 5.40%
Jul 2012 - May 2017 US$1,100 1.170 5.70% 5.10%
Jul 2012 - Nov 2021 US$500 1.022 3.45% 3.96%
Jul 2012 - Mar 2038 US$550 1.170 6.25% 5.76%
----------------------------------------------------------------------------
----------------------------------------------------------------------------
All cross currency swap derivative financial instruments designated as hedges at
June 30, 2012, were classified as cash flow hedges.
In addition to the cross currency swap contracts noted above, at June 30, 2012,
the Company had US$2,472 million of foreign currency forward contracts
outstanding, with terms of approximately 30 days or less.
b) Credit Risk
Credit risk is the risk that a party to a financial instrument will cause a
financial loss to the Company by failing to discharge an obligation.
Counterparty credit risk management
The Company's accounts receivable are mainly with customers in the crude oil and
natural gas industry and are subject to normal industry credit risks. The
Company manages these risks by reviewing its exposure to individual companies on
a regular basis and where appropriate, ensures that parental guarantees or
letters of credit are in place to minimize the impact in the event of default.
At June 30, 2012, substantially all of the Company's accounts receivable were
due within normal trade terms.
The Company is also exposed to possible losses in the event of nonperformance by
counterparties to derivative financial instruments; however, the Company manages
this credit risk by entering into agreements with counterparties that are
substantially all investment grade financial institutions and other entities. At
June 30, 2012, the Company had net risk management assets of $22 million with
specific counterparties related to derivative financial instruments (December
31, 2011 - $nil).
c) Liquidity Risk
Liquidity risk is the risk that the Company will encounter difficulty in meeting
obligations associated with financial liabilities.
Management of liquidity risk requires the Company to maintain sufficient cash
and cash equivalents, along with other sources of capital, consisting primarily
of cash flow from operating activities, available credit facilities, and access
to debt capital markets, to meet obligations as they become due. The Company
believes it has adequate bank credit facilities to provide liquidity to manage
fluctuations in the timing of the receipt and/or disbursement of operating cash
flows.
The maturity dates for financial liabilities are as follows:
1 to less 2 to less
Less than than than
1 year 2 years 5 years Thereafter
----------------------------------------------------------------------------
Accounts payable $ 415 $ - $ - $ -
Accrued liabilities $ 2,196 $ - $ - $ -
Risk management $ - $ 37 $ 104 $ 47
Other long-term
liabilities $ 31 $ 23 $ 44 $ -
Long-term debt (1) $ 1,164 $ - $ 2,882 $ 4,526
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Long-term debt represents principal repayments only and does not reflect
fair value adjustments, original issue discounts or transaction costs.
14. COMMITMENTS AND CONTINGENCIES
The Company has committed to certain payments as follows:
Remaining
2012 2013 2014 2015 2016 Thereafter
----------------------------------------------------------------------------
Product transportation and
pipeline $ 119 $ 212 $ 201 $ 189 $ 125 $ 889
Offshore equipment
operating leases and
offshore drilling $ 76 $ 135 $ 100 $ 83 $ 53 $ 119
Office leases $ 15 $ 33 $ 34 $ 32 $ 33 $ 304
Other $ 150 $ 170 $ 96 $ 34 $ 2 $ 8
----------------------------------------------------------------------------
----------------------------------------------------------------------------
In addition to the commitments disclosed above, the Company has entered into
various agreements related to the engineering, procurement and construction of
subsequent phases of Horizon. These contracts can be cancelled by the Company
upon notice without penalty, subject to the costs incurred up to and in respect
of the cancellation.
The Company is a defendant and plaintiff in a number of legal actions arising in
the normal course of business. In addition, the Company is subject to certain
contractor construction claims. The Company believes that any liabilities that
might arise pertaining to any such matters would not have a material effect on
its consolidated financial position.
