ANNUAL REPORT 2011 - Connacher Oil and Gas

ANNUAL REPORT 2011
WELL
POSITIONED
RESERVES
504 million barrels of proven
plus probable reserves
REFINERY
Throughput averaged 9,890
barrels per day in 2011

CORPORATE PROFILE
Connacher Oil and Gas Limited is in an enviable operating position in the
midst of one of the world’s largest accumulations of crude oil or bitumen
located in the north eastern Athabasca region of Alberta. Since 2004,
Connacher has established itself as a significant independent player in the
Canadian oil sands industry with an enterprise value in excess of $1.3 billion
and an underlying pre-tax and after-tax net asset value which is significantly
higher. While we are one of the smaller companies engaged in the business,
our reviews say we are nimble, innovative and committed to the efficient
modular expansion of our productive capacity.
We also have conventional crude oil and natural gas properties and a
profitable 9,500 bbl/d heavy crude oil refinery in Great Falls, Montana.
Our integrated approach is designed to mitigate risk and our proved and
probable reserve base of half a billion barrels should facilitate a long run of
success and value enhancement.
CONTENT
Connacher’s 2011 Annual
GENERAL Meeting
June 28, 2012
3:00 PM (MDT)
Calgary Petroleum Club – Devonian Room
319 – 5 Avenue SW, Calgary, Alberta
5
LETTER TO
SHAREHOLDERS
Connacher is committed to maximizing
shareholder value in 2012.
9
OPERATIONS REVIEW
Connacher’s first steam assisted gravity
drainage project has been producing
bitumen since late 2007.

AR 2011
PG 1
02 HIGHLIGHTS
05 LETTER TO SHAREHOLDERS
09 REVIEW OF OPERATIONS
12 RESERVES
12
RESERVES
Connacher’s estimated proved and
probable oil and natural gas reserves
total approximately 504 million barrels
of oil equivalent.
16
HEALTH, SAFETY AND
THE ENVIRONMENT
Connacher is committed to developing
its resources responsibly.
16 HEALTH, SAFETY AND THE
ENVIRONMENT
18 MANAGEMENT AND
BOARD OF DIRECTORS
19 MANAGEMENT’S
DISCUSSION AND ANALYSIS
44 CONSOLIDATED FINANCIAL
STATEMENTS
IBC CORPORATE INFORMATION

AR 2011
PG 2
HIGHLIGHTS
Connacher’s overall objective is to create shareholder value.
In 2011, we accomplished our goals of monetizing non-core,
mature and non-cash generating assets; reducing balance
sheet risk by extending the maturity, and reducing the interest
coupon on our long-term debt; reducing our exposure to foreign
exchange risk through a reduction of U.S. denominated debt;
and increasing year over year production at Great Divide.
PRODUCTION (boepd)
15000
14,493
ADJUSTED EBITDA (1) ($ IN MILLIONS)
150
REFINERY THROUGHPUT (bbl/d)
10000
12000
10,699
120
8000
9000
9,216
90
6000
6000
60
4000
3000
30
2000
0
2009
2010
2011
0
2009
2010
2011
0
2009
2010
2011
• CRUDE OIL bbl/d
• NATURAL GAS boe/d
• BITUMEN bbl/d
(1) A non-GAAP measure which is defined in the Advisory section of this annual report.
“Connacher is focused on
delivering successive and sustained
improvement in operating and
financial results and liquidity. ”

AR 2011
PG 3
Years ended December 31
FINANCIAL ($000 except per share amounts) 2011 2010 % Change
Revenue, net of royalties $872,806 $589,931 48
Adjusted EBITDA (2) 129,871 92,206 41
Net earnings (loss) (114,105) (44,669) 155
Per share, basic and diluted (0.25) (0.10) 150
Capital expenditures 163,428 259,165 (37)
Cash on hand 117,045 19,532 499
Working capital 16,876 138,644 (87)
Long-term debt 856,068 847,387 1
Shareholders’ equity 421,076 523,187 (20)
Total assets $1,605,626 $1,569,137 (2)
OPERATIONAL
Daily production volumes (4)
Bitumen (bbl/d) 13,379 8,299 61
Crude oil (bbl/d) 427 883 (52)
Natural gas (Mcf/d) 4,124 9,100 (55)
Barrels of oil equivalent (boe/d) (5) 14,493 10,699 35
Upstream pricing (6)
Bitumen ($/bbl) $47.59 $45.65 4
Crude oil ($/bbl) $82.44 $65.63 26
Natural gas ($/Mcf) $3.70 $3.90 (5)
Barrels of oil equivalent ($/boe) (5) $47.41 $44.13 7
Downstream
Throughput – Crude charged (bbl/d) 9,890 9,693 2
Refinery utilization (%) 104 102 2
Margins (%) 10 9 11
RESERVES INFORMATION
Reserves and resources (mboe) (7)
Proved (1P) reserves 176,995 186,668 (5)
Proved plus probable (2P) reserves 503,753 509,434 (1)
Proved plus probable plus possible (3P) reserves (9) 609,601 613,485 (1)
Best estimate contingent resources 174,692 220,572 (21)
Reserves and resources values ($million) (8)
1P reserves $1,145 $1,497 (24)
2P reserves $2,462 $3,101 (21)
3P reserves (9) $3,183 $3,849 (17)
Best estimate contingent resources $142 $571 (75)
COMMON SHARES
Shares outstanding end of period (000) 448,260 447,168 -
Weighted average shares outstanding for the period
Basic (000) 448,025 432,258 4
Diluted (000) 448,025 432,258 4
Volume traded (000) 628,718 585,135 7
Common share price ($)
High $1.66 $1.88 (12)
Low $0.24 $1.10 (78)
Close (end of period) $0.76 $1.33 (43)
(1) A non-GAAP measure which is defined in the Advisory section of the MD&A.
(2) No dividends have been declared by the company since its incorporation.
(3) Effective October 1, 2010, the capitalized costs relating to the company’s second oil sands project, Algar, were added to the full cost pool for depletion and ceiling test calculations and the revenues, expenses and finance charges associated with the project were
reported in the statement of operations. In this Annual Report, we use the word “commerciality” to describe these circumstances. Prior thereto, Algar was considered a major development project under construction and all costs, including related financing costs and
internal operating expenses net of revenue, were capitalized. Accordingly, the above table does not include production and sales volumes for Algar prior to October 1, 2010. Daily production and sales averages are based on total calendar years during the year
(4) Represents bitumen, crude oil and natural gas produced in the period. Actual sales volumes may be different due to inventory at the period end. Actual production volumes sold were 14,390 boe/d in 2011 (10,606 boe/d in 2010).
(5) All references to barrels of oil equivalent (boe) are calculated on the basis of 6 Mcf:1 bbl. This conversion is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Boes
may be misleading, particularly if used in isolation. Additionally, given the value ratio based on the current price of crude oil as compared to natural gas is significantly different from the energy equivalency of 6:1, utilizing a conversion ratio of 6:1 may be misleading as
an indication of value.
(6) Before royalties and risk management contract gains or losses and after applicable diluent and transportation costs divided by actual sales volumes.
(7) The reserve and resource estimates for 2011 and 2010 were prepared by GLJ Petroleum Consultants Ltd., an independent professional petroleum engineering firm, in accordance with Canadian Securities Administrators’ National Instrument 51-101 and the
Canadian Oil and Gas Evaluation Handbook. For the definitions of the terms used please refer to the “Production, Sales and Reserves” section of the annual report.
(8) PV10 of future net revenues associated with reserves and resources do not necessarily represent fair market value.
(9) As at December 31, 2011, possible reserves were 106 million bbls valued at PV10 of $721 million (2010 – 104 million bbls valued at PV10 of $748 million).

AR 2011
PG 4
“Connacher
remains bullish
about the
long-term price
of bitumen.”

AR 2011
PG 5
Volatility in the oil and gas industry and new technologies
and transportation initiatives made for an interesting year at
Connacher. The first half of 2011 saw the continued ramp-up
of Algar (which commenced production in August 2010) and a
focus on increasing reliability at both Pod One and Algar.
LETTER TO SHAREHOLDERS
Dislocated pricing in the bitumen market
due to pipeline outages and apportionment
across North America resulted in Connacher
pioneering the sale of diluted bitumen
(dilbit) by rail to the Gulf and West coasts.
Operational reliability continued to improve
during the year as evidenced by reduced
chemical usage, improved water treating
and recycling rates, upgraded electrical
services, improved downhole pump run life
and optimized evaporator performance.
Work continued during the year on the
Great Divide expansion project, for which
Connacher expects to obtain regulatory
approval in the first half of 2012. The
SAGD+ trial (where solvent is mixed with
steam and injected into the reservoir) started
in July and demonstrated very encouraging
results as a way to improve well productivity
and reduce steam:oil ratios (“SORs”).
debt. Asset sales continued throughout
the year and added to cash balances. Joint
venture processes were initiated in the oil
sands and light oil resource plays but were
subsequently suspended.
The refinery in Great Falls, Montana had
strong results in 2011 as prices for refined
products in its market area remained healthy
throughout the year.
In May 2011, the Company refinanced
its long-term debt at lower coupon rates,
extended maturities to 2018 and 2019
and reduced its exposure to U.S. dollar
denominated debt by replacing a portion of
its debt with Canadian dollar denominated

AR 2011
PG 6
As at December 31, 2011, Connacher’s
estimated proved and probable (“2P”)
bitumen and conventional crude oil, natural
gas and natural gas liquids reserves, as
evaluated by GLJ Petroleum Consultants
Ltd. (“GLJ”), independent qualified reserves
evaluators, totaled approximately 504 million
barrels of oil equivalent (“boe”). Despite a
very modest capital program during 2011,
bitumen reserve volumes held virtually
constant in all reserve categories, with the
exception of proved producing bitumen,
of which approximately 4.9 million barrels
were produced during the year. The 10
percent pre-tax present value of 2P reserves
decreased to $2.5 billion, due primarily to
increased estimated future capital costs,
adjusted near-term production forecasts and
capital plans. Contingent and prospective
bitumen resources also declined, mainly as a
result of the sale of the Company’s Halfway
Creek property.
In 2011, the Company embarked on a
program to rationalize its non-core asset
base. In February 2011, the mature Battrum,
Saskatchewan crude oil producing property
was sold for $56.2 million and in April 2011
the Marten Creek/Randall natural gas
property in north central Alberta was sold for
$22.1 million. Additionally, Connacher sold
its undivided 50 percent working interest
in lands at Halfway Creek, Alberta, situated
south of Fort McMurray, for $26.5 million, as
well as undeveloped land for $12.5 million,
primarily situated at Latornell in the Deep
Basin of northwestern Alberta. Total proceeds
from these divestitures was $117.3 million
which was added to working capital.
Connacher’s 9,500 bbl/d heavy oil
refinery in Great Falls, Montana had a very
successful 2011, operating at 104 percent
of capacity, up from 102 percent of capacity
in 2010. Strong refinery margins were
primarily due to the improved stability of
refining operations, more favorable weather
conditions for road paving activities that
buoyed higher relative asphalt sales and
increased demand for refined petroleum
products such as gasoline, diesel and jet
fuel in 2011.
The refinery is strategically aligned with the
Company’s oil sands business. It primarily
processes Canadian heavy sour crude
oil into a range of higher value refined
petroleum products, thereby capturing more
of the value chain in a produced barrel
of oil. Accordingly, the refinery provides a
physical hedge for Connacher’s bitumen
revenue by recovering a portion of the heavy
oil differential in its netbacks under normal
operating conditions. Over the past several
years closely aligned marketing initiatives
between upstream and downstream
operations served the Company well in
dealing with the challenging North American
energy market environment.
Notwithstanding higher adjusted EBITDA,
the Company incurred a net loss of
$114.1 million or $0.25 per share in 2011
compared to a net loss of $44.7 million or
$0.10 per share in 2010. This was primarily
due to lower unrealized foreign exchange
gains, mainly in respect of U.S. dollar
denominated debt, and higher depletion and
finance charges, partially offset by gains on
the sale of assets and on risk management
contracts. Please refer to the Management’s
Discussion and Analysis for the year ended
December 31, 2011 (“MD&A”) for a more
detailed discussion in this regard.
At December 31, 2011, cash balances were
$117.0 million, working capital was $16.9
million and long-term debt totaled $856.0
million. Convertible debentures with face
value of approximately $100 million are due
for repayment in June of 2012, accounting
for the difference between cash and working
capital as the debentures are classified
as current debt on the balance sheet.
Connacher has available bank credit lines
of $100 million net of outstanding letters of
credit totaling $2.2 million which had been
issued by the Company at year end 2011.

AR 2011
PG 7
“Thanks to our liquidity, balanced
operations, production potential
and demonstrated execution,
we’re optimistic about the future.”
Total capital expenditures during the year
were $163.4 million which was financed
from operating cash flow and cash balances.
Details of the overall capital program are
contained in the MD&A.
Externally there is great uncertainty
in the capital and debt markets which
creates volatility in oil prices and oil price
differentials. Connacher remains bullish
about the long term price of bitumen, but
the Company also recognizes that during
the second quarter there will be continued
pressure on differentials and therefore
wellhead pricing. The price of natural gas is
a key component in Connacher’s oil sands
operations (natural gas is the biggest cost
component in the generation of steam) and
is expected to remain low for the remainder
of the year. Locally, the Alberta corridor
continues to be a “bubble” with regard to
costs of services, fabrication of equipment
and access to human resources. Importantly,
the hiatus in Connacher’s capital spending
provided time to determine more cost
effective if not local solutions. The everincreasing
focus on oil sands by the media,
stakeholders and governments has resulted
in expanded - not streamlined - approval
processes. Effective leadership on both
sides of the border will be necessary to drive
efficient and economic outcomes.
Connacher is focused on delivering
successive and sustained improvement in
operating and financial results and liquidity.
Based on currently available information
and prevailing commodity prices, the
Company anticipates 2012 results that
reflect solid operational performance in
spite of current capital constraints.
The Company’s 2012 capital budget has
been set at $50.0 million as outlined in the
Company’s MD&A, including the previously
announced maintenance capital budget of
$37.0 million. The Company is proceeding
with preparatory work on several sustaining
and growth projects, including the recently
completed five-well core hole program
designed to provide further technical data
for the Great Divide expansion project
and Pad 104 drilling program at Pod One.
Additional work is ongoing to finalize the
design basis memorandum for the Great
Divide expansion project, complete the
preparation of a commercial front end
engineering design study for the Company’s
SAGD+ project and the expansion and
upgrading of rail and other facilities at the
Montana refinery.
As previously announced, the Company’s
Board of Directors has initiated a process
to review Connacher’s business plan and to
identify, examine and consider all strategies
available to the Company, both near and
long term, in order to prudently determine
the optimal course of action for the
Company. Goldman Sachs and RBC Capital
Markets have been engaged to assist the
Board of Directors in connection with this
strategic review. In addition, the current
directors of the Company are pleased to
welcome Mr. Greg Boland and Mr. Garry
Mihaichuk to the Board.
The Company has a number of capital
projects with very good economics that
are expected to increase production
and/or improve netbacks. These projects
will continue to be evaluated during this
period and will be undertaken as free cash
flow is available.
Thanks to Connacher’s liquidity, balanced
operations, significant production potential
and demonstrated execution, we’re
optimistic about the future.
Colin M. Evans and Kelly J. Ogle
Co-Managing Directors
March 15, 2012

AR 2011
PG 8
AB
FORT MCMURRAY
SK
Great Divide
Pod One/Algar
EDMONTON
Central Alberta Conventional
CANADA
CALGARY
U.S.A.
Montana Refining Company
GREAT FALLS
MT
CANADA
U.S.A.
Oil Sands Assets
Conventional Assets
Refinery

AR 2011
PG 9
Review of Operations
In 2011, Connacher demonstrated:
• Average bitumen production of 13,379 bbl/day and average total
production of 14,493 boe/day
• Increased reliability in oil sands operations with plant steam
throughput achieving design conditions
• Most profitable refinery operations since the company acquired
Montana Refining Company, Inc (“MRC)” in 2006
• A technical leap forward with SAGD+ technology that will benefit
Algar and the industry
• Continued progress on the Great Divide expansion project design,
engineering and stewardship through the application process
• A successful property rationalization process with sale of Battrum,
Marten Creek, Halfway Creek, Latornell and minor undeveloped land
• Innovative marketing and transportation solutions to pipeline
restrictions and pricing volatility
At the same time Connacher had to deal with:
• Declining production and increasing SORs at Pod One as the wells
have been producing since 2007
• Minor reservoir issues at Algar
• Poor initial production results from the conventional resource play
• Capital restraints for the latter half of the year
All bITUMEN producers had to deal with:
• Volatile pricing for bitumen and diluent
• Infrastructure problems, particularly pipeline outages that affected
access to market
• Rapidly rising costs for equipment and services
• Increased competition for key competencies
Connacher’s first steam assisted gravity
drainage (“SAGD”) project at Great Divide,
Pod One, has been producing bitumen
since late 2007, with commercial production
commencing March 1, 2008. Connacher’s
second SAGD project Algar, commenced
producing bitumen in August 2010 and
commerciality was achieved October 1,
2010. Production from both projects since
start-up through December 31, 2011 has
totaled approximately 12.6 million barrels of
bitumen, of which 4.9 million barrels were
produced in 2011.
Steam throughput reached design
conditions at both plants in 2011. Natural
gas prices were essentially flat year-overyear
which helped operating costs in the oil
sands operations. Although the company
met revised production guidance in 2011,
lower bitumen production and cash flow
necessitated constraining capital spending
in the oil sands in the second half of the
year. Projects requiring regulatory approval
received approval but the capital for those
projects was deferred.
An application was submitted in May
of 2010 that proposes a 24,000 bbl/d
expansion of the existing Algar facility – a
“brownfield” expansion. While guiding the
application through the regulatory process,
engineering and design work continued
throughout the year on the Great Divide
expansion project.
Connacher’s SAGD+ trial commenced
in July 2011 at Algar and the company
is encouraged by initial results. The
SAGD+ trial has the potential to improve
productivity and reduce SORs by injecting
steam mixed with solvent into the reservoir.
Two wells were selected to test whether
varying solvent volumes added to the
steam injection would result in production
increases, reduced SORs and the
economics recovery of injected solvent at
surface treating facilities.
The objectives, specifically, were to:
• test the incremental bitumen
production increase
• monitor the timing for solvent recovery
• measure how much solvent was retained
in the reservoir rather than being produced
to surface
• evaluate the optimal solvent concentration
in the steam

AR 2011
PG 10
Pilot results from July to year end 2011
exceeded expectations. Average production
increases for the two wells was 29 percent
with an average decrease in SORs of 17
percent. Moreover, solvent recovery in the
field during steady-state solvent injection
was greater than 85 percent. Pilot testing
on additional wells will be required in 2012
to confirm repeatable results at which point
full implementation of SAGD+ at Algar will
be considered. Capital will be required for
facility modifications in order to capture and
recycle the recovered solvent. SAGD+ may
be a very straightforward and rapid method
of increasing bitumen production and
optimizing steam allocation.
Quigley
Great Divide
Pod One
Thornbury
Algar
The refinery in Great Falls, Montana had
strong results in 2011. Refinery throughput
averaged 9,890 bbl/d. While prices for
refined products in MRC’s market area
remained healthy throughout the year. The
margins or “crack spread” for key products
produced by MRC (gasoline, diesel, jet fuel
and asphalt) also remained strong during
the year. Inventory management of asphalt
was a focus in 2011 and, with good weather
throughout most of the paving season,
asphalt sales were maximized. MRC actively
sells asphalt into the Canadian market as
well as its local market in Montana. Excess
naphtha is sold to Connacher’s bitumen
operations for use as diluent. The refinery
provides a physical hedge for the oil sands
operations as it purchases Canadian heavy
sour crude for processing into higher value
products. When differentials (the difference
between light oil and heavy oil prices)
widen, the result is lower wellhead prices for
bitumen. Fortunately, the refinery benefits
as its crude feedstock becomes cheaper,
providing better margins.
63 Bitumen accumulation
In 2011, bitumen market access in North
America and farther afield became a major
challenge producers, pipeline companies,
governments and other stakeholders
including environmental groups. Ruptures,
spills and outages in North American
pipeline infrastructure throughout the year
caused disruptions in the Alberta oil market,
restricting access to market for producers.
Public protests regarding new pipeline

AR 2011
PG 11
proposals helped to politicize and delay
approvals for needed takeaway capacity.
As a result, crude oil from Canada and many
new rapidly expanding American oilfields
faced a discount in market price relative to
the benchmark West Texas Intermediate
(“WTI”) oil price. WTI was, in turn, discounted
relative to world oil prices, more specifically
by the benchmark Brent oil price. As a risk
mitigant to these issues, starting in early
2011, Connacher began moving dilbit by
rail to markets that wanted to purchase and
process bitumen but weren’t able to access
Canadian heavy crude by pipeline. These
markets are located both on the West coast
and the Gulf coast. Prices received were
as good as or better than local Canadian
markets-net of transportation changes.
As a result of these successful efforts
to pioneer “dilbit by rail” Connacher has
committed to expanding its leased rail car
fleet and continues to explore new market
opportunities. Using rail cars to transport
crude oil is a strategy that many companies,
particularly producers in North Dakota, are
also pursuing.
Asset sales continued throughout the year
and added to cash balances. Battrum,
Marten Creek, Halfway Creek, Latornell
and minor undeveloped land were sold.
Connacher’s strategy was to dispose
of properties with limited upside but
significant new capital or maintenance
Connacher pioneered
“dilbit by rail” to the Gulf
Coast and West Coast
capital expenditures, allowing the company
to focus on projects with better potential.
In addition, after significant review during
2010, a decision to sell natural gas
properties was also advanced. Given the
short to medium term direction for natural
gas pricing (subsequently born out), it was
decided that producing natural gas as a
physical hedge for natural gas consumption
in the production of steam in the oil
sands was not necessary at present. As
a result several gas properties were sold
including the Marten Creek property. Overall
conventional production declined over 50
percent, primarily as a result of the asset
rationalization program. Two new light oil
resource plays in central Alberta were
tested in 2011. Although initial results were
disappointing and production did not meet
economic hurdles, there is significant oil in
place at Twining and Penhold. Technical and
geological review would suggest that the
completion and frac techniques employed
for these wells can be improved upon and
optimized. However, the company is not
prepared to invest more capital in these
plays at this time.
Joint venture processes to obtain a partner
commenced in the oil sands and the light
oil resources plays but neither process was
satisfactorily resolved by year end.
T 83
T 82
T 81
RG13 RG12 RG11W4
“Connacher has
identified multiple
SAGD horizontal
well pair locations
as part of the
Great Divide
expansion project.”
EIA Well Pairs Existing Well Pairs Net SAGD Pay

AR 2011
PG 12
RESERVES
Connacher’s estimated proved and probable
bitumen and conventional crude oil and
natural gas reserves total approximately
504 million barrels of oil equivalent. This
estimate is based on a report by GLJ,
independent qualified reserves evaluators,
as of December 31, 2011. Despite a
modest capital program during 2011,
bitumen reserve volumes held virtually
constant in all reserve categories compared
with 2010, with the exception of proved
producing bitumen, of which approximately
4.9 million barrels were produced during
the year. The 10 percent pre-tax present
value (“10% PV”) of 2P reserves decreased
to $2.5 billion, due primarily to increased
estimated future capital costs. Contingent
Connacher has 500
million barrels of 2P
bitumen reserves
and prospective bitumen resources also
declined, mainly as a result of the sale of
the Company’s 50% interest in the Halfway
Creek oil sands property.
Detailed information included in the GLJ
December 31, 2011 report (“Year-End 2011
Report”) regarding Connacher’s reserves
and resources and associated present
values is provided in the following tables,
including a comparison of year-end 2011
results to year-end 2010 results.
The Year-End 2011 Report was prepared
using assumptions and methodology
guidelines outlined in the Canadian Oil
and Gas Evaluation Handbook (“COGE
Handbook”) and in accordance with
National Instrument 51-101 (“NI 51-101”).
Comparisons with respect to Connacher’s
conventional and bitumen reserves, bitumen
resources and for 10% PV for December
31, 2011 are to estimates contained in the
report, prepared by GLJ, with an effective
date of December 31, 2010 (“Year-End
2010 Report”).
Connacher owns a 100 percent working
interest in approximately 87,000 net acres
of oil sands leases, primarily located at its
Great Divide project in northeastern Alberta,
situated 80 kilometres southwest of Fort
McMurray. Numerous oil accumulations in
the McMurray formation have been identified
for continuing and future development on
Connacher’s properties.
Since March of 2008, Connacher production
from Great Divide has totaled approximately
12.6 million barrels of bitumen, of which 4.9
million barrels were produced in 2011. Such
amounts have been deducted from earlier
estimates of proved reserves prior to the
calculation of reserves as at December 31,
2011. Connacher’s conventional reserve
base declined, due primarily to the sale of
several mature conventional properties,
totaling approximately 8.2 million boe.
The GLJ Year-End 2011 Report was
prepared using the GLJ January 1, 2012
price forecast, effective December 31,
2011. Readers are referred to the notes to
the Summary Tables for details regarding the
price forecast used by GLJ. Earlier reports
were prepared using the price forecasts
then being applied by GLJ.
WORKING INTEREST RESERVES
(MMBBL) – BITUMEN
700
600
500
400
300
200
100
0
4,000
3,500
3,000
2,500
2,000
1,500
1,000
500
0
2007
2008
2009
2010
2011
• PROVED • PROBABLE • POSSIBLE
BEFORE TAX PV10
($MILLION) – BITUMEN
2007
2008
2009
2010
2011
• PROVED • PROBABLE • POSSIBLE

AR 2011
PG 13
reservoir description and modeling
Rapid Evolution of Connacher’s Oil Sands Understanding
2005 CURRENT
RG13 RG12 RG11W4
RG13 RG12 R
T 83
• 3-D Imaging
T 83
• Exploration Core Holes
• Data Integration and
Modeling
T 82
T 81
• Exploitable Resource
Characterization
T 82
T 81
Best Estimate Contingent Resources (2C) : 127 MMbbl
Highway 63
EIA Well Pairs Existing Well Pairs Net SAGD Pay
2P Reserves : 500 MMbbl
EIA Well Pairs
Existing Well Pairs
The recognized exploitable Great Divide bitumen resource in the McMurray formation has increased as a result of Connacher’s ongoing drilling,
reservoir characterization, seismic delineation and commercialization.
WORking Interest VOLumes
Connacher Oil and Gas Limited
Bitumen Reserves and Resources
31 - DEC - 10
(mbbl)
31 - DEC - 11
(mbbl)
Proved Reserves (1P) (1) 180,166 175,185 -3%
Proved and Probable Reserves (2P) (1)(2) 499,657 500,825 0%
Proved, Probable and Possible Reserves (3P) (1)(2)(3) 603,709 605,687 0%
Low Estimate Contingent Resources (4)(6) 223,443 173,487 -22%
Best Estimate Contingent Resources (4)(7) 220,572 174,692 -21%
High Estimate Contingent Resources (4)(8) 408,908 243,239 -41%
Best Estimate Prospective Resources (5)(7) 80,240 53,589 -33%
High Estimate Prospective Resources (5)(8) 287,337 148,349 -48%
12 MO
% ∆

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PG 14
Connacher Oil and Gas Limited
Conventional Canadian Reserves
LIGHT/MEDIUM OIL/NGL (mbbl)
NATURAL GAS (mmcf)
31/12/10 31/12/11 12 MO % ∆ 31/12/10 31/12/11 12 MO % ∆
Proved Reserves (1P) (1) 2,524 778 -69% 23,864 6,186 -76%
Probable Reserves (2) 972 556 -43% 13,818 3,371 -77%
Proved + Probable Reserves (2P) (1) (2) 3,496 1,336 -62% 37,682 9,557 -77%
Connacher Oil and Gas Limited
Combined Conventional and Bitumen Reserves (9)
31 - DEC - 10
(mboe)
31 - DEC - 11
(mboe)
Proved Conventional (1) 6,502 1,810 -72%
Proved Bitumen (1) 180,166 175,185 -3%
Total Proved (1P) (1) 186,668 176,995 -5%
Probable Conventional (2) 3,275 1,118 -66%
Probable Bitumen (2) 319,491 325,640 2%
Total Probable (2) 322,766 326,758 1%
Proved + Probable Conventional (1)(2) 9,777 2,928 -70%
Proved + Probable Bitumen (1)(2) 499,657 500,825 0%
Total Proved + Probable (2P) (1)(2) 509,434 503,753 -1%
Total 3P Reserves (1)(2)(3) 613,485 609,601 -1%
12 MO
% ∆
PRESENT VALUE (12)
Connacher Oil and Gas Limited 10% Present Value of
Future Net Revenue Based on Forecast Prices and Costs
Bitumen Reserves and Resources - Before Tax
31 - DEC - 10
($MM)
31 - DEC - 11
($MM)
12 MO
% ∆
Proved Reserves (1P) (1) 1,397 1,110 -21%
Proved and Probable Reserves (2P) (1)(2) 2,966 2,412 -19%
Proved, Probable and Possible Reserves (3P) (1)(2)(3) 3,714 3,127 -16%
Low Estimate Contingent Resources (4)(6) 780 618 -21%
Best Estimate Contingent Resources (4)(7) 571 142 -75%
High Estimate Contingent Resources (4)(8) 1,212 372 -69%
Best Estimate Prospective Resources (5)(7) 217 47 -78%
High Estimate Prospective Resources (5)(8) 696 196 -72%

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Connacher Oil and Gas Limited 10% Present Value
31 - DEC - 10
of Future Net Revenue Based on Forecast Prices
($MM)
and Costs Combined Conventional and Bitumen
Reserves - Before Tax (9)
31 - DEC - 11
($MM)
12 MO
% ∆
Proved Conventional (1) 100 35 -65%
Proved Bitumen (1) 1,397 1,110 -21%
Total Proved (1P) (1) 1,497 1,145 -23%
Probable Conventional (2) 36 15 -59%
Probable Bitumen (2) 1,569 1,302 -17%
Total Probable (2) 1,605 1,317 -18%
Proved + Probable Conventional (1)(2) 135 50 -63%
Proved + Probable Bitumen (1)(2) 2,966 2,412 -19%
Total Proved + Probable (2P) (1)(2) 3,101 2,462 -21%
Total 3P Reserves (1)(2)(3) 3,849 3,183 -17%
Notes:
1) Proved Reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves.
2) Probable Reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the
estimated proved plus probable reserves.
3) Possible Reserves are those additional reserves that are less certain to be recovered than probable reserves. It is unlikely that the actual remaining quantities recovered will exceed the sum of the estimated proved plus
probable plus possible reserves. There is a 10% probability that the quantities actually recovered will equal or exceed the sum of proved plus probable plus possible reserves.
4) Contingent resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which
are not currently considered to be commercially recoverable due to one or more contingencies. These resource estimates are not currently classified as reserves, pending further reservoir delineation, project application,
facility and reservoir design work, preparation of firm development plans and Company approvals. Contingent resources entail additional commercial risk than reserves and adjustments for commercial risks have not been
incorporated in the summaries set forth herein. There is no certainty that it will be commercially viable to produce any portion of the contingent resources.
5) Prospective Resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from undiscovered accumulations by application of future development projects. Prospective
Resources have both an associated chance of discovery and a chance of development. The Prospective Resources estimates reflected herein have been risked for the chance of discovery but have not been risked for
the chance of development and hence are considered partially risked estimates. Prospective Resources entail additional commercial risk than reserves and adjustments for commercial risks have not been incorporated
in the summaries set forth herein. There is no certainty that any portion of the prospective resources will be discovered. If discovered, there is no certainty that it will be commercially viable to produce any portion of the
resources. Moreover, if a discovery is made, there is no certainty that it will be developed. If it is developed, there is no certainty as to the timing of such development.
6) Low Estimate: this is considered to be a conservative estimate of the quantity that will actually be recovered. It is likely that the actual remaining quantities recovered will exceed the low estimate. If probabilistic methods
are used, there should be at least a 90 percent probability that the quantities actually recovered will equal or exceed the low estimate.
7) Best Estimate: this is considered to be the best estimate of the quantity that will actually be recovered. It is equally likely that the actual remaining quantities recovered will exceed the best estimate. If probabilistic
methods are used, there should be at least a 50 percent probability that the quantities actually recovered will equal or exceed the best estimate.
8) High Estimate: this is considered to be an optimistic estimate of the quantity that will actually be recovered. It is unlikely that the actual remaining quantities recovered will exceed the high estimate. If probabilistic methods
are used, there should be at least a 10 percent probability that the quantities actually recovered will equal or exceed the high estimate.
9) Does not include bitumen resources or undeveloped land value.
10) Pricing assumptions in the Year-End 2010 Report and Year-End 2011 Report were as follows:
BITUMEN
(wellhead) ($/bbl)
WTI
(US$/bbl)
NATURAL GAS
(AECO) ($/mmbtu)
Year-End 2010 Year-End 2011 Year-End 2010 Year-End 2011 Year-End 2010 Year-End 2011
2012 54.41 57.69 89.00 97.00 4.74 3.49
2013 55.39 60.24 90.00 100.00 5.31 4.13
2014 58.50 64.39 92.00 100.00 5.77 4.59
2015 60.88 66.00 95.17 100.00 6.22 5.05
2016 62.57 66.00 97.55 100.00 6.53 5.51
2017 64.51 65.90 100.26 100.00 6.76 5.97
2018 66.27 66.82 102.74 101.35 6.90 6.21
2019 68.21 68.27 105.45 103.38 7.06 6.33
2020 69.69 69.74 107.56 105.45 7.21 6.46
Thereafter +2%/yr +2%/yr +2%/yr +2%/yr +2%/yr +2%/yr
US$/CDN$ exchange rates were 0.98 in the Year End 2010 Report and 0.98 in the Year End 2011 Report.
11) Tables may not add due to rounding.
12) Estimated values disclosed do not represent fair market value.

