Connacher Oil and Gas Limited

THE STAGE IS SET

CONNACHER AR 2010

1 3 4 10 24 34 36 42 44 46 72 100 101

Corporate Profile Highlights Letter to Shareholders Review of Operations Production, Sales and Reserves Investment in Petrolifera Petroleum Limited Health, Safety and the Environment Stakeholder Relations Corporate Governance and Social Responsibility Management’s Discussion and Analysis Consolidated Financial Statements Management and Board of Directors Corporate Information

ThE STAGE IS SET

Connacher Oil and Gas Limited has established an enviable reputation of on-time, under-budget construction of facilities in a remote and challenging region of Alberta. In short order, our competitors talk of the “Connacher way” of doing things in the in situ world of bitumen recovery.

Our operations are in the midst of one of the world’s largest accumulations of crude oil or bitumen and 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.

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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, U.S.A. Our integrated approach is designed to mitigate risk while we go about our business of maximizing shareholder value. Our proved and probable reserve base of over half a billion barrels should facilitate a long run of success and value enhancement.

Connacher has set the stage for sustainable and profitable growth. The company’s production is ramping up, integrated operations are in place and expansion plans are underway.

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BUILT TO PERFORM

It takes hardy people, tons of steel, a heightened commitment to the environment and respect for the people and wildlife of the area to cope with the bright lights and the challenges of Alberta’s oil sands. Connacher’s people are dedicated to doing it the right way, the Connacher way!

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With the construction of Algar and the related Cogen plant in 2010, Connacher reinforced its reputation for on time, on budget performance.

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HIGHLIGHTS FINANCIAL ($000 except per share amounts) Revenues, net of royalties Cash flow (1) Per share, basic and diluted (1) Adjusted EBITDA (1) Net earnings (loss) Per share, basic Additions to property, plant and equipment Cash on hand Working capital Long-term debt Shareholders’ equity Total assets

Years ended December 31 2010 $ 574,302 $ 36,884 $ 0.09 $ 92,206 $ (38,798) $ (0.09) $ 247,978 $ 19,532 $ 65,375 $ 843,601 $ 650,183 $ 1,683,998

2009 $ 428,214 $ 12,522 $ 0.04 $ 37,268 $ 26,158 $ 0.08 $ 322,064 $ 256,787 $ 246,707 $ 876,181 $ 671,588 $ 1,741,866

% Change 34 195 125 147 (248) (213) (23) (92) (74) (4) (3) (3)

8,299 883 9,100 10,699

6,274 1,041 11,407 9,216

32 (15) (20) 16

$ 45.65 $ 65.63 $ 3.90 $ 44.13

$ 39.39 $ 54.61 $ 3.90 $ 37.81

16 20 17

9,693 102 8

7,820 82 4

24 24 100

186,668 509,434 613,485 220,572

180,159 388,915 471,406 134,919

4 31 30 63

$ 1,497 $ 3,101 $ 3,849 $ 571

$ 1,491 $ 2,156 $ 3,310 $ 384

44 16 49

447,168

427,031

5

432,258 432,258 585,135

326,560 327,067 654,270

33 32 (11)

$ 1.88 $ 1.10 $ 1.33

$ 1.66 $ 0.61 $ 1.28

13 80 4

OPERATIONAL Daily production volumes (4) Bitumen (bbl/d) Crude oil (bbl/d) Natural gas (Mcf/d) Barrels of oil equivalent (boe/d) (5) Upstream pricing (6) Bitumen ($/bbl) Crude oil ($/bbl) Natural gas ($/Mcf) Barrels of oil equivalent ($/boe) (5) Downstream Throughput – Crude charged (bbl/d) Refinery utilization (%) Margins (%)

RESERVES INFORMATION Reserves and resources (mboe) (7) Proved (1P) reserves Proved plus probable (2P) reserves Proved plus probable plus possible (3P) reserves (9) Best estimate contingent resources Reserves and resources values ($million) (8) 1P reserves 2P reserves 3P reserves (9) Best estimate contingent resources

COMMON SHARES Shares outstanding end of period (000) Weighted average shares outstanding for the period Basic (000) Diluted (000) Volume traded (000) Common share price ($) High Low Close (end of period) (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 describle 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 a total calendar 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 10,606 boe/d in 2010 (2009 – 9,216 boe/d) (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 (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 2010 and 2009 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, 2010, possible reserves were 104 million bbls with a PV10 of $748 million (2009 – 82 million bbls with a PV10 of $1.2 billion)

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letter to shareholders Richard A. Gusella Chairman and Chief Executive Officer

The highlight of Connacher’s 2010 season was the successful completion of Algar, our second 10,000 bbl/d steam assisted gravity drainage or SAGD project, comprised of surface facilities and associated horizontal well pairs.

This was completed in April 2010, on time and under budget. Subsequently, Algar was commissioned and put onstream in August 2010. We began recording Algar operating and financial results on October 1, 2010.

In September 2010, we also completed the related 13.1 megawatt electrical co-generation or cogen plant, again on time and considerably under budget. We have established an enviable reputation of performance in this regard.

During the year, we occasionally encountered challenges, including unreliable and erratic power supplies, related pump failures and other issues which arose during day to day operations. We overcame these through the ingenuity and dedication shown by all levels of our staff, as we remained determined to improve our operating performance. The experiences of 2010 now favorably position us as we move into our fourth year of bitumen production and diluted bitumen or dilbit sales. We have now sold almost eight million barrels of bitumen since we first started production at Pod One in December 2007.

Algar experienced a very acceptable rampup from commencement of operations through the end of the year.

When combined with production from Pod One, we have on occasion exceeded 15,000 bbl/d of bitumen production, or over 75 percent of design capacity. Importantly, we are still in the early stages of rampup at Algar and are improving output levels at both plants. Our goal continues to be to improve total production towards 90 percent utilization, with a target steam:oil ratio or SOR approaching approximately three times, accompanied by lower operating costs. In the meantime, our December 2010 bitumen production exited at approximately 14,000 bbl/d, which was over 50 percent above our full year 2010 average daily bitumen production. Certainly this sets a nice base for our 2011 expectations.

We are in the early days of our exploitation and development program at Great Divide. In fact, we are still exploring. In 2010, we had very successful core hole and 3D seismic programs, which resulted in a meaningful increase in our reserve base. Our proved and probable or 2P reserves now exceed 500 million barrels. Our best estimate contingent resources add over 220 million additional barrels to our asset base.

We are one of the few independent companies to actually be able to record proved and probable bitumen reserves, supported by actual and growing production. These reserves provide a solid backing for the value

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Our experienced personnel have been together as a solid team for several years now and it is gratifying to hear about the “Connacher” way of doing things.

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of our company, which significantly exceeds current stock market appraisal. As we perform and demonstrate a reliable and growing production base, this gap will narrow and our financial flexibility will improve. We are conducting a similar core hole program on our lands during the first quarter of 2011 and hope for continued expansion of our reserve and resource base, which is rapidly approaching one billion barrels.

As mentioned, during 2010 we encountered some unusual developments, which eroded some of the growing investor confidence which had been emerging, in anticipation of the Algar rampup and Great Divide production growth. The most significant adverse factor was the unavailability of adequate and reliable electrical power, until we successfully completed and activated our cogen plant. Periodic brownouts and outages not only reduced plant reliability and curtailed volumes, but also had a damaging impact on our electrical submersible pump performance. Also, for a short period, the timing of Algar’s start-up was a contributing factor, as regulatory lag had delayed the construction start-up of both our cogen plant and also that of a regional substation designed to address outstanding shortages and reliability. In other words, as we expanded we stressed the electrical system and, periodically, the system failed.

Left

h cogen under

ne 1 – Algar wit

2, Sce get Right Act

and under bud Algar – on time

construction

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Our focus is on superior performance by our officers, managers and staff for the benefit of our shareholders.

The upshot was Pod One production levels did not meet our expectations and did not meet those of the growing number of financial analysts who follow our company. While our Great Divide production was anticipated to grow into our balance sheet, the disappointment resulting from our second quarter Pod One performance, due primarily to external factors, still gave rise to concerns. They included whether we could achieve greater plant utilization at lower SORs and whether Algar would perform similarly to Pod One. By extension, we heard concerns about debt levels, coverages and our projected capacity

to internally fund our future growth, without having to raise additional equity or borrow more money. This impaired our share price performance in the second half of the year. However, our recent demonstration of consistent and more reliable results from our Great Divide operations is starting to restore confidence. Higher oil prices are also a contributing factor to a greater and more diversified interest in our common shares at improving prices.

Prices for heavy oil during 2010 were adversely influenced by market factors, including in particular during September 2010 and October 2010, when pipeline breaks and related curtailments resulted in weak markets and wider differentials. Some of these conditions have continued into early 2011.

Fortunately for Connacher, our refinery in Great Falls, Montana had an excellent year, benefiting downstream from upstream differential adversity. While we generally enjoyed good refining results throughout the year, buoyed by strong asphalt prices and stronger light product margins, poor summer weather conditions curtailed paving and road building. The lingering effects of the 2008-2009 recession were also discernible. We expect another strong year for refining in 2011 and we anticipate much better upstream results, especially if current strong crude oil prices persist and differentials narrow.

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We at Connacher recognize that we will be judged by our performance over the long run, so we focus on operational excellence, innovation and commitment.

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AR AR2010 2010 CONNACHER CONNACHER

Life in the public glare is never simple for any company. We at Connacher recognize that we will be judged by our performance over the long run, so we focus on operational excellence, innovation and commitment.

We are in a long-life, capital intensive theater which involves very complicated systems, challenging production, environmental diligence, extensive water handling, difficult weather conditions and remote living conditions for our staff, especially at Great Divide. I am pleased to say we have assembled a highly qualified and motivated group of people at all levels of our organization, while keeping our numbers small relative to our peers. Our focus is on superior performance by our officers, managers and staff for the benefit of our shareholders. Capital markets judge us by what we do and how we perform in delivering on our undertakings and guidance. In the process, we have not always achieved everything we wanted to, but it was not for lack of effort. We have experienced significant and key learnings, which we believe will serve us well in the future. Once we introduce additional innovations, which are described in greater detail in our review of operations, we are confident our future will be stronger and more secure. This will be a long running successful story! It may even see a reprise some year.

Our financial results continued to improve and our outlook is buoyant. Crude oil prices were healthy throughout most of 2010, although heavy oil differentials widened considerably at various times during the year. Natural gas prices remained weak and are anticipated to remain so, in both an absolute and relative sense. Geopolitical conditions are currently influencing crude oil prices, as is the recovery from the deep recession of 2008-2009. We are highly leveraged to crude oil price movements, although we do use appropriate hedges during periods of high capital expenditures and with financial leverage on our balance sheet. During 2010, we expanded our repertoire into an “unconventional” light gravity crude oil resource play and established a strong land base in the Three Hills/Twining region of south central Alberta.

We are in the midst of drilling and testing our first three wells, which are long-reach horizontal probes that we frac extensively using recently-developed “multi-frac” technology. If our early wells are successful, we may be able to drill over 100 follow-up locations and significantly increase high netback conventional production. This will be an excellent complement to our long-life, large reserve base in the oil sands.

We own 100 percent of this project.

Pod One

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Our story will continue to change as it unfolds; the players will be supported by understudies, with the ability to step in when needed.

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AR AR2010 2010 CONNACHER CONNACHER

Our stage is set.

We continue to adapt and innovate as is necessary in a dynamic business such as we are in.

We have submitted an application to regulators to expand our design capacity at Algar, from 10,000 bbl/d to 34,000 bbl/d. Upon completion, this would take Great Divide to a plant capacity of 44,000 bbl/d of bitumen, including steam generating capacity approaching 130,000 bbl/d. In this process, we are subjected to extensive and detailed scrutiny on environmental, operational and sustainability issues. We anticipate approval of our application by late 2011, which timetable positions us to focus on our engineering,

operational and financial plans during 2011 for our next round of sustained growth, in 2012 and beyond.

In the intervening period, we anticipate being able to deliver higher production and successively improving financial results. This, in turn, should translate into broader capital market support and improved valuations for you, our shareholders.

Our stage is set. We continue to adapt and innovate as is necessary in a dynamic business such as we are in. This is evident in our asset rationalization program; our technical advances; new projects, including “SAGD plus” with solvents at Algar; our pioneering use of high temperature electrical submersible pumps; our recognition of key learnings from operations and their application at both Algar and Pod One and the list goes on. We also streamlined our management group during the year and recognized those who were making the kind of contributions that guarantee Connacher will be a success. We introduced a major new play, our Pekisko multi-frac horizontal well program at Three Hills/Twining, areas where we already had a production base. So our “project” approach here also incorporated sound scientific principles, experience and a willingness to take risks.

During 2011, we will be modest in our approach and spending. Our revised 2011 capital budget is $122 million, considerably less than our 2010 outlays, which exceeded $236 million, as we finished up our Algar project and built the cogen plant. Nevertheless, taking a breather like this will enable us to refocus on optimization and achievement of goals to benefit all of our stakeholders. We may also entertain joint venture proposals to assist in financing our next round of growth, if we determine it to be advantageous to accelerate our growth in the short run, but will not do so precipitously for short-term gratification at the cost of compromising longer-term value. We will only “deal” if it is the right deal, to enhance shareholder value on a sustainable basis. We will assess capital market conditions with a view to continued strengthening of our financial condition. Our primary focus will be on refinancing our long-term debt on more favorable terms, if conditions permit this to be accomplished at reasonable cost. This would free up more internally-generated funds to finance our continued expansion and lower our overall cost of capital.

As with all organizations, we experience some turnover at all levels. We thank our retiring Director, Stewart McGregor, for his past contribution to our progress. We also wish our past employees “good luck” in their new ventures, as we welcome new employees to the Connacher troupe. We continue to be viewed as a good employer and we are pleased that people want to work for us and stay with us. We are confident of our future because of the experiences of the past. Our story will continue to change as it unfolds; the players will be supported by understudies, with the ability to step in when needed, bringing new ideas and approaches which are so important for any organization if it is to stay vital. Our experienced personnel have been together as a solid team for several years now and it is gratifying to hear about the “Connacher” way of doing things. It bodes well for the future to have this healthy mix of old and new, as we close the curtain on the past year and look forward with enthusiasm to 2011.

Respectfully submitted,

“R.A. Gusella” Richard A. Gusella Chairman and Chief Executive Officer March 17, 2011

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Review of operations

Peter Sametz President and Chief Operating Officer

In 2010 Connacher successfully demonstrated: • “Best in class” project execution • Reserve and resource volume and value additions • Optimization and problem-solving in our production and refining operations • Effective management of our asset portfolio, with timely divestitures and the development of new core areas • Development of key competencies, with an expanded and strengthened pool of human resources • Development of our oil sands growth plan, supported by new technology

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Connacher’s infrastructure has been built to accommodate future expansion in the Great Divide region.

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Connache

r’s 2010 S tage

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Steam-Assisted

Gravity Drainage (SAGD

)

4

Well Pad and Plant

3

Impermeable Cap Rock Layer Steam Injection Well Oil Production Well

1

Oil Sands

2

Ste Cham am ber

1 Steam injected and rises, producing heat 2 Hot bitumen drops down 3 Hot bitumen emulsion produced from lower well 4 Bitumen and hot water separated at surface; dilbit sold, water cleaned and recycled

Connacher’s operations in 2010 were comprised of bitumen production at its two steam-assisted gravity drainage (“SAGD”) projects from our Great Divide oil sands operations in northeastern Alberta; conventional crude oil and natural gas production in Alberta and Saskatchewan; our refining operations in Great Falls, Montana and the marketing and transportation of our production, including upstream diluted bitumen (“dilbit”), conventional crude oil and natural gas and the sale of downstream refined products. Subsequent to year-end, Connacher sold its mature oil property at Battrum, Saskatchewan and agreed to sell its natural gas properties at Marten Creek/Randall, Alberta.

The focus of our major effort in 2010 was on our principal asset, Connacher’s Great Divide oil sands operation. We have now built and operate two 100 percent-owned SAGD projects, Pod One and Algar, each with a rated design capacity of 10,000 bbl/d of bitumen. Also, we produce steam – 27,000 bbl/d at Pod One and 30,000 bbl/d at Algar – for injection into the subsurface McMurray reservoir utilizing horizontal well pairs.

The steam is injected into the upper “injector” well of the well pairs, condenses in the reservoir and thereby transfers its heat into the reservoir. This liberates the bitumen, which drains by gravity to the lower “producer” well. An emulsion, primarily comprised of hot water and bitumen, is then produced to the surface where the components are separated. The bitumen is diluted with lighter condensate and sold as dilbit, similar in composition to conventional heavy oil. Approximately 90 percent of the produced water is recycled, cleaned and reused to make new steam for continuous injection into the subsurface.

Construction of the Algar plant, which is part of our second project in the region, recommenced during the second half of 2009 and was completed ahead of schedule and under budget, in April 2010. Subsequently, the plant was commissioned, steam was circulated in the horizontal well pairs for approximately three months and then SAGD production commenced in August 2010. Commerciality was achieved in October 2010.

Our 13.1 megawatt electrical co-generation plant at Algar was completed in September 2010, also ahead of the construction schedule and well under budget. When activated, the cogen plant considerably improved electrical power reliability for Connacher at Great Divide. We expect further improvements in the region with the anticipated spring 2011 completion of a nearby substation being built by the regional power supplier.

We have an excellent record of field execution. We have effectively managed significant projects, under budget and finishing ahead of schedule. We have proven our approach works. Both the Algar plant and the cogen facility were significant projects built in remote regions under difficult conditions. The final capital cost of the Algar 12

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We are proud of the fact that the “Connacher approach” is being emulated by our competitors.

project, including the cost of related well pairs and the cogen plant, was a considerable sum at approximately $400 million, so this was a large undertaking. We are proud of the fact that the “Connacher approach” is being emulated by our competitors.

We also identified and managed several production optimization procedures and facility improvements at Pod One in 2010, including evaporator operation and maintenance, treating improvements, installation of downhole electrical submersible pumps and other electrical and system improvements with a

view to increased reliability, growing production and to improve steam:oil ratios (“SORs”). Results of these initiatives were observed primarily in the fourth quarter of 2010 at Pod One. Some of these improvements were significant enough to be brought to the attention of industry by Connacher’s technical personnel at various technical forums held during late 2010 and early 2011.

Our production rampup at Algar has proceeded very well and also benefited from the incorporation of some of our Pod One key learnings. We have also seen operational synergies from the two plants at Great Divide.

These will aid our production optimization and the operational efficiency of both projects in 2011.

In addition to these major capital and maintenance undertakings, we also drilled 81 gross core holes on our oil sands lease block during the first quarter of 2010. This contributed to the increase of our proved and probable reserves (“2P”) to over half a billion barrels. We also expanded our best estimate resource base and still have evaluated only fifteen percent of our overall land base through drilling. Excluding the multinationals, we have one of the largest volumes and concentrations of crude oil reserves among Canadian public oil companies.

Our conventional oil and gas activity saw us quietly assemble an attractive land position on a light-gravity crude oil play in central Alberta. We own a significant interest in approximately 30 sections of well-situated P&NG rights, amenable to the application of horizontal drilling, accompanied by multi-frac stimulation. This resource play concept in conventional light oil dovetailed very well with our “project” approach to the oil sands, in that we assembled a large land base, drilled core holes and ran 3D seismic for critical pre-drilling geological data. We then used the front end geological and geophysical data gathered for horizontal well placement, in addition to drilling and completion design. Connacher has already drilled three wells on this Pekisko play

” at Algar

tors or “Boilers

Steam genera

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and when we establish a reliable production history, we could have upwards of 100 locations for future development. The play is an interesting adjunct to our oil sands operations, as it offers high netbacks, near term cash flow and the prospect of solid economic returns.

Subsequent to year end, we closed the sale of our mature Battrum, Saskatchewan properties at an attractive price and have reached an agreement to sell our Marten Creek/Randall, Alberta acreage and associated natural gas production and reserves. With the emergence of a much expanded North American natural gas supply and lower pricing, the need for the balance of upstream natural gas production and consumption in our oil sands operations became less compelling and upstream natural gas returns on investment were being eroded. We continue to maintain an excellent land position at Latornell, Alberta, on trend with indicated and significant Montney and Duvernay natural gas and natural gas liquids discoveries, also amenable to multi-frac stimulation and horizontal drilling with access to attractive incentives.

Our refining and marketing activities were profitable throughout 2010. High refinery utilization, strong margins for refined products, excellent asphalt prices and efficient operations offset the adverse impact of poor summer weather conditions, which impacted the level of highway construction and paving. The lingering effects of the 2008 and 2009 economic downturns were also discernible in our traditional market areas. We did, however, expand our market penetration into stronger economic regions, including Alberta.

Our 2010 achievements were a credit to both our head office and field personnel. This includes our executives, managers, support staff and field personnel in both Canada and in the United States of America. During 2010, we modified and enhanced our management team, adapted to challenges and set the basis for our future growth and development in the oil sands, conventional and refining. During the year, we consciously emphasized operational excellence, a program designed to encourage effort and accomplishment, accept responsibility and develop solutions to problems as they arise. We have numerous examples of the effectiveness of this program, which was enthusiastically accepted by our personnel. We have also conducted all our operations in a responsible manner. Your company has an enviable record on health, safety, environmental and regulatory issues.

We continue to develop a strong and logical long-term growth plan for our asset base. Our application to expand bitumen processing capacity at Algar by 24,000 bbl/d to 34,000 bbl/d was submitted to regulatory authorities in May 2010 and we anticipate this process to conclude in late 2011. Combined with Pod One our total rated bitumen processing capacity would then be 44,000 bbl/d. The intervening period will provide us with the time and additional operating experience to make certain we have developed the appropriate and most effective engineering, operating and financial structure to accomplish this expansion in the most productive manner. This may be done independently, as we have operated to date, or with alternative solutions, as dictated by economic and capital market conditions.

We have also stressed a program of technical innovation, especially in our oil sands operations. During 2011, following regulatory applications in 2010, we will proceed with several technical initiatives, including co-injection of solvent with steam in Algar, co-injection of natural gas with steam in Pod One and the installation of additional high temperature downhole pumps (“ESPs�). Connacher was the first company, worldwide, to employ high

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temperature ESPs in 2010. We are enthused about the potential positive impact of all these initiatives on our production levels, ultimate recoveries and production efficiency with lower SORs as a consequence.

We anticipate 2011 will be a year of focused asset optimization, technical design and innovation and new market development. As we will not be building a large plant or project during 2011, our revised capital budget for 2011 is a modest $122 million. It will be internally financed. Planned outlays include requisite maintenance and sustaining capital, a solid continuing core hole program at Great Divide and the surrounding area, new drilling at Three Hills/Twining and further minor upgrades to our Great Falls refinery. We will have a nice balance between growth and responsible maintenance. Any plans to accelerate our Three Hills/Twining program, if warranted, will also be internally financed, including from asset sale proceeds.

Our capital program is well underway with encouraging initial results. We expect to see growing bitumen production during 2011. We also expect to take new directions with our conventional upstream programs, especially if our early drilling at our Three Hills/Twining Pekisko play is successful. It will be “out with the old, in with the new”, characterized by higher netbacks, year round access and increased proximity. As we become increasingly self-reliant and able to finance much of our growth from internally-generated sources, the lowest cost of capital available to the company, we are also internally developing new play concepts to accelerate our growth. Our strength is in our people, the principal actors on the operating stage. We believe our stage is set for continued operational improvements with increasing efficiency.

nnacher – Stage

Innovation – Co Innovation

Impact

is Set

cap in lean zone/gas Reduces SORs Downhole ct of lower pressure Minimizes impa pumps n ductio Stabilizes pro reliability reases power Inc n Co-generatio duction nt Stabilizes pro Facility capital investme with minimal Reduces SORs Methane higher pressure co-injection operations at Allows SAGD n Gas cap ctio du pro repressuring Higher Reduces SORs Solvent SAGD productivity Increases well ction Higher produ uirement imal steam req ction with min Higher produ Infill Wells

Status

Ongoing Pod One Ongoing 2011 (Pod One) 2011 (Pod One) 2011 (Algar)

Medium Term (Pod One)

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AR AR 2010 2010 CONNACHER CONNACHER

15 15

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CONNACHER’S OIL SANDS OPERATIONS Connacher owns a 100 percent working interest in approximately 100,000 net acres of oil sands rights in the Great Divide, Thornbury, Quigley and Halfway Creek (Hangingstone) regions of northeastern Alberta. Most of these lands were initially acquired in early 2004 and the primary focus of our activity has been in the Great Divide area, situated in approximately Townships 81-83, Ranges 11-12, W4M.

GREAT DIVIDE Our principal asset is named Great Divide and it is comprised of Pod One, Algar and associated contiguous leases, identified accumulations, reserves and resources. Pod One was built in 2007 and it came onstream in December 2007. It was our first 10,000 bbl/d SAGD project and is comprised of surface facilities that make 27,000 bbl/d of steam, clean and recycle water and process production from associated horizontal well pairs, which are also part of the project. Steam made at the surface facility is injected into the McMurray Formation, which comprises the reservoir at approximately 475 meters subsurface. The resultant emulsion of hot water and bitumen is produced to the surface, where it is separated. The bitumen is processed, diluted and sold into the market as diluted bitumen or “dilbit”. The associated water is recycled and reused to make new steam after cleanup so it is a continuous process. No surface water is used in the process and the non-potable source water, while fresh, is unusable for human consumption or for agriculture.

Algar was also designed as a 10,000 bbl/d project, with the capacity to generate 30,000 bbl/d of steam, slightly more than at Pod One. It was completed under budget and on time in April 2010, at a cost of approximately $366 million, excluding the cogen facility. SAGD production from Algar’s well pairs commenced in August 2010 and results have been included in our accounts since October 2010, signifying commerciality. Numerous key learnings and improvements were incorporated into Algar as a result of the experience gained in the prior operation of Pod One. Also, a 13.1 megawatt natural gas-fired electrical co-generation plant was installed at Algar to address power shortages in the region. This also helped the operational stability at Pod One. Algar is presently in a rampup stage, which normally requires about one year or more after production startup, in order to facilitate development of effective steam chambers and heat up the reservoir. This enables the movement of bitumen into the producer wellbore and to the surface for processing and subsequent sale. Algar was constructed in a manner to facilitate on-site expansion to approximately 34,000 bbl/d of bitumen processing capacity and approximately 100,000 bbl/d of steam generation capacity. This is anticipated to occur after 2012, once regulatory approvals are received and final decisions are made with respect to engineering, design and optimum methods to finance this growth. The good news for Connacher is the reserve backing for this expansion already exists.

Connacher anticipates being able to develop productive capacity exceeding 50,000 bbl/d and possibly approaching 70,000 bbl/d from its Great Divide lease block during the next several years. We continue to evaluate the associated

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leases which constitute Great Divide and the Great Divide Expansion Project, which is under regulatory review and which is expected to receive late 2011 approval. This is accomplished primarily with our annual winter season core hole programs to secure additional reliable subsurface data. This assists our independent reserve and resource evaluators in their assessment of our reserves and productive potential in their annual reviews. We are well advanced in our assessment of the Great Divide leases, including a program this year targeting approximately 60 core holes.

Results will supplement data we secured through 3D seismic programs conducted over this lease block in prior years.

POD ONE We constructed our first 10,000 bbl/d SAGD project, Pod One, in 2007 after a program of seismic and core holes and the related regulatory process. The plant and related wellbores were completed at a cost of $272 million. It is located in close proximity to Highway 63, which runs through our main lease block and also includes a recentlyexpanded trucking facility, the capacity of which enables Connacher to transport and sell up to approximately 26,000 bbl/d of dilbit into currently available markets. Algar is linked by transfer lines to Pod One, so all Great Divide production is handled through the Pod One terminal. Also, diluent is provided to Algar by a pipeline from Pod One. Pod One now has a total of 19 SAGD well pairs connected to the facilities. Production during the year was below expectations for a number of reasons, including evaporator issues, unreliable power, poor collateral pump performance or pump failures and the impact of managing certain reservoir characteristics which required technical assessment and innovation. Despite these challenges, we have now produced over six million barrels of bitumen from Pod One since it was activated. We also demonstrated steady state improvement during the second half of the year, particularly in the fourth quarter 2010. Improved power reliability and stability appear to be fundamental to the long-term realization of the project’s capacity.

Separately in this section we have highlighted innovations introduced into our oil sands operations. These were designed to deal with the various challenges which characterize our reservoir and bitumen production.

These include the installation of downhole pumps to reduce SORs and reduce the adverse impact of lean zones; a planned methane co-injection in the northern part of Pod One to reduce SORs; gas cap repressuring to facilitate higher production and eventually the drilling of infill wells without a related steam injection well to capitalize on the impact of steam being injected into the reservoir since 2007.

All of these initiatives are at different stages of development. Our field personnel have worked assiduously to achieve production targets and goals and have introduced numerous procedures and innovations to overcome the challenges of bitumen production that they have encountered. This is “operational excellence” in action.

We remain confident that sustainable growth will occur during 2011 to move towards improved efficiencies, lower SORs, lower operating costs and improved netbacks arising from higher plant utilization.

ls

s diluent arriva

l/d of dilbit plu

e – 26,000 bb

inal at Pod On

truck term The expanded

AR 2010 CONNACHER

17

ALGAR Construction of our Algar project was initiated in late 2008, suspended for a period of time due to the deleterious impact of the crude oil price collapse and recession, then reactivated in July 2009 and completed in April 2010, on time and under budget at a total cost of $366 million, excluding the cogen facility. Algar was also designed for a productive capacity of 10,000 bbl/d of bitumen and 30,000 bbl/d of steam. There are seventeen associated SAGD horizontal well pairs, sixteen of which have been activated and are now contributing to current production levels. We recently commenced steaming the seventeenth well. The project’s rampup was initiated in August 2010, after commissioning and steam circulation in the well bores for approximately three months. Commerciality was determined to have occurred on October 1, 2010.

We constructed a 13.1 megawatt natural-gas fired electrical cogen plant at Algar, also built on time and under budget, in keeping with our excellent reputation of project development. This was done to improve power reliability in the region. The plant has performed admirably since its startup in September 2010. The cogen plant can also produce surplus steam, which means we can operate our steam generators at a lower level of utilization and at lower cost to achieve satisfactory steam volumes for our purposes.

