Laricina Energy Ltd.

2010 Annual Report

A D V A N C I N G O N A L L F R O N T SAccelerating value creation through experience, knowledge and confidence

Advancements by Laricina Energy Ltd. in 2010 demonstrated our evolution into an oil sands producer. Since our inception in December 2005, careful planning, building a high-quality asset portfolio containing extensive sandstone and carbonate reservoirs, systematic resource delineation and evaluation, and thorough regulatory applications have positioned Laricina for success as we advanced to steam-assisted gravity drainage (SAGD) operations, which we initiated in 2010.

Capital expenditures of $115 million in 2010 allowed us to complete our Saleski pilot – the world’s first operational SAGD Grosmont bitumen carbonate project – and to launch construction of our Germain commercial demonstration project just before year-end. With steam injection at Saleski well underway, Laricina anticipates first oil in the second quarter of 2011. Construction of the $330 million Germain project will continue throughout 2011. Going forward, Laricina intends to step-up phase development of its two key projects at Saleski and Germain and advance additional in situ oil sands projects from its portfolio of 10 properties. Laricina is clearly advancing on all fronts.

Annual General Meeting

The Annual General Meeting of Laricina’s shareholders will take place on May 26, 2011 at 10:00 a.m. MDT in the Strand Room of the Metropolitan Centre, at 333–4th Ave. S.W., Calgary, Alberta.

Contents

2 Advancing Our Value

4 Advancing Our Assets

6 President’s Letter

10 Advancing Our Depth in People

12 Operations Review

40 Management’s Discussion and Analysis

56 Auditors’ Report to the Shareholders

57 Consolidated Financial Statements

60 Notes to the Consolidated Financial Statements

72 Corporate Information

This annual report contains certain “forward-looking statements” under applicable securities laws and includes such statements about the Company’s plans that are based on assumptions and that involve risk and uncertainties. Actual results may differ materially. Refer to page 40 for additional information on forward-looking statements.

Laricina Energy Ltd.1

It means moving our bitumen resources towards commercialization –

our first project is operational and first oil is expected in 2011, the first step of our march

towards ultimate production potential of 500,000* net barrels of bitumen per day.

It includes attracting high-quality equity investors – including Canada Pension Plan

Investment Board – raising more than $340 million and nearly doubling our

capital employed in 2010, enabling us to demonstrate value by developing our projects.

It involves continually focusing on technological enhancements – conceiving, testing,

applying, refining – and pushing out the boundaries of established approaches, with a view to optimizing productivity,

environmental performance and asset value.

And it’s about expanding our teams and skill-sets,

and forging even stronger ties with the communities around our projects.

What Does it Mean

At Laricina, We’re Advancing On All Fronts.

to Advance

* See Project Summary tables on page 15.

> 18 metres bitumen in carbonate

McMurray trend

FORT MCMURRAY

Nisku Subcrop

Grosmont Subcrop

Peace River

Edmonton

Red Earth

ALBERTA

Wabasca-Desmarais

Diversifi ed Portfolio of Oil Sands Assets

Laricina is a pure-play in situ oil sands company with 10 properties totalling more than 74,000 net hectares of oil sands rights. These properties off er exposure to four major bitumen-bearing formations – two sandstones and two carbonates, all with thick pay zones, high bitumen content and good reservoir permeability. (See page 16.) They will be developed exclusively through underground (drillable) or in situ recovery. We have evaluated more than 360 delineation wells and reviewed 2-D and 3-D seismic in order to establish the resource potential on our lands. Under the Company’s phased growth plan, our fi rst two projects – Saleski and Germain – are moving toward commercialization.

FORT

MCMURRAY

Wabasca–Desmarais

Burnt Lakes

Germain

Portage

Thornbury

Thornbury West

House River

BoilerRapids

ConnCreek

PoplarCreek

Saleski

Advancing Our Value

2010 Annual Report2

80


Industry Leader in the Carbonates

11.1billion

$11.9billion

4.6billion

500,000$797million

Barrels of exploitable-bitumen-in-place*

Barrels of net recoverable resources*

Present value of future net revenue (10% pre-tax)*

Cash equity raised since inception (to Dec. 31, 2010)

Barrels per day net production potential*

Laricina’s Saleski pilot is the industry’s first operating SAGD pilot project to tap bitumen trapped in a carbonate deposit – the Grosmont Formation. The Grosmont is Canada’s second-largest bitumen-bearing reservoir. Steam injection at Saleski began before year-end 2010 and first oil is expected in the second quarter of 2011.

The Grand Rapids is the second major bitumen-bearing sandstone formation being developed in Alberta’s oil sands. Two competitor projects, one of them offsetting Laricina lands, are establishing the Grand Rapids as a commercial reservoir. Laricina’s 5,000-barrel-per-day Germain commercial demonstration project is one of only four thermal Grand Rapids oil sands projects in the industry at present. Construction will continue throughout 2011 for start-up in late 2012.

Laricina is generating technologies to enhance the proven SAGD recovery method that will be initially used to develop our assets. The first is solvent-cyclic (SC) SAGD, which is designed to reduce steam requirements, increase productivity, increase ultimate bitumen recovery, and improve environmental performance. Further enhancements include refined well placement, drilling and completions technology, our patent-pending passive heat-assisted recovery method (PHARM) and electromagnetic heating. Our focus on developing and applying these technologies is aimed at increasing the net present value of Laricina’s resource base to maximize shareholder value.

Exploiting the Grand Rapids

Value-Enhancing Innovations

Highly experienced, committed staff (at Dec. 31, 2010)

Net recoverable resources per fully diluted share* 78 barrels

* Based on the best estimate contingent and prospective resources and proved plus probable reserves as defined in the report of GLJ Petroleum Consultants Ltd. at December 31, 2010. Recoverable resources are the unrisked arithmetic sum of proved plus probable reserves and best estimate contingent and prospective resources. See Project Summary tables on page 15.

Drilling operations at Saleski.

The first SC-SAGD pilot in the Grosmont.

Saleski producer well-head and pump drive.

2010 Annual Report4

Construction of the Saleski pilot plant, drilling of the remaining horizontal wells in 2010, and steam injection just before year-end represent a large step in Laricina’s transformation from a prospector/explorer of oil sands resources to an operator/producer of commercial reserves. The Saleski pilot also breaks new ground – pioneering development of the Grosmont as an economic formation for SAGD, testing specific well design and well placement to exploit the dual-zone carbonate opportunity, and testing Laricina’s SC-SAGD approach. The regulatory application for our first expansion phase of 10,700 barrels per day was filed before year-end.

At Saleski

Advancing Our Assets

Our key landholdings at Saleski and Germain are concentrated to the west of Alberta’s original oil sands development corridor and are well-positioned relative to important infrastructure, including year-round roads, as well as natural gas, power and water supplies, and heavy oil take-away capacity.

Preparation of Germain commercial demonstration project plant site and well pad.

Germain natural gas pipeline installation, winter 2010-2011.

Drilling operations at Germain.


Our confidence in the more established Grand Rapids sandstone formation allowed us to commit to a 5,000-barrel-per-day commercial demonstration project. Front-end engineering was completed in March 2010, followed by financing support in the summer and regulatory approvals in October. Like Saleski, the Germain project will employ SC-SAGD. Germain is currently under construction, with horizontal well drilling to begin mid-year. Laricina intends to commence steam injection in late 2012, initiating the first of a series of commercial production phases with combined production capacity of more than 200,000 barrels per day.

At Germain

2010 Annual Report6

Let’s Talk About Advancing

Laricina executed its strategy throughout 2010 and advanced on all fronts: operational, technological, financial and organizational. We raised approximately $340 million from top-quality equity investors. We strengthened our head office team and built our field operating team. We continued our focus on technology innovation, including filing a third patent application.

The nearly $200 million gross investment in the Saleski pilot and infrastructure make Laricina the leading company in the de-risking and commercialization of the Grosmont Formation carbonates, Canada’s second-largest bitumen-bearing reservoir. Bringing the pilot on-stream will enable us to establish well performance curves for conventional SAGD and SC-SAGD in the Grosmont. The Saleski performance curves will reveal how the Grosmont carbonates compare to the typical McMurray sand reservoir. Then the task of what we do with our resource begins. We will need to select the right tools to maximize economics.

As of early April 2011, our observations of the production and injection wells indicate that steam injection has proceeded well and heating is progressing as expected. The transition to production on the first well-pair is expected in the second quarter with ramp-up in production to peak well rates to occur over the next 12-18 months. (See page 25.)

Laricina has coupled creation of a new oil sands play at Saleski with exploitation of an existing commercial horizon, the Grand Rapids sandstone formation, in a new area: Germain. Just south of Germain is a major oil sands operator’s planned 180,000-barrel-per-day Grand Rapids project, where initial well-testing is underway.

President’s Letter:

Most visibly, we completed construction, commissioned and started steam injection of the Saleski SC-SAGD pilot and

commenced construction of our Germain commercial demonstration project as the year turned. It was a breakthrough year for Laricina as we truly continue to advance on all fronts.

The past year represented a step change in Laricina’s evolution as an oil sands company, from the development of ideas, capture of land, evaluation of resources and initial regulatory applications – activities marking an early-stage company – to the drilling of wells and construction of facilities characteristic of an operating company. Key pieces progressed from being promises of future performance to accomplishments. We proved our ability to construct facilities, drill horizontal wells and initiate a SAGD operation. These advancements are de-risking not only our two key projects but the Company and its business model. The coming year will bring further advancements into the reality of operations and production as we begin to commercialize our resource base.

I am proud of Laricina’s breakthrough in 2010 and the progress our team has made along the pathway we laid out upon founding the Company in 2005. We intended to be deliberate, and to manage risk in our approach to building, staffing and development. Each step has taught us something and refocused us for the next. Today, we are where we said we would be at this point in our development.

Saleski and Germain are the first two of our 10 oil sands properties to begin commercialization – the first two cornerstones to building out the business. We advanced both projects in 2010. I encourage the reader to look over the more detailed information on Saleski, Germain, and our other oil sands projects that’s provided later in the Annual Report.

The nearly $200 million gross investment in the Saleski pilot and infrastructure makes Laricina the leading company in the de-risking and commercialization of the Grosmont Formation carbonates, Canada’s second-largest bitumen-bearing reservoir.