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Health, Safety, and The Environment
Connacher is committed to developing
its resources responsibly, and minimizing
its impact on the air, land and water. The
Company does this by adhering to strict
operational guidelines and investing in
research and technology. Moreover, in
order to grow the business responsibly
the Company consults with stakeholders
prior to development, maximizes local
benefits and opportunities and ensures
environmental protection before, during and
after operations. Additionally, Connacher
operates in a variety of ecosystems – some
with sensitive characteristics. The Company
strives to conserve biodiversity, including
studying the impacts on wildlife and
following strict guidelines when working in
environmentally sensitive areas.
KEEPING a Minimal
fOOTPRINT
Connacher’s SAGD production operations
allow it to access large subsurface bitumen
deposits from only a few strategically-placed
well pads. Due in large part to the use
of state-of-the-art directional drilling and
bitumen recovery processes, the natural
landscape directly above a bitumen deposit
requires little-to-no permanent disturbance
in order to extract the resource. Those
land areas that are disturbed are done
so while adhering to the philosophy of
minimal disturbance and timely reclamation.
Connacher’s facilities are compact in size
and efficient in design, thereby minimizing
the amount of land disturbance necessary to
accommodate them.
USING and Reusing Water
Responsibly
In accordance with applicable regulations,
Connacher is required to recycle at least
90% of the water used for its bitumen
extraction process, with the balance being
comprised of make-up water. Connacher’s
in-situ production process uses non-potable
make-up water, which is derived from a deep,
subsurface aquifer and is unsuitable for
drinking or irrigation. Connacher’s production
process draws no water from any rivers,
lakes, or streams, nor is any used water ever
discharged into these types of water bodies.
Through the use of new technologies and
efficient operating practices, Connacher
continues its success in further reducing the
amount of water used to extract bitumen.
In fact, since it began operating in 2008,
Connacher’s Pod One facility has seen
a 33% decrease in its make-up water
consumption. Building on that success,
Connacher’s Algar facility was designed
to operate at an even higher level of
efficiently, often reaching a 98% water
recycle rate. Algar has also shown a
significant reduction in its make-up water
consumption since startup.
Emissions Reduction
Through Technology
Air emissions are a reality of bitumen, crude
oil, and natural gas energy production, as
they are with most other viable forms of
energy generation. The resource industry
has a role to play by embracing new
technologies and implementing bestpractices
that hold promise in achieving
meaningful reductions in emissions.
Connacher too has a role to play. Through
its 13.1 megawatt natural gas-powered cogeneration
facility, the installation of highlyefficient
electric submersible pumps, and
its solvent co-injection process, Connacher
continues to press forward with initiatives
that result in a more efficient bitumen
extraction process. The more efficient the
process becomes, the less energy is required
in order to extract the bitumen – and that
results in lower emissions.
MAKE-UP WATER INTENSITY
08
09
10
11
0.19
0.0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8
• ALGAR • POD 1
0.36
0.43
0.49
SUPPORTING and
MONITORING Wildlife
0.63
Connacher believes that the development
of bitumen resources should not occur
at the expense of the wildlife populations
that inhabit its operating area. Connacher
continues to rely on its Wildlife Monitoring
Program as a critical means by which to
assess wildlife population, movement, activity
and condition within its project area. Through
the use of tools such as motion-activated
wildlife cameras, winter track surveys,
wildlife sighting cards and vehicular traffic
monitors, a constant stream of valuable data
is collected from within Connacher’s project
area. The data undergoes a comprehensive
evaluation by professional wildlife biologists
and is then correlated to Connacher’s
production and exploration activities
within the project area in order to better
understand wildlife responses to them. Key
findings are then used to influence future
operating and development strategies.
In 2011, Connacher completed the
construction of several wildlife crossing
structures with the sole purpose to facilitate
0.80

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PG 17
the movement of wildlife over its aboveground
pipelines. Several unique surface
reclamation techniques were used in an
effort to create crossings that were to
appear to be as natural as the adjacent
undisturbed forest. Wildlife monitoring
equipment was also installed at each
DISTRIBUTION OF WILDLIFE SPECIES
PHOTOGRAPHED SINCE 2008
• UNGULATES (moose, deer, caribou) / 47%
• WOODLAND CARIBOU / 12%
• LARGE PREDATOR (wolves, bear) / 15%
• BIRDS / 14%
• OTHER MAMMALS (squirrel, hare, beaver, mouse) / 13%
• SMALL PREDATORS (fox, lynx, marten, fisher) / 10%
• UNIDENTIFIABLE MAMMALS / 1%
crossing so that wildlife activity adjacent
to these structures can be extensively
monitored over the next several years.
Observations made at these crossings will
provide for further refinement of the concept
and the integration into Connacher’s future
expansion plans.
COMMITTED TO BUILDING
LONG-TERM RELATIONSHIPS
Connacher is committed to working with
its stakeholders to develop and maintain
long-term beneficial relationships.
These stakeholders include a variety
of individuals and businesses, such as
investors, employees, community members,
government and Aboriginal people that
are impacted by Connacher’s operational
development in Alberta. Connacher
continues to work closely with all
stakeholders to ensure they are informed
of our operations, any future development
plans and our progress.
In 2011, Connacher completed over 200
engagements with Aboriginal stakeholders.
Connacher’s Environment Impact
Assessment (EIA) received no statements
of concern from the local Aboriginal
communities in regards to a proposed
expansion at Great Divide. In addition to
these engagements, Connacher employees
were trained in Aboriginal Awareness to
recognize the impact our operations have
on the surrounding communities and people.
This awareness helps to better equip our
employees with knowledge to maintain
these favorable relationships.
In addition to Connacher’s Aboriginal
stakeholder initiatives, the company
conducted numerous tours of its SAGD
plants in 2011. Participants ranged from
politicians to business owners, regulatory
boards and various media from within North
America. Conducting these tours allows
Connacher to engage its stakeholders
and reinforce its commitment to building
relationships with those interested and
impacted by our projects.
CORPORATE GOVERNANCE
Connacher is committed to a high standard
of corporate governance practices. We
believe good corporate governance is in the
best interest of our shareholders, and that it
also promotes effective decision making at
all levels of the Company’s activities.
The principal role of the Board of Directors
is stewardship of the Company. The Board
oversees the conduct of business and dayto-day
management of the affairs of the
Company which is delegated to the officers
of the Company. To facilitate the Board of
Directors in the discharge of its duties, the
Board has established five committees,
being the Audit Committee, Governance
Committee, Health, Safety and Environment
Committee, Human Resources Committee
and Reserves Committees. All committees
are comprised of at least a majority of
independent directors.
In its pursuit of effective governance,
Connacher is mindful of prevailing
recommendations with respect to best
practices as advanced by Canadian
regulatory authorities, non-regulatory
organizations and other standards which are
advanced from time to time by institutional
and other investors. We comply with
the objectives and guidelines relating to
corporate governance adopted by the
Canadian Securities Administrators and the
Toronto Stock Exchange. A full examination
of our corporate governance policies will be
provided in our Management Proxy Circular,
which will be filed on SEDAR (www.sedar.
com) and mailed to all shareholders in
connection with our 2012 annual meeting
of shareholders.

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MANAGEMENT
Colin M. Evans
Interim co-Managing Director
Brenda G. Hughes
Chief Financial Officer
Kelly J. Ogle
Interim co-Managing Director
Merle D. Johnson
Vice President, Oil Sands
BOARD OF DIRECTORS
D. Hugh Bessell
Jennifer K. Kennedy
Gregory A. Boland
Garry P. Mihaichuk
Peter D. Sametz
Interim Chief Executive Officer
Stephen A. Marston
Vice President,
Exploration, Land, A & D
Colin M. Evans
Kelly J. Ogle
Jesse J. Beaudry
Vice President, Sustainability
W.C. (Mike) Seth
FORWARD-LOOKING INFORMATION
This report contains forward-looking information including
but not limited to, anticipated future operating and
financial results, anticipated capital expenditures for 2012,
anticipated impact of Connacher’s integrated approach on
risk mitigation, anticipated impact of the Company’s reserve
base on success and value enhancement, timing of receipt
of regulatory approval for the Great Divide expansion
project, the future price of bitumen and natural gas, wellhead
pricing and future differentials, future liquidity, new projects
which may be undertaken once cash flow becomes available
and the impact such projects may have on production and
netbacks, the potential impact that full implementation of
SAGD+ could have on bitumen production and allocation of
steam to wells, the future expansion of leased rail cars and
new market opportunities.
Statements relating to “reserves” and “resources” are
deemed to be forward-looking statements, as they involved
the implied assessment, based on certain estimates and
assumptions, that the reserves and resources described exist
in the quantities predicted or estimated, and can be profitably
produced in the future. Additional information relating to the
Company’s reserves and resources, including the risks and
uncertainties and assumptions related thereto, are described
in further detail in Connacher’s Annual Information Form
for the year ended December 31, 2011 (the “AIF) which is
available at www.sedar. com.
Forward-looking information is based on management’s
expectations regarding future growth, results of operations,
production, future commodity prices and foreign exchange
rates, future capital and other expenditures (including the
amount, nature and sources of funding thereof), plans for
and results of drilling activity, environmental matters, business
prospects and opportunities and future economic conditions.
Forward-looking information involves significant known and
unknown risks and uncertainties, which could cause actual
results to differ materially from those anticipated. These
risks include, but are not limited to operational risks in
development, exploration, production and startup activities;
delays or changes in plans with respect to exploration or
development projects or capital expenditures; the uncertainty
of reserve and resource estimates; the uncertainty of
estimates and projections relating to production, costs
and expenses, and health, safety and environmental
risks; the risk of commodity price and foreign exchange
rate fluctuations; risks associated with the impact of
general economic conditions; sales volumes and risks and
uncertainties associated with securing and maintaining the
necessary regulatory approvals and financing to proceed
with the continued expansion of the Great Divide oil sands
project. Additional risks and uncertainties are described in
Connacher’s AIF.
Although Connacher believes that the expectations in such
forward-looking information are reasonable, there can be no
assurance that such expectations shall prove to be correct.
The forward-looking information included in this report is
expressly qualified in its entirety by this cautionary statement.
The forward-looking information included in this report is
made as of March 16, 2012 and Connacher assumes no
obligation to update or revise any forward-looking information
to reflect new events or circumstances, except as required
by law.
Per barrel of oil equivalent (boe) amounts have been
calculated using a conversion rate of six thousand cubic feet
of natural gas to one barrel of crude oil (6:1). The conversion
is based on an energy equivalency conversion method
primarily applicable to the burner tip and does not represent
a value equivalency at the wellhead. Boes may be misleading,
particularly if used in isolation. Additionally, given the value
ratio based on the current price of crude oil as compared
to natural gas is significantly different from the energy
equivalency of 6:1, utilizing a conversion ratio of 6:1 may be
misleading as an indication of value.

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PG 19
MANAGEMENT’S DISCUSSION AND ANALYSIS
This Management’s Discussion and Analysis (“MD&A”) for Connacher Oil and Gas Limited (“Connacher” or the “company” ” or “we” or “our”) is dated
March 15, 2012 and should be read in conjunction with Connacher’s consolidated financial statements for the years ended December 31, 2011
(“YTD 2011”) and December 31, 2010 (“YTD 2010”).
The consolidated financial statements and comparative information have been prepared in accordance with International Financial Reporting
Standard (“IFRS”) 1, “First-time Adoption of International Financial Reporting Standards” as issued by the International Accounting Standards
Board. In this MD&A, the term “previous GAAP” refers to Canadian generally accepted accounting principles prior to the adoption of IFRS.
Unless otherwise noted, 2010 comparative information has been prepared in accordance with IFRS, which now comprises Canadian GAAP.
The adoption of IFRS has not had any material impact on the company’s operations or strategic directions. The most significant area of impact
was the adoption of the IFRS upstream oil and gas accounting principles. Further information on the IFRS impacts is provided in the Accounting
Policies and Estimates Section of this MD&A.
Please read the Advisory section of the MD&A which provides information on Forward-Looking Statements, Non-GAAP measurements
and other information. Additional information relating to Connacher, including Connacher’s Annual Information Form (“AIF”), can be found
on SEDAR at www.sedar.com or on the company’s website at www.connacheroil.com.
2011 OVERVIEW
Connacher is a Calgary-based integrated energy company. We explore for, develop and produce bitumen, crude oil, natural gas and natural gas liquids
in Canada, our upstream business segment. We also own and operate a heavy oil refinery in Great Falls, Montana through our wholly owned subsidiary
Montana Refining Company, Inc. (‘‘MRCI’’), our downstream business segment. The refinery processes and refines crude oil into refined products
including gasoline, jet fuel, diesel fuel/distillates, asphalt and other ancillary products. Connacher’s shares trade on the TSX under the symbol CLL.
Our primary asset is our 100% ownership of bitumen reserves and production from two steam assisted gravity drainage (“SAGD”) plants, Pod
One and Algar, at our Great Divide oil sands lease block in northeastern Alberta. While SAGD bitumen production represents our greatest growth
opportunity, we benefit strategically from also owning conventional production and refining assets for reasons of risk mitigation, capital requirements
and regulatory process, among other factors.
Our heavy crude oil refinery provides a strategic advantage because it offers a partial hedge against heavy crude oil differential price risk, provides
diluent needed for our oil sands operations and affords a beneficial window on marketing opportunities in the United States of America (“USA”) for
our bitumen and dilbit (bitumen mixed with diluent).
The table below shows the distribution of our gross revenue from oil sands production, conventional production and refining for the most recent and
comparative reporting periods.
Gross revenue
and % of total gross revenue
Three months ended December 31 Year ended December 31
2011 2010 2011 2010
($000) % ($000) % ($000) % ($000) %
Oil sands (1)(2) $ 123,150 53 $ 99,456 54 $ 443,768 49 $ 247,187 40
Conventional (1) 4,330 2 8,010 4 18,494 2 34,171 6
Refining (1) 107,010 45 77,435 42 441,143 49 334,165 54
Total gross revenues (1)(2) $ 234,490 100 $ 184,901 100 $ 903,405 100 $ 615,523 100
(1) Before eliminating intercompany transactions and before royalties.
(2) Revenue from Algar included effective October 1, 2010.
The increase in oil sands gross revenue of 24 percent in Q4 2011 was primarily driven by higher realized bitumen prices. Oil sands revenue increased
significantly in YTD 2011 compared to YTD 2010 due to the start-up of production at Algar, our second oil sands SAGD project. Conventional gross
revenue decreased in the 2011 periods compared to the 2010 periods primarily due to lower production as a result of the sale of certain mature
producing properties. Refining revenues increased in 2011 periods due to higher refined products sales volumes and realized prices.
Connacher’s overall objective is to create shareholder value. In 2011, we accomplished our goals of monetizing non-core, mature and non-cash
generating assets; reducing balance sheet risk by extending the maturity profile of, and reducing interest coupon on our long term debt and reducing
our exposure to foreign exchange risk through a reduction of US denominated debt; and increasing year over year production at Great Divide.

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PG 20
2012 OUTLOOK
As previously announced, the company’s Board of Directors has initiated a process to review Connacher’s business plan and to identify, examine and
consider all strategies available to the company, both near and long term, in order to prudently determine the optimal course of action for the company.
Goldman Sachs and RBC Capital Markets have been engaged to assist the Board of Directors in connection with this strategic review. The company
has a number of capital projects with very good economics that are expected to increase production and/or improve netbacks. These projects will
continue to be evaluated during this period and will be undertaken when free cash flow is available.
Externally there is great uncertainty in the capital and debt markets which creates volatility in oil prices and oil price differentials. We remain bullish
regarding the long term price of bitumen, but we also recognize that during the second quarter there will be continued pressure on differentials and
therefore bitumen wellhead pricing. The price of natural gas is a key component in the company’s oil sands operations (natural gas is the biggest cost
component in the generation of steam) and is expected to remain low for the remainder of the year. Locally, the Alberta corridor continues to be a “bubble”
with regard to costs of services, fabrication of equipment and access to talent. Importantly, the hiatus in our capital spending provided time to determine
more cost effective if not local solutions. The ever-increasing focus on oil sands by the media, stakeholders and governments has resulted in expanded,
not streamlined, approval processes. Effective leadership on both sides of the border will be necessary to drive efficient and economic outcomes.
Connacher is focused on delivering successive and sustained improvement in operating and financial results and liquidity. Based on currently available
information and prevailing commodity prices, we anticipate 2012 results to reflect solid operational performance given capital constraints.
As a means of managing the risk of commodity price volatility, we monitor crude oil markets and enter into risk management commodity sales
contracts from time to time to ensure the company has adequate downside commodity price protection, having regard to its established hedging
policy, financial leverage and capital commitments.
2012 CAPITAL EXPENDITURE BUDGET AND PRODUCTION GUIDANCE
Our 2012 capital budget has been set at $50 million as outlined below, including the previously announced maintenance capital budget of
$37 million. The company is proceeding with preparatory work on several sustaining and growth projects, including a five- well core hole
program to provide further technical data for the Great Divide expansion project and Pad 104 drilling program (Pod One), preparatory lease
work and equipment pre-orders for Pad 104, finalizing the design basis memorandum for the Great Divide expansion project, preparation of a
commercial front-end engineering design study for the company’s SAGD+ project and expansion and upgrading of the rail and other facilities
at the Montana refinery.
2012 capital budget on a cash basis ($ in millions)
Upstream $ 35
Downstream 11
Corporate 4
Total 2012 capital budget on cash basis $ 50
Actual capital expenditures incurred during 2012 could differ materially from these estimates – please see “Forward-Looking Information” in the
Advisory section and “Risk Factors”.
2012 production guidance
Upstream Production (boe/d) 12,600 – 13,900
Downstream Crude Charged (bbl/d) 9,150 – 10,600
The 2012 production guidance provided includes provision for turnarounds at both Pod One and Algar in Q3 2012 and does not include
incremental production which may be achieved from recommencement of the company’s SAGD+ project or completion of any future project.
Actual production achieved during 2012 could differ materially from these estimates – please see “Forward-Looking Information” in the Advisory
section and “Risk Factors”.
LIQUIDITY
Connacher is committed to maintaining substantial liquidity and accordingly, reported a cash position of $117.0 million at December 31, 2011, up
from $19.5 million a year earlier. During 2011, we concluded certain key activities to increase liquidity in response to current market conditions and
to enable us to redeem our 4 ¾ percent $100 million Convertible Debentures when due on June 30, 2012. These 2011 liquidity-building initiatives
follow significant developments, comprised of both asset sales and the refinancing of our long term debt. Our key liquidity-focused activities related to
our asset rationalization and capital spending were as follows:
• We refinanced our long-term debt in May 2011 which provided significantly lower interest rates and extended maturities to 2018 and 2019,
without interim principal payments and without incurring any restrictive financial or maintenance covenants. The refinancing involved the timely and
successful sale of Secured Second Lien Senior Notes, in both US and Canadian capital markets. These notes are further described under “New
Notes” in the Capital Resources section of this MD&A. Proceeds of the New Notes were used to fund a tender offer and pay associated costs
to acquire previously outstanding high coupon debt, which had been placed in the US high yield market during 2007 and 2009. In addition to

AR 2011
PG 21
reduced interest rates and anticipated annual interest expense reductions, we reduced our exposure to currency fluctuations with the placement of
a portion of the New Notes in the Canadian market with payment in Canadian dollars, our reporting currency.
• We were successful in increasing the size of our Revolving Credit Facility. Our overall and prospective liquidity was improved during 2011 by the
continued availability of an upsized syndicated revolving credit facility in the amount of $100 million, on which there is only $2 million utilized to
back-stop letters of credit.
• We completed the sales of our mature producing conventional oil and gas properties and minor unproved lands in Alberta and Saskatchewan and
the sale of our 50 percent interest in lands at Halfway Creek, Alberta for net proceeds of $117.3 million. We also sold our investment in common
shares of Gran Tierra Energy Inc. for net proceeds of $21.1 million.
• We reduced our 2012 capital expenditure budget.
Higher trade and accrued receivables and inventory balances as at December 31, 2011, compared to December 31, 2010, are primarily due to
increases in production and sales in 2011. Higher trade and accrued payables as at December 31, 2011, compared to December 31, 2010, reflect
the timing of capital expenditure programs and interest payments.
As we enter 2012, one of the company’s biggest challenges is the volatility of commodity prices and the uncertainty surrounding the US:Canadian
dollar exchange rate and their combined significance to the company’s operating performance and results. There is considerable pressure on
heavy crude oil pricing due to uncertainty surrounding the market impact of the Seaway pipeline reversal announcement, Bakken crude supply,
transportation constraints and planned Pad IV refinery turnarounds and shutdowns. Management regularly assesses alternative hedging strategies
to protect the company’s cash flow from the risk of severe downturns in crude oil prices, refined product pricing and adverse foreign exchange rate
fluctuations. Although the company’s integrated business model provides some risk mitigation, it does not provide a complete hedge, particularly
against commodity price volatility. The purpose of any hedging activity undertaken is to ensure more predictable cash flow availability to supplement
cash balances. This allows us to continue to service and discharge indebtedness, complete capital projects and protect the credit capacity of
Connacher’s oil and gas reserves in an uncertain or volatile commodity price environment.
The company has WTI risk management contracts on a portion of its crude oil, gasoline and diesel sales and AECO risk management contracts on a
portion of its natural gas consumption requirements. Details of these risk management contracts are provided in this MD&A. These risk management
contracts are undertaken pursuant to policies adopted by the Board of Directors and having consideration for restrictions embedded in our longterm
debt indenture. At December 31, 2011, the company had net working capital of $16.9 million (December 31, 2010 – $138.6 million), including
$117.0 million of cash (December 31, 2010 – $19.5 million) and after deducting the company’s current portion of long-term debt of $102.0 million
(December 31, 2010 – nil).
SELECT ANNUAL INFORMATION
($000 except per share amounts) 2011 2010 2009 (1)
Revenue, net of royalties $ 872,806 $ 589,931 $ 449,789
Adjusted EBITDA (2) 129,871 92,206 37,268
Net earnings (loss) (114,105) (44,669) 26,158
Net earnings (loss) per share - basic and diluted (0.25) (0.10) 0.08
Additions to property, plant and equipment and
163,428 259,165 322,064
exploration and evaluation assets
Total assets 1,605,626 1,569,137 1,741,866
Long-term debt $ 856,068 $ 847,387 $ 876,181
(1) Presented in accordance with previous GAAP as reported previously in the respective financial statements.
(2) Adjusted EBITDA is a non-GAAP measure, which is defined in the Advisory section of the MD&A.
In 2011, higher revenue in both the upstream and downstream segments contributed to a 48 percent increase in the total net revenue compared
to 2010. Upstream revenue increased by 65 percent, primarily as result of a 62 percent increase in bitumen sales volumes (13,276 bbl/d in 2011
compared to 8,206 bbl/d in 2010) as a result of the commissioning of the company’s second oil sands project, Algar, and the inclusion of its
operating results from October 1, 2010. In addition, higher weighted average upstream sales prices ($47.41/boe in 2011 compared to $44.13/boe
in 2010) contributed to increased revenue in 2011 compared to 2010. This was primarily due to higher benchmark crude oil prices, partially offset
by wider heavy crude oil differentials resulting from pipeline disruptions and other factors. Downstream revenue increased by 32 percent in 2011,
compared to 2010, due to an 11 percent increase in sales volume (11,141 bbl/d in 2011 compared to 10,080 bbl/d in 2010) and a 19 percent
increase in the weighted average sales price of refined petroleum products sold ($105.46/bbl in 2011 compared to $88.68/bbl in 2010).
In 2010, revenue increased by 31 percent compared to 2009 primarily due to higher sales volume in oil sands operations coupled with higher
commodity prices in both upstream and downstream segments.
In 2011, adjusted EBITDA increased 41 percent compared to 2010, primarily due to higher upstream and downstream netbacks. Similarly, higher
netbacks in both segments contributed to an increase in adjusted EBITDA in 2010 compared to 2009.
Notwithstanding higher adjusted EBITDA, the company incurred a net loss of $114.1 million in 2011 compared to net loss of $44.7 million in 2010.

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This was primarily due to lower foreign exchange gains, higher depletion, depreciation, amortization and impairment and higher financing related costs
partially offset by gains on sale of assets and risk management contracts.
The company incurred capital expenditures of $163.4 million in 2011 compared to $259.2 million in 2010. Reduced capital expenditures in 2011
were primarily due to the completion of the Algar plant in 2010.
The company completed the refinancing of its long-term debt in 2011 to reduce cash interest, extend maturities and reduce exposure to foreign
exchange rate fluctuations. As a result, the long-term debt balance was increased in 2011 compared to 2010 to fund the redemption premium paid
for the refinancing of the long-term debt.
Although the face value of our long-term debt did not change in 2010 compared to 2009, its carrying value decreased in 2010 due to the effect of
translation to a Canadian dollar equivalent of our US-dollar denominated long-term debt, at a stronger Canadian dollar exchange rate as at December
31, 2010 compared to its level at December 31, 2009. The majority of the company’s long-term debt was previously denominated in US dollars.
FINANCIAL AND OPERATING REVIEW
UPSTREAM - CANADA
SALES AND PRODUCTION VOLUMES (1) Three months ended December 31 Year ended December 31
2011 2010 % Change 2011 2010 % Change
Dilbit sales – bbl/d (2) 17,278 17,442 (1) 17,165 11,012 56
Diluent used – bbl/d (2) (4,024) (4,573) (12) (3,889) (2,806) 39
Bitumen sold – bbl/d (2) 13,254 12,869 3 13,276 8,206 62
Crude oil – bbl/d 417 873 (52) 427 883 (52)
Natural gas – Mcf/d 2,955 8,318 (64) 4,124 9,100 (55)
Total sales volumes – boe/d 14,164 15,128 (6) 14,390 10,606 36
Total production volumes – boe/d (3) 14,083 15,498 (9) 14,493 10,699 35
(1) Effective October 1, 2010, the capitalized costs relating to the company’s second oil sands project, Algar, were subjected to depletion and the revenues, expenses and finance charges associated with
the project were reported in the statement of operations. Prior thereto, Algar was considered a major development project under construction and all costs, including related financing costs and operating
expenses net of revenue were capitalized. Accordingly, the above table does not include production and sales volumes for Algar prior to October 1, 2010.
(2) Bitumen produced at our oil sands project is mixed with purchased diluent and sold as “dilbit”. Diluent is a light hydrocarbon that improves the marketing and transportation quality of bitumen. Diluent volumes
used have been deducted in calculating bitumen production and sales volumes.
(3) The company’s bitumen sales volumes differ from its production volumes due to changes in inventory and other product losses.
In Q4 2011, bitumen sold includes the impact of our pilot SAGD+ project at our two well pads in Great Divide. Diluent used in Q4 2011 decreased by
12 percent compared to Q4 2010, which reflects both the impact of this project and the impact of first quarter production at Algar in 2010. Bitumen
sold increased 62 percent in YTD 2011 compared to YTD 2010, primarily due to the startup of, Algar booked effective October 1, 2010.
In Q4 2011 and YTD 2011, conventional production and sales volumes declined compared to the 2010 periods primarily due to the property sales
early in the year, partially offset by new production coming on stream from our resource plays.
COMMODITY PRICES AND RISK MANAGEMENT
Three months ended December 31 Year ended December 31
Average benchmark prices 2011 2010 % 2011 2010 %
West Texas Intermediate (WTI) crude oil US$/barrel at Cushing $ 94.05 $ 85.16 10 $ 95.14 $ 79.51 20
Heavy Oil Differential – C$/bbl (1) 10.70 18.35 (42) 16.95 14.69 15
Western Canadian Select (WCS) C$/bbl 85.53 67.87 26 77.15 67.23 15
Edmonton C5 (C$/bbl) (1) 111.36 86.24 29 104.21 84.23 24
Natural Gas (Alberta spot) C$/Mcf at AECO 3.40 3.61 (6) 3.56 3.98 (11)
Average realized prices (2)(3)
Bitumen - C$/bbl 53.04 45.08 18 47.59 45.65 4
Crude oil - C$/bbl 89.57 66.72 34 82.44 65.63 26
Natural gas - C$/Mcf 3.27 3.44 (5) 3.70 3.90 (5)
Weighted average sales price – C$/boe (4) $ 52.96 $ 44.09 20 $ 47.41 $ 44.13 7
Weighted average sales price, including realized gains/loss on risk
management contracts – C$/boe (2) (4) $ 52.29 $ 42.89 22 $ 45.67 $ 43.68 5
(1) Heavy oil differential refers to the WCS discount to WTI; Edmonton C5 is the benchmark price for diluent.
(2) Based on sales volume and calculated before royalties and after blending and transportation costs.
(3) Before risk management contract gains or losses.
(4) Boe is defined in the Advisory section of the MD&A.

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Connacher’s bitumen production slate is a heavy gravity crude oil. Consequently, the bitumen selling prices realized by the company are lower than the
WTI reference price. This difference is commonly referred to as the “heavy oil differential” as applied to crude oil prices. Actual realized bitumen prices
are a calculated amount derived by deduction from diluted bitumen (“dilbit”) sales prices of such items as the cost of diluent, transportation charges for
both diluent from purchase points to our Great Divide site and for dilbit from our Great Divide site to market. Other factors which influence calculated
bitumen prices include the relative value of the Canadian dollar, the blend ratio and quality differentials.
In YTD 2011, higher realized bitumen prices were driven by higher benchmark WTI prices partially offset by wider heavy oil differentials, higher diluent
costs and higher transportation charges necessitated by the need to utilize transportation alternatives and more distant markets because of pipeline
apportionment and other issues. The heavy oil differential discount widened in 2011 due to market demand and supply issues for heavy crude relative
to lighter crude, attributed primarily to USA refinery needs and pipeline disruptions or other bottlenecks that limited the transportation capacity for
heavy crude oil to the USA.
Higher realized conventional crude oil pricing in 2011 resulted from generally higher market oil prices and an increased weighting of a lighter crude
oil as a result of disposing of our medium gravity Saskatchewan oil properties and adding new light gravity crude oil production from our resource
plays. The change in realized natural gas prices in 2011 was consistent with the change in benchmark prices.
Dilbit, crude oil and natural gas are generally sold on month-to-month sales contracts at prices negotiated with major Canadian or USA marketers,
refiners, regional upgraders or other end users, by reference to various benchmark prices, including WTI market prices for crude oil and AECO
market prices for natural gas. Connacher maintains various short-term contracts for the sale of dilbit to a variety of heavy oil purchasers in central and
northern Alberta. In order to secure diluent supplies, Connacher also utilizes short-term diluent purchase contracts and acquires certain volumes from
its own refinery at Great Falls, Montana.
As a means of managing the risk of commodity price volatility, management monitors crude oil markets and enters into risk management commodity
sales contracts from time to time to ensure Connacher has adequate downside commodity price protection, having regard to its established hedging
policy, financial leverage and capital commitments. Our hedging program is administered by a management subcommittee comprised of appropriate
departmental representatives.
The company recorded unrealized and realized losses of $23.7 million and $0.9 million, respectively, in Q4 2011 (Q4 2010 – an unrealized and
realized loss of $16.3 million and $1.7 million, respectively) and for the YTD 2011, the company recorded an unrealized gain of $7.2 million and a
realized loss of $9.2 million (YTD 2010 – an unrealized loss of $13.6 million and a realized loss of $1.7 million) on the risk management contracts.
Currently, the company has the following WTI crude oil price risk management contracts in place:
Volume (bbl/d)
Type Pricing (WTI US$/bbl) Q1 2012 Q2 2012 Q3 2012 Q4 2012 Year 2013
Swap $90.60 2,000 2,000 2,000 2,000 -
Swap $90.50 - - 1,000 1,000 -
Swap $109.40 - 1,000 - - -
Collar Call $96.00 Put $80.00 2,000 - - - -
Collar Call $100.00 Put $80.00 2,000 2,000 - - -
Collar Call $120.00 Put $80.00 2,000 2,000 2,000 2,000 -
Collar Call $98.00 Put $80.00 - - 1,000 1,000 -
Collar Call $118.00 Put $100.00 - - 1,000 - -
Collar Call $116.50 Put $100.00 - - - 1,000 -
Collar Call $118.30 Put $90.00 - - - - 300
Collar Call $117.80 Put $90.00 - - - - 1,000
8,000 7,000 7,000 7,000 1,300

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UPSTREAM REVENUE (1)
Three months ended December 31 2011 2010
($000 except per unit amounts) Oil sands Crude oil Natural gas Total Oil sands Crude oil Natural gas Total
Gross upstream revenues (2) $ 123,150 $ 3,441 $ 889 $ 127,480 $ 99,456 $ 5,377 $ 2,633 $ 107,466
Diluent costs (3) (43,727) - - (43,727) (37,810) - - (37,810)
Transportation costs (14,741) (3) - (14,744) (8,273) (15) (1) (8,289)
Revenues $ 64,682 $ 3,438 $ 889 $ 69,009 $ 53,373 $ 5,362 $ 2,632 $ 61,367
Price ($ per bbl / Mcf / boe) (4) $ 53.04 $ 89.57 $ 3.27 $ 52.96 $ 45.08 $ 66.72 $ 3.44 $ 44.09
Year ended December 31 2011 2010
($000 except per unit amounts) Oil sands Crude oil Natural gas Total Oil sands Crude oil Natural gas Total
Gross upstream revenues (2) $ 443,768 $ 12,929 $ 5,565 $ 462,262 $ 247,187 $ 21,229 $ 12,942 $ 281,358
Diluent costs (3) (162,410) - - (162,410) (91,644) - - (91,644)
Transportation costs (50,757) (81) - (50,838) (18,806) (66) (1) (18,873)
Revenues $ 230,601 $ 12,848 $ 5,565 $ 249,014 $ 136,737 $ 21,163 $ 12,941 $ 170,841
Price ($ per bbl / Mcf / boe) (4) $ 47.59 $ 82.44 $ 3.70 $ 47.41 $ 45.65 $ 65.63 $ 3.90 $ 44.13
(1) Effective October 1, 2010, the capitalized costs relating to the company’s second oil sands project, Algar, were subjected to depletion and the revenues, expenses and finance charges associated with
the project were reported in the statement of operations. Prior thereto, Algar was considered a major development project under construction and all costs, including related financing costs and operating
expenses net of revenue were capitalized. Accordingly, the above table does not include operating results for Algar prior to October 1, 2010.
(2) Bitumen produced at our oil sands project is mixed with purchased diluent and sold as “dilbit”. Gross revenues represent sales of dilbit, crude oil and natural gas and are presented before royalties. In the
consolidated financial statements, upstream revenues are presented net of royalties.
(3) The cost of diluent has been deducted from gross revenues in calculating revenues, above, whereas the diluent costs have been included in “Blending and costs of product sold” in the consolidated financial
statements. Diluent costs, above, include purchases of $3.8 million and $15.2 million from our subsidiary, MRCI in Q4 2011 and YTD 2011, respectively (Q1 2010 and YTD 2010 - $3.8 million and $14.3
million, respectively) at market prices. These intercompany transactions have been eliminated in our consolidated financial statements.
(4) Per unit prices are calculated using revenues divided by bitumen, crude oil and natural gas actual volumes sold.
The bitumen produced by Connacher requires blending to reduce its viscosity in order to transfer the bitumen to market. Diluent used represented
approximately 23 percent of the dilbit barrel sold in Q4 2011 and YTD 2011 (26 percent in Q4 2010 and 25 percent in YTD 2010). In 2011, we
purchased 3,889 bbl/d of diluent at $114.41 per bbl, including transportation costs, compared to 2,806 bbl/d at $89.48 per barrel for the same
period last year. The cost of blending diluent is recovered at the sale price of the blended product.
Transportation costs represent costs to transport dilbit and crude oil to customers. Transportation costs increased by 78 percent in Q4 2011
compared to Q4 2010 and 169 percent in YTD 2011 compared to YTD 2010, due to increased bitumen sales volumes as wells as higher trucking
costs resulting from both industry cost pressures and increased long-haul trucking to markets in 2011 arising from sales market disruptions.
Additionally, we commenced railing dilbit to new USA markets to alleviate downstream barriers, to access new sales markets that are less connected
to current WTI/WCS pricing levels and which give evidence of being more aligned with higher Brent oil pricing. In conjunction with our goal of
optimizing netbacks, railing dilbit is a part of our marketing diversification strategy, primarily aimed at mitigating the risk of plant curtailment due to any
inability to sell production in congested markets, combined with minimal on-site storage facilities. Transportation and marketing costs for 2011 also
include the carrying cost of temporary storage facilities secured in Tacoma, Washington during the year.
ROYALTIES (1)
Three months ended December 31 2011 2010
($000 except per unit amounts) Oil sands Crude oil Natural gas Total Oil sands Crude oil Natural gas Total
Royalties $ 3,772 $ 544 $ (98) $ 4,218 $ 2,188 $ 1,587 $ 70 $ 3,845
Royalties ($ per bbl / Mcf / boe) (2) $ 3.09 $ 14.17 $ (0.36) $ 3.24 $ 1.85 $ 19.76 $ 0.09 $ 2.76
Year ended December 31 2011 2010
($000 except per unit amounts) Oil sands Crude oil Natural gas Total Oil sands Crude oil Natural gas Total
Royalties $ 13,740 $ 2,556 $ (938) $ 15,358 $ 5,440 $ 5,713 $ 172 $ 11,325
Royalties ($ per bbl / Mcf / boe) (2) $ 2.83 $ 16.40 $ (0.62) $ 2.92 $ 1.82 $ 17.72 $ 0.05 $ 2.93
(1) Effective October 1, 2010, the capitalized costs relating to the company’s second oil sands project, Algar, were subjected to depletion and the revenues, expenses and finance charges associated with
the project were reported in the statement of operations. Prior thereto, Algar was considered a major development project under construction and all costs, including related financing costs and operating
expenses net of revenue were capitalized. Accordingly, the above table does not include operating results for Algar prior to October 1, 2010.
(2) Per unit royalties are calculated using royalties divided by bitumen, crude oil and natural gas actual volumes sold.
Royalties represent charges against production or revenue by governments and landowners. From period to period, royalties vary due to changes in the
product mix, the components of which are subject to different royalty rates. Additionally, royalty rates are applied on a sliding scale to commodity prices.
Royalties in Q4 2011 and YTD 2011 increased by 10 percent and 36 percent compared to Q4 2010 and YTD 2010, respectively, primarily due to
higher sales volumes and higher WTI benchmark prices on which royalties are calculated, partially offset by Alberta gas cost allowance recoveries.