Reducing the demand on the regional grid has also resulted in improved electrical power reliability for Pod One. The impending completion of a nearby substation by the regional power supplier anticipated for May 2011, will also enhance overall power availability, flexibility and stability for our Great Divide operations, including our planned expansion at Algar when it occurs.

Great Divide

Quigley

Pod One Algar Thornbury

63

Connacher

’s great d

18

AR 2010 CONNACHER

ivide and

area hold

ings

Bitumen accumulation

Our early stage rampup proceeded very well, exceeding previously documented performances by our competitors.

Our early stage rampup at Algar proceeded very well, exceeding previously documented performances by our competitors. In late 2010 and early 2011, short-term adverse market conditions caused us to control the rampup but we remain satisfied with the performance to date. In combination with Pod One, we substantially achieved our 2010 exit guidance levels and, subject to normal qualifiers about any forecast, we remain optimistic about anticipated production and operating results for 2011.

Algar was designed for expansion on site. During 2010, we submitted an application, under the name “Great Divide Expansion Project”,

accompanied by an Environmental Impact Assessment, for our main lease block to expand Algar productive capacity from 10,000 bbl/d to 34,000 bbl/d. We expect regulatory approval by late 2011, but do not anticipate any new construction until mid-2012 at the earliest. In the intervening period, our focus will be on optimizing production, streamlining existing operations, introducing innovations to enhance productivity and the designing of a financial plan that facilitates this expansion at minimum dilution. Our primary emphasis will be on increasing internally generated funds, the source of our lowest cost of capital, while continuing to rationalize our asset base and possibly, a refinancing of our outstanding long-term debt.

Of particular interest on the innovation side is our recently-approved application to proceed with a “Solvent SAGD” project on several wells on one pad at Algar. Based on laboratory results and simulation studies, we believe that with efficient solvent recovery, this project will help us reduce SORs, increase well productivity and reservoir recovery factors and thus experience higher overall productivity at Algar.

GENERAL Connacher’s Great Divide oil sands operations are growing in maturity and performance. We have now produced almost eight million barrels of bitumen since we initiated operations in December 2007. We have developed a substantial reserve base exceeding half a billion barrels in the region. We are continuing with our systematic core hole program to expand and enhance our reserve base through additions and upgrading from resources to reserves. This program is continuing in early 2011 and we are encouraged by early results.

Connacher’s objective in 2011 is to produce between 14,500 bbl/d and 16,500 bbl/d of bitumen from our two plants, achieving a utilization rate exceeding 80 percent at the higher end, with a longer term goal of approximately 90 percent utilization to allow for maintenance and turnarounds. This will result in lower SORs, lower unit operating costs and higher netbacks in years to come, assuming reasonably stable to improving dilbit prices over the ensuing years. Because we have a long-life reserve base and are highly leveraged to crude oil prices, our shareholders will remain favorably exposed to higher volumes and prices for many years to come.

OTHER OIL SANDS HOLDINGS Connacher also owns extensive undeveloped lands at Thornbury and Quigley, in the general Great Divide region and a 50 percent undivided working interest at Halfway Creek, situated closer to Fort McMurray. Our independent consultants have assigned considerable best estimate resources to our Halfway creek acreage based on core hole drilling and other exploration activity conducted to date on this 24,320 acre lease block. It is well situated in relation to anticipated development activity by a third party in the region.

We will be conducting some core hole drilling and 3D seismic on our Thornbury property during our 2011 program. Earlier drilling provided some leads and prospects on this acreage and we will evaluate the potential of these lands once new data is available to us. It is of continuing importance because of the close proximity to our existing operations, thereby improving the possibility of efficient low cost exploitation through access to more centralized facilities over the long run.

AR 2010 CONNACHER

19

Pump jack at new Twining well

Conventional Since 2001, Connacher has held interests in various conventional crude oil, natural gas and natural gas liquids properties with production and reserves in Western Canada. These properties were primarily held as a source of cash flow to assist in offsetting general and administrative expenses during the development of our Pod One and Algar oil sands projects. They also contributed to the company’s borrowing capacity and in the case of northern Alberta natural gas properties, provided a strategic hedge against the possibility of significant increases in natural gas prices, as Connacher burns natural gas to make steam and now electricity in its bitumen extraction process.

In 2009 and increasingly in 2010, in part due to the disconnect which has emerged in the economics of crude oil versus natural gas, Connacher’s conventional focus has been on crude oil development and new exploration opportunities. This occurred despite the fact natural gas represented, at various times, 60 percent or more of our conventional production, expressed on a boe basis.

Our principal conventional crude oil properties in 2010 were located at Battrum, Saskatchewan and, to a lesser extent, at Three Hills/Twining and Gilby in central Alberta. During 2010, we invested capital in Battrum to upgrade facilities and pipelines associated with this mature waterflood property, which produced medium gravity crude oil from an excellent reservoir. Towards year end 2010, in conjunction with our continuous strategic review of assets, we concluded it would be a good time to monetize our Battrum property. We conducted a broad auction process and, subsequent to year end, have concluded the sale of this property and some minor interests in southwestern Saskatchewan, concluding our involvement for the moment in that province. We were pleased with the sale price offered by the successful bidder and closed the transaction on February 15, 2011.

Cash proceeds were added to working capital and were used to reduce our net indebtedness.

Simultaneously, throughout 2010 we quietly advanced our application of our technologically-driven approach in the oil sands to secure ownership of approximately 30 sections of lands in the general Three Hills/ Twining area of central Alberta, where we already had an established production base, with related facilities.

Following the drilling of core holes to secure additional geological data, the completion of 3D seismic programs, a thorough investigation of multi-frac technology and careful horizontal well design, in late 2010 we embarked on a three well program to test the potential of identified resources. Results to date have been very encouraging and we anticipate release of additional information, once we have completed all three wells, have placed them on production and have developed a “type” curve for production and decline for this light gravity, high-netback crude oil play. With success, we could realize early and considerable cash flow, attractive netbacks and a high return on investment. These conventional resource projects are discretionary in scale, which can make them “self-funding” much more quickly than oil sands projects, which require large amounts of up front capital, with longer capital recovery periods. In excess of 100 potential locations have been identified, so in short order this project could materially alter the composition of our crude oil production slate. Other similar 20

AR 2010 CONNACHER

opportunities in Alberta have been mapped by our experienced exploration team and we are quietly positioning ourselves on a ground floor basis in these plays, at low cost. Our approach will continue to be scientifically based, resource opportunity driven, largely 100 percent-owned and geared towards crude oil or liquids rich natural gas in areas where land positions or production have been well established.

At year end, our principal producing natural gas properties in Alberta were located at Marten Creek/Randall in north central Alberta, due west of our oil sands acreage. As indicated, these properties were acquired and developed to provide the company with a strategic and timely physical hedge against corporate natural gas consumption. In past years, Connacher has made a modest investment in these lands to retain production levels with new drilling, offsetting natural declines and also to add additional deliverability and reserves. Recently, however, with the advent of shale gas developments and other market developments for natural gas, resulting in the prospect of lower wellhead prices for several years, we have curtailed our investments in pursuit of earlier objectives, due to the erosion of risk-adjusted returns in the natural gas business. Subsequent to year end, we reached an agreement to sell these properties following a widespread auction process. We will continue to monitor opportunities as increased rationalization occurs within the natural gas industry, while we continue to have unfettered access to low-priced volumes available in the marketplace.

Our conventional thrust has been modified to meet the current economic and technological realities, while capitalizing on our company’s in-house technical expertise. Low natural gas prices and abundant supply remove some of the strategic concerns we had when we started construction of our oil sands projects in 2006. At that time, we had just witnessed very high natural gas prices and the cost of natural gas was and continues to be a material operating cost component in the oil sands. However, our earlier concerns have abated considerably in recent years and the traditional linkage between natural gas prices and crude oil prices has eroded in a dramatic fashion. Accordingly, it appears our shift towards new plays, new technology, lighter gravity crude oil with attendant higher netbacks and going about our business in a confident and systematic manner was propitious in both timing and application.

Pekisko Pool

Horizontal Multistage Frac Potential

CLL Lands T29 CLL Ostracod Oil Pool & Battery Porous Pekisko Oil Fairway Recent CLL Multi-stage Frac Horizontal Wells R26 R25 (3) Future Drilling Campaign Recent Industry Horizontal Wells

THREE HILLS/Twining AR 2010 CONNACHER

21

Refining and Marketing Connacher has owned and operated a complex heavy crude oil refinery in Great Falls, Montana since 2006.

The original rationale for acquiring the refinery was to mitigate the risk associated with the price differential for the heavy crude oil that we anticipated producing and selling from our Great Divide oil sands property, compared to light crude oil prices. We envisaged that the refining operations would enable Connacher to recover a portion of the traditional heavy crude oil differential discount.

We have been very pleased with the overall results of this strategy since the acquisition, especially with an approximate 18 month payout of the purchase price and the excellent results achieved by this operating division in 2010, when a significant net operating income or refining margin was achieved.

While 2008 and 2009 were difficult years for all refiners, our Montana Refining division had excellent relative performance during this challenging period. Undaunted by the severe recession, we essentially broke even during those volatile and difficult times and also made investments to upgrade the refinery, expanding throughput capacity and investing capital to meet prevailing regulatory and environmental standards. We also improved the physical appearance of the refinery, enhancing the community and our place therein with the construction of a new perimeter fence and with improvements to a riverside walkway near the refinery. We remain committed to responsible conduct of our business and we are a considerable employer and generator of economic activity in the region.

In 2010, we achieved record levels of throughput and process reliability, reduced our operating costs and expanded markets. As a result of our high utilization rates and our optimal position to capitalize on widened differentials for Canadian heavy crude oil prices, which occurred during the period late in 2010 when Enbridge had pipeline ruptures, we earned excellent net margins on our full product slate. Poor weather conditions prevailed throughout much of the key paving season in the western United States and Canada in 2010. This limited overall volumes of asphalt sold, but we still managed to achieve record sales into premium Canadian markets. We secured a strong position heading into the 2011 paving season. We ended 2010 with higher asphalt inventories than in 2009, but in recent months have been able to adapt by processing lighter crude oil through our refinery, thus avoiding the need for large season-end, deep discount asphalt sales of previous years. This flexibility and innovative approach reflects our continuing commitment to operational excellence, which promotes these types of positive responses to changing industry circumstances.

“

We believe our 2010 performance is further proof of the validity of our integrated approach.

AR AR 2010 2010 CONNACHER CONNACHER

“

22 22

In 2010, we achieved record levels of throughput and process reliability, reduced our operating costs and expanded markets.

During the year, we recognized the significant contribution of key individuals in our Montana Refining operation, thus providing them with more accountability and independence, while streamlining responsibilities.

We continue to be committed to the strategy which resulted in the ownership of Montana Refining. This ownership has also benefited our expanding and strengthened marketing groups in both Calgary and Great Falls. As a small refiner, Connacher has developed a unique dynamic capability to move product by truck, rail and by utilizing

downstream storage capacity. This capability is anticipated to be highly valuable in solving market and transportation challenges for heavy crude oil, while enabling us to capitalize on available market opportunities for our upstream operations at Great Divide. We have also eased ourselves into utilization of rail cars for the movement of diluent from Montana to Alberta for our oil sands operation and also into the movement of dilbit directly to US markets from Alberta. As a consequence, we have participated in the development of new markets and transportation options for Canadian dilbit. In part these initiatives have been pursued because of the adverse impact arising from pipeline breaks and oversupply into Cushing, Oklahoma. These factors have adversely affected WTI pricing conditions and underscored the need for new market development and penetration, within North America, until identified bottlenecks are resolved.

We are also aware of a growing focus on developing new overseas markets for oil sands production, including access to West Coast ports for possible sales to Asia. We are monitoring these developments in an attempt to be positioned to capture options as they might become available to us.

Last year, 2010, marked Connacher’s fifth year in the refining business. Upon reflection, our refining business has been a rewarding investment. Our initial investment paid out quickly, our throughput capacity has been expanded and, in this time, we have responded proactively to environmental issues and requirements, broadened our market penetration and enhanced our relationships within and with the community. We believe our 2010 performance is further proof of the validity of our integrated approach.

pany

Montana Refining Com

AR 2010 CONNACHER

23

Production, Sales and reserves

Bitumen During 2010, Connacher produced a total of 3.2 million barrels of bitumen, 322 thousand barrels of conventional crude oil and natural gas liquids and 3.3 billion cubic feet of natural gas. Total corporate production was 4.06 million boe, up 21 percent over 2009 levels of 3.36 million boe. Bitumen sales in 2010 averaged 8,206 bbl/d, an increase of 31 percent over 6,274 bbl/d in 2009, reflecting the impact of the startup of Algar during the year and its commerciality, effective October 1, 2010. The company’s bitumen production in 2010 was 8,299 bbl/d, while fourth quarter 2010 bitumen production averaged 13,328 bbl/d and December production averaged 14,004 bbl/d. Algar was still ramping up at year end 2010, so we anticipate continued bitumen production improvements to be achieved throughout 2011, comparatively on a year-over-year basis and successively each quarter of 2011, under normal market conditions. Our previously-announced guidance indicated a potential range of 14,500 – 16,500 bbl/d during 2011 for Great Divide production. The difference between bitumen production and sales is recorded as inventory.

Bitumen sales in 2010 reflected not only the effective startup of Algar, but also some challenges at Pod One during the year, primarily related to unstable power supplies during the May 2010 to August 2010 period.

These issues arose from adverse weather conditions, including electrical storms, erratic supply, some stress on the regional power grid from the Algar startup and regulatory delays, which impeded a more timely construction start-up of the Algar co-generation plant and a regional substation designed to remediate the capacity of the grid in the region. There was also some collateral damage to pump efficiency and longevity at Pod One, as we experienced several premature failures of our electric submersible pumps. We believe this was due to the stop-start circumstances arising from the erratic electrical power supply conditions. We are pleased to report, however, that since the startup of the Algar co-generation plant in September 2010, power supplies have been increasingly reliable and the substation is scheduled for completion in May 2011. This should alleviate ongoing concerns about this particular issue, other than those which are weather-related.

Connacher’s peak production at Great Divide during the year occurred during the month of December 2010, when we produced 14,004 bbl/d from both projects. We saw steady and regular production improvements at Pod One following the challenges of the summer months and we are optimistic about its continued gradual, if not spectacular, improvement during 2011. We have already initiated a methane co-injection scheme on the five northern wells at Pod One. This was approved by regulators and is designed to create a “thermal blanket” near the top of the steam chamber related to the northern wells, which have never been as productive as our other wells at this project. With this effective insulation, we anticipate being able to reduce SORs associated with lower productivity and thus redirect surplus steam to better performing wells oriented to the west and south at Pod One. Accordingly, we believe this should further reduce overall SORs through an anticipated increase in overall productivity.

24

AR 2010 CONNACHER

During 2010, Connacher produced a total of 3.2 million barrels of bitumen, 322 thousand barrels of conventional crude oil and natural gas liquids and 3.3 billion cubic feet of natural gas.

At Algar, we completed construction in April 2010, commissioned the project in May 2010 and then started making and then sequentially circulating steam in 16 of the 17 horizontal SAGD well pairs we had drilled while building the plant. We commenced receiving incidental bitumen production fairly quickly and the Algar rampup occurred so efficiently we were able to achieve commerciality in October 2010 and start recording results in our accounts at that time. While overall Algar sales averaged at 1,485 bbl/d for the full year, we only recorded results in fourth quarter 2010, when Algar sales levels averaged 5,890 bbl/d. It should be remembered that normal rampups for SAGD operations generally take from between one year to one and one-half years. Accordingly, we have high hopes and are confident of continued production improvements from this project, sequentially and overall in 2011.

We plan to introduce an innovative new procedure at Algar on one of our well pads in 2011, with the anticipated commencement of a “SAGD with solvent” project. This is likely to be operative sometime in the third quarter of the year and the associated capital costs have been included in our 2011 budget. Whereas our innovation at Pod One with methane is more “remedial” in nature, the “SAGD with solvent” initiative at Algar has the potential to be a game changer for us, in terms of well productivity and recovery factors. Our lab work and simulation studies indicate there is significant potential for this initiative. We are at the cutting edge of new technological applications and if the pilot is successful, we envisage a broadened application of this process in the new wells we would plan to drill in 2012 and beyond, as and when we embark on our Great Divide expansion program. This is contemplated to increase throughput capacity at Algar from 10,000 bbl/d to 34,000 bbl/d by late 2013 or 2014. This expansion would increase our total design capacity to a level of 44,000 bbl/d at Great Divide.

Our focus on operations at Great Divide is to continue lowering SORs and increasing operating efficiency. Our field operating personnel have acquired considerable and valuable experience since we first started production at Pod One in December 2007. This experience should serve us well in our continuing and expanded operations in years to come. We believe this is why the Algar rampup has proceeded so well and why we believe we can anticipate our SOR targets will approach three, consistent with our design rates, reservoir quality and after managing the unique challenges presented by each well in the pools being exploited.

Often times we are asked if our late 2008/early 2009 curtailment permanently damaged our Pod One reservoir and we wish to assure our shareholders that this certainly does not appear to be the case. We do not anticipate this decision will have any long-term implications and this has been confirmed by our independent

AR 2010 CONNACHER

25

reserves evaluator. We did have to deal with a lean zone during 2010 at Pod One. We do not have to deal with similar issues at Algar, although we do have minor bottom water present in about three wells at Algar.

This is not dissimilar to conditions found by other successful operators in the region and has been resolved by the recent installation of pumps. We knew this condition existed before Algar was started up. Effective pumping, including the use of high temperature electrical submersible pumps at Pod One, should enable us to realize stable and improving volumes there for some time. Our next big initiative at Pod One is likely to be the drilling of “infill” wells to take advantage of the immense amount of heat we have injected as steam into the McMurray reservoir, to the point where we can anticipate drilling long reach horizontal wells, without a steam well being paired to it. We will likely conduct this drilling within the next year or so, once we recover additional temperature data to be satisfied the conditions for bitumen flow exist prior to drilling.

All of these initiatives have occurred in the normal course of our business in managing our reservoir. In keeping with our theme, our efforts since 2008 have been to “set the stage” for a consistent production performance in our upstream bitumen business. We have expanded our truck terminal at Pod One to handle added volumes related to Algar. We have aligned ourselves with rail and storage alternatives, if market conditions remain as challenging as they have been in early 2011, due to pipeline curtailment and strained storage capacity at Cushing, Oklahoma. These factors pushed back market access and adversely affected pricing in certain traditional markets. As a SAGD producer, we need continuous steam injection and continuous sales of our diluted production to minimize the prospect of any adverse short-term impact on reservoir performance arising from curtailment.

We now have the ability to produce approximately 57,000 bbl/d of steam at Great Divide. With steam generation capability largely fixed, the most effective way to increase bitumen production is to reduce SORs. We do this by efficient steam distribution in the bitumen reservoir, ensuring we optimize the allocation of steam to our 35 producing SAGD well pairs. We are just starting to steam the 17th well at Algar, which will increase the total well count to 36 SAGD well pairs. We constantly monitor our SAGD wells; we reduce SORs through the use of ESPs, which facilitate operating at lower pressure in the wellbores by reducing the amount of steam required per barrel of bitumen produced. A total of 12 ESPs, both conventional and high temperature, were in place at the end of 2010 at Pod One and we just installed three more ESPs at Algar. We were the first operator in the SAGD oil sands world to install and utilize an ultra high temperature ESP. Again, consistent with Connacher’s way of doing things, we seek out new developments and apply them expeditiously. Our calculated simple average SOR in 2010 at Pod One was approximately 3.7. Our 2010 Pod One SOR was impacted by the steaming of two new well pairs without attendant production and by power outages and resultant erratic steam production and bitumen recovery during the middle part of 2010. Our indicated average SOR for the fourth quarter 2010 at Algar was 3.9.

26

AR 2010 CONNACHER

Conventional Crude Oil Conventional crude oil and natural gas liquids production and sales in 2010 were 883 bbl/d, compared to 1,041 bbl/d in 2009, a decrease of 15 percent. This occurred due to normal declines arising from the maturity of our properties, including Battrum, which was sold subsequent to year end for approximately $57.5 million cash. Prior to sale, we had invested some capital to reverse the production decline in this legacy property, which we had owned for some time. We decided to monetize this asset due to its age and limited expansion potential. We were satisfied with the consideration we received after a broad based auction.

Subsequent to year end, we commenced activity on a light gravity crude oil resource play at our Three Hills/Twining project in central Alberta. We have now drilled three wells into the project, with one well just onstream, another about to start up and a third well preparing for a frac. All three wells were long reach horizontal wells that qualify for Alberta’s preferential royalty rate. With approximately 30 sections and up to 100 identified well locations potentially to be drilled on this project, we will assess early production results before determining the pace of development later this year and into 2012. Availability of suitable drilling and fracing equipment is challenging at this time, so we anticipate having to develop a program which will allow a longer-term alliance with select service suppliers. We approached this as a project in a manner similar to how we approached our individual oil sands projects, based on a high degree of technological analysis before embarking on major capital outlays. This means we can tap into the range of expertise we have developed internally. Our troupe is ready for action and able to follow through when called upon. Once we have the confidence arising from reliable results at Three Hills/Twining, we expect to redeploy a portion of our asset rationalization proceeds to accelerate the rate at which we capitalize on our success in the play.

Conventional Natural Gas Natural gas production and sales in 2010 were 9.1 mmcf/d, a decline of 20 percent from last year’s level of 11.4 mmcf/d. Due to oversupply in the market place, with attendant declining prices for natural gas at the wellhead, we significantly curtailed capital investment in our natural gas properties. Furthermore, with the indicated availability of natural gas at low prices, we have less incentive to retain our existing properties as a physical hedge to our project requirements at Great Divide and at our refinery in Great Falls, Montana. Without any compelling reinvestment incentive, we have now agreed to the sale of our northern Alberta natural gas assets at Marten Creek and Randall, west of our Great Divide area. We envisage a redeployment of proceeds of approximately $22.5 million to reduce net debt in the first instance. We will retain our excellent natural gas and natural gas liquids exposure at Latornell, near Resthaven in central western Alberta, due to interesting new shale prospects and other opportunities in this area, arising from the application of horizontal multi-frac drilling and stimulation for liquids-rich natural gas.

Sales, Prices On an energy equivalent basis, sales in 2010 were 10,606 boe/d compared to 9,216 boe/d in 2009, an increase of 15 percent.

West Texas Intermediate (“WTI”) crude oil prices averaged US$79.51 per barrel in 2010, compared to US$61.99 per barrel in 2009, an increase of 28 percent. The average price received for our crude oil sales in 2009 was $54.61 per barrel; in 2010 it was $65.63 per barrel, an increase of 20 percent. This reflected stronger crude oil prices in 2010, offset somewhat by a stronger Canadian dollar. Heavy crude AR 2010 CONNACHER

27

oil differentials were more volatile during 2010 and started to widen later in the year, compared to 2009.

Bitumen prices, which are a calculated price, averaged $45.65 during 2010. There was evidence of strengthening later in the year, although we experienced very low bitumen prices during August, September and October 2010 as a consequence of the Enbridge pipeline break and collateral market implications. All discussed bitumen prices are net of diluent costs and transportation charges.

While the reference AECO natural gas price averaged $3.98 per mcf in 2010, and in 2009, it deteriorated throughout the year and averaged $3.44 per mcf during the fourth quarter 2010. Our natural gas sales prices averaged $3.90 per mcf in 2010, the same as in 2009. However, our prices also deteriorated throughout 2010, as new supplies and high storage were not conducive to price escalation.

On an oil equivalent basis, our prices averaged $44.13 per boe in 2010, compared to $37.81 per boe in 2009, an increase of 17 percent. The level of prices compared to WTI reflects the quality of crude oil produced, primarily influenced by our bitumen volumes as this is low gravity crude oil. Also, natural gas is converted to equivalent values at a much higher heat ratio than is evident in the pricing relationship between an mcf of natural gas and a barrel of crude oil.

Upstream Sales Volumes (1) Oil sands – bitumen bbl/d

Q1

Q2

Q3

Q4

2010

2009 % Change

6,936

6,211

6,758

12,868

8,206

6,274

Conventional crude oil and NGLs – bbl/d

31

937

906

819

873

883

1,041

(15)

Natural gas – Mcf/d

9,662

9,278

9,158

8,318

9,101

11,407

(20)

Total – boe/d

9,483

8,663

9,103

15,128

10,606

9,216

15

(1) 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

2010 BITUMEN PRODUCTION SUMMARY

Algar

Pod One

Nov

Dec

16,000 14,000 12,000 10,000 8,000 6,000 4,000 2,000 0

Jan

Feb

Mar

Apr

May

Jun

Jul

Aug

Sept

Oct

RESERVES Connacher’s 10 percent present value (“PV10”) of its estimated pre-tax future net revenue of its proved and probable (“2P”) reserves, as evaluated by GLJ Petroleum Consultants Ltd., independent qualified reserves evaluators, (“GLJ”), as at December 31, 2010 (“Year-End 2010 Reserve Report”) was $3.1 billion, compared to $2.2 billion as at December 31, 2009, an increase of 44 percent. The PV10 of estimated pre-tax future net revenue of proved, probable and possible (“3P”) reserves as at December 31, 2010 was $3.8 billion, compared to $3.3 billion as at December 31, 2009, an increase of 16 percent. Included in 3P reserves are 104 million barrels of possible reserves with a PV10 of $748 million. The increases primarily reflect the impact of the success of the company’s core hole program at Great Divide; the 2010 completion, commissioning and start-up of Algar, our second SAGD project; the submission of an EIA application for the Great Divide Expansion Project; and a higher price deck for crude oil and bitumen used by GLJ. Possible reserves and all resources were only evaluated with respect to Connacher’s oil sands properties.

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AR 2010 CONNACHER

WORKING INTEREST RESERVES (MBBL) – BITUMEN Proved

Probable

BEFORE TAX PV10 ($MILLION) – BITUMEN

Possible

Proved

700

4,000

600

3,500

Probable

Possible

3,000

500

2,500 400 2,000 300 1,500 200

1,000

100

500

0

0 12/06

12/07

12/08

12/09

12/10

12/06

12/07

12/08

12/09

12/10

Working Interest Volumes Bitumen Reserves and Resources (mbbl) 31/12/09

31/12/10

Proved Reserves (1P) (2)

173,225

180,166

% Change 4%

Proved and Probable Reserves (2P) (2)(3)

379,180

499,657

32%

Proved, Probable and Possible Reserves (3P) (2)(3)(4)

461,672

603,709

31%

Low Estimate Contingent Resources (5)(7)

148,408

223,443

51%

Best Estimate Contingent Resources (5)(8)

134,919

220,572

63%

High Estimate Contingent Resources (4)(8)

188,766

408,908

117%

Best Estimate Prospective Resources (5)(7)

97,142

80,240

(17%)

High Estimate Prospective Resources (5)(8)

236,786

287,337

21%

Conventional Canadian Reserves

Light/Medium Oil/NGL (mbbl) 31/12/09

Proved Reserves (1P) (2) Probable Reserves (3) Proved + Probable Reserves (2P) (2)(3)

31/12/10 % Change

Natural Gas (mmcf) 31/12/09

31/12/10 % Change

2,379

2,524

7%

27,324

23,864

(13%)

845

972

15%

11,733

13,818

18%

3,224

3,496

9%

39,057

37,682

(4%)

Combined Conventional and Bitumen Reserves (9) (mboe)

31/12/09

31/12/10

% Change

6,934

6,502

(6%)

Proved Bitumen (2)

173,225

180,166

4%

Total Proved (1P)

180,159

186,668

4%

2,801

3,275

17%

Probable Bitumen(3)

205,955

319,491

55%

Total Probable (3)

208,756

322,766

55%

Proved Conventional (2)

(2)

Probable Conventional (3)

9,735

9,777

1%

Proved + Probable Bitumen(2)(3)

379,180

499,657

32%

Total Proved + Probable (2P) (2)(3)

388,915

509,434

31%

Total 3P Reserves (2)(3)(4)

471,406

613,485

30%

Proved + Probable Conventional

(2)(3)

AR 2010 CONNACHER

29

Present Value 10% Present Value of Future Net Revenue Based on Forecast Prices and Costs Bitumen Reserves and Resources – Before Tax ($million) 31/12/09

31/12/10

% Change

1,369

1,397

2%

Proved and Probable Reserves (2P) (2)(3)

2,001

2,966

48%

Proved, Probable and Possible Reserves (3P) (2)(3)(4)

Proved Reserves (1P)

(2)

3,156

3,714

18%

Low Estimate Contingent Resources (5)(7)

176

780

343%

Best Estimate Contingent Resources (5)(8)

384

571

49%

High Estimate Contingent Resources (5)(9)

531

1,212

128%

Best Estimate Prospective Resources (6)(8)

236

217

(8%)

High Estimate Prospective Resources (6)(9)

610

696

14%

31/12/09

31/12/10

% Change

122

100

(19%)

Proved Bitumen (2)

1,369

1,397

2%

Total Proved (1P)

1,491

1,497

0%

33

36

9%

632

1,569

148%

665

1,605

141%

10% Present Value of Future Net Revenue Based on Forecast Prices and Costs Combined Conventional and Bitumen Reserves – Before Tax (9) ($million)

Proved Conventional (2)

(2)

Probable Conventional (3) Probable Bitumen (3) Total Probable (3)

155

135

(12%)

Proved + Probable Bitumen (2)(3)

2,001

2,966

48%

Total Proved + Probable (2P) (2)(3)

2,156

3,101

44%

Total 3P Reserves (2)(3)(4)

3,310

3,849

16%

Proved + Probable Conventional

(2)(3)

(1) 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 (2) 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 (3) 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 (4) 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 percent probability that the quantities actually recovered will equal or exceed the sum of proved plus possible reserves (5) 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 (6) 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 contingent resources and adjustments for commercial risks have not been incorporated in the summaries set forth herein. 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 (7) 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 (8) 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 be greater or less than 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 (9) 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 best high estimate (10) Does not include undeveloped conventional land value

30

AR 2010 CONNACHER

(11) Pricing assumptions in the Year-End 2009 Report and Year-End 2010 Reserve Report were as follows:

Bitumen (wellhead) ($/bbl)

WTI (US$/bbl)

Natural Gas (AECO) ($/mcf)

Year end 2009

Year end 2010

Year end 2009

Year end 2010

Year end 2009

Year end 2010

2011

53.01

53.31

83.00

88.00

6.79

4.16

2012

54.36

54.41

86.00

89.00

6.89

4.74

2013

57.03

55.39

89.00

90.00

6.95

5.31

2014

60.77

58.50

92.00

92.00

7.05

5.77

2015

62.14

60.88

93.84

95.17

7.16

6.22

2016

63.53

62.57

95.72

97.55

7.42

6.53

2017

64.96

64.51

97.64

100.26

7.95

6.76

2018

66.41

66.27

99.59

102.74

8.52

6.90

2019

67.74

68.21

101.58

105.45

8.69

7.06

+2%/yr

+2%/yr

+2%/yr

+2%/yr

+2%/yr

+2%/yr

Thereafter

US$/CDN$ exchange rates were 0.95 in the Year-End 2009 Report and 0.98 in the Year-End 2010 Reserve Report (12) Values include processing and other income (13) Tables may not add due to rounding

Unconventional Reserves (Bitumen or Heavy Oil) Connacher owns a 100 percent working interest in approximately 100,000 net acres of oil sands leases, primarily located at its Great Divide project in northeastern Alberta, situated 80 kilometers southwest of Fort McMurray and including a 50 percent working interest in 38 sections at Halfway Creek, Alberta. Numerous oil accumulations in the McMurray formation have been identified for development.