Germain’s diminishing risk profile provided confidence for the capital commitment of approximately $330 million. With primary SAGD performance curves being established by other operators, the 5,000-barrel-per-day size offers us the opportunity to acquire broader, commercial-level information and to incorporate the SC-SAGD process. The commercial demonstration project is the first of several phases expected to be capable of producing more than 200,000 barrels per day under our current Grand Rapids plan.

Laricina’s operational advancements in 2010 were accompanied by advancements in other key areas. We more than doubled our capital available to employ in 2010, largely by adding top-quality investors, Canada Pension Plan Investment Board (CPPIB) and Korea Investment Corporation, whose combined $300 million investment over the summer provided the capital to launch Germain. Throughout Laricina’s development our goal has been to attract high-quality investors. Both new investors have a long time-horizon and, we are optimistic, will become strong financial partners. Our working capital increased to $364 million at year-end, which fully funds our expected $340 million 2011 spending program. Our strong equity position provides time

and flexibility to consider the full range of capital options in 2011 – private and public equity as well as debt, joint ventures or asset sales.

Innovation is a large creator of wealth in the energy sector as it adds value to conventional processes. Innovative thinking gains momentum when a company captures new plays, applies new recovery techniques to existing plays or existing techniques to new areas (or both), and develops technical enhancements that drive costs down and resource recovery up. Laricina has focused on innovation as part of its business plan and we strive to create and cultivate these advantages. Saleski and Germain can be exploited with ordinary SAGD, but we are adding the SC component at both projects. As SC-SAGD technology is applied, we will test where we can go after that, both in terms of the size of the steps and the tools to be used. We will also examine our PHARM technology and then perhaps electromagnetic heating with solvents as well as other innovations. (Please see our discussion of Advancing our Innovations on page 37.)

Laricina has always partnered with other experts to strengthen its innovation process, such as the University of Calgary (U of C), the founding school of in situ SAGD recovery research. We have invested

Geological team.

2010 Annual Report8

or committed nearly $1 million in funding research, student scholarships and facilities. We have co-authored numerous papers focused on subjects relevant to Laricina’s business with professors and students in the engineering faculty, and we chair the U of C’s solvent heat-assisted recovery program (SHARP). In 2010 we filed our third patent application for in situ recovery relating to the utilization of electromagnetic applications for recovery processes. Last year approximately $40 million gross of funding or capital commitments was provided for the support of our technology advancements through technical and industry partners, and the Climate Change and Emissions Management Corp.

People drive every business. Laricina is no different. We started with eight people and have focused on attracting and developing strong professionals to build the Company and drive our projects. Our approach to securing the necessary skilled and expert personnel is to work continuously to strengthen the abilities of our existing staff and supplement them with new graduates and seasoned people as we grow. We believe that this combination will best position Laricina to succeed on its path of growth.

Looking forward, 2011 will see the next stage of progress in developing our project inventory, which has net estimated production potential of more than

500,000-barrels-per-day. With a spending program of $340 million, Laricina has a broad plan underway in 2011 including:

– Continued ramp-up of the Saleski pilot while gathering well performance curves to assist in planning the first expansion;

– Advance our project at Germain, including camp expansion, civil work, laying 21-km gas supply pipeline, drilling observation and service wells, ordering major equipment, commencing drilling of horizontal well-pairs in July, and commencing facility construction and receipt of facility modules in the third quarter;

– Prepare for performance testing of solvents in SC-SAGD at Saleski;

– Continue work on PHARM and assessment of electromagnetic heating of bitumen reservoirs;

– Maintain the flow in our pipeline of ideas;

– Hire Germain field staff over the next 18–24 months; – Grow head office team from 80 to approximately

110 over the next 12–18 months;

– Progressing of first Saleski expansion application;

– Continued work on the Germain regulatory and environmental impact assessment (EIA) filing for additional phase capacity of 150,000 barrels per day; and

– Further enhancement of our balance sheet.

We anticipate continuation of the positive economic and business trends that characterized 2010, including strength in global GDP, population growth, energy consumption, commodity pricing and capital markets. Global crude oil consumption, for example, in 2010 exceeded the previous peak

Drilling at Germain.

Looking forward, 2011 will see the next stage of progress in developing our project inventory, which has net estimated production potential of more than 500,000 barrels per day.


of 2008, before the economic downturn, and is forecast to increase further in 2011. As of early April 2011 crude prices were once again more than $100 per barrel WTI, sufficient to drive robust capital investment in the Alberta oil sands.

We intend to continue contributing to the improving public understanding of the oil sands as an energy sector. Canadian oil is among the highest-quality global sources of crude oil. Cambridge Energy Research Associates reported in 2010 that the sector’s progress on carbon management has reduced the marginally larger carbon footprint of oil sands production by 5–15 percent versus competing U.S. crude oil imports. On other measures like social responsibility, government integrity/ethics, environmental regulation and responsible development, Canadian oil easily outranks competing U.S. imports.

The public is recognizing that Canadian oil is responsibly developed and produced in a world in need of energy. The International Energy Agency regards Canada’s oil sands as the largest source of developing oil supply outside of OPEC. In 2011 we believe that the public will develop a better understanding of what the oil sands sector does and the progress it is making. We see this as positive, not only in and of itself, but for Laricina’s position in the capital markets. We are committed to offering shareholders an investment they can view positively not only in terms of profitability but also as a responsible business.

As a Laricina investor, you can be proud that the Company plays an active role in an industry committed to responsible development. We intend to develop further improvements to our extraction methods, which are already among the industry’s most advanced and progressive in terms of economics, environmental footprint, water use and air emissions. In our SAGD projects, reductions in environmental impacts are also improvements in economics – a reduced steam-oil ratio, for example, attains both objectives.

Similarly to publicly-traded companies, we adopted International Financial Reporting Standards (IFRS) this year with a view to continuing to present the Company on a comparable basis. We are on-schedule

Glen C. SchmidtPresident and Chief Executive OfficerApril 6, 2011

in establishing new processes and procedures for the preparation of IFRS-compliant financial statements, and are on-track for full implementation by the end of the first quarter of 2011.

As we advance our production phases we remain focused on our near-term target to achieve 40,000 barrels per day of net installed capacity by 2015. We expect 2011 and 2012 to be even more significant than the successful year just passed in terms of moving toward that goal. For the tremendous results organizationally, operationally and financially in 2010 I would like to congratulate and thank every member of our team. We are confident that our expanded head office and field teams will deliver results, as we advance on all fronts in 2011 with a sense of excitement.

Saleski Lead Operator in the field.

(signed) “Glen C. Schmidt”

2010 Annual Report10

Field Team We entered 2010 with a core group of four field staff, and built up the permanent and contract team to 28 skilled, qualified supervisors, operators and journeymen representing the key trades. These are great people who could work anywhere in the industry, and chose Laricina. We also strengthened our ties to the communities around our projects, hiring two young field operators from Wabasca, Alberta and added to our local office staff.

Leadership Entering 2011 our executive and senior management leadership team totalled 15 and combined with our head office and field team had grown to 80 skilled, committed people from an original founding group of eight in 2005. We advanced our leadership capabilities in 2010 by hiring four seasoned professionals from outside the Company and promoting four highly-qualified people from within. With an added focus on operational capacity and the necessary oversight, we created new positions and promoted George Brindle to Vice President of Facilities and Derek Keller to Vice President of Production. We also expanded our Board of Directors, and welcomed Jeff Donahue as a new director.

Advancing Our Depth in People

Building internal capacities is key to managing the Company’s transition to a commercial operator and continuing its advancement towards 40,000 barrels per day of net installed capacity by 2015. In 2010 we added over 40 new people including contract staff and through our cooperative student program. We are expanding our workforce to accommodate operating facilities and to continue to grow ideas and careers. The carbonates and Grand Rapids are seen as the next big stages for Alberta’s oil sands, and people want to be part of these opportunities.

Leadership team.

Saleski maintenance team.

Field operations.

The Saleski pilot construction workforce peaked at 350 – many of whom are now working on the Germain project. Our field operations team is expected to double by early 2012. Laricina’s phased expansion approach will contribute to construction efficiency by making successive use of increasingly seasoned crews and operating staff who have recent experience building the Saleski pilot. Laricina takes a building approach to working with members in the community as well, and we will continue to create capacity toward a sustainable workforce in Wabasca, Alberta.


Technical Team Laricina added 19 new geological, engineering and operating personnel in 2010. With construction at Saleski in full swing and at Germain about to begin, we had a particular focus on facility engineering. Next to our field team, the facility team experienced the greatest growth last year. Our support for young people at the academic stage, such as our cooperative/summer student program, strengthened our ability to place Laricina on the “career map” and attract qualified young professionals in a competitive industry.

Of the new hires in 2010 and early 2011, three are recent graduates that had come through our cooperative/summer program. We attract new graduates because we have invested in and built a relationship with them before they graduate. The Laricina “story” itself – having the first project in the next big oil sands play, the Grosmont carbonates – is helping to attract top-quality technical people. As we continue to advance on all fronts, we increase our attractiveness to an even broader pool of professional talent. Laricina is seen as an attractive career option, providing growth, opportunity and technical challenge to highly qualified people who have the capacity to think outside the box.

Reservoir engineering.

Facilities design.

Corporate and finance strategy.


Advancing Our Projects

As a pure-play in situ (drillable) oil sands developer, Laricina’s business objective is to create value by optimizing the economic returns of its portfolio through application of SAGD enhanced with innovative resource recovery strategies. Of our 10 project/prospect areas, five are in an advanced stage of assessment, with the Saleski pilot being operational and the Germain commercial demonstration project under construction. All of Laricina’s project/prospect areas are located in the greater Athabasca oil sands region of northeast Alberta.

Saleski and Germain are our first assets to be developed. The Saleski Grosmont carbonate pilot became operational with the commencement of steam injection just before year-end 2010. Also just before year-end construction commenced at the Germain Grand Rapids commercial demonstration project. With these milestones, Laricina has moved from the prospecting and exploration phases to oil sands operations.