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OPERATING COSTS (1)
Three months ended December 31 2011 2010
($000 except per unit amounts) Oil sands Crude oil Natural gas Total Oil sands Crude oil Natural gas Total
Operating costs $ 23,923 $ 781 $ 560 $ 25,264 $ 22,447 $ 1,331 $ 1,145 $ 24,923
Operating costs ($ per bbl / Mcf / boe) (2) $ 19.62 $ 20.35 $ 2.07 $ 19.39 $ 18.96 $ 16.57 $ 1.50 $ 17.91
Year ended December 31 2011 2010
($000 except per unit amounts) Oil sands Crude oil Natural gas Total Oil sands Crude oil Natural gas Total
Operating costs $ 97,295 $ 2,929 $ 2,912 $ 103,136 $ 60,344 $ 4,407 $ 5,403 $ 70,154
Operating costs ($ per bbl / Mcf / boe) (2) $ 20.08 $ 18.80 $ 1.93 $ 19.64 $ 20.15 $ 13.67 $ 1.63 $ 18.12
(1) Effective October 1, 2010, the capitalized costs relating to the company’s second oil sands project, Algar, were subjected to depletion and the revenues, expenses and finance charges associated with
the project were reported in the statement of operations. Prior thereto, Algar was considered a major development project under construction and all costs, including related financing costs and operating
expenses net of revenue were capitalized. Accordingly, the above table does not include operating results for Algar prior to October 1, 2010.
(2) Per unit costs are calculated using operating costs divided by bitumen, crude oil and natural gas actual volumes sold.
Total oil sands operating costs increased by 7 percent in Q4 2011 compared to Q4 2010, reflecting general industry cost conditions and increased by
61 percent in YTD 2011 compared to YTD 2010 due to the incremental production at Algar. Operating costs in 2011 also include incremental costs
related to our SAGD+ pilot project.
The table below summarizes information related to our oil sands operating costs:
Three months ended December 31 Year ended December 31
2011 2010 2011 2010
($000) ($ per bbl) ($000) ($ per bbl) ($000) ($ per bbl) ($000) ($ per bbl)
Natural gas costs (1) $ 6,696 5.49 $ 7,187 6.07 $ 29,263 6.04 $ 18,142 6.06
Other operating costs 17,227 14.13 15,260 12.89 68,032 14.04 42,202 14.09
Total oil sands operating costs $ 23,923 $ 19.62 $ 22,447 $ 18.96 $ 97,295 $ 20.08 $ 60,344 $ 20.15
(1) Excluding risk management contract gains and losses. Includes natural gas consumed by boilers at the cogeneration facility and by other vessels at Great Divide.
We utilize natural gas primarily for our boilers at both plants and our cogeneration facility at Algar. In Q4 2011, the combined steam: oil ratio (“SOR”)
from Pod One and Algar was 4.1 compared to 3.8 in Q4 2010. On a YTD basis, SOR was 4.0 in 2011 compared to 4.3 in 2010. The company had
been producing high levels of steam at Algar to test the reservoir performance while in ramp-up, but recently reduced steam production without any
attendant reduction of bitumen production. At Pod One, the higher SORs reflect the impact of underperforming wells on the north pad. The drilling of
new wells and new technologies such as SAGD+ are anticipated to lower SORs and improve individual well and overall productivity.
We commissioned our 13 megawatt cogeneration plant at Algar in 2010 and as a consequence have experienced the benefits of improved power
stability in our oil sands operations. Although this has resulted in higher natural gas utilization and related costs, it has reduced our reliance on third
party power suppliers and has improved operational reliability at both Pod One and Algar.
The company also recorded risk management contract losses of $1.9 million in Q4 2011 and $2.5 million in YTD 2011 relating to AECO natural
gas purchase contracts. These losses are not included in the calculation of operating costs noted in the table above. Currently, the company has the
following AECO natural gas price risk management contracts:
• January 1, 2012 – December 31, 2012 – 5,000 GJ/d at a minimum of AECO CAD$3.70/GJ and a maximum of AECO CAD$4.30/GJ;
• January 1, 2012 – December 31, 2012 – 5,000 GJ/d at a minimum of AECO CAD$2.80/GJ and a maximum of AECO CAD$4.00/GJ;
• March 1, 2012 – June 30, 2012 – 2,500 GJ/d at a minimum of AECO $1.85/GJ and a maximum of AECO $2.90/GJ; and
• July 1, 2012 – September 30, 2012 – 2,500 GJ/d at a minimum of AECO $1.85/GJ and a maximum of AECO $3.20/GJ.
SAGD+
Connacher completed a steam with solvent (SAGD+) field trial on two of its wells located on Pad 203 at Algar in 2011, as a pilot project designed
to enhance reservoir recovery and bitumen production, while lowering steam injection volumes. Results were encouraging, with an approximate
29 percent increase in base-line bitumen production and a reduction in SOR by approximately 17 percent. The company is currently completing a
commercial front-end engineering design study on this project. While solvent recoveries and related production impact have exceeded expectations,
facility modifications will have to be implemented to fully capture and recycle the recovered solvent.

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UPSTREAM NETBACKS (1)
Three months ended December 31 2011 2010
($ per bbl / Mcf / boe) Oil sands Crude oil Natural gas Total Oil sands Crude oil Natural gas Total
Revenues (2) $ 53.04 $ 89.57 $ 3.27 $ 52.96 $ 45.08 $ 66.72 $ 3.44 $ 44.09
Royalties (3.09) (14.17) 0.36 (3.24) (1.85) (19.76) (0.09) (2.76)
Operating costs (19.62) (20.35) (2.07) (19.39) (18.96) (16.57) (1.50) (17.91)
Netbacks (3) $ 30.33 $ 55.05 $ 1.56 $ 30.33 $ 24.27 $ 30.39 $ 1.85 $ 23.42
Year ended December 31, 2011 2011 2010
($ per bbl / Mcf / boe) Oil sands Crude oil Natural gas Total Oil sands Crude oil Natural gas Total
Revenues (2) $ 47.59 $ 82.44 $ 3.70 $ 47.41 $ 45.65 $ 65.63 $ 3.90 $ 44.13
Royalties (2.83) (16.40) 0.62 (2.92) (1.82) (17.72) (0.05) (2.93)
Operating costs (20.08) (18.80) (1.93) (19.64) (20.15) (13.67) (1.63) (18.12)
Netbacks (3) $ 24.68 $ 47.24 $ 2.39 $ 24.85 $ 23.68 $ 34.24 $ 2.22 $ 23.08
(1) Effective October 1, 2010, the capitalized costs relating to the company’s second oil sands project, Algar, were subjected to depletion and the revenues, expenses and finance charges associated with
the project were reported in the statement of operations. Prior thereto, Algar was considered a major development project under construction and all costs, including related financing costs and operating
expenses net of revenue, were capitalized. Accordingly, the above table does not include operating results for Algar prior to October 1, 2010.
(2) Revenues are calculated after deducting diluent and transportation costs, but before royalties and risk management contract gains or losses.
(3) Netbacks are a non-GAAP measure and are defined in the Advisory section of the MD&A.
DOWNSTREAM - USA
Connacher’s wholly-owned subsidiary, MRCI operates a 9,500 bbl/d heavy oil refinery located in Great Falls, Montana (the “Refinery”) which is
strategically aligned with our oil sands business. It primarily processes Canadian heavy sour crude oil into a range of higher value refined petroleum
products, thereby capturing more of the value chain in a produced barrel of oil. Accordingly, the Refinery provides a physical hedge for our bitumen
revenue by recovering a portion of the heavy oil differential in its netbacks under normal operating conditions. In 2011, the refinery margin per barrel of
bitumen sold was $8.67 (2010 - $9.70 per bbl), illustrating the positive contribution to overall corporate netbacks of owning the Refinery. The Refinery
is located on an approximately 73 acre site and is a fully integrated refinery with reforming, isomerization and alkylation processes for formulation of
gasoline blends, hydro-treating for ultra low sulphur diesel and fluid catalytic cracking for conversion of heavy gas oils to gasoline and distillate products.
Also, it is a major supplier of paving grade asphalt, polymer modified grades and asphalt emulsions for road construction. The Refinery delivers products
in Montana and to neighboring regions, including, Alberta, Canada, by truck and rail transport. Upon completion of the benzene removal project currently
underway, the Refinery will also be able to access the southern Alberta market for gasoline. The Refinery is also a source of supply for a portion of our
diluent requirements for oil sands operations. These intercompany purchases and sales have been eliminated on consolidation.
The operating results of our Refinery are subject to a number of seasonal factors which cause production and sales to vary throughout the year. The
Refinery’s primary asphalt market is paving for road construction, which is in greater demand during the summer. Consequently, the Refinery runs a
higher proportion of lighter, higher cost crude in the October to March period to restrict asphalt production, and sales prices and volumes for asphalt
are higher in the summer and lower in the colder seasons. During the winter, most of the Refinery’s asphalt production is stored in tankage for sale in
the subsequent summer. Seasonal factors also affect the production and sale of gasoline, which has a higher demand in summer months. As a result,
inventory levels, sales volumes and prices can be expected to fluctuate on a seasonal basis. The Refinery has approximately one million barrels of
feedstock and product tankage.
REFINERY THROUGHPUT
Three months ended December 31 Year ended December 31
2011 2010 2011 2010
Crude charged – bbl/d (1) 10,295 10,137 9,890 9,693
Refinery production – bbl/d (2) 11,515 11,964 10,876 10,704
Sales of refined petroleum products – bbl/d (3) 10,330 9,068 11,141 10,080
Refinery utilization (4) 108% 107% 104% 102%
(1) Crude charged represents the barrels per day of crude oil processed at the Refinery.
(2) Refinery production represents the barrels per day of refined products yielded from processing crude and other refinery feedstock.
(3) Includes refined products purchased for resale and blending.
(4) Represents crude charged divided by total crude capacity of the Refinery of 9,500 bbl/d.

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SALES PRODUCT MIX (%)
Three months ended December 31 Year ended December 31
2011 2010 2011 2010
Gasoline 45 49 41 45
Diesel 22 17 18 16
Jet fuel 4 5 5 7
Asphalt 27 25 34 30
Other 2 4 2 2
Total 100 100 100 100
In Q4 2011 and YTD 2011, the total sales volumes of refined petroleum products increased by 14 percent and 11 percent compared to Q4 2010
and YTD 2010, respectively, primarily due to the improved stability of refining operations, more favorable weather conditions for road paving activities
that buoyed higher relative asphalt sales and increased demand for refined petroleum products in 2011.
COMMODITY PRICES
Three months ended December 31 Year ended December 31
2011 2010 % 2011 2010 %
Average benchmark prices
West Texas Intermediate (WTI) crude oil US$/barrel at Cushing $ 94.05 $ 85.16 10 $ 95.14 $ 79.51 20
Average realized crude oil input cost
Crude Oil – US$/bbl at Refinery 90.05 72.00 25 84.28 69.33 22
Average realized refined product prices (1)
Gasoline – US$/bbl 107.56 88.35 22 112.35 87.48 28
Diesel – US$/bbl 136.38 107.82 26 126.77 94.97 33
Jet fuel – US$/bbl 131.23 105.18 25 133.65 96.57 38
Asphalt – US$/bbl 87.77 79.22 11 87.99 81.49 8
Weighted average sales price – US$ per bbl $ 108.32 $ 89.13 22 $ 106.81 $ 86.02 24
Weighted average sales price, including realized gains/loss
on risk management contracts – US$/bbl $ 109.43 $ 89.13 23 $ 107.06 $ 85.88 25
(1) Before risk management contracts gains and losses and after transportation costs.
The Refinery operates in PADD IV and is exposed to niche-like markets that resulted in above average realized refined product prices in 2011. Sales
of refined petroleum products are generally made on sales contracts negotiated with wholesalers, retailers and large end-users for gasoline, jet fuel
and diesel and with construction contractors and road builders for asphalt. Frequently, sales contracts are for periods in excess of one month.
General and local economic conditions affect refined product demand and pricing. We anticipate they will continue to influence our downstream
financial results in the future. To mitigate some of the risk of lower future gasoline and diesel selling prices and margins, the company entered
into certain risk management sales contracts. In Q4 2011, the company recorded a realized and unrealized gain of $1.0 million and $5.3 million,
respectively (Q4 2010 - $nil). In YTD 2011, the company recorded a realized and unrealized gain of $1.0 million and $5.6 million, respectively (YTD
2010 - realized loss of $543,000). Currently, the following risk management contracts in place:
• Gasoline swap – January 1, 2012 – March 31, 2012 – 1,000 bbl/d at WTI per barrel plus US$27.50/bbl;
• Diesel swap – January 1, 2012 – December 31, 2012 – 1,000 bbl/d at WTI per barrel plus US$32.25/bbl;
• Gasoline swap – April 1, 2012 – June 30, 2012 – 1,000 bbl/d at WTI per barrel plus US$21.25/bbl;
• Gasoline swap – April 1, 2012 – June 30, 2012 – 815 bbl/d at WTI per barrel plus US$23.00/bbl.
DOWNSTREAM REVENUE
Three months ended December 31 Year ended December 31
2011 2010 2011 2010
Gross revenue (1) ($000) $ 107,010 $ 77,435 $ 441,143 $ 334,165
Transportation and handling cost (2) ($000) (1,899) (2,905) (12,282) (7,899)
Downstream revenue ($000) $ 105,111 $ 74,530 $ 428,861 $ 326,266
Weighted average sales price ($ per bbl) (3) $ 110.60 $ 90.32 $ 105.47 $ 88.68
(1) Includes intersegment sales of $3.8 million in Q4 2011 and $15.2 million in YTD 2011 ($3.8 million in Q4 2010 and $14.3 million in YTD 2010), which were transacted at prevailing market prices and have
been eliminated from the consolidated financial statements. The costs of these sales were $3.5 million in Q4 2011 and $13.7 million in YTD 2011 ($3.4 million in Q4 2010 and $13.0 million in YTD 2010).
(2) Transportation cost is deducted in calculating above revenue whereas it is included in expenses in the consolidated statements of operations.
(3) Per unit prices are calculated using revenue divided by volumes of refined products sold.

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In Q4 2011 and YTD 2011, downstream revenue increased by 41 percent and 31 percent compared to Q4 2010 and YTD 2010, respectively. Higher
revenue was primarily due to higher light products production in 2011 relative to 2010 combined with higher weighted average realized sales prices
for all products, driven by stronger economic conditions in our sales market.
PRODUCT AND OPERATING COSTS
Three months ended December 31 Year ended December 31
2011 2010 2011 2010
Crude oil and other feedstocks ($000) $ 89,500 $ 59,760 $ 358,416 $ 266,205
Crude oil and other feedstocks ($ per bbl) (1) $ 94.17 $ 72.42 $ 88.14 $ 72.35
Operating costs ($000) $ 7,966 $ 6,686 $ 28,453 $ 30,994
Operating costs ($ per bbl) (1) $ 8.38 $ 8.10 $ 7.00 $ 8.42
(1) Per unit costs are calculated using crude oil purchases and operations costs divided by volumes of refined products sold; costs are exclusive of depreciation and amortization.
In Q4 2011, crude oil purchases and other feedstock costs per bbl increased by 30 percent compared to levels in Q4 2010 due to increased WTI
prices and narrower heavy oil differentials in Q1 2011 relative to the previous year. However, on a year to date basis, significantly higher WTI prices
were offset by wider heavy oil differentials, resulting in a lower year over year increase at 22 percent.
The Refinery completed a major maintenance turnaround in fourth quarter of 2009 and has commenced planning for the next turnaround scheduled
for the second quarter of 2013.
REFINING MARGIN (1) Three months ended December 31 Year ended December 31
2011 2010 2011 2010
Refining margin (1) ($000) $ 7,645 $ 8,084 $ 41,992 $ 29,067
Refining margin (weighted average $ per bbl) $ 8.05 $ 9.80 $ 10.33 $ 7.91
Refining margin (% of revenue) 7% 11% 10% 9%
(1) Refining margin is a non-GAAP measure and defined in the Advisory section of the MD&A. Refining netbacks are calculated by deducting crude oil purchases and operating costs from revenue. Refining
netbacks are calculated before eliminating inter-segment sales and related costs of sales.
CORPORATE REVIEW
GENERAL AND ADMINISTRATIVE EXPENSES
In Q4 2011, general and administrative (“G&A”) expenses were $8.5 million (YTD 2011 - $34.2 million), compared to $6.5 million in Q4 2010 (YTD
2010 - $23.8 million), primarily as a result of bringing our second oil sands plant on production effective October 1, 2010 (including higher staff
costs) as well as special advisory fees and other fees incurred in conjunction with the company’s joint venture processes in Q4 2011.
SHARE BASED COMPENSATION
Three months ended December 31 Year ended December 31
($000) 2011 2010 2011 2010
Charged to expense $ 734 $ 1,184 $ 3,453 $ 5,019
Capitalized to property, plant and equipment 19 142 238 1,610
Total $ 753 $ 1,326 $ 3,691 $ 6,629
The decrease in share based compensation charges in 2011 is primarily due to a lower number of options being granted in 2011 compared to 2010.
DEPLETION, DEPRECIATION, AMORTIZATION AND IMPAIRMENT (“DD&A”)
The following table summarizes the depletion, depreciation, amortization and impairment expense:
Three months ended December 31 Year ended December 31
($000) 2011 2010 2011 2010
Upstream $ 25,052 $ 18,799 $ 82,535 $ 57,966
Downstream 2,449 2,994 9,278 10,470
Corporate 526 664 1,859 2,330
Impairment - upstream 24,700 4,467 24,700 4,467
Amortization of exploration and evaluation assets 905 1,318 3,637 4,609
Total $ 53,632 $ 28,242 $ 122,009 $ 79,842

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Depletion expense is calculated using the unit-of-production method, based on estimated total proved and probable (“2P”) reserves. Future capital
costs estimated to realize production from the company’s 2P reserve is also added to the carrying amount of capitalized costs for depletion purposes.
Depletion expense was higher in the 2011 periods as a result of increased production. On a boe basis, depletion was $19.33/boe of production in
Q4 2011 (Q4 2010 - $13.18/boe of production). Downstream and corporate property, plant and equipment are depreciated over their estimated
useful lives.
The company recorded impairment charge of $24.7 million in 2011 (2010 - $4.5 million) relating to certain conventional oil and gas properties
located in Central Alberta.
FINANCE CHARGES
Three months ended December 31 Year ended December 31
($000) 2011 2010 2011 2010
Finance charges – total $ 30,994 $ 25,635 $ 95,588 $ 107,735
Less: Capitalized – – – (38,290)
Finance charges – expensed $ 30,994 $ 25,635 $ 95,588 $ 69,445
Finance charges include interest expense relating to the Convertible Debentures, Senior Notes and the Revolving Credit Facility (the “Facility”),
amortization of transaction costs of the Facility, standby fees associated with the Facility and fees on letters of credit issued. Finance charges also
include non-cash charges with respect to the Convertible Debentures and Senior Notes. Higher finance charges in Q4 2011 compared to Q4 2010
was primarily due to a higher unrealized loss on remeasurement of Convertible Debentures at fair value. Total finance charges in YTD 2011 were
lower than YTD 2010 primarily due to lower interest on Senior Notes and lower unrealized loss on remeasurement of Convertible Debentures to fair
value. Lower interest expense on New Notes resulted from the debt refinancing completed in May 2011.
REFINANCING OF LONG-TERM DEBT
As a result of the issuance of new Second Lien Senior Notes (the “New Notes”) and the purchase and redemption of old Notes during Q2 2011,
the company performed an analysis and determined that this transaction partially resulted in a modification and partially an extinguishment of old
Notes. Accordingly, the company recorded costs of refinancing of $36.1 million as a discount on the New Notes and approximately $61.9 million
was expensed in the consolidated statement of operations. The repayment of US dollar denominated old Notes in YTD 2011 also resulted in the
realization of a foreign exchange gain of $11.6 million.
FOREIGN EXCHANGE GAINS
The value of the Canadian dollar relative to the U.S. dollar has risen and fallen throughout 2011 (trading between $0.95 U.S. and $1.04 U.S.) and has
had a significant impact on Connacher’s results, upon settling US dollar-denominated transactions and translating its US dollar-denominated long-term
debt and US dollar cash balances into Canadian dollars for financial reporting purposes. We recorded foreign exchange gain of $10.7 million in Q4
2011 compared with gains of $26.9 million in Q4 2010 and losses of $8.9 million in YTD 2011 compared with gains of $41.6 million for YTD 2010.
GAIN ON DISPOSITION OF ASSETS
In Q4 2011, the company realized a gain of $0.6 million (Q4 2010 – loss of $1.2 million) primarily from the sale of oil and gas properties offset by a
loss on the sale of Gran Tierra Energy Inc. common shares (“Gran Tierra Energy”) (see below). For YTD 2011, a gain of $43.5 million (YTD 2010 –
loss of $0.8 million), was realized primarily from the sale of our Marten Creek, Battrum, Latornell and Halfway Creek oil and gas properties and sale of
Gran Tierra Energy shares.
SHARE OF INTEREST IN AND LOSS ON ASSOCIATE
In March 2011, Petrolifera Petroleum Limited (“Petrolifera”) was acquired by Gran Tierra Energy. Under the terms of the sale, Connacher’s holding in
Petrolifera was exchanged for 3.3 million common shares and 841,000 common share purchase warrants of Gran Tierra Energy Inc. The common
share purchase warrants expired unexercised in 2011. As a result of the transaction, the company recognized a loss of $2.3 million and transferred
a loss of $4.5 million, an amount which had previously been recognized in other comprehensive loss. Common shares of Gran Tierra Energy Inc.
received were sold in Q4 2011 for net proceeds of $21.1 million resulting in a net loss of $4.6 million.
INCOME TAXES
The total income tax recovery of $24,000 in 2011 (2010 – $8.1 million) included a current income tax provision of $1.5 million (2010 – recovery
of $291,000) and deferred income tax recovery of $1.6 million (2010 - $7.8 million). The increase in current income tax provision in 2011 primarily
relates to higher net earnings in MRCI.
The company has specific tax matters under discussion with tax authorities, the outcome of which is uncertain. Where the final outcome of these
matters is different from the amounts currently recorded, such differences will be recorded in net earnings (loss) in the period in which such
determination is made.

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ADJUSTED EBITDA, CASH FLOW AND NET LOSS
Connacher realized improved operational performance in 2011 as a result of higher upstream and downstream sales volumes and higher product
selling prices. This improved performance resulted in higher adjusted EBITDA. Adjusted EBITDA was $39.1 million in Q4 2011 compared to $31.9
million reported in Q4 2010; YTD 2011 was up 41 percent to $129.9 million, compared to $92.2 million in YTD 2010.
Cash flow in Q4 2011 of $19.3 million was 114 percent higher than the $9.0 million reported in Q4 2010. YTD 2011 cash flow of $45.1 million was
26 percent higher than in YTD 2010 when it was $35.9 million. Increased cash flow in 2011 periods was primarily due to higher netbacks.
The company realized net loss of $59.5 million in Q4 2011 compared to a net loss of $25.6 million in Q4 2010 and incurred a net loss of $114.1
million in YTD 2011 compared to a loss of $44.7 million in YTD 2010 primarily due to higher finance charges, the cost of refinancing long-term debt,
higher depletion, depreciation, amortization and impairment charges and foreign exchange losses incurred in 2011.
CAPITAL EXPENDITURES
ACTUAL CAPITAL EXPENDITURES
Year ended December 31
($000) 2011 2010
Upstream $ 137,974 $ 191,740
Downstream 18,653 8,575
Cash-related capital expenditures 156,627 200,315
Non-cash related capital expenditures 6,801 58,850
Total capital expenditures $ 163,428 $ 259,165
YTD 2011 cash capital expenditures for maintenance and sustaining activities were $51 million, including $32 million at our oil sands operations;
$6 million in our conventional operations and head office requirements; and $13 million at our Refinery related to boiler replacement and substation
upgrades. YTD 2011 growth and special projects cash capital expenditures of $106 million included $63 million related to our conventional; $2
million at our oil sands producing operations; $6 million related to the Great Divide Environmental Impact Assessment; $30 million related to oil sands
exploration activities; and $5 million at our Refinery related to the benzene removal project. Conventional outlays were entirely financed from proceeds
of sales of non-core or mature conventional properties.
YTD 2010 cash capital expenditures for maintenance and sustaining activities were $32 million, including $15 million at our oil sands operations;
$9 million in our conventional operations and head office requirements; and $8 million at our Refinery related to boiler replacement and substation
upgrades. YTD 2010 growth and special projects cash capital expenditures of $168 million included $153 million related to our oil sands operations;
$13 million at our conventional operations and $1 million at our Refinery related to the benzene removal project.
Non-cash related capital expenditures include revisions for changes in estimated costs and rates of discount relating to decommissioning liabilities.
CAPITAL RESOURCES
Connacher’s objectives in managing its cash, debt, equity, balance sheet and future capital expenditure programs are to safeguard its ability to meet
its financial obligations, to maintain a flexible capital structure that allows financing options when a financing need arises and to optimize its use of
short-term and long-term debt and equity at an appropriate level of risk. The company manages its capital structure and follows a financial strategy
that considers economic and industry conditions, the risk characteristics and long-term nature of its underlying assets and its growth opportunities. It
strives to continuously improve its credit rating and reduce its cost of capital.
The company reported the following debt outstanding:
($000) December 31, 2011 December 31, 2010
Convertible Debentures, 4.75%, due June 30, 2012 $ 98,564 $ 96,548
First Lien Senior Notes, 11.75%, due July 15, 2014 - 184,176
Second Lien Senior Notes, 10.25%, due December 15, 2015 3,470 566,663
Second Lien Senior Notes, 8.75%, due August 1, 2018 343,138 -
Second Lien Senior Notes, 8.5%, due August 1, 2019 512,930 -
Total $ 958,102 $ 847,387
CONVERTIBLE DEBENTURES
It is the present intention of the company to redeem the 4.75% $100 million Convertible Debentures when due on June 30, 2012.

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NEW NOTES
We issued US$550 million face value 8.5% Senior Secured Second Lien Notes due August 1, 2019 and CAD$350 million face value 8.75% Senior
Secured Second Lien Notes due August 1, 2018 at par and capitalized transaction costs of $17.6 million relating to their issuance.
Interest is payable semi-annually on February 1 and August 1 each year the New Notes are outstanding. The New Notes are secured on a second
priority basis by liens on all of the company’s existing and future property, excluding certain pipeline assets in the USA.
Proceeds received from the sale of collateralized assets (excluding oil and gas properties for which no reserves have been assigned) are required to
be re-invested in existing oil and gas properties, to acquire new oil and gas properties or to repay the Facility. If such proceeds are not used for these
purposes within one year, the company is required to make an offer to repurchase the New Notes at par to the extent such proceeds exceed $25
million plus any re-invested and repaid amounts. Following an offer to purchase the New Notes in connection with an asset sale, the company may
redeem all or part of the US-dollar denominated New Notes at 108.5 percent and Canadian-dollar denominated New Notes at 108.75 percent with
any remaining asset sale proceeds. As of December 31, 2011, all asset sale proceeds have been re-invested in our oil and gas properties.
Provisions in the indenture allow the company to redeem the New Notes as follows:
• at any time prior to August 1, 2014, the company may redeem up to 35 percent of the US-dollar denominated New Notes at a price of 108.5
percent and up to 35 percent of the Canadian-dollar denominated New Notes at the price of 108.75 percent with proceeds of equity offerings of
at least $10 million;
• at any time prior to August 1, 2015, the company may redeem some or all of the New Notes at their principal amount plus a make whole premium
plus applicable interest;
• after August 1, 2015, the US-dollar denominated New Notes may be redeemed at redemption prices ranging from 104.25 percent, reducing to
100 percent on August 1, 2017 and thereafter; and
• after August 1, 2015, the Canadian–dollar denominated New Notes may be redeemed at redemption prices ranging from 104.375 percent
reducing to 100 percent on August 1, 2017 and thereafter.
In the event of a Change of Control of the company, the holders of the New Notes have the right to require the company to purchase the New Notes
at a price of not less than 101 percent of the principal amount to be repurchased.
The company repurchased US$783.5 million face value of the outstanding 11 ¾% First Lien Senior Notes and 10 ¼% Second Lien Senior Notes
(the “Old Notes”) (representing 99% of the Old Notes outstanding) for cash consideration of US$854.7 million (CAD$835.9 million). The company
determined that this transaction resulted partially in a modification and partially as an extinguishment of debt. Accordingly, the company recorded
$36.1 million as a discount on the New Notes and approximately $61.9 million was expensed in the consolidated statement of operations. The
repayment of US-dollar denominated Senior Notes in 2011 also resulted in the realization of a foreign exchange gain of $11.6 million.
The company redeemed remaining amounts outstanding relating to the Second Lien Senior Notes, 10 ¼% in January 2012.
CREDIT FACILITY
On May 31, 2011, the company entered into an Amended and Restated Senior Secured Revolving Credit Facility. The Facility provides for revolving
credit financing of up to $100 million, subject to borrowing base availability, including sub-facilities for letters of credit, swingline loans and borrowings
in Canadian dollars and U.S. dollars. The Facility has an accordian feature whereby the Company can increase the Facility to $125 million. All
outstanding loans under the new Facility are due and payable in full on May 31, 2014.
In the case of Canadian dollar drawings, borrowings under the new Facility bear interest at a rate per annum equal to the Canadian Prime Rate plus the
applicable margin; in the case of US dollar drawings at US Base Rate plus the applicable margin. The applicable margins for borrowings under the new
Facility are subject to steps up and steps down based on average ratings of the company’s debt as published by Moody’s and Standard and Poors.
In addition to paying interest on outstanding principal under the new Facility, the company is required to pay a standby fee in respect of the unutilized
commitments thereunder, which fee will be determined based on utilization of the new Facility with rates established in the Facility in a similar manner
to the interest margins. The company must also pay customary letter of credit fees equal to the applicable margin. As of December 31, 2011, the
Company’s interest rate on the new Facility was approximately 6.5%. The new Facility contains a requirement to maintain a ratio of consolidated total
debt to total capitalization of under 75% (with convertible debt treated as equity and with up to $120 million added to equity for IFRS conversion
adjustments) and borrowings under the new Facility cannot exceed two times trailing adjusted EBITDA.
All obligations under the new Facility are unconditionally guaranteed by the company, are secured by substantially all of the assets of the company,
including a first priority security interest on all current and future property, with the exception of certain pipeline assets in the USA.
As of December 31, 2011, the company had letters of credit outstanding under the Facility of $2.2 million. No other amounts were owed under
the Facility.

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Connacher’s capital structure and certain financial ratios are noted below:
($000) December 31, 2011 December 31, 2010
Long-term debt (1) $ 856,068 $ 847,387
Shareholders’ equity 421,076 523,187
Total Long-term debt plus Equity (“capitalization”) $ 1,277,144 $ 1,370,574
Long-term debt to capitalization (2) 67% 62%
(1) Long-term debt is stated at its carrying value, which is net of transaction costs including current portion.
(2) Calculated as long-term debt divided by the book value of shareholders’ equity plus long-term debt.
The long-term debt agreements contain certain provisions, which restrict the company’s ability to incur additional indebtedness, pay dividends, to
make certain payments and to dispose of collateralized assets. At December 31, 2011, the company was in compliance with all of the terms of its
debt agreements.
SHARES OUTSTANDING
As at December 31, 2011, the number of common shares issued and outstanding was 448.3 million (December 31, 2010 – 447.2 million). The
increase in 2011 was due to shares issued in respect of share option exercises and shares issued under share incentive awards plan.
As at March 15, 2012, the company had the following securities issued and outstanding.
• 448,575,641 common shares;
• 24,416,150 stock options under the company’s Stock Option Plan;
• 494,190 share units under the Share Award Incentive Plan; and
• 470,124 share units under the Share Unit Plan.
CONTRACTUAL OBLIGATIONS AND COMMITMENTS
In the normal course of business, the company is obligated to make future payments. These obligations represent contracts and other commitments
that are known and non-cancellable. The company is committed under its operating leases for office premises, vehicles and rail cars. The company is
also obligated to make certain payments under its software license agreements, facility and equipment maintenance arrangements and long term debt
indentures are as follows:
As at December 31, 2011
2012 1-3 years 4-6 years Thereafter Total
($000)
Operating leases (1) $ 5,284 $ 17,015 $ 4,742 $ - $ 27,041
Other commitments (2) 8,487 18,129 4,855 14,400 45,871
Long-term debt at face value including interest (3) 180,559 234,509 774,049 367,865 1,556,982
Defined benefit plan contributions 1,530 - - - 1,530
Total $ 195,860 $ 269,656 $ 783,643 $ 382,265 $ 1,631,424
(1) Includes rent of office space and lease rentals for vehicles and rail cars.
(2) Primarily relates to power infrastructure cost.
(3) Includes future interest payments.
The above table excludes ongoing crude oil and product purchase commitments of the Refinery, which are in the normal course of business and are
contracted at market prices.
OFF BALANCE SHEET ITEMS
At December 31, 2011 and December 31, 2010, the company did not have any off‐balance sheet arrangements other than letters of credit
outstanding under the Facility of $2.2 million (December 31, 2010: $5.7 million).
TRANSACTIONS WITH RELATED PARTIES
The company had transactions with its related parties which include Petrolifera, a previously associated company and key management personnel.
Associate
Connacher provided certain general and administrative services to Petrolifera and received approximately $45,000 as fees in 2011 (2010: $180,000).
Petrolifera also reimbursed Connacher for certain other out–of–pocket expenses incurred by Connacher on Petrolifera’s behalf. In addition, the company
rented a portion of its office building to Petrolifera on sublease. The company recovered rental expenses of $30,000 in 2011 (2010 : $137,000).
The service and sublease agreements were terminated in March 2011.

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Compensation of key management personnel
Key management personnel include directors and executive officers of Connacher. The compensation paid or payable to key management for services
is shown below:
For the year ended December 31
2011 2010
(Canadian dollar in thousands)
Short–term employee benefits $ 4,309 $ 4,353
Post–employment benefits 197 229
Termination benefits - 312
Other long–term benefits 96 103
Share–based payments 1,217 2,031
$ 5,819 $ 7,028
The company has management contracts with executive officers that require the company to pay a lump sum payment in case of loss of employment
under certain circumstances as prescribed in these contracts. Subsequent to December 31, 2011, the company paid approximately $5.5 million
under these contracts as compensation for loss of employment.
RISK FACTORS AND RISK MANAGEMENT
GENERAL
Connacher is engaged in the oil and gas exploration, development, production, and refining industry. The business is inherently risky and there is no
assurance that hydrocarbon reserves will be discovered and economically produced. Operational risks include competition, reservoir performance
uncertainties, environmental factors and regulatory and safety concerns. Financial risks associated with the petroleum industry include fluctuations in
commodity prices, interest rates, currency exchange rates and the cost of goods and services.
Connacher’s financial and operating performance is potentially affected by a number of factors including, but not limited to, risks associated with the
production and refining of oil and gas, commodity prices and exchange rates, environmental legislation, changes to royalty and income tax legislation,
credit and capital market conditions, credit risk for failure of performance of third parties and other risks and uncertainties described in more detail in
Connacher’s Annual Information Form filed with securities regulatory authorities.
Connacher employs highly qualified people, uses sound operating and business practices and evaluates all potential and existing wells using the latest
applicable technology. The company complies with government regulations and has in place an up-to-date emergency response program. Connacher
adheres to environment and safety policies and standards. Decommissioning liabilities are recognized upon acquisition, construction and development
of the assets. Connacher maintains property and liability insurance coverage. The coverage provides a reasonable amount of protection from risk of
loss; however, not all risks are foreseeable or insurable.
COMMODITY PRICE AND EXCHANGE RATE RISKS
Connacher’s future financial performance remains closely linked to crude oil, natural gas and refined product prices and foreign exchange rate
changes which may be influenced by many factors including global and regional supply and demand, seasonality, political events and weather. These
factors can cause a high degree of price volatility. We mitigate some of the risk associated with changes in commodity prices through the use of
hedges and other derivative financial instruments.
Dilbit, crude oil, diluent, and refined products purchase and sale prices are based on U.S. dollar benchmarks that result in our realized prices being
influenced by the US:Canadian dollar exchange rate, thereby creating another element of uncertainty. Should the Canadian dollar strengthen compared
to the U.S dollar, the resulting negative effect on revenue, including the translation of MRCI’s U.S. denominated results to Canadian dollars for financial
reporting purposes would be partially offset with exchange gains on translating our U.S. dollar denominated debt and associated interest payments
thereon. The opposite would occur should the Canadian dollar weaken compared to the U.S. dollar. See “Liquidity” and “Capital Resources” above.
REGULATORY APPROVAL RISKS
Before proceeding with most major development projects, Connacher must obtain regulatory approvals, which approvals must be maintained in
good standing during the currency of the particular project. The regulatory approval process involves stakeholder consultation, environmental impact
assessments and public hearings, among other factors. Failure to obtain regulatory approvals, or failure to obtain them on a timely basis, could
result in delays, abandonment, or restructuring of projects and increased costs, all of which could negatively impact future earnings and cash flow.
Failure to maintain approvals, licenses, permits and authorizations in good standing could result in the imposition of fines, production limitations or
suspension orders.

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PERFORMANCE
Our financial and operating performance is potentially affected by a number of factors, including, but not limited to the following:
• Our ability to reliably operate our conventional and oil sands facilities and our refinery is important in meeting production targets.
• Operating costs could be impacted by inflationary pressures on labor, volatile pricing for natural gas used as an energy source in oil sands
processes and planned and unplanned maintenance. We continue to address these risks though such strategies as application of technologies and
an increased focus on regular preventative maintenance. The Refinery is in its final year of operation prior to the scheduled turnaround in 2013.
• While fiscal regimes in Alberta, Canada and the USA are generally stable relative to many global jurisdictions, royalty and tax treatments are
subject to periodic review, the outcome of which is not predictable and could result in changes to the company’s planned investments and rates of
return on existing investments.
• Management expects that fluctuations in demand and supply for refined products, margin and price volatility, market competition and the seasonal
demand fluctuations for some of our refined products will continue to impact our refining business.
• There are certain risks associated with the execution of capital projects, including the risk of cost overruns and delays. Numerous risks and
uncertainties can affect construction schedules, including the availability of labor and other impacts of competing projects drawing on the same
resources during the same time period.
CAPITAL REQUIREMENTS
The company anticipates making substantial capital expenditures for the acquisition, exploration, development and production of bitumen and crude oil
reserves and refining in the future. As the company’s revenues may decline as a result of decreased commodity pricing, it may be required to reduce
capital expenditures. In addition, uncertain levels of near term industry activity coupled with the global economic situation exposes the company
to additional access to capital risk. There can be no assurance that debt or equity financing, or cash generated by operations will be available or
sufficient to meet these requirements or for other corporate purposes or, if debt or equity financing is available, that it will be on terms acceptable
to the company. The inability of the company to access sufficient capital for its operations and growth could have a material adverse effect on the
company’s business financial condition, results of operations and prospects.
THIRD PARTY CREDIT RISK
Credit risk is a risk of failure of performance by counter-parties. We attempt to mitigate this credit risk before contract initiation and ensuring product
sales and delivery contracts are made with well-known and financially strong crude oil and natural gas marketers. The company may be exposed to third
party credit risk through its contractual arrangements with its current counter-parties. In the event such entities fail to meet their contractual obligations
to the company, such failures may have a material adverse effect on the company’s business, financial condition, results of operations and prospects.
ENVIRONMENTAL
All phases of the oil and gas and refining business present environmental risks and hazards and are subject to environmental regulation pursuant
to a variety of federal, provincial, state and local laws and regulations. Compliance with such legislation can require significant expenditures and
a breach may result in the imposition of fines and penalties, some of which may be material. Environmental legislation is evolving in a manner
expected to result in stricter standards and enforcement, larger fines and liability and potentially increased capital expenditures and operating costs.
There has been much public debate with respect to Canada’s alternative strategies with respect to climate change and the control of greenhouse
gases. Implementation of strategies for reducing greenhouse gases could have a material impact on the nature of oil, gas and refining operations,
including those of the company. Given the evolving nature of the issues related to climate change and the control of greenhouse gases and
resulting requirements, it is not possible to predict either the nature of those requirements or the impact on the company and its operations and
financial condition. The company may be subject to remedial environmental and litigation costs resulting from potential unknown and unforeseeable
environmental impacts arising from the company’s operations. While these costs have not been material to the company in the past, there is no
guarantee that this will continue to be the case in the future as the company carries on with development of technologies.
At our Refinery, we now make ultra-low sulphur diesel and gasoline. We are also mandated to remove benzene from our refined gasoline commencing
in 2011. This project is ongoing however we were required to purchase benzene credits in 2011 and will continue to do so until commissioning of the
project. Thereafter, our benzene purchase requirements will be reduced but not 100 percent mitigated. Our upstream and downstream businesses are
closely regulated with respect to land disturbance, water usage and green house gas emission. To meet these requirements, our operations personnel
closely follow established environmental policies and procedures and regularly report to regulators. The quality of these reports has been affirmed by
recent audits.