15. SEGMENTED INFORMATION
Exploration and Production
North America North Sea
(millions of Three Months Six Months Three Months Six Months
Canadian dollars, Ended Ended Ended Ended
unaudited) Jun 30 Jun 30 Jun 30 Jun 30
-------------- ------------- ------------ -------------
2012 2011 2012 2011 2012 2011 2012 2011
----------------------------------------------------------------------------
Segmented product
sales 2,757 3,207 5,815 5,913 236 342 515 631
Less: royalties (244) (391) (632) (717) - (1) (1) (2)
----------------------------------------------------------------------------
Segmented revenue 2,513 2,816 5,183 5,196 236 341 514 629
----------------------------------------------------------------------------
Segmented expenses
Production 505 466 1,087 924 119 109 204 195
Transportation and
blending 683 660 1,398 1,272 3 3 6 7
Depletion,
depreciation and
amortization 811 697 1,609 1,400 75 65 159 133
Asset retirement
obligation
accretion 21 17 42 35 7 8 14 16
Realized risk
management
activities (61) 34 33 104 - - - -
Horizon asset
impairment
provision - - - - - - - -
Insurance recovery -
property damage
(note 7) - - - - - - - -
Insurance recovery -
business
interruption
(note 7) - - - - - - - -
Equity loss from
jointly controlled
entity 5 - 5 - - - - -
----------------------------------------------------------------------------
Total segmented
expenses 1,964 1,874 4,174 3,735 204 185 383 351
----------------------------------------------------------------------------
Segmented earnings
(loss) before the
following 549 942 1,009 1,461 32 156 131 278
----------------------------------------------------------------------------
Non-segmented
expenses
Administration
Share-based
compensation
Interest and other
financing costs
Unrealized risk
management
activities
Foreign exchange
loss (gain)
----------------------------------------------------------------------------
Total non-segmented
expenses
----------------------------------------------------------------------------
Earnings before
taxes
Current income tax
expense
Deferred income tax
expense
----------------------------------------------------------------------------
Net earnings
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Exploration and Production
Total Exploration and
Offshore Africa Production
(millions of Three Months Six Months Three Months Six Months
Canadian dollars, Ended Ended Ended Ended
unaudited) Jun 30 Jun 30 Jun 30 Jun 30
------------- ------------- ------------- -------------
2012 2011 2012 2011 2012 2011 2012 2011
----------------------------------------------------------------------------
Segmented product
sales 240 173 457 388 3,233 3,722 6,787 6,932
Less: royalties (62) (2) (96) (22) (306) (394) (729) (741)
----------------------------------------------------------------------------
Segmented revenue 178 171 361 366 2,927 3,328 6,058 6,191
----------------------------------------------------------------------------
Segmented expenses
Production 51 33 73 75 675 608 1,364 1,194
Transportation and
blending 1 (1) 1 - 687 662 1,405 1,279
Depletion,
depreciation and
amortization 50 73 78 126 936 835 1,846 1,659
Asset retirement
obligation
accretion 2 1 3 3 30 26 59 54
Realized risk
management
activities - - - - (61) 34 33 104
Horizon asset
impairment
provision - - - - - - - -
Insurance recovery -
property damage
(note 7) - - - - - - - -
Insurance recovery -
business
interruption
(note 7) - - - - - - - -
Equity loss from
jointly controlled
entity - - - - 5 - 5 -
----------------------------------------------------------------------------
Total segmented
expenses 104 106 155 204 2,272 2,165 4,712 4,290
----------------------------------------------------------------------------
Segmented earnings
(loss) before the
following 74 65 206 162 655 1,163 1,346 1,901
----------------------------------------------------------------------------
Non-segmented
expenses
Administration
Share-based
compensation
Interest and other
financing costs
Unrealized risk
management
activities
Foreign exchange
loss (gain)
----------------------------------------------------------------------------
Total non-segmented
expenses
----------------------------------------------------------------------------
Earnings before
taxes
Current income tax
expense
Deferred income tax
expense
----------------------------------------------------------------------------
Net earnings
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Oil Sands Mining and
Upgrading Midstream
(millions of Six Months Three Months Six Months
Canadian dollars, Three Months Ended Ended Ended