Laricina began the long-lead process of oil sands development in 2005 by applying its understanding of reservoir fundamentals to identify lands with scale and attractive reservoir characteristics in prospective areas that lay close to physical infrastructure. Along with effective analyses and evaluations, identification of site-specific innovative processes and technologies, and geological vision, this careful and targeted land selection enabled Laricina to establish a portfolio of highly prospective oil sands leases with multi-billion-barrel resource potential. Laricina’s business model applies proven and field-tested recovery technologies centred on SAGD, while implementing process innovations to maximize value.

Laricina has a verifiable track record in advancing its development strategy, which comprises the following key principles:

of bitumen-bearing assets, currently totalling 10 properties;

A Stepwise Approach2010 >> 2011 >> 2012 >> 2013 >>

at Saleski pilot, completed facility construction, built field operations team, commenced steam injection

new equity capital to fund project activity through 2011

commercial demonstration project approval, completed front-end engineering and design work, signed contracts for the expanded operating and construction camps, initiated detailed engineering, commenced commercial demonstration project construction, contracted to construct a slant drilling rig that will be dedicated to horizontal drilling at Germain

Germain Phase 2 expansion

per-day commercial expansion at Saleski

exploration drilling and geophysical programs

in Q2, ramp-up production, establish key production

Grosmont

expansion covering next three phases to 155,000 barrels per day and launch front-end engineering and design

procurement/fabrication and field construction at Germain, install natural gas pipeline, drill six horizontal well-pairs by year-end

engineering and design for Saleski Phase 1

geological studies

development at Poplar Creek

at Germain, plan to drill remaining four horizontal well-pairs, receive electrical service, commence steam injection by year-end

Saleski

towards 1,800 barrels per

Saleski pilot

commercial project regulatory approval, start detailed engineering and module procurement/fabrication

for Germain Phase 2

Saleski Phase 1 expansion and commence steam injection by year-end

approval for 30,000-barrel-per-day expansion

at Germain, initiate SC-

fabrication for Germain Phase 2

applications for future phases

bitumen resources

Operations Review


physical infrastructure, as we have done at Saleski and Germain;

delineation, fi eld research and laboratory modelling and testing to quantify resource potential, as shown by our numerous technical studies, research partnerships, patent applications and process innovations;

applications, which have resulted in high-quality applications meeting regulatory requirements;

development, as described below;

demonstrating technical success and maintaining fi nancial discipline;

beginning with SC-SAGD being applied at Saleski and Germain;

technical teams;

and

Laricina divides asset development into manageable-sized pieces. The current phases at Saleski and Germain are the beginning. We plan to

execute in a controlled fashion, managing the operational, human resource and fi nancial requirements as we grow to our near-term objective of 40,000 barrels per day of net installed capacity by 2015.

Project segments will increase from approximately 10,000 barrels per day and grow up to 60,000 barrels per day or more as initial pilot and commercial demonstration phases prove design, execution and enhancements. Staggering project phases should facilitate execution effi ciencies as project teams move continuously through a development cycle. Overlying this is a stage-gate of projects, facilitating optimal practices and successive innovations as fi eld testing proves them out.

The proximity of the Saleski and Germain projects allows for the integration of roads, natural gas supply, power and pipelines given their location approximately 33 km apart and proximity to conventional oil production at Pelican Lake. Oil sales can be managed to match production growth in two stages: early trucking of production followed by integration via pipeline to regional crude oil terminals.

Beyond Saleski and Germain, Laricina’s large portfolio of development opportunities will be executed using the same staging philosophy. This includes projects at Burnt Lakes, Poplar Creek and Conn Creek, as well as additional opportunities from Laricina’s inventory of prospects on less-delineated lands.

Targeted bitumen formations showing development horizons. (Based on best estimate contingent and prospective resources and proved plus probable reserves.)

GROSMONT

WINTERBURN

MCMURRAY

WABAMUNWABISKAW-MCMURRAYCLEARWATERGRAND RAPIDSCOLORADO

725 mmbblsrecoverable resource

McMurray and Wabiskaw-McMurray Formations (sands)

1,340 mmbblsrecoverable resourceGrand Rapids Formation(sands)

2,567mmbblsrecoverable resource

Grosmont and Winterburn Formations (carbonates)


Net Present Value Before Tax, 10% Discount 2P + Best Estimate Contingent and Prospective Resources ($ billions)

Advancing Our Resource Value

$11.9$0

6229

4.61.2Net Recoverable Resources(mmbbls)

Recoverable Resources Per Hectare(mmbbls)

2006

2006

2006

2010

2010

2010

Operations Review

See Project Summary tables on opposite page.


Average Area in Recoverable Anticipated Gross Peak Working Hectares Resources (2) Start-up (3) Production (3)

Project Area Formation Interest (gross) (gross, mmbbls) (year) (bbls/d)

Saleski Grosmont 60% 17,152 2,721 2010 271,800

Germain Grand Rapids 96% 16,128 1,347 2012 202,700

Germain Winterburn* 94% 18,176 438 2021 40,000

Burnt Lakes Grosmont 100% 11,499 523 2015 60,000

Conn Creek McMurray 100% 9,728 260 2015 30,000

Poplar Creek McMurray 50% 2,336 126 2014 25,000

Other Properties McMurray/Grand Rapids 93% 25,088 483 undefined undefined

* In addition to the Germain lands of 16,128 hectares where Laricina holds Grand Rapids and Winterburn rights, Laricina holds an additional 2,048 hectares of Winterburn rights only.

Contingent and Prospective Reserves Exploitable OBIP (mmbbls) (4) Resources (mmbbls) (5) (mmbbls) (6)

Resource Summary 2P + Best 3P + High SC-SAGD (Best) Best High SC-SAGD (Best) 2P 3P

Carbonates – Grosmont/Winterburn 7,247 9,358 7,247 2,567 4,897 3,081 – –

Sands – Grand Rapids 2,453 2,524 2,453 1,304 1,559 1,538 36 43

Sands – McMurray/Wabiskaw 1,421 2,355 1,421 725 1,333 725 – –

Total 11,121 14,237 11,121 4,596 7,789 5,344 36 43

% of Total Net Present Value, Before Tax, 10% Discount (7) $ millions mmbbls Resources

2P + Best estimate contingent and prospective resources 11,863 4,183 90%

3P + High estimate contingent and prospective resources 22,096 6,952 89%

SC-SAGD Best estimate technology sensitivity (8) 14,884 4,895 92%

Project Summary (1)

Growth in Value and Resources (1) (2)

(1) Based on the report of GLJ Petroleum Consultants Ltd. (GLJ) regarding Laricina’s properties effective December 31, 2010 (GLJ Report) using GLJ’s commodity price forecast as at January 1, 2011. All values shown are net to Laricina’s working interest unless otherwise indicated. Recoverable resources and production estimates for Conn Creek, Poplar Creek, and Saleski are based on SAGD technology; Germain Winterburn is based on CSS technology; and Burnt Lakes development is based on a combination of SAGD and CSS technology; Germain Grand Rapids Phase 1 is based on SAGD technology and subsequent phases are based on GLJ’s risked SC-SAGD view.

(2) Recoverable resources includes the unrisked arithmetic sum of best estimate contingent and prospective resources and proved plus probable reserves as defined in the GLJ Report.

(3) Anticipated start-up year and peak production rates are subject to certain development milestones, regulatory approvals, available funding and project priority, in addition to other unknown uncertainties. No assurance can be made the actual start-up year or peak production rates will materialize as represented. Peak production rates are for individual projects and commence at staggered intervals and therefore have not been aggregated.

(4) Exploitable OBIP refers to original-bitumen-in-place that is targeted for development using thermal recovery technologies. The best and high estimates include contingent and prospective resources.

(5) Contingent resource values have been risked for chance of development while prospective resources have been risked for chance of discovery but not for chance of development. There is no certainty that any portion of the prospective resources will be discovered or, if discovered, if it will be commercially viable to produce any portion of the prospective resources.

(6) 2P means proved plus probable reserves and 3P means proved plus probable plus possible reserves.

(7) The 2P plus best and 3P plus high estimates net economic forecast prepared on: Conn Creek, Poplar Creek, and Saleski are based on SAGD technology; Germain Grand Rapids Phase 1 are based on SAGD technology and subsequent phases are based on GLJ’s risked SC SAGD view; Germain Winterburn are based on CSS technology; and Burnt Lakes development are based on a combination of SAGD and CSS technology. The SC-SAGD best estimate technology sensitivity (Laricina technology sensitivity) net economic forecasts were prepared on Saleski-Grosmont and Germain-Grand Rapids based on SC-SAGD technology and remaining properties based on SAGD/CSS technology. Excludes value for undeveloped land, which represents approximately 32 percent of Laricina’s net land base.

(8) SC-SAGD best estimate technology sensitivity was based on Laricina’s risked view of resources.

(9) Delineation wells include all exploration and development wells that were either cored or logged through the bitumen zones of interest.

Recoverable Resources Per Hectare (mmbbls)

Recoverable Resources By Formation (mmbbls)

(9)

Laricina Wells Legacy WellsMcMurray Grand Rapids Carbonates


Operations Review

Advancing Our Geologic Understanding

like coral and plankton. They include some of the world’s largest conventional oil fields, as well as major historical light oil fields in Alberta, among them the famous Leduc discovery.

High-Quality Sandstone and Carbonate Prospects

Laricina’s asset portfolio provides resource development opportunities in four major sand and carbonate formations in west Athabasca. The McMurray Formation is found at Conn Creek and Poplar Creek and Laricina’s other growth properties at Thornbury, Thornbury West, House River and Boiler Rapids. The McMurray is the industry’s “original” oil sand formation, holding an estimated 959* billion barrels-in-place – more than half the total bitumen resource. The McMurray also dominates in situ development. The younger Cretaceous Grand Rapids sands, multiple thick sandstones lying in the Upper Mannville Group and holding 54.5* billion barrels of bitumen-in-place, are now gaining increasing industry attention, and are the focus at Laricina’s Germain asset.

Overview: Sands and Carbonates

Together, sands and carbonates represent a 1.8-trillion-barrel oil resource.