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ACCOUNTING POLICIES AND ESTIMATES
ADOPTION OF INTERNATIONAL FINANCIAL REPORTING STANDARDS
On January 1, 2011, the company adopted International Financial Reporting Standards (“IFRS”) for financial reporting purposes, using a transition
date of January 1, 2010. The financial statements for the year ended December 31, 2011, including required comparative information, have been
prepared in accordance with International Financial Reporting Standards 1, First-time Adoption of International Financial Reporting Standards.
The following provides a summary reconciliation of Connacher’s 2010 net loss before taxes calculated in accordance with previous GAAP and
Connacher’s 2010 net loss after taxes calculated in accordance with IFRS, along with a discussion of the significant IFRS accounting policy changes.
Summary Net Loss Reconciliation
(Canadian dollar in thousands) YTD 2010
Net loss per previous GAAP $ (38,798)
Exploration and evaluation expense (964)
Depletion, depreciation, amortization and impairment 1,305
Disposition of oil and gas properties (5,287)
Compensation 44
Unwinding of discount on decommissioning liabilities 812
Interest in associate 3,140
Unrealized loss on revaluation of Convertible Debentures (228)
Income taxes (4,693)
Net loss per IFRS $ (44,669)
ACCOUNTING POLICY CHANGES
The following discussion explains the significant differences between Connacher’s previous GAAP accounting policies and those applied by the
company under IFRS. IFRS policies have been retrospectively and consistently applied except where specific IFRS 1 optional and mandatory
exemptions permitted an alternative treatment upon transition to IFRS for first-time adopters. IFRS 1 requires the presentation of comparative
information as at the January 1, 2010 (“transition date”) and subsequent comparative periods as well as the consistent and retrospective application
of IFRS accounting policies. To assist with the transition, the provisions of IFRS 1 allow for certain mandatory exceptions and optional exemptions
for first-time adopters. The significant mandatory exceptions and optional exemptions applied under IFRS 1 in preparing the consolidated financial
statements are set out below followed by a discussion regarding the impact of individually significant items.
Deemed cost election for oil and gas properties
Under previous GAAP, the company followed the “full cost” method of accounting for petroleum and natural gas activities under which all costs directly
associated with the acquisition of, the exploration for, and the development of petroleum and natural gas reserves were capitalized on a country–
by–country cost centre basis. The company had one cost centre, Canada, for the upstream segment. Costs accumulated within this one cost centre
were depleted using the unit–of–production method based on proved reserves determined using estimated future prices and costs. Upon transition
to IFRS, the company was required to adopt new accounting policies for upstream activities, including the segregation of exploration and evaluation
costs and petroleum and natural gas properties. Under IFRS, exploration and evaluation costs are those expenditures for which technical feasibility
and commercial viability has not yet been determined, are presented separately on the balance sheet as exploration and evaluation assets and may
or may not be amortized based on the company’s accounting policy. Petroleum and natural gas properties include those expenditures where technical
feasibility and commercial viability has been determined, are presented as a part of property, plant and equipment on the balance sheet and are
depleted and depreciated on a segregated basis based on the company’s accounting policy. The company adopted the IFRS 1 exemption whereby the
company deemed its January 1, 2010 IFRS upstream asset costs to be equal to its previous GAAP historical upstream property, plant and equipment
net book value. Accordingly, exploration and evaluation costs were deemed equal to the unproved properties balance and the petroleum and natural
gas properties costs were deemed equal to the remaining upstream full cost pool balance. The petroleum and natural gas property costs were
allocated for depletion, depreciation and impairment testing purposes on a pro rata basis using proved reserves values at the transition date.
Leases
The company has elected not to reassess whether an arrangement contains a lease under International Financial Reporting Interpretations Committee
Interpretation 4 for contracts that were assessed under previous GAAP.
Business Combinations
IFRS 3, “Business Combinations” has not been applied to business combinations that occurred before the transition date.
Borrowing Costs
Borrowing costs directly attributable to the acquisition or construction of qualifying assets were not retrospectively restated prior to transition date.

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Estimates
Hindsight was not used to create or revise estimates and accordingly, the estimates made by the company under previous GAAP are consistent with
their application under IFRS.
Additional exemptions applied
The company applied additional exemptions for cumulative foreign currency translation differences, share-based compensation, decommissioning
liabilities and accounting for investment in associate, which are explained in the respective paragraphs below.
Exploration and Evaluation
As explained above under “Deemed cost election for oil and gas properties”, the company reclassified $96.2 million and $120.8 million to exploration
and evaluation assets at January 1, 2010 and December 31, 2010, respectively, based on the deemed carrying amounts representing unproved
properties balance as determined under previous GAAP.
Additionally, under IFRS, costs incurred prior to obtaining the legal rights to explore are expensed whereas under previous GAAP these costs were
capitalized as part of property, plant and equipment. Accordingly, the company recognized exploration and evaluation expense in net earnings (loss)
of $964,000 in the year ended December 31, 2010 and recorded the corresponding decrease to the property, plant and equipment. This adjustment
also resulted in an equivalent decrease in cash flow from operating activities under IFRS compared to the reported amounts under previous GAAP.
The effect of the above adjustment on deficit was a reduction of $722,000 after tax benefits of $242,000 for the year ended December 31, 2010.
Depletion, Depreciation and Amortization
Under previous GAAP, petroleum and natural gas properties were depleted using the unit-of-production method calculated for each one Canada cost
centre. Under IFRS, petroleum and natural gas properties are depleted using the unit-of-production method based on estimated proved and probable
reserves determined using estimated future prices and costs calculated at the established area level. Further, as permitted under IFRS, the company
elected to amortize certain exploration and evaluation assets (undeveloped land) over the lease term. Under previous GAAP, undeveloped land was
tested for impairment and any resulting impairment was included in the full cost pool for depletion purposes. As a result, depletion, depreciation and
amortization expense decreased by $1.3 million in the year ended December 31, 2010, with a corresponding increase to exploration and evaluation
assets and property, plant and equipment.
The effect of the above adjustment on deficit was a decrease of $1.0 million after tax benefits of $0.3 million for the year ended December 31, 2010.
Impairment
Under previous GAAP, capitalized costs of petroleum and natural gas properties and goodwill were tested for impairment separately whereas
under IFRS, capitalized costs of petroleum and natural gas properties and goodwill are allocated to cash-generating units (“CGU’s”) for impairment
testing purposes.
Under previous GAAP, impairment of petroleum and natural gas properties was recognized if their carrying amount exceeded the undiscounted cash
flows from proved reserves for a country cost centre. Impairment was measured as the amount by which the carrying amount exceeded the sum of
the fair value of the proved and probable reserves and the costs of unproved properties. The company did not report any impairment under previous
GAAP on December 31, 2009 and 2010.
Under previous GAAP, goodwill was tested with reference to the reporting unit. The company had allocated goodwill to the upstream reporting unit
and goodwill was not considered impaired. Under IFRS, impairment is recognized if the carrying amount for a CGU exceeds the recoverable amount.
A CGU is defined as the smallest identifiable group of assets that generates cash inflows that are largely independent of the cash inflows from other
assets or groups of assets. On the transition date, the company performed an impairment test by allocating all capitalized costs of petroleum and
natural gas properties, goodwill and directly related liabilities to applicable cash-generating units based on their ability to generate largely independent
cash flows (a lower level than previous GAAP) and determined that an impairment charge of $113.9 million on January 1, 2010 was required. Of the
total impairment charge, $103.7 million was allocated to goodwill and $10.2 million was allocated to petroleum and natural gas properties, with the
corresponding increase to deficit of $111.3 million, net of a tax benefit of $2.6 million.
Asset and Liabilities Held For Sale and Disposition of Oil and Gas Properties
Under previous GAAP, the proceeds from disposition of petroleum and natural gas properties were deducted from the full cost pool without
recognition of a gain or loss and the accounting standard for classification of assets and liabilities as held for sale was not applicable to the disposition
of petroleum and natural gas properties, unless the impact of the disposition was expected to result in a change to the depletion, depreciation and
amortization rate of 20 percent or greater, in which case a gain or loss was recorded and assets and liabilities were classified as held for sale.
Under IFRS, gains or losses are recorded on dispositions and are calculated as the difference between the proceeds and the net book value of the asset
disposed of, and the requirements of the classification of assets and liabilities as held for sale are applicable to all petroleum and natural gas properties.

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The company classified its assets and liabilities relating to certain petroleum and natural gas properties as held for sale on December 31, 2010 and
recorded them at lower of their carrying amount or fair value less costs to sell. The adjustment resulted in a reclassification of carrying amount of
property, plant and equipment totaling $54.3 million, exploration and evaluation assets totaling $5.7 million and decommissioning liability totaling
$10.9 million to assets and liabilities classified as held for sale. At December 31, 2010, an impairment charge of $4.5 million was recognized based
on the difference between the December 31, 2010 carrying amounts of the assets prior to reclassification and the estimated recoverable amount.
The recoverable amount was determined using fair value less costs to sell which was based on the sale price subsequently agreed to binding sale
agreements with third parties.
During the year ended December 31, 2010, the company recognized a loss of $0.8 million on the sale of minor petroleum and natural gas properties
and exploration and evaluation assets.
The effect of the above adjustments on deficit was a reduction of $3.9 million after tax benefits of $1.3 million for the year ended December 31, 2010.
Foreign Currency
In accordance with IFRS 1, the company has elected to deem all foreign currency translation differences that arose prior to the transition date in
respect of foreign operations and the company’s share of associate’s translation differences to be nil and reclassified amounts recorded in other
comprehensive loss as determined in accordance with previous GAAP to deficit. As a result, accumulated other comprehensive loss was decreased by
$16.2 million with a corresponding increase to deficit as at January 1, 2010.
Compensation – Defined Benefit Plan
The company elected to use the IFRS 1 exemption whereby the cumulative unamortized net actuarial gains and losses of the company’s defined
benefit plan were charged to deficit on January 1, 2010. This resulted in a decrease of $722,000 to the accrued benefit obligation and a
corresponding decrease to deficit.
Decommissioning liabilities
Under previous GAAP, the asset retirement obligation was measured at the estimated fair value determined using estimated future cash outflows
discounted using a credit-adjusted risk free interest rate and the liability was not remeasured to reflect period end discount rates. Under IFRS, the
asset retirement obligation has been named “decommissioning liabilities”, fair value is measured as the best estimate of the future expenditure to be
incurred discounted at a risk free interest rate, decommissioning liabilities are remeasured using the period end discount rate.
In conjunction with the IFRS 1 exemption regarding petroleum and natural gas properties discussed above, the company was required to remeasure
its decommissioning liabilities upon transition to IFRS and recognize the difference in deficit. The application of this exemption resulted in a $20.9
million increase to decommissioning liabilities on the company’s consolidated balance sheet as at January 1, 2010 and a charge to deficit of $15.6
million net of tax benefit of $5.2 million. Subsequent IFRS remeasurements of decommissioning liabilities are recorded through property, plant and
equipment with an offsetting adjustment to decommissioning liabilities. As at December 31, 2010, excluding the January 1, 2010 adjustment, the
company’s decommissioning liabilities increased by $10.9 million which primarily reflects the remeasurement of the obligation using the company’s
discount rate of 3.2 percent as at December 31, 2010. The use of the lower discount rate resulted in a decrease in the provision for unwinding of the
discount totaling $812,000 for the year ended December 31, 2010.
Investment in Associate
As at January 1, 2010 and December 31, 2010, the company owned 26.9 million Petrolifera common shares, representing 22 percent and 18.5
percent, respectively, of Petrolifera’s issued and outstanding common shares and 6.8 million Petrolifera share purchase warrants. Petrolifera was
accounted for as an equity investment in associate. The following are the key differences in IFRS compared to previous GAAP.
• As a part of the company’s transition to IFRS, the company recorded adjustments to its share of loss, other comprehensive loss and dilution loss
with a corresponding effect on the investment account balance and deficit reflecting the adjustments to conform Petrolifera’s financial position and
results of operations in accordance with IFRS and the accounting policies adopted by the company on its transition date.
• Under previous GAAP, the company did not record the investment in share purchase warrants separately and allocated the total cost of $11.9
million for additional shares purchased in 2009 to an investment in equity-accounted for investment on the consolidated balance sheet whereas
under IFRS, share purchase warrants meet the definition of a derivative asset that should be bifurcated from the host contract (investment in
associate) and recorded at fair value on each reporting period end with changes recorded in net earnings (loss). As a result, the company recorded
the fair value of share purchase warrants on January 1, 2010 by increasing other assets and decreasing deficit. In addition, the company recorded
an unrealized loss of $2.2 million in 2010 representing the change in fair value of this derivative financial asset.
• Under IFRS, assets relating to the investment in Petrolifera were classified as assets held for sale on December 31, 2010. Equity accounting
ceased on December 31, 2010 and the carrying amount of the investment in associate was classified as assets held for sale and recorded at
the lower of its carrying amount and fair value less costs to sell. Under previous GAAP, the accounting standard for classification of assets and
liabilities as held for sale was not applicable to the disposition of investment in associate and accordingly, no classification of assets held for sale
was reported. However, under previous GAAP, the company recognized impairment to record the investment at its fair value.

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Taxes
The company recorded the differences to the amounts reported for deferred taxes under previous GAAP compared to IFRS for flow-through shares,
discount on issue of long-term debt, capitalized share-based compensation, inter-company capital losses and the effects of IFRS transition adjustments.
Debt
Under previous GAAP, the convertible debentures were treated as a compound financial instrument with a debt and equity component. Under IFRS, the
equity component is considered an embedded derivative. As permitted under IFRS, the company designated the convertible debentures as “fair value through
profit and loss” and accordingly, recorded convertible debentures at fair value at each reporting period end with changes reported within net earnings (loss).
As a result, the equity portion of convertible debentures was reduced by $16.8 million with a corresponding decrease to deficit on January 1, 2010 and
December 31, 2010. In addition, the company recognized the effect of change in fair value by increasing the value of the convertible debentures by $3.6
million on January 1, 2010 with a corresponding increase to deficit. The adjustment also resulted in an increase of finance charges in 2010.
Reclassifications
In order to comply with the presentation of net earnings (loss) adopted by the company under IFRS, in the downstream segment, the company
classified $3.9 million from operating expenses to general and administrative expenses in 2010.
Further, under previous GAAP, the unwinding of the discount on decommissioning liabilities was included as a part of depletion, depreciation and
accretion expense in the consolidated statements of operations and comprehensive loss. Under IFRS this amount totaling $2.9 million in 2010 has
been reclassified to finance charges.
Changes to the Statement of Cash flow
The following is a reconciliation of the company’s cash flow from operating, investing and financing activities reported in accordance with previous
GAAP to IFRS for the year ended December 31, 2010:
(Canadian dollar in thousands)
Year ended December
31, 2010
Cash flow from operating activities under previous GAAP $ 10,785
Exploration and evaluation expenses (964)
Interest expense on long-term debt 55,637
Change in working capital relating to interest expense on long-term debt 974
Cash flow from operating activities under IFRS $ 66,432
Cash flow used in investing activities under previous GAAP $ (269,763)
Exploration and evaluation expenses 964
Interest capitalized on long-term debt 35,408
Cash flow used in investing activities under IFRS (233,391)
Cash flow from financing activities under previous GAAP $ 25,793
Interest expense paid (92,019)
Cash flow used in financing activities under IFRS $ (66,226)
Under previous GAAP, interest paid on long-term debt was reported as a part of operating activities. During Q4 2011, as permissible under under
IFRS, the company elected to present interest payments on long-term debt as financing activities.
Loss per share
Basic and diluted loss per share under IFRS were impacted by the IFRS adjustments discussed above.
CRITICAL ACCOUNTING ESTIMATES
We make judgments, estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets
and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period.
Although these estimates are based on management’s best knowledge of the amount, event or actions, actual results ultimately may differ from those
estimates. Accordingly, actual reported amounts may differ from estimated amounts as future confirming events occur.
Estimation of petroleum and natural gas reserves
Petroleum and natural gas reserve estimates are used in the unit–of–production depletion and depreciation calculation, determination of the timing
of abandonment costs and impairment analysis of upstream assets. The company’s proved plus probable reserves are estimated with reference
to available geological, geophysical and engineering data. Estimates of petroleum and natural gas reserves are inherently imprecise, require the
application of judgment and are subject to regular revision, either upward or downward, based on new information.

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Management is responsible for estimating the quantities of petroleum and natural gas reserves. Estimates are prepared in accordance with National
Instrument 51-101, generally accepted industry practices and the standards of the Canadian Oil and Gas Evaluation Handbook. On an annual basis,
we have an independent reserves evaluation completed. GLJ Petroleum Consultants performed the annual evaluation effective December 31, 2011.
The Board of Directors has established a Reserves Committee to assist them in overseeing the annual review of our petroleum and natural gas
reserves. The Reserves Committee comprises two independent Directors and meets with management periodically to review the reserves process and
results. The Reserves Committee appoints and meets with the independent reserve evaluation independent of management, to review the scope of
their work, whether they have had access to sufficient information, the nature and satisfactory resolution of any material differences of opinion, and
their independence.
Changes to estimates of petroleum and natural gas reserves affect prospectively the amounts of depletion, depreciation, amortization and impairment
charged and, consequently, the carrying amounts of petroleum and natural gas properties and exploration and evaluation assets. The impact of future
changes to estimates on the consolidated financial statements of subsequent periods could be material.
Impairment of assets
For the purposes of impairment analysis of the company’s assets, the key assumptions used in estimating cash flows are future commodity prices,
expected production volumes and refinery throughput, cost structures and the outlook of market supply and demand conditions appropriate to the
local circumstances and environment. These assumptions and estimates are highly uncertain matters and are subject to change as new information
becomes available. Changes in economic conditions can also affect the rate used to discount future cash flow estimates.
Changes in assumptions could affect the carrying amounts of assets, and impairment charges and reversals will affect net earnings (loss).
Decommissioning liabilities
Provisions are recognized for the future abandonment and reclamation of petroleum, natural gas and refining properties at the end of their economic
lives. The estimated cost is recognized in net earnings (loss) over the life of the reserves on a unit–of–production basis. Changes in the estimates
of costs to be incurred, reserves or in the rate of production will therefore affect net earnings (loss), generally over the remaining economic life of
petroleum and natural gas assets.
Estimates of the amounts of decommissioning provisions recognized are based on current legal and constructive requirements, technology and price
levels. Because actual outflows can differ from estimates due to changes in laws, regulations, public expectations, technology, industry standards,
prices and conditions, and can take place many years in the future, the carrying amounts of such provisions are regularly reviewed and adjusted to
take account of such changes. The interest rate used to discount the cash flows is reviewed quarterly.
Legal and other contingent matters
In respect of these matters, the company is required to determine whether a loss is probable based on judgment and interpretation of laws and
regulations and determine if such a loss can be estimated. When any such loss is determined, it is charged to earnings. Management continually
monitors known and potential contingent matters and makes appropriate provisions by charges to earnings when warranted by circumstance.
Taxation
Tax provisions are recognized when it is considered probable that there will be a future outflow of funds to a taxing authority. In such cases, provision
is made for the amount that is expected to be settled, where this can be reasonably estimated. This requires the application of judgment as to the
ultimate outcome, which can change over time depending on facts and circumstances. A change in estimate of the likelihood of a future outflow and/
or in the expected amount to be settled would be recognized in net earnings (loss) in the period in which the change occurs.
Deferred tax assets are recognized only to the extent it is considered probable that those assets will be recoverable. This involves an assessment
of when those deferred tax assets are likely to be realized, and a judgment as to whether or not there will be sufficient taxable profits available to
offset the tax assets when they do reverse. This requires assumptions regarding future profitability and is therefore inherently uncertain. To the extent
assumptions regarding future profitability change, there can be an increase or decrease in the amounts recognized in respect of deferred tax assets
as well as in the amounts recognized in net earnings (loss) in the period in which the change occurs.
Tax provisions are based on enacted or substantively enacted laws. Changes in those laws could affect amounts recognized in net earnings (loss)
both in the period of change, which would include any impact on cumulative provisions, and in future periods.
Derivative financial instruments
We may use derivative financial instruments to manage exposure to market risks relating to commodity prices, foreign currency exchange rates and
interest rates. Derivative financial instruments are not used for speculative purposes. We enter into financial transactions to help reduce exposure
to price fluctuations with respect to commodity purchase and sale transactions to achieve targeted investment returns and growth objectives, while
maintaining prescribed financial metrics. These transactions generally are swaps, collars or options and are generally entered into with major financial
institutions or commodities trading institutions as counterparties. We may also use derivative financial instruments, such as interest rate swap

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agreements, to manage the fixed interest rate debt and related cost of borrowing. Derivative instruments that do not qualify as hedges, or are not
designated as hedges, are recorded using the mark-to-market method of accounting whereby instruments are recorded in the Consolidated Balance
Sheet as either an asset or liability, with changes in fair value recognized in net earnings (loss). Realized gains or losses from financial derivatives related
to crude oil and natural gas prices are recognized in revenues as the related sales occur. Unrealized gains and losses are recognized in revenues at the
end of each reporting period. The estimate of fair value of all derivative instruments is based on quoted market prices or, in their absence, third-party
market indications and forecasts. The estimated fair value of financial assets and liabilities, by their very nature, is subject to measurement uncertainty.
DISCLOSURE CONTROLS AND PROCEDURES
The company’s Chief Executive Officer (“CEO”) and Chief Financial Officer (“CFO”) have designed, or caused to be designed under their supervision,
disclosure controls and procedures to provide reasonable assurance that: (i) material information relating to the company is made known to the
company’s CEO and CFO by others, particularly during the period in which the annual filings are being prepared; and (ii) information required to be
disclosed by the company in its annual filings, interim filings or other reports filed or submitted by it under securities legislation is recorded, processed,
summarized and reported within the time period specified in securities legislation. Such officers have evaluated, or caused to be evaluated under their
supervision, the effectiveness of the company’s disclosure controls and procedures at the financial year end of the company and have concluded that
the company’s disclosure controls and procedures are effective at the financial year end of the company for the foregoing purposes.
INTERNAL CONTROLS OVER FINANCIAL REPORTING
The CEO and CFO have designed, or caused to be designed under their supervision, internal controls over financial reporting to provide reasonable
assurance regarding the reliability of the company’s financial reporting and the preparation of financial statements for external purposes in accordance
with Canadian GAAP. Such officers have evaluated, or caused to be evaluated under their supervision, the effectiveness of the company’s internal
controls over financial reporting at the financial year end of the company and concluded that the company’s internal controls over financial reporting is
effective at the financial year end of the company for the foregoing purpose.
The company’s CEO and CFO are required to cause the company to disclose any change in the company’s internal controls over financial reporting
that occurred during the company’s most recent interim period that has materially affected, or is reasonably likely to materially affect, the company’s
internal controls over financial reporting. No material changes in the company’s internal controls over financial reporting were identified during such
period that has materially affected, or are reasonably likely to materially affect, the company’s internal controls over financial reporting.
It should be noted that a control system, including the company’s disclosure and internal controls and procedures, no matter how well conceived,
can provide only reasonable, but not absolute, assurance that the objectives of the control system will be met and it should not be expected that the
disclosure and internal controls and procedures will prevent all errors or fraud. In reaching a reasonable level of assurance, management necessarily is
required to apply its judgment in evaluating the cost-benefit relationship of possible controls and procedures.
ADVISORY SECTION
FORWARD-LOOKING INFORMATION
This report, including the outlook contained in the MD&A, contains forward-looking information including but not limited to, anticipated future operating and
financial results, expectations of future production, anticipated capital expenditures for 2012, the expected impact of new technologies such as SAGD+
on production and SORs, the use of risk management sales contracts to mitigate market risk relating to commodity prices, foreign currency exchange
rates and interest rates, the possible future redemption of Connacher’s Convertible Debentures, the ability of the Refinery to access new markets upon
completion of the benzene removal project, the scheduled turnaround at the Refinery and oil sands plants, seasonal fluctuations in production and the sale
of gasoline, impact of failing to obtain, a delay in obtaining, or failure to retain necessary approvals and authorizations and future capital projects.
Forward-looking information is based on management’s expectations regarding future growth, results of operations, production, future commodity
prices and foreign exchange rates, future capital and other expenditures (including the amount, nature and sources of funding thereof), plans for and
results of drilling activity, environmental matters, business prospects and opportunities and future economic conditions.
Forward-looking information involves significant known and unknown risks and uncertainties, which could cause actual results to differ materially from
those anticipated. These risks include, but are not limited to operational risks in development, exploration, production and start up activities; delays
or changes in plans with respect to exploration or development projects or capital expenditures; the uncertainty of reserve and resource estimates;
the uncertainty of estimates and projections relating to production, costs and expenses, and health, safety and environmental risks; the risk of
commodity price and foreign exchange rate fluctuations; risks associated with the impact of general economic conditions; sales volumes and risks and
uncertainties associated with securing and maintaining the necessary regulatory approvals and financing to proceed with the continued expansion of
the Great Divide oil sands project.

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The production outlook contained in the MD&A is based on certain assumptions regarding operational performance including, among others, steam
generation levels and SORs, unplanned operational upsets, well productivity, realized netbacks which may accelerate or delay our capital program,
including planned facility optimization programs and future market conditions and is subject to risk and uncertainties, including those risk and
uncertainties described above. Additional risks and uncertainties are described in further detail in Connacher’s Annual Information Form (“AIF”) for the
year ended December 31, 2011 which is available at ww.sedar.com.
Although Connacher believes that the expectations in such forward‐looking information are reasonable, there can be no assurance that such
expectations shall prove to be correct. The forward‐looking information included in this report is expressly qualified in its entirety by this cautionary
statement. The forward‐looking information included in this report is made as of the date of the MD&A and Connacher assumes no obligation to
update or revise any forward‐looking information to reflect new events or circumstances, except as required by law.
Per barrel of oil equivalent (boe) amounts have been calculated using a conversion rate of six thousand cubic feet of natural gas to one barrel of
crude oil (6:1). The conversion is based on an energy equivalency conversion method primarily applicable to the burner tip and does not represent
a value equivalency at the wellhead. Boes may be misleading, particularly if used in isolation. Additionally, given the value ratio based on the current
price of crude oil as compared to natural gas is significantly different from the energy equivalency of 6:1, utilizing a conversion ratio of 6:1 may be
misleading as an indication of value.
NON-GAAP MEASUREMENTS
The MD&A contains terms commonly used in the oil and gas industry, such as, netback, refinery margin, adjusted earnings before interest, taxes,
depreciation and amortization (“adjusted EBITDA”) and cash flow. These terms are not defined by the financial measures used by Connacher to
prepare its financial statements and are referred to herein as non-GAAP measures. These non-GAAP measures should not be considered an
alternative to, or more meaningful than, cash provided by operating activities or net earnings (loss) as determined in accordance with Canadian GAAP
as an indicator of Connacher’s performance. Management believes that in addition to net earnings (loss), netbacks, margins and adjusted EBITDA are
useful financial measurements which assist in demonstrating the company’s ability to make interest payments, fund capital expenditures necessary
for future growth or to repay debt. Connacher’s determination of netbacks, margins, adjusted EBITDA and cash flow may not be comparable to that
reported by other companies.
NETBACKS AND MARGINS
Upstream netbacks, including by product, are calculated by deducting the related diluent, transportation, field operating costs and royalties from upstream
revenues. Downstream margins are calculated by deducting crude oil purchases and operating and transportation costs from refining sales revenues.
ADJUSTED EBITDA
Adjusted EBITDA is calculated as net earnings (loss) before finance charges, current and deferred income tax provisions and recoveries, depletion,
depreciation and amortization, exploration and evaluation expense, share-based compensation, foreign exchange gains/losses, unrealized gains/
losses on risk management contracts, interest and other income, gain (loss) on disposition of assets, defined benefit plan expense, share of interest in
and loss on associate and refinancing of long-term debt.
CASH FLOW
Cash flow includes all cash flows from operating activities and is calculated before changes in non-cash working capital, pension funding,
decommissioning liabilities settled and after interest expense on long-term debt. The most comparable measure calculated in accordance with
Canadian GAAP is cash flow from operating activities. Cash flow from operating activities is reconciled with the cash flow for the three months and
year ended December 31, 2011 and 2010 below.

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RECONCILIATIONS OF NON-GAAP MEASURES
RECONCILIATIONS OF NETBACKS AND ADJUSTED EBITDA TO NET LOSS
(Canadian dollar in thousands) Three months ended December 31 Year ended December 31
2011 2010 2011 2010
Upstream netbacks $ 39,527 $ 32,599 $ 130,520 $ 89,362
Downstream netback 7,645 8,084 41,992 29,067
Realized gain (loss) on risk management
195 (2,140) (9,125) (2,843)
contracts
General and administrative (8,540) (6,553) (34,224) (23,806)
Defined benefit plan expense (recovery) 268 (39) 708 426
Adjusted EBITDA $ 39,095 $ 31,951 $ 129,871 $ 92,206
Interest and other income 380 83 979 256
Defined benefit plan (expense) recovery (268) 39 (708) (426)
Gain on disposition of assets 529 (1,243) 43,457 (811)
Unrealized gain (loss) on risk management
(20,328) (15,868) 11,252 (14,343)
contracts
Share-based compensation (734) (1,184) (3,453) (5,019)
Finance charges (30,994) (25,635) (95,588) (69,445)
Foreign exchange gain (loss) 10,678 26,935 (8,909) 41,641
Depletion, depreciation, amortization and
(53,632) (28,242) (122,009) (79,842)
impairment
Income tax recovery (provision) (4,234) (1,958) 24 8,094
Share of interest in and loss on disposition of
(12) (10,494) (6,840) (16,016)
associate
Exploration and evaluation (expense) recovery 62 - (210) (964)
Refinancing of long-term debt (19) - (61,971) -
Net loss $ (59,477) $ (25,616) $ (114,105) $ (44,669)
RECONCILIATIONS OF CASH FLOW FROM OPERATING ACTIVITIES TO CASH FLOW
(Canadian dollar in thousands) Three months ended December 31 Year ended December 31
2011 2010 2011 2010
Cash flow from operating activities $ 39,206 $ (2,774) $ 142,423 $ 66,432
Changes in non-cash working capital 893 34,178 (14,048) 23,962
Decommissioning liabilities settled (29) 140 1,018 647
Defined pension plan contributions 7 - 504 517
Interest expense on long-term debt (20,812) (22,453) (84,759) (55,637)
Cash flow $ 19,265 $ 9,091 $ 45,138 $ 35,921
CRUDE OIL, NGLs AND NATURAL GAS CONVERSIONS
In this document, certain natural gas volumes have been converted to barrels of oil equivalent (“BOE”) on the basis of one barrel to six thousand cubic
feet. BOE may be misleading, particularly if used in isolation. A conversion ratio of one bbl to six Mcf is based on an energy equivalency conversion
method primarily applicable at the burner tip and does not necessarily represent value equivalency at the well head. Additionally, given the value ratio
based on the current price of crude oil as compared to natural gas is significantly different from the energy equivalency of 6:1, utilizing conversion
ratio of 6:1 may be misleading as an indication of value.

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QUARTERLY HIGHLIGHTS
Fluctuations in results over the previous eight quarters are due principally to variations in oil and gas prices, production and sales volumes and foreign
exchange rates relative to U.S. dollar denominated debt. For comparability, the following table presents the financial information for all of the quarters
presented in the same format as was adopted in the quarter ended December 31, 2011.
FINANCIAL ($000 except per share amounts) 2010 2010 2010 2010 2011 2011 2011 2011
Three Months Ended Mar 31 Jun 30 Sept 30 Dec 31 Mar 31 June 30 Sept 30 Dec 31
Revenue, net of royalties $ 121,095 $ 132,877 $ 158,714 $ 177,245 $ 178,990 $ 234,556 $ 232,806 $ 226,454
Adjusted EBITDA (1) 14,440 20,173 25,642 31,951 15,845 37,608 37,323 39,095
Net earnings (loss) 8,505 (31,717) 4,159 (25,616) (14,101) (44,169) 3,642 (59,477)
Basic and Diluted per share 0.02 (0.07) 0.01 (0.06) (0.03) (0.10) 0.01 (0.13)
Capital expenditures 118,272 59,176 49,842 31,735 40,830 38,988 46,940 36,670
Cash on hand 118,382 69,412 51,120 19,532 42,865 31,525 81,744 117,045
Working capital surplus 127,416 100,202 62,047 138,644 80,902 18,954 50,801 16,876
Long-term debt 856,495 889,797 873,032 847,387 843,089 829,310 865,540 856,068
Shareholders’ equity $ 554,328 $ 530,086 503,251 523,187 $ 515,941 $ 467,057 $ 477,358 $ 421,076
OPERATIONAL
Upstream: Daily production volumes (2)
Bitumen – bbl/d 6,936 6,211 6,758 13,238 13,200 13,720 13,454 13,173
Crude oil – bbl/d 937 906 819 873 540 398 355 417
Natural gas – Mcf/d 9,662 9,278 9,158 8,318 6,805 3,755 3,036 2,955
Equivalent – boe/d (3) 9,483 8,663 9,103 15,498 14,874 14,744 14,315 14,083
Product sales prices (4)
Bitumen – $/bbl 51.98 43.13 42.68 45.08 41.78 54.49 40.98 53.04
Crude oil – $/bbl 71.08 61.90 62.45 66.72 71.70 90.93 80.63 89.57
Natural gas – $/Mcf 4.86 3.78 3.42 3.44 3.57 3.94 4.09 3.27
Selected highlights – $/boe (3)
Weighted average sales price (4) 49.99 41.44 40.74 44.09 41.31 54.15 41.39 52.96
Royalties 3.57 2.73 2.72 2.76 2.15 3.99 2.33 3.24
Operating costs 17.47 19.25 18.08 17.91 21.18 19.23 18.72 19.39
Netback (1) 28.95 19.46 19.94 23.42 17.97 30.93 20.33 30.33
Downstream: Refining
Crude charged – bbl/d 9,347 9,373 9,903 10,137 9,764 9,860 9,638 10,295
Refining utilization – % 98 99 104 107 103 104 101 108
Margins – % (8) 12 13 9 6 10 14 7
COMMON SHARES
Shares outstanding end of period (000) 428,246 429,103 429,120 447,168 447,858 448,058 448,260 448,260
Weighted average shares outstanding for the period
Basic (000) 427,830 429,023 429,106 442,941 448,457 447,992 448,204 448,260
Diluted (000) 430,077 429,023 431,487 442,941 448,457 447,992 449,351 448,260
Volume traded (000) 167,483 182,419 98,105 137,128 180,297 127,468 106,243 214,710
Common share price ($)
High 1.65 1.88 1.52 1.35 1.66 1. 59 1.12 1.00
Low 1.16 1.20 1.15 1.10 1.26 1.03 0.32 0.24
Close (end of period) 1.49 1.29 1.20 1.33 1.43 1.05 0.33 0.76
(1) A non-GAAP measure which is defined in the Advisory section of the MD&A. Reconciliations of Adjusted EBITDA on a quarterly basis are contained in the previously issued MD&A for the applicable quarter.
(2) Represents bitumen, crude oil and natural gas produced in the period. Actual sales volumes may be different due to inventory changes during the period.
(3) All references to barrels of oil equivalent (boe) are calculated on the basis of 6 Mcf: 1 bbl. This conversion is based on an energy equivalency conversion method primarily applicable at the burner tip and dooes
may be misleading, particularly if used in isolation.
(4) Before royalties and risk management contract gains or losses and after applicable diluent and transportation costs divided by actual sales volumes.