unaudited) Ended Jun 30 Jun 30 Jun 30 Jun 30
--------------------------------------------------------
2012 2011 2012 2011 2012 2011 2012 2011
----------------------------------------------------------------------------
Segmented product
sales 951 3 1,365 89 22 21 43 43
Less: royalties (55) - (76) (4) - - - -
----------------------------------------------------------------------------
Segmented revenue 896 3 1,289 85 22 21 43 43
----------------------------------------------------------------------------
Segmented expenses
Production 388 221 734 477 7 5 14 12
Transportation and
blending 18 15 30 31 - - - -
Depletion,
depreciation and
amortization 146 33 209 56 2 2 4 4
Asset retirement
obligation
accretion 8 5 16 10 - - - -
Realized risk
management
activities - - - - - - - -
Horizon asset
impairment
provision - - - 396 - - - -
Insurance recovery -
property damage
(note 7) - - - (396) - - - -
Insurance recovery -
business
interruption
(note 7) - (136) - (136) - - - -
Equity loss from
jointly controlled
entity - - - - - - - -
----------------------------------------------------------------------------
Total segmented
expenses 560 138 989 438 9 7 18 16
----------------------------------------------------------------------------
Segmented earnings
(loss) before the
following 336 (135) 300 (353) 13 14 25 27
----------------------------------------------------------------------------
Non-segmented
expenses
Administration
Share-based
compensation
Interest and other
financing costs
Unrealized risk
management
activities
Foreign exchange
loss (gain)
----------------------------------------------------------------------------
Total non-segmented
expenses
----------------------------------------------------------------------------
Earnings before
taxes
Current income tax
expense
Deferred income tax
expense
----------------------------------------------------------------------------
Net earnings
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Inter-segment elimination
and other Total
(millions of Three Months Six Months Three Months Six Months
Canadian dollars, Ended Ended Ended Ended
unaudited) Jun 30 Jun 30 Jun 30 Jun 30
--------------------------------------------------------
2012 2011 2012 2011 2012 2011 2012 2011
----------------------------------------------------------------------------
Segmented product
sales (19) (19) (37) (35) 4,187 3,727 8,158 7,029
Less: royalties - - - - (361) (394) (805) (745)
----------------------------------------------------------------------------
Segmented revenue (19) (19) (37) (35) 3,826 3,333 7,353 6,284
----------------------------------------------------------------------------
Segmented expenses
Production (2) (1) (6) (5) 1,068 833 2,106 1,678
Transportation and
blending (14) (12) (27) (24) 691 665 1,408 1,286
Depletion,
depreciation and
amortization - - - - 1,084 870 2,059 1,719
Asset retirement
obligation
accretion - - - - 38 31 75 64
Realized risk
management
activities - - - - (61) 34 33 104
Horizon asset
impairment
provision - - - - - - - 396
Insurance recovery -
property damage
(note 7) - - - - - - - (396)
Insurance recovery -
business
interruption
(note 7) - - - - - (136) - (136)
Equity loss from
jointly controlled
entity - - - - 5 - 5 -
----------------------------------------------------------------------------
Total segmented
expenses (16) (13) (33) (29) 2,825 2,297 5,686 4,715
----------------------------------------------------------------------------
Segmented earnings
(loss) before the
following (3) (6) (4) (6) 1,001 1,036 1,667 1,569
----------------------------------------------------------------------------
Non-segmented
expenses
Administration 77 69 142 123
Share-based
compensation (115) (188) (222) (60)
Interest and other
financing costs 93 99 189 193
Unrealized risk
management
activities (144) (118) (84) (64)
Foreign exchange
loss (gain) 62 (37) 8 (104)
----------------------------------------------------------------------------
Total non-segmented
expenses (27) (175) 33 88
----------------------------------------------------------------------------
Earnings before
taxes 1,028 1,211 1,634 1,481
Current income tax
expense 213 225 444 396
Deferred income tax
expense 62 57 10 110
----------------------------------------------------------------------------
Net earnings 753 929 1,180 975
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Capital Expenditures (1)
Period Ended
---------------------------------------------------
Jun 30, 2012
----------------------------------------------------------------------------
Non cash
and fair value Capitalized