Sands

bitumen-in-place, 10 percent surface-minable, 90 percent in situ recovery

McMurray, Grand Rapids

high-permeability reservoirs

industry activity and investment to date

Carbonates

bitumen-in-place, of which Laricina estimates 100 billion barrels are recoverable

Winterburn (471* billion barrels bitumen-in-place)

in situ recovery

permeability but can be correlated over regional distances

bitumen recovery from Grosmont carbonates

* All resource estimates on this page are from the Energy Resources Conservation Board (ERCB), except where indicated as Laricina estimates.

In pursuing bitumen resources the energy industry historically focused on clastic (sand) deposits, with successful commercial development beginning in the late 1960s, initially through surface mining of shallow McMurray Formation sands followed by in situ recovery of the deeper-lying McMurray deposits in the late 1980s. With the introduction of SAGD technology, the thickest portions (40 metres plus) of the McMurray bitumen deposit were the initial targets for development.

As SAGD was proven effective there, operators began applying it to thinner McMurray bitumen resources (15–25 metres thick). More recently, operators like Laricina have applied to use SAGD in other clastic resources such as the younger and shallower Grand Rapids Formation. These Grand Rapids targets are generally 10–25 metres thick and are broadly deposited with predictable sand distribution.

Geologically, however, a whole other world is available: the carbonates. Carbonates are sedimentary rock such as limestone formed from decayed organisms

Grosmont “A” Subcrop Edge

T81

T85

T90

T95

T100

R20R23R1W5R3

Ath

abas

ca R

iver

T100

T95

T90

T85

T80

T75

T70

R15R1W3 R20W4 R10 R5

WABASCA —DESMARAIS

FORT MCMURRAY


Carbonates:Grosmont and Winterburn Bitumen Trend

Grosmont C and D net pay (>10m and 18% porosity)Grosmont C and D net pay (>10m and 12% porosity)Winterburn net pay (>10m and 12% porosity)Laricina property

ALBERTA

Edmonton

Calgary

Sands:McMurray and Upper Grand Rapids Bitumen Trends With Basal Water

Selected Project Operators

McMurray bitumen trend >10mMcMurray basal water >5mMcMurray bitumen trend >10m and basal water >5mUpper Grand Rapids bitumen trend >10mUpper Grand Rapids basal water >5mUpper Grand Rapids bitumen trend >10m and basal water >5mLaricina propertySurface mineable area boundary

Suncor Energy Inc.Nexen Inc.ConocoPhillips CompanyConnacher Oil and Gas Ltd.MEG Energy Corp.Cenovus Energy Inc.Devon Energy Corp.

Athabasca Oil Sands Corp.Suncor Energy Inc.Royal Dutch Shell PlcHusky Energy Inc.Cenovus Energy Inc.

Selected Lease Owners

Sands

Carbonates


The upper Grand Rapids sand in west Athabasca is extensively bitumen-saturated, but overlies water-saturated sands at the bitumen margins (see map on previous page). Bitumen over water is not unique as many of the existing McMurray SAGD operations occur where McMurray bitumen is associated with basal water. Like other operators, Laricina considers basal water associated with bitumen pay to be manageable when utilizing proper SAGD operating strategies.

Of Canada’s estimated “oil sands” resource of 1.8 trillion* barrels-in-place, 30 percent is held in carbonates. Alberta’s Grosmont and Winterburn carbonates hold a combined estimated 471* billion barrels of bitumen-in-place. The multiple-zone Grosmont Formation (see graphic, page 23) is the primary prospective carbonate at Saleski and Burnt Lakes. The targeted development zones at Saleski are the Grosmont C and D, averaging a combined 40 metres-plus in thickness, and at Burnt Lakes the Grosmont D, averaging 20 metres in thickness. At Germain Laricina plans to develop the Blueridge and Graminia carbonate units of the Winterburn Formation in addition to the primary Grand Rapids sandstone target (see graphic on page 13).

In exploring the carbonates for suitable development areas, Laricina assessed numerous factors including pay thickness and porosity and permeability development (see discussion on page 21). The Company sought – and believes it has found – geology that not only holds vast bitumen-in-place but will allow much of the bitumen to flow economically to the wellbore. In Laricina’s estimation, Saleski and Germain hold some of the Alberta oil sands region’s most prospective carbonate geology.

*According to the ERCB.

Laricina’s Saleski project is the global energy industry’s first-ever application of SAGD technology to a bitumen carbonate reservoir – and also the first seeking to prove the commerciality of extracting bitumen from carbonates. The Company has devoted years to understanding the extent and mineralogical nature of the carbonate geology underlying Laricina’s properties and, equally important, how the in-place bitumen resource will respond to extraction processes applied to the carbonates.

Advancing Company Knowledge

In 2010 Laricina continued to advance its understanding of the carbonates through a number of laboratory experiments including Grosmont relative permeability tests, wettability tests, and steaming of core plugs and full-diameter core. The Company subjected new core and well data to a sophisticated array of tests, and performed further mineralogical tests of core samples and physical tests of bitumen samples. These analyses and observations were designed to sharpen the picture and advance Laricina’s understanding on both the large scale (field variations) and small scale (within the pore space).

Operations Review

Advancing Our Geologic Understanding


bitumen resource in the Saleski lease is independently estimated at 2.7 billion barrels gross (see page 15).

Reservoir quality is defined by the amount and types of porosity and permeability within the rock. Porosity is the amount of space within the rock that can contain fluid, and is expressed as a percentage of the total volume. The Grosmont’s porosity at Saleski ranges from 12 percent to 40 percent and averages approximately 23 percent, an exceptionally high value in a carbonate reservoir. Permeability indicates the ability of fluid to move through a reservoir – very roughly, analogous to how quickly a soaked sponge might release water when squeezed – and is critical to all oil and natural gas production. The Grosmont’s permeability at Saleski ranges from 2 Darcy to 20-plus Darcy, the industry’s standard unit of permeability. These values are superior to clastic oil sands.

Understanding the Grosmont

Operations Review

Advancing Saleski

The Grosmont carbonate reservoir at Saleski fulfils the key criteria of broad areal extent, substantial pay thickness and high bitumen saturation needed to create a large oil-in-place bitumen resource. Laricina’s thorough resource delineation, testing and modelling over the past five years create confidence that this carbonate reservoir also has the geological characteristics needed for economic commercial bitumen extraction using SAGD. This is currently being tested in the Saleski pilot, described in detail beginning on page 23.

The Upper Devonian Grosmont carbonate is a remarkable bitumen-bearing reservoir of limestone and dolomite. Lying at 325 metres average depth and an average of 120 metres thick, the Grosmont has four separate types of porosity – matrix, vugs, fracture and breccia – and associated permeability types enhanced by karst (see description on page 21). Recoverable


Operations Review

Grosmont Carbonate

Advancing Saleski

The Grosmont’s high porosity and permeability result from its depositional history. Northeast Alberta was covered by a shallow sea 370 million years ago. Surrounding lands were low-lying with little topography, tending not to shed sandy (clastic) sediments into the sea. This allowed for precipitation of calcium carbonate (limestone) from decaying micro-organisms, such as occurs in the Caribbean Sea today. Settling to the bottom, these limestone grains built seaward as broad platforms. Slow settlement and sea level rise created the space to build a series of broad platform carbonate rocks: the Grosmont A, B, C and D units, in that order.

As sea level rose further over time, the Grosmont was buried by shale followed by other carbonates. Fluids moving through the limestone converted it to dolomite, increasing the rock’s porosity because dolomite crystals are smaller than limestone crystals.

Much later, the Grosmont and surrounding strata were tilted and uplifted, then eroded and exposed over a large region. During this exposure, the Grosmont dolomites were leached by rainwater entering along fractures. The water’s movement “corroded” the dolomite grains, widening fractures and enlarging pores. This process substantially increased the Grosmont’s porosity and permeability, especially portions closest to the erosion surface. This leaching is called karst.

About 120 million years ago, the Grosmont was buried again, this time by Cretaceous clastics. Sometime later, light crude oil migrated into the pore system and was trapped by the overlying Cretaceous shales. The oil evolved into the bitumen that today is Laricina’s target for production.

Bitumen Production in the Carbonates

Several cyclic steam stimulation (CSS) and vertical well pilot projects were attempted in the Grosmont in the 1970s and 1980s. The Buffalo Creek pilot, operated by the Union Oil Company from 1980–86, used a CSS or “huff-and-puff” injection scheme. The best well,

at 10A-5-88-19W4, recovered about 100,000 barrels of oil over 10 cycles, with a cumulative steam-oil ratio of about 6:1, which was better or comparable to contemporary McMurray tests. Laricina’s Saleski pilot is the industry’s first SAGD project intended to demonstrate both technically feasible and economically viable bitumen production from the carbonates.

Uplift and exposure allowed fresh water leaching of the carbonate grains, resulting in increased porosity.

The Grosmont Formation originated in the late Devonian as a shallow-water, marine deposit.

An electrical image log of the formation provides information of the rock structure and sedimentary features. It allows visualization of reservoir characteristics such as fractures, breccia zones and vuggy porosity.

Magnified Core Thin Section: Lower Grosmont D – dolomite grainstone with rims of dolomite cement. Blue indicates porosity. Leaching is evident within and between the grains.

Core photos of the Grosmont D breccia zone showing clasts within highly porous bitumen-saturated matrix.


Understanding Porosity and Permeability

The Grosmont’s porosity can be classified into two main types: micro porosity (pores less than one millimetre in diameter) and macro porosity (pores greater than one millimetre plus fractures).

Micro Porosity Consists Of:

(between carbonate grains), intra-particle and inter-crystalline. Matrix porosity is common throughout the Grosmont C and D units; and

greater than one millimetre in size in a crumbly and disaggregated matrix of smaller dolomite grains and crystals. Solution breccias are common in the Upper and Lower Grosmont D and Upper Grosmont C units.

Macro Porosity Consists Of:

physical or chemical process, typically less than three centimetres in diameter, and are most common in the Grosmont C vuggy unit and the amphipora-rich beds of the middle Grosmont D unit; and

depths and was a by-product of compaction and collapsing of cavities created by karst dissolution of the Grosmont reservoirs. Fracturing contributes to porosity as well as permeability over the entire Grosmont C and D units.

Permeability:

The Grosmont C and D units at Saleski have excellent permeability due to the significant contribution of vugular and fracture porosity to the reservoir development. Fracturing is particularly important in that it improves vertical permeability and connects reservoir units. Fractures enable injecting steam into the reservoir at well below fracture pressure, which is not possible in fully saturated, clastic oil sands.