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Management’s Report
To the Shareholders of Connacher Oil and Gas Limited:
The consolidated financial statements of Connacher Oil and Gas Limited were prepared by and are the responsibility of management. The
consolidated financial statements have been prepared in conformity with International Financial Reporting Standards appropriate in the circumstances
and include some amounts that are based on managements’ best estimates and judgments. Information contained elsewhere in the annual filing is
consistent, where applicable, with information contained in the consolidated financial statements.
The company maintains systems of internal accounting controls designed to provide reasonable assurance that all transactions are properly recorded
in the company’s books and records, that policies and procedures are adhered to and that the assets are protected from unauthorized use. The
systems of internal accounting controls are complemented by the selection, training and development of qualified staff.
The consolidated financial statements have been audited by the independent accounting firm Deloitte & Touche LLP whose appointment is ratified
annually by the shareholders at the annual shareholders’ meeting. The independent auditors perform such tests and related procedures as they deem
necessary to arrive at an opinion on the fairness of the financial statements. The audit committee of the board of directors periodically meets with
the independent auditors and management to obtain satisfaction that they are properly discharging their responsibilities. The independent auditors
have unrestricted access to the audit committee, without management present, to discuss the results of their examination and the quality of financial
reporting and internal accounting controls.
Signed,
“Peter D. Sametz”
Interim Chief Executive Officer
Signed,
“Brenda G. Hughes”
Chief Financial Officer
March 15, 2012

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Independent Auditor’s Report
To the Shareholders of Connacher Oil and Gas Limited:
We have audited the accompanying consolidated financial statements of Connacher Oil and Gas Limited, which comprise the consolidated balance
sheet as at December 31, 2011, December 31, 2010 and January 1, 2010, and the consolidated statements of operations and comprehensive loss,
consolidated statements of changes in shareholders’ equity and consolidated statements of cash flow for the years ended December 31, 2011 and
2010, and the notes to the consolidated financial statements.
Management’s Responsibility for the Consolidated Financial Statements
Management is responsible for the preparation and fair presentation of these consolidated financial statements in accordance with International
Financial Reporting Standards, and for such internal control as management determines is necessary to enable the preparation of consolidated
financial statements that are free from material misstatement, whether due to fraud or error.
Auditor’s Responsibility
Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance
with Canadian generally accepted auditing standards. Those standards require that we comply with ethical requirements and plan and perform the
audit to obtain reasonable assurance about whether the consolidated financial statements are free from material misstatement.
An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the consolidated financial statements. The
procedures selected depend on the auditor’s judgment, including the assessment of the risks of material misstatement of the consolidated financial
statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the entity’s preparation
and fair presentation of the consolidated financial statements in order to design audit procedures that are appropriate in the circumstances, but not
for the purpose of expressing an opinion on the effectiveness of the entity’s internal control. An audit also includes evaluating the appropriateness of
accounting policies used and the reasonableness of accounting estimates made by management, as well as evaluating the overall presentation of the
consolidated financial statements.
We believe that the audit evidence we have obtained in our audits is sufficient and appropriate to provide a basis for our audit opinion.
Opinion
In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of Connacher Oil and Gas Limited as
at December 31, 2011, December 31, 2010 and January 1, 2010 and its financial performance and its cash flows for the years ended December 31,
2011 and 2010 in accordance with International Financial Reporting Standards.
Signed,
“DELOITTE & TOUCHE LLP”
Chartered Accountants
March 15, 2012
Calgary, Alberta

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Consolidated Balance Sheet
Canadian dollar in thousands
As at Notes December 31, 2011 December 31, 2010 January 1, 2010
ASSETS
CURRENT ASSETS
Cash $ 117,045 $ 19,532 $ 256,787
Trade and accrued receivables 5 62,999 57,419 43,067
Inventories 6 60,146 57,144 36,871
Other assets 7 12,697 17,653 17,774
Assets held for sale 8 – 88,157 –
252,887 239,905 354,499
NON–CURRENT ASSETS
Other assets 7 676 615 3,419
Investment in associate 8 – – 48,240
Exploration and evaluation assets 9 117,429 110,949 96,162
Property, plant and equipment 10 1,234,634 1,217,668 1,123,914
1,352,739 1,329,232 1,271,735
$ 1,605,626 $ 1,569,137 $ 1,626,234
LIABILITIES AND SHAREHOLDERS’ EQUITY
CURRENT LIABILITIES
Trade and accrued payables 11 $ 126,367 $ 81,370 $ 104,804
Risk management contracts 12 7,610 8,984 4,520
Liabilities relating to assets held for sale 8 – 10,907 –
Current portion of long–term debt 13 102,034 – –
236,011 101,261 109,324
NON–CURRENT LIABILITIES
Risk management contracts 12 – 9,879 –
Long–term debt 13 856,068 847,387 879,739
Decommissioning liabilities 14 66,078 60,038 53,729
Retirement benefit obligation 15 415 193 344
Deferred income taxes 16 25,978 27,192 34,501
948,539 944,689 968,313
SHAREHOLDERS’ EQUITY
Share capital 17 620,266 618,628 593,119
Contributed surplus 18 38,841 36,107 31,040
Deficit (233,709) (119,604) (74,935)
Accumulated other comprehensive loss (4,322) (7,452) (627)
Accumulated other comprehensive loss
relating to assets held for sale
8 – (4,492) –
421,076 523,187 548,597
$ 1,605,626 $ 1,569,137 $ 1,626,234
The accompanying notes to the consolidated financial statements are an integral part of these statements.
Approved by the Board:
D.H. Bessell, Director
W.C. Seth, Director

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Consolidated Statements of Operations and
Comprehensive Loss
Canadian dollar in thousands, except per share amounts
For the year ended December 31 Notes 2011 2010
INCOME
Revenue, net of royalties 4 $ 872,806 $ 589,931
Interest and other income 979 256
873,785 590,187
EXPENSES
Blending and costs of products sold 505,585 343,582
Production and operating 131,589 101,148
Transportation and handling 63,120 26,772
General and administrative 34,224 23,806
Share–based compensation 18.4 3,453 5,019
Exploration and evaluation expenses 210 964
Depletion, depreciation, amortization and impairment 122,009 79,842
(Gain) loss on risk management contracts 12 (2,127) 17,186
Finance charges 19 95,588 69,445
Refinancing of long–term debt 13.3 61,971 –
Foreign exchange loss (gain) 20 8,909 (41,641)
(Gain) loss on disposition of assets 21 (43,457) 811
Share of interest in and loss on disposition of associate 8.2 6,840 16,016
987,914 642,950
LOSS BEFORE INCOME TAX (114,129) (52,763)
Income tax recovery 16 24 8,094
NET LOSS (114,105) (44,669)
OTHER COMPREHENSIVE INCOME (LOSS) AFTER TAX
Items recognized in other comprehensive income (loss)
Exchange loss (gain) on translating foreign operations 3,130 (7,452)
Available for sale financial asset 21 (9,080) –
Share of other comprehensive loss of associate 16 – (4,287)
Items reclassified to net earnings (loss)
Available for sale financial asset 21 9,080 –
Share of other comprehensive loss of associate 8.2 4,492 422
OTHER COMPREHENSIVE INCOME (LOSS) AFTER TAX 7,622 (11,317)
TOTAL COMPREHENSIVE LOSS $ (106,483) $ (55,986)
NET LOSS PER SHARE – basic and diluted 17 $ (0.25) $ (0.10)
The accompanying notes to the consolidated financial statements are an integral part of these statements.

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Consolidated Statements of Changes in Shareholders’ Equity
Canadian dollar in thousands
For the year ended December 31
2011 2010
(Canadian dollar in thousands)
SHARE CAPITAL
Balance, beginning of year $ 618,628 $ 593,119
Cash received on flow–through common shares issuance – 23,074
Cash received on exercise of stock options 752 1,936
Transfer from contributed surplus – stock options exercised 423 1,082
Transfer from contributed surplus – share awards settled 534 480
Share issue costs (71) (1,063)
Balance, end of year $ 620,266 $ 618,628
CONTRIBUTED SURPLUS
Balance, beginning of year $ 36,107 $ 31,040
Share–based compensation 3,691 6,629
Transfer to share capital – stock options exercised (423) (1,082)
Transfer to share capital – share awards settled (534) (480)
Balance, end of year $ 38,841 $ 36,107
DEFICIT
Balance, beginning of year $ (119,604) $ (74,935)
Net loss (1) (114,105) (44,669)
Balance, end of year $ (233,709) $ (119,604)
ACCUMULATED OTHER COMPREHENSIVE LOSS
Balance, beginning of year (including classified as held for sale) $ (11,944) $ (627)
Exchange differences on translating foreign operations (1) 3,130 (7,452)
Available for sale financial assets (1) (9,080) –
Share of other comprehensive loss of associate (1) – (4,287)
Amounts reclassified to net earnings (loss) – Available for sale assets (1) 9,080 –
Amounts reclassified to net earnings (loss)
– Share of other comprehensive loss of associate (1) 4,492 422
Balance, end of year $ (4,322) $ (11,944)
Total Shareholders’ Equity $ 421,076 $ 523,187
(1) Total comprehensive loss for 2011 is $106.5 million (2010 - $55.9 million).
The accompanying notes to the consolidated financial statements are an integral part of these statements.

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Consolidated Statements of Cash Flow
Canadian dollar in thousands
For the year ended December 31 Notes 2011 2010
OPERATING
Net loss $ (114,105) $ (44,669)
Adjustments for:
Share–based compensation 18.4 3,453 5,019
Depletion, depreciation, amortization and impairment 122,009 79,842
Unrealized (gain) loss on risk management contracts 12 (11,252) 14,343
Interest expense on long-term debt 84,759 55,637
Finance charges – non-cash 9,141 11,539
Refinancing of long–term debt 13.3 61,971 –
Unrealized foreign exchange loss (gain) 20 22,980 (39,603)
Realized foreign exchange gain on settlement of debt 13.3 (11,592) –
(Gain) loss on disposition of assets 21 (43,457) 811
Defined benefit plan expense 15 708 426
Share of interest in and loss on associate 8.2 6,840 16,016
Deferred income tax recovery 16 (1,558) (7,803)
129,897 91,558
Changes in non–cash working capital 23 14,048 (23,962)
Defined benefit plan contributions 15 (504) (517)
Decommissioning liabilities settled 14 (1,018) (647)
Cash flow from operating activities 142,423 66,432
INVESTING
Expenditures on property, plant and equipment (134,228) (175,095)
Exploration and evaluation expenditures (22,399) (25,220)
Proceeds on disposition of assets 117,258 1,721
Proceeds on sale of equity securities 21 21,064 –
Changes in non–cash working capital 23 5,519 (34,797)
Cash flow used in investing activities (12,786) (233,391)
FINANCING
Proceeds on issue of common shares 17 752 27,282
Share issue costs 17 (71) (1,489)
Interest paid on long-term debt (65,460) (92,019)
Proceeds on issue of long–term debt 13 950,912 –
Repayment of long–term debt 13 (899,402) –
Long–term debt issue cost 13 (18,451) –
Cash flow used in financing activities (31,720) (66,226)
NET INCREASE (DECREASE) IN CASH 97,917 (233,185)
Foreign exchange loss on cash balances held in foreign currency (404) (4,070)
CASH, BEGINNING OF YEAR 19,532 256,787
CASH, END OF YEAR $ 117,045 $ 19,532
The accompanying notes to the consolidated financial statements are an integral part of these statements.

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Notes to the Consolidated Financial Statements
For the years ended December 31, 2011 and 2010
1. Nature of Operations
Connacher Oil and Gas Limited (“Connacher”) is a public company listed on the Toronto Stock Exchange under the symbol CLL and headquartered in
Calgary, Alberta, Canada. The consolidated financial statements, as at December 31, 2011 and for the year then ended, comprise those of Connacher
and its subsidiaries (collectively referred to as the “company”). The address of the company’s principal office is Suite 900, 322 – 6th Avenue S.W.,
Calgary, Alberta. The company is engaged in the business of development, production and refining of bitumen, crude oil and natural gas.
These consolidated financial statements were approved and authorized for issuance by the Board of Directors on March 15, 2012.
2. Basis of PREPARATION
2.1 Statement of compliance
The consolidated financial statements have been prepared in accordance with International Financial Reporting Standards (“IFRS”). These are the company’s
first consolidated financial statements prepared under IFRS. As a result, IFRS 1, “First–time Adoption of International Financial Reporting Standards” has
been applied. In these financial statements, the term “previous GAAP” refers to Canadian generally accepted accounting principles prior to the adoption of
IFRS. An explanation of the impacts on financial performance, financial position and cash flows on the transition to IFRS is provided in note 27.
2.2 Basis of measurement
These consolidated financial statements have been prepared on a historical cost basis except for the following which have been measured at fair value:
• Risk management contracts;
• Investment in equity securities and share purchase warrants;
• Liabilities for cash–settled share–based payment arrangements;
• Assets classified as held for sale where the carrying amount is higher than the fair value; and
• Convertible Debentures.
2.3 Functional and presentation currency
The consolidated financial statements are presented in Canadian dollars which is the functional currency of Connacher. The functional currency of the
company’s subsidiary companies is primarily the US dollar.
2.4 Use of estimates and judgments
The timely preparation of consolidated financial statements requires management to make judgments, estimates and assumptions that affect the
reported amounts of assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses
during the reporting period. Although these estimates are based on management’s best knowledge of the amount, event or actions, actual results
ultimately may differ from those estimates. Accordingly, actual reported amounts may differ from estimated amounts as future confirming events occur.
Estimation of petroleum and natural gas reserves
Petroleum and natural gas reserve estimates are used in the unit–of–production depletion and depreciation calculation, determination of the timing of
abandonment costs and impairment analysis of upstream assets. The company’s proved plus probable reserves are estimated annually by independent
reserves engineers with reference to available geological, geophysical and engineering data. Estimates of petroleum and natural gas reserves are
inherently imprecise, require the application of judgment and are subject to regular revision, either upward or downward, based on new information.
The impact of future changes to estimates on the consolidated financial statements of subsequent periods could be material.
Changes to estimates of petroleum and natural gas reserves affect prospectively the amounts of depletion, depreciation, amortization and impairment
charged and, consequently, the carrying amounts of petroleum and natural gas properties and exploration and evaluation assets.
Information about the carrying amounts of petroleum and natural gas properties and exploration and evaluation assets and the amounts charged to
net earnings (loss), including depletion, depreciation, amortization and impairment, is presented in note 9 and 10.

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Impairment of assets
For the purposes of impairment analysis of the company’s assets, the key assumptions used in estimating cash flows are future commodity prices,
expected production volumes and refinery throughput, cost structures and the outlook of market supply and demand conditions appropriate to the
local circumstances and environment. These assumptions and estimates are highly uncertain matters and are subject to change as new information
becomes available. Changes in economic conditions can also affect the rate used to discount future cash flow estimates.
Changes in assumptions could affect the carrying amounts of assets and impairment charges and reversals will affect net earnings (loss).
Information about the carrying amounts of assets and impairments is presented in notes 9 and 10.
Decommissioning liabilities
Provisions are recognized for the future abandonment and reclamation of petroleum, natural gas and refining properties at the end of their economic
lives. The estimated cost is recognized in net earnings (loss) over the life of the reserves on a unit–of–production basis. Changes in the estimates
of costs to be incurred, reserves or in the rate of production will therefore affect net earnings (loss), generally over the remaining economic life of
petroleum and natural gas assets.
Estimates of the amounts of decommissioning provisions recognized are based on current legal and constructive requirements, technology and price
levels. Because actual outflows can differ from estimates due to changes in laws, regulations, public expectations, technology, industry standards,
prices and conditions, and can take place many years in the future, the carrying amounts of such provisions are regularly reviewed and adjusted to
take account of such changes. The interest rate used to discount the cash flows is reviewed quarterly.
Information about decommissioning liabilities is presented in note 14.
Taxation
Tax provisions are recognized when it is considered probable that there will be a future outflow of funds to a taxing authority. In such cases, provision
is made for the amount that is expected to be settled, where this can be reasonably estimated. This requires the application of judgment as to the
ultimate outcome, which can change over time depending on facts and circumstances. A change in estimate of the likelihood of a future outflow and/
or in the expected amount to be settled would be recognized in net earnings (loss) in the period in which the change occurs.
Deferred tax assets are recognized only to the extent it is considered probable that those assets will be recoverable. This involves an assessment
of when those deferred tax assets are likely to be realized, and a judgment as to whether or not there will be sufficient taxable profits available to
offset the tax assets when they do reverse. This requires assumptions regarding future profitability and is therefore inherently uncertain. To the extent
assumptions regarding future profitability change, there can be an increase or decrease in the amounts recognized in respect of deferred tax assets
as well as in the amounts recognized in net earnings (loss) in the period in which the change occurs.
Tax provisions are based on enacted or substantively enacted laws. Changes in those laws could affect amounts recognized in net earnings (loss)
both in the period of change, which would include any impact on cumulative provisions, and in future periods.
Financial instruments
The company records its financial instruments at fair value on inception and at each reporting period depending on their subsequent classification.
The calculation of the fair value requires judgment around expected outcome and is based on multiple variables such as the company’s credit risk and
interest rate spread. The estimated fair value of the financial instruments, by their very nature, is subject to measurement uncertainty.
Other significant areas of judgment
The estimates of net realizable value of inventory involve estimating future selling prices and accordingly, are subject to measurement uncertainty.
The amounts for pension assets, obligations and pension costs charged to net earnings (loss) depend on certain actuarial and economic assumptions,
which are subject to measurement uncertainty.
Amounts recorded for share–based compensation expense are based, in part, on the historical volatility of the company’s share price, which may not
be indicative of future volatility. Accordingly, those amounts are subject to measurement uncertainty.
3. SIGNIFICANT ACCOUNTING POLICIES
3.1 Basis of consolidation
The consolidated financial statements include the financial statements of Connacher and its subsidiaries, being those which are controlled by the
company. Control exists when the company has the power to govern the financial and operating policies of an entity so as to obtain benefits from its
activities. The financial statements of subsidiaries are included in the consolidated financial statements from the date that control commences until the
date that control ceases, using consistent accounting policies. All inter–company balances and transactions, including gains and losses arising from
such transactions, are eliminated.

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3.2 Inventories
Inventories are stated at the lower of cost or net realizable value. Cost comprises direct purchase and blending costs, costs of production and other
indirect costs and is determined using the weighted average cost method. Net realizable value is the estimated selling price in the ordinary course of
business less costs to complete and sell.
3.3 Exploration and Evaluation assets (“E&E”)
E&E expenditures incurred prior to acquiring the legal right to explore are charged to expense as incurred and recorded as E&E expense in net
earnings (loss).
All costs directly associated with exploration and evaluation of oil and gas activities are initially capitalized. E&E costs are those expenditures where
technical feasibility and commercial viability has not been yet been determined and include license and unproved property acquisition costs, geological
and geophysical costs and costs of drilling exploratory wells.
E&E costs are not amortized except for the costs associated with unproved land which are amortized to expense over the lease term. E&E assets are
transferred to property, plant and equipment when they are determined to meet technical feasibility and commercial viability.
The carrying amount of E&E assets is tested for impairment in accordance with note 3.6 annually, upon transfer to property, plant and equipment,
when an area is determined not to be technically feasible and commercially viable or the company decides not to continue with its activity.
3.4 Property, plant and equipment (“PP&E”)
Recognition and measurement
Property, plant and equipment is initially recognized at cost which represents all costs directly associated with the development of petroleum and
natural gas reserves where technical feasibility and commercial viability have been determined. Such costs include drilling costs of development wells,
tangible costs of facilities and infrastructure construction, costs of optimization and enhanced recovery projects, proved property acquisition costs,
asset decommissioning costs, transfers from E&E assets and borrowing costs relating to qualifying assets.
Expenditures on major maintenance repairs comprise the cost of replacement assets or parts of assets, inspection costs and overhaul costs. Where
an asset or part of an asset that was separately depreciated is replaced and it is probable that future economic benefits associated with the item
will flow to the company, the expenditure is capitalized and the carrying amount of the replaced asset is derecognized. Major inspection and overhaul
costs associated with major maintenance programs are capitalized and amortized over the period to the next inspection. Normal overhaul and repair
and maintenance costs are charged to net earnings (loss) when incurred.
Property, plant and equipment are subsequently carried at cost less accumulated depletion, depreciation, amortization and impairment. Gains and losses
on disposals are determined by comparing disposal proceeds with the carrying amounts of assets sold and are recognized in net earnings (loss).
Depletion, depreciation, amortization and impairment
Property, plant and equipment relating to petroleum and natural gas properties including related facilities are depleted and depreciated using the unit–
of–production method over the proved and probable reserves before royalties and determined using forecast prices and costs. For the purpose of this
calculation, natural gas is converted to oil on an energy equivalent basis. Estimated future costs to develop proved and probable reserves are included
in costs subject to depletion. Costs of major development projects are excluded from depletion and depreciation until the asset is available for use.
Property, plant and equipment relating to refining properties are depreciated and amortized using the straight–line method, based on the estimated
useful lives of assets which range from 3 to 16 years.
Property, plant and equipment relating to the corporate office include leasehold improvements and computer and office equipment. Leasehold
improvements are amortized using the straight–line method over the lease term whereas computer and office equipment are amortized using the
declining balance method at 20% to 30% per annum.
The estimates of useful lives of property, plant and equipment are reviewed annually and if, necessary, changes are accounted for prospectively.
Impairment
The carrying amount of property, plant and equipment is reviewed for impairment, in accordance with note 3.6, whenever events or changes in
circumstances indicate the carrying amount may not be recoverable.
3.5 Business combinations and goodwill
Business combinations are accounted for using the acquisition method. The acquired identifiable net assets are measured at their fair value at the
date of acquisition. Any excess of the purchase price over the fair value of the net assets acquired is recognized as goodwill. Any deficiency of the
purchase price below the fair value of the net assets acquired is recorded as a gain in net earnings (loss). Associated transaction costs are expensed
when incurred.

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Goodwill is allocated to the applicable cash–generating unit as defined in note 3.6. Goodwill is not amortized and is tested for impairment annually
on December 31 or whenever there is an indication that the cash-generating unit to which goodwill is allocated may be impaired, in accordance with
note 3.6.
3.6 Impairment
Non–financial assets (E&E, PP&E and Goodwill)
When impairment indicators exist or when impairment testing is required for non–financial assets, an impairment test is carried out in which the
carrying amounts of those assets are compared to their recoverable amount, which is the higher of fair value less costs to sell (“FVLCS”) and value–
in–use (“VIU”). For purposes of the impairment test, E&E, PP&E and goodwill are grouped together into the smallest group of assets that generates
largely independent cash flows from other assets or groups of assets (the “cash–generating unit” or “CGU”).
VIU is determined by estimating the discounted future cash flows expected to be derived from continuing use of the assets. In determining FVLCS,
recent market transactions are taken into account, if available. If no such transactions can be identified, an appropriate valuation model is used. These
calculations are corroborated by valuation multiples or other available fair value indicators.
Impairment losses are recognized in net earnings (loss) and reported within depletion, depreciation, amortization and impairment. Impairment losses
recognized in respect of a CGU are allocated first to reduce the carrying amount of any goodwill allocated to the CGU and then to reduce the carrying
amount of the other assets in the CGU.
An impairment loss in respect of goodwill is not reversed. In respect of other assets, impairment losses recognized in prior years are assessed at each
reporting date for any indications that the loss has decreased or no longer exists. If the amount of the impairment loss decreases in a subsequent
period and the decrease can be objectively related to an event occurring after the impairment was recognized, the impairment loss is reversed up to the
original carrying amount of the asset that would have been determined, net of depletion, depreciation, amortization and impairment, if no impairment loss
had been recognized. Such reversal is recognized in net earnings (loss) and reported within depletion, depreciation, amortization and impairment.
Financial assets (Cash, Trade and accrued receivable and Investment in equity securities)
A financial asset not carried at fair value through profit or loss is assessed at each reporting date to determine whether there is objective evidence
that it is impaired. A financial asset is impaired if objective evidence indicates that a loss event has occurred after the initial recognition of the asset,
and that the loss event had a negative effect on the estimated future cash flows of that asset that can be estimated reliably.
The company considers evidence of impairment for trade and accrued receivables at a specific asset level. All individually significant trade and
accrued receivables are assessed for specific impairment. An impairment loss is calculated as the difference between its carrying amount and the
present value of the estimated future cash flows discounted at the asset’s original effective interest rate. Losses are recognized in net earnings (loss)
and reflected in an allowance account against trade and accrued receivables. When a subsequent event causes the amount of impairment loss to
decrease, the decrease in impairment loss is reversed through net earnings (loss).
3.7 Investment in associate
An associate is an entity over which the company has the right to exercise significant influence, but not control, over the financial and operating
policies. The investment in associate is accounted for using the equity method of accounting. Under the equity method, the investment is initially
recorded at cost and subsequently adjusted for the post–acquisition changes in the company’s share of net assets of associate, after adjustment to
align the accounting policies with those of the company. The company’s net earnings or loss reflects the company’s share of the net earnings or loss
after tax of the associate.
The company assesses the investment in associate for impairment whenever events or changes in circumstances indicate that the carrying amount
may not be recoverable. If any such indication of impairment exists, the carrying amount of the investment is compared with its recoverable amount,
being the higher of its fair value less costs to sell and value in use. Where the carrying amount exceeds the recoverable amount, the investment is
written down to its recoverable amount.
The company ceases to use the equity method of accounting on the date from which it no longer has significant influence over the associate, or when
the investment becomes held for sale.
Losses of an associate in excess of the company’s equity interest in that associate are recognized only to the extent that the company has incurred
legal or constructive obligations or made payments on behalf of the associate.
3.8 Income taxes
Tax expense comprises current and deferred taxes. Tax expense is recognized in net earnings (loss) except when it relates to items recognized in
other comprehensive income (loss). Income tax assets and liabilities are presented separately in the consolidated balance sheet except where there is
a right of set–off within fiscal jurisdictions and an intention to settle such balances on a net basis.

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Current tax expense is based on the results for the period as adjusted for items that are not taxable or not deductible. Current tax is calculated
using tax rates and laws that have been enacted or substantively enacted at the end of the reporting period. Management periodically evaluates
positions taken in tax returns with respect to situations in which applicable tax regulation is subject to interpretation. Provisions are established where
appropriate on the basis of amounts expected to be paid to the tax authorities.
Deferred tax is recognized in the balance sheet using the liability method of accounting for income taxes, on temporary differences arising between
the tax bases of assets and liabilities and their carrying amounts. Deferred tax is calculated using tax rates and laws that have been enacted or
substantively enacted at the end of the reporting period, and which are expected to apply when the related deferred tax asset is realized or the
deferred tax liability is settled.
3.9 Provisions
Decommissioning liabilities
The company recognizes a decommissioning liability for abandoning petroleum and natural gas wells, related facilities, compressors and plants,
removal of equipment from leased acreage and for returning such land to its original condition, in the period in which a well or related asset is drilled,
constructed or acquired. The decommissioning liability is estimated using the present value of the estimated expected future cash outflows at a
risk–free interest rate. The obligation is reviewed regularly by management, based upon current costs, laws and regulations, public expectations,
technology, and industry standards. The liability is initially capitalized as part of the carrying amount of the related property, plant and equipment
The effects of changes to the liability resulting from revisions to the timing or the amount of the original estimate of the provision are reflected on a
prospective basis, generally by adjustment to the carrying amount of the related property, plant and equipment. Actual abandonment and reclamation
expenditures are charged against the liability as incurred and obligations related to properties disposed are removed.
The company also has decommissioning obligations with respect to certain of its refinery assets due to various legal obligations to clean and/or dispose
of various component parts of the refinery at the time they are retired. However, these component parts can be used for extended and indeterminate
periods of time as long as they are properly maintained and/or upgraded. It is the Company’s practice and current intent to maintain its refinery assets
and continue making improvements to the assets based on technological advances. As such, the present value of such obligations is minimal.
Premium on flow–through common shares
Under Canadian income tax legislation, a company is permitted to issue flow–through shares whereby the company is obligated to incur qualifying
expenditures related to petroleum and natural gas exploration activities and to renounce the related income tax deductions to the investors. Generally,
due to the benefit of transferring the tax deduction to the investors, the shares issued on flow–through basis are offered at prices higher than the
prevailing quoted prices of the shares. Accordingly, the proceeds from issuance of these shares are allocated between share capital and the liability
to incur these qualifying expenditures The amounts allocated to share capital represents the quoted price of the existing shares whereas the liability
represents the difference between the quoted price of the existing shares and the amount the investor pays for the flow-through shares. The liability is
reversed when qualifying expenditures are renounced and reported within deferred income tax in net earnings (loss).
3.10 Employee benefits
Employee retirement plans
The company maintains a funded defined benefit pension plan and defined contribution savings plans.
A valuation of the defined benefit plan is carried out annually by independent actuaries, using the projected unit credit method to calculate the
defined benefit obligation. Pension cost primarily represents the increase in the actuarial present value of the obligation for pension benefits based
on employee service during the year and the interest on this obligation in respect of employee service in previous years, net of the expected return
on plan assets. Plan assets are valued at fair value. The present value of the accumulated benefit obligation is determined by actuaries. The expected
return on plan assets is based on market expectations at the beginning of the fiscal period for returns over the entire life of the benefit obligation.
Actuarial gains and losses are recognized as income or expense when the net cumulative unrecognized actuarial gains and losses at the end of the
previous reporting year exceed 10% of the higher of the defined benefit obligation and the fair value of plan assets at that date. These gains and
losses are recognized in net earnings (loss) over the expected average remaining working lives of the employees participating in the plan.
For defined contribution saving plans, the cost is the amount of employer contributions payable for the period.
Share–based compensation plans
Directors, employees and consultants of the company receive remuneration in the form of share–based payment transactions, whereby those
individuals render services as consideration for equity instruments. The company maintains a stock option plan, share award incentive plan and share
unit plan. Share–based compensation is initially recognized over the vesting period at the fair value on the date of grant with a corresponding increase
to contributed surplus for equity–settled plans and to trade and accrued payables for cash–settled plans. Equity–settled plans are subsequently not
remeasured whereas the cash–settled plans are remeasured to fair value at each reporting period–end. Fair value on the date of grant is estimated
using either a Black–Scholes option pricing model or the closing price of the common shares, as defined in the plans. Upon the issue of shares under
the plans, the proceeds received on exercise of stock options and the amounts previously recognized in contributed surplus for the plans are credited
to share capital.

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3.11 Leases
Agreements under which payments are made to owners in return for the right to use an asset for a period are accounted for as leases. Leases that
transfer substantially all the risks and rewards of ownership are recognized at the commencement of the lease term as finance leases within property,
plant and equipment and liabilities at the fair value of the leased asset or, if lower, at the present value of the minimum lease payments. Finance lease
payments are apportioned between interest expense and a reduction of the liability. All other leases are recorded as operating leases, and the costs
are recognized in net earnings (loss) on a straight–line basis.
3.12 Foreign currency
Foreign currency transactions
Transactions denominated in foreign currencies are translated to the respective functional currencies of the entities at monthly average exchange rates.
Monetary assets and liabilities denominated in foreign currencies at the reporting date are translated to the functional currency at the exchange rate
prevailing on the reporting date. Foreign exchange gains and losses resulting from the translation and settlement are recognized in net earnings (loss).
Foreign operations
The assets and liabilities of foreign operations are translated to Canadian dollars at exchange rates at the reporting date, while their statements of
operations, other comprehensive income (loss) and cash flows are translated at monthly average rates. The resulting foreign currency differences
are recognized in other comprehensive income (loss). Upon divestment of all or part of an interest in, or upon liquidation of, a foreign operation, the
cumulative currency translation differences are generally recognized in net earnings (loss). Foreign exchange gains or losses arising from monetary
assets and liabilities that form part of the net investment in the foreign operation are recognized in other comprehensive income (loss).
3.13 Financial instruments
Financial instruments consist of financial assets, financial liabilities and derivative financial instruments and are initially recognized at fair value plus,
in the case of a financial assets or financial liability not at fair value through profit or loss, transactions costs. Measurement in subsequent periods
depends on whether the financial instrument has been classified as “fair value through profit or loss”, “loans and receivables”, “available–for–sale”,
“held–to–maturity”, or “financial liabilities measured at amortized cost“ as follows:
Financial assets
Financial assets comprise cash, trade and accrued receivable and investment in equity securities.
Trade and accrued receivables are classified as “loans and receivables” and recorded at amortized cost less any impairment.
Investments in equity securities are classified as available–for–sale and are carried at fair value, less any impairment. Unrealized gains and losses
other than impairments are recognized in other comprehensive income (loss). On disposal, net gains and losses previously deferred in accumulated
other comprehensive income (loss) are recognized in net earnings (loss).
Financial liabilities
Financial liabilities comprise trade and accrued payables, Senior Notes, Convertible Debentures and the amounts outstanding under the Revolving
Credit Facility.
Trade and accrued payables and Senior Notes are classified as “financial liabilities measured at amortized cost” and are measured at amortized cost
using the effective interest rate method.
Convertible Debentures are classified as “fair value through profit and loss” whereby they are carried at the fair value at each reporting date.
Unrealized gains and losses on remeasurement to fair value at each reporting period–end are recognized in net earnings (loss).
Transaction costs relating to the Revolving Credit Facility are amortized over its term using the straight line method. The Facility is measured at
amortized cost, net of transaction costs, in the event that amounts are drawn and outstanding under the Facility at the reporting period-end. In the
event no amounts are outstanding at the reporting period-end, unamortized transaction costs are included in other assets.
Derivative financial instruments
Derivative financial instruments comprise investments in share purchase warrants, risk management contracts and embedded derivatives.
The investment in share purchase warrants is classified as “fair value through profit and loss” whereby it is carried at the fair value at the reporting
date. Unrealized gains and losses on remeasurement to fair value at each reporting period–end are recognized in net earnings (loss).
The company enters into certain risk management contracts in order to reduce its exposure to market risks from fluctuations in commodity prices,
foreign currency and interest rates. These instruments are not used for speculative purposes. The company has not designated its risk management
contracts as effective accounting hedges and thus has not applied hedge accounting. As a result, all risk management contracts are classified as
“fair value through profit and loss” and recorded on the balance sheet at fair value at each reporting date. Realized gains or losses from financial
risk management contracts are recognized in net earnings (loss) as the contracts are settled. Unrealized gains and losses are recognized in net

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earnings (loss) at the end of each respective reporting period based on the changes in fair value of the contracts. The estimated fair value of all risk
management contracts is derived from third–party market indications and forecasts. Attributable transaction costs are recorded in net earnings (loss).
The company accounts for its forward physical delivery sales and purchase contracts that are entered into and continued to be held for the purpose
of receipt or delivery of non–financial items in accordance with its expected purchase, sale or usage requirements, as executory contracts. As such,
these contracts are not considered derivative financial instruments and thus have not been recorded on the consolidated balance sheet. Settlements
of these physical sales and purchase contracts are recognized in related revenues and expenses.
Derivatives embedded within contracts that are not already required to be recognized at fair value, and that are not closely related to the host contract
in terms of economic characteristics and risks, are separated from their host contract and recognized at fair value; associated gains and losses are
recognized in net earnings (loss). The company has no material embedded derivatives.
3.14 Revenue recognition
Revenue from sales of bitumen, crude oil, natural gas and refined products is recognized at the fair value of consideration received or receivable, after
deducting royalties, when title passes to the customer. For sales by upstream operations, this generally occurs when product is physically transferred
into a pipe, delivery trucks are accepted by the customer, or railcars have been transloaded. For sales by downstream operations, it is either at the
loading or delivery point, depending on contractual conditions.
3.15 Finance charges
Finance charges comprise interest expense on long–term debt, amortization of transaction costs and stand–by fees of the Facility, unwinding of the
discount on decommissioning liabilities, unrealized gain/loss on revaluation of convertible debentures and share purchase warrants, bank charges and
any impairment losses recognized on financial assets.
Finance charges directly attributable to the acquisition, construction or production of qualifying assets, which are assets that necessarily take a
substantial period of time to get ready for their intended use, are added to the cost of those assets, until such time as the assets are substantially
ready for their intended use. All other finance costs are recognized in net earnings (loss) in the period in which they are incurred using the effective
interest method. Interest has been capitalized at the rate of interest applicable to the specific borrowings financing the asset, or where financed
through general borrowings, at a capitalization rate representing the average interest rate on such borrowings.
3.16 Earnings (loss) per share
The company presents basic and diluted earnings (loss) per share data for its common shares. Basic earnings (loss) per share is calculated by dividing
net earnings (loss) attributable to ordinary equity holders of the company by the weighted average number of common shares outstanding during
the period. Diluted earnings (loss) per share is determined by adjusting the earnings or loss attributable to common shareholders and the weighted
average number of common shares outstanding for the effects of dilutive instruments, which may include convertible debentures, stock options, share
incentive awards and share units.
3.17 Non–current assets classified as held for sale
Non–current assets, or disposal groups comprising assets and liabilities, that are expected to be recovered primarily through sale rather than
through continuing use, are classified as held for sale. Immediately before classification as held for sale, the assets, or components of a disposal
group, are remeasured in accordance with the company’s accounting policies. Thereafter, the assets, or disposal group, are measured at the lower
of their carrying amount and fair value less cost to sell. Impairment losses on initial classification as held for sale and subsequent gains or losses on
remeasurement are recognized in net earnings (loss). Property, plant and equipment classified as held for sale are not depleted or depreciated and
investment in associate classified as held for sale is not equity accounted.
3.18 Fair value measurements
Fair value measurements are estimates of the amounts for which assets or liabilities could be exchanged at the measurement date, based on
the assumption that such exchanges take place between knowledgeable, unrelated parties in unforced transactions. Where available, fair value
measurements are derived from prices quoted in active markets for identical assets or liabilities. In the absence of such information, other observable
inputs are used to estimate fair value. Where publicly available information is not available, fair value is determined using estimation techniques that take
into account market perspectives relevant to the asset or liability so as far as they can reasonably be ascertained, based on predominantly unobservable
inputs. For risk management contracts and for share–based compensation plans, fair value estimations are generally determined using models and
other valuation methods, the key inputs for which include future prices, volatility, price correlation, counterparty credit risk and market liquidity, as
appropriate; for other assets and liabilities, fair value estimations are generally based on the net present value of expected future cash flows.
3.19 Recent accounting pronouncements issued but not yet adopted
The company has reviewed new and revised accounting pronouncements that have been issued but are not yet effective for the financial year
beginning January 1, 2011 and determined that the following may have an impact on the company:

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IAS 1 Presentation of Financial Statements (“IAS 1”)
IAS 1 was amended in June 2011 to provide guidance on the presentation of items contained in other comprehensive income (“OCI”) and their
classification within OCI. The amendments are to be applied for annual periods beginning on or after July 1, 2012 with earlier adoption permitted. The
amendments are not expected to have a significant impact on the company’s consolidated financial statements.
IAS 12 Income Taxes (“IAS 12”)
IAS 12 was amended in December 2010 to remove subjectivity in determining on which basis an entity measures the deferred tax relating to an
asset. The amendment introduces a presumption that an entity will assess whether the carrying amount of an asset will be recovered through the sale
of the asset. The amendment to IAS 12 is effective for reporting periods beginning on or after January 1, 2012. The company is currently evaluating
the impact of this amendment to IAS 12 on its consolidated financial statements.
IAS 19 Employee Benefits (“IAS 19”)
IAS 19 was amended in June 2011 to change the accounting for defined benefit plans and termination benefits. The amendments require the
immediate recognition of actuarial gains or losses. The amendments also mandate additional presentation and disclosure requirements. The
amendments are be applied for annual periods beginning on or after January 1, 2013 with earlier adoption permitted. The company is currently
evaluating the impact of this standard on its consolidated financial statements.
IFRS 7 Financial Instruments: Disclosures (“IFRS 7”)
IFRS 7 was amended in October 2010 to provide additional disclosure on the transfer of financial assets including the possible effects of any residual
risks that the transferring entity retains. These amendments are for annual periods beginning on or after July 1, 2011. The company is currently
evaluating the impact of these amendments to IFRS 7 on its consolidated financial statements.
IFRS 9 Financial Instruments (“IFRS 9”)
IFRS 9 was issued in November 2009 and is the first step to replace current IAS 39, “Financial Instruments: Recognition and Measurement”. IFRS
9 uses a single approach to determine whether a financial asset is measured at amortized cost or fair value, replacing the multiple rules in IAS 39.
The approach in IFRS 9 is based on how an entity manages its financial instruments in the context of its business model and the contractual cash
flow characteristics of the financial assets. The new standard also requires a single impairment method to be used, replacing the multiple impairment
methods in IAS 39. IFRS 9 is effective for annual periods beginning on or after January 1, 2015. The company is currently evaluating the impact of
IFRS 9 on its consolidated financial statements.
IFRS 10 Consolidated Financial Statements (“IFRS 10”)
IFRS 10 establishes principles for the presentation and preparation of consolidated financial statements when an entity controls one or more other
entities. IFRS 10 supersedes IAS 27 “Consolidated and Separate Financial Statements” and SIC–12 “Consolidation—Special Purpose Entities” and is
effective for annual periods beginning on or after January 1, 2013. Earlier application is permitted. The company is currently evaluating the impact of
this standard on its consolidated financial statements.
IFRS 11 Joint Arrangements (“IFRS 11”)
IFRS 11 establishes principles for financial reporting by parties to a joint arrangement. IFRS 11 supersedes current IAS 31 “Interests in Joint Ventures
and SIC–13 Jointly Controlled Entities—Non–Monetary Contributions by Venturers” and is effective for annual periods beginning on or after January 1,
2013. Earlier application is permitted. The company is currently evaluating the impact of this standard on its consolidated financial statements.
IFRS 12 Disclosure of Interests in Other Entities (“IFRS 12”)
IFRS 12 applies to entities that have an interest in a subsidiary, a joint arrangement, an associate or an unconsolidated structured entity. IFRS 12 is
effective for annual periods beginning on or after January 1, 2013. Earlier application is permitted. The company is currently evaluating the impact of
this standard on its consolidated financial statements.
IAS 28 Investments in Associates and Joint Ventures (“IAS 28”)
IAS 28 was amended in 2011 and prescribes the accounting for investments in associates and sets out the requirements for the application of the equity
method when accounting for investments in associates and joint ventures. IAS 28 is effective for annual periods beginning on or after January 1, 2013.
Earlier application is permitted. The company is currently evaluating the impact of this amendment to IAS 28 on its consolidated financial statements.
IFRS 13 Fair Value Measurements (“IFRS 13”)
IFRS 13 defines fair value, sets out in a single IFRS framework for measuring fair value and requires disclosures about fair value measurements. IFRS
13 is to be applied for annual periods beginning on or after January 1, 2013. Earlier application is permitted. The company is currently evaluating the
impact of this standard on its consolidated financial statements.

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Financial Instruments - Presentation (“IAS 32”)
In December 2011, certain amendments to IAS 32 were issued which address inconsistencies when applying the offsetting criteria outlined in this
standard. These amendments clarify certain of the criteria required to be met in order to permit the offsetting of financial assets and financial liabilities.
These amendments are required to be adopted retrospectively for periods beginning January 1, 2014. The company is currently evaluating the impact
of this standard on its consolidated financial statements.
4. SEGMENT REPORTING
Management has segmented the company’s business based on differences in products and services and management responsibility. The company’s
business is conducted predominantly through two major operating segments – upstream in Canada and downstream in USA, through a wholly–owned
subsidiary, Montana Refining Company, Inc. (‘‘MRCI’’). Upstream includes exploration for and the development and production of bitumen, crude oil and
natural gas. Downstream includes refining of primarily crude oil to produce and market gasoline, jet fuel, diesel fuels, asphalt and ancillary products.
4.1 Segment revenue and results
Performance is measured based on segment operating income. This measure excludes interest and other income, gain (loss) on disposition of assets,
unrealized gain (loss) on risk management contracts, share-based compensation, employee benefit plan expense, finance charges, foreign exchange
gain (loss), depletion, depreciation, amortization and impairment, share of interest in and loss on disposition of associate, exploration and evaluation
expenses and costs of refinancing long–term debt.
The accounting policies of the segments are the same as the company’s accounting policies provided in note 3. Transfer prices between operating
segments are on an arm’s length basis in a manner similar to transactions with third parties.
Information regarding revenue and results of each reportable segment is presented below followed by the reconciliations:
Revenue, net of royalties
For the year ended December 31 2011 2010
(Canadian dollar in thousands)
Segment
revenue
Segment
revenue
Inter–
segment
revenue
Revenue
from
external
customers
Inter–
segment
revenue
Revenue
from
external
customers
Upstream – Canada $ 446,904 $ – $ 446,904 $ 270,033 $ – $ 270,033
Downstream – USA 441,143 (15,241) 425,902 334,165 (14,267) 319,898
Total $ 888,047 $ (15,241) $ 872,806 $ 604,198 $ (14,267) $ 589,931
Results
For the year ended December 31 2011 2010
(Canadian dollar in thousands)
Upstream Downstream Total Upstream Downstream Total
Canada
USA
Canada
USA
Segment operating income $ 90,180 $ 39,691 $ 129,871 $ 68,183 $ 24,023 $ 92,206
Depletion, depreciation, amortization and impairment $ 110,872 $ 9,278 $ 120,150 $ 67,042 $ 10,470 $ 77,512
In 2011 and 2010, the company recorded an impairment charge of $24.7 million and $4.5 million, respectively, within the upstream segment.
See note 10 for more details.
Reconciliation of depletion, depreciation, amortization and impairment
For the year ended December 31
2011 2010
(Canadian dollar in thousands)
Segment depletion, depreciation, amortization and impairment $ 120,150 $ 77,512
Corporate depreciation 1,859 2,330
Consolidated depletion, depreciation, amortization and impairment $ 122,009 $ 79,842

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Reconciliation of segment operating income to net loss before taxes
For the year ended December 31
2011 2010
(Canadian dollar in thousands)
Upstream segment operating income $ 90,180 $ 68,183
Downstream segment operating income 39,691 24,023
Interest and other income 979 256
Gain (loss) on disposition of assets 43,457 (811)
Unrealized gain (loss) on risk management contracts 11,252 (14,343)
Employee benefit plan expense (708) (426)
Stock–based compensation (3,453) (5,019)
Finance charges (95,588) (69,445)
Foreign exchange (loss) gain (8,909) 41,641
Depletion, depreciation, amortization and impairment (122,009) (79,842)
Share of interest in and loss on disposition of associate (6,840) (16,016)
Exploration and evaluation expenses (210) (964)
Refinancing of long–term debt (61,971) –
Net loss before taxes $ (114,129) $ (52,763)
4.2 Capital expenditures
For the year ended December 31
2011 2010
(Canadian dollar in thousands)
Upstream – Canada $ 136,520 $ 189,612
Downstream – USA 18,653 8,575
Corporate – Canada 1,454 2,128
Capital expenditures – total $ 156,627 $ 200,315
4.3 Entity–wide disclosures
Information about products
The following provides the information relating to the company’s external revenue from its major products:
For the year ended December 31
2011 2010
(Canadian dollar in thousands)
Diluted bitumen $ 430,027 $ 241,747
Crude oil 10,372 15,516
Natural gas 6,505 12,770
Gasoline 175,066 138,252
Asphalt 125,287 93,980
Diesel and jet fuel 118,136 83,885
Other refined products 7,413 3,781
Total revenue from external customers $ 872,806 $ 589,931
Information about geographical areas
The company operates in two principal geographical areas (Canada and USA). The information regarding revenue from external customers of these
locations is presented above. The following table provides information regarding non–current assets (excluding asset classified as held for sale $nil
(2010 : $88.2 million) relating to these locations:
As at December 31
2011 2010
(Canadian dollar in thousands)
Canada $ 1,260,073 $ 1,248,016
USA 92,666 81,216
Total $ 1,352,739 $ 1,329,232
Information about major customers
Revenue from one customer of the company’s upstream segment represents approximately $201.4 million of the company’s total revenue in 2011.
Revenue from two customers of the company’s upstream segment represents approximately $157.8 million and $72.3 million of the company’s total
revenue in 2010.

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5. Trade and ACCRUED RECEIVABLES
As at
December 31, 2011 December 31, 2010 January 1, 2010
(Canadian dollar in thousands)
Trade receivables $ 16,257 $ 16,904 $ 14,295
Accrued revenue 45,848 39,942 16,358
Other receivables 894 527 12,385
Due from associate – 46 29
$ 62,999 $ 57,419 $ 43,067
6. INVENTORIES
As at
December 31, 2011 December 31, 2010 January 1, 2010
(Canadian dollar in thousands)
Diluted bitumen and diluents $ 9,201 $ 4,106 $ -
Finished products 31,536 38,056 18,185
Input materials:
Crude oil, feedstocks and unfinished products 9,891 8,327 13,456
Chemicals and supplies 9,518 6,655 5,230
$ 60,146 $ 57,144 $ 36,871
The cost of inventories recognized as an expense during 2011 was $719.4 million (2010: $510.2 million).
As a result of improved commodity prices, the company reversed the previous write–down totaling $1.4 million in 2010. These reversals are included
in “blending and costs of products sold”. There were no material write–downs or reversal of write–downs in 2011.
7. OTHER Assets
As at
December 31, 2011 December 31, 2010 January 1, 2010
(Canadian dollar in thousands)
Prepayments and others $ 11,899 $ 5,585 $ 4,080
Deposits 321 10,948 10,355
Unamortized transaction costs relating to the Facility 1,153 939 1,440
Income taxes refundable – 796 2,607
Share purchase warrants (note 8.2) – – 2,711
Total 13,373 18,268 21,193
Less: non–current portion (676) (615) (3,419)
Current portion $ 12,697 $ 17,653 $ 17,774
8. Assets, LIABILITIES and Equity Classified as HELD For Sale
The major classes of assets and liabilities classified as held for sale are as follows:
As at December 31
Notes 2011 2010
(Canadian dollar in thousands)
Assets classified as held for sale
Property, plant and equipment 8.1 $ – $ 54,348
Exploration and evaluation assets 8.1 – 5,652
Investment in associate 8.2 – 27,683
Investment in share purchase warrants 8.2 – 474
Assets classified as held for sale $ – $ 88,157
Liabilities associated with assets classified as held for sale
Decommissioning liabilities 8.1 $ – $ 10,907
Equity associated with assets classified as held for sale
Accumulated other comprehensive loss 8.2 $ – $ 4,492

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8.1 Petroleum and natural gas properties
As a part of the company’s program to rationalize its conventional petroleum and natural gas properties, on November 15, 2010, the company’s
management committed to a plan to sell its conventional petroleum and natural gas properties located in Northern Alberta and Southwest
Saskatchewan. Accordingly, the carrying amount of the assets and liabilities relating to these properties was classified as held for sale on December
31, 2010. The sale of these properties was completed in 2011 for the net proceeds of $78.3 million resulting in a gain of $28.4 million.
Assets classified as held for sale are not depleted, depreciated or amortized.
8.2 Investment in associate
The following table shows the changes in the balance of investment in associate:
For the year ended December 31
2011 2010
(Canadian dollar in thousands)
Balance, beginning of year $ – $ 48,240
Effects of transactions recorded in net earnings (loss)
Share of loss – (1,999)
Dilution loss – (3,832)
Accumulated impairment – (9,763)
– (15,594)
Share of other comprehensive loss before tax – (4,963)
Balance, end of year, classified as held for sale $ – $ 27,683
As at December 31, 2010, Connacher owned 26.9 million common shares, representing 18.5 percent, of Petrolifera Petroleum Limited’s (“Petrolifera”)
issued and outstanding common shares and 6.8 million Petrolifera share purchase warrants. Petrolifera’s common shares and common share
purchase warrants were listed on Toronto Stock Exchange. Petrolifera was engaged in petroleum and natural gas exploration, development and
production facilities in South America. The investment in common shares was recorded as an investment in associate and the investment in share
purchase warrants was recorded as the derivative financial asset held for trading and recorded at fair value.
In April 2010, Petrolifera closed a public offering of 23,678,500 common shares at a price of $0.85 per common share for gross proceeds of
$20.1 million (the “Offering”). Connacher did not subscribe for shares in the Offering and accordingly, Connacher’s equity interest in Petrolifera
was reduced to 18.5 percent from 22 percent. The reduction in the ownership interest resulted in a dilution loss of $3.8 million in the year ended
December 31, 2010. In addition, $422,000 was transferred from other comprehensive loss to net earnings (loss) representing share of other
comprehensive loss of Petrolifera.
The assets relating to the associate were classified as an asset held for sale on December 31, 2010, following management’s commitment to support
the sale of all of the issued and outstanding common shares of Petrolifera to Gran Tierra Energy Inc. (“Gran Tierra Energy”). Gran Tierra Energy
entered into a Plan of Arrangement (the “Arrangement”) with Petrolifera on January 17, 2011, pursuant to which Gran Tierra Energy acquired all of the
issued and outstanding common shares and common share purchase warrants of Petrolifera.
Equity accounting ceased on December 31, 2010 upon reclassification as an asset held for sale. An impairment loss of $9.8 million on the
remeasurement of the investment in Petrolifera to the lower of its carrying amount and its fair value less costs to sell was recognized in 2010.
Upon the completion of a share exchange under the Arrangement in March 2011, the company received 3.3 million common shares and 841,000
common share purchase warrants of Gran Tierra Energy (see note 21). Connacher de-recognized the investment in Petrolifera in March 2011 and
recorded a loss of $6.8 million, including a $4.5 million transfer from other comprehensive income (loss).
In consideration for the assistance provided by the company in 2005 to Petrolifera in securing two Peruvian licenses for exploratory lands and for
the provision of financial guarantees respecting Petrolifera’s annual work commitments on the two licensed blocks, Connacher was awarded a 10
percent carried working interest (“CWI”) through the drilling of the first well on each block. Petrolifera had the right of first purchase of this CWI should
Connacher elect to sell it at some future date. The CWI is convertible at Connacher’s election into a two percent gross overriding royalty on each
license, after the drilling of the first well on each block. In 2011, Connacher was fully released from the provision of financial guarantees. Also, in
2011, Petrolifera relinquished its interest in one of the two Peruvian licenses. The company continues to own the CWI relating to the remaining license
and related rights after the completion of the transaction under the Arrangement.

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9. EXPLORATION and Evaluation assets (“E&E”)
(Canadian dollar in thousands)
Upstream Segment – Canada
Cost
Balance, January 1, 2010 $ 96,162
Additions 25,220
Disposition (172)
Transferred to assets classified as held for sale (note 8.1) (8,688)
Balance, December 31, 2010 112,522
Additions 22,399
Disposition (13,107)
Balance, December 31, 2011 $ 121,814
Accumulated amortization and impairment
Balance, January 1, 2010 $ –
Charge for the year 4,609
Transferred to assets classified as held for sale (note 8.1) (3,036)
Balance, December 31, 2010 1,573
Charge for the year 3,637
Disposition (825)
Balance, December 31, 2011 $ 4,385
Carrying amount
As at January 1, 2010 $ 96,162
As at December 31, 2010 $ 110,949
As at December 31, 2011 $ 117,429
E&E assets include unproved land and the company’s oil sands projects which are pending the determination of technical feasibility and
commercial viability.
In 2011, the company sold certain unproved properties relating to its oil sands and conventional operations for the net proceeds of $29.3 million and
recorded a gain of $17.4 million.
All of the company’s E&E assets are collateralized to secure long–term debt. See note 13.

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10. PROPERTY, Plant and Equipment
(Canadian dollar in thousands)
Petroleum and natural
gas properties (Upstream)
Refining (Downstream) Corporate Total
Cost
Balance, January 1, 2010 $ 1,029,396 $ 105,789 $ 12,272 $ 1,147,457
Additions 207,219 8,575 2,128 217,922
Dispositions (4,036) – – (4,036)
Change in decommissioning liabilities (note 14) 16,023 – – 16,023
Foreign currency translation changes – (5,887) – (5,887)
Transferred to assets classified as held for sale
(59,679) – – (59,679)
(note 8.1)
Balance, December 31, 2010 1,188,923 108,477 14,400 1,311,800
Additions 115,946 18,653 1,454 136,053
Change in decommissioning liabilities (note 14) 4,976 – – 4,976
Dispositions (8,986) – – (8,986)
Foreign currency translation changes – 2,932 – 2,932
Balance, December 31, 2011 $ 1,300,859 $ 130,062 $ 15,854 $ 1,446,775
Accumulated depletion, depreciation and impairment
Balance, January 1, 2010 $ – $ 18,075 $ 5,468 $ 23,543
Depletion and depreciation 61,604 10,470 2,330 74,404
Impairment charge 4,476 – – 4,476
Dispositions (1,676) – – (1,676)
Foreign currency translation changes – (1,284) – (1,284)
Transferred to assets classified as held for sale
(5,331) – – (5,331)
(note 8.1)
Balance, December 31, 2010 59,073 27,261 7,798 94,132
Depletion and depreciation 82,905 9,278 1,859 94,042
Impairment charge 24,700 – – 24,700
Dispositions (1,590) – – (1,590)
Foreign currency translation changes – 857 – 857
Balance, December 31, 2011 $ 165,088 $ 37,396 $ 9,657 $ 212,141
Carrying amount
At January 1, 2010 $ 1,029,396 $ 87,714 $ 6,804 $ 1,123,914
At December 31, 2010 $ 1,129,850 $ 81,216 $ 6,602 $ 1,217,668
At December 31, 2011 $ 1,135,771 $ 92,666 $ 6,197 $ 1,234,634
In May 2011, the company acquired certain petroleum and natural gas properties for cash consideration of $9.7 million. The acquisition resulted in the
allocation of $11.9 million to upstream property, plant and equipment and $2.2 million to decommissioning liabilities.
In 2011, the company sold certain petroleum and natural gas properties relating to its conventional operations for the net proceeds of $9.7 million
and recorded a gain of $2.3 million.
Due to the reduction of reserves relating to its conventional petroleum and natural gas properties, the company performed an impairment test of
its Central Alberta CGU (part of upstream segment) as at December 31, 2011 and recognized an impairment charge of $24.7 million (included
in depletion, depreciation, amortization and impairment) based on the difference between the carrying amount and the recoverable amount. The
recoverable amount was determined using the value in use calculated using a 10% discounted cash flows.
Due to a substantial decrease in natural gas prices, the company performed an impairment test of its Northwest Alberta CGU (part of upstream
segment) as at December 31, 2010 and recognized an impairment charge of $4.5 million based on the difference between the carrying amount and
the recoverable amount. The recoverable amount was determined using the fair value less costs to sell which was derived from the sale price agreed
under the binding sale agreement with the third party.
The net carrying amount at December 31, 2011, includes $21.2 million (2010: $8.6 million) of Refining (Downstream) assets in the course of
construction and not subject to depreciation.
Property, plant and equipment with a carrying cost of $1,223 million (2010: $1,205 million) is collateralized to secure long–term debt. See note 13.

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11. Trade and ACCRUED PAYABLES
As at
December 31, 2011 December 31, 2010 January 1, 2010
(Canadian dollar in thousands)
Trade payables $ 19,509 $ 10,973 $ 14,355
Accrued interest payable 32,587 13,280 15,946
Other accrued liabilities 70,093 54,514 70,303
Other payables 2,967 2,284 4,200
Taxes payable 1,211 319 –
$ 126,367 $ 81,370 $ 104,804
12. FINANCIAL INSTRUMENTS
The company’s financial instruments include its cash, trade and accrued receivables, risk management contracts, trade and accrued payables and
long–term debt. Information relating to these financial instruments including fair values is provided below.
12.1 Fair value measurements for financial instruments
Fair value estimates are made at a specific point in time, based on relevant market information and information about the financial instrument. These
estimates cannot be determined with precision as they are subjective in nature and involve uncertainties and matters of judgment.
The following table shows the comparison of the carrying and fair values of the company’s financial instruments:
December 31, 2011 December 31, 2010 January 1, 2010
(Canadian dollar in thousands)
Carrying Fair Value Carrying Fair Value Carrying Fair Value
Amount
Amount
Amount
Loans and receivables
Cash (1) $ 117,045 $ 117,045 $ 19,532 $ 19,532 $ 256,787 $ 256,787
Trade and accrued receivables (1) 62,999 62,999 57,419 57,419 43,067 43,067
Fair value through profit and loss (“FVTPL”)
Derivative financial assets (2) – – 474 474 2,711 2,711
Risk management contracts liabilities (3) 7,610 7,610 18,863 18,863 4,520 4,520
Convertible debentures (2) 98,564 98,564 96,548 96,548 92,046 92,046
Other liabilities
Trade and accrued payables (1) 126,367 126,367 81,370 81,370 104,804 104,804
Long–term debt excluding convertible debentures (4) $ 859,538 $ 830,443 $ 750,839 $ 803,872 $ 787,693 $ 800,000
(1) The fair values of cash, trade and accrued receivables and trade and accrued payables approximate their carrying amounts due to the short–term maturity of those instruments.
(2) The fair values of the derivative financial assets and convertible debentures are based on quoted market prices, a Level 1 measurement.
(3) The fair values of the risk management contracts liabilities were derived from observable market prices or indices, a Level 2 measurement.
(4) The fair values of long–term debt excluding convertible debentures have been determined based on market information.
12.2 Risk exposures
The company is exposed to market risks related to the volatility of commodity prices, foreign exchange rates and interest rates. In certain instances,
the company uses derivative instruments to manage the company’s exposure to these risks. The company is also exposed to credit risk on accounts
receivable, to counterparties to risk management contracts and to liquidity risk relating to debt and the fulfillment of its financial obligations. The
company employs risk management strategies and policies to ensure that any exposures to risk are in compliance with the company’s business
objectives and risk tolerance levels. Risk management is ultimately established by the company’s Board of Directors and is implemented and
monitored by senior management of the company.
Credit risk
Credit risk is the risk that the contracting entity will not fulfill its obligations under a contract when they are due. The company generally extends
unsecured credit to customers and therefore, the collection of accounts receivable may be affected by changes in economic or other conditions.
Management believes this risk is mitigated by the size and creditworthiness of the companies to which credit has been extended. The company has
not historically experienced any material credit loss in the collection of accounts receivable.

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Accounts receivable are due primarily from crude oil and natural gas purchasers in the petroleum and natural gas industry and Government and
large wholesale and retail purchasers of refined products. Accounts receivable are subject to normal industry credit risks. The company periodically
assesses the financial strength of its purchasers and will adjust its marketing plan to mitigate credit risks. This assessment involves a review of
external credit ratings and an internal credit review, based on the purchaser’s past financial performance. The company considers all amounts due over
90 days as past due. As at December 31, 2011, approximately $1.5 million (2010 : $1.1 million) of accounts receivable were past due primarily from
taxation authorities, all of which were considered to be collectible.
The company is also exposed to credit risk from counterparties to risk management contracts. This risk is managed by limiting counterparties to
investment grade banking institutions; there has been no history of impairment with these counterparties.
The maximum exposure to credit risk relating to the above classes of financial assets at December 31, 2011 and 2010 is the carrying amount of
these assets.
Liquidity risk
Liquidity risk is the risk that the company will not have sufficient funds to repay its debts and fulfill its financial obligations. To manage this risk,
the company pre–funds major development projects, monitors expenditures against pre–approved budgets to control costs, regularly monitors its
operating cash flow, working capital and bank balances against its business plan, maintains accessible revolving banking lines of credit and maintains
prudent insurance programs to minimize exposure to insurable losses. Additionally, the long term nature of the company’s debt repayment obligations
is aligned to the long term nature of its assets. Principal repayments are not required on the Second Lien Senior Notes until their maturity in 2018 and
2019. The company also has a revolving credit facility of $100 million (note 13.4), which gives Connacher additional short–term financial flexibility for
its working capital requirements. The following table shows the maturities of Connacher’s financial liabilities:
As at December 31, 2011
Total Within 1 year 2–5 years 6–7 years
(Canadian dollar in thousands)
Non–derivative liabilities:
Accounts payable and accrued liabilities $ 126,367 $ 126,367 $ – $ –
Long–term debt and interest payment obligations (1) 1,556,982 180,559 312,679 1,063,744
Derivative–based liabilities:
Risk management contracts $ 7,610 $ 7,610 $ – $ –
(1) USD denominated principal and interested payments are converted into Canadian dollars using exchange rate prevailing on December 31, 2011.
Market risk and sensitivity analysis
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 objective
of market risk management is to manage and control market price exposures within acceptable limits, while maximizing returns. Market risk is
comprised of commodity price risk, interest rate risk and foreign currency risk.
Commodity price risk
The company is exposed to commodity price risk as a result of potential changes in the market prices of its bitumen and refined product sales and
its crude oil and natural gas sales and purchases. In accordance with policies approved by the Board of Directors, derivative contracts, including
commodity futures contracts, price swaps and collars may be utilized to reduce exposure to price fluctuations associated with a portion of these sales
or purchases. The following table summarizes the net position of the company’s risk management contracts:
As at December 31
2011 2010
(Canadian dollar in thousands)
Current liabilities (assets)
Crude oil contracts $ 11,001 $ 8,241
Refined products contracts (5,593) –
Natural gas contracts 2,202 743
Current liabilities 7,610 8,984
Non–current liabilities
Crude oil contracts – 9,879
Non–current liabilities – 9,879
Risk management contract liabilities $ 7,610 $ 18,863

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The following tables summarize the details of the risk management contract positions:
December 31, 2011 – Crude oil contracts
Volume (bbl/d) Term Type Price
(WTI U.S.$/bbl)
Liability (Asset) as at
December 31, 2011
(Canadian dollar
in thousands)
2,000 Jan 1, 2012 – Dec 31, 2012 Swap $ 90.60 6,084
2,000 Apr 1, 2011 – Mar 31, 2012 Call option $ 96.00 1,140
2,000 Apr 1, 2011 – Mar 31, 2012 Put option $ 80.00 (97)
2,000 Jul 1, 2011 – Jun 30, 2012 Call option $ 100.00 2,220
2,000 Jul 1, 2011 – Jun 30, 2012 Put option $ 80.00 (556)
2,000 Jan 1, 2012 – Dec 31, 2012 Call option $ 120.00 1,908
2,000 Jan 1, 2012 – Dec 31, 2012 Put option $ 80.00 (2,425)
1,000 Jul 1, 2012 – Dec 31, 2012 Call option $ 98.00 2,155
1,000 Jul 1, 2012 – Dec 31, 2012 Put option $ 80.00 (893)
1,000 Jul 1, 2012 – Dec 31, 2012 Swap $ 90.50 1,465
Balance, as at December 31, 2011 11,001
December 31, 2011 – Refined products contracts
Volume (bbl/d) Term Type Price (Asset) as at December
31, 2011
(Canadian dollar
in thousands)
1,000 bbl/d Jan 1, 2012 – Mar 31, 2012 Gasoline Swap Floating price (1) + U.S. $27.50 $ (1,240)
1,000 bbl/d Jan 1, 2012 – Dec 31, 2012 Diesel Swap Floating price (1) + U.S. $32.25 (3,837)
1,000 bbl/d Apr 1, 2011 – Jun 30, 2012 Gasoline Swap Floating price (1) + U.S. $21.25 (516)
Balance, as at December 31, 2011 $ (5,593)
(1) For the calculation period, the company receives floating price which is an average WTI per barrel plus specified margin and pays average Nymex RBOB per gallon for gasoline or Platts-US Market Scan Gulf
Coast per gallon for diesel.
December 31, 2011 – Natural gas contracts
Volume (GJ/d) Term Type Price
(AECO CAD$/GJ)
Liability (Asset) as at
December 31, 2011
(Canadian dollar
in thousands)
5,000 Jan 1, 2012 – Dec 31 2012 Call option $ 4.30 $ (50)
5,000 Jan 1, 2012 – Dec 31 2012 Put option $ 3.70 1,801
5,000 Jan 1, 2012 – Dec 31 2012 Call option $ 4.00 (74)
5,000 Jan 1, 2012 – Dec 31 2012 Put option $ 2.80 525
Balance, as at December 31, 2011 $ 2,202
Subsequent to December 31, 2011, the company entered into the following additional risk management contracts:
• Crude oil collar – Jan 1, 2013 – Dec 31, 2013 – 300 bbl/d at a minimum of WTI $90/bbl and a maximum of WTI $118.30/bbl;
• Crude oil collar – Jan 1, 2013 – Dec 31, 2013 – 1,000 bbl/d at a minimum of WTI $90/bbl and a maximum of WTI $117.80/bbl;
• Crude oil collar – Jul 1, 2012 – Sept 30, 2012 – 1,000 bbl/d at a minimum of WTI $100/bbl and a maximum of WTI $118/bbl;
• Crude oil collar – Oct 1, 2012 – Dec 31, 2012 – 1,000 bbl/d at a minimum of WTI $100/bbl and a maximum of WTI $116.50/bbl;
• Crude oil swap – April 1, 2012 – June 30, 2012 – 1,000 bbl/d at C$109.40/bbl;
• Gasoline swap – April 1, 2012 – June 30, 2012 – 815 bbl/d at WTI per barrel plus US$23.00/bbl;
• Natural gas collar – Mar 1, 2012 – Jun 30, 2012 – 2,500 GJ/d at a minimum of AECO $1.85/GJ and a maximum of AECO $2.90/GJ; and
• Natural gas collar – Jul 1, 2012 – Oct 30, 2012 – 2,500 GJ/d at a minimum of AECO $1.85/GJ and a maximum of AECO $3.20/GJ.

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December 31, 2010 – Crude oil contracts
Volume (bbl/d) Term Type Price
(WTI U.S.$/bbl)
Liability (Asset) as at
December 31, 2010
(Canadian dollar
in thousands)
1,000 Jan 1, 2011 – Mar 31, 2011 Swap $ 86.10 $ 561
1,000 Jan 1, 2011 – Mar 31, 2011 Swap $ 88.10 382
2,000 Apr 1, 2011 – Jun 30, 2011 Swap $ 85.25 1,552
2,000 Jan 1, 2011 – Dec 31, 2011 Swap (1) $ 90.60 10,392
2,000 Jan 1, 2011 – Mar 31, 2011 Call option $ 100.25 162
2,000 Jan 1, 2011 – Mar 31, 2011 Put option $ 80.00 (82)
2,000 Apr 1, 2011 – Mar 31, 2012 Call option $ 96.00 5,918
2,000 Apr 1, 2011 – Mar 31, 2012 Put option $ 80.00 (2,796)
2,000 Jul 1, 2011 – Jun 30, 2012 Call option $ 100.00 5,591
2,000 Jul 1, 2011 – Jun 30, 2012 Put option $ 80.00 (3,560)
Balance, as at December 31, 2010 $ 18,120
(1) On December 30, 2011, the counterparty had a right to extend the maturity date of the contract for additional one year from January 1, 2012 to December 31, 2012 at US$ 90.60/bbl. The counter party
exercised its right to extend the contract on December 30, 2011.
December 31, 2010 – Natural gas contracts
Volume (GJ/d) Term Type Price
(AECO CAD$/GJ)
Liability as at
December 31, 2010
(Canadian dollar
in thousands)
4,000 Sept 1, 2010 – Aug 31, 2011 Swap $ 3.87 $ 187
4,000 Oct 1, 2010 – Sept 30, 2011 Swap $ 4.20 556
Balance, as at December 31, 2010 $ 743
The following table summarizes the amounts recorded in net earnings (loss) with respect to the risk management contracts:
For the year ended December 31 2011 2010
(Canadian dollar in thousands) Upstream Downstream Total Upstream Downstream Total
Unrealized (gain) loss $ (5,659) $ (5,593) $ (11,252) $ 14,343 $ – $ 14,343
Realized (gain) loss 10,161 (1,036) 9,125 2,300 543 2,843
(Gain) loss on risk management contracts $ 4,502 $ (6,629) $ (2,127) $ 16,643 $ 543 $ 17,186
As at December 31, 2011, had the forward price for WTI been U.S. $1/bbl higher or lower, the impact relating to the crude oil and refined products
risk management contracts would have been to increase or decrease, respectively, net loss before income taxes by $1.9 million.
As at December 31, 2011, had the forward price for AECO been CAD $0.10/GJ higher or lower, the impact relating to the natural gas risk
management contracts would have been to decrease or increase, respectively, net loss before income taxes by $275,000.
Interest rate risk
Interest rate risk refers to the risk that the future cash flows of a financial instrument will fluctuate because of changes in market interest rates. The
company’s Second Lien Senior Notes and Convertible Debentures have fixed interest rate obligations and, therefore, are not subject to changes
in interest rates. The Revolving Credit Facility bears floating interest rate. At December 31, 2011, the company had no debt outstanding under the
Facility. Therefore, the potential increase or decrease in net earnings or loss for each one percent change in interest rate was nil.
Currency risk
Currency risk is the risk that the fair value or future cash flows of a financial instrument will fluctuate because of changes in foreign exchange rates.
The company is exposed to fluctuations in foreign currency on its financial instruments primarily as a result of its U.S. dollar denominated long–term
debt, crude oil sales based on U.S. dollar indices and commodity price contracts that are settled in U.S. dollars. The effect on the company’s financial
instruments of a $0.01 change in the U.S. to Canadian dollar exchange rate would have resulted in a $4.7 million change in foreign exchange gain/
loss at December 31, 2011. The company’s downstream operations operate with a U.S. dollar functional currency, which gives rise to currency
exchange rate risk on translation of MRCI’s operations. The impact is recorded in other comprehensive income/loss. The effect on the company’s
financial instruments of a $0.01 change in the U.S. to Canadian dollar exchange rate would have resulted in $54,000 change in other comprehensive
income (loss) at December 31, 2011. The company manages these exchange rate risks by occasionally entering into fixed rate currency exchange
contracts on future U.S. dollar payments and U.S. dollar sales receipts. In 2011, the company entered in a fixed rate forward contract to buy US$ 5
million at 1.019 on July 22, 2012 to minimize its exposure to the foreign exchange fluctuations on its interest payments due in 2012. The unrealized
gain of $5,000 relating to this contract was recorded as a part of finance charges and other assets in 2011. Subsequent to December 31, 2011, the
company entered a fixed rate forward contract to buy US$ 5 million at 1.0175 on July 20, 2012.