Pod One, Connacher’s first SAGD project at Great Divide, has been producing bitumen since December 2007, with commercial production commencing March 1, 2008. Algar commenced producing bitumen in August 2010 and commerciality was achieved on October 1, 2010. Production since start-up at Great Divide through December 31, 2010 has totaled approximately 7.7 million barrels of bitumen, of which 3.2 million barrels were produced in 2010, including 2.1 million barrels of bitumen in the second half of 2010. The total production amounts have been deducted prior to the calculation of remaining reserves and resources, as at December 31, 2010. The estimates contained herein also do not reflect the company’s current 2011 core hole drilling program at Great Divide and Thornbury.

After Production of 3.2 Million Barrels of Bitumen in 2010 Total 1P bitumen reserves increased four percent over year-end 2009 levels of 173 million barrels to 180 million barrels. The Year-End 2010 Reserve Report of the crude oil, bitumen, natural gas liquids and natural gas interests of Connacher, was dated February 18, 2011 and was effective December 31, 2010 and estimated Connacher’s 1P bitumen reserves would generate $4.8 billion of undiscounted pre-tax future net revenue, with a PV10 of $1.4 billion, after deduction of future capital requirements of $2.4 billion and well abandonment costs of $84 million. This represents a two percent increase in the PV10 over last year.

Total 2P bitumen reserves were estimated at 500 million barrels, a year-over-year increase of 32 percent; 2P bitumen reserves were forecast to generate $13.2 billion of pre-tax future net revenue, with a PV10 of $3 billion, after provision for future capital of $8.4 billion and well abandonment costs of $288 million. This represents a 48 percent increase in the PV10 over last year.

Total 3P bitumen reserves, including 104 million barrels of possible reserves, were estimated at 604 million barrels, a 31 percent increases over 2009 levels, with a PV10 estimated at $3.7 billion. Connacher’s reserves hold significant value, overall and on a per share basis.

Best Estimate Contingent bitumen resources were estimated to have increased 63 percent from 135 million barrels to 221 million barrels; the pre-tax PV10 increased 49 percent to $571 million from $384 million last year. Our core hole program at Halfway Creek, Alberta was the primary contributor to this improvement.

AR 2010 CONNACHER

31

Conventional Reserves Connacher’s conventional reserve base remained fairly stable in 2010. This is generally a good sign as modest capital investment was made in these properties during the year, largely at Battrum on facilities and conventional is presently overwhelmed in scale by the magnitude of the company’s bitumen reserves and resources.

After Production of Approximately 876 Thousand Boe During 2010 1P conventional reserves declined six percent to 6.5 million boe compared to levels at December 31, 2009.

The Year-End 2010 Reserve Report estimated that Connacher’s conventional 1P reserves would generate $154 million of pre-tax future net revenue with a PV10 of $100 million, after provision for future capital requirements estimated at $9.3 million and well abandonment costs of $4.9 million.

Connacher’s 2P conventional reserves increased one percent to 9.8 million boe. The company’s 2P conventional reserves were forecast to generate $236 million of pre-tax future net revenue, with a PV10 of $135 million, after provision for future capital requirements of $22.3 million and forecast well abandonment costs of $5.6 million.

The increase in 2P reserves reflected a modest but efficient capital program during 2010 and as indicated in the lead-in, is after production during the year. The 12 percent decline in the PV10 of 2P reserves reflected the decline in 1P reserves, lower price assumptions for natural gas and higher operating costs to allow for inflationary pressures.

Subsequent to year end, Connacher sold its Battrum, Saskatchewan properties and agreed to sell its Marten Creek/Randall, Alberta interests.

Total Corporate Bitumen and Conventional (Combined Equivalent Boe) Reserves On a combined equivalent basis, at December 31, 2010 1P bitumen and conventional reserves were estimated by GLJ to be 187 million boe, an increase of four percent from the December 31, 2009 estimate of 180 million boe; 2P combined equivalent reserves were estimated to be 509 million boe, an increase of 31 percent from the December 31, 2009 estimate of 389 million boe and 3P combined equivalent reserves were estimated to be 613 million boe, an increase of 30 percent from the December 31, 2009 estimate of 471 million boe. Possible reserves rose to 104 million barrels in 2010 from 82 million barrels in 2009.

As at December 31, 2010, no reserve volumes or future net revenue or present value thereof were assigned herein to Connacher’s 18.5 percent equity interest in Petrolifera Petroleum Limited’s crude oil and natural gas reserves.

32

AR 2010 CONNACHER

Forecast Prices and Costs The undiscounted future operating expense, capital cost and abandonment costs contained in the Year-End 2010 Reserve Report were as follows: ($million) Operating costs

Proved

Proved Plus Probable

4,840

$

$

Capital costs Abandonment costs

11,248

2,457

8,408

89

293

2010 Year End 2P Reserve Volume Reconciliation (1)(2)(3) 2P (Mboe) December 31, 2009

388,914

Extensions

124,492

Infill drilling

73

Improved recovery

186

Technical revisions

48

Dispositions

(117)

Economic factors

(40)

Production December 31, 2010

(4,122) 509,434

(1) May not add due to rounding (2) Calculated based on gross reserves and forecast price case as at December 31, 2010 (3) All references to barrels of oil equivalent (boe) are calculated on the basis of 6 mcf:1 bbl. Boe may be misleading, particularly if used in isolation. A boe conversion ratio of 6 mcf:1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead

Unproved Property Valuation Connacher retained Sayer Energy Advisors (“Sayer”), independent energy advisors of Calgary, Alberta, to conduct an evaluation of its unproved properties in Western Canada. Sayer completed a report (the “Sayer Report”), with an effective date of December 31, 2010. It was prepared within the Code of Ethics of the Association of Profession Engineers, Geologists and Geophysicists of Alberta.

Sayer assigned a low value of $13.4 million, a median value of $14.6 million and a high value of $15.8 million to Connacher’s 66,210 net hectares (165,326 net acres) of petroleum and natural gas rights held in the Provinces of Alberta and Saskatchewan as at December 31, 2010. The valuation does not include any of Connacher‘s undeveloped bitumen rights, which were evaluated within the Year-End 2010 Reserve Report.

AR 2010 CONNACHER

33

INVESTMENT IN PETROLIFERA PETROLEUM LIMITED

We anticipate monetizing this investment at an appropriate time, to maximize value and to redirect proceeds to other corporate purposes.

At December 31, 2010, Connacher maintained an approximate 18.5 percent equity stake in Petrolifera Petroleum Limited, a public company with its common shares listed on the Toronto Stock Exchange. Connacher created Petrolifera in late 2005 by selling a working interest in an Argentinean concession, outside of our main focus area, to Petrolifera for treasury shares and a note, which was subsequently repaid. Over time, while supporting certain of Petrolifera’s financing initiatives, including its initial public offering, our interest in the company has been reduced to its current level.

Petrolifera enjoyed early success in its Argentinean drilling program, discovering the Puesto Morales Norte (“PMN”) crude oil and natural gas field in late 2005 and into early 2006. This early success was followed with a development drilling and facilities construction program to exploit this significant new find. Subsequently, additional lands were secured in Argentina and the company diversified its holdings by acquiring 100 percent-owned interests in Peru and later in Colombia.

In late 2007, as its operations expanded, Petrolifera’s realized price in Argentina was frozen by the local political authorities, which constricted available cash flow and liquidity. Liquidity was further hampered and partially impaired by the collapse of the Canadian commercial paper market for Asset Backed Commercial Paper (“ABCP”), highly-rated investments in which surplus corporate funds had been invested through that company’s bank. Both of these events, combined with mediocre performance from a waterflood in a portion of the PMN field, disappointing drilling in offsetting lands and declining production at PMN adversely impacted on the market price of Petrolifera’s common shares over time. As a controlling shareholder, Connacher was restricted in its ability to monetize its holdings in an arbitrary manner.

In 2009, Petrolifera commenced drilling its La Pinta well in Colombia on the Sierra Nevada License.

This proved to be a dual zone light gravity crude oil discovery but was a very costly well, due to drilling and testing issues arising from challenging overpressured geological conditions. The cost of the well further impacted on Petrolifera’s liquidity and necessitated dilutive equity financings to have the capital to meet all financial commitments and obligations associated with the company’s various exploration blocks. In better times, these commitments might have been farmed out, but the recession of 2008 and 2009 limited Petrolifera’s options. Due to Colombian restrictions on flaring

34

AR 2010 CONNACHER

Left Preparing to drill in

Colombia

Right Field work in Peru

natural gas, the La Pinta well could not be put on production until a natural gas conservation or marketing solution was secured. Inadequate free capital also constrained the company’s ability to adequately fund maintenance capital in Argentina to offset normal declines and Argentinean cash flow was then dedicated to bank debt reduction, limiting the availability of growth capital.

In 2010, Petrolifera drilled and tested a second commitment well on the Sierra Nevada License at Brillante. This proved to be a significant natural gas discovery, which tested attractive volumes on both short-term and long-term tests. While meaningful, these results occurred at a time when capital markets exhibited little, if any, interest in new natural gas finds because of the apparent emerging oversupply in North America, accompanied as it was by weak natural gas prices. Capital markets were also concerned about long-term capital requirements Petrolifera would face in future developments and how these were to be financed. Discussions to sell Argentinean assets and to farm out Peruvian properties were underway with considerable encouragement, but were protracted.

In part to serve as a catalyst to conclude negotiations regarding a possible Argentinean sale and Peru farmouts and having regard to the costs and quantum of future capital needs, the Board of Directors of Petrolifera determined in September 2010 that it was timely to engage in a strategic review process covering a broad range of alternatives.

Following an extensive canvas of alternatives, conducted by a financial advisor and under the aegis and direction of an independent committee of Petrolifera’s Board of Directors, it was concluded that entering into an arrangement agreement to effect a business combination with Gran Tierra Energy Inc. (“Gran Tierra Energy”), a well-financed oil and gas company active in all the same countries as Petrolifera, was the preferred course of action for the company and its security holders.

Connacher subsequently endorsed the transaction and entered into a support agreement to vote its shares in favor of the transaction, which will result in the receipt of approximately 3.3 million common shares and 840,000 warrants to acquire a like number of shares of Gran Tierra Energy, at a price of $9.67 for each additional common share until August 28, 2011.

Petrolifera’s shareholders will vote on the transaction on March 17, 2011 and if approved on the ensuing day by the Courts of Alberta and other regulators, Petrolifera will become a subsidiary of Gran Tierra Energy. The approximate market value of our Petrolifera investment and prospective Gran Tierra holdings, at present, is $30 million. We anticipate monetizing this investment at an appropriate time, to maximize value and to redirect proceeds to other corporate purposes. While we booked an impairment related to Petrolifera at year-end it was a non-cash charge.

The cash value of our remaining holdings exceeds our actual cash investment.

AR 2010 CONNACHER

35

our COMMITMENT

Health, Safety and the Environment Connacher’s commitment to effective health, safety, environmental and regulatory strategies is evident in all aspects of our business. From our corporate business plans, to our operating standards, to the attitudes and actions of our employees, these principles are ingrained in Connacher’s corporate fabric and culture. This starts with the appreciation, by senior management and employees alike, that for Connacher to achieve long-term corporate goals of growth, profitability and enhanced shareholder value, we must recognize the significance that sustainability plays in achieving these objectives.

Connacher is sensitive to the need for effective environmental management on an ongoing basis. We believe our environmental initiatives will significantly contribute to our long-term viability as a company.

While Connacher is in the energy business, we are simultaneously stewards of our environment and we strive to meet these obligations in a proactive manner, adopting techniques, technology and programs designed to ensure the viability of our interaction with our natural surroundings. Additionally, Connacher strives to not only meet industry standards, but also to exceed them whenever and wherever possible.

This is a priority and we are proud of our record and response to the challenges.

36 36

AR AR 2010 2010 CONNACHER CONNACHER

Responsible WATER Use Connacher recycles more than 90 percent of the water used for SAGD bitumen extraction. In order to make up the difference, wePOD draw make-up water fromPOD a deep, ONE ONE non-potable aquifer. No water is ever drawn from

GHGfor EMISSIONS EMISSIONS rivers, lakes or streams production purposes,S0 nor 2 is water ever discharged into surface water bodies.

Furthermore, Connacher’s developed land areas are designed 0.78 to allow rainfall to drain naturally back into the surrounding environment.

0.62

Saline versus non-saline 0.54 0.54 0.51 water is ideal for any in situ oil sands Why isn’t Connacher using saline water? Although subsurface saline 0.45 production facility, such aquifers do not exist in the vicinity of Connacher’s operations. In fact, in 2010 Connacher commissioned a comprehensive environmental study in an effort to identify a saline water source for its operations. After investigating all options within a 25 km radius of our operating area, we determined that no economically viable saline water alternatives existed. While Connacher’s make-up water source is non-saline, it is also non-potable, meaning that it is unsuitable for human consumption or for agricultural irrigation.

In the future, Connacher’s primary water strategy remains one of conservation. Our goal is to continue to reduce the non-saline, non-potable water intensity at our Pod One facility and to implement the same intensity reduction strategies at our Algar facility. Through a combination of new technologies and operating 2008 2010* 2009 efficiencies, Connacher has 2009 reduced the amount2008 of water used2010* to extract bitumen since we commenced per tons/1,000has m Tonsexample, of CO equivalent operations in 2008; for make-up waterS0intensity been lowered by 25 percent since startup.

2

3

2

of bitumen produced

cubic metres of bitumen

Connacher’s robust water quality monitoring programs ensured that neither surface nor groundwater quality or *as at September 30, 2010 *as at September 30, 2010 quantity was adversely affected by our activities.

SALINE GROUNDWATER SOU

RCE STUDY AREA

RAPHED

ores

)

POD ONE WATER INTENSITY

63

Birds 11%

Fort McMurray

Athabasca

0.63 0.49

River

0.46

881

Connacher (Pod One)

Woodland Caribou

Connacher (Algar)

63

Ungulates 55%

2008 2009 2010* make-up water used/m3 of bitumen produced

9,000 km2

881

(woodland caribou, moose, white-tailed deer)

*as at September 30, 2010 Connacher Land Holdings Connacher Producing Land Significant Oil Sands Operations Saline Groundwater Study Area

y Area

Saline Groundwater Source Stud

AR 2010 CONNACHER

37

“

Through enhanced operating practices, we are able to minimize the impact of our activities on the surrounding wildlife.

“

Co-existence With WILDLIFE Connacher believes that the development of bitumen resources should not occur at the expense of surrounding wildlife. Maintaining wildlife biodiversity throughout the planning, development and production phases is of paramount importance. We commit considerable resources and funds to biodiversity preservation efforts prior to the development phases, through baseline monitoring and predictive analysis, but also during and after these phases through ongoing monitoring programs and statistical analysis.

To ensure our development and operating activities do not have adverse effects on the local wildlife population, Connacher created a wildlife monitoring program. The program is designed to encompass Connacher’s entire operating area and to gather scientific evidence on the population, movement, activity and condition of the area’s wildlife species. Through techniques that include wildlife cameras, winter track surveys, wildlife sighting cards and vehicular traffic monitors, Connacher is able to collect a tremendous amount of valuable scientific data that can be evaluated by professional wildlife biologists and used to shape both current operating practices and future development strategies. Connacher’s wildlife monitoring program began prior to Connacher entering the production phase and will continue throughout this phase, which could last from 25 to 40 years or more.

One of the most effective elements of Connacher’s wildlife monitoring program is our motion-activated wildlife camera program. At present, Connacher has 37 motion-activated cameras at strategic locations within our operating area. Although they have only been in place for three years, these cameras have already captured over 10,000 photographs of more than 30 different species of local wildlife. Of particular note, over 25 percent of the wildlife photographs taken to date are of the endangered Woodland Caribou species. Our goal is to operate in harmony with all wildlife in the region.

Through enhanced operating practices, we are able to minimize the impact of our activities on the surrounding wildlife. Techniques such as low-impact seismic and minimal disturbance construction are fundamental elements of Connacher’s exploration programs, while access control, land footprint reduction and accelerated reclamation strategies are used extensively once exploration programs conclude and the production phase begins. To further augment these efforts, Connacher has also constructed naturalized wildlife crossing structures over our surface pipeline infrastructure to facilitate the free movement of wildlife.

Additionally, Connacher is a strong proponent of the regional biodiversity monitoring concept and, as such, elected to become a financial contributor to the Alberta Biodiversity Monitoring Institute (“ABMI”).

The ABMI is an independent organization that collects scientific data on over 2,000 species of plants and animals from over 1,600 monitoring locations throughout Alberta. The purpose of ABMI’s work is to monitor changes in relevant species, habitats and human land use so they may be incorporated into future planning and decision-making by land users, including industry and government.

38

AR 2010 CONNACHER

POD ONE GHG EMISSIONS

POD ONE S02 EMISSIONS 0.78

0.62 0.54

0.54

0.51

0.45 Pod One

63

Algar

great divide

Camera locatio

ns

2008 2009 2010*

2008 2009 2010*

Tons of CO2 equivalent per cubic metres of bitumen

S02 tons/1,000 m3 of bitumen produced

*as at September 30, 2010

*as at September 30, 2010

DISTRIBUTION OF WILDLIFE PHOTOGRAPHED

Rodents 5%

Other 4%

Birds 11%

Woodland Caribou

Big Carnivores 14%

Ungulates 55%

(wolf, black bear)

(woodland caribou, moose, white-tailed deer)

Small Carnivores 11% (coyote, red fox, weasel)

These photos ta ken from motio n-activated wildlife cameras within the Great Divide area.

AR AR 2010 2010 CONNACHER CONNACHER

39 39

HISTORICAL Conventional Oil & Gas exploration seismic line Connacher’s NEW Low-impact OSE seismic line

Early restoration of our small footprints are beneficial

Original

RECLAIMED New approache

s minimize land

disturbance

Minimal LAND Disturbance Since Connacher does not require open mine pits or tailings ponds to extract bitumen, we occupy only a fraction of the land required by an equivalent bitumen mining operation. By utilizing state-of-the-art directional and horizontal drilling technology, Connacher is able to access large subsurface bitumen deposits using multiple resource wells from a few strategically-placed well pads. In most cases, the natural landscape directly above a bitumen deposit requires little, if any, disturbance in order to extract the resource. Connacher’s facilities are compact and efficient, thereby minimizing the amount of long-term land disturbance necessary to accommodate them.

Connacher’s exploration and seismic programs are based on the principles of low impact and minimal disturbance followed by timely reclamation. This enables Connacher to collect an extensive amount of geologic data over a large area, while creating only a small amount of short-term surface disturbance. Upon completion of each exploration program, the associated surface disturbances immediately enter Connacher’s corporate reclamation management program. The guiding principle is to ensure that the reclamation of past land disturbances keeps pace with the development of new ones. This principle has proven to be highly successful as Connacher has already received Government of Alberta reclamation certificates for several of our historic exploration programs. In fact, Connacher anticipates that by 2015 we will have reclaimed more than 1,500 hectares of land, or the equivalent of 2,800 football fields.

40 40

AR AR 2010 2010 CONNACHER CONNACHER

es

caribou, te-tailed deer)

Cleaner AIR Through Technology The world needs more energy and crude oil. Bitumen and natural gas will continue to play a large part in meeting those needs, now and in the future. Connacher believes new, innovative technologies will help produce more crude oil, bitumen and natural gas to meet growing demand, while also reducing overall emissions. Connacher is working with a variety of new technologies to make this happen, including the Algar 13.1 megawatt co-generation facility, commissioned and activated in September 2010. This facility has enabled us to selfsupply much of our power requirements from a cleaner energy source, as it reduces demand for electricity from Alberta’s coal-fired power grid. Co-generation also generates heat that can be used in the SAGD process.

Additionally, the use of electric submersible pumps has reduced our SORs and contributed to the continuing reduction of our emissions footprint. Other innovations aimed at lowering SORs and improving productivity and energy output relative to the input required to extract bitumen will be introduced in 2011.

POD ONE GHG EMISSIONS

POD ONE S02 EMISSIONS 0.78

0.62 0.54

0.54

0.51

0.45

2008 2009 2010*

2008 2009 2010*

Tons of CO2 equivalent per cubic metres of bitumen

S02 tons/1,000 m3 of bitumen produced

*as at September 30, 2010

*as at September 30, 2010

Connacher 2010 Environmental Report

POD ONE WATER INTENSITY 0.63 0.49

0.46

2008 2009 2010* make-up water used/m3 of bitumen produced

*as at September 30, 2010

AR AR 2010 2010 CONNACHER CONNACHER

41 41

Stakeholder Relations

Connacher’s Commitment to Stakeholders Connacher is committed to working with its various stakeholders. Whether it is aboriginal groups in northern Alberta, non-profit organizations in Calgary, government agencies in Montana or its shareholder base, Connacher believes in developing strong and sustainable relationships.

Connacher is an active supporter, directly and through staff participation and involvement, in various charitable causes in the regions in which it conducts activities. Our internal donations committee appropriately places an emphasis on the needs of children, the elderly, the disabled and the unfortunates in society who require support or encouragement.

Mindful of its corporate obligations, Connacher regularly consults with stakeholders, including Aboriginal peoples, in its conduct of business throughout western Canada. Through consultation, Connacher is able to clearly share its vision of growth and receive feedback from stakeholders about issues concerning the environment and wildlife, together with economic and social development.

Connacher has a great story to tell and is proud to share it. Connacher works with industry organizations such as the In Situ Oil Sands Alliance (“IOSA”), the Oil Sands Developers Group (“OSDG”) and others to host tours and advance the understanding of the importance of the in situ method of oil sands development. Politicians from various levels of government, elders and chiefs and other stakeholders and dignitaries from across North America have had escorted tours while visiting Connacher’s Great Divide sites with these objectives in mind.

Clearly these visits are carefully organized and limited for obvious safety reasons.

In Montana, we have excellent relationships with the citizens and city of Great Falls and our refinery personnel regularly engage in joint emergency response exercises with various local, state and federal agencies to ensure preparedness and coordination in case of an emergency.

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“

Connacher believes in sharing economic development opportunities with local businesses everywhere it operates.

“

Building Relationships and Creating Opportunities Connacher believes in sharing economic development opportunities with local businesses everywhere it operates. In Montana, we focus on the use of local businesses and services. At the Great Divide oil sands project in northern Alberta, exploration, development and construction work provides local businesses an opportunity to grow and develop alongside Connacher, as it continues to expand its SAGD projects. By using local contractors, Connacher is helping to create sustainable businesses and working partnerships that benefit all parties.

During 2010, Connacher formalized several agreements with the aboriginal communities of northeastern Alberta. Connacher signed Memoranda of Understanding and Cooperation Agreements with both First Nations and Métis stakeholders. These documents outline how Connacher will engage the aboriginal groups and cooperate with them for the term of the agreements. These agreements further develop and strengthen the relationship between Connacher and its aboriginal stakeholders.

At Great Divide, Connacher created new positions specifically targeted at aboriginal candidates. For example, the “Maintenance Assistant” position was created to enable Connacher to recruit young aboriginals into its oil sands operations. These types of positions were designed to expose these new employees to trades common to SAGD operations. Maintenance Assistants are mentored by electricians, instrumentation technicians, welders and millwrights. By exposing new employees to these trades, our objective is to eventually have them indentured as an apprentice in one of the trades.

By recruiting, teaching, and supporting young apprenticeships, Connacher is helping to create a sustainable workforce for its continued growth while simultaneously providing opportunities for young aboriginals to grow and prosper as a member of the Connacher talent pool.

As a result of our meaningful relationship with its aboriginal stakeholders in northeastern Alberta, a traditional blessing ceremony was conducted at the Algar site in August 2010 by members of the Fort McMurray #468 First Nation. A caribou crossing was chosen as the blessing site which also reflects our joint commitment to both regional wildlife and the environment.

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43

Corporate Governance and Social Responsibility Connacher Oil and Gas Limited, its Board of Directors and its Management are collectively committed to a high standard of corporate governance practices. This commitment is believed not only to be in the best interest of shareholders, but that it also promotes effective decision making at all levels of the company’s activities.

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.

Connacher’s 2010 Board of Directors was comprised of eight individuals. Six of these Directors were non-Management and five were considered independent. All of the company’s Board Committees were comprised of the non-Management Directors.

The Chairs of Connacher’s Audit and Reserves Committees are considered experts. The Chair of our Audit Committee is a Fellow Chartered Accountant who held the position of Deputy Chairman with a recognized national accounting firm, prior to his retirement and subsequent appointment to Connacher’s Board of Directors. The Chair of our Reserves Committee was the President of an independent engineering consulting firm, prior to his retirement and subsequent appointment to Connacher’s Board.

In total, Connacher has five Board Committees, including Audit, Governance, Human Resources, Reserves and Health, Safety and Environment.

Connacher’s Human Resources Committee, which oversees and makes recommendations with respect to the remuneration of management, was entirely comprised of independent Directors. Connacher’s Lead Director was an independent Director and the Governance Committee is comprised of non-Management Directors.

The Governance Committee makes recommendations on the remuneration of non-Management Directors to the full Board. At the Board level, all Directors participate in voting upon the remuneration to be awarded to non-Management Directors. The Governance Committee sought advice from an independent compensation consultant in the initial establishment of remuneration for its independent Directors and the Human Resources Committee has on occasion similarly sought assistance in its deliberations on remuneration, short-term and long-term incentives and other consideration for management and staff.

Connacher has developed a mandate for its Board of Directors, each Committee of the Board, the Lead Director, individual Directors, the Chair of each committee, the Chairman of the Board and for the Chief Executive Officer. These are reviewed annually by the Governance Committee and updated to take into account changes or developments considered beneficial to good governance practices.

Additionally, the Governance Committee assesses individual performance of Directors and numerous other items, which are detailed in the company’s Information Circular and attachments thereto. A Directors’ Skills Matrix has been developed to assist in evaluating Board composition and the expertise of potential new 44

AR 2010 CONNACHER

Connacher believes it is a fair and sound employer, a good corporate citizen and that it conducts its business in a proper manner.

nominees, in broadening the overall Board skill level and diversifying the Board. A succession plan has been advanced with the assumption of the role of Chairman and Chief Executive Officer by the former President and the appointment of a new President who is continuing as Chief Operating Officer and has also become a member of the Board of Directors. While no formal and final timeline or commitment for accession to the added role of Chief Executive Officer for the President has been established, it is generally anticipated this will occur, subject to final Board concurrence, in approximately three years or when the current Chief Executive Officer achieves the age of seventy years.

Connacher also has a Disclosure Committee, comprised of the Chief Executive Officer, counsel (as required) and internal operating and financial personnel with a sound understanding of various aspects of Connacher’s business to ensure full, true, plain and timely disclosure of material facts to the public and our shareholders based on reliable information. Our objective is to provide useful, understandable, correct and timely information to our shareholders. A log is maintained and this Committee reports through the Governance Committee to the Board of Directors.

The company has also adopted various Board-approved policies with respect to sound business conduct, especially with respect to Disclosure, Trading in Securities, Reporting of Inappropriate Activity and Authorization and Approval Procedures and also has additional company policies which deal with a Respectful Workplace, Violence in the Workplace, Fit-to-Work and Privacy. Connacher also has a Code of Ethics. These are updated and reviewed on a regular basis or as required by management, its Governance Committee and the Board of Directors, as appropriate.

Connacher is mindful of safety in the workplace and under the auspices of the Health, Safety and Environment Committee, management has developed a Safety Program Manual and has adopted Emergency Response Plans to deal with possible disasters, including for example, sour gas emissions. A safety video for presentation to all employees, trades, subtrades and suppliers has been developed and rolled out to our various field offices and activity sites, including in Montana where Connacher operates a refinery within the city limits of Great Falls. Our Montana operation has also developed its own safety and emergency response procedures in conjunction with local and State authorities, as required by US law.

Connacher has a trading blackout policy which is imposed pursuant to its Trading in Securities Policy. This is invoked by the Chief Executive Officer or his designee, the Assistant Corporate Secretary and it is applicable to all employees and insiders, as legally defined and to related parties of such individuals, including one’s spouse and family members. It is generally invoked prior to the release of material information and remains in full force and in effect for one business day of market trading thereafter, to allow for dissemination of information to the investing public. In some circumstances, the blackout period is extended, especially around the time of release of critical financial and operating results. Insiders also have an overriding obligation to adhere to all prevailing securities laws in respect of inside information and tipping.

Connacher believes it is a fair and sound employer, a good corporate citizen and that it conducts its business in a proper manner. Its constituent parts – the company, the Board of Directors, management and staff – endorse good governance practices. An emphasis is placed on strong internal financial and operating controls and this commitment is manifested in the company’s reputation as a good place to work, as a good company with which to do business and as a company in which to be a shareholder.