25

25

30

35 35

40

40

4545

R20 R19

Pilot Plantand

Pilot Wells

Upper Grosmont D

Gamma Ray Density Depth (m) Resistivity

Middle Grosmont D

Lower Grosmont D

Upper Grosmont CMarl

Middle Grosmont C

Lower Grosmont C

Upper Ireton

Grosmont B

325

350

375

400


Saleski Key Project Parameters

Saleski Grosmont Bitumen –

Argillaceous dolomite

Vuggy dolomite

Bitumen interval

Dololaminate

Mixed lithology

Operations Review

Advancing Saleski

Typical well log characterizing the various lithofacies of the Upper Ireton, Grosmont C and D zones and net bitumen pay map at Saleski.

Pilot

1,800-barrel-per-day capacity carbonate pilot, operational December 2010, three well-pairs, approximately $200 million cumulative gross capital cost including infrastructure

Lease boundary

Contour (5m interval)

Formation

Grosmont Carbonate,

Estimated Recoverable Resources

1.6 billion barrels net, using conventional SAGD, based on 39 percent recovery factor from 4.1 billion barrels of original-bitumen-in-place in the Grosmont C and D

ProductionPotential

271,800 barrels per day gross using base SAGD technology

2010-2011 winter drilling program

Typical Well Log

Previous wells

Injector Wells

Grosmont D

Grosmont C

ProducerWells

Saleski pilot well trajectories in the Grosmont C and D zones.


Saleski is a stand-alone project with all production, steam generation, water treatment and storage, and power generation/supply facilities located on-site (natural gas is externally supplied). In 2007-2008 Laricina built a 21-km high-grade road from the nearby Al-Pac Chipewyan Lake forestry haul road to provide year-round access to the Germain project. With Saleski proceeding ahead of Germain, Laricina built a 32-km high-grade, all-weather gravel road with two bridges from the Germain intersection to Saleski, ensuring year-round movement of heavy loads. Both road-building phases employed locally-based contractors and labour.

Sourcing of long-lead components began in 2007 and fi eld construction of the pilot plant began in December 2009. Detailed engineering lasted 10 months and was concurrent with module fabrication. Field construction employed a peak workforce of 350 and was substantially completed prior to December 23, 2010 start-up, lasting 91/2 months including production systems. Key infrastructure includes a 100 millimetre diameter, 2.9-km natural gas pipeline, in service November 2010, which will also serve the planned Phase 1 commercial plant.

A historic moment in Laricina’s advancement occurred on December 23, 2010, when steam injection began in the fi rst injection well at the Saleski pilot plant. This was the culmination of a four-year process of resource delineation, testing, regulatory applications, plant design and engineering, and lastly pilot project construction.

Saleski is an innovative project in the oil sands, being built to improve on the proven extraction method of SAGD by adding solvents to steam. The SC-SAGD process aims to improve mobilization of the bitumen in the carbonate reservoir and move it effi ciently to the producing horizontal well. The goal of SC-SAGD is to reduce the steam needed to extract bitumen, creating a host of operational, economic and environmental benefi ts. SC-SAGD is explained more fully under “Advancing Germain” on page 33. The key objective of the Saleski pilot is to demonstrate SAGD followed by SC-SAGD recovery from the Grosmont carbonate reservoir.

Saleski pilot project.

Saleski pilot central processing facilities and well pad.


Saleski Pilot Plant

Operations Review

Advancing Saleski

The plant design includes room for four injector/producer well pairs, of which three pairs have been drilled and initially two pairs are tied-in to the plant. The pilot’s primary water source and disposal wells are 10 km west of the plant, connected by pipeline. Adjoining the well pad are an on-site disposal well and two source water wells. The plant is designed with a capacity of 1,800 barrels per day at a steam-oil ratio of 1.6:1 under SC-SAGD.

Water for steam generation is drawn from deep underground via five remote and two on-site wells from the Grand Rapids Formation, and is filtered and softened before entering the steam generating system. Saturated steam is separated and dry steam is sent to control skids at the injection wells.

The produced emulsion is separated in the conventional free water knockout and treater, and produced water is disposed deep underground in the Cooking Lake Formation. Source water is non-potable, and both the source and disposal formations are geologically sealed and not in communication with either groundwater or surface water, creating a safe and environmentally secure process.

The planned addition of solvent to the SAGD process required only minor changes to the Saleski production train, adding evaporation and solvent recycling equipment similar to that used in the gas processing sector. The process gathers then recovers, recycles and reuses the injected solvents, which is critical to the overall recovery economics, given the high value of hydrocarbon-based solvents.


Next Steps: Pilot Ramp-Up

Steam injection at Saleski into the first two of three well-pairs has proceeded well and heating is progressing as expected. This pre-heating step will help establish the steam chamber along the well’s entire length. Once the Company is satisfied that thermal communication between the wells has occurred, it will initiate bitumen production. The transition to production on the first well-pair is expected in the second quarter of 2011.

Following this:

and SAGD performance will be established with the ramp-up in production to peak well rates over the next 12–18 months;

and steam injection rates will be reduced to the operating well pairs;

well pair; and

follow.

Diluent will be trucked in for treating, transport and reservoir needs, and produced blended bitumen will be trucked out to regional crude oil terminals where full blending to pipeline specifications will be done.

The Saleski pilot’s crucial role is to evaluate SAGD and SC-SAGD bitumen extraction in the carbonates. Specifically, it will establish key operating parameters: the steam conformance along the wellbore, time to convert well pairs to production and first oil, time to reach peak production under SAGD and SC-SAGD, production rates, steam-oil ratio, solvent and steam injection rates, solvent recovery rates, and others. Pilot operation will also gather key production-related information, including solids production and handling, produced bitumen properties, produced natural gas properties and produced water properties.

The plant design includes an array of observation and measurement tools to maximize the amount and quality of information gathered. Once understood, these parameters will guide the design and help to optimize the cost-effectiveness of the larger commercial phases.

Laricina’s key targets for each well pair include first oil within three to four months of first steam, peak production of greater than 600 barrels per day per producing well, and a long term steam-oil ratio below 3:1 under pure SAGD. These targets are comparable to a typical McMurray SAGD project. Laricina plans to begin adding solvents approximately 12 months after start of production, establishing key parameters such as solvent injection and production rates and the resulting steam reduction per barrel of oil produced.

Planning and foundational work for Phase 1 commercial development began well before the Saleski pilot became operational. Following approval of the application to add solvents to the base SAGD process, Laricina applied to the ERCB and Alberta Environment in late December 2010 to amend the approved pilot project by adding the Phase 1 commercial project.

Phase 1 will add production of 10,700 barrels per day with a target steam-oil ratio of 2:1 under SC-SAGD. Located just southwest of the pilot, Phase 1 will use the existing road, fuel gas pipeline, water source and disposal wells and associated pipelines, and construction and operations camps to maximize operational synergies. The fi rst pad for Phase 1 will consist of 20 well pairs (10 in the Grosmont D and 10 in the Grosmont C) of which 16 will be initially started to establish 10,700 barrel-per-day production.

Laricina plans to initiate Phase 1 construction in the third quarter of 2012 subject to regulatory approval and available fi nancing. Steam injection is scheduled to commence in late 2013, with full Phase 1 production rates achieved 12–18 months after start-up. Laricina intends to connect Saleski to the Alberta power grid in 2013 via a high-voltage power line serving a proposed new on-site electrical substation. Production will be trucked initially until a sales pipeline is constructed in 2014 or 2015. Laricina’s preliminary estimate for Phase 1 plant construction and drilling is $400–$450 million gross subject to revision based on a more detailed cost assessment of major components and labour following the completion of front-end engineering and design.

Passive Heat-Assisted Recovery Method

Information from the pilot will also allow Laricina to plan future phases utilizing its PHARM concept. PHARM takes advantage of the heat emanating from one steam chamber to recover bitumen from an adjacent zone using only a producing or injecting well, thereby utilizing the heat lost from one chamber to develop the other.

PHARM process schematic in the Grosmont carbonates.


Operations Review

Advancing Saleski

D Zone

C Zone


2013>>2011>>2010>>

Drilled horizontal well pairs, completed facility construction, built fi eld operations team, and commenced steam injection at Saleski pilot, applied for 10,700-barrel-per-day commercial expansion at Saleski

Launch front-end engineering and design for Saleski Phase 1, fi rst oil expected at pilot in Q2, ramp up production, establish key production parameters for SAGD in the Grosmont, initiate SC-SAGD

Ramp-up towards peak production of 1,800 barrels per day through SC-SAGD at Saleski pilot, receive Saleski Phase 1 commercial project regulatory approval and start module procurement/fabrication

Start fi eld construction of Saleski Phase 1 expansion and commence steam injection by year-end

Ramp up SAGD production at Phase 1, advance regulatory applications for future phases

2012>> 2014>>

The Upside of Saleski

17,152Hectares

1.6 billion

Barrels net recoverable resource

>270,000 Barrels per daygross productionpotential

60% Workinginterest

Drilling at Saleski


Understanding the Grand Rapids

The lands west of the Athabasca River contain significant bitumen resource suitable for SAGD development. To date, most in situ projects have been in the McMurray Formation channel sands to the river’s east side. On the west side, the main sandstone target is the Grand Rapids Formation, part of the Upper Mannville Group (see map on page 17). Its multiple thick sandstones host 54.5 billion barrels of bitumen-in-place, according to ERCB estimates. The Upper Grand Rapids is the largest of the three deposits identified (Upper, Middle and Lower), with an estimated 33.8* billion barrels of bitumen-in-place.

The Grand Rapids is the primary target at Laricina’s Germain project, which covers nearly 18,200 hectares at approximate 96 percent average working. The Upper Grand Rapids bitumen target underlies nearly the entire lease at an average depth of 225 metres. Its presence and thickness are highly predictable.

*According to the ERCB.

Operations Review

Advancing Germain

Its origins as a shoreface deposit provide remarkable reservoir uniformity, which is important to efficient SAGD development and is not always the case in the less continuous, more heterogeneous McMurray channel sands.