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13. Long–Term Debt
As at December 31, 2011 December 31, 2010 January 1, 2010
(Canadian dollar in thousands)
Notes
Second Lien Senior Notes, due August 1, 2019
13.1 $ 559,350 $ – $ –
(US$550 million)
Second Lien Senior Notes, due August 1, 2018
13.1 350,000 – –
(CAD$350 million)
Second Lien Senior Notes, due December 15, 2015
13.2 3,474 584,168 617,294
(US$3.4 million)
First Lien Senior Notes, due July 15, 2014 (US$Nil)
13.2 – 198,920 210,200
Senior Notes, due July 15, 2014 (US$ 100,000)
Convertible Debentures, due June 30, 2012
13.5 98,564 96,548 92,046
(CAD$100 million)
Total debt 1,011,388 879,636 919,540
Unamortized discount and transaction costs (53,286) (32,249) (39,801)
Current portion of long–term debt (102,034) – –
Long–term debt $ 856,068 $ 847,387 $ 879,739
13.1 Second Lien Senior Notes issued in 2011
In May 2011, the company issued US$550 million face value 8.5% Senior Secured Second Lien Notes due August 1, 2019 and CAD$350 million
face value 8.75% Senior Secured Second Lien Notes due August 1, 2018 (the “New Notes”) at par and capitalized transaction costs of $17.6 million
relating to their issuance.
Interest is payable semi–annually on February 1 and August 1 each year the New Notes are outstanding. The New Notes are secured on a second
priority basis by liens on all of the company’s existing and future property, excluding certain pipeline assets in the USA.
Proceeds received from the sale of collateralized assets (excluding oil and gas properties for which no reserves are assigned) are required to be
re–invested in existing exploration and evaluation and petroleum and natural gas properties, to acquire new oil and gas properties or to repay the
Revolving Credit Facility (note 13.4). If such proceeds are not used for these purposes within one year, the company is required to make an offer to
repurchase the New Notes at par to the extent such proceeds exceed $25 million plus any re–invested and repaid amounts. Following an offer to
purchase the New Notes in connection with an asset sale, the company may redeem all or part of the US–dollar denominated New Notes at 108.5
percent and Canadian–dollar denominated New Notes at 108.75 percent with any remaining asset sale proceeds. As of December 31, 2011, all
asset sale proceeds have been re–invested in exploration and evaluation and petroleum and natural gas properties.
Provisions in the indenture allow the company to redeem the New Notes as follows:
• at any time prior to August 1, 2014, the company may redeem up to 35% of the US–dollar denominated New Notes at a price of 108.5 percent
and up to 35% of the Canadian–dollar denominated New Notes at the price of 108.75 percent with proceeds of certain equity offerings of at least
$10 million;
• at any time prior to August 1, 2015, the company may redeem some or all of the New Notes at their principal amount plus a make whole premium
plus applicable interest;
• after August 1, 2015, the US–dollar denominated New Notes may be redeemed at redemption prices ranging from 104.25 percent, reducing to
100 percent on August 1, 2017, and thereafter; and
• after August 1, 2015, the Canadian–dollar denominated New Notes may be redeemed at redemption prices ranging from 104.375 percent
reducing to 100 percent on August 1, 2017 and thereafter.
In the event of a Change of Control of the company, the holders of the New Notes have the right to require the company to purchase the New Notes
at a price of not less than 101 percent of the principal amount to be repurchased.
13.2 First Lien Senior Notes due 2014 and and Second Lien Senior Notes due 2015
In conjunction with the completion of the issuance of the New Notes described in note 13.1, in 2011, the company repurchased US$ 783.5 million of
the face value of the outstanding First Lien Senior Notes due 2014 and Second Lien Senior Notes due 2015 (the “Old Notes”) for cash consideration
of US$ 854.7 million (CAD$ 835.9 million). See note 13.3 for the accounting of costs associated with this transaction.
As of December 31, 2011, the company has fully redeemed its First Lien Senior Notes due 2014. The remaining amount outstanding under Second
Lien Senior Notes due 2015 are classified as current liabilities as the company redeemed these Notes in January 2012 for total cash consideration
of $3.6 million.

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13.3 Refinancing of long–term debt and realized foreign exchange gain
As a result of the issuance of the New Notes and the purchase and redemption of the Old Notes in 2011, the company performed an analysis
to determine whether the transaction was to be accounted for as a modification or an extinguishment of debt. The company determined that this
transaction resulted partially in a modification and partially as an extinguishment. Accordingly, the company recorded costs of refinancing of $36.1
million as a discount on the New Notes and approximately $61.9 million was expensed. The company also realized a foreign exchange gain of $11.6
million upon redemption of this debt.
13.4 Revolving Credit Facility
As at December 31, 2010, the company had a revolving credit facility of US$50 million. In 2011, the company entered into an Amended and Restated
Senior Secured Revolving Credit Facility (the “Facility”). The company incurred and capitalized transaction costs of approximately $817,000 on
amendment of the Facility (2010 : $251,000).
The Facility provides for revolving credit financing of up to $100 million, subject to borrowing base availability, including sub–facilities for letters of
credit, swingline loans and borrowings in Canadian dollars and U.S. dollars. The Facility has an accordion feature whereby the Company can increase
the Facility to $125.0 million. All outstanding loans under the Facility are due and payable in full on May 31, 2014.
In the case of Canadian dollar drawings, borrowings under the Facility bear interest at a rate per annum equal to the Canadian Prime Rate plus the
applicable margin; in the case of US dollar drawings at US Base Rate plus the applicable margin. The applicable margin for borrowings under the
Facility are subject to steps up and steps down based on average ratings the company’s debt as published by Moody’s and Standard and Poors.
In addition to paying interest on outstanding principal under the Facility, the company is required to pay a standby fee in respect of the unutilized
commitments thereunder, which fee is determined based on utilization of the Facility with rates established in the Facility in a similar manner to
the interest margins. The company must also pay customary letter of credit fees equal to the applicable margin. As at December 31, 2011, the
Company’s interest rate on the Facility was approximately 6.5% per annum. The Facility contains a requirement to maintain a ratio of consolidated
total debt to total capitalization of under 75% (with convertible debt treated as equity and with up to $120 million added to equity for IFRS conversion
adjustments) and borrowings under the Facility cannot exceed two times trailing adjusted EBITDA. The company has been in compliance with all
covenants throughout 2010 and 2011.
All obligations under the Facility are unconditionally guaranteed by the company, are secured by substantially all of the assets of the company,
including a first priority security interest on all of the current and future property, with the exception of certain pipeline assets in the USA.
In 2011, the company borrowed and repaid $62.9 million under the Facility. As at December 31, 2011, the company had letters of credit outstanding
under the Facility of $2.2 million. No other amounts were outstanding under the Facility.
13.5 Convertible Debentures, Due June 30, 2012
In May 2007, Connacher issued subordinated unsecured Convertible Debentures with a face value of $100,050,000. Interest is payable semi–
annually on June 30 and December 31 at the rate of 4.75 percent. The Convertible Debentures mature on June 30, 2012, unless converted prior to
that date. The Convertible Debentures are convertible at any time into common shares, at the option of the holder, at a conversion price of $5.00 per
share. The Convertible Debentures are traded on Toronto Stock Exchange.
The Convertible Debentures are redeemable on or after June 30, 2010 by the company, in whole or in part, at a redemption price equal to 100
percent of the principal amount of the Convertible Debentures to be redeemed, plus accrued and unpaid interest, provided that the market price of the
company’s common shares is at least 120 percent of the conversion price of the Convertible Debentures.
The Convertible Debenture is considered a hybrid instrument for accounting purposes with a liability and a conversion option. The conversion option
is considered an embedded derivative as the company has a choice to settle in cash in lieu of issuing shares in the event the debenture holders
exercise their option to convert the debentures. The company elected not to bifurcate this embedded derivative and designated the entire Convertible
Debentures as “fair value through profit and loss” and accordingly, recorded Convertible Debentures at fair value at each reporting period end with
changes reported within net earnings (loss).
In 2011, the company recorded unrealized loss of $2.0 million (2010: $4.5 million) on remeasurement of the Convertible Debentures to fair value. The
changes in the fair value of Convertible Debentures attributable to movements in the company’s credit risk are detailed in the table below:
For the year ended December 31
2011 2010
(Canadian dollar in thousands)
Cumulative change in the fair value $ 2,235 $ 7,671
Annual change in the fair value $ 5,436 $ 7,083
The movement in fair value due to credit risk is calculated as the amount of change in fair value that is not attributable to changes in market
conditions that give risk to market risk.

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The amount the company would contractually be required to pay at maturity was $1.5 million and $3.5 million more than the carrying amount as at
December 31, 2011 and 2010, respectively.
14. Decommissioning LIABILITIES
The following table summarizes the details of decommissioning liabilities:
For the year ended December 31
2011 2010
(Canadian dollar in thousands)
Balance, beginning of year $ 70,945 $ 53,729
Liabilities incurred 2,415 11,560
Liabilities acquired (note 10) 2,229 –
Liabilities settled (1,018) (647)
Liabilities disposed (10,483) (263)
Change in estimates 332 4,463
Unwinding of discount 1,658 2,103
Balance, end of year 66,078 70,945
Classified as held for sale – current portion (note 8) – (10,907)
Balance, non–current portion $ 66,078 $ 60,038
As a result of the analysis of the estimates of cash flows and timing to abandon and reclaim petroleum and natural gas properties and changes in
interest rates, the company recorded an increase in decommissioning liabilities of $0.3 million in 2011 (2010 : $4.5 million). At December 31, 2011,
the estimated total undiscounted amount at current cost required to settle the decommissioning liabilities was $67.6 million (2010 : $77.4 million).
These payments are expected to be made over the the next 8 to 25 years. This amount has been discounted using risk–free rates of interest ranging
between 1.66 percent to 2.42 percent, depending on the estimated time to abandon the asset.
15. RETIREMENT BENEFIT Obligation
The company maintains the following retirement/savings plans for its employees: a defined benefit pension plan for USA based employees and a
defined contribution savings plans for its USA and Canadian based employees.
15.1 Defined benefit pension plan for USA employees
The company’s USA subsidiary, MRCI, maintains a non–contributory defined benefit retirement plan (the “Defined Benefit Plan”) covering MRCI’s
employees. MRCI’s policy is to make regular contributions in accordance with the funding requirements of the United States Employee Retirement
Income Security Act of 1974, as determined by regular actuarial valuations. The company’s defined benefit obligation is based on the employees’
years of service and compensation, effective from and after, March 31, 2006, the date that Connacher acquired MRCI. The information relating to the
Defined Benefit Plan is as follows:
The amounts recognized in the balance sheet are as follows:
As at December 31
2011 2010
(Canadian dollar in thousands)
Present value of obligation $ 4,329 $ 2,607
Fair value of plan assets (1,620) (1,299)
2,709 1,308
Unrecognized actuarial loss (2,294) (1,115)
Liability recognized in balance sheet $ 415 $ 193
The amounts recognized in net earnings (loss) are as follows:
For the year ended December 31
2011 2010
(Canadian dollar in thousands)
Current service cost $ 603 $ 409
Interest on obligation 156 121
Expected return on plan assets (105) (93)
Net actuarial loss (gain) recognized 54 (11)
Total expense included in general and administrative expenses $ 708 $ 426
Actual return on plan assets $ (1) $ 133

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Changes in present value of the defined benefit obligation are as follows:
For the year ended December 31
2011 2010
(Canadian dollar in thousands)
Defined benefit obligation, beginning of year $ 2,607 $ 1,225
Current service cost 603 409
Interest cost 156 121
Actuarial loss 1,104 1,193
Benefits paid (216) (166)
Foreign exchange loss (gain) 75 (175)
Defined benefit obligation, end of year $ 4,329 $ 2,607
Changes in fair value of plan assets are as follows:
For the year ended December 31
2011 2010
(Canadian dollar in thousands)
Fair value of plan assets, beginning of year $ 1,299 $ 881
Expected return on plan assets 105 93
Actuarial (loss) gain on plan asset (106) 40
Employer contributions 504 517
Benefits paid (216) (166)
Foreign exchange gain (loss) 34 (66)
Fair value of plan assets, end of year $ 1,620 $ 1,299
The company contributed US $1.5 million to the plan in 2012.
MRCI is responsible for administering the Defined Benefit Plan and has retained the services of an independent and professional investment
manager, as fund manager, for the related investment portfolio. Among the factors considered in developing the investment policy are the Defined
Benefit Plan’s primary investment goal, rate of return objective, investment risk, investment time horizon, role of asset classes and asset allocation.
The expected rate of return on plan assets is based on historical and projected rates of return for each asset class in the plan investment portfolio.
The objective of the plan’s asset allocation policy is to manage the funded status of the plan at an appropriate level of risk, giving consideration to the
security of the assets and the potential volatility of market returns and the resulting effect on both contribution requirements and pension expense.
The long–term return is expected to achieve or exceed the return from a composite benchmark comprised of passive investments in appropriate
market indices. The asset allocation structure is subject to diversification requirements and constraints which reduce risk by limiting exposure to
individual equity investments, credit rating categories and foreign currency exposures. The composition of the plan asset is as follows:
As at December 31 2011 2010
Equity securities (percent) 58 58
Fixed income securities (percent) 38 38
Cash and cash equivalents (percent) 4 4
Total 100 100
Principal assumptions at the end of the reporting year (expressed as weighted averages):
As at December 31 2011 2010
Discount rate at December 31 (percent) 4.9 6.3
Expected return on plan assets at December 31 (percent) 7.3 8.9
Future salary increases (percent) 3.0 3.0
Expected future service life (years) 16.8 15.7

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Estimated future benefits payments under the plan are as follows:
(Canadian dollar in thousands) As at December 31, 2011
2012 $ 872
2013 125
2014 100
2015 79
2016 137
2017 to 2021 1,932
Total $ 3,245
Amounts for the current and previous three years are as follows:
As at December 31
2011 2010 2009
(Canadian dollar in thousands)
Defined benefit obligation $ 4,329 $ 2,607 $ 1,225
Plan assets (1,620) (1,299) (881)
Deficit $ 2,709 $ 1,308 $ 344
Experience adjustments on plan liabilities $ 1,104 $ 1,193 $ (755)
Experience adjustments on plan assets $ (106) $ 40 $ 72
15.2 Defined contribution savings plan for USA Employees
MRCI also maintains a defined contribution (US tax code “401(k)”) savings plan that covers all of its employees. MRCI’s contributions are based on
employees’ compensation and partially match employee contributions. In 2011, MRCI contributed $325,000 (2010 - $367,000) to this plan to satisfy,
in full, its obligation under this plan. The contribution was recognized as follows:
For the year ended December 31
2011 2010
(Canadian dollar in thousands)
Production and operating expense $ 258 $ 309
General and administrative expense 67 58
Total $ 325 $ 367
15.3 Defined contribution savings plan for Canadian employees
The company also maintains a defined contribution savings plan for its Canadian employees, whereby the company matches employee contributions
to a maximum of eight percent of each employee’s salary. In 2011, the company contributed $1.5 million (2010 – $1.4 million) to this plan to satisfy,
in full, its obligation under this plan. The contribution was recognized as follows:
For the year ended December 31
2011 2010
(Canadian dollar in thousands)
Production and operating expense $ 773 $ 746
General and administrative expense 682 623
Total $ 1,455 $ 1,369
16. INCOME TAXES
Income tax provision (recovery) recognized in net earnings (loss)
For the year ended December 31
2011 2010
(Canadian dollar in thousands)
Current income tax (provision) recovery $ (1,534) $ 291
Deferred income tax recovery 1,558 7,803
Total income tax recovery $ 24 $ 8,094
Income tax recovery recognized in other comprehensive income (loss)
For the year ended December 31
(Canadian dollar in thousands) Before tax Tax
2011
After tax Before tax Tax
2010
After tax
Share of other comprehensive income (loss) of associate $ – $ – $ – $ (4,963) $ 676 $ (4,287)

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The provision for income taxes in net loss reflects an effective tax rate which differs from the expected statutory tax rate. These differences are
presented below:
For the years ended December 31
2011 2010
(Canadian dollar in thousands)
Loss before income taxes $ 114,129 $ 52,763
Applicable tax rate 26.51% 28.05%
Expected income tax expense recovery 30,256 14,800
Impact of reduction in Canadian tax rates (1,735) (1,609)
Impact of rate adjustment on US operations (2,576) (416)
Foreign taxes (280) (752)
Capital taxes (52) (437)
Non taxable portion of foreign exchange gains and other (4,680) 2,159
Impairment and dilution loss in associate (1,813) (2,772)
Non deductible stock–based compensation costs (915) (1,408)
Effect of unused tax losses not recognized as deferred tax assets (9,083) (1,471)
Non-deductible portion of refinancing costs (9,098) –
Total income tax recovery $ 24 $ 8,094
Applicable tax rate is the aggregate of the federal income tax rate of 16.5% (2010 : 18%) and provincial tax rate of 10.01% (2010 : 10.05%). The
reduction in provincial rates year over year are due to an increased allocation of income to Alberta which is taxable at 10%.
The following is the analysis of deferred tax liabilities and assets:
2011 Opening
balance
Recognized in
net loss
Recognized
directly
in equity
Recognized in
other compprehensive
Income (loss)
Foreign
exchange
loss
Recognized
in trade
and accrued
Payables
Deferred income tax liability
Property, plant and equipment $ 175,180 $ 37,819 $ – $ – $ 344 $ – $ 213,343
Long–term debt 8,164 517 – – – – 8,681
183,344 38,336 – – 344 – 222,024
Deferred income tax asset
Losses carried forward 127,836 43,891 – – – – 171,727
Financing and share issue costs 4,885 1,008 – – – – 5,893
Decommissioning liabilities 15,926 598 – – – – 16,524
Investment in Petrolifera 274 (274) – – – – –
Risk management contracts and others 7,231 (5,329) – – – – 1,902
156,152 39,894 – – – – 196,046
Net deferred income tax liability $ 27,192 $ (1,558) $ – $ – $ 344 $ – $ 25,978
Closing
balance
2010 Opening
balance
Recognized
in net loss
Recognized
directly
in equity
Recognized in
other compprehensive
Income (loss)
Foreign
exchange
loss
Recognized in
trade and
accrued
Payables
(note 17.1)
Deferred income tax liability
Property, plant and equipment $ 136,551 $ 37,033 $ – $ – $ (676) $ 2,272 $ 175,180
Long–term debt 3,472 4,692 – – – – 8,164
140,023 41,725 – – (676) 2,272 183,344
Deferred income tax asset
Losses carried forward 85,422 42,414 – – – – 127,836
Financing and share issue costs 7,871 (3,412) 426 – – – 4,885
Decommissioning liabilities 13,475 2,451 – – – – 15,926
Investment in Petrolifera (3,181) 2,779 – 676 – – 274
Risk management contracts and others 1,935 5,296 – – – – 7,231
105,522 49,528 426 676 – – 156,152
Net deferred income tax liability $ 34,501 $ (7,803) $ (426) $ (676) $ (676) $ 2,272 $ 27,192
Closing
balance

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The following provide the details of unrecognized deductible temporary differences, unused losses and unused tax credits for which no deferred tax
asset has been recognized:
As at December 31
2011 2010
(Canadian dollar in thousands)
Non-capital losses $ 1,138 $ 1,138
Capital losses 155,700 82,202
Successor Canadian resource tax pools 4,151 4,151
Unused tax credits $ 3,388 $ 3,388
The unrecognized non-capital losses expire in 2026, capital losses and successor Canadian resource tax pool do not have a set expiration and the
unused tax credits expire in 2029 and 2030.
The company has specific tax matters under discussion with tax authorities, the outcome of which is uncertain. Where the outcome of these matters is
different from the amounts currently recorded, such differences will be recorded in net earnings (loss) in the period in which such determination is made.
17. SHARE CAPITAL
Authorized: unlimited number of common voting shares with no par value
Authorized: unlimited number of first preferred shares with no par value of which none are outstanding
Authorized: unlimited number of second preferred shares with no par value of which none are outstanding
17.1 Issued and outstanding common share capital
For the year ended December 31 2011 2010
Number Canadian dollar in
thousands
Number Canadian dollar in
thousands
Balance, beginning of year 447,167,694 $ 618,628 427,031,362 $ 593,119
Issued for cash on flow–through basis
net of premium of $2,272 – – 17,480,000 23,074
Shares issued upon exercise of stock options 810,088 752 2,017,836 1,936
Transfer from contributed surplus – share awards 282,209 534 638,496 480
Transfer from contributed surplus – stock options 423 1,082
Share issue cost, net of tax – (71) – (1,063)
Balance, end of year 448,259,991 $ 620,266 447,167,694 $ 618,628
Weighted average common shares outstanding
basic and diluted 448,024,574 432,257,947
In October 2010, the company issued 17,480,000 common shares on a flow–through basis at a price of $1.45 per common share for gross proceeds
of $25.3 million and renounced the qualifying expenditures to investors effective December 31, 2010. A premium of $2.3 million representing
the difference between the gross proceeds and the share price of the company on the date of issue was initially recognized in trade and accrued
payables and was subsequently recorded as a deferred tax provision on the renouncement of the qualifying expenditures on December 31, 2010.
18. Stock Option Plan, SHARE AWARD INCENTIVE Plan and SHARE UNIT Plan
18.1 Stock Option Plan
The company has a Stock Option Plan for all officers, employees and consultants permitting the issue from time to time of options entitling the
holders to acquire common shares. Options are granted at the discretion of the Board of Directors. The options have a term of five years to maturity
and vest annually over a two to three year period. The maximum number of common shares reserved for issuance pursuant to the Stock Option Plan
is ten percent of the issued common shares of the company from time to time, less four million common shares reserved for issuance under Share
Award Incentive Plan and less the number of common shares reserved for issuance for outstanding grants pursuant to the Share Unit Plan.

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The following table shows the changes in stock options and the related weighted average exercise prices:
For the year ended December 31 2011 2010
Number of Options
Weighted Average
Exercise Price
Number of Options
Weighted Average
Exercise Price
Outstanding, beginning of year 24,413,668 $ 1.50 22,579,045 $ 1.72
Granted 5,075,064 1.18 10,263,154 1.36
Exercised (810,088) 0.93 (2,017,836) 0.96
Forfeited (3,129,409) 1.39 (3,153,695) 2.15
Expired (475,500) 4.36 (3,257,000) 2.31
Outstanding, end of year 25,073,735 $ 1.41 24,413,668 $ 1.50
Exercisable, end of year 17,668,872 $ 1.49 13,166,750 $ 1.73
The weighted average share price on the date of exercise for the options exercised in 2011 was $1.38 per common share (2010 : $1.47).
The following table summarizes stock options outstanding and exercisable under the plan.
As at December 31 2011 2010
Range of Exercise Prices
Number
Outstanding
Number
Outstanding
Weighted
Average
Exercise Price
Weighted
Average
Remaining
Contractual Life
Weighted
Average Exercise
Price
Weighted
Average
Remaining
Contractual Life
$ 0.28 – $ 0.99 3,926,926 $ 0.72 2.9 3,598,599 $ 0.75 3.3
$ 1.00 – $ 1.99 18,699,151 1.27 3.2 17,691,857 1.26 3.9
$ 2.00 – $ 2.99 15,000 2.10 1.8 15,000 2.10 2.8
$ 3.00 – $ 3.99 2,253,649 3.62 0.6 2,573,703 3.62 1.5
$ 4.00 – $ 4.99 179,009 4.16 0.6 366,509 4.14 1.0
$ 5.00 – $ 5.99 – – – 168,000 5.04 0.2
25,073,735 $ 1.41 2.9 24,413,668 $ 1.50 3.5
At the date of grant, the weighted average fair value of stock options granted in 2011 was $0.45 per option (2010 : $0.66 per option). The fair value of
stock options granted was estimated on the date of grant using the Black–Scholes option pricing model using the following weighted average assumptions.
For the year ended ended December 31 2011 2010
Weighted average share and exercise price ($ per share) $ 1.18 $ 1.36
Risk free interest rate (percent) 1.8 1.9
Expected option life (year) 3.0 3.0
Expected volatility (percent) 54 72
Dividend yield (percent) – –
Forfeiture rate (percent) 6.5 6.0
The expected volatility measured at the standard deviation of continuously compounded share returns was based on statistical analysis of the daily
share prices over the last two years (2010 : three years).
18.2 Share Award Incentive Plan
Under the Share Award Incentive Plan, share units may be granted to non–employee directors of the company in amounts determined by the Board of
Directors on the recommendation of the Governance Committee. Share units have a one year vesting period and are settled by issuing common shares
from treasury, subject to certain limitations. The Board of Directors may alternatively elect to pay cash equal to the fair market value of the common
shares to be delivered to non–employee directors, upon vesting of such share units, in lieu of delivering common shares. The awards granted in 2011
and 2010 were expected to be settled by delivery of common shares and accordingly, were considered an equity–settled awards for accounting
purposes. The maximum number of common shares reserved for issuance under the Share Award Incentive Plan is four million common shares.
The following table summarizes the changes in Share Award Incentive Plan:
For the year ended December 31 2011 2010
Outstanding, beginning of year 380,598 648,916
Granted 375,000 380,598
Vested and settled by issuing common shares (282,209) (638,496)
Vested and settled in cash (1) (124,431) –
Cancelled (36,458) (10,420)
Outstanding, end of year 312,500 380,598
(1) In satisfaction of withholding tax requirements.

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The estimated fair value of each award granted under the Share Award Incentive Plan was $1.36 (2010 : $1.29), which is equal to the share price
at the date of the grant. The outstanding awards of 312,500 and 380,598 as at December 31, 2011 and 2010, respectively, were fully vested and
settled in January 2012 and 2011, respectively.
18.3 Share Unit Plan
In 2011, the shareholders approved a Share Unit Plan for the company. The Share Unit Plan allows for the granting of Restricted Share Units
(“RSUs”) and Performance Share Units (“PSUs”) to officers and employees of the company. An RSU represents the right of the holder to receive
one fully–paid common share for each unit granted. A PSU represents the right of the holder to receive between 0 and 2 fully–paid common shares
for each unit granted on the vesting date, depending on the performance factor applied thereto. The Board of Directors may alternatively elect to
pay cash upon vesting of such share units, in lieu of delivering common shares. The units granted in 2011 are expected to be settled by delivery of
common shares and accordingly, are considered equity–settled awards for accounting purposes. The maximum number of common shares that may
be reserved from time to time for issuance under the Share Unit Plan is five million common shares. RSUs or PSUs granted under the Plan generally
vest annually over a three year period.
The following table summarizes the changes in Share Unit Plan:
For the year ended December 31 2011 2010
Outstanding, beginning of year – –
Granted 645,616 –
Vested and Settled – –
Forfeited (56,172) –
Outstanding, end of year 589,444 –
Vested, end of year – –
The estimated fair value of each RSUs granted under the Share Unit Plan was $1.05, which is equal to the share price at the date of the grant. A
forfeiture rate of 6% was used in calculating the share–based compensation in 2011. The outstanding RSUs vest 50% on July 1, 2012 and 50% on
July 1, 2013. No PSUs were granted in 2011 under the Share Unit Plan.
18.4 Share–based compensation
For the year ended December 31
2011 2010
(Canadian dollar in thousands)
Stock Option Plan $ 2,980 $ 6,095
Share Award Incentive Plan 453 534
Share Unit Plan 258 –
Total share–based compensation 3,691 6,629
Less: Share–based compensation capitalized (238) (1,610)
Share–based compensation expensed $ 3,453 $ 5,019
18.5 Contributed surplus
For the year ended December 31
2011 2010
(Canadian dollar in thousands)
Balance, beginning of year $ 36,107 $ 31,040
Share–based compensation 3,691 6,629
Transfer to share capital – stock options exercised (423) (1,082)
Transfer to share capital – share awards settled (534) (480)
Balance, end of year $ 38,841 $ 36,107

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19. FINANCE Charges
For the year ended December 31
2011 2010
(Canadian dollar in thousands)
Interest expense on long–term debt:
Senior Notes $ 85,133 $ 91,922
Convertible Debentures 4,751 4,751
Revolving Credit Facility 275 72
Amortization of transaction costs relating to the Facility 427 752
Stand–by fees relating to the Facility 796 999
Bank charges and other fees 386 397
Unrealized loss on derivative financial asset (note 21) 152 2,237
Unwinding of discount on decommissioning liabilities (note 14) 1,658 2,103
Unrealized loss on remeasurement of convertible debentures (note 13.5) 2,015 4,502
Unrealized gain on foreign exchange contract (note 12) (5) –
95,588 107,735
Less: Interest capitalized on qualified assets – (38,290)
Finance charges $ 95,588 $ 69,445
Capitalized interest relates to the construction of the qualifying assets and has been included as a part of cost of upstream petroleum and natural gas
properties. Effective October 1, 2010, capitalization of interest ceased.
20. Foreign EXCHANGE (Gain) LOSS
For the year ended December 31
2011 2010
(Canadian dollar in thousands)
Unrealized foreign exchange loss (gain) on translation of:
U.S. denominated long–term debt $ 19,275 $ (42,552)
Foreign currency denominated cash balances 364 3,241
Other foreign currency denominated monetary items 3,341 (292)
Unrealized foreign exchange loss (gain) 22,980 (39,603)
Realized foreign exchange gain (note 13.3) (14,071) (2,038)
Foreign exchange loss (gain) $ 8,909 $ (41,641)
21. Gain (LOSS) On Disposition of Assets
The following table shows the gain (loss) on disposition of assets recognized:
For the year ended December 31
2011 2010
(Canadian dollar in thousands)
Gain on disposition of asset classified as held for sale (note 8.1) $ 28,357 $ –
Gain on disposition of exploration and evaluation assets (note 9) 17,361 366
Gain (loss) on disposition of property, plant and equipment (note 10) 2,345 (1,177)
Loss on sale of equity securities (4,606) –
Net gain (loss) on disposition of assets $ 43,457 $ (811)
Upon completion of the exchange of an investment in associate as described in note 8.2 in March 2011, the company acquired 3.3 million common
shares and 841,000 common share purchase warrants of Gran Tierra Energy Inc. The common shares and common share purchase warrants of
Gran Tierra Energy were listed on Toronto Stock Exchange. The investment in common shares was recorded at $25.7 million on the exchange with
subsequent fair value measurement changes of $9.1 million recorded in other comprehensive loss. The investment was sold in 2011 for net cash
proceeds of $21.1 million resulting in a loss of $4.6 million recorded in net earnings (loss), including the transfer of the $9.1 million from other
comprehensive loss. Each common share purchase warrant entitled the company to purchase one common share of Gran Tierra Energy for $9.62 per
common share. The common share purchase warrants expired unexercised in 2011, resulting in a loss of $152,000.
22. CAPITAL Management
The company is exposed to financial risks on its financial instruments and in the way it finances its capital requirements. The company works to
minimize its exposures to these risks through forward financial planning and with the use of financial derivatives. Connacher’s objectives in managing
its cash, debt and equity and its future capital requirements are to safeguard its ability to meet its financial obligations, to maintain a flexible capital

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structure that allows multiple financing options when a financing need or opportunity arises and to optimize its use of long–term debt and equity at an
appropriate level of risk. The company manages its capital structure and follows a financial strategy that considers economic and industry conditions,
the risk characteristics and the long–term nature of its underlying assets and its growth opportunities. It strives to continuously improve its credit rating
with the objective of reducing its cost of capital. Connacher’s current capital structure is summarized below:
As at December 31
2011 2010
(Canadian dollar in thousands)
Long–term debt (1) $ 856,068 $ 847,387
Shareholders’ equity 421,076 523,187
Total long–term debt plus equity (“capitalization”) $ 1,277,144 $ 1,370,574
Long–term debt to capitalization (2) 67% 62%
(1) Long–term debt is stated at its carrying amount, which is net of transaction costs.
(2) Calculated as long–term debt divided by the book value of shareholders’ equity plus long–term debt.
The long–term debt agreements contain certain provisions, which restrict the company’s ability to incur additional indebtedness, pay dividends, make
certain payments and dispose of collateralized assets.
23. CASH flow information
Changes in non–cash working capital
As at December 31
2011 2010
(Canadian dollar in thousands)
Trade and accrued receivables $ (4,752) $ (15,618)
Inventories (2,277) (21,802)
Other assets 6,061 (173)
Trade and accrued payables 20,535 (21,166)
Total $ 19,567 $ (58,759)
Relating to:
Operations $ 14,048 $ (23,962)
Investing 5,519 (34,797)
Total $ 19,567 $ (58,759)
Non–cash transaction
In 2011, the company received 3.3 million common shares and 841,000 common share purchase warrants of Gran Tierra Energy in exchange for the
interest in associate. See note 8.2 and 21. There were no significant non–cash transactions in 2010.
24. RELATED PARTY Transactions
Subsidiaries
Details of the company’s subsidiaries at the end of December 31, 2011, December 31, 2010 and January 1, 2010 are as follows:
Name of subsidiary Principal activity Place of incorporation
and operation
Proportion of
ownership interest
Great Divide Holding Corporation Holding company Canada 100
Great Divide Pipeline Corporation Petroleum and natural gas USA 100
Great Divide Pipeline Limited Petroleum and natural gas Canada 100
Montana Refining Company, Inc Refining USA 100
Balances and transactions between Connacher and its subsidiaries have been eliminated on consolidation and are not disclosed in this note. Details
of transactions between the company and other related parties are disclosed below.
Associate
Under the terms of an Administrative Services Agreement, dated January 1, 2008 with Petrolifera, Connacher provided certain general and
administrative services to Petrolifera. The fee for this service was $15,000 per month. Petrolifera paid Connacher $45,000 in 2011 (2010: $180,000)
under the Administrative Services Agreement. Petrolifera also reimbursed Connacher for certain other out–of–pocket expenses incurred by
Connacher on Petrolifera’s behalf. The agreement was terminated upon closing of the transaction under the Plan of Arrangement. See note 8.2.
The company also rented a portion of its office building to Petrolifera on sublease. The company recovered rental expenses of $30,000 in 2011
(2010: $137,000). The sublease was terminated upon completion of the transaction under the Plan of Arrangement. See note 8.2.

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Compensation of key management personnel
Key management personnel include directors and executive officers of Connacher. The compensation paid or payable to key management for services
is shown below:
For the year ended December 31
2011 2010
(Canadian dollar in thousands)
Short–term employee benefits $ 4,309 $ 4,353
Post–employment benefits 197 229
Termination benefits – 312
Other long–term benefits 96 103
Share–based payments 1,217 2,031
$ 5,819 $ 7,028
The company has management contracts with executive officers that require the company to pay a lump sum payment in case of loss of employment
under certain circumstances as prescribed in these contracts. Subsequent to December 31, 2011, the company paid approximately $5.5 million under
these contracts as compensation for loss of employment.
The stock options, awards and units held by key management personnel under the Stock Option Plan, Share Award Incentive Plan and Share Unit
Plan were as follows:
As at December 31 2011 2010
Stock options
Number of options (number in 000) 7,583 7,776
Weighted average exercise price ($ per share) $ 1.75 $ 1.86
Weighted average remaining life (years) 2.4 3.0
Share awards
Number of awards (number in 000) 313 381
Weighted average remaining life (years) 4 4
Share units
Number of units (number in 000) 141 –
Weighted average remaining life (years) 4.6 –
25. Operating LEASE Arrangements
Lease arrangements
Operating leases relate to the lease of office space, rail cars and other equipment with terms ranging from 1 to 7 years. Certain of the leases entitle
the company to renew the lease at the end of its lease term at then current market rates. The company does not have any material purchase options
within its operating lease arrangements.
Payments recognized as expense or capitalized
For the year ended December 31
2011 2010
(Canadian dollar in thousands)
Minimum lease payments expensed – production, operating and transportation $ 1,574 $ 725
Minimum lease payments expensed – general and administrative 5,390 2,714
Minimum lease rentals received under sublease (151) (575)
Total expense charged 6,813 2,864
Minimum lease payments capitalized as a part of property, plant and equipment 606 1,409
Total minimum lease payments recognized under operating lease $ 7,419 $ 4,273
Non–cancellable operating lease commitments
As at December 31
2011 2010
(Canadian dollar in thousands)
No later than 1 year $ 5,284 $ 3,243
Later than 1 year but no later than 5 years 20,212 11,738
Later than 5 years 1,545 4,923
Total minimum lease payments under operating lease $ 27,041 $ 19,904

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26. Commitments
Capital expenditure commitments
As at December 31
2011 2010
(Canadian dollar in thousands)
Commitments relating to the acquisition of property, plant and equipment $ – $ 1,566
Service and maintenance commitments
The company is also contractually committed under certain contracts for the service and maintenance of facilities and equipment. The following table
provides the details of these commitments:
As at December 31
2011 2010
(Canadian dollar in thousands)
No later than 1 year $ 8,487 $ 4,104
Later than 1 year but no later than 5 years 20,584 12,171
Later than 5 years 16,800 38,702
Total commitments $ 45,871 $ 54,977
The primary service and maintenance commitment of the company included above relates to power infrastructure costs of $31.8 million as at
December 31, 2011.
27. First TIME ADOPTION of IFRS
As described in note 2, these are the company’s first consolidated financial statements prepared in accordance with IFRS. As a result, these
consolidated financial statements have been prepared in accordance with IFRS 1, “First–time Adoption of International Financial Reporting Standards”.
IFRS 1 requires the presentation of comparative information as at the January 1, 2010 (the “transition date”) and subsequent comparative periods
using the consistent and retrospective application of IFRS accounting policies. However, to assist with the transition, the provisions of IFRS 1 allow
for certain mandatory exceptions and optional exemptions from the requirement of retrospective application of accounting policies and standards on
first–time adoption of IFRS. Accordingly, these consolidated financial statements were prepared using the accounting policies stated in note 3 of the
consolidated financial statements and were retrospectively and consistently applied except where specific IFRS 1 mandatory exceptions and optional
exemptions required or permitted an alternative treatment upon transition to IFRS for first–time adopters. The significant mandatory exceptions and
optional exemptions applied under IFRS 1 in preparing these consolidated financial statements are set out below:
Deemed cost election for petroleum and natural gas properties
Under previous GAAP, the company followed the “full cost” method of accounting for petroleum and natural gas activities under which all costs directly
associated with the acquisition of, the exploration for, and the development of petroleum and natural gas reserves were capitalized on a country–
by–country cost centre basis. The company had one cost centre, Canada, for the upstream segment. Costs accumulated within this one cost centre
were depleted using the unit–of–production method based on proved reserves determined using estimated future prices and costs. Upon transition
to IFRS, the company was required to adopt new accounting policies for upstream activities, including the segregation of exploration and evaluation
costs and petroleum and natural gas properties. Under IFRS, exploration and evaluation costs are those expenditures for which technical feasibility
and commercial viability has not yet been determined, are presented separately on the balance sheet as exploration and evaluation assets and may
or may not be amortized based on the company’s accounting policy. Petroleum and natural gas properties include those expenditures where technical
feasibility and commercial viability has been determined, are presented as a part of property, plant and equipment on the balance sheet and are
depleted and depreciated on a segregated basis based on the company’s accounting policy. The company adopted the IFRS 1 exemption whereby the
company deemed its January 1, 2010 IFRS upstream asset costs to be equal to its previous GAAP historical upstream property, plant and equipment
net book value. Accordingly, exploration and evaluation costs were deemed equal to the unproved properties balance and the petroleum and natural
gas properties costs were deemed equal to the remaining upstream full cost pool balance. The petroleum and natural gas property costs were
allocated for depletion, depreciation and impairment testing purposes on a pro rata basis using proved reserves values at the transition date.
Leases
The company elected not to reassess whether an arrangement contained a lease under IFRIC 4, “Determining whether an Arrangement contains a
Lease”, for contracts that were assessed under previous GAAP.
Business combinations
IFRS 3, “Business Combinations” was not applied to business combinations that occurred before the transition date.
Borrowing costs
Borrowing costs directly attributable to the acquisition or construction of qualifying assets were not retrospectively restated prior to the transition date.