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45

MANAGEMENT’S DISCUSSION AND ANALYSIS Richard R. Kines Vice President, Finance and Chief Financial Officer

This Management’s Discussion and Analysis (“MD&A”) for Connacher Oil and Gas Limited (“Connacher” or the “company”) is dated March 17, 2011 and should be read in conjunction with the audited consolidated financial statements for the year ended December 31, 2010 and the audited consolidated financial statements and MD&A for the year ended December 31, 2009. The consolidated financial statements have been prepared in accordance with Canadian generally accepted accounting principles (“GAAP”) and are presented in Canadian dollars (C$). MD&A provides management’s view of the financial condition of the company and the results of its operations for the reporting periods.

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 the company’s website at www.connacheroil.com.

BACKGROUND INFORMATION AND BUSINESS STRATEGY Headquartered in Calgary, Alberta, Canada, Connacher is a growing integrated crude oil and natural gas company with a focus on producing bitumen and expanding its in situ oil sands projects located near Fort McMurray, Alberta.

Connacher also owns and operates conventional crude oil and natural gas production in Alberta and owns and operates a heavy oil refinery in Great Falls, Montana. Connacher also owns 26.9 million common shares representing 18.5 percent of Petrolifera Petroleum Limited (“Petrolifera”) and 6.8 million Petrolifera share purchase warrants.

Petrolifera is engaged in petroleum and natural gas exploration, development and production activities in South America. Petrolifera is in the process of being acquired by Gran Tierra Energy Inc. pursuant to a plan of arrangement which is anticipated to close on or about March 18, 2011. Connacher will then become a shareholder of Gran Tierra Energy Inc., a listed public company. These shares may be monetized by Connacher in due course.

The company’s business is conducted through two major business segments – upstream in Canada and downstream in the United States of America (“U.S.A.”) through its wholly owned subsidiary, Montana Refining Company, Inc. (‘‘MRCI’’). Upstream includes exploration, development and production of bitumen, crude oil, natural gas and natural gas liquids. Downstream includes refining of crude oil to produce and market gasoline, jet fuel, diesel fuels, asphalt and ancillary products.

Connacher’s overall objective is to create shareholder value. Specific goals that contribute to the achievement of this objective and the innovative and committed strategy in pursuit of these goals are tabulated below: OBJECTIVES • Optimize bitumen production at Great Divide • Position the company to achieve bitumen productive capacity of 44,000 bbl/d, following receipt of regulatory approval anticipated in late 2011 • Continue to grow bitumen and conventional reserves and resources • Introduce innovative solutions to enhance optimization objective 46 46

AR AR 2010 2010 CONNACHER CONNACHER

“

Connacher’s overall objective is to create shareholder value.

“

STRATEGY • Own and operate large working interests in oil and gas properties • Focus on projects exhibiting characteristics of expandability, repeatability and sustainability • Mitigate and manage the risks of a smaller company in the oil sands with an integrated approach • Operate with financial discipline, maintain a high level of liquidity and prefund major capital programs

CONSOLIDATED FINANCIAL AND OPERATING REVIEW SELECT ANNUAL INFORMATION ($000 except per share amounts) Revenue, net of royalties Cash flow (1) Cash flow per share – basic and diluted (1) Net earnings (loss) Net earnings (loss) per share – basic and diluted Additions to property, plant and equipment Total assets Long-term debt

2010

2009

2008

$ 574,302

$ 428,214

$ 636,734

36,884

12,522

54,817

0.09

0.04

0.26

(38,798)

26,158

(26,603)

(0.09)

0.08

(0.13)

247,978

322,064

351,736

1,683,998

1,741,866

1,431,675

$ 843,601

$ 876,181

$ 778,732

(1) Cash flow is a non-GAAP measure, which is defined in the Advisory section of the MD&A

In 2010, higher revenue in both upstream and downstream segments contributed to a 34 percent increase in total net revenue compared to 2009. Upstream revenue increased by 41 percent, primarily as result of a 31 percent increase in bitumen sales volume (8,206 bbl/d in 2010 compared to 6,274 bbl/d in 2009) as a result of the completion of the construction 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 ($44.13/boe in 2010 compared to $37.81/boe in 2009) contributed to increased revenue in 2010 compared to 2009. 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 24 percent in 2010, compared to 2009, due to a 10 percent increase in the sales volume of refined petroleum products (10,080 bbl/d in 2010 compared to 9,188 bbl/d in 2009) due to increased crude oil refining volumes. We experienced a 15 percent increase in the weighted average sales price of refined petroleum products sold ($88.68/bbl in 2010 compared to $77.05 per bbl in 2009) due to higher benchmark prices and from sales of our specialty asphalt products under favorable price arrangements.

In 2009, revenue decreased by 33 percent compared to 2008. Although upstream production and sales volumes increased in 2009, the impact of reduced market pricing for crude oil and refined petroleum products, caused by the economic downturn in 2009 and lower volumes of refined petroleum products produced and sold resulted in lower revenues in 2009 compared to 2008.

In 2010, cash flow increased 195 percent compared to levels achieved in 2009, primarily due to higher upstream and downstream netbacks and lower realized risk management contract losses, partially offset by higher finance charges and lower realized foreign exchange gains.

AR 2010 CONNACHER

47

Lower cash flow in 2009 compared to 2008 was due to lower upstream and downstream selling prices, higher realized risk management contract losses and higher finance charges.

Notwithstanding higher upstream and downstream cash flow, the company incurred a net loss of $38.8 million in 2010 compared to net earnings of $26.2 million in 2009. This was primarily due to lower unrealized foreign exchange gains, higher depletion, higher finance charges and an impairment charge related to our equity investment in Petrolifera in 2010.

In 2009, net earnings were higher than in 2008 primarily due to higher unrealized foreign exchange gains.

The company incurred capital expenditures of $248 million in 2010 compared to $322 million in 2009, as our main capital project, Algar, was completed in 2010.

A slight decrease in total assets in 2010 was primarily due to a decrease in cash balances. Higher cash balances in 2009 compared to 2010 were primarily due to financings completed in late 2009.

Total assets increased as at December 31, 2009 compared to December 31, 2008 as a result of capital additions to our oil sands properties.

Although the face value of our long-term debt did not change in 2010, its carrying value decreased slightly 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 is denominated in US dollars.

The increase in long-term debt at December 31, 2009 compared to December 31, 2008 was primarily due to the issuance of First Lien Senior Notes in 2009.

SELECT QUARTERLY INFORMATION Q1 2009

Q2 2009

Q3 2009

Q4 2009

Q1 2010

Q2 2010

Q3 2010

Q4 2010

$ 62,602

$ 101,529

$ 153,798

$ 110,285

$ 119,602

$ 142,975

$ 152,391

$ 159,334

(4,692)

9,570

10,410

(2,766)

3,948

8,668

15,178

9,090

Cash flow per share – basic (1)

(0.02)

0.04

0.03

(0.07)

0.01

0.02

0.04

0.02

Cash flow per share – diluted (1)

(0.02)

0.03

0.03

(0.07)

0.01

0.02

0.04

0.02

($000 except per share amounts) Revenues, net of royalties Cash flow (1)

(46,844)

39,966

47,767

(14,731)

5,546

(33,126)

7,946

(19,164)

Net earnings (loss) per share – basic

(0.22)

0.15

0.12

(0.03)

0.01

(0.08)

0.02

(0.04)

Net earnings (loss) per share – diluted

(0.22)

0.14

0.11

(0.03)

0.01

(0.08)

0.02

(0.04)

$ 64,255

$ 40,236

$ 100,727

$ 116,846

$ 118,272

$ 59,316

$ 49,842

$ 20,548

Net earnings (loss)

Additions to property, plant and equipment

(1) Cash flow is a non-GAAP measure, which is defined in the Advisory section of the MD&A

In the fourth quarter 2010 (“Q4 2010”), higher revenue in both upstream and downstream segments contributed to a 44 percent increase in revenue compared to Q4 2009. Upstream revenue increased in Q4 2010 compared to Q4 2009 due to higher sales volume (15,128 boe/d in Q4 2010 compared to 8,690 boe/d in Q4 2009), resulting from the completion of the construction of Algar and inclusion of its operating results from October 1, 2010. Downstream revenues increased in Q4 2010 compared to Q4 2009 primarily due to increase in the weighted average sales price of refined products ($94.47/bbl in Q4 2010 compared to $71.73/bbl in Q4 2009), resulting from generally higher benchmark prices and also due to increased throughput resulting from improved reliability.

In Q4 2010, cash flow was significantly higher compared to Q4 2009, primarily due to higher upstream and downstream pricing and sales volumes, as noted above.

Despite higher upstream and downstream netbacks, the company incurred a net loss of $19.2 million in Q4 2010 compared to net loss of $14.7 million in Q4 2009 primarily due to higher non-cash charges for risk management contracts, depletion and an impairment charge relating to our investment in Petrolifera.

The company had capital expenditures of $20.5 million in Q4 2010, compared to $117 million in Q4 2009. A significant portion of capital expenditures in Q4 2009 were incurred at our oil sands properties for construction of Algar, which was completed earlier in 2010.

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AR 2010 CONNACHER

SEGMENTED FINANCIAL AND OPERATING REVIEW UPSTREAM – CANADA COMMODITY PRICES AND RISK MANAGEMENT Three months ended December 31

Years ended December 31

% Change

2010

2009

% Change

$ 76.03

12

$ 79.51

$ 61.99

28

4.62

(22)

3.98

3.98

-

67.87

67.66

-

67.23

58.66

15

18.35

12.82

43

14.69

11.89

24

Bitumen – C$/bbl

45.08

48.23

(7)

45.65

39.39

16

Crude oil – C$/bbl

66.72

67.24

(1)

65.63

54.61

20

3.44

4.34

(21)

3.90

3.90

-

$ 44.09

45.76

(4)

$ 44.13

37.81

17

2010

2009

$ 85.16 3.61

Western Canadian Select (WCS) C$/bbl Differential – WTI/WCS C$/bbl

Average benchmark prices West Texas Intermediate (WTI) crude oil US$/barrel at Cushing Natural Gas (Alberta spot) C$/Mcf at AECO

Average realized prices

(1)

Natural gas – C$/Mcf Weighted average sales price – C$/boe

(2)

(1) Before royalties and risk management contract gains or losses and after applicable diluent and transportation costs divided by actual sales volumes (2) Boes are defined in the Advisory section of the MD&A

Connacher’s crude oil and bitumen production slate is a heavy gravity crude. Consequently, the crude oil and 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”.

In 2010, higher benchmark crude oil prices resulted in higher realized average selling prices for bitumen and crude oil compared to 2009. The increase was partially offset by wider heavy oil differentials and a stronger Canadian dollar relative to the US dollar. Realized natural gas prices in 2010 were in line with benchmark prices.

In Q4 2010, the heavy oil differential discount widened due to Enbridge pipeline disruptions in the U.S.A. that limited the transportation capacity of heavy crude products, resulting in lower realized crude oil and bitumen selling prices compared to Q4 2009. Lower AECO natural gas prices in Q4 2010 resulted in lower realized selling prices for natural gas in Q4 2010 compared to Q4 2009.

Diluted bitumen (“dilbit”), crude oil and natural gas are generally sold on month-to-month sales contracts negotiated with major Canadian or US marketers, refiners, regional upgraders or other end users, at either spot reference prices or at prices subject to commodity contracts based on WTI market prices for crude oil and AECO market prices for natural gas. In this regard, 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 preferred diluent supplies, Connacher also utilizes short-term diluent purchase contracts. As a means of managing the risk of commodity price volatility, Connacher enters into risk management commodity sales contracts from time to time.

Consequently, our revenue in 2010 was also influenced by the following WTI crude oil price risk management contracts: • January 1, 2010 – December 31, 2010 – 2,500 bbl/d at WTI US$78.00/bbl; • February 1, 2010 – April 30, 2010 – 2,500 bbl/d at WTI US$79.02/bbl; • May 1, 2010 – December 31, 2010 – 2,500 bbl/d at a minimum of WTI US$75.00/bbl and a maximum of WTI US$95.00/bbl; • January 1, 2011 – March 31, 2011 – 1,000 bbl/d at WTI US$86.10/bbl; • January 1, 2011 – March 31, 2011 – 1,000 bbl/d at WTI US$88.10/bbl; • January 1, 2011 – December 31, 2011 – 2,000 bbl/d at WTI US$90.60/bbl and the counterparty has a right, on December 30, 2011, to extend the maturity of the contract for one additional year at the same price; • January 1, 2011 – March 31, 2011 – 2,000 bbl/d at a minimum of WTI US$80.00/bbl and a maximum of WTI US$100.25/bbl; • April 1, 2011 – June 30, 2011 – 2,000 bbl/d at WTI US$85.25/bbl; • April 1, 2011 – March 31, 2012 – 2,000 bbl/d at a minimum of WTI US$80.00/bbl and a maximum of WTI US$96.00/bbl; and • July 1, 2011 – June 30, 2012 – 2,000 bbl/d at a minimum of WTI US$80.00/bbl and a maximum of WTI US$100.00/bbl.

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49

Subsequent to December 31, 2010, the company entered in the following risk management contract: • January 1, 2012 – December 31, 2012 – 2,000 bbl/d at a minimum of WTI US$80.00 bbl/d and a maximum of WTI US$120.00/bbl.

The company recorded unrealized and realized losses of $13.6 million and $1.7 million, respectively, in 2010 (2009 – unrealized and realized losses of $4.5 million and $20.6 million, respectively) on the above risk management contracts.

PRODUCTION AND SALES VOLUMES (1) 2010

2009

Dilbit sales – bbl/d (2)

11,012

8,493

30

Diluent used – bbl/d (2)

(2,806)

(2,219)

26

Years ended December 31

% Change

8,206

6,274

31

Change in inventory – bbl/d

93

-

100

Bitumen produced – bbl/d (2)

8,299

6,274

32

883

1,041

(15)

Bitumen sold (2)

Crude oil produced and sold – bbl/d

9,100

11,407

(20)

Total production volumes – boe/d

10,699

9,216

16

Total sales volumes – boe/d (3)

10,606

9,216

15

Natural gas produced and sold – Mcf/d

(1) 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. 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. Daily production and sales averages are based on a total calendar year (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 sales volumes differ from its production volumes due to changes in inventory

Bitumen production increased by 32 percent in 2010 compared to 2009, primarily due to the completion of the company’s second oil sands project, Algar. In late September 2010, the company completed the conversion of a majority of Algar’s well pairs to full-scale steam-assisted gravity drainage (“SAGD”) bitumen production and accordingly processed increasing levels of bitumen through the surface plant. Consequently, Algar production was included in the above volumes from October 1, 2010. Algar average production was 1,510 bbl/d in 2010, as incorporated above on a calendar year basis.

At Pod One, the company’s first oil sands project, production for the year 2010 averaged 6,789 bbl/d compared to 6,274 bbl/d in 2009, representing an increase of eight percent. Production was affected by evaporator performance issues and by numerous periodic power outages and related pump failures in the summer of 2010. Operational reliability at Pod One and Algar has improved subsequent to the activation of a newly constructed co-generation facility at Algar in early September 2010 which also reduced power demands on the regional grid.

In 2010, conventional crude oil and natural gas production and sales volumes decreased by 15 percent and 20 percent respectively, compared to 2009, primarily due to natural reservoir declines resulting from reduced capital spending on conventional properties.

UPSTREAM REVENUE (1) Year ended December 31, 2010 Oil sands

Crude oil

Natural gas

Gross upstream revenues (2) $ 247,187

$ 21,229

$ 12,942

($000 except per unit amounts)

Year ended December 31, 2009

Total

Oil sands

Crude oil

Natural gas

Total

$ 281,358

$ 162,640

$ 21,070

$ 16,232

$ 199,942

Diluent costs (3)

(91,644)

-

-

(91,644)

(60,407)

-

-

(60,407)

Transportation costs

(18,806)

(66)

(1)

(18,873)

(12,031)

(321)

(3)

(12,355)

$ 136,737

$ 21,163

$ 12,941

$ 170,841

$ 90,202

$ 20,749

$ 16,229

$ 127,180

Price ($ per bbl/Mcf/boe) (4) $ 45.65

$ 65.63

$ 3.90

$ 44.13

$ 39.39

$ 54.61

$ 3.90

$ 37.81

Revenues

(1) 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. 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 cost have been included in “Upstream-diluent purchases and operating costs” in the consolidated financial statements. Diluent costs, above, include purchases of $14.3 million from our subsidiary, MRCI in 2010 and $7 million in 2009 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 50

AR 2010 CONNACHER

Gross upstream revenues increased by 41 percent in 2010 compared to 2009, primarily due to higher bitumen revenue, partially offset by lower natural gas revenue. Higher bitumen revenue in 2010 was due to higher bitumen sales volumes at higher realized commodity selling prices.

Diluent used represented approximately 25 percent of the dilbit barrel sold in 2010 (26 percent in 2009). Total diluent costs increased by 52 percent in 2010 compared to 2009, primarily due to the 31 percent increase in bitumen sales volume for the year and a 20 percent increase in diluent pricing, which was driven by higher energy prices in 2010.

Transportation costs are costs to transport dilbit and crude oil to customers. Transportation costs increased by 53 percent in 2010 compared to 2009, due to the 31 percent increase in bitumen sales volumes, higher trucking costs and increased sales travel distances to markets in 2010, due to the Enbridge pipeline disruptions. In 2009 and 2010, all of our dilbit sales were transported by trucks. We continue to evaluate the merits of a sales pipeline as a transportation alternative. Additionally, we recently commenced railing some dilbit to new U.S.A. markets to alleviate downstream related barriers to the overall production rampup at Great Divide and to access new sales markets that are less tied to current WCS pricing levels. Although this will result in higher transportation costs and higher inventory levels and related carrying costs, we anticipate higher netbacks may be achieved.

ROYALTIES (1) Year ended December 31, 2010

Year ended December 31, 2009

Oil sands

Crude oil

Natural gas

Royalties

$ 5,440

$ 5,713

$ 172

$ 11,325

$ 2,370

$ 4,990

$ 623

$ 7,983

Royalties ($ per bbl/Mcf/boe) (2)

$ 1.82

$ 17.72

$ 0.05

$ 2.93

$ 1.03

$ 13.13

$ 0.15

$ 2.37

($000 except per unit amounts)

Total

Oil sands

Crude oil

Natural gas

Total

(1) 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. 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 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 2010 increased by 42 percent compared to 2009, primarily due to higher oil prices. This was reflected in higher per unit royalty costs for bitumen and crude oil. The reduction in the 2010 per unit royalty cost for natural gas, compared to the 2009, reflected Alberta gas cost allowance recoveries in conjunction with lower natural gas prices.

Our oil sands royalties are computed on a “gross basis” (before recovering allowed capital and other costs) at one percent of gross bitumen revenue when oil trades at or below the WTI equivalency of C$55.00 per barrel, increasing to nine percent when the WTI equivalency is at or above C$120.00 per barrel. After payout of allowed capital and other costs, oil sands royalties are also to be computed on a “net basis” (bitumen revenue less allowed operating and other costs) calculated at 25 percent when the WTI equivalency is less than or equal to C$55.00 per barrel, escalating to 40 percent, when the WTI equivalency is at or above C$120.00 per barrel. The oil sands royalty then payable would be the higher of the computed gross and net amounts. Based on recent bitumen selling prices and our internal analysis, a royalty payout position is not anticipated until 2015.

OPERATING COSTS (1) Year ended December 31, 2010

Years ended December 31, 2009

Oil sands

Crude oil

Natural gas

Total

Oil sands

Crude oil

Natural gas

Total

Operating costs

$ 60,344

$ 4,407

$ 5,403

$ 70,154

$ 42,980

$ 4,380

$ 9,407

$ 56,767

Operating costs ($ per bbl/Mcf/boe) (2)

$ 20.15

$ 13.67

$ 1.63

$ 18.12

$ 18.77

$ 11.53

$ 2.26

$ 16.88

($000 except per unit amounts)

(1) 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. 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

AR 2010 CONNACHER

51

Total operating costs in 2010 were 24 percent higher than in 2009, primarily due to higher operating costs in our oil sands operations. Oil sands operating costs increased by 40 percent in 2010 compared to 2009 and by seven percent on a per unit basis in 2010 compared to 2009.

The primary reason for the increase in total and per unit oil sands operating costs in 2010, compared to 2009, were costs associated with unplanned evaporator and treating system maintenance in the first quarter of 2010, combined with costs associated with numerous plant shut downs and start-ups resulting from an abnormally high occurrence of power failures experienced at Pod One in the summer of 2010. There was also collateral wear on down-hole pumps, necessitating some replacements earlier than anticipated. In September 2010, a 13.1 megawatt co-generation facility at Algar was commissioned and commenced operations. This has resulted in stable and adequate power at Algar and helped increase power reliability at Pod One. The resultant reduction of grid-related power outages continues to improve production performance reliability at Pod One. The completion of an electric substation by the regional power utility at Great Divide in the first half of 2011 is anticipated to provide additional power reliability for our oil sands operations, as surplus power from the Algar Co-generation facility will then be able to be directed to Pod One, reducing reliance on the third-party power grid. Additionally, the continued rampup of bitumen production at Algar in 2011 should spread our fixed operating costs over a larger production base, lowering unit operating costs.

The tables below summarize information related to our oil sands operating costs: 2010

Years ended December 31

Natural gas costs (1) Other operating costs Total oil sands operating costs

2009

($000)

%

($000)

%

$ 18,142

30

$ 13,480

31

42,202

70

29,500

69

$ 60,344

100

$ 42,980

100

(1) Excluding risk management contract gains and losses. Includes natural gas consumed by boilers and other vessels at Great Divide

In 2010 the combined full year steam:oil ratio (“SOR”) from Pod One and Algar was 4.3; in 2009, when only Pod One was in operation, it was 3.7. The 2009 and 2010 SORs reflect the initial steaming of new well pairs in each year (two new well pairs in each of 2009 and 2010 for Pod One and 16 new well pairs for Algar in 2010). It is a common SAGD practice to circulate steam into new wells for approximately 90 days before converting the wells to full SAGD production. During this steam circulation phase, minimal bitumen (oil) is produced and consequently, SORs are typically higher than experienced during the long-term production phase. As production ramps up from these new wells and as we apply additional enhanced recovery techniques, we anticipate lower SORs. The company also recorded risk management contract losses of $1.3 million relating to the following AECO natural gas purchase contracts. These losses are not included in the calculation of operating costs noted in the table above.

• September 1, 2010 – August 31, 2011 – 4,000 GJ/d at AECO CAD$3.87/GJ; and • October 1, 2010 – September 30, 2011 – 4,000 GJ/d at AECO CAD$4.20/GJ. Conventional crude oil operating costs were slightly higher in 2010, due to additional expensed work-overs; on a per unit basis, they were higher primarily due to a significant fixed component and lower production volumes in 2010.

Natural gas operating costs were lower in 2010, due to improved operating efficiencies arising from capital investment in 2009, notwithstanding lower production volumes in 2010.

52

AR 2010 CONNACHER

UPSTREAM NETBACKS (1) ($000 except per unit amounts) Year ended December 31, 2010

Oil sands ($000)

Bitumen ($ per bbl)

Crude oil ($000)

Revenues (2)

$ 136,737

$ 45.65

$ 21,163

Crude oil Natural gas Natural gas ($ per bbl) ($000) ($ per Mcf) $ 65.63

$ 12,941

$ 3.90

Total ($000)

Total ($ per boe)

$ 170,841

$ 44.13

(5,440)

(1.82)

(5,713)

(17.72)

(172)

(0.05)

(11,325)

(2.93)

(60,344)

(20.15)

(4,407)

(13.67)

(5,403)

(1.63)

(70,154)

(18.12)

Netbacks (3)

$ 70,953

$ 23.68

$ 11,043

$ 34.24

$ 7,366

$ 2.22

$ 89,362

$ 23.08

Year ended December 31, 2009

Oil sands ($000)

Bitumen ($ per bbl)

Crude oil ($000)

Crude oil ($ per bbl)

Natural gas ($000)

Natural gas ($ per Mcf)

Total ($000)

Total ($ per boe)

Revenues (2)

$ 90,202

$ 39.39

$ 20,749

$ 54.61

$ 16,229

$ 3.90

$ 127,180

$ 37.81

(2,370)

(1.03)

(4,990)

(13.13)

(623)

(0.15)

(7,983)

(2.37)

Royalties Operating costs

Royalties Operating costs Netbacks (3)

(42,980)

(18.77)

(4,380)

(11.53)

(9,407)

(2.26)

(56,767)

(16.88)

$ 44,852

$ 19.59

$ 11,379

$ 29.95

$ 6,199

$ 1.49

$ 62,430

$ 18.56

(1) 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. 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 non-GAAP measure and are defined in the Advisory section of the MD&A

Total upstream netbacks were 43 percent higher in 2010 compared to 2009, due to higher sales volumes and higher realized prices of bitumen and crude oil. Sales volumes of bitumen increased by 31 percent in 2010 compared to 2009, primarily due to new production at Algar. Bitumen and crude selling oil prices increased by 16 percent and 20 percent, respectively, in 2010 compared to 2009, consistent with higher benchmark oil prices.

DOWNSTREAM – U.S.A. Connacher’s 9,500 bbl/d heavy oil refinery is located in Great Falls, Montana (the “Refinery”) and is strategically aligned with our oil sands business. It primarily processes Canadian heavy crude oil (similar to Great Divide dilbit) into a range of higher value refined petroleum products, including regular and premium gasoline, jet fuel, diesel and asphalt. 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.

The Refinery is complex and includes reforming, isomerization and alkylation processes for formulation of gasoline blends, hydro-treating for sulphur removal 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 neighboring regions, including, Alberta, Canada, by truck and rail transport.

The Refinery is subject to a number of seasonal factors which cause product sales revenues 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, prices and volumes for our asphalt sales tend to be 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 and the production and sale of diesel, which has a higher winter demand. As a result, inventory levels, sales volumes and prices can be expected to fluctuate on a seasonal basis.

COMMODITY PRICES AND RISK MANAGEMENT Three months ended December 31

Years ended December 31

2010

2009

% Change

2010

2009

% Change

$ 85.16

$ 76.03

12

$ 79.51

$ 61.99

28

Average benchmark prices West Texas Intermediate (WTI) crude oil US$/barrel at Cushing Average realized prices (1) Gasoline – US$/bbl Diesel – US$/bbl

88.35

75.51

17

87.55

69.16

27

107.82

83.98

28

95.03

71.42

33

Asphalt – US$/bbl

79.22

57.11

39

81.37

67.76

20

Jet fuel – US$/bbl

$ 105.18

$ 89.82

17

$ 96.55

$ 82.29

17

(1) Before risk management contracts gains and losses and after transportation costs AR 2010 CONNACHER

53

Higher world prices for refined products in 2010 compared to 2009 resulted in higher realized weighted average sales prices for our refined petroleum products. Sales of refined petroleum products are generally made on monthly 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. Occasionally, sales contracts are for periods in excess of one month. As at December 31, 2010, MRCI has agreements to sell approximately 667,000 barrels of asphalt at a weighted average price approximating US$95.00 per barrel.

To mitigate some of the risk of reduced gasoline selling prices and margins, the company entered into a risk management contract to sell 2,000 bbl/d of gasoline at the calendar month average WTI price expressed in US$/bbl plus US$9.00/bbl for the period of April 1, 2010 to September 30, 2010. The contract expired on September 30, 2010 and resulted in a realized loss of $543,000 in 2010, which, has been separately reported.

REFINERY THROUGHPUT Years ended December 31

2010

2009

9,693

7,820

Refinery production – bbl/d (2)

10,704

8,797

Sales of refined petroleum products – bbl/d (3)

10,080

9,188

102%

82%

Crude charged – bbl/d

(1)

Refinery utilization (4) (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 (4) Represents crude charged divided by total crude capacity of the Refinery

In 2010, the total sales volume of refined petroleum products increased by 10 percent compared to 2009 primarily due to the improved stability of refining operations subsequent to the completion of the ultra low sulphur diesel (“ULSD”) project in 2009, our triennial plant turnaround in late 2009 and increased demand for refined petroleum products in 2010. A significant portion of our Refinery sales is derived from gasoline (4,500 bbl/d or 45%), diesel (1,617 bbl/d or 16%), jet fuel (693 bbl/d or 7%) and asphalt (2,971 bbl/d or 30%). Increases in gasoline, diesel and jet fuel sales volumes in 2010 were offset by a decrease in asphalt sales volumes, due to adverse weather conditions during the high activity summer/fall paving season. As at December 31, 2010, MRCI has agreements to sell approximately 667,000 barrels of asphalt at a weighted average price approximating US$95.00 per barrel in 2011.

DOWNSTREAM REVENUE Years ended December 31 Gross revenue

(1)

($000)

Transportation cost (2)

2010 $ 334,165

2009 $

264,924

(7,899)

(6,524)

Revenue

$ 326,266

$

258,400

Weighted average sales price ($ per bbl) (3)

$ 88.68

$

77.05

(1) Includes intersegment sales of $14.3 million in 2010 (2009 – $7.1 million), which were transacted at prevailing market prices and have been eliminated from the consolidated financial statements (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

In 2010, total downstream revenue was 26 percent higher compared to 2009, primarily due to refining and selling larger volumes and due to higher weighted average realized sales prices. Total sales volume increased by 10 percent in 2010 compared to 2009 and the weighted average sales price of refined petroleum products sold increased by 15 percent, driven by stronger economic conditions in our sales market.

CRUDE OIL AND OPERATING COSTS 2010

2009

Crude oil purchases and operating costs (1) ($000)

$ 301,084

$ 248,837

Crude oil purchases and operating costs ($ per bbl) (2)

$ 81.83

$ 74.20

Years ended December 31

(1) Includes intersegment cost of sales of $13.2 million in 2010 (2009 - $6.8 million) which has been eliminated from the consolidated financial statements (2) Per unit costs is calculated using crude oil purchases and operations costs divided by volumes of refined products sold

In 2010, total crude oil purchases and operating costs increased by 21 percent compared to levels in 2009 primarily due to higher refined crude oil volumes and higher benchmark crude oil prices. Notwithstanding that WTI crude oil prices increased by 28 percent in 2010 compared to 2009, crude oil and operating costs per barrel only increased by 10 percent primarily due to the benefit of lower feedstock costs due to wider heavy crude oil differentials in 2010.