Over the past five years Laricina has laid the groundwork for successful SAGD development of the Grand Rapids at Germain. Laricina has evaluated 168 delineation wells drilled into the Grand Rapids (plus 20 into the Winterburn carbonates), as well as 99 core samples. The Company has 65.7 km of 2-D seismic and 11.2 square km of 3-D seismic covering the project area (see wireline logs and core photos of a type well on the opposite page). Laricina’s reservoir evaluation has demonstrated that the Upper Grand Rapids sand is homogeneous, with very limited and rare muddy interbeds.

The Grand Rapids’ main reservoir parameters are similar to the McMurray’s, with bitumen thickness of 10-25 metres, average porosity of 34 percent, bitumen saturation of 65–75 percent and permeability of 1–5 Darcys. These characteristics fulfil the key criteria of large resource-in-place as well as the reservoir’s physical amenability to flowing bitumen. Overall the Grand Rapids represents a “conventional” SAGD reservoir environment, similar to the well-understood McMurray sands.


Germain facies interpretation from 3-D seismic. Integrated log, core, facies and 3-D seismic provide a 3-D reservoir characterization illustrating the lateral and vertical homogeneity within the Upper Grand Rapids reservoir.

The Grand Rapids Formation: a continuous and uniform shoreface sand.

Upper Grand Rapids: A Continuous and Uniform Interval

Grand Rapids Core Photograph

Bitumen sand Shaley sand Gas sand

Wet sand Shale Cemented

The Grand Rapids Formation

Grand Rapids core sample: clean, consistent bitumen-saturated sands. (White areas are empty core sleeves.)

Germain Key Project Parameters

Phase 1 Project

5,000-barrel-per-day commercial demonstration project, with 10 well-pairs using SAGD and SC-SAGD, $330 million estimated gross capital cost

Lease boundary (Grand Rapids oil sands rights)Contour (5m interval)

Formation

Grand Rapids – Lower Cretaceous Mannville Group sand, 225 metres average depth, net pay thickness 10–25 metres, bitumen saturation averaging 75 percent

Winterburn – Devonian carbonate, 420 metres average depth, net pay thickness 15–30 metres, bitumen saturation averaging 80 percent

Estimated Recoverable Resources

Grand Rapids – 1.3 billion barrels net using SC-SAGD, based on 55 percent recovery factor from 2.4 billion barrels of original-bitumen-in-place

Winterburn – 412 million barrels net using CSS, based on 30 percent recovery factor from 1.4 billion barrels of original-bitumen-in-place

Production Potential

Grand Rapids – 202,700 barrels per day gross (phases 1–5)

Winterburn – 40,000 barrels per day gross (Phase 6)

Commercial demonstration area

2010-2011 winter drilling program


Germain – Grand Rapids Net Pay

Typical Well Log

200

225

250

Gamma Ray Density Depth (m) Resistivity

Upper Grand Rapids

Middle Grand Rapids

Lower Grand Rapids

Sand

Porosity >27%

Upper transition zone

Bitumen

Basal water

Typical well log characterizing the highly porous clean sand of the Upper Grand Rapids and net bitumen pay map at Germain.

Operations Review

Advancing Germain

Previous wells


Laricina is currently constructing the Germain commercial demonstration project (CDP), Phase 1 of its development plan for Germain. It has a planned capacity of 5,000 barrels per day using SC-SAGD and a planned cost of approximately $330 million. Construction commenced just before year-end 2010 and will continue throughout 2011 and 2012. During the most recent winter season Laricina drilled another 29 delineation, core, water source, water disposal, water monitoring and SAGD observation wells. Current 3D seismic provides full coverage over the CDP. Laricina plans to initiate steam injection by year-end 2012.

The project’s natural gas supply line was installed in the first quarter of 2011, while the metering station at the tie-in point to the gas transmission system is to be installed in the first quarter of 2012. The natural gas line has been sized to accommodate both the CDP and the Phase 2 expansion of 30,000 barrels per day. Approval for electrical infrastructure is expected in the second quarter of 2011, with construction expected to be completed in the second quarter of 2012.

The Germain CDP includes an initial 10 well pairs to be drilled from a common pad adjacent to a central processing facility containing water treatment, steam generation, production handling and waste disposal facilities. Other than being larger than the Saleski facility completed in 2010, the Germain CDP is largely similar but will incorporate produced water recycling. As with Saleski, diluent required for treatment, blending and bitumen recovery will be trucked in and diluted bitumen production will be trucked out to regional crude oil terminals. Truck-based transport and marketing will continue until Germain is pipeline-connected in 2014 or 2015.

Also as with Saleski, the initial Germain wells will be important in establishing essential production parameters defined by the particular reservoir. Laricina expects the Grand Rapids reservoir will behave similarly to the established McMurray Formation. Two other Grand Rapids projects now underway or in testing will also provide useful information. A major oil sands operator’s planned 180,000-barrel-per-day Grand Rapids project is just south of Germain and initial well-testing is underway in a single well pilot. Another Grand Rapids project at Wolf Lake in Alberta’s Cold Lake oil sands region showed first oil in 90 days, peak per-well rates of 600 barrels per day and a steam-oil ratio of 3:1.

Laricina in 2010 contracted construction of a super-single drilling rig with slant and vertical drilling capability that will be dedicated to drilling the horizontal wells at Germain beginning in July 2011. Six well pairs will be drilled by the fourth quarter of 2011 and the remainder are planned in 2012. Following steam injection commencing near year-end 2012, first oil is expected three to four months later, and the CDP will ramp-up toward full production 12-18 months after start-up. Initial operation will be SAGD for approximately six to 12 months, followed by solvent injection to begin SC-SAGD (see page 33). The CDP is expected to recover approximately 50 million barrels of bitumen over approximately 35 years, based on an expected 55 percent recovery factor (ratio of bitumen-in-place). The CDP will include an ultimate planned total of 40 well-pairs to maintain rated productivity over its producing life.

0 200 400

METRES

800

INJECTOR WELL

PRODUCER WELL

PIPE RACK

ROAD

BITUMEN TREATINGPROPANE BULLETS

SOLVENT INJECTION

WATER TREATMENT

TRUCK TERMINAL

OIL REMOVAL

DILBIT EXCHANGE

STEAM GENERATION

SLOP

SKIM

DE-DILLING

STORAGE TANKS

FLARE

OFFICE/CONTROL BUILDING

MAINTENANCEWAREHOUSE

DILUENT

DILB

ITDI

LBIT

DILB

IT

Germain

Saleski

T87

R25 R24 R23 R22 R21 R20 R19 R18 R17

T86

T85

Ath

abas

ca R

iver

Wabasca-Desmarais

T84

T83

T82

T81

T80


Germain Plot Plan

Observation well

Water source and disposal well

Plant site and well pad

Access road

Germain CDP central processing facilities and initial well pad.

Layout of the Germain CDP development plan with initial well pad and corresponding infrastructure and facilities.

Germain lease

Saleski lease

Highway

Road

Operations Review

Advancing Germain


By combining solvent with steam, Laricina expects to reduce the steam-oil ratio, improve overall recovery, improve bitumen fl ow rates, and reduce water use and carbon emissions intensity. Laboratory bench tests and simulations have achieved steam-oil ratio reductions of 25–40 percent (from 3:1 to as little as 1.8:1), similar to reductions demonstrated in the fi eld by other operators using competitive enhanced SAGD approaches. SC-SAGD is expected to deliver simultaneous economic and environmental benefi ts. At least two other large oil sands producers have selected a version of solvents and SAGD for their developments.

Basal Water

The Company’s other major recovery innovation at Germain is to place producing wells within the thin layer of reservoir water that lies just below the bitumen pay zone. The conventional approach is to place the producing well above any “basal water”. Laricina’s well placement at the base of porosity is supported by studies and testing that suggest placing the producing well in the basal water will maximize well productivity and resource recovery.

After a start-up phase, the steam and bitumen begin to displace the basal water. Because this occurs, the traditional well placement above the basal water eventually leaves large volumes of bitumen resource “stranded” below the level of the producing well, even though the well was initially placed at the bottom of the bitumen pay zone. Under Laricina’s basal water development methodology, the well recovers bitumen that has displaced the basal water. Further, the basal water can be exploited to increase the volume of reservoir that is heated by steam, mobilizing more bitumen over the long term.

SC-SAGD is a Laricina-developed improvement to SAGD technology, centred on injecting alternating phases of solvents and steam into the reservoir. SC-SAGD is the basic development model for the Grand Rapids sands. The solvents being contemplated are combinations of heavier hydrocarbons such as condensate (C5+, so named for the number of carbon atoms in the molecule), followed by a lighter hydrocarbon such as propane (C3). Developing SC-SAGD involved genetic algorithms to identify the optimal process combination, and is described further under “Advancing our Innovations” on page 37.

Under SC-SAGD, the solvent moves ahead of the steam, pre-treating the bitumen and initiating gravity drainage. The advancing steam-front then empties the progressively larger underground chamber, while much of the solvent re-circulates through convection and is eventually recovered, an important consideration given the value of hydrocarbon solvents. The steam injection rate will decline as solvent is injected.

Recovery Process

Grand Rapids Formation

Producer Well

Injector Well

SAGD SC-SAGD


Next Steps: Germain Project Expansion

Laricina’s Germain project has a total of six planned phases over a minimum 30-year planned operating life, including the CDP as Phase 1, which occupies only three percent of the Germain lease. In the second half of 2011 Laricina intends to file an application for the initial Germain project expansion covering phases 2–4, increasing combined production capacity to 155,000 barrels per day. Phase 2 will consist of a 30,000-barrel-per-day facility with some integration to the CDP. Phases 3 and 4 are each 60,000-barrel-per-day facilities. Future phases 5 and 6 are in the conceptual planning stage and include the Winterburn development plan that will expand production to over 240,000 gross barrels per day.

The initial well pads for phases 2–4 will accommodate ten well-pairs, with 80-metre spacing between the pairs in the reservoir and 800 metres of lateral reach. All pads will be designed for SAGD and SC-SAGD.

Laricina is conducting the required comprehensive EIA to assess the environmental and socio-economic impacts of the proposed expansion. The EIA will document baseline conditions in the area, assess local and regional impacts, examine expansion alternatives, evaluate cumulative effects and provide monitoring and management plans.