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Estimates
Hindsight was not used to create or revise estimates and accordingly, the estimates made by the company under previous GAAP are consistent with
their application under IFRS.
Additional exemptions applied
The company applied additional exemptions for cumulative foreign currency translation differences, share-based compensation, asset retirement
obligations/decommissioning liabilities and accounting for its investment in associate, which are explained in notes 27.4, 27.5, 27.6 and 27.7, respectively.
The following reconciliations present the adjustments made to the company’s previous GAAP financial results of operations and financial position to
comply with IFRS 1. A summary of the significant accounting policy changes and applicable exemptions are discussed following the reconciliations.
Reconciliations include the company’s consolidated balance sheets as at December 31, 2010 and January 1, 2010 and the consolidated statements
of operations and comprehensive loss for the year ended December 31, 2010.
Reconciliation of Consolidated Balance Sheet
As at January 1, 2010
(Canadian dollar in thousands)
IFRS Adjustments
Previous E&E Impairment
Foreign Compen– ARO Associate Taxes Debt IFRS
GAAP
Currency sation
ASSETS Notes 27.1 27.2 27.4 27.5 27.6 27.7 27.8 27.9
CURRENT ASSETS
Cash $ 256,787 $ – $ – $ – $ – $ – $ – $ – $ – $ 256,787
Trade and accrued receivables 43,067 – – – – – – – – 43,067
Inventories 36,871 – – – – – – – – 36,871
Other assets 17,774 – – – – – – – – 17,774
Deferred tax assets 2,348 – – – – – – (2,348) – –
356,847 – – – – – – (2,348) – 354,499
NON–CURRENT ASSETS
Other assets 708 – – – – – 2,711 – – 3,419
Investment in associate 50,379 – – – – – (2,139) – – 48,240
Exploration and evaluation assets – 96,162 – – – – – – – 96,162
Property, plant and equipment 1,230,256 (96,162) (10,180) – – – – – – 1,123,914
Goodwill 103,676 – (103,676) – – – – – – –
1,385,019 – (113,856) – – – 572 – – 1,271,735
$ 1,741,866 $ – $ (113,856) $ – $ – $ – $ 572 $ (2,348) $ – $ 1,626,234
LIABILITIES AND SHAREHOLDERS’ EQUITY
CURRENT LIABILITIES
Trade and accrued payables $ 105,620 $ – $ – $ – $ (816) $ – $ – $ – $ – $ 104,804
Risk management contracts 4,520 – – – – – – – – 4,520
110,140 – – – (816) – – – – 109,324
NON–CURRENT LIABILITIES
Long–term debt 876,181 – – – – – – – 3,558 879,739
Decommissioning liabilities 32,848 – – – – 20,881 – – – 53,729
Retirement benefit obligation 1,066 – – – (722) – – – – 344
Deferred income taxes 50,043 – (2,545) – – (5,237) 72 (7,832) – 34,501
960,138 – (2,545) – (722) 15,644 72 (7,832) 3,558 968,313
SHAREHOLDERS’ EQUITY
Share capital 590,845 – – – – – – 2,274 – 593,119
Equity component of convertible
16,817 – – – – – – – (16,817) –
debentures
Contributed surplus 30,560 – – – 480 – – – 31,040
Retained Earnings (Deficit) 49,544 – (111,311) (16,178) 1,058 (15,644) 1,127 3,210 13,259 (74,935)
Accumulated other
comprehensive loss (16,178) – – 16,178 – – (627) – (627)
671,588 – (111,311) – 1,538 (15,644) 500 5,484 (3,558) 548,597
$ 1,741,866 $ – $ (113,856) $ – $ – $ – $ 572 $ (2,348) $ – $ 1,626,234

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Reconciliation of Consolidated Balance Sheet
As at December 31, 2010
(Canadian dollar in thousands)
Previous
GAAP
E&E
AHFS &
Disposi–
tion
Foreign
Currency
IFRS Adjustments
DD&A and
Impairment
Compensation
ARO Associate Taxes Debt IFRS
ASSETS Notes 27.1 27.2 27.3 27.4 27.5 27.6 27.7 27.8 27.9
CURRENT ASSETS
Cash $ 19,532 $ – $ – $ – $ – $ – $ – $ – $ – $ – $ 19,532
Trade and accrued receivables 57,419 – – – – – – – – – 57,419
Inventories 57,144 – – – – – – – – – 57,144
Other assets 17,653 – – – – – – – – – 17,653
Deferred tax assets 4,497 – – – – – – – (4,497) – –
Assets held for sale – – – 60,000 – – – 28,157 – – 88,157
156,245 – – 60,000 – – – 28,157 (4,497) – 239,905
NON–CURRENT ASSETS
Other assets 615 – – – – – – – – – 615
Investment in associate 27,938 – – – – – – (27,938) – – –
Exploration and evaluation assets – 120,844 (4,609) (5,286) – – – – – – 110,949
Property, plant and equipment 1,395,524 (121,808) (4,266) (60,001) – (53) 11,685 – (3,413) – 1,217,668
Goodwill 103,676 – (103,676) – – – – – – – –
1,527,753 (964) (112,551) (65,287) – (53) 11,685 (27,938) (3,413) – 1,329,232
$ 1,683,998 $ (964) $ (112,551) $ (5,287) $ – $ (53) $ 11,685 $ 219 $ (7,910) $ – $ 1,569,137
LIABILITIES AND SHAREHOLDERS’ EQUITY
CURRENT LIABILITIES
Trade and accrued payables $ 81,886 $ – $ – $ – $ – $ (516) $ – $ – $ – $ – $ 81,370
Risk management contracts 8,984 – – – – – – – – – 8,984
Liabilities relating to
assets held for sale – – – 10,907 – – – – – – 10,907
90,870 – – 10,907 – (516) – – – – 101,261
NON–CURRENT LIABILITIES
Risk management contracts 9,879 – – – – – – – – – 9,879
Long–term debt 843,601 – – – – – – – – 3,786 847,387
Decommissioning liabilities 39,191 – – (10,907) – – 31,754 – – – 60,038
Retirement benefit obligation 915 – – – – (722) – – – – 193
Deferred income tax 49,359 (242) (2,237) (1,331) – – (6,108) (636) (11,613) – 27,192
942,945 (242) (2,237) (12,238) – (722) 25,646 (636) (11,613) 3,786 944,689
SHAREHOLDERS’ EQUITY
Share capital 611,599 – – – – (522) – – 7,551 – 618,628
Equity component of debentures 16,817 – – – – – – – – (16,817) –
Contributed surplus 35,503 – – – – 604 – – – – 36,107
Retained earnings (Deficit) 10,746 (722) (110,314) (3,956) (16,178) 1,103 (13,961) 4,495 (3,848) 13,031 (119,604)
Accumulated other
comprehensive loss (24,482) – – – 16,178 – – 852 – – (7,452)
Accumulated other comprehensive
loss for assets held for sale – – – – – – – (4,492) – – (4,492)
650,183 (722) (110,314) (3,956) – 1,185 (13,961) 855 3,703 (3,786) 523,187
$ 1,683,998 $ (964) $ (112,551) $ (5,287) $ – $ (53) $ 11,685 $ 219 $ (7,910) $ – $ 1,569,137

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Reconciliation of Consolidated Statement of Operations and Comprehensive Loss
For the year ended December 31, 2010
(Canadian dollar in thousands)
Previous
GAAP
E&E
DD&A and
Impair-ment
AHFS &
Disposi–tion
IFRS Adjustments
Compensation
ARO Associate Taxes Reclass Debt IFRS
INCOME Notes 27.1 27.2 27.3 27.5 27.6 27.7 27.8 27.10 27.9
Revenue $ 589,931 $ – $ – $ – $ – $ – $ – $ – $ – $ – $ 589,931
Interest and other income 256 – – – – – – – – – 256
590,187 – – – – – – – – – 590,187
EXPENSES
Blending and costs of products sold 347,467 – – – – – – – (3,885) – 343,582
Production and operating 101,148 – – – – – – – – – 101,148
Transportation and handling 26,772 – – – – – – – – 26,772
General and administrative 19,921 – – – – – – 3,885 – 23,806
Share–based compensation 5,063 – – – (44) – – – – – 5,019
Exploration and evaluation 964 – – – – – – – – 964
Depletion, depreciation, amortization 79,586 – (1,305) 4,476 – – – – (2,915) – 79,842
and impairment
Loss on risk management contracts 17,186 – – – – – – – – – 17,186
Finance charges 64,877 – – – (812) 2,237 – 2,915 228 69,445
Foreign exchange gains (41,641) – – – – – – – – – (41,641)
Loss on disposition of assets – – – 811 – – – – – – 811
Share of interest in associate 21,393 – – – – – (5,377) – – – 16,016
641,772 964 (1,305) 5,287 (44) (812) (3,140) – – 228 642,950
EARNINGS (LOSS) BEFORE TAX (51,585) (964) 1,305 (5,287) 44 812 3,140 – – (228) (52,763)
Income tax (expense) recovery 12,787 242 (308) 1,331 – 871 228 (7,057) – – 8,094
NET EARNINGS (LOSS) (38,798) (722) 997 (3,956) 44 1,683 3,368 (7,057) – (228) (44,669)
OTHER COMPREHENSIVE LOSS
AFTER TAX
Exchange differences on translating (7,452) – – – – – – – – – (7,452)
foreign operations
Share of other comprehensive loss (852) – – – – – (3,435) – – – (4,287)
of associate
Transfer on loss of ownership – – – – – – 422 – – – 422
OTHER COMPREHENSIVE
(8,304) – – – – – (3,013) – – – (11,317)
LOSS AFTER TAX
TOTAL COMPREHENSIVE LOSS $ (47,102) $ (722) $ 997 $ (3,956) $ 44 $ 1,683 $ 355 $ (7,057) $ – $ (228) $ (55,986)
LOSS PER SHARE
Previous
IFRS
GAAP
Basic and diluted (note 27.12) $ (0.09) $ (0.10)
27. FIRST time adoption of IFRS (continued)
27.1 Exploration and Evaluation (“E&E”)
As explained above under “Deemed cost election for petroleum and natural gas properties”, the company reclassified $96.2 million and $120.8 million
to exploration and evaluation assets at January 1, 2010 and December 31, 2010, respectively, based on the deemed carrying amounts representing
the unproved properties balance as determined under previous GAAP.
Additionally, under IFRS, costs incurred prior to obtaining the legal rights to explore are expensed whereas under previous GAAP these costs were
capitalized as part of property, plant and equipment. Accordingly, the company recognized exploration and evaluation expense in net earnings (loss)
of $964,000 in the year ended December 31, 2010 and recorded the corresponding decrease to the property, plant and equipment. This adjustment
also resulted in an equivalent decrease in cash flow from operating activities under IFRS compared to the reported amounts under previous GAAP.
The effect of the above adjustment on retained earnings (deficit) was a reduction of $722,000 after tax benefits of $242,000 for the year ended
December 31, 2010.

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27.2 Depletion, Depreciation and Amortization (“DD&A”) and Impairment
Depletion, depreciation and amortization
As explained above under “Deemed cost election for petroleum and natural gas properties”, petroleum and natural gas properties at January 1, 2010
were deemed to be $1,029 million, representing the upstream full cost pool balance under previous GAAP and were presented as property, plant
and equipment.
Under previous GAAP, petroleum and natural gas properties were depleted using the unit–of–production method calculated for one Canada cost
centre. Under IFRS, petroleum and natural gas properties are depleted using the unit–of–production method based on estimated proved and probable
reserves determined using estimated future prices and costs calculated at the established area level. Further, as permitted under IFRS, the company
elected to amortize certain exploration and evaluation assets (undeveloped land) over the lease term. Under previous GAAP, undeveloped land was
tested for impairment and any resulting impairment was included in the full cost pool for depletion purposes. As a result, DD&A decreased by $1.3
million in the year ended December 31, 2010 with a corresponding change to exploration and evaluation assets and property, plant and equipment.
The effect of the above adjustment on deficit was a decrease of $1.0 million after tax benefits of $0.3 million for the year ended December 31, 2010.
Impairment
Under previous GAAP, capitalized costs of petroleum and natural gas properties and goodwill were tested for impairment separately whereas
under IFRS, capitalized costs of petroleum and natural gas properties and goodwill are allocated to cash–generating units (“CGU’s) for impairment
testing purposes.
Under previous GAAP, impairment of petroleum and natural gas properties was recognized if the carrying amount exceeded the undiscounted cash
flows from proved reserves for a country cost centre. Impairment was measured as the amount by which the carrying amount exceeded the sum
of the fair value of proved and probable reserves and the costs of unproved properties. The company did not report any impairment under previous
GAAP on December 31, 2009 and 2010.
Under previous GAAP, goodwill was tested with reference to the reporting unit. All assets and liabilities, including goodwill were allocated to the
company’s segments, referred to as reporting units. To initially test impairment, the fair value of each reporting unit was determined and compared
to the carrying amount of the reporting unit. If the fair value of the reporting unit was less than the carrying amount, a second test was performed to
determine the amount of the impairment. The amount of the impairment was determined by deducting the fair value of the reporting unit’s assets and
liabilities from the fair value of the reporting unit to determine the implied fair value of goodwill and comparing that amount to the carrying amount of
the reporting unit’s goodwill. Under previous GAAP, the goodwill was allocated to the upstream reporting unit and was not considered impaired.
Under IFRS, impairment is recognized if the carrying amount for a CGU exceeds the recoverable amount. A CGU is defined as the smallest
identifiable group of assets that generates cash inflows that are largely independent of the cash inflows from other assets or group of assets. If the
carrying amount of the CGU exceeds the recoverable amount, the CGU is written down with the impairment recognized in net earnings (loss). The
recoverable amount is determined as the higher of value in use and fair value less cost to sell where value in use is the present value of the future
cash flows expected to be derived from continuing use of the CGU and fair value less cost to sell is the estimated amount obtainable from the sale of
the CGU in an arm’s length transaction between knowledgeable and willing parties, less costs of disposal.
IFRS requires the performance of a goodwill impairment test upon the transition date. The company performed an impairment test by allocating all
capitalized costs of petroleum and natural gas properties, goodwill and directly related liabilities to applicable cash–generating units based on their
ability to generate largely independent cash flows (a lower level than previous GAAP) and determined that an impairment charge of $113.9 million on
January 1, 2010 was required. Of the total impairment charge, $103.7 million was allocated to goodwill and $10.2 million was allocated to petroleum
and natural gas properties with the corresponding increase to deficit of $111.3 million, net of tax benefits of $2.6 million.
The recoverable amount used in the impairment calculation was determined using the value in use, calculated using a discounted cash flow model.
The company engaged an independent firm of reserve evaluators to estimate the company’s petroleum and natural gas reserves. The cash flows
used in the valuation were derived from this report. The cash flow projections used by the company in the impairment assessment covered a period
of 5 years which the company determined to be appropriate production profile for the assets in Northern Alberta CGU, which primarily contained dry
natural gas.
The key assumptions used included natural gas prices, production volumes, operating costs, future capital expenditure and the discount rate as
follows: The AECO natural gas price assumption was an average of $5.96/mmBtu in 2010, $6.79/mmBtu in 2011, $6.89/mmBtu in 2012, $6.95/
mmBtu in 2013, $7.05/mmBtu in 2014. Production volumes were estimated taking into account existing natural gas reserves and well capability.
Future capital expenditures were estimated based on the company’s budget allocated to the CGU and operating costs were estimated based on
historical experience adjusted for inflation at a rate of 2%. The future cash flows were discounted using a discount rate of 14%.

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27.3 Asset and Liabilities Held For Sale (“AHFS”) and Disposition of Petroleum and Natural Gas Properties
Under previous GAAP, the proceeds from disposition of petroleum and natural gas properties were deducted from the full cost pool without
recognition of a gain or loss and the accounting standard for classification of assets and liabilities as held for sale was not applicable to the disposition
of petroleum and natural gas properties, unless the impact of the disposition was expected to result in a change to the DD&A rate of 20 percent or
greater, in which case a gain or loss was recorded and assets and liabilities were classified as held for sale.
Under IFRS, gains or losses are recorded on dispositions and are calculated as the difference between the proceeds and the net book value of the asset
disposed of, and the requirements of the classification of assets and liabilities as held for sale are applicable to all petroleum and natural gas properties.
As explained in note 8.1, the company classified its assets and liabilities relating to certain petroleum and natural gas properties as held for sale
on December 31, 2010 and recorded them at the lower of their carrying amount or fair value less costs to sell. The adjustment resulted in a
reclassification of the carrying amount of property, plant and equipment totaling $54.3 million, exploration and evaluation assets totaling $5.7 million
and asset retirement obligation/decommissioning liabilities totaling $10.9 million to assets and liabilities classified as held for sale as at December
31, 2010. At December 31, 2010, an impairment charge of $4.5 million was recognized as depletion, depreciation, amortization and impairment based
on the difference between the December 31, 2010 carrying amount of the assets prior to reclassification and the estimated recoverable amount.
The recoverable amount was determined using fair value less costs to sell which was based on the the sale price subsequently agreed to under the
binding sale agreements with the third party. See note 10.
During the year ended December 31, 2010, the company recognized a loss of $0.8 million on the sale of minor petroleum and natural gas properties
and exploration and evaluation assets.
The effect of the above adjustments on deficit was a reduction of $3.9 million after tax benefits of $1.3 million for the year ended December 31, 2010.
27.4 Foreign Currency
In accordance with IFRS 1, the company has elected to deem all foreign currency translation differences that arose prior to the transition date in
respect of foreign operations and the company’s share of associate’s translation differences to be nil and reclassified amounts recorded in other
comprehensive loss as determined in accordance with previous GAAP to Retained Earnings (Deficit). As a result, accumulated other comprehensive
loss was decreased by $16.2 million with a corresponding increase to deficit as at January 1, 2010.
27.5 Compensation
Share-based payments
In accordance with IFRS 1, the company has elected to apply the requirements of IFRS 2 “Share–Based Payment” to those equity instruments
that were issued after November 7, 2002 but that had not vested as of January 1, 2010. The company had two equity compensation plans on the
transition date.
Employee Stock Option Plan – previous GAAP allowed the company to choose an accounting policy of recording the estimate of forfeiture either
on the date of the grant or by recording it in the period when forfeiture actually occurred. The company’s accounting policy had been to record
forfeitures in the period when they occurred. IFRS requires entities to measure the estimate of forfeiture at the time of grant. As a result, share–based
compensation expense and property, plant and equipment were decreased with a corresponding decrease to contributed surplus for the year ended
December 31, 2010. The impact of the estimate of the forfeitures on the unvested options as of January 1, 2010 was not material and no adjustment
was required on January 1, 2010.
Share Award Incentive Plan – Under previous GAAP, awards issued under share award incentive plan were considered a liability award and were
revalued at each reporting period end with changes recorded in net earnings (loss) and the corresponding amounts recorded in trade and accounts
payable. Under IFRS 2, awards issued under the share award plan are equity–settled awards and recorded on the date of grant using the grant date
fair value. The grant date fair value is determined based on the quoted market price of the company’s common shares on the date of grant. As a result,
share–based compensation was decreased to reflect the removal of the impact of revaluation recorded under previous GAAP. Additionally the related
share–based compensation which was reported as a part of trade and accounts payables under previous GAAP was reclassified to contributed
surplus. On January 1, 2010, the company reclassified $816,000 from trade and accounts payables, removed prior revaluation from Retained
Earnings (Deficit) totaling $336,000 and recorded the remaining amount of $480,000 to contributed surplus representing the value of outstanding
awards on the transition date.
The effect of the above share based payments adjustments was an increase of $44,000 to deficit, a reduction to property, plant and equipment
of $53,000, a reduction to trade and accounts payables of $516,000 and an increase to contributed surplus of $604,000 for the year ended
December 31, 2010.
Defined benefit plan
The company elected to use the IFRS 1 exemption whereby the cumulative unamortized net actuarial gains and losses of the company’s defined
benefit plan were charged to deficit on January 1, 2010. This resulted in a decrease of $722,000 to the accrued benefit obligation and a
corresponding decrease to deficit.

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27.6 Asset Retirement Obligation (“ARO”) / Decommissioning liabilities
Under previous GAAP, the asset retirement obligation was measured at estimated fair value determined using estimated future cash outflows
discounted using a credit–adjusted risk free interest rate and the liability was not remeasured to reflect period end discount rates. Under IFRS, the
asset retirement obligation has been named “decommissioning liabilities”, fair value is measured as the best estimate of the future expenditures to be
incurred discounted at a risk free interest rate, and decommissioning liabilities are remeasured using the period end discount rate.
In conjunction with the IFRS 1 exemption regarding petroleum and natural gas properties discussed above, the company was required to remeasure
its decommissioning liabilities upon transition to IFRS and recognize the difference in Retained Earnings (Deficit). The application of this exemption
resulted in a $20.9 million increase to decommissioning liabilities on the company’s consolidated balance sheet as at January 1, 2010 and a charge
to Retained Earnings (Deficit) of $15.6 million net of tax benefits of $5.2 million. Subsequent IFRS remeasurements of decommissioning liabilities are
recorded through property, plant and equipment with an offsetting adjustment to decommissioning liabilities. As at December 31, 2010, excluding the
January 1, 2010 adjustment, the company’s decommissioning liabilities increased by $10.9 million which primarily reflects the remeasurement of the
obligation using the company’s discount rate of 3.2 percent as at December 31, 2010. The use of the lower discount rate resulted in a decrease in
the provision for unwinding of the discount totaling $812,000 for the year ended December 31, 2010.
27.7 Investment in Associate
As at January, 1, 2010 and December 31, 2010, the company owned 26.9 million Petrolifera common shares, representing 22 percent as at January
1, 2010 and 18.5 percent as at December 31, 2010 of Petrolifera’s issued and outstanding common shares, and 6.8 million Petrolifera share
purchase warrants. Petrolifera was accounted for as an equity investment in associate. The following are the key differences in IFRS compared to
previous GAAP.
• Petrolifera was a public company and prepared 2010 and previous financial statements in accordance with Canadian generally accepted
accounting principles similar to the company’s reporting in 2010 and previous years. Accordingly, the company’s share of loss, other
comprehensive loss, dilution loss and associated deferred tax recorded in 2010 and previous years were based on previous GAAP amounts
reported by Petrolifera. As a part of the company’s transition to IFRS, the company recorded the adjustments to its share of loss, other
comprehensive loss and dilution loss with a corresponding effect on the investment account balance and Retained Earnings (Deficit) reflecting the
adjustments to conform Petrolifera’s financial position and results of operations in accordance with IFRS and the accounting policies adopted by
the company on the transition date.
• In 2009, Petrolifera completed an equity financing under which Petrolifera issued 66.5 million common share units. Each unit was comprised of
one Petrolifera common share and one–half Petrolifera share purchase warrant. Connacher subscribed for 13,556,000 units at a cost of $11.9
million. Each full Petrolifera share purchase warrant entitled the holder to purchase one Petrolifera common share at a price of $1.20 per common
share for a period of two years from issuance. These share purchase warrants were listed on Toronto Stock Exchange.
Under previous GAAP, the total cost of $11.9 million was recorded as an investment in equity–accounted for investment on the consolidated balance
sheet. Under IFRS, share purchase warrants meet the definition of a derivative asset that should be bifurcated from the host contract (investment in
associate) and recorded at fair value on each reporting period end with changes recorded in net earnings (loss). As a result, the company recorded
the fair value of share purchase warrants on January 1, 2010 by increasing other assets and decreasing deficit. In addition, the company recorded an
unrealized loss of $2.2 million in 2010 representing the change in fair value of this derivative financial asset.
• In April 2010, Petrolifera issued common shares as a part of equity financing and the company did not subscribe for shares in this financing.
Accordingly, the company’s equity interest in Petrolifera was reduced to 18.5 percent from 22 percent. The reduction in the ownership interest
resulted in a dilution loss which is required to be recorded under both under previous GAAP and IFRS in net earnings (loss). However, the amount
of dilution loss under IFRS is different due to IFRS adjustments recorded in the investment account balance as discussed above. Further, IFRS
requires the reclassification at the time of dilution of a proportionate amount of gain or loss previously recognized in other comprehensive loss to
net earnings (loss). Accordingly, the company recorded a transfer of $422,000 in 2010 from other comprehensive loss to net earnings (loss) and
reported within share of interest in associate.
• As explained in note 8.2, under IFRS, assets relating to the investment in Petrolifera were classified as assets held for sale on December 31,
2010. Equity accounting ceased on December 31, 2010 and the carrying amount of the investment in associate was reclassified as assets
held for sale and recorded at the lower of its carrying amount and fair value less costs to sell. Under previous GAAP, the accounting standard
for classification of assets and liabilities as held for sale was not applicable to the disposition of an investment in associate and accordingly, no
classification of asset held for sale was reported. However, under previous GAAP, the company recognized impairment to record the investment at
its fair value.

AR 2011
PG 87
The following table summarizes the effect of transition to IFRS relating to investment in Petrolifera:
(Canadian dollar in thousands) January 1, 2010 December 31, 2010
Balance sheet
Amount reported under previous GAAP $ 50,379 $ 27,938
Share of accumulated income (loss) (1,584) 4,873
Share of accumulated other comprehensive loss (627) (4,492)
Deferred tax 72 (636)
Total Investment balance under IFRS 48,240 27,683
Other asset – derivative financial asset 2,711 474
Total investment in Petrolifera 50,951 28,157
Less: Assets classified as held for sale $ – $ 28,157
Net earnings (loss)
Share of interest in associate $ – $ 5,377
Finance charges – change in fair value of derivative – (2,237)
Deferred tax – 228
Effect to Retained Earnings (Deficit) excluding January, 1 2010 adjustments – 3,368
Adjustments to Retained Earnings (Deficit) – January 1, 2010
Share of loss (1,584) (1,584)
Derivative financial asset 2,711 2,711
1,127 1,127
Total impact on Retained Earnings (Deficit) $ 1,127 $ 4,495
27.8 Taxes
The company recorded the following differences to the amounts reported for deferred tax under previous GAAP compared to IFRS.
Flow–through shares – Under Canadian income tax legislation, a company is permitted to issue flow–through shares whereby the company is
obligated to incur qualifying expenditures and renounce the related income tax deductions to the investors. Generally, due to transferring the benefit
of tax deductions to the investors, common shares issued on a flow–through basis are offered at higher than the prevailing quoted prices of the
company’s common shares.
Under previous GAAP, the company recorded a deferred tax liability on renouncement of these qualifying expenditures with a corresponding reduction
of share capital. Under IFRS, the proceeds from issuance of these shares are allocated between share capital and a liability to incur the qualifying
expenditures. The amount allocated to share capital represents the quoted price of the existing shares whereas the liability represents the difference
between the quoted price of the existing shares and the amount the investor pays for the shares. The liability is reversed when qualifying expenditures
are renounced for tax purposes. As a result, share capital increased by $2.3 million and $7.6 million with a corresponding increase to deficit on
January 1, 2010, and December 31, 2010, respectively.
Discount on issue of long–term debt and capitalized stock–based compensation – Under IFRS deferred tax on temporary differences is not
recorded for an item which is not a business combination and at the time of the transaction, neither affects accounting or taxable income. As a result,
the company reversed previously recognized deferred income tax asset and liability with respect to the non-deductible portion of discount on issue of
long-term debt and capitalized stock-based compensation with a corresponding reduction to Retained Earnings (Deficit).
Inter–company capital losses and foreign exchange – An adjustment to recognize the deferred tax benefit on an intercompany capital loss was
recorded under IFRS net of unrealized foreign exchange gain or losses on long–term debt. This was not permitted under previous GAAP.
Current vs non–current classification – Under IFRS, all deferred taxes are classified as non–current, irrespective of the classification of the
underlying assets or liabilities to which they relate, or the expected reversal of the temporary difference. The effect was to reclassify $2.3 million at
January 1, 2010 and $4.5 million at December 31, 2010 from deferred tax assets (current) to deferred tax liabilities (non–current).

AR 2011
PG 88
The above adjustments changed the deferred tax liability as follows:
As at
January 1, 2010 December 31, 2010
(Canadian dollar in thousands)
Flow–through shares $ 7,555 $ 6,943
Capital loss on intercompany transaction (13,039) (12,653)
Discount on long–term debt – (875)
Foreign exchange impact on debt – 3,470
Capitalized Stock–based compensation – (4,001)
Reclassification (2,348) (4,497)
Change in deferred tax liability $ (7,832) $ (11,613)
Other items – In addition to the above items, the change in deferred tax liability on January 1, 2010 and as at and for the year ended December 31,
2010 reflects the change in temporary differences resulting from the adjustments on transition to IFRS as described above.
27.9 Debt
Under previous GAAP, the convertible debentures were treated as a compound financial instrument with a debt and equity component. Under IFRS,
the equity component is considered an embedded derivative. As permitted under IFRS, the company designated the convertible debentures as “fair
value through profit and loss” and accordingly, recorded convertible debentures at fair value at each reporting end with changes reported within net
earnings (loss). As a result, the equity portion of convertible debentures was reduced by $16.8 million with a corresponding increase to Retained
Earnings (Deficit) on January 1, 2010 and December 31, 2010. In addition, the company recognized the effect of change in fair value by increasing
the value of the convertible debentures by $3.6 million on January 1, 2010 with a corresponding increase to deficit. The adjustment also resulted in
an increase of finance charges in 2010.
27.10 Reclassifications
In order to comply with the presentation of net earnings (loss) adopted by the company under IFRS, in the downstream segment, the company
classified $3.9 million from operating expenses to general and administrative expenses in 2010.
Further, under previous GAAP, the unwinding of the discount on decommissioning liabilities was included as a part of depletion, depreciation and
accretion expense in the consolidated statements of operations and comprehensive loss. Under IFRS this amount totaling $2.9 million in 2010 has
been reclassified to finance charges.
27.11 Changes to the Statement of Cash flow
The following is a reconciliation of the company’s cash flow from operating, investing and financing activities reported in accordance with previous
GAAP to IFRS for the year ended December 31, 2010:
Year ended December 31
2010
(Canadian dollar in thousands)
Cash flow from operating activities under previous GAAP $ 10,785
Exploration and evaluation expenses (964)
Interest expense on long-term debt 55,637
Change in working capital relating to interest expense on long-term debt 974
Cash flow from operating activities under IFRS $ 66,432
Cash flow used in investing activities under previous GAAP $ (269,763)
Exploration and evaluation expenses 964
Interest capitalized on long-term debt 35,408
Cash flow used in investing activities under IFRS (233,391)
Cash flow from financing activities under previous GAAP $ 25,793
Interest expense paid (92,019)
Cash flow used in financing activities under IFRS $ (66,226)
Under previous GAAP, interest expense on long-term debt was reported as a part of operating activities. Under IFRS, the company has elected to
present interest payments on long-term debt in financing activities.
27.12 Loss per share
Basic and diluted loss per share under IFRS were impacted by the IFRS adjustments discussed above.

CORPORATE INFORMATION
Board of Directors
D. Hugh Bessell (1)(2)(3)(5)
Chairman, Audit Committee
Retired Deputy Chairman,
KPMG, LLP, Toronto
Gregory A. Boland (1)(5)
President and Chief Executive Officer,
West Face Capital Inc., Toronto
Colin M. Evans
Co-Managing Director,
Connacher Oil and Gas Limited
President, Evans & Co. Inc., Calgary
Jennifer K. Kennedy (2)(4)
Chairman, Governance Committee
Partner, Norton Rose Canada LLP, Calgary
Garry P. Mihaichuk (2)(3)
Chairman, Human Resources Committee
President, GWM Resources Ltd., Calgary
Kelly J. Ogle (4)
Chairman, HS&E Committee
Co-Managing Director,
Connacher Oil and Gas Limited
President and Chief Executive Officer,
Trafina Energy Ltd., Calgary
W.C. (Mike) Seth (1)(3)(4)(5)
Chairman, Reserves Committee
President, Seth Consultants Ltd., Calgary
(1) Audit Committee
(2) Governance Committee
(3) Human Resources Committee
(4) Health, Safety and Environment Committee
(5) Reserves Committee
Abbreviations
bbl/d
boe
boe/d
mboe
Mcf
Mcf/d
mmbtu
MMcf
NGL
PV
SAGD
WTI
barrels per day
barrels of oil equivalent
barrels of oil equivalent per day
thousand barrels of oil equivalent
thousand cubic feet
thousand cubic feet per day
million British thermal units
million cubic feet
natural gas liquids
present value
steam assisted gravity drainage
West Texas Intermediate
Officers
Colin M. Evans
Interim co-Managing Director
Kelly J. Ogle
Interim co-Managing Director
Peter D. Sametz
Interim Chief Executive Officer
Brenda G. Hughes
Chief Financial Officer
Jesse J. Beaudry
Vice President, Sustainability
Merle D. Johnson
Vice President, Oil Sands
Stephen A. Marston
Vice President, Exploration, Land, A & D
TORONTO Stock ExCHANGE
Trading symbol – CLL
Head Office
Suite 900
332 – 6 Avenue SW
Calgary, AB T2P 0B2
Canada
tel 403.538.6201 / fax 403.538.6225
www.connacheroil.com
inquiries@connacheroil.com
Common SHARES
CUSIP
ISIN
20588Y103
CA20588Y1034
Debt (U.S. RESIDENTS)
8.75% Second Lien CUSIP 20588YAF0
8.75% Second Lien ISIN CA20588YAF03
8.5% Second Lien CUSIP 20588YAE3
8.5% Second Lien ISIN US20588YAE32
4.75% Convertible CUSIP 20588YAB9
4.75% Convertible ISIN US20588YAB92
Debt (Non U.S. RESIDENTS)
8.75% Second Lien CUSIP C2627NAE3
8.75% Second Lien ISIN CAC2627NAE53
8.5% Second Lien CUSIP C2627NAC9
8.5% Second Lien ISIN USC2627NAC95
4.75% Convertible CUSIP 20588YAA1
4.75% Convertible ISIN CA20588YAA16
Subsidiaries
Great Divide Holding Corporation
Great Divide Pipeline Corporation
Great Divide Pipeline Limited
Montana Refining Company, Inc.
AuDITORS
Deloitte & Touche LLP, Calgary
BankERS
Royal Bank of Canada, Calgary
Solicitors
Norton Rose Canada LLP
S.E.N.C.R.L., s.r.l. Calgary
Reservoir Engineers
GLJ Petroleum Consultants Ltd., Calgary
RegISTRAR and
Transfer AgENT
Valiant Trust Company, Calgary and Toronto
Designed by bmir Bryan Mills Iradesso

Suite 900, 332 - 6 Avenue SW Calgary, AB Canada T2P 0B2
T 403.538.6201 F 403.538.6225 E inquiries@connacheroil.com
www.connacheroil.com