54

AR 2010 CONNACHER

REFINING NETBACKS (1) Years ended December 31

2010

Refining netbacks (1) ($000)

$ 25,182

$

9,564

Refining netbacks (weighted average $ per bbl)

$ 6.84

$

2.85

2009

8%

Refining netbacks (% of revenue)

4%

(1) Refining netbacks 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

Refining netbacks were 163 percent higher in 2010 compared to 2009 and refining netbacks per barrel of refined petroleum product sold increased by 140 percent. This significant increase in 2010 compared to 2009 was due to refining and selling higher volumes, higher realized prices and lower feedstock cost due to wider heavy oil differentials. In addition, the higher netbacks in 2010 also include the benefit of a reversal of a previous inventory write-down totalling $1.4 million.

CORPORATE REVIEW INTEREST AND OTHER INCOME In 2010, the company earned interest and other income of $256,000 (2009 – $3.6 million), primarily from temporarily investing surplus funds in short-term deposits. A portion of the interest earned was recognized as income and a portion (in respect of cash balances on hand from pre-funding oil sands projects under construction) was credited to capitalized costs. Interest and other income in 2009 included a gain of $2.3 million on the repurchase of Second Senior Lien Notes.

No similar transactions occurred in 2010.

GENERAL AND ADMINISTRATIVE EXPENSES In 2010, general and administrative (“G&A”) expenses were $19.9 million, compared to $14.8 million in 2009, an increase of 35 percent, primarily due to personnel costs of an expanded staff required to support corporate growth. In 2010, G&A of $5.1 million attributable to capital projects was also capitalized to upstream property, plant and equipment (2009 – $5.0 million).

STOCK BASED COMPENSATION The company recorded non-cash stock-based compensation charges as follows: Years ended December 31 ($000) Charged to expense Capitalized to property, plant and equipment Total

2010

2009

$ 5,063

$ 4,562

1,664

1,095

$ 6,727

$ 5,657

The increase from the prior period was due to higher fair values for options granted in 2010.

FINANCE CHARGES Finance charges include interest expense relating to the Convertible Debentures, First and Second Lien Senior Notes and the Revolving Credit Facility (the “Facility”), amortization of the Facility transaction costs, stand-by fees associated with the Facility and fees on letters of credit issued. Finance charges also include non-cash accretion charges with respect to the Convertible Debentures and First and Second Lien Senior Notes. The company has capitalized interest on a portion of its long-term debt, proceeds of which were used to finance the construction of major oil sands projects.

In 2010, finance charges of $64.9 million were higher than $44.4 million expensed in 2009. The higher finance charges in 2010 were primarily a result of higher debt levels, following issuance of the First Lien Senior Notes in June 2009. In addition, finance charges relating to the company’s second oil sands project, Algar, which had been capitalized during its construction, were charged to the statement of operations after October 1, 2010. Connacher capitalized finance charges of $38.3 million in 2010 (2009 – $52.4 million) in respect of its oil sands capital projects.

FOREIGN EXCHANGE GAINS The value of the Canadian dollar relative to the US dollar has strengthened over the past two years. This had a significant impact on Connacher upon translating its US dollar-denominated long-term debt and US dollar cash balances into Canadian dollars for financial reporting purposes. Connacher recognized foreign exchange gains of $41.6 million in 2010 (2009 – $106.2 million).

AR 2010 CONNACHER

55

DEPLETION, DEPRECIATION AND ACCRETION (“DD&A”) 2010

2009

$ 63,872

$ 55,525

10,471

7,391

Years ended December 31 ($000) Depletion expense on upstream property, plant and equipment Depreciation expense on downstream property, plant and equipment Depreciation on corporate property, plant and equipment

2,328

1,445

Accretion expense on asset retirement obligations

2,915

2,201

Total

$ 79,586

$

66,562

Depletion expense is calculated using the unit-of-production method based on estimated total proved reserves. Depletion equated to $16.36/boe of production in 2010 (2009 – $16.51/boe of production). Effective October 1, 2010, the capitalized costs relating to Algar were subjected to depletion which resulted in higher depletion expense in 2010 compared to 2009.

Future development costs of $1.4 billion (2009 – $1.4 billion) were included in the depletion calculation while capital costs of $118.7 million (2009 – $96.9 million), related to unproved properties, were excluded from the depletion calculation.

Downstream and corporate property, plant and equipment are depreciated over their estimated useful lives.

EQUITY INTEREST IN PETROLIFERA PETROLEUM LIMITED (“PETROLIFERA”) Connacher accounts for its investment in Petrolifera under the equity method of accounting. Connacher’s share of Petrolifera’s loss in 2010 was a $1.8 million (2009 – $2.5 million).

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”). The company did not subscribe for shares in the Offering and 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 non-cash dilution loss of $4.3 million in 2010. Connacher continued to equity account for this investment in 2010 despite the modest reduction in percentage ownership.

In January 2011, Petrolifera entered into an arrangement agreement with Gran Tierra Energy Inc. (“Gran Tierra Energy”), pursuant to which Gran Tierra Energy would indirectly acquire all of the issued and outstanding common shares and common share purchase warrants of Petrolifera. Under the terms of the arrangement agreement, if the transaction proceeded with necessary approvals, Connacher would receive 3.3 million common shares and 841,000 share purchase warrants of Gran Tierra Energy on the expected closing date of March 18, 2011. Based on this transaction, the estimated fair value of our investment in Petrolifera was $15.3 million lower than our carrying value. Consequently, the company recorded an impairment charge of $15.3 million in 2010.

INCOME TAXES The total income tax recovery of $12.8 million in 2010 (2009 – $7.3 million) included a current income tax recovery of $291,000 (2009 – $1.6 million), principally related to taxes refundable by MRCI. The future income tax recovery of $12.5 million in 2010 (2009 – $5.7 million) reflected the change in tax pools during the periods.

The approximate amounts of total income tax pools available as at December 31, 2010 were $1,248 million in Canada and $48 million in the U.S.A. (2009 – $1,075 million in Canada and $53 million in the U.S.A.), including non-capital losses of approximately $503 million in Canada and $18 million in the U.S.A., which expire over time to 2030 and $34 million of net capital losses in Canada, which are available to reduce taxable capital gains in future.

NET EARNINGS (LOSS) Notwithstanding higher upstream and downstream netbacks, the company incurred a net loss of $38.8 million in 2010 compared to net earnings of $26.2 million in 2009, primarily due to non-cash charges including lower unrealized foreign exchange gains, higher depletion expense and an investment impairment charge of $15.3 million.

SHARES OUTSTANDING As at December 31, 2010, the number of common shares issued and outstanding was 447.2 million (December 31, 2009 – 427.0 million). The increase in 2010 compared to 2009 was due to shares issued on a flow-through basis in October 2010, shares issued in respect of share option exercises and shares issued to non-employee directors in respect of director share awards.

As at March 17, 2011, the company had the following securities issued and outstanding: • 447,839,563 common shares; • 24,082,334 stock options under the company’s Stock Option Plan; and • 375,000 share units under the Share Award Incentive Plan.

Additionally, the company’s $100 million of outstanding convertible debentures are convertible at the option of the holder at a conversion price of $5.00 per common share into common shares of the company.

56

AR 2010 CONNACHER

CAPITAL INVESTMENT Capital expenditures incurred are presented below: Years ended December 31 ($millions) Algar

2010 $ 72

2009 $

168

Pod One and trucking terminal

28

30

Co-generation facility and sales transfer lines

25

13

Exploration program

29

13

Conventional and corporate

22

14

Refinery expenditures Capitalized interest, G&A and other costs EIA application and other Capital expenditures Non-cash expenditures Additions to property, plant and equipment

8

21

50

54

3

1

237

314

11

8

$ 248

$ 322

In 2010, expenditures on Algar were primarily related to the completion of construction, commissioning of the plant and for minor capital projects after start-up of operations. Pod One expenditures were related to the drilling and completion of two additional SAGD well pairs, initial installation of nine down-hole electric submersible pumps (“ESPs”) and the expansion of the trucking terminal and for other facility enhancements. Connacher also completed the construction of 13.1 megawatt co-generation facility at Algar and constructed two 8 km transfer pipelines between Algar and Pod One, to allow for the consolidation of marketing efforts at the Pod One trucking terminal. Exploration expenditures were incurred primarily to drill 68 exploratory core holes at Great Divide, 13 (6.5 net) exploratory core holes at Halfway Creek and for seismic expenditures related to the 2010 winter exploration program. Expenditures on conventional activities were primarily for drilling (two crude oil wells, three natural gas wells, four abandoned wells at Marten Creek and three stratagraphic wells at Twining), land acquisition, seismic, well work-overs and facilities. Refinery expenditures were comprised of a number of smaller projects, including additional water treatment facilities and initial work on each of a boiler replacement, a 20 megawatt electrical substation and the benzene removal project.

In 2009, expenditures at Algar were primarily related to the design, construction and drilling of 17 SAGD well pairs.

Pod One expenditures were incurred to drill and complete two SAGD well pairs and to install seven new ESPs and for other facility enhancement expenditures. Exploration and evaluation expenditures represented the drilling of 23 exploratory core holes, one SAGD observation well and one water source well. Expenditures on conventional properties were incurred for drilling (two wells), land acquisitions, seismic, well work-overs and facilities. Refinery capital expenditures were primarily directed to the completion and tie-in of our new hydrogen plant, as part of the completion of the ultra-low sulphur diesel project, the regularly scheduled turnaround and the scheduled replacement of the fluid catalytic cracker reactor.

RECENT FINANCINGS Common Share Issuance On June 5, 2009 Connacher issued 191,762,500 common shares from treasury at a price of $0.90 per common share, for gross proceeds of $173 million. The proceeds were raised for working capital to fund the company’s capital expenditures, including Algar and for general corporate purposes. At December 31, 2010, the proceeds had been fully utilized to fund capital expenditures, including oil sands capital costs.

First Lien Senior Secured Notes On June 16, 2009, the company issued US$200 million first lien five-year secured notes (“First Lien Senior Notes”) at an issue price of 93.678 percent for gross proceeds of $212 million in equivalent Canadian funds. These funds were raised for working capital and for general corporate purposes, including funding a portion of the remaining expenditures associated with the construction and drilling costs of Algar. At December 31, 2010, the proceeds had been utilized to fund capital expenditures primarily related to Algar. Construction of Algar was completed in April 2010.

Flow-Through Shares In October 2009, to fund the company’s 2010 exploration program the company issued 23,172,500 common shares on a flow-through basis at $1.30 per common share, for gross proceeds of $30.1 million. At December 31, 2010, the proceeds had been utilized to fund capital expenditures for the exploration program. The company renounced the income tax benefits of these expenditures ($30.1 million) to the subscribing investors, effective December 31, 2009.

AR 2010 CONNACHER

57

In October 2010, to fund the company’s 2011 exploration program, 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. Most of these expenditures will be incurred in 2011.

Revolving Credit Facility The company has a US$50 million revolving credit facility (the “Facility”) provided by a syndicate of Canadian and international banks. At December 31, 2010, $5.7 million of letters of credit were issued in the normal course of business pursuant to the Facility.

In 2010, the Facility was amended. The Facility was extended to November 24, 2013, borrowing and stand-by costs were reduced and an interest coverage covenant was removed. The Facility is available for general corporate purposes and provides Connacher with additional liquidity and financial flexibility, including the issuance of letters of credit and the conduct of hedging activities. The Facility ranks senior to all of Connacher’s other indebtedness and is collateralized by a first priority security interest in all present and after-acquired assets of Connacher, except Connacher’s investment in Petrolifera and the pipeline assets of an inactive subsidiary.

The Facility has the following financial covenants: • Consolidated total debt (excluding the company’s outstanding convertible debentures) to total capitalization (defined to include all debt, convertible debentures and equity) shall not be greater than 70 percent, declining to 65 percent when production from Algar exceeds 8,000 bbl/d for a period of 30 consecutive days; and • debt outstanding under the Revolving Credit Facility to EBITDA (defined to include earnings before finance charges, taxes, depletion, depreciation and accretion, risk management contract gains or losses, share of loss, dilution loss and impairment loss in Petrolifera, stock-based compensation expense, employee benefit costs, gain or loss on disposition of property, plant and equipment and foreign exchange gains or losses) shall not be greater than 2.0:1.

As at December 31, 2010, Connacher was in compliance with all its debt covenants.

LIQUIDITY AND CAPITAL RESOURCES In 2010, cash flow increased by 195 percent to $36.9 million ($0.09 per basic and diluted share outstanding) compared to $12.5 million ($0.04 per basic and diluted share outstanding) in 2009.

At December 31, 2010, the company had working capital of $65.4 million (December 31, 2009 – $247 million), including $19.5 million of cash (December 31, 2009 – $257 million). The significant decrease in working capital, as at December 31, 2010, compared to December 31, 2009 was due to the decrease in our cash balances. The company completed a debt financing and equity financings in 2009 which resulted in higher cash balances as at December 31, 2009. The majority of these funds were used in the first half of 2010 on the completion of the construction of Algar and other capital activities. As at December 31, 2010, there were limited outstanding capital expenditure commitments and as all of the company’s indebtedness is long-term in nature, with no principal repayment obligation until June 2012, management believes that the company has sufficient liquidity and anticipated financial capacity, in combination with cash generated from operations in 2011 to fund its ongoing capital program and to satisfy its financial obligations in 2011.

The increase in accounts receivable balances as at December 31, 2010 compared to December 31, 2009, was primarily due to higher revenue in 2010 compared to 2009. Inventory balances increased as at December 31, 2010 compared to December 31, 2009 primarily due to higher inventory volumes and values of our refined products. Lower accounts payable and accrued liabilities as at December 31, 2010 compared to 2009 reflect lower capital expenditures towards the end of 2010.

In light of the current volatility of commodity prices, the US:Canadian dollar exchange rate and their significance to the company’s operating performance, management constantly 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 indebtedness, complete capital projects and protect the credit capacity of Connacher’s oil and gas reserves in an uncertain or volatile commodity price environment.

In 2010, the company entered into WTI risk management contracts on a portion of its crude oil sales and on a portion of its refined gasoline sales and entered into AECO risk management contracts on a portion of its natural gas consumption requirements. Details of these risk management contracts were provided earlier in this MD&A.

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In February 2011, the company closed its Battrum property sale for gross proceeds of $57.5 million, subject to normal closing adjustments. The effective date of the sale was January 1, 2011. The sale proceeds were added to Connacher’s cash balances and working capital, thereby reducing net debt. In March 2011, we entered into an agreement to sell our Marten Creek/Randall properties on April 29, 2011 for gross proceeds of $22.5 million, subject to normal closing adjustments. The sale proceeds will be added to cash balances and hence, will further strengthen our liquidity.

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 of its underlying assets and its growth opportunities. It strives to continuously improve its credit rating and reduce its cost of capital. Connacher monitors its capital structure, using a number of financial ratios and industry metrics, to ensure its objectives are being met and to ensure continued compliance with financial debt covenants.

The company reported the following debt outstanding: 2010

2009

Convertible Debentures, 4 ¾%, due June 30, 2012

$ 92,762

$ 88,488

First Lien Senior Notes, 11 ¾%, due July 15, 2014

184,176

191,509

Second Lien Senior Notes, 10 ¼%, due December 15, 2015

566,663

596,184

843,601

$ 876,181

2010

2009

$ 843,601

$ 876,181

As at December 31 ($000)

$

Total – no current maturities

Connacher’s capital structure and certain financial ratios are noted below: As at December 31 ($000) Long-term debt

(1)

Shareholders’ equity Total Debt plus Equity (“capitalization”)

650,183

671,588

$ 1,493,784

$ 1,547,769

56%

57%

Debt to book capitalization (2)

(1) Long-term debt is stated at its carrying value, which is net of transaction costs and the Convertible Debentures’ equity component value (2) Calculated as long-term debt divided by the book value of shareholders’ equity plus long-term debt

As at December 31, 2010, the company’s net debt (long-term debt, net of cash on hand) was $824 million. Its net debt to book capitalization was 55 percent. Completion of Algar resulted in reduced cash balances but it is anticipated that the higher production will result in increased cash flow from operations in 2011 and ensuing years, if similar prices are realized for sales of bitumen.

COMMITMENTS AND CONTRACTUAL OBLIGATIONS The company’s annual commitments under leases for office premises and operating costs, software license agreements, other equipment and long-term debt are as follows: As at December 31, 2010 ($000) Operating commitments

(1)

Capital commitments (2) Long-term debt, at face value including interest (3) Asset retirement obligations Employee future benefits Total

2011

1-3 years

4-5 years

Thereafter

Total

$ 7,280

$ 18,323

$ 8,537

$ 40,673

$ 74,813

1,632

-

-

-

1,632

87,997

540,335

641,507

-

1,269,839

-

2,370

-

84,640

87,010

497

-

-

-

497

$ 97,406

$ 561,028

$ 650,044

$ 125,313

$ 1,433,791

(1) Includes rent of office space, operating lease rentals for vehicles and equipment, maintenance fee relating to the co-generation facility and charges relating to utility agreements (2) Primarily related to drilling rig commitments and success fee relating to the sale of properties (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. The above table also excludes the company’s commitment to incur qualifying capital expenditures under its flow-through common share issuance in October 2010.

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OUTLOOK We expect stronger financial results in 2011 compared to 2010, due to anticipated higher production and sales volumes and more stable operating performance at Pod One and the continued production rampup at Algar. We also anticipate more stable operations and improved efficiencies resulting from fewer power disruptions, with the activation of our co-generation facility at Algar. It appears higher commodity prices (supported by our hedging program) will prevail and we anticipate favorable results from our refining and conventional operations.

All of our debt is long-term, with our first maturity in 2012 and remaining maturities in 2014 and 2015. We will monitor the long-term debt market for advantageous refinancing alternatives, having regard for existing call provisions and maturities and provided price and term alternatives extant in the public debt market remain favorable. Our focus in 2011 will be on optimizing our production at Great Divide, rationalizing non-core conventional assets, expanding our new core areas with drilling success and delivering successive and sustained improvement in operating and financial results, at lower cost.

Future cash flows will be substantially sheltered from current cash taxes by the company’s tax pools, which currently exceed $1.2 billion and which will be augmented by future capital expenditures.

ESTIMATED 2010 NETBACKS AND ADJUSTED EBITDA In our 2009 MD&A, as contained in our annual report and as filed separately on SEDAR, we provided guidance with regard to Connacher’s estimated 2010 adjusted EBITDA per barrel of bitumen sold. We updated that guidance in our Q3 2010 MD&A (the “Q3 2010 estimate”). Estimated 2010 adjusted EBITDA is calculated on an annual basis and, consequently, quarterly adjusted EBITDA per barrel of bitumen sold will vary from the average annual adjusted EBITDA. The table below compares the company’s consolidated results for year ended December 31, 2010 (“2010 Actual results”) to the Q3 2010 estimate.

Explanations for variances are provided below the table.

2010 Actual Results $/bbl of bitumen Bitumen netback

$

Total ($millions)

23.68

$

71

Q3 2010 Estimate $/bbl of bitumen $

21.42

Total ($millions) $

66

Conventional netback

6.01

18

6.01

19

Refining cash netback (1)

8.68

26

8.88

27

Loss on risk management contracts

(1.00)

(3)

(0.79)

(2)

Corporate netback

37.37

112

35.52

110

Corporate G&A Adjusted EBITDA (2)

(6.68) $ 30.69

(20) $

92

(6.21) $

29.31

(19) $

91

(1) Refining cash netback excludes the non-cash charge of defined benefit plan expense (2) Adjusted EBITDA is a non-GAAP measure, which is defined in the Advisory section of the MD&A

2010 adjusted EBITDA of $92 million was $1 million higher than the Q3 2010 estimate for the same period for the reasons cited below.

The 2010 bitumen netback of $71 million was $5 million greater than the Q3 2010 estimate for the same period. The higher actual bitumen netback was primarily due to stronger crude oil prices, a weaker Canadian dollar, narrower heavy oil differentials and lower diluent premiums to WTI as compared to assumptions used in the Q3 2010 estimate. 2010 actual daily bitumen sales volumes were three percent lower than the Q3 2010 estimate of sales volumes for the same period.

The 2010 conventional netback of $18 million was in line with the Q3 2010 estimate for the same period.

The 2010 refining netback of $26 million was $1 million lower than the Q3 2010 estimate for the same period, as narrower heavy oil differentials and lower volumes of asphalt sold in the fourth quarter of 2010 more than offset higher realized margins on sales of gasoline, diesel and jet fuel, compared to assumptions used in the Q3 2010 estimate.

Realized losses on risk management contracts in 2010 of $3 million were $1 million greater than the Q3 2010 estimate for the same period because of higher actual WTI prices compared to assumptions used in the Q3 2010 estimate.

Corporate G&A in 2010 of $20 million was $1 million greater than the Q3 2010 estimate for the same period, because of higher staffing costs.

Actual adjusted EBITDA on a per barrel basis was higher than anticipated at Q3 2010 due to the above noted difference notwithstanding 2010 actual daily bitumen sales volumes were three percent lower than the Q3 2010 estimate of sales volumes for the same period.

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2011 OUTLOOK The company’s revised 2011 production guidance and cash capital expenditure budget is as follows: 2011 Production Guidance Bitumen production (bbl/d)

14,500 – 16,500 (1)

1,000 – 1,400

Total upstream production (boe/d)

15,500 – 17,900

Conventional production (boe/d)

(1) Excludes production from Battrum and Marten Creek/Randall properties from the respective closing dates

2011 Capital Budget on Cash Basis

($millions)

Sustaining and maintenance capital Oil sands

$ 35

Conventional

2

Refining

10

Corporate

6

Total sustaining and maintenance

53

Growth capital and special projects Oil sands

8

Conventional

16

Refining

9

Exploration

26

EIA and Algar expansion engineering

10

Total growth capital and special projects Total 2011 capital budget

69 $ 122

Sustaining and maintenance capital for the oil sands includes two initial ESPs at Pod One and three at Algar, expenditures related to a diluent recovery system, tankage at Pod One and for minor projects. At the Refinery, sustaining and maintenance capital includes the completion of a 20MW electrical substation and expenditures related to ethanol blending, tank and boiler replacements.

Growth capital for the oil sands includes expenditures related to solvent SAGD at Algar and enhanced recovery at Pod One. In conventional operations, growth capital includes expenditures related to our three well resource project at Twining and land purchases. The Refinery growth expenditures relate to the completion of the benzene removal project.

The exploration budget is for our current core-hole and 3D seismic program at Great Divide and Thornbury.

The 2011 production and capital guidance assumes the sale of our Marten Creek/Randall properties for $22.5 million on April 29, 2011. The company anticipates that cash balances and full year 2011 adjusted EBITDA (assuming similar WTI pricing and foreign exchange levels in 2010), together with available unused revolving lines of banking credit, should be more than sufficient to meet all budgeted capital expenditures and ongoing financial obligations throughout 2011. Actual production achieved and capital expenditures incurred during 2011 could differ materially from these estimates – please see “Forward-Looking Information” in the Advisory section and “Risk Factors”.

RELATED PARTY TRANSACTIONS In 2010 the company incurred professional legal fees of $779,000 (2009 – $1.3 million) to a law firm in which an officer and a director of the company were partners. Transactions with the related party occurred within the normal course of business and have been measured at their exchange amount on normal business terms. The exchange amount is the amount of consideration established and agreed to with the related parties. As at December 31, 2010, accounts payable to the law firm was approximately $158,000 (2009 – $71,000).

SIGNIFICANT ACCOUNTING POLICIES AND APPLICATION OF CRITICAL ACCOUNTING ESTIMATES The significant accounting policies used by the company are described below. Certain accounting policies require that management make appropriate decisions with respect to the formulation of estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses. Changes in these estimates and assumptions may have a material impact on the company’s financial results and condition. The following discusses such accounting policies and is AR 2010 CONNACHER

61

included herein to aid the reader in assessing the critical accounting policies and practices of the company and the likelihood of materially different results being reported. Management reviews its estimates and assumptions regularly in light of changing circumstances, economic and otherwise. The emergence of new information and changed circumstances may result in changes to estimates and assumptions which could be material and the company might realize different results from the application of new accounting standards promulgated, from time to time, by various regulatory rule-making bodies.

RESERVE ESTIMATES The reserve estimates for 2010 and 2009 were prepared by GLJ Petroleum Consultants Ltd., an independent professional petroleum engineering firm, in accordance with Canadian Securities Administrators’ National Instrument 51-101 (NI 51-101) and the Canadian Oil and Gas Evaluation Handbook. Under NI 51-101, proved reserves are those reserves which can be estimated with a high degree of certainty to be recoverable. It is likely that actual remaining quantities recovered will exceed estimated proved reserves. 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. 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 pus probable plus possible reserves. There is a 10 percent probability that the quantities actually recovered will equal or exceed the sum of proved plus probable plus possible reserves.

All of the company’s oil and gas reserve estimates are made by independent reservoir engineers using all available geological and reservoir data as well as historical production data. Estimates are reviewed and revised as appropriate.

Revisions occur as a result of changes in prices, costs, fiscal regimes, reservoir performance or a change in the company’s plans. The reserve estimates can also be used in determining the company’s borrowing base for its credit facilities and may impact the same upon revision or changes to the reserve estimates. The effect of changes in proved oil and gas reserves on the financial results and position of the company is described below.

Full Cost Accounting For Oil And Gas Activities The company uses the full cost method of accounting for exploration and development activities. In accordance with this method of accounting, all costs associated with exploration and developments are capitalized whether successful or not.

The aggregate of net capitalized costs and estimated future development costs is depleted using the unit-of-production method based on estimated proved oil and gas reserves. A change in estimated total proved reserves could significantly affect the company’s calculation of depletion.

Major Development Projects And Unproved Properties Certain costs related to acquiring and evaluating unproved properties are excluded from net capitalized costs subject to depletion until proved reserves have been determined or their value is impaired. Costs associated with major development projects are not depleted until they are capable of production or the related development activity ceases or the property is determined to be impaired. All capitalized costs are reviewed quarterly and any impairment is transferred to the costs being depleted.

All costs related to the Great Divide oil sands project are being capitalized to specific projects, or “Pods”. The capital costs and estimates of future capital requirements for Pods are added to the company’s depletable costs and depleted under the unit-of-production method based on the company’s total proved reserves when each Pod becomes capable of production or the development activities at any Pod ceases or an impairment occurs. Effective October 1, 2010, the company’s second oil sands project, Algar, became capable of commercial production and its related costs were added to the company’s depletable cost pool.

Ceiling Test The company is required to review the carrying value of oil and gas assets for potential impairment. Impairment is indicated if the carrying value of oil and gas cost centre is not recoverable by the future undiscounted cash flows. If impairment is indicated, the amount by which the carrying value exceeds the estimated fair value of oil and gas assets is charged to earnings.

The ceiling test is based on estimates of reserves, production rate, crude oil, bitumen and natural gas prices, future development costs and other relevant assumptions. By their nature reserve estimates are subject to measurement uncertainty and the impact of ceiling test calculations on the consolidated financial statements for changes in reserve estimates could be material.

ASSET RETIREMENT OBLIGATIONS The company is required to provide for future removal and site restoration costs by estimating these costs in accordance with existing laws, contracts or other policies. These estimated costs are charged to earnings and the appropriate liability account over the expected service life of the asset. When the future removal and site restoration costs cannot be reasonably determined, a contingent liability may exist. Contingent liabilities are charged to earnings only when management is able to determine the amount and the likelihood of the future obligation. The company estimates future retirement costs based on current costs as estimated by the company’s engineers adjusted for inflation and credit risk.

These estimates are subjective.

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AR 2010 CONNACHER

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.

INCOME TAXES The company follows the liability method of accounting for income taxes. Under this method tax assets are recognized when it is more than likely realization will occur. Tax liabilities are recognized for temporary differences between recorded book values and underlying tax values. Rates used to determine income tax asset and liability amounts are enacted tax rates expected to be used in future periods when the timing differences reverse. The period in which a timing difference reverses are impacted by future income and capital expenditures. Rates are also affected by legislation changes. These components can impact the charge for future income taxes.

Tax interpretations, regulations and legislations in the jurisdictions in which the Company, its subsidiary and equity accounted for investment operate are subject to change. As such, income taxes are subject to measurement uncertainty and the interpretations can impact net earnings through income tax expense arising from the changes in future income tax asset and liabilities.

STOCK-BASED COMPENSATION The company uses the fair value method to account for stock options. The determination of the amounts for stockbased compensation is based on estimates of share price volatility, interest rates and the expected life of the option.

These estimates by their nature are subject to measurement uncertainty.

SHARE AWARD PLAN Obligations under our share award plan for non-employee directors are accrued as compensation expense over the vesting period. Fluctuations in the price of our common shares change the accrued compensation expense and are recognized when they occur.

EMPLOYEE FUTURE BENEFITS As a consequence of the Refinery acquisition and related employment of Refinery personnel, our US subsidiary, MRCI, adopted employee future benefit plans with effect from March 31, 2006. A non-contributory defined benefit retirement plan covers only certain Refinery employees from March 31, 2006. MRCI’s policy is to make regular contributions in accordance with the regulatory requirements. Benefits are based on employees’ years of service and compensation.

We also established defined contribution (US tax code ‘‘401(k)’’) plans that cover all Refinery employees from March 31, 2006. MRCI’s contributions are based on employees’ compensation and partially match employee contributions.

LONG-LIVED ASSETS Depreciation and amortization is calculated based on estimated useful lives and salvage values. When assets are placed into service, estimates are made with respect to their useful lives that are believed to be reasonable. However, factors such as new technologies, competition, regulation or environmental matters could cause changes to estimates, thus impacting the future calculation of depreciation and amortization. Long-lived assets are also evaluated for potential impairment by identifying whether indicators of impairment exist and, if so, assessing whether the long-lived assets are recoverable from estimated future undiscounted cash flow. The actual amount of impairment loss, if any, to be recorded is equal to the amount by which a long-lived asset’s carrying value exceeds its fair value. Estimates of future discontinued cash flow and fair values of assets require subjective assumptions with regard to future operating results and actual results could differ from those estimates.