Pending regulatory approval, initial construction of Phase 2 will commence in 2013 with the drilling of 50 initial well-pairs and plant earthworks. Operations are to commence in late 2014, with production ramping toward 30,000 barrels per day over a planned 12-18 months. Following peak production in 2015-2016, a further 10 well-pairs per year will be drilled to maintain Phase 2 production over the Phase 2 life-cycle. Phases 3 and 4 will need an initial 100 well-pairs per phase, to bring on additional production of 60,000 barrels per day per phase. Construction is expected to commence in 2016 for Phase 3 and 2018 for Phase 4, with operations commencing in 2018 and 2021, respectively.

Operations Review

Advancing Germain

The Germain project will have a significant positive economic impact on the community, the province and Canada. Laricina’s full life-cycle capital investment in the Germain project will exceed $10.8 billion. Phase 2 drilling and construction will employ a peak workforce of 300 and 50 full-time operating staff, of whom a substantial number will be from the local community. Laricina estimates the Germain project will generate $13 billion in lifetime provincial royalties and $6 billion in federal and provincial taxes.

Winterburn Carbonate Opportunity

As part of its staged long-term development plan, Laricina also intends to exploit the Winterburn carbonates at Germain (see map on page 17). The Winterburn transforms Germain into a dual-zone opportunity, offering future capital synergies by levering existing facilities to access additional resources. The Winterburn underlies approximately 63 sections or 90 percent of the Germain lease at about 420 metres depth and offers 15–30 metres of net pay thickness, with high bitumen saturation.

Like the Grosmont, the Winterburn is a shallow marine Upper Devonian dolomite reservoir that was karsted during the early Cretaceous and is densely fractured. Porosity types are similar to the Grosmont with extensive development of disaggregated dolomite.

Testing to date includes a 2009 injection test to evaluate fluid injectivity and reservoir permeability. In the current winter season Laricina drilled three stratigraphic exploration wells to continue delineating the resource extent and further its reservoir understanding.

Developing the Winterburn is considered Phase 6 of the Germain development plan and will involve a separate approval process.


2013>>2011>>2010>>

Received CDP approval, began CDP construction at year-end, commissioned phase 2–4 EIA, contracted drilling rig construction

CDP construction, file Germain project expansion EIA application covering phases 2–4, launch front-end engineering and design for Phase 2

Complete CDP construction, initiate steam injection by year-end, initiate detailed engineering and design for Phase 2

First oil in CDP, establish key production parameters, ramp up production, initiate SC phase CDP, receive expansion approval and begin construction including first 50 well-pairs and plant earthworks for Phase 2

Achieve full 5,000-barrel- per-day CDP production. Initiate steam injection in 30,000-barrel- per-day Phase 2

2012>> 2014>>

The Upside of Germain

18,176Hectares*

1.7 billion

Barrels net recoverable resource

>240,000 Barrels per day gross production potential

96% Working interest

Construction activities at Germain

* In addition to the Germain lands of 16,128 hectares where Laricina holds Grand Rapids and Winterburn rights, Laricina holds an additional 2,048 hectares of Winterburn rights only.


Burnt Lakes

Recognizing the value of the bitumen in the Grosmont carbonates at Saleski, Laricina acquired the Burnt Lakes property to further increase its holding of Grosmont carbonate along its regional trend to the northwest (see map on page 17). The carbonates are highly predictable over a large areal extent along the sub-crop edge, maintaining their gross thickness of greater than 30 metres, with high porosity and bitumen saturation.

The Burnt Lakes property targets the Grosmont D zone, the richest bitumen-saturated zone. Laricina owns 100 percent working interest in the 11,499-hectare Burnt Lakes leases. Laricina has drilled and cored seven stratigraphic test wells at Burnt Lakes since acquiring the leases. Burnt Lakes is estimated by GLJ to contain 523 million barrels of net recoverable resource (best estimate). Project development will occur in tandem with Saleski once a commercial template has been developed for the Grosmont and is expected to support production of 60,000 barrels per day.

Poplar Creek – Conn Creek

At Poplar Creek Laricina holds a 50 percent working interest over 2,336 gross hectares (1,168 net) and at Conn Creek holds 9,728 hectares at 100 percent working interest. Laricina is the operator of both projects. Poplar Creek and Conn Creek are estimated by GLJ to contain 126 million barrels and 260 million barrels, respectively, of gross recoverable resource (best estimate) from the McMurray Formation. Laricina estimates Poplar Creek can support gross production of up to 25,000 barrels per day and Conn Creek 30,000 barrels per day.

Operations Review

Advancing Our Future Projects

Poplar Creek and Conn Creek are high-quality prospects given their size, reservoir characteristics and proximity to existing infrastructure. Both are adjacent to several in situ oil sands leases operated by leading exploration and production companies. There is extensive delineation at both properties, with Poplar Creek averaging more than five wells per section and Conn Creek approximately one well per section. Laricina has a preliminary development plan in preparation for the Poplar Creek regulatory application. Although our current plans are focused on Saleski and Germain, Laricina is developing regulatory applications to advance the Poplar Creek and Conn Creek projects and increase the value of these assets. In 2011 Laricina will participate in a regional infrastructure study in order to work towards a crossing of the Clearwater River.

Growth Properties

Beyond its five core properties, Saleski, Germain, Burnt Lakes, Poplar Creek and Conn Creek, Laricina has a significant inventory of prospects that are in earlier stages of exploration, which represent approximately 32 percent of its land base. The larger prospects are Boiler Rapids and House River. All are in the McMurray Formation except Portage, which is in the Grand Rapids Formation. GLJ has assigned gross contingent and prospective resources (best estimate) of 483 million barrels to the growth prospects.

McMurray opportunities in the stacked fluvial-estuarine sands.

FORT

MCMURRAY

Wabasca–Desmarais

Burnt Lakes

Germain

Portage

Thornbury

Thornbury West

House River

BoilerRapids

ConnCreek

PoplarCreek

Saleski

A portfolio of future growth opportunities.

Growth Properties


Operations Review

Technology innovation and recovery process enhancements are important tools to increase bitumen recovery and maximize economics of in situ oil sands projects. All of Laricina’s projects are viable with ordinary SAGD, but the Company sees innovation driving major upside in recoveries and value creation. With 11.1 billion barrels of estimated original net bitumen-in-place and a current net recoverable resource estimate of 4.6 billion barrels, every $1 per barrel increase in production netbacks and/or every million barrels of incremental recovery represent significant new value for shareholders.

Innovation is a core component of Laricina’s business model. Our process is guided by rigorous “gating”, or culling ideas so that only those that appear achievable and economic receive resources. We believe carefully managed innovation creates a competitive advantage.

Improved environmental performance is integral to Laricina’s innovation drive. In SAGD projects, reduced environmental impact generally goes hand-in-hand with improved profitability, because reducing the steam-oil ratio lowers energy usage per barrel of bitumen produced and, therefore, carbon emissions.

Unlocking Solvents Through Genetic Algorithms

Laricina’s innovation process includes prioritization by time to commerciality – and solvents were identified early as offering a practical path to commercialization. Mechanics and economic benefits of SC-SAGD are discussed on page 33. Laricina focused on narrowing the staggering number of theoretical combinations of types and blends of solvent, injection volumes and pressures, and timing and blending with steam. The Company employed genetic algorithms to identify the optimized combination of variables. Theoretical optimization was supported by lab tests and small-scale field tests. Today, SC-SAGD is integral to the Saleski and Germain projects.

PHARM

PHARM is another component of the year-by-year continuum of Laricina innovation. A patent application was filed in 2009. PHARM is described on page 26.

Advancing Our Innovations

ESEIEH

The Enhanced Solvent Extraction Incorporating Electromagnetic Heating or ESEIEH project aims to achieve high performance of solvents for underground extraction of bitumen, eliminating the need for water to make steam. Solvents perform poorly at ambient reservoir temperature, hence Laricina’s focus on combining solvent with steam. Steam, however, demands high temperatures and significant surface facilities, which limits the economic benefits of adding solvent. ESEIEH aims to achieve energy-efficient mild heating of the reservoir using electromagnetic waves from antennae placed in the reservoir, facilitating high performance from the injected solvents.

Following in-house work, Laricina in 2010 partnered with two other oil sands developers plus Harris Corp., a U.S. defence contractor with deep expertise in electromagnetic waves. A key goal is to achieve efficient and controlled distribution of radio energy and thus heating. The partners have a four-year development timetable culminating in a full oil sands pilot operation. The project is receiving funding and support from the Government of Alberta’s Climate Change and Emissions Management Corp.

OASIS

OASIS is a Laricina-designed software system designed to allow the rapid creation of new computer simulators for engineering advanced recovery processes and associated technologies. Simulators model numerous crucial systems, such as reservoir fluid flows, steam and emulsion flows and heat transfer in wellbores, together determining the technical and economic success or failure of a process. Advanced models allow for more rigorous engineering by solving problems resistant to a conventional mathematical approach. Sound simulation work can save millions of dollars and months of future field time by rapidly evaluating new concepts before committing to hardware testing. For slightly more effort than required to develop one simulator for one process, Laricina is creating a package that can produce new simulators in as little as one to two weeks, versus one to two years in the past.


Testing water samples.

Operations Review

Advancing Our Innovations

Relationships With Universities

Much of Laricina’s reservoir research has been done in university labs, which is cost-effective and academically rigorous. Laricina’s practice of recruiting interns and engineers in training from universities led to the consortium known as the solvent heat-assisted recovery process or SHARP. Chaired by Laricina, SHARP focuses on gathering data on solvent-bitumen mixtures, which are important inputs used in reservoir simulations. SHARP is one example of Laricina’s broad spectrum of collaborative work with universities.

Innovation Always Has A Practical Purpose

Laricina is not doing research for its own sake, nor is it interested in extremely long-lead or low-probability ideas. Laricina’s innovation team members always remind themselves, “Hope is not a method”. Ideas are rigorously filtered for practicality and profitability. Laricina’s innovation team seeks improvements that have high potential impact on SAGD operations and for which a path to commerciality can be drawn via clear steps. These steps are “stage-gated” from easiest to most difficult, so that resources are applied efficiently.