Net 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)(4) 639 35 674
Midstream 5 - 5
Head office 15 - 15
----------------------------------------------------------------------------
$ 2,565 $ 52 $ 2,617
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Period Ended
----------------------------------------------------
Jun 30, 2011
----------------------------------------------------------------------------
Non cash and fair Capitalized
Net expenditures value changes(2) costs
----------------------------------------------------------------------------
Exploration and
evaluation assets
Exploration and
Production
North America $ 114 $ (136) $ (22)
North Sea - (4) (4)
Offshore Africa 1 - 1
----------------------------------------------------------------------------
$ 115 $ (140) $ (25)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Property, plant and
equipment
Exploration and
Production
North America $ 2,031 $ 142 $ 2,173
North Sea 110 4 114
Offshore Africa 49 (17) 32
----------------------------------------------------------------------------
2,190 129 2,319
Oil Sands Mining and
Upgrading(3)(4) 685 (406) 279
Midstream 4 - 4
Head office 12 - 12
----------------------------------------------------------------------------
$ 2,891 $ (277) $ 2,614
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) This table provides a reconciliation of capitalized costs and does not
include the impact of foreign exchange adjustments and accumulated
depletion and depreciation.
(2) Asset retirement obligations, deferred income tax adjustments related to
differences between carrying amounts and tax values, transfers of
exploration and evaluation assets, and other fair value adjustments.
(3) Net expenditures for Oil Sands Mining and Upgrading also include
capitalized interest and share-based compensation.
(4) During the first quarter of 2011, the Company derecognized certain
property, plant and equipment related to the coker fire at Horizon in
the amount of $411 million. This amount was included in non cash and
fair value changes.
Segmented Assets
Total Assets
-----------------------
Jun 30 Dec 31
2012 2011
----------------------------------------------------------------------------
Exploration and Production
North America $ 28,822 $ 28,554
North Sea 1,761 1,809
Offshore Africa 993 1,070
Other 32 23
Oil Sands Mining and Upgrading 15,568 15,433
Midstream 330 321
Head office 76 68
----------------------------------------------------------------------------
$ 47,582 $ 47,278
----------------------------------------------------------------------------
----------------------------------------------------------------------------
SUPPLEMENTARY INFORMATION
INTEREST COVERAGE RATIOS
The following financial ratios are provided in connection with the Company's
continuous offering of medium-term notes pursuant to the short form prospectus
dated October 2011. These ratios are based on the Company's interim consolidated
financial statements that are prepared in accordance with accounting principles
generally accepted in Canada.
Interest coverage ratios for the twelve month period ended June
30, 2012:
----------------------------------------------------------------------------
Interest coverage (times)
Net earnings (1) 9.7x
Cash flow from operations (2) 18.3x
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) Net earnings plus income taxes and interest expense excluding current
and deferred PRT expense and other taxes; divided by the sum of interest
expense and capitalized interest.
(2) Cash flow from operations plus current income taxes and interest expense
excluding current PRT expense and other taxes; divided by the sum of
interest expense and capitalized interest.
CONFERENCE CALL
A conference call will be held at 9:00 a.m. Mountain Daylight Time, 11:00 a.m.
Eastern Daylight Time on Thursday, August 9, 2012. The North American conference
call number is 1-800-952-6845 and the outside North American conference call
number is 001-416-695-7848. Please call in about 10 minutes before the starting
time in order to be patched into the call. The conference call will also be
broadcast live on the internet and may be accessed through the Canadian Natural
website at www.cnrl.com.
A taped rebroadcast will be available until 6:00 p.m. Mountain Time, Thursday,
August 16, 2012. To access the rebroadcast in North America, dial
1-800-408-3053. Those outside of North America, dial 001-905-694-9451. The pass
code to use is 3662875.
WEBCAST
This call is being webcast and can be accessed on Canadian Natural's website at
www.cnrl.com.
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