GOODWILL Goodwill arose on a corporate acquisition in 2006. Goodwill, which represents the excess of purchase price over fair value of net assets acquired, is assessed for impairment annually. Goodwill and all other assets and liabilities have been allocated to our segments, referred to as reporting units. To assess impairment, the fair value of each reporting unit is determined and compared to the book value of the reporting unit. If the fair value of the reporting unit is less than the book value, then a second test is performed to determine the amount of the impairment. The amount of the impairment is 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 book value of the reporting unit’s goodwill. Any excess of the book value of goodwill over the implied fair value of goodwill is the impairment amount.

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63

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. We may also use derivative financial instruments, such as interest rate swap 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. 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 respective 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.

INTERNATIONAL FINANCIAL REPORTING STANDARDS The company is executing a conversion project to complete the transition to IFRS by January 1, 2011, including the preparation of 2010 required comparative information. The conversion plan consists of four phases: diagnostic; design and planning; solution development; and implementation. The company is currently in the implementation phase and is still in the process of finalizing the financial impact of adopting IFRS. However, we have determined that the differences that could have the greatest impact on Connacher’s consolidated financial statements relate to accounting for exploration and development activities, property, plant and equipment, goodwill, asset retirement obligations and income taxes.

The majority of the adjustments made on transition to IFRS will be recorded retrospectively to the opening balance of retained earnings at January 1, 2010. Changes arising from the transition where the accounting standards do not require retrospective application will be applied prospectively to transactions occurring subsequent to January 1, 2010.

IFRS 1 ‘‘First-Time Adoption of International Financial Reporting Standards’’ provides entities adopting IFRS for the first time with a number of optional and mandatory exemptions, in certain specific areas, to the general requirement for full retrospective application of IFRS. The company is in the final stage of analyzing the various accounting policy choices available and will implement those determined to be most appropriate in the company’s circumstances.

One such exemption we will utilize is the amendment to IFRS 1 issued by the International Accounting Standards Board (IASB) in July 2009 respecting the determination of opening balances of property, plant and equipment. That amendment permits oil and gas companies currently using the full cost method of accounting to allocate the balance of property, plant and equipment as determined under Canadian GAAP to the IFRS categories of exploration and evaluation assets and development and producing properties without requiring full retrospective restatement of historic property, plant and equipment balances to the IFRS basis of accounting.

Other exemptions from retrospective application of IFRS which we will use are those available for foreign currency translation differences recorded in accumulated other comprehensive income, actuarial gains and losses relating to MRCI’s defined benefit pension plan, stock-based compensation, borrowing costs, leases, decommissioning liabilities included in the cost of property, plant and equipment and business combinations.

The following discussion provides an overview of the areas that will have the greatest impact on Connacher’s consolidated financial statements. The items discussed below should not be considered a complete list of the changes which may occur as a result of the transition to IFRS. The discussion is intended to highlight the areas of most significant impact on Connacher based on the work completed to date. However, the company’s analysis of the changes is ongoing.

PROPERTY, PLANT & EQUIPMENT International Accounting Standard (IAS) 16 ‘‘Property, Plant & Equipment’’ and Canadian GAAP contain the same basic principles. However there are some differences. IFRS requires that significant components of an asset be depreciated separately. Depreciation under IFRS commences when an asset is available for use. Capitalization of costs under IFRS ceases when an item of property, plant and equipment is in the location and condition necessary for it to be capable of operating in the manner intended by management. IFRS also permits property, plant and equipment to be measured using the fair value model or the historical cost model. The company will not adopt the fair value model to measure its property, plant and equipment. Additionally, under IFRS exploration and evaluation assets are accounted for separately from development and producing assets.

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AR 2010 CONNACHER

IFRS 1 contains an elective exemption where an entity may elect to reset as the new cost basis for property, plant and equipment, its fair value at the date of transition. The company will not use this exemption and will continue to measure its property, plant and equipment at cost.

Connacher will adopt the IFRS 1 exemption, which allows the Company to deem its January 1, 2010 IFRS upstream asset costs to be equal to its Canadian GAAP historical upstream net book value. On January 1, 2010, the IFRS exploration and evaluation asset is approximately $96.9 million, which is equal to the Canadian GAAP unproved properties balance. The IFRS development costs will be equal to the full cost pool balance. Connacher allocated this upstream full cost pool to its developed oil and gas properties in proportion to their established reserve values.

IMPAIRMENT TESTING OF ASSETS Impairment testing of non-financial assets under IFRS, including property, plant and equipment and goodwill, is measured using discounted cash flows and fair values. Under Canadian GAAP, an asset’s carrying amount was first compared to its undiscounted future cash flows. If the carrying value exceeded that amount, the impairment was measured as the excess of the carrying value over the asset’s discounted future cash flows. Under IFRS, there is no initial assessment using undiscounted cash flows. Therefore, impairments may occur more frequently under IFRS compared to Canadian GAAP. Under IFRS there is an opportunity to reverse impairment losses for assets other than goodwill where there is a favorable change in the circumstances which gave rise to the impairment. Under Canadian GAAP, impairments were not reversed.

Additionally, under Canadian GAAP, Connacher’s oil and gas assets were tested for impairment in a single, country-wide full cost pool. Under IFRS, assets must be segregated into “cash-generating units” (“CGUs”) for purposes of impairment testing. 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. As a result, impairments may occur with respect to certain of the company’s assets which would not have been incurred under Canadian GAAP because of the ability under full cost accounting to shelter assets using the cash flow from the all of the company’s oil and gas properties included in the full cost pool. The company expects to record impairment charge of approximately $103 million, on January 1, 2010, relating to its Goodwill with corresponding charge to retained earnings. The company is still in the process of finalizing the effect of impairment on its oil and gas assets.

ASSET RETIREMENT OBLIGATIONS Differences exist between Canadian GAAP and IFRS with respect to the measurement of asset retirement obligations.

Specifically, under Canadian GAAP asset retirement obligations were measured at fair value using a credit-adjusted riskfree discount rate. Under IFRS, asset retirements obligations are measured using the best estimate of the expenditure required to settle the obligation, and are discounted using a risk-free interest rate. Using such a lower discount rate will result in an increase in Connacher’s asset retirement obligation recorded on the consolidated balance sheet.

In addition, IFRS requires changes to the timing of cash flows, estimated amounts of cash flows and discount rates to be accounted for prospectively. Canadian GAAP is similar; however, under IFRS changes to the discount rates for ARO are only applied to the incremental changes in the liability and not to the entire liability.

As a result of Connacher’s use of the IFRS 1 upstream asset exemption, the Company is required to revalue its January 1, 2010 ARO balance recognizing the adjustment in retained earnings. The company expects to recognize an increase in the obligation of approximately $20 million with a corresponding reduction to retained earnings on the IFRS opening balance sheet.

INCOME TAXES Under IAS 12 “Income Taxes”, deferred taxes are not recognized for temporary differences arising from the initial recognition of an asset or liability in a transaction which is not a business combination and which at the time of the transaction affects neither accounting nor taxable income. Canadian GAAP contains no such exemption.

Additionally, under IFRS current and deferred taxes are normally recognized in the income statement, except to the extent that deferred tax arises from (1) an item that has been recognized directly in equity, whether in the same or a different period, (2) a business combination or (3) a share-based payment transaction. If a deferred tax asset or liability is remeasured subsequent to initial recognition, the impact of remeasurement is recorded in earnings, unless it relates to an item originally recognized in equity, in which case the change would also be recorded in equity. The practice of tracking the remeasurement of taxes back to the item which originally triggered the recognition is commonly referred to as ‘‘backwards tracing.’’ Canadian GAAP prohibits backwards tracing except in relation to business combinations and financial reorganizations.

Connacher expects to recognize a decrease in the deferred tax liability of approximately $16 million with a corresponding increase to retained earnings of $20 million and decrease to equity portion of convertible debentures of $4 million on the IFRS opening balance sheet.

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Other IFRS 1 Considerations As permitted by IFRS 1, Connacher’s foreign currency translation adjustment, currently the only balance in Connacher’s accumulated other comprehensive income, will be deemed to be zero and the balance of $16 million will be reclassified to retained earnings on January 1, 2010. There is no impact to Connacher’s shareholders equity as a result of this reclassification.

Retrospective restatement of foreign currency translation adjustments under IFRS principles will not be performed.

With respect to employee benefit plans, cumulative unamortized actuarial gains and losses will be charged to retained earnings on January 1, 2010. As such, they will not be retrospectively restated using IFRS principles. Connacher expects to recognize a decrease in the pension liability of approximately $0.7 million with a corresponding increase to retained earnings on the IFRS opening balance sheet.

INTERNAL CONTROLS Connacher is currently assessing the impact of the conversion to IFRS on internal controls and business processes.

Based on our initial assessment, the impact is not expected to be significant. However, some additional controls will be required in regard to recording transitional adjustments and new processes for identifying and separately accounting for exploration and evaluation assets.

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.

RISK FACTORS AND RISK MANAGEMENT GENERAL Connacher is engaged in the oil and gas exploration, development, production, and refining industry. This 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.

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Connacher’s financial and operating performance is potentially affected by a number of factors including, but not limited to, risks associated with the 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. Asset retirement obligations 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 and natural gas commodity prices and foreign exchange rate changes, which may be influenced by many factors, including global and regional supply and demand, seasonality, worldwide 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.

Crude oil and dilbit selling prices are based on US 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 US dollar, the resulting negative effect on revenue, including the translation of MRCI’s US denominated results to Canadian dollars for financial reporting purposes, would be partially offset with exchange gains on translating our US dollar denominated debt and associated interest payments thereon. The opposite would occur should the Canadian dollar weaken compared to the US 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.

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 to meet 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 preventative maintenance.

• While fiscal regimes in Alberta and Canada 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. 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 “recent” global credit crisis 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 AR 2010 CONNACHER

67

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 in 2011. This project is ongoing and is on schedule. 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 report has been affirmed by recent audits.

ADVISORY SECTION FORWARD-LOOKING INFORMATION This report, including the Letter to Shareholders and the 2011 outlook contained in the MD&A, contains forward-looking information including but not limited to, anticipated future operating and financial results, forecast netbacks and margins, forecast realized gain (loss) on risk management contracts, future corporate general and administration expenses, future profitability, expectations of future production, anticipated sales volumes for 2011, further anticipated reductions in operating costs as a result of continued operational optimization at Great Divide Pod One and Algar, expected operational performance of the co-generation facility at Algar and subsequent completion of an electrical substation, future SORs, anticipated capital expenditures for 2011, anticipated sources of funding for capital expenditures and current and future financial obligations, potential rationalization of the conventional property base, future development and exploration activities, estimates of future commodity prices, foreign exchange rates and heavy oil differentials, utilization of alternative financial derivative strategies to protect the company’s cash flow, Petrolifera’s proposed acquisition by Gran Tierra Energy Inc., the possible monetization of Connacher’s equity investment in Gran Tierra Energy Inc. assuming the completion of the acquisition of Petrolifera, future possible joint venture arrangements, anticipated commencement of a “SAGD with solvent” project at Algar, anticipated future reclamation, timing of receipt of regulatory approvals for future expansion at oil sands properties, future royalties which may become payable and the anticipated impact of the conversion to International Financing Reporting Standards (“IFRS”) on the company’s consolidated financial statements. 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, future economic conditions and the plans and expected impacts of adopting IFRS. Statements relating to “reserves” and “resources” are deemed to be forward-looking statements, as they involve 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. The assumptions relating to the reserves and resources of Connacher are described in further detail in Connacher’s Annual Information Form for the year ended December 31, 2010 which is available at www.sedar.com.

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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; 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.

The 2011 outlook contained in MD&A is based on certain assumptions regarding operational performance including, among others, steam generation levels and steam oil ratios, timing and duration of planned maintenance activities and results thereof, 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 for the year ended December 31, 2010 which is available at www.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 March 17, 2011 and Connacher assumes no obligation to update or revise any forward-looking information to reflect new events or circumstances, except as required by law.

In addition, design capacity is not necessarily indicative of the stabilized production levels that may ultimately be achieved at Connacher’s SAGD facilities. Moreover, reported average or instantaneous production levels may not be reflective of sustainable production rates and future production rates may differ materially from the production rates reflected in this report due to, among other factors, difficulties or interruptions encountered during the production of bitumen or other hydrocarbons.

NON-GAAP MEASUREMENTS The MD&A contains terms commonly used in the oil and gas industry, such as cash flow, cash flow per share, netback, bitumen netback, conventional netback, refinery margins or netback, corporate netback and adjusted earnings before interest, taxes, depreciation and amortization (“adjusted EBITDA”). These terms are not defined by GAAP and 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 GAAP as an indicator of Connacher’s performance. Management believes that in addition to net earnings (loss), cash flow, netbacks or net margins and adjusted EBITDA are useful financial measurements which assist in demonstrating the company’s ability to fund capital expenditures necessary for future growth or to repay debt. Connacher’s determination of cash flow, netbacks, margins and adjusted EBITDA may not be comparable to that reported by other companies.

CASH FLOW Cash flow and cash flow per share do not have standardized meanings prescribed by GAAP and therefore may not be comparable to similar measures used by other companies. Cash flow includes all cash flow from operating activities and is calculated before changes in non-cash working capital, pension funding and asset retirement expenditures. The most comparable measure calculated in accordance with GAAP is cash flow from operating activities. Cash flow from operating activities is reconciled with the cash flow for three and twelve months ended December 31, 2010 and 2009 below. Cash flow per share is calculated by dividing cash flow by the calculated weighted average number of shares outstanding. Management uses this non-GAAP measurement (which is a common industry parameter) for its own performance measure and to provide its shareholders and investors with a measurement of the company’s efficiency and its ability to fund future growth expenditures.

NETBACKS Upstream netbacks, including by product, are calculated by deducting the related diluent, transportation, field operating costs and royalties from upstream revenues. Downstream netbacks are calculated by deducting crude oil and operating costs from refining sales revenues.

ADJUSTED EBITDA Adjusted EBITDA is calculated as net earnings before finance charges, taxes, depreciation, amortization and accretion, stock based compensation, foreign exchange gains/losses, unrealized gains/losses on risk management contracts, interest/other income, equity earnings/losses and dilution gains/losses.

RECONCILIATIONS OF NON-GAAP MEASURES Cash flow is reconciled to cash flow from operating activities and upstream and downstream netbacks and adjusted EBITDA are reconciled to net loss herein.

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69

RECONCILIATIONS OF CASH FLOW TO CASH FLOW FROM OPERATING ACTIVITIES Three months ended December 31

Cash flow

2009

2010

2009

$ 9,090

$ (2,766)

$ 36,884

$ 12,522

(35,151)

8,294

(24,935)

(17,300)

(140)

14

(647)

(142)

-

-

(517)

(234)

$ (26,201)

$ 5,542

$ 10,785

$ (5,154)

Non-cash working capital changes Asset retirement expenditures Contribution to defined benefit plan Cash flow from operating activities

Years ended December 31

2010

($000)

RECONCILIATIONS OF UPSTREAM AND DOWNSTREAM NETBACKS TO NET EARNINGS Three months ended December 31 2010 ($000, except per unit amounts) Upstream netbacks Downstream netbacks

General and administrative Stock-based compensation Finance charges Foreign exchange gain Depletion, depreciation and accretion Income tax recovery Equity interest in Petrolifera loss

Per Boe

Total

Per Boe

Total

Per Boe

Total

Per Boe

$ 32,599

$ 23.42

$ 18,149

$ 22.69

$ 89,362

$ 23.08

$ 62,430

$ 18.56

7,091

5.10

(4,050)

(5.07)

25,182

6.50

9,564

2.84

83

0.06

187

0.23

256

0.07

3,550

1.06

(18,008)

(12.94)

(9,300)

(11.63)

(17,186)

(4.44)

(25,125)

(7.47)

(5,560)

(3.99)

(3,710)

(4.64)

(19,921)

(5.15)

(14,772)

(4.39)

(1,240)

(0.89)

(2,118)

(2.65)

(5,063)

(1.31)

(4,562)

(1.36)

(25,706)

(18.47)

(13,190)

(16.50)

(64,877)

(16.76)

(44,354)

(13.19)

26,935

19.35

12,275

15.35

41,641

10.76

106,164

31.56

(23,636)

(16.98)

(16,884)

(21.12)

(79,586)

(20.56)

(66,562)

(19.79)

4,282

3.08

7,139

8.93

12,787

2.70

7,305

2.17

(731)

(0.53)

(810)

(1.00)

(1,847)

(0.48)

(2,468)

(0.72)

-

-

(2,419)

(3.02)

(4,273)

(1.10)

(5,012)

(1.49)

(15,273)

(10.97)

-

-

(15,273)

(3.95)

-

-

$ (18.43) $ (38,798) $ (10.64) $ 26,158

$ 7.78

Dilution loss Impairment loss in Petrolifera Net earnings (loss)

2009

Total

Interest and other income Gain (loss) on risk management

Years ended December 31 2010

2009

$ (19,164) $ (13.76) $ 14,731

RECONCILIATION OF ACTUAL ADJUSTED EBITDA IN TOTAL AND PER BARREL OF BITUMEN PRODUCED

Adjusted EBITDA

2010

2009

$/bbl of bitumen

Total ($millions)

Total ($millions)

$ 30.69

$ 92

0.10

-

Interest and other income

$

37 4

Employee benefit expense

(0.14)

(1)

(1)

Unrealized loss on risk management contracts

(4.79)

(14)

(5)

Stock-based compensation Finance charges Foreign exchange gain Depletion, depreciation and accretion Income tax recovery Equity interest in Petrolifera loss

(1.69)

(5)

(5)

(21.66)

(65)

(44)

13.90

42

106

(26.57)

(80)

(66)

4.27

13

7

(0.62)

(2)

(7)

Dilution loss

(1.43)

(4)

-

Impairment loss in Petrolifera

(5.10)

(15)

-

$ (13.04)

$ (39)

$ 26

Net earnings (loss)

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.

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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 US dollar denominated debt. Significant volatility and low commodity prices, together with severe economic uncertainty in Q1 2009 are the primary factors affecting financial results during that quarter.

Financial ($000 except per share amounts) Three months ended

2009 Mar 31

2009 June 30

2009 Sept 30

2009 Dec 31

2010 Mar 31

2010 June 30

2010 Sept 30

2010 Dec 31

Revenues, net of royalties

61,757

100,219

151,360

108,354

118,411

141,270

150,293

156,429

(4,692)

9,570

10,410

(2,766)

3,948

8,668

15,178

9,090

Basic, per share (1)

(0.02)

0.04

0.03

(0.07)

0.01

0.02

0.04

0.02

Diluted, per share (1)

(0.02)

0.03

0.03

(0.07)

0.01

0.02

0.04

0.02

Adjusted EBITDA (1)

2,772

13,259

16,724

4,513

14,440

20,173

25,642

31,951

Net earnings (loss)

Cash flow (1)

(46,844)

39,966

47,767

(14,731)

5,546

(33,126)

7,946

(19,164)

Basic per share

(0.22)

0.15

0.12

(0.03)

0.01

(0.08)

0.02

(0.04)

Diluted per share

(0.22)

0.14

0.11

(0.03)

0.01

(0.08)

0.02

(0.04)

64,255

40,236

100,727

116,846

118,272

59,316

49,842

20,548 19,532

Property and equipment additions

96,220

401,160

333,634

256,787

118,382

69,412

51,120

Working capital surplus

120,035

455,001

347,139

245,067

127,186

99,834

61,543

65,375

Long-term debt

803,915

960,593

889,113

876,181

851,978

888,323

867,650

843,601

Shareholders’ equity

428,276

622,235

658,336

671,588

668,722

644,166

648,543

650,183

Bitumen – bbl/d

6,170

6,284

6,551

6,090

6,936

6,211

6,758

13,238

Crude oil – bbl/d

1,180

1,114

993

880

937

906

819

873

Natural gas – Mcf/d

12,828

12,144

10,377

10,319

9,662

9,278

9,158

8,318

Equivalent – boe/d (3)

9,488

9,421

9,274

8,690

9,483

8,663

9,103

15,498

Bitumen – $/bbl

22.45

40.95

45.30

48.23

51.98

43.13

42.68

45.08

Crude oil – $/bbl

39.63

54.87

60.58

67.24

71.08

61.90

62.45

66.72

4.89

3.35

2.91

4.34

4.86

3.78

3.42

3.44

26.13

38.11

41.74

45.76

49.99

41.44

40.74

44.09

3.02

1.90

2.13

2.45

3.57

2.73

2.72

2.76

17.73

13.98

15.43

20.61

17.47

19.25

18.08

17.91

5.38

22.23

24.18

22.70

28.95

19.46

19.94

23.42

6,867

9,145

7,076

8,188

9,347

9,373

9,903

10,137

72

96

75

86

98

99

104

107

7

5

8

(7)

(8)

12

12

9

211,291

403,546

403,567

427,031

428,246

429,103

429,120

447,168

Basic (000)

211,286

266,425

403,565

421,804

427,830

429,023

429,106

442,941

Diluted (000)

211,286

286,985

424,058

422,344

430,077

429,023

431,487

442,941

Volume traded (000)

67,387

249,700

129,206

207,978

167,483

182,419

98,105

137,128

High

1.00

1.66

1.15

1.33

1.65

1.88

1.52

1.35

Low

0.61

0.74

0.76

0.94

1.16

1.20

1.15

1.10

Close (end of period)

0.74

0.92

1.10

1.28

1.49

1.29

1.20

1.33

Cash on hand

Operational Upstream: Daily production volumes (2)

Product sales prices (4)

Natural gas – $/Mcf Selected highlights – $/boe (3) Weighted average sales price (4) Royalties Operating costs Netback (1) Downstream: Refining Crude charged – bbl/d Refining utilization – % Margins – %

Common Shares Shares outstanding end of period (000) Weighted average shares outstanding for the period

Common share price ($)

(1) A non-GAAP measure which is defined in the Advisory section of the MD&A (2) Represents bitumen, crude oil and natural gas produced in the period. Actual sales volumes may be different due to the inventory at the period end. Actual production volumes sold were 15,405 boe/d in Q4 2010 (production volumes equal sales volume from Q1 2009 to Q3 2010) (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 does not represent a value equivalency at the wellhead. Boes 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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CONNACHER OIL AND GAS LIMITED

Consolidated financial statements For the year ended December 31, 2010

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 Canadian generally accepted accounting principles appropriate in the circumstances and include some amounts that are based on managements’ best estimates and judgments. Information contained elsewhere in the Annual Report 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 accountants 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 accountants and management to obtain satisfaction that they are properly discharging their responsibilities. The independent accountants 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, Signed, “R.A. Gusella”

“R.R. Kines”

Chairman and Chief Executive Officer

Vice President, Finance and Chief Financial Officer

March 17, 2011

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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 sheets as at December 31, 2010 and 2009, and the consolidated statements of operations and retained earnings, comprehensive income (loss), accumulated other comprehensive loss and cash flow for the years then ended, 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 Canadian generally accepted accounting principles, 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, 2010 and 2009 and the results of its operations and its cash flows for the years then ended in accordance with Canadian generally accepted accounting principles.

“Deloitte & Touche LLP” Chartered Accountants Calgary, Alberta March 17, 2011

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CONNACHER OIL AND GAS LIMITED

Consolidated Balance Sheets As at December 31 (Canadian dollar in thousands)

2010

2009

ASSETS CURRENT ASSETS $ 19,532

$ 256,787

Accounts receivable

57,419

43,067

Inventories (note 4)

57,144

36,871

Prepayments and other assets

16,857

15,166

Cash

Income taxes recoverable Future income tax asset (note 10)

796

2,608

4,497

2,348

156,245

356,847

615

708

27,938

50,379

1,395,524

1,230,256

103,676

103,676

$ 1,683,998

$ 1,741,866

Accounts payable and accrued liabilities

$ 81,886

$ 105,620

Risk management contracts (note 13.2)

8,984

4,520

90,870

110,140

Prepayments and other assets (note 7.4) Investment in Petrolifera Petroleum Limited (note 6) Property, plant and equipment (note 5) Goodwill

LIABILITIES AND SHAREHOLDERS’ EQUITY CURRENT LIABILITIES

Risk management contracts (note 13.2) Long-term debt (note 7) Asset retirement obligations (note 8) Employee future benefits (note 9) Future income taxes (note 10)

9,879

-

843,601

876,181

39,191

32,848

915

1,066

49,359

50,043

1,033,815

1,070,278

SHAREHOLDERS’ EQUITY 611,599

590,845

Equity component of convertible debentures (note 7.1)

16,817

16,817

Contributed surplus (note 12)

35,503

30,560

Retained earnings

10,746

49,544

Share capital (note 11)

Accumulated other comprehensive loss

(24,482)

(16,178)

650,183

671,588

$ 1,683,998

$ 1,741,866

Commitments (note 18) Subsequent events (notes 6.2 and 19)

The accompanying notes to the consolidated financial statements are an integral part of these statements.

Approved by the Board: Signed Signed “D.H. Bessell”, Director

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AR 2010 CONNACHER

“C.M. Evans”, Director

CONNACHER OIL AND GAS LIMITED

Consolidated Statements of Operations and Retained Earnings For the years ended December 31 (Canadian dollar in thousands, except per share amounts)

2010

2009

REVENUE $ 270,033

$ 191,959

Downstream (note 16)

319,898

257,830

Loss on revenue risk management contracts (note 13.2)

(15,885)

(25,125)

Upstream, net of royalties

256

3,550

574,302

428,214

Upstream – diluent purchases and operating costs (note 16)

160,697

116,910

Downstream – crude oil purchases and operating costs (note 16)

287,918

242,006

26,772

18,879

1,301

-

19,921

14,772

Interest and other income

EXPENSES

Transportation costs (note 16) Loss on operating cost risk management contracts (note 13.2) General and administrative Stock-based compensation (note 12) Finance charges (note 7.6) Foreign exchange gain (note 13.2) Depletion, depreciation and accretion

Earnings (loss) before income taxes and other items

5,063

4,562

64,877

44,354

(41,641)

(106,164)

79,586

66,562

604,494

401,881

(30,192)

26,333

Share of loss, dilution loss and impairment loss in Petrolifera Petroleum Limited (note 6)

(21,393)

(7,480)

Earnings (loss) before income taxes

(51,585)

18,853

Current income tax recovery (note 10) Future income tax recovery (note 10)

NET EARNINGS (LOSS)

291

1,601

12,496

5,704

12,787

7,305

(38,798)

26,158

49,544

23,386

Retained earnings, end of year

$ 10,746

$ 49,544

EARNINGS (LOSS) PER SHARE – basic and diluted (note 17.1)

$ (0.09)

$ 0.08

Retained earnings, beginning of year

The accompanying notes to the consolidated financial statements are an integral part of these statements.

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CONNACHER OIL AND GAS LIMITED

Consolidated Statements of Comprehensive Income (Loss) For the years ended December 31 (Canadian dollar in thousands) Net earnings (loss) Foreign currency translation adjustment Comprehensive income (loss)

2010

2009

$ (38,798)

$

(8,304)

26,158

$ (47,102)

(23,980) $

2,178

Consolidated Statements of Accumulated Other Comprehensive Loss For the years ended December 31 (Canadian dollar in thousands) Balance, beginning of year Foreign currency translation adjustment relating to Montana Refining Company, Inc. Share of foreign currency translation adjustment of Petrolifera Petroleum Limited, net of tax of $196 (2009 – $104) Balance, end of year

2010

2009

$ (16,178)

$

(7,452)

(23,255)

(852) $ (24,482)

(725)

$

The accompanying notes to the consolidated financial statements are an integral part of these statements.

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AR 2010 CONNACHER

7,802

(16,178)

CONNACHER OIL AND GAS LIMITED

Consolidated Statements of Cash Flow For the years ended December 31 (Canadian dollar in thousands)

2010

2009

$ (38,798)

$ 26,158

79,586

66,562

Cash provided by (used in) the following activities:

OPERATING Net earnings (loss) Add (Deduct) items not involving cash: Depletion, depreciation and accretion Stock-based compensation

5,063

4,562

Financing charges – non-cash portion

6,970

5,061

Defined benefit plan expense (note 9.1) Future income tax recovery Unrealized loss on risk management contracts - net (note 13.2) Gain on repurchase of Second Lien Senior Notes Share of loss, dilution loss and impairment loss in Petrolifera Petroleum Limited (note 6)

426

651

(12,496)

(5,704)

14,343

4,520

-

(2,271)

21,393

7,480

(39,603)

(94,497)

36,884

12,522

Contribution to defined benefit plan (note 9.1)

(517)

(234)

Asset retirement expenditures (note 8)

(647)

(142)

(24,935)

(17,300)

10,785

(5,154)

Proceeds on issue of common shares (note 11.1)

27,282

203,098

Share issue costs

(1,489)

(10,560)

Issuance of First Lien Senior Notes

-

212,218

Debt issue cost of First Lien Senior Notes

-

(7,503)

Repurchase of Second Lien Senior Notes

-

(2,901)

25,793

394,352

(236,687)

(313,894)

1,721

-

Unrealized foreign exchange gain (note 13.2) Cash flow from operations before working capital and other changes

Changes in non-cash working capital (note 17.2)

FINANCING

INVESTING Capital expenditures Proceeds on disposition of property, plant and equipment Investments in Petrolifera Petroleum Limited Changes in non-cash working capital (note 17.2)

NET (DECREASE) INCREASE IN CASH Foreign exchange loss on cash balances held in foreign currency CASH, BEGINNING OF YEAR CASH, END OF YEAR

-

(12,029)

(34,797)

(14,948)

(269,763)

(340,871)

(233,185)

48,327

(4,070)

(15,203)

256,787

223,663

$ 19,532

$ 256,787

For supplementary cash flow information – see note 17 The accompanying notes to the consolidated financial statements are an integral part of these statements.

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CONNACHER OIL AND GAS LIMITED

Notes to the Consolidated Financial Statements For the Years ended December 31, 2010 and December 31, 2009

1. Nature of Operations and Organization Connacher Oil and Gas Limited (“Connacher” or “the company”) is a publicly traded integrated energy company headquartered in Calgary, Alberta, Canada.

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 business segments – upstream in Canada and downstream in U.S.A., through a wholly-owned subsidiary, Montana Refining Company, Inc. (‘‘MRCI’’).

Upstream includes exploration for and 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.

The company also has an investment in Petrolifera Petroleum Limited (“Petrolifera”), which has been accounted for on the equity basis. Petrolifera is engaged in petroleum and natural gas exploration, development and production activities in South America. See note 6.2.