The best ideas are pursued whole-heartedly, with full support from senior leadership. Laricina’s strong internal process enabled solvent to be brought to the fore early. Not all innovations are grand ideas. Many are smaller, less visible, incremental steps that will bring cumulative benefits over time to the Company’s SAGD operations.


Advancing Our Presence In the Community

Operations Review

Community Engagement Initiatives

Contracts in Wabasca Area ($ millions)

Meaningful and fruitful community relations are of strategic significance as well as of social and ethical importance to Laricina. In 2010 Laricina advanced a number of important community relations initiatives.

Regulatory Approval and Consultation

Laricina’s practice of collaborative consultation and community engagement with Aboriginal stakeholders has meant that no exploration or development approvals have been held up by stakeholder concerns. In 2010 Laricina hosted workshops, held formal and informal meetings, and provided written updates on project plans and activities. The Bigstone Cree Nation’s (BCN) Government and Industry Relations Office provided formalized feedback suggesting the Company’s consultation efforts are being positively received.

In the Wabasca area Laricina continues to employ local and regional contractors and hire local workers. In 2010 Laricina provided safety orientations for 279 local workers who were employed to work on the Saleski and Germain projects, invested approximately

$16 million in local contracts, and awarded an additional $6 million to businesses in Slave Lake and Athabasca. Since 2006 the Company has awarded over $31 million in work to local contractors. In addition, Laricina has worked closely with the BCN to identify spin-off economic opportunities so the First Nation can broaden its economic base by focusing on services it can offer to the oil industry.

Managing Growth

Laricina continued to work with the BCN, the Metis Local #90 and the M.D. of Opportunity #17 on local issues and opportunities related to potential oil sands development. Laricina commissioned a community-wide impact assessment that identified concerns in the areas of aboriginal heritage, communications technology, economic development, education and training, employment, environmental management, infrastructure, safety and social enhancements – plus the need to communicate career opportunities to local people.

A community-wide career fair organized by Laricina attracted more than 200 local students, who were able to interact personally with individuals employed in the oil patch, heavy equipment operators and law enforcement and emergency medical service providers.

People Of the Land

Nametow-askiy Inu-wok, or People of the Land, is the name of four short videos produced by Laricina in partnership with BCN. They tell the story of why traditional lands are important to the BCN’s culture, history and values. They feature BCN Elder Mike Beaver, who speaks knowledgeably and passionately about the traditional territory’s importance. “From our traditional territories, we draw our identity, our rich heritage, culture, language and our stories,” Mike declares. The videos feature Mike singing self-composed traditional songs in Cree and accompanying himself on the traditional drum. The videos also draw on information shared by BCN traditional land users during Laricina-sponsored assessments over the previous two years, which recorded traditional land uses and stories about the significance of areas used by BCN people around Laricina’s Germain, Saleski and Burnt Lakes leases.


Management’s Discussion and Analysis

This Management’s Discussion and Analysis (MD&A) of the financial results of Laricina Energy Ltd. (Laricina or the

Company) for the years ended December 31, 2010 and 2009 was prepared as of April 6, 2011 and should be read in

conjunction with the audited consolidated financial statements and the accompanying notes for the years ending

December 31, 2010 and 2009 in this annual report. The financial information presented in this MD&A has been

prepared in accordance with Canadian generally accepted accounting principles (GAAP). Information is reported

in Canadian dollars.

The information in this MD&A provides management’s analysis of the financial and operating results of the

Company and contains forward-looking statements based on estimates and assumptions that are subject to risks

and uncertainties. Readers are directed to the following “Advisory on Forward-Looking Statements” which applies

to this MD&A and annual report. Actual results or events may vary materially from those anticipated.

Advisory on Forward-Looking Statements

This MD&A and annual report contain certain forward-looking statements relating to, without limitation,

the Company’s business and its intentions, plans, expectations, anticipated financial performance or condition.

Forward-looking statements may include, but are not limited to, statements concerning estimates of contingent,

prospective and recoverable resources and reserves, total potential production volumes, statements relating to

the continued advancement of the Company’s projects and other statements which are not historical facts.

Forward-looking statements typically contain words such as “plan”, “expect”, “estimate”, “intend”, “believe”,

“anticipate”, “project”, “forecast” or other similar words suggesting future outcomes and statements that actions,

events or conditions “may”, “would”, “could” or “will” be taken or occur in the future. You are cautioned not to

place undue reliance on any forward-looking statements as there can be no assurance that the plans, intentions or

expectation upon which they are based will occur. By their nature, forward-looking statements involve numerous

assumptions, known and unknown risks and uncertainties, both general and specific, that contribute to the

possibility that the predictions, forecasts, projections and other forward-looking statements will not occur. Although

the Company’s management believes that the expectations represented by such forward-looking statements are

reasonable as of April 6, 2011, there can be no assurance that such expectations will prove to be correct and,

accordingly, that actual results will be consistent with the forward-looking statements. The risks and other factors

that could cause results to differ materially from those expressed in the forward-looking statements contained in this

MD&A and annual report include, but are not limited to: geological conditions relating to the Company’s properties;

the impact of regulatory changes especially as such relate to royalties, taxation and environmental changes; the

impact of technology on operations and processes and the performance of new technology expected to be applied

or utilized by the Company; labour shortages; supply and demand metrics for oil and natural gas; the impact of

pipeline capacity, upgrading capacity and refinery demand; general economic business and market conditions

and such other risks and uncertainties described from time to time in the reports and filings made with securities

regulatory authorities, contained in other disclosure documents or otherwise provided by the Company. The actual

results, performance or achievements of the Company could differ materially from those expressed in or implied by

forward-looking statements contained in this MD&A and annual report and, accordingly, no assurance can be given

that any of the events anticipated by the forward-looking statements will transpire or occur, or if any of them

do, what benefit Laricina will derive from them. Unless required by law the Company does not undertake any

obligation to update publicly or to revise any of the included forward-looking statements, whether as a result of

new information, future events or otherwise. The forward-looking statements contained in this MD&A and annual

report are expressly qualified by this advisory and disclaimer.


Overview of 2010

Throughout 2010 Laricina, an Alberta-based in situ oil sands company since November 2005, reached a number

of significant milestones as it began transitioning from a development-stage to an operating enterprise. The

Company has focused on the completion of the pilot facility at Saleski, one of two core development areas. Prior to

year-end, steam injection was initiated at Saleski with bitumen production anticipated in the second quarter of

2011. The Saleski pilot is the first steam-assisted gravity drainage (SAGD) development project in the Grosmont

Formation carbonate reservoir.

The Company was successful in the completion of four private placements during the year, providing the

necessary funds for the development of the commercial demonstration project at Germain, its second core

development area, which received regulatory approval in October 2010. Detailed engineering for the Germain

solvent-cyclic (SC) SAGD facility commenced prior to year-end.

Laricina has made substantial progress in securing the geological, engineering, operational and other expertise

necessary to transition into a producing enterprise. Focus will be placed on hiring additional corporate and field

employees during 2011 to support the Saleski pilot facility, the Germain commercial demonstration facility and

continued advancements in technology, as well as the Company’s other properties.

Oil Sands Resources and Reserves

Laricina has focused on four bitumen-bearing geological formations for development: McMurray, Grand Rapids,

Grosmont and Winterburn. GLJ Petroleum Consultants Ltd. (GLJ) completed an independent reserves and

resource assessment and economic evaluation of the Company’s oil sands properties effective December 31, 2010

(GLJ Report).

Consistent with net recoverable bitumen reported in the Company’s 2009 annual report the GLJ Report identified

best estimate contingent and prospective resources of 4.6 billion barrels of net recoverable bitumen. The current

high estimate contingent and prospective resources are comparable to the March 1, 2010 report by GLJ of 7.8 billion

barrels. Recovery methods including SAGD, SC-SAGD and cyclical steam stimulation (CSS) were applied when

evaluating the resource potential of each reservoir.

Contingent Resources (1) (2)

(mmbbls) Low Best High

Grosmont/Winterburn 276 2,568 4,897

Grand Rapids 755 1,304 1,559

McMurray/Wabiskaw 225 501 728

Total 1,256 4,373 7,184


Prospective Resources (3)

(mmbbls) Low Best High

Grosmont/Winterburn – – –

Grand Rapids – – –

McMurray/Wabiskaw 27 223 605

Total 27 223 605

(1) The Canadian Oil and Gas Evaluation Handbook (COGE Handbook) defines contingent resources as quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies. Contingencies may include factors such as economic, legal, environmental, political, and regulatory matters, or a lack of markets. It is also appropriate to classify as contingent resources the estimated discoverable recoverable quantities associated with a project in early evaluation status.

(2) Contingent resources for Conn Creek, Poplar Creek and Saleski are based on SAGD technology; Germain Winterburn is based on CSS technology; Burnt Lakes development is based on a combination of SAGD and CSS technology; Germain Grand Rapids Phase 1 is based on SAGD technology and subsequent phases are based on GLJ’s risked SC-SAGD view.

(3) The COGE Handbook defines prospective resources as 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.

At December 31, 2010 the Company has proved plus probable reserves of 36 million barrels and proved plus

probable plus possible reserves of 43 million barrels, consistent with the March 1, 2010 report by GLJ. These

reserves are associated with the Grand Rapids Formation and the approval of the Germain commercial

demonstration project.

Laricina requested GLJ to provide an enhanced evaluation of the best estimate reserves and resources for the

Germain Grand Rapids and Saleski Grosmont formations using SC-SAGD development plans. Inclusive of SC-SAGD,

the current best estimate net recoverable resources assigned by GLJ was 5.3 billion barrels at December 31, 2010,

which is consistent with the March 1, 2010 report by GLJ. The SC-SAGD best estimate net recoverable resource

evaluation includes 3.1 billion barrels in the Grosmont/Winterburn, 1.5 billion barrels in the Grand Rapids and 0.7 in

the McMurray/Wabiskaw formations.

The possible incremental value available through the application of SC-SAGD recovery techniques will be dependent

on the successful implementation and operation of Laricina’s Germain commercial demonstration project and the

second stage of the Saleski pilot both of which will incorporate an application of solvents. Laricina did not request

an assessment of the application of SC-SAGD on the McMurray, Wabiskaw or