2. Significant Accounting Policies 2.1 Principles of Consolidation and Preparation of Financial Statements The consolidated financial statements have been prepared in accordance with Canadian generally accepted accounting principles (‘‘Canadian GAAP’’) and include the accounts of the company and its subsidiaries after the elimination of intercompany balances and transactions. Some of the company’s upstream activities are conducted jointly with third parties and accordingly these consolidated financial statements reflect the company’s proportionate share of these activities. All amounts are presented in Canadian dollars unless otherwise specified.

2.2 Cash and Cash Equivalents Cash and cash equivalents consist of cash on hand and short-term deposits with initial maturities of equal to or less than three months. There were no short-term deposits as at December 31, 2010 and December 31, 2009.

2.3 Inventories Inventories are stated at the lower of cost or net realizable value. Cost is determined following the weighted average cost method. Previous impairment write-downs are reversed when or if there is a change in the situation that caused the impairment.

2.4 Property, Plant and Equipment Petroleum and Natural Gas – Upstream The company follows the full cost method of accounting whereby all costs relating to the exploration for and development of bitumen, crude oil and natural gas reserves is capitalized on a country by country cost centre basis.

Such costs include land acquisition, geological and geophysical activity, drilling of productive and non-productive wells, asset retirement costs, carrying costs directly related to unproved properties and administrative and interest costs directly related to exploration and development activities. Expenditures related to renewals or betterments that improve the productive capacity or extend the life of an asset are capitalized. Maintenance and repairs are expensed as incurred.

Capitalized costs of petroleum and natural gas properties, plant and related equipment within a cost centre are depleted and depreciated using the unit-of-production method, based on estimated proved reserves, before royalties, as determined by the company’s independent reservoir engineers. For the purpose of this calculation, production and reserves of natural gas are converted to equivalent units of crude oil based on relative energy content (6 Mcf:1 barrel).

Costs subject to depletion and depreciation include the estimated future costs required to develop proved reserves.

Proceeds from dispositions are normally credited to oil and gas properties and a gain or loss is not recognized, unless the gain or loss changes the depletion rate by 20 percent or more.

Costs of acquiring and evaluating unproved properties are excluded from costs subject to depletion and depreciation until it is determined whether or not proved reserves are attributable to the properties, or the property is determined to be impaired. Costs associated with major development projects are excluded from costs subject to depletion and 78

AR 2010 CONNACHER

depreciation until the property becomes capable of production or development activity ceases or the property is determined to be impaired.

Impairment losses are recognized when the carrying amount of a cost centre exceeds the sum of: • the undiscounted cash flows expected to result from production of proved reserves, based on forecast oil and gas prices and costs; • the cost of unproved properties, less impairment; and • the cost of major development projects, less impairment.

The amount of impairment loss is determined to be the amount by which the carrying amount of the cost centre exceeds the sum of: • the fair value of proved and probable reserves, calculated using a present value technique that uses the cash flows expected to result from production of the proved and probable reserves, discounted using an appropriate rate; and • the cost, less impairment, of unproved properties and major development projects.

Refining – Downstream Depreciation and amortization of refining assets are calculated based on estimated useful lives and salvage values. When assets are placed into service, estimates are made with respect to their useful lives that are believed to be reasonable.

However, factors such as competition, regulation or environmental matters could cause changes to estimates, thus impacting the future calculation of depreciation and amortization. Depreciation is provided using the straight-line method, based on estimated useful lives of assets, which range from three to sixteen years.

Long-lived refining assets are also evaluated for potential impairment by identifying whether indicators of impairment exist and, if so, assessing whether the long-lived assets are recoverable from estimated future undiscounted cash flows. The actual amount of impairment loss, if any, to be recorded is equal to the amount by which a long-lived asset’s carrying value exceeds its fair value. Estimates of future cash flows and fair values of assets require subjective assumptions with regard to future operating results and actual results could differ from those estimates.

The refining assets require regular major maintenance and repairs, which are commonly referred to as ‘‘turnarounds’’.

The required frequency of the maintenance varies by asset type and occurs generally every three to four years. The costs of turnarounds are recorded as capital costs if they meet the definition of a capital asset and are amortized on a straight-line method over the period of the life of that capital asset. Normal repairs and maintenance costs that do not meet the criteria for recognition as an asset are charged to earnings when they arise.

Furniture, Equipment and Leaseholds – Corporate Furniture and equipment are recorded at cost and are depreciated on a declining balance basis at rates of 20 percent to 30 percent per year. Leaseholds are amortized over the lease term.

2.5 Investment in Petrolifera Petroleum Limited (“Petrolifera”) The investment in Petrolifera is accounted for on the equity basis, whereby the carrying value reflects the company’s initial cost of its investment, the company’s equity interest share of its accumulated income (loss) and other comprehensive income (loss) and the dilution gains and losses resulting from the issuance of additional shares by the investee, net of any permanent impairment in the value of investment.

2.6 Income Taxes The company follows the liability method of accounting for income taxes. Under this method, income tax liabilities and assets are recognized for the estimated tax consequences attributed to differences between the amounts reported in the financial statements and their respective tax bases, using substantively enacted income tax rates. The effect of a change in income tax rates on future income tax assets and liabilities is recognized in income in the period during which that change occurs. Future tax assets recognized are assessed by management at each balance sheet date for impairment. An impairment is recognized when management assesses that it is not more likely than not that the asset will be recovered.

2.7 Goodwill Goodwill is the excess of purchase price over fair value of net assets acquired in a business combination. Goodwill is not amortized and is subject to impairment test at least on an annual basis, or more frequently, if there are indicators of impairment. Goodwill and all other assets and liabilities have been allocated to the company’s segments, referred to as reporting units. To assess impairment, the fair value of each reporting unit is determined and compared to the carrying value of the reporting unit. If the fair value of the reporting unit is less than the carrying value, then a second test is performed to determine the amount of the impairment. The amount of the impairment is 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 value of the reporting unit’s goodwill. Any excess of the carrying value of goodwill over the implied fair value of goodwill is the impairment amount.

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2.8 Asset Retirement Obligations The company recognizes an asset retirement obligation for abandoning petroleum, natural gas and bitumen wells, related facilities, compressors and gas plants, removal of equipment from leased acreage and for returning such land to its original condition, by estimating and recording the fair value of each asset retirement obligation arising in the period a well or related asset is drilled, constructed or acquired. This fair value is estimated using the present value of the estimated future cash outflows to abandon the asset at the company’s credit adjusted risk-free interest rate and includes estimates for inflation. The obligation is reviewed regularly by management, based upon current regulations, costs, technologies and industry standards. The discounted obligation is initially capitalized as part of the carrying amount of the related upstream property, plant and equipment and a corresponding liability is recognized. The liability is accreted against earnings until it is settled, or the property is sold and is included as a component of depletion, depreciation and accretion expense. The amount of the capitalized retirement obligation is depleted and depreciated on the same basis as the other capitalized upstream property, plant and equipment. Actual abandonment and reclamation expenditures are charged to the accumulated obligation as incurred and costs of properties disposed are removed.

2.9 Employee Future Benefits The company maintains a defined benefit pension plan and defined contribution savings plans. The costs associated with the defined benefit pension plan are actuarially determined using the projected benefit method, prorated on service and management’s best estimate of expected plan investment performance, salary escalation and retirement ages of employees. The expected return on plan assets is based on the fair value of those assets. The cost of the company’s portion of the defined contribution savings plans is expensed as incurred.

2.10 Convertible Debentures On initial recognition, the convertible debentures were classified into debt and equity components at fair value. The fair value of the liability component was determined as the present value of the principal and interest payments, discounted using the company’s incremental borrowing rate for debt with similar terms but without a conversion feature. The amount of the equity component was determined as a residual, after deducting the amount of the liability component from the face value of the debentures. Subsequent to the initial recognition, the liability component is remeasured at amortized cost using the effective interest rate method. The equity component is not remeasured subsequent to initial recognition.

2.11 Stock-Based Compensation Employee Stock Options The fair value of each stock option granted is estimated on the date of grant using the Black-Scholes option pricing model. The amount is expensed or capitalized and credited to contributed surplus over the vesting period. Upon exercise of the options, the exercise proceeds, together with amounts previously credited to contributed surplus, are credited to share capital. On the occurrence of forfeitures, accrued compensation for an unvested option is adjusted to earnings by decreasing the compensation cost in the period of actual forfeiture.

Share Award Plan For Non-Employee Directors Obligations for payments in common shares under the company’s share award plan for non-employee directors are accrued as stock-based compensation expense and liabilities over the vesting period. Fluctuations in the price of the company’s common shares change the accrued compensation expense and are recognized over the remaining vesting period.

2.12 Flow-Through Shares The resource expenditure deductions, for income tax purposes, related to exploratory and development activities funded by flow-through share arrangements are renounced to investors in accordance with tax legislation. Accordingly, share capital is reduced and the future income tax liability is increased by the tax benefits related to the expenditures at the time they are renounced.

2.13 Foreign Currency Translation Monetary assets and liabilities denominated in foreign currency are translated at the rate of exchange prevailing on the balance sheet date. Gains or losses resulting from these translation adjustments are included in statement of operations.

Non-monetary assets and liabilities and revenue and expenses are recorded using monthly average rates of exchange.

The accounts of self-sustaining foreign operations are translated to Canadian dollars using the current rate method.

Assets and liabilities are translated at the rate of exchange prevailing on the balance sheet date and revenues and expenses are translated at the monthly average exchange rate for the period. Gains and losses on the translation of self-sustaining foreign operations are included in other comprehensive income (loss). MRCI’s operations are considered self-sustaining for the purposes of these consolidated financial statements.

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2.14 Financial Instruments Non-Derivative Financial Instruments Non-derivative financial instruments comprise cash, accounts receivable, accounts payable and accrued liabilities and long-term debt. Non-derivative financial instruments are recognized initially at fair value plus any directly attributable costs. Subsequent to initial recognition, non-derivative financial instruments are classified as follows with their respective subsequent measurement basis: Non-derivative financial instrument

Classification

Subsequent measurement basis

Cash

Held for trading

Fair value

Accounts receivable

Held for trading

Fair value

Accounts payable and accrued liabilities

Held for trading

Fair value

Long-term debt (Revolving Credit Facility)

Other liabilities

Amortized cost. Transaction costs are amortized over the term of the facility using the straight line method.

Long-term debt (First and Second Lien Senior Notes)

Other liabilities

Amortized cost. Transaction costs are amortized using the effective interest rate method.

Derivative Financial Instruments The company enters into certain derivative 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 derivative contracts as effective accounting hedges and thus has not applied hedge accounting. As a result, all derivative contracts are classified as “held for trading� and recorded on the balance sheet at fair value at each reporting date. Realized gains or losses from derivative contracts related to crude oil and gasoline commodity price contracts are recognized in revenue as the related sales occur. Realized gains or losses from derivative contracts related to natural gas costs are recognized in expenses as the related natural gas costs are incurred.

Unrealized gains and losses on the derivative contracts are recorded as revenue or expenses based on the mark-tomarket calculations at the end of each respective reporting period. Attributable transaction costs are recorded in the statement of operations.

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 at fair value on the consolidated balance sheet. Settlements of these physical sales and purchase contracts are recognized in related revenues and expenses.

2.15 Revenue Recognition Revenues from the sale of crude oil, natural gas, natural gas liquids, bitumen, purchased commodities and refined petroleum products are recorded when title passes to an external party and payment has either been received or collection is reasonably certain. Sales between the business segments of the company are eliminated from revenues and expenses.

Revenues received prior to bringing an item of property, plant and equipment into its substantial completion and productive use are credited to the capitalized costs of the property, plant and equipment.

2.16 Measurement Uncertainty The timely preparation of the consolidated financial statements in conformity with Canadian GAAP requires that management make estimates and assumptions and use judgment regarding 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 period. Such estimates primarily relate to unsettled transactions and events as of the date of the consolidated financial statements. Accordingly, actual results may differ from estimated amounts as future confirming events occur.

Amounts recorded for depletion, depreciation and accretion expense, asset retirement costs and obligations and amounts used in impairment tests for goodwill and property, plant and equipment are based on estimates. These estimates include petroleum and natural gas reserves, future petroleum and natural gas prices, future interest rates and future costs required to develop those reserves and other fair value assumptions. By their nature, these estimates are subject to measurement uncertainty and changes in such estimates in future years could be material.

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 statement of operations depend on certain actuarial and economic assumptions which are subject to measurement uncertainty.

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The estimated fair value of the investment in Petrolifera involves estimates which, by their nature, are subject to uncertainty.

The estimated fair value of derivative instruments involves the estimates of forecast commodity price and volatility and accordingly, is subject to measurement uncertainty.

Tax interpretations, regulations and legislation in the jurisdictions in which the company and its subsidiary and Petrolifera operate are subject to change.

Amounts recorded for stock-based compensation expense are based 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.

2.17 Per Share Amounts Basic per share amounts are calculated using the weighted average number of common shares outstanding for the year.

The company follows the treasury stock method to calculate diluted per share amounts. The treasury stock method assumes that any proceeds from the exercise of in-the-money stock options and other dilutive instruments, plus the amount of stock-based compensation not yet recognized would be used to purchase common shares at the average market price during the period.

2.18 Reclassifications Certain information provided for the prior year has been reclassified to conform to the presentation adopted in 2010.

3. Recent Accounting Pronouncements 3.1 International Financial Reporting Standards (“IFRS”): Effective January 1, 2011, the company will be required to report its consolidated financial statements in accordance with IFRS and restate the comparative information for year ended December 31, 2010. The company is in final phase of the assessment of the significant impacts on its consolidated financial statements relating to the conversion to IFRS.

4. Inventories 2010

2009

$ 10,222

$ 13,456

40,267

18,185

6,655

5,230

As at December 31 (Canadian dollar in thousands) Raw materials Finished products Chemicals and supplies

$ 57,144

$

36,871

As a result of improved commodity prices, Connacher reversed the previous write-down totaling $1.4 million and $9 million in 2010 and 2009, respectively. These reversals are included in “Downstream-Crude Oil Purchases and Operating Costs”.

5. Property, Plant and Equipment As at December 31, 2010

(Canadian dollar in thousands) Upstream Downstream Furniture, equipment and leaseholds

Cost

Accumulated Depletion & Depreciation

Net Book Value

$ 1,539,693

$ 231,988

107,615

26,398

As at December 31, 2009

Cost

Accumulated Depletion & Depreciation

Net Book Value

$ 1,307,705

$ 1,303,276

$ 167,538

$ 1,135,738

81,217

105,789

18,075

87,714

14,400

7,798

6,602

12,272

5,468

6,804

$ 1,661,708

$ 266,184

$ 1,395,524

$ 1,421,337

$ 191,081

$ 1,230,256

In 2010, the company capitalized $5.1 million (2009 – $5.0 million) of general and administrative expenses, $1.7 million (2009 – $1.1 million) of stock-based compensation costs and $38.3 million (2009 – $52.4 million) of interest and financing costs related to upstream property, plant and equipment.

As at December 31, 2010, costs relating to unproved properties totaling $118.7 million (2009 – $96.9 million) were excluded from costs subject to depletion and depreciation. As at December 31, 2010, future development costs of approximately $1.4 billion (2009 – $1.4 billion) were included in costs subject to depletion.

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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 after October 1, 2010 have been recorded in the statement of operations. Prior to October 1, 2010, Algar was considered a major development project and all costs, including financing costs and expenses net of revenues were capitalized and were not subjected to depletion.

Connacher’s petroleum and natural gas reserves were evaluated by qualified independent evaluators as at December 31, 2010 using the following forecast price assumptions. Based on these assumptions, the company completed a ceiling test of its upstream property, plant and equipment and determined no impairment was required for 2010 and 2009.

2011

2012

2013

2014

2015

2016

2017

2018

2019

2020

2021+

Heavy oil @ Hardisty ($Cdn/bbl) $ 68.79 $ 68.33 $ 67.03 $ 67.84 $ 70.23 $ 72.03 $ 74.08

$75.95 $ 78.00 $ 79.59 +2.0%/yr

WTI @ Cushing (US$/bbl)

102.74

Alberta Spot (CDN$/mmbtu)

88.00

89.00

90.00

92.00

95.17

97.55

100.26

105.45

107.56 +2.0%/yr

$ 4.16 $ 4.74 $ 5.31 $ 5.77 $ 6.22 $ 6.53 $ 6.76 $ 6.90 $ 7.06 $ 7.21 +2.0%/yr

6. Investment in Petrolifera Petroleum Limited (“Petrolifera”) As at December 31 (Canadian dollar in thousands) Balance, beginning of year

2010

2009

$ 50,379

$ 46,659

(1,847)

(2,468)

(4,273)

(5,012)

Effect of items recorded in consolidated statement of operations Share of loss Dilution loss (note 6.1) Accumulated impairment (note 6.2)

Acquisition of units (note 6.3) Share of other comprehensive loss Balance, end of year

(15,273)

-

(21,393)

(7,480)

-

12,029

(1,048)

(829)

$ 27,938

$ 50,379

As at December 31, 2010 and December 31, 2009, Connacher owned 26.9 million Petrolifera common shares, representing 18.5 percent as at December 31, 2010 and 22 percent as at December 31, 2009, of Petrolifera’s issued and outstanding common shares and 6.8 million Petrolifera share purchase warrants.

6.1 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 $4.3 million for the year ended December 31, 2010.

6.2 In January 2011, Petrolifera entered into an agreement with Gran Tierra Energy Inc. (“Gran Tierra Energy”) pursuant to which Gran Tierra Energy would acquire all of the issued and outstanding common shares and common share purchase warrants of Petrolifera. Under the terms of the agreement, Connacher would receive 0.1241 of a common share and common share purchase warrant of Gran Tierra Energy for each Petrolifera common share and common share purchase warrant held. The transaction is subject to the approval of the shareholders of Petrolifera. As at December 31, 2010, Connacher performed an impairment test of its investment in Petrolifera by comparing the carrying amount of the investment with its fair value. This resulted in an impairment loss of $15.3 million which was recognized in 2010.

6.3 In 2009, Petrolifera issued 66.5 million units from treasury to raise gross proceeds of $58 million. Each unit was comprised of one Petrolifera common share and one-half Petrolifera share purchase warrant. 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. Connacher subscribed for 13,556,000 units at a cost of $11.9 million.

In addition, in 2009, Connacher exercised its previously held option (see below) to purchase an additional 200,000 Petrolifera common shares at $0.50 per common share at a cost of $100,000.

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 granted a five-year option to acquire 200,000 common shares at $0.50 per share (note 6.1) and was granted a 10 percent carried working interest (“CWI”) through the drilling of the first well on each

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block. Petrolifera has 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 2010, Connacher was fully released from the provision of financial guarantees. The company will continue to own the CWI and related rights after the closing of the transaction described in note 6.2.

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 $180,000 in 2010 (2009 – $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 will be terminated upon closing of the transaction described in note 6.2.

7. Long-Term Debt As at December 31 (Canadian dollar in thousands)

2010

2009

$ 100,014

$ 100,014

First Lien Senior Notes, Due July 15, 2014 (US$200 million) (note 7.2)

198,920

210,200

Second Lien Senior Notes, Due December 15, 2015 (US$587 million) (note 7.3)

584,168

617,294

883,102

927,508

Convertible Debentures, Due June 30, 2012 (CAD$100 million) (note 7.1)

Unamortized discount and transaction costs Long-term debt

(39,501)

(51,327)

$ 843,601

$ 876,181

7.1 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 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.

As at the date of issuance, the value of the conversion feature of the Convertible Debentures was accounted for as a separate component of equity in the amount of $16.8 million.

In June 2009, $36,000 principal amount of Convertible Debentures were converted into 7,200 common shares.

Accordingly, a portion of each of the liability and equity components of the debentures, together with the principal amount, were transferred to share capital and no gain or loss was recorded.

7.2 First Lien Senior Notes, Due July 15, 2014 In June 2009, the company issued US$200 million of First Lien Senior Notes (“FLSN”). Interest is payable semi-annually at a rate of 11.75 percent on January 15 and July 15 each year the FLSN is outstanding and the principal is to be repaid on July 15, 2014. The FLSN are secured on a first priority basis (subject to specific liens up to US$50 million for the Revolving Credit Facility – note 7.4) by liens on all of the company’s assets, excluding certain pipeline assets in the U.S.A. and the company’s investment in Petrolifera.

The company may redeem some or all of the FLSN at their principal amount, plus a make whole premium, if such redemption occurs prior to July 15, 2011. The company may redeem up to 35 percent of the FLSN prior to July 15, 2011 at a redemption price of 111.75 percent of the principal amount, plus accrued interest, with the proceeds of certain equity offerings, provided that at least 65 percent of the aggregate principal amount of the FLSN remains outstanding on existing terms. After July 15, 2011, the FLSN may be redeemed at redemption prices ranging from 105.875 percent, reducing to 100 percent on July 15, 2013 and thereafter.

Upon a change of control of the company, the holders of the FLSN may require Connacher to purchase the FLSN at the redemption prices noted above, with a minimum price of 101 percent of the principal amount to be repurchased.

7.3 Second Lien Senior Notes, Due December 15, 2015 In December 2007, the company issued US$600 million of Second Lien Senior Notes (“SLSN”). Interest is payable semi-annually at a rate of 10.25 percent on June 15 and December 15 each year the SLSN is outstanding and the principal is to be repaid on December 15, 2015. The SLSN are secured by a second lien covering all of the company’s assets, with the exception of certain pipeline assets in the U.S.A. and the company’s investment in Petrolifera.

84

AR 2010 CONNACHER

The company may redeem some or all of the SLSN at their principal amount plus a make whole premium, if such redemption occurs prior to December 15, 2011. After December 15, 2011, the SLSN may be redeemed at redemption prices ranging from 105.125 percent, reducing to 100 percent on December 15, 2013, and thereafter.

In 2009, the company repurchased a total face value of SLSN of US$4.7 million (CAD$5.1 million) in the market at a discount and cancelled the repurchased SLSNs. No similar repurchases were made in 2010.

Upon a change of control of the company, the holders of the SLSN may require Connacher to purchase the SLSN at the redemption prices noted above, with a minimum price of 101 percent of the principal amount to be repurchased.

7.4 Revolving Credit Facility The company has a US$50 million revolving credit facility (the “Facility”). In 2010, the Facility was amended to extend the maturity to November 24, 2013, to reduce certain interest costs and to remove an interest coverage covenant.

The two remaining financial covenants are: • Total debt (excluding the convertible debentures) to total capitalization (defined to include all debt, convertible debentures and share holders’ equity) shall not be greater than 70 percent, declining to 65 percent when production from Algar exceeds 8,000 bbl/d for a period of 30 consecutive days; and • Debt outstanding under the Facility to EBITDA (defined to include Earnings before Finance charges, Taxes, Depletion, Depreciation and Accretion, Risk management contract gains or losses, Share of loss, dilution loss and impairment loss in Petrolifera, Stock-based compensation expense, Employee benefits cost, Gain or loss on disposition of property, plant and equipment and Foreign exchange gains or losses) shall not be greater than 2.0:1.

The company has been in compliance with all covenants throughout 2009 and 2010.

The Facility ranks ahead of the company’s First and Second Lien Senior Notes. It is secured by a first lien charge on all of the company’s assets, excluding certain pipeline assets in the U.S.A. and the company’s investment in Petrolifera. Borrowings are available as Canadian bankers acceptances, Canadian prime rate, LIBOR-base loans or US-dollar base rate loans. For the amounts drawn under the Facility, interest is payable quarterly at floating rates of lenders’ Canadian prime rate, a US base rate, a Bankers’ Acceptance rate, or at a LIBOR rate plus applicable margins. At December 31, 2010, $5.7 million of letters of credit were issued and outstanding pursuant to the Facility. In 2010, the weighted average interest rate on the Facility was 7.8 percent per annum.

The following table reconciles the beginning and ending balance of transaction costs of the Facility recorded as a part of prepayments and other assets: For the years ended December 31 (Canadian dollar in thousands) Balance, beginning of year Paid during the year Amortization expense for the year Total

2010

2009

$ 1,440

$ -

251

2,456

(752)

(1,016)

939

1,440

(324)

(732)

$ 615

$ 708

2010

2009

2011

$ -

$ -

2012

100,014

100,014

2013

-

-

2014

198,920

210,200

Less: current portion Prepayments and other assets – non-current

7.5 Principal Repayments Due Principal repayments for all the aforementioned loans are due as follows: As at December 31 (Canadian dollar in thousands)

2015

584,168

617,294

Total

$ 883,102

$ 927,508

AR 2010 CONNACHER

85

7.6 Finance Charges For the years ended December 31 (Canadian dollar in thousands) Interest expense on long-term debt Amortization of transaction costs relating to the Facility

2010

2009

$ 101,018

$ 94,549

752

1,016

Stand-by fees relating to the Facility

999

648

Bank charges and other fees

398

499

103,167

96,712

(38,290)

(52,358)

$ 64,877

$ 44,354

Less: Interest capitalized (note 7.6.1) Finance charges – net

7.6.1 Capitalized interest relates to the construction of the Algar project and has been included as a part of cost of upstream property, plant and equipment. Effective October 1, 2010, capitalization of interest ceased (note 5).

8. Asset Retirement Obligations The following table reconciles the beginning and ending aggregate carrying amount of the obligation associated with the company’s retirement of its upstream petroleum and natural gas properties and facilities: 2010

2009

$ 32,848

$ 26,396

4,339

6,194

Liabilities settled

(647)

(142)

Liabilities disposed

(264)

-

-

(1,803)

For the year ended December 31 (Canadian dollar in thousands) Balance, beginning of year Liabilities incurred

Change in estimates Accretion expense Balance, end of year

2,915

2,203

$ 39,191

$ 32,848

At December 31, 2010, the estimated total undiscounted amount required to settle the asset retirement obligations was $87.0 million (December 31, 2009 – $72.0 million). These obligations are expected to be settled over a period of 25 years.

This amount has been discounted using credit-adjusted risk-free rates of interest ranging between 6 percent to 10 percent, depending on the year in which the obligation was incurred and after provision for inflation at 2 percent per annum.

The company has not recorded an asset retirement obligation for the Refining property, plant and equipment as it is currently the company’s intent to maintain and upgrade the refinery so that it will be operational for the foreseeable future. Consequently, it is not possible at the present time to estimate a date or range of dates for settlement of any asset retirement obligation related to the refinery.

9. Employee Future Benefits The company maintains the following retirement/savings plans for its employees: a defined benefit pension plan and a defined contribution savings plan for its U.S.A. based employees and a defined contribution savings plan for its Canadian employees.

86

AR 2010 CONNACHER

9.1 Defined Benefit Pension Plan for U.S.A. Employees The company’s U.S.A. 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: Defined Benefit Plan Obligation 2010

For the years ended December 31 (Canadian dollar in thousands)

2009

$ 1,225

Defined benefit plan obligation, beginning of year

$

409

Current service cost Interest cost Actuarial loss (gain)

1,470 623

121

97

1,193

(755)

Benefits paid

(166)

(13)

Foreign exchange gain

(175)

(197)

$ 2,607

Defined benefit plan obligation, end of year

$

1,225

Defined Benefit Plan Assets 2010

For the years ended December 31 (Canadian dollar in thousands)

$ 881

Fair value of defined benefit plan assets, beginning of year

2009 $

640

Actual return on plan assets

133

141

Employer contributions

517

234

Benefits paid Foreign exchange loss $

Fair value of defined benefit plan assets, end of year

(166)

(13)

(66)

(121)

1,299

$

881

Funded Status of the Defined Benefit Plan 2010

As at December 31 (Canadian dollar in thousands)

$ 2,607

Defined benefit plan obligation, end of year Fair value of defined benefit plan assets, end of year Excess defined benefit obligation Unamortized net actuarial (loss) gain

Weighted average assumptions used in

Accrued Benefit Obligation

$

1,225

(1,299)

(881)

1,308

344

(393)

722

$ 915

Accrued defined benefit obligation

2009

$

1,066

Defined Benefit Plan Expense

2010

2009

2010

Discount rate

6.3

7.9

7.9

5.8

Expected long-term rate of return on plan assets

n/a

n/a

8.9

9.8

Long-term rate of increase in compensation level

3.0

3.0

3.0

3.0

(Percent)

2009

The expense relating to the Defined Benefit Plan was included in Downstream – crude oil purchases and operating expenses and comprised the following: (Canadian dollar in thousands) Current service cost

2010 $ 409

2009

$

623

Interest cost

121

97

Expected return on plan assets

(93)

(69)

Amortization of net actuarial (gain) loss

(11)

Net defined benefit plan expense

$ 426

$

651

The company amortizes the portion of the unrecognized actuarial gains or losses that exceed 10 percent of the greater of the accrued benefit obligation or fair value of benefit plan assets. The gains or losses that are in excess of 10 percent are amortized over the expected future years of service which was 15.7 years as at December 31, 2010 (December 31, 2009 – 15.6 years).

AR 2010 CONNACHER

87

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 company expects to contribute US$500,000 to the plan in 2011.

The composition of the Defined Benefit Plan asset was as follows: 2010

2009

Equity securities

58

58

Fixed income securities

38

38

(Percent)

Cash and cash equivalents Total

4

4

100

100

Estimated future benefits payments under the Defined Benefit Plan are as follows: (Canadian dollar in thousands)

As at December 31, 2010

2011

$ 50

2012

63

2013

96

2014

107

2015

119

2016 to 2020 Total

799 $ 1,234

9.2 Defined Contribution Savings Plan For U.S.A. 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 2010, MRCI contributed $367,000 which was recorded to “Downstream – crude oil purchases and operating costs” (2009 – $400,000) to this plan to satisfy, in full, its obligation under this plan.

9.3 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 2010, the company contributed $1.3 million (2009 – $839,000) which was recorded to general and administrative expenses to satisfy, in full, its obligation under this plan.

88

AR 2010 CONNACHER

10. Income Taxes The provision for income taxes in the consolidated statement of operations reflects an effective tax rate which differs from the expected statutory tax rate. These differences are presented below: For the years ended December 31 (Canadian dollar in thousands) Earnings (loss) before income taxes

2010 $ (51,585)

2009 $

18,853

Canadian statutory rate

28.05%

Expected income tax expense (recovery)

(14,470)

5,486

3,563

1,329

Foreign taxes

(752)

(756)

Capital taxes

437

402

(5,968)

(16,302)

3,000

1,210

Impact of reduction in Canadian tax rates

Non taxable portion of foreign exchange gains Impairment and dilution loss in Petrolifera Non deductible stock-based compensation costs Recovery of income taxes

29.1%

1,403 $ (12,787)

1,326 $

(7,305)

The net future income tax liability comprises the tax effect of the following temporary differences: As at December 31 (Canadian dollar in thousands)

2010

2009

Future income tax liability Property, plant and equipment Investment in Petrolifera Long-term debt

$ 175,983

$

427

131,541 3,109

7,355

3,472

183,765

138,122

132,919

87,976

Future income tax asset Non-capital losses carried forward Financing and share issue costs

4,885

7,871

Asset retirement obligation

9,818

8,238

Capital losses carried forward

8,523

8,560

Risk management contracts and others

7,231

1,935

163,376

114,580

(24,473)

(24,153)

Less: valuation allowance

Net future income tax liability Less: current portion of future income tax asset Net future income tax liability – non-current

138,903

90,427

44,862

47,695

4,497 $ 49,359

2,348 $

50,043

The approximate amount of total income tax pools available as at December 31, 2010 were $1,248 million in Canada and $48 million in the U.S.A. (2009 – $1,075 million in Canada and $53 million in the U.S.A.), including non-capital losses of approximately $503 million in Canada and $18 million in the U.S.A., which expire over time to 2030 and $34 million of net capital losses in Canada which are available to reduce taxable capital gains in future. These capital losses have no expiry and their future income tax benefit has not been recognized due to uncertainty of their realization at December 31, 2010 and 2009.

AR 2010 CONNACHER

89

11. Share Capital Authorized: unlimited number of common voting shares Authorized: unlimited number of first preferred shares of which none are outstanding Authorized: unlimited number of second preferred shares of which none are outstanding 11.1 Issued and Outstanding Common Share Capital Number

2010 Amount

Number

2009 Amount

Balance, beginning of year

427,031,362

$ 590,845

211,181,815

$ 395,023

Issued for cash (note 11.2)

-

-

191,762,500

172,586

17,480,000

25,346

23,172,500

30,124

2,017,836

1,936

579,724

388

For the years ended December 31 (Canadian dollar in thousands except number of shares)

Issued for cash on flow-through basis (note 11.3) Shares issued upon exercise of stock options (note 12.2)

1,082

Assigned value of stock options exercised (note 12.1) Conversion of debentures (note 7.1) Shares issued to directors as compensation (note 12.3)

-

7,200

36

638,496

1,002

327,623

302

Share issue cost, net of future income tax of $426 (2009 – $2,763)

(1,063)

Tax effect of flow-through shares (note 11.3)

(7,549)

Balance, end of year

183

-

447,167,694

$ 611,599

(7,797) 427,031,362

$ 590,845

11.2 In June 2009, the company issued 191,762,500 common shares at $0.90 per common share for gross proceeds of $172.6 million.

11.3 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. The related future income tax liability will be accounted for in 2011. As at December 31, 2010, the total remaining commitments to the qualifying expenditures pursuant to this flow-through share issuances was $25.3 million.

In October 2009, the company issued 23,172,500 common shares on a flow-through basis at $1.30 per common share for gross proceeds of $30.1 million and renounced the qualifying expenditures to investors effective December 31, 2009.

The related tax effect of $7.5 million was recorded in 2010.

12. Contributed Surplus, Stock Options and Share Award Plan for Non-Employee Directors 12.1 Contributed Surplus The following table shows the changes in contributed surplus: For the years ended December 31 (Canadian dollar in thousands) Balance, beginning of year Stock based compensation expensed Stock based compensation capitalized Assigned value of stock options exercised Balance, end of year

90

AR 2010 CONNACHER

2010 $ 30,560

2009 $

26,053

4,361

3,595

1,664

1,095

(1,082) $ 35,503

(183) $

30,560

12.2 Stock Options The company has a stock option plan permitting the issue from time to time of options entitling the holders to acquire common shares up to an aggregate of 10 percent of the number of common shares outstanding less four million common share reserved for directors share awards. Options are granted at the discretion of the Board of Directors on such terms as the board may determine. The options have a term of five years to maturity and vest over the period of two to three years.

The following table shows the changes in stock options and the related weighted average exercise prices: 2010

2009

Number of Options

Weighted Average Exercise Price

Number of Options

Weighted Average Exercise Price

Outstanding, beginning of year

22,579,045

$ 1.72

16,383,104

$ 3.16

Granted

10,263,154

1.36

12,318,375

0.96

Exercised

(2,017,836)

0.96

(579,724)

0.67

Forfeited

(3,153,695)

2.15

(945,710)

1.97

Expired

(3,257,000)

2.31

(190,000)

1.35

-

-

(4,407,000)

4.89

Outstanding, end of year

24,413,668

$ 1.50

22,579,045

$ 1.72

Exercisable, end of year

13,166,750

$ 1.73

12,689,028

$ 2.18

For the years ended December 31

Cancelled

The following table summarizes stock options outstanding and exercisable under the plan: As at December 31, 2010

Number Outstanding

Weighted Average Exercise Price

Weighted Average Remaining Contractual Life

$0.20 – $0.99

3,598,599

$ 0.75

$1.00 – $1.99

17,691,857

1.26

$2.00 – $2.99

15,000

$3.00 – $3.99 $4.00 – $4.99 $5.00 – $5.99

Range of Exercise Prices

As at December 31, 2009

Number Outstanding

Weighted Average Exercise Price

Weighted Average Remaining Contractual Life

3.3

5,089,267

$ 0.76

3.8

3.9

11,399,047

1.19

4.1

2.10

2.8

1,692,000

2.67

0.9

2,573,703

3.62

1.5

3,441,222

3.61

2.4

366,509

4.14

1.0

432,509

4.24

1.8

168,000

5.04

0.2

525,000

5.04

1.2

24,413,668

$ 1.50

3.5

22,579,045

$ 1.72

3.4

The fair value of each stock option granted is estimated on the date of grant using the Black-Scholes option pricing model using the following weighted average assumptions: 2010

2009

Risk free interest rate (percent)

1.9

1.3

Expected option life (years)

3.0

3.0

Expected volatility (percent)

72

72

For the years ended December 31

The weighted average fair value at the date of grant of options granted during the year ended December 31, 2010 was $0.66 per option (2009 – $0.46 per option).

AR 2010 CONNACHER

91

12.3 Share Award Plan For Non-Employee Directors Under the share award 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 vest in January of the year following issue 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.

2010

2009

Outstanding, beginning of year

648,916

392,705

Granted

380,598

638,496

(638,496)

(327,623)

For the years ended December 31 (Number of common share units)

Issued Cancelled

(10,420)

(54,662)

Outstanding, end of year (1)

380,598

648,916

-

10,420

Exercisable, end of year (1) Vested and issued in January 2011 and January 2010

In 2010, $702,000 was recorded as a part of stock based compensation expense and accounts payable and accrued liabilities in respect of outstanding shares under the share award plan (2009 – $967,000).

13. Financial Instruments Connacher’s financial instruments include its cash, accounts receivable, accounts payable and accrued liabilities, risk management contracts and long-term debt.

13.1 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: Carrying Value

Fair Value

Cash (1)

$ 19,532

$ 19,532

Accounts receivable (1)

$ 57,419

$ 57,419

Accounts payable and accrued liabilities (1)

$ 81,886

$ 81,886

Risk management contracts (2)

$ 18,863

$ 18,863

Convertible Debentures (3)

$ 92,762

$ 96,548

First Lien Senior Notes (3)

$

184,176

$ 216,823

Second Lien Senior Notes (3)

$

566,663

$ 587,049

As at December 31, 2010 (Canadian dollar in thousands) Held for trading

Other liabilities

(1) The fair value of cash is determined based on transaction value and is categorized as a Level 1 measurement. The fair values of accounts receivable and accounts payable and accrued liabilities are determined from transaction values which were derived from observable market input. The fair values of these financial instruments were based on Level 2 measurements (2) The fair values of the risk management contracts were determined using forward prices. These values were derived in part using active quotes and in part using observable market-corroborated data. The fair values of risk management contracts were based on Level 2 measurements (3) The estimated fair values of the long-term debt have been determined based on market information

13.2 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.

92

AR 2010 CONNACHER

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.

Accounts receivable are due from crude oil and natural gas purchasers and joint venture partners in the petroleum and natural gas industry and are subject to normal industry credit risks. The company periodically assesses the financial strength of its crude oil and natural gas 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. Generally, the only instances of impairment are when a purchaser or partner is facing bankruptcy or extreme financial distress. Sales made to two upstream customers represented 78 percent of the total upstream sales in 2010 (2009 – three customers represented 90 percent). Sales made to one downstream customer represented 12 percent and 10 percent, respectively of the total downstream sales in 2010 and 2009, respectively. Three upstream customers represented 73 percent of the upstream accounts receivable as at December 31, 2010. One downstream customer comprised 10 percent of the downstream account receivable balances as at December 31, 2010 (2009 – three customers comprised 38 percent). The company considers all amounts due over 90 days as past due. As at December 31, 2010, $1.1 million of accounts receivable were past due, 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, 2010 and December 31, 2009 is the carrying value of accounts receivable.

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. The Convertible Debentures do not mature until June 30, 2012, unless converted to common shares earlier and principal repayments are not required on the First or Second Lien Senior Notes until their maturity dates of July 15, 2014 and December 15, 2015, respectively. The company also has a revolving credit facility of US$50 million, as more fully described in note 7.4, which gives Connacher additional short-term financial flexibility for its working capital requirements.

The following table shows the maturities of Connacher’s financial liabilities: Total

Within 1 Year

1-3 Years

4-5 Years

Accounts payable and accrued liabilities

$ 81,886

$ 81,886

$ -

$ -

Long-term debt and interest payment obligations (1)

$ 1,269,840

$ 87,997

$ 540,336

$ 641,507

$ 18,863

$ 8,984

$ 9,879

$

As at December 31 (Canadian dollar in thousands) Non-derivative liabilities:

Derivative-based liabilities: Risk management contracts

-

(1) The amounts include the face value of the principal amounts due in Canadian dollar for US$ denominated loans

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. Market risk is comprised of commodity price risk, interest rate risk and foreign currency risk. The objective of market risk management is to manage and control market price exposures within acceptable limits, while maximizing returns.

AR 2010 CONNACHER

93

Commodity Price Risk The company is exposed to commodity price risk as a result of potential changes in the market prices of its crude oil sales and purchases and bitumen, natural gas and refined product sales. A portion of this risk is mitigated by Connacher’s integrated business model. The cost of purchasing natural gas for use in its oil sands and refinery operations is partially offset by the company’s conventional natural gas sales. In accordance with policies approved by the Board of Directors, derivative contracts, including petroleum commodity futures contracts, price swaps and collars may be utilized to reduce exposure to price fluctuations associated with a portion of the sales of natural gas, crude oil or bitumen sales volumes and for the sale of refined products.

The following table summarizes the net position of the company’s risk management contracts: 2010

2009

$ 8,984

$ 4,520

As at December 31 (Canadian dollar in thousands) Current liability

9,879

-

$ 18,863

$ 4,520

Non-current liability Net risk management contracts liability

The following table shows the net unrealized risk management positions: 2010

2009

$ 18,120

$ 4,520

743

-

$ 18,863

$ 4,520

As at December 31 (Canadian dollar in thousands) Crude oil liability – Upstream Natural gas liability – Upstream Liability, end of year

The following tables show the details of the risk management positions: December 31, 2010 – Crude Oil Contracts – Upstream Liability (Asset) as at December 31, 2010 (Canadian dollar in thousands) $ 561

Term

Type

Price (WTI US$/bbl)

1,000

Jan 1, 2011 – Mar 31, 2011

Swap

$ 86.10

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)

Volume (bbl/d)

Balance, as at December 31, 2010

$ 18,120

(1) On December 30, 2011, the counterparty has 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

Subsequent to December 31, 2010, the company entered in the following risk management contract: • January 1, 2012 – December 31, 2012 – 2,000 bbl/d at a minimum of WTI US$80.00 bbl/d and a maximum of WTI US$120.00/bbl.

December 31, 2010 – Natural Gas Contracts – Upstream 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

Volume (GJ/d)

Balance, as at December 31, 2010

94

AR 2010 CONNACHER

556 $ 743

December 31, 2009 – Crude Oil Contracts – Upstream Term

Type

Price (WTI US$/bbl)

Liability as at December 31, 2009 (Canadian dollar in thousands)

2,500

Jan 1 – Dec 31, 2010

Swap

$ 78.00

$ 4,115

2,500

Feb 1 – Apr 30, 2010

Swap

$ 79.02

Volume (bbl/d)

405

Balance, as at December 31, 2009

$ 4,520

The following table summarizes the amounts recorded in the statement of operations with respect to the revenue-related risk management contracts: For the years end December 31 (Canadian dollar in thousands) Unrealized loss Realized loss Loss on risk management contracts

2010 Upstream $ 13,600

2009

(1)

Total

Upstream

$ -

$ 13,600

$ 4,520

Downstream

1,742

543

2,285

20,605

$ 15,342

$ 543

$ 5,885

$ 25,125

(1) In April 2010, the company entered into a commodity price risk contract to hedge its gasoline revenue at a floating price of WTI plus US$9/bbl. The contract expired on September 30, 2010

The following table summarizes the amounts recorded in the statement of operations with respect to the operating costrelated upstream risk management contracts: For the years ended December 31 (Canadian dollar in thousands) Unrealized loss Realized loss Loss on risk management contracts

2010

2009

$ 743

$ -

558

-

$ 1,301

$ -

As at December 31, 2010, had the forward price for WTI been US$1/bbl higher or lower, the impact relating to the crude oil risk management contracts would have been to increase or decrease, respectively, the loss before income taxes by $2.6 million.

As at December 31, 2010, 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, the loss before income taxes by $206,000.

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 First and 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, 2010, the company had no floating rate 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 US dollar denominated long-term debt, crude oil sales based on US dollar indices and commodity price contracts that are settled in US dollars. The effect on the company’s financial instruments of a $0.01 change in the US to Canadian dollar exchange rate would have resulted in a $7.6 million change in foreign exchange gain/loss at December 31, 2010. The company’s downstream operations operate with a US 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 US to Canadian dollar exchange rate would have resulted in $84,000 change in other comprehensive income (loss) at December 31, 2010. The company manages these exchange rate risks by occasionally entering into fixed rate currency exchange contracts on future US dollar payments and US dollar sales receipts.

AR 2010 CONNACHER

95

The following table summarizes the components of the company’s foreign exchange gain (loss): 2010

2009

$ 42,552

$ 109,854

(3,241)

(14,062)

For the year ended December 31 (Canadian dollar in thousands) Unrealized foreign exchange gain (loss) on translation of: US denominated First and Second Lien Senior Notes Foreign currency denominated cash balances Other foreign currency denominated monetary items Unrealized foreign exchange gain

(1,295)

39,603

94,497

2,038

11,667

$ 41,641

$ 106,164

Realized foreign exchange gain (1) Foreign exchange gain

292

(1) In 2008, Connacher entered into a foreign exchange revenue collar for the calendar year 2009 which set a floor of $11.92 million and a ceiling of $13 million on a notional amount of US$10 million of monthly production revenue. In 2009, a foreign exchange gain of $8.0 million was realized in respect of this contract

14. 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 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 monitors its capital structure using a number of financial ratios and industry metrics to ensure its objectives are being met and to ensure continued compliance with its financial covenants.

Connacher’s current capital structure is summarized below: 2010

2009

$ 843,601

$ 876,181

As at December 31 (Canadian dollar in thousands) Long-term debt (1)

650,183

671,588

$ 1,493,784

$ 1,547,769

56%

57%

Shareholders’ equity Total Debt plus Equity (“capitalization”) Debt to book capitalization (2)

(1) Long-term debt is stated at its carrying value, which is net of transaction costs and the Convertible Debentures’ equity component value (2) Calculated as long-term debt divided by the book value of shareholders’ equity plus long-term debt

As at December 31, 2010, the company’s net debt (long-term debt, net of cash on hand) was $824 million. Its net debt to book capitalization was 55 percent (2009 – 40 percent).

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. The Revolving Credit Facility has financial covenants of which the company was in compliance throughout 2010 and 2009.

15. Related Party Transactions In 2010 the company incurred professional legal fees of $779,000 (2009 – $1.3 million) to a law firm in which an officer and a director of the company were partners. Transactions with the related party occurred within the normal course of business and have been measured at their exchange amount on normal business terms. The exchange amount is the amount of consideration established and agreed to with the related parties. As at December 31, 2010, accounts payable to the law firm was approximately $158,000 (2009 – $71,000).

96

AR 2010 CONNACHER

16. Segmented Information The company has two business segments. In Canada, the company is in the business of exploring for and producing bitumen and natural gas. In the U.S.A., the company is in the business of refining and marketing petroleum products.

The significant information of these segments is presented below.

(Canadian dollar in thousands) For the year ended December 31, 2010 Net revenues Diluent, crude oil purchases and operating costs Transportation costs Loss on risk management contracts – net

Canada Oil and Gas

U.S.A. Refining

Intersegment Elimination (1)

Total

$ 270,033

$ 334,165

$ (14,267)

$ 589,931

161,798

301,084

(14,267)

448,615

18,873

7,899

-

26,772

(16,643)

(543)

-

(17,186) (1,847)

(1,847)

-

-

138

118

-

256

Finance charges

64,853

24

-

64,877

Depletion, depreciation and accretion

69,115

10,471

-

79,586 (12,787)

Equity interest in Petrolifera loss Interest and other income

Income tax recovery

(12,416)

(371)

-

Net (loss) earnings

(43,517)

4,719

-

(38,798)

1,314,308

81,216

-

1,395,524

103,676

-

-

103,676

Property, plant and equipment Goodwill Capital expenditures Total assets

228,112

8,575

-

236,687

$ 1,519,603

164,395

$ -

$ 1,683,998

$ 191,959

$ 264,924

$ (7,094)

$ 449,789 358,916

For the year ended December 31, 2009 Net revenues

117,173

248,837

(7,094)

Transportation costs

Diluent, crude oil purchases and operating costs

12,355

6,524

-

18,879

Loss on risk management contracts

(25,125)

-

-

(25,125)

(2,468)

-

-

(2,468)

Equity interest in Petrolifera loss

2,950

600

-

3,550

Finance charges

Interest and other income

43,979

375

-

44,354

Depletion, depreciation and accretion

59,171

7,391

-

66,562

(4,062)

(3,243)

-

(7,305)

Income tax recovery Net earnings (loss) Property, plant and equipment

29,406

(3,248)

-

26,158

1,142,542

87,714

-

1,230,256

Goodwill

103,676

-

-

103,676

Capital expenditures

293,074

20,820

-

313,894

$ 1,592,591

$ 149,275

$ -

Total assets

$

1,741,866

(1) Intersegment sales of $14.3 million (2009 – $7.1 million) and related costs of sales of $13.2 million (2009 – $6.8 million) are eliminated on consolidation

17. Supplementary Information 17.1 Per Share Amounts For the years ended December 31 (000) Weighted average common shares outstanding – basic Dilutive effect of employee stock options Dilutive effect of non-employee directors share award plan Weighted average common shares outstanding – diluted

2010

2009

432,258

326,560

-

126

-

381

432,258

327,067

Outstanding employee stock options of 24.4 million as at December 31, 2010 (2009 – 22.6 million) and non-employee director share awards of 381,000 as at December 31, 2010 (2009 – nil) were excluded from the diluted earnings per share calculation as the effect of including them would be anti-dilutive. Common shares issuable upon the exercise of convertible debentures (note 7.1) were excluded as the effect of including them would be anti-dilutive.

AR 2010 CONNACHER

97

17.2 Changes in Non-Cash Working Capital 2010

2009

$ (15,618)

$ (25,145)

(21,802)

(8,530)

As at December 31 (Canadian dollar in thousands) Accounts receivable Inventories Due from Petrolifera Prepayments and other assets

13 (16,427)

1,751

9,197

(22,139)

8,644

$ (59,732)

$ (32,248)

$ (24,935)

$ (17,300)

(34,797)

(14,948)

$ (59,732)

$ (32,248)

Income taxes recoverable Accounts payable and accrued liabilities Total

(17) (1,907)

Relating to: Operations Investing Total

17.3 Other Cash Flow Information 2010

2009

Interest paid

$ 92,019

$ 71,999

Income taxes paid

$ 421

$ 1,621

For the years ended December 31 (Canadian dollar in thousands)

18. Commitments 2011

2012

2013

2014

2015

Thereafter

Total

$ 3,243

$ 2,913

$ 2,934

$ 2,940

$ 2,951

$ 4,923

$ 19,904 52,926

As at December 31, 2010 Operating leases Service and maintenance

2,192

2,905

2,898

2,892

2,617

38,702

Capital commitments

1,566

-

-

-

-

-

1,566

Other commitments

1,192

569

252

21

19

-

2,053

$ 8,913

$ 6,387

$ 6,084

$ 5,853

$ 5,587

$ 43,625

$ 76,449

Total

In addition, the company is also obligated to make contributions to the defined benefit plan (note 9.1), incur qualifying expenditures under the flow-through share issuances (note 11.3) and is committed to financial liabilities (note 13.2).

19. Subsequent Events In February 2011, the company closed the sale of certain properties for gross proceeds of $57.5 million, subject to normal closing adjustments. As at December 31, 2010, the company received a deposit of $5.8 million related to this disposition, which was held in escrow with the company’s counsel and accordingly, was excluded from reported cash balances.

In addition, in March 2011, the company entered into an agreement to sell certain properties for gross proceeds of $22.5 million and received a deposit of $2.25 million related to this transaction. This sale is expected to close on April 29, 2011.

98

AR 2010 CONNACHER

FIVE YEAR HIGHLIGHTS Years ended December 31 FINANCIAL ($000 except per share amounts) Revenues, net of royalties Cash flow (1) Per share, basic (1) Per share, diluted (1) Adjusted EBITDA (1) Net earnings (loss) Per share, basic Additions to property, plant and equipment Cash on hand Working capital Long-term debt Shareholders’ equity Total assets

2010 $ 574,302 $ 36,884 $ 0.09 $ 0.09 $ 92,206 $ (38,798) $ (0.09) $ 247,978 $ 19,532 $ 65,375 $ 843,601 $ 650,183 $ 1,683,998

2009 $ 428,214 $ 12,522 $ 0.04 $ 0.04 $ 37,268 $ 26,158 $ 0.08 $ 322,064 $ 256,787 $ 246,707 $ 876,181 $ 671,588 $ 1,741,866

2008 $ 636,734 $ 54,817 $ 0.26 $ 0.26 $ 60,300 $ (26,603) $ (0.13) $ 351,736 $ 223,663 $ 197,914 $ 778,732 $ 469,087 $ 1,431,675

2007 $ 348,129 $ 44,965 $ 0.22 $ 0.22 $ 61,464 $ 40,961 $ 0.20 $ 322,962 $ 392,271 $ 389,789 $ 664,462 $ 480,439 $ 1,258,828

2006 $ 246,571 $ 40,196 $ 0.22 $ 0.21 $ 49,217 $ 6,953 $ 0.04 $ 451,525 $ 142,391 $ 118,626 $ 209,754 $ 385,398 $ 712,930

8,299 883 9,100 10,699

6,274 1,041 11,407 9,216

5,456 1,029 12,570 8,581

792 9,172 2,320

980 10,473 2,725

$ 45.65 $ 65.63 $ 3.90 $ 44.13

$ 39.39 $ 54.61 $ 3.90 $ 37.81

$ 45.74 $ 82.01 $ 8.08 $ 50.76

$ $ 52.80 $ 6.38 $ 43.22

$ $ 53.85 $ 5.85 $ 41.83

9,693 102 8

7,820 82 4

9,194 97 (2)

9,485 100 15

8,713 94 14

186,668 509,434

180,159 388,915

182,839 379,474

59,856 187,249

50,379 92,933

613,485

471,406

452,294

251,466

118,646

220,572

134,919

132,772

125,531

103,671

$ 1,497 $ 3,101 $ 3,849 $ 571

$ 1,491 $ 2,156 $ 3,310 $ 384

$ 1,026 $ 1,543 $ 2,274 $ 167

$ 603 $ 1,194 $ 1,308 $ 348

$ 312 $ 528 $ 616 $ 208

447,168

427,031

211,182

209,971

197,894

432,258 432,258

326,560 327,067

210,794 214,647

200,092 202,766

184,469 188,432

OPERATIONAL Daily production volumes (4) Bitumen (bbl/d) Crude oil (bbl/d) Natural gas (Mcf/d) Barrels of oil equivalent (boe/d) (5) Upstream pricing (6) Bitumen ($/bbl) Crude oil ($/bbl) Natural gas ($/Mcf) Barrels of oil equivalent ($/boe) (5) Downstream Throughput – Crude charged (bbl/d) Refinery utilization (%) Margins (%)

RESERVES AND RESOURCES Reserves and resources (mboe) (1) Proved (1P) reserves Proved plus probable (2P) reserves Proved plus probable plus possible (3P) reserves Best estimate contingent resources Reserves and resources values ($million) (8) 1P reserves 2P reserves 3P reserves Best estimate contingent resources

COMMON SHARES Shares outstanding end of period (000) Weighted average shares outstanding for the period Basic (000) Diluted (000)

(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.

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. Similarly, effective March 1, 2008, the capitalized costs relating to the company’s first oil sands project, Pod One, 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. Prior thereto, Pod One 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 Pod One prior to March 1, 2008. Daily production averages are based on a total calendar 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 volumes sold were 10,606 boe/d in 2010 (2009 – 9,216 boe/d; 2008 – 8,581 boe/d; 2007 – 2,320 boe/d; 2006 – 2,725 boe/d) (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 (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 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 revenue before taxes. Future net revenues associated with reserves and resources do not necessarily represent fair market value AR 2010 CONNACHER

99

Management

Richard A. (Dick) Gusella Chairman and Chief Executive Officer

Peter D. Sametz President and Chief Operating Officer

Richard R. (Rick) Kines Vice President, Finance and Chief Financial Officer

Cameron Todd Senior Vice President, Operations, Refining & Marketing

Merle Johnson Vice President, Engineering

Steve Marston Vice President, Exploration

Grant Ukrainetz Vice President, Corporate Development

Brenda G. Hughes Assistant Corporate Secretary

Board of Directors

100

Richard A. (Dick) Gusella

D. Hugh Bessell

Colin M. Evans

Jennifer K. Kennedy

Stewart D. McGregor

Kelly J. Ogle

Peter D. Sametz

W. C. (Mike) Seth

AR 2010 CONNACHER

Corporate Information Board of Directors

Officers

Head Office

Richard A. Gusella Chairman and Chief Executive Officer, Connacher Oil and Gas Limited, Calgary

Richard A. Gusella Chairman and Chief Executive Officer

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

D. Hugh Bessell (1)(3)(5) Chairman, Audit Committee Retired Deputy Chairman, KPMG, LLP, Toronto Colin M. Evans (1)(3)(5) Chairman, Human Resource Committee President, Evans & Co. Inc., Calgary Jennifer K. Kennedy (2)(4) Chairman, Governance Committee Partner, MacLeod Dixon LLP, Calgary

Peter D. Sametz President and Chief Operating Officer Richard R. Kines Vice President, Finance and Chief Financial Officer Cameron M. Todd Senior Vice President, Operations, Refining & Marketing Merle Johnson Vice President, Engineering

Stewart D. McGregor (6) Lead Director President, Camun Consulting Corporation, Calgary

Stephen A. Marston Vice President, Exploration

Kelly J. Ogle (1)(3)(4) Chairman, HS&E Committee President and Chief Executive Officer, Trafina Energy Ltd., Calgary

Brenda G. Hughes Assistant Corporate Secretary

Peter D. Sametz President and Chief Operating Officer, Connacher Oil and Gas Limited, Calgary W.C. (Mike) Seth (2)(4)(5) Chairman, Reserves Committee President, Seth Consultants Ltd., Calgary (1) (2) (3) (4) (5) (6)

Grant D. Ukrainetz Vice President, Corporate Development

Rashi Sengar Corporate Secretary Partner, Macleod Dixon LLP

Toronto Stock Exchange Trading symbol – CLL

Common Shares CUSIP ISIN

20588Y103 CA20588Y1034

Debt (US Residents) 11.75% First Lien CUSIP 20588YAD5 11.75% First Lien ISIN US20588YAD58 10.25% Second Lien CUSIP 20588YAC7 10.25% Second Lien ISIN US20588YAC75 4.75% Convertible CUSIP 20588YAB9 4.75% Convertible ISIN US20588YAB92

Debt (Non US Residents) 11.75% First Lien CUSIP C2627NAB1 11.75% First Lien ISIN USC2627NAB13 10.25% Second Lien CUSIP C2627NAA3 10.25% Second Lien ISIN USC2627NAA30 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.

Audit Committee Governance Committee Human Resources Committee Health, Safety and Environment Committee Reserves Committee Mr. McGregor is not standing for re-election in 2011

Related Company Petrolifera Petroleum Limited

Auditors Deloitte & Touche LLP, Calgary

Bankers Royal Bank of Canada, Calgary

Solicitors

Abbreviations bbls barrels

mmbbls million barrels

bbl/d

barrels per day

bcf

billion cubic feet

mmboe million barrels of oil equivalent

boe

barrels of oil equivalent

mmbtu million British thermal units

boe/d

barrels of oil equivalent per day

MMcf

DCF

discounted cash flow

MMcf/d million cubic feet per day

million cubic feet

GJ gigajoule

NGLs

mbbls

PV present value

thousand barrels

natural gas liquids

mboe thousand barrels of oil equivalent

SAGD

Mcf

thousand cubic feet

WI working interest

Mcf/d

thousand cubic feet per day

WTI

Steam Assisted Gravity Drainage

West Texas Intermediate

Designed by Bryan Mills Ira desso

Macleod Dixon LLP, Calgary

Reservoir Engineers GLJ Petroleum Consultants Ltd., Calgary

Registrar and Transfer Agent Valiant Trust Company, Calgary and Toronto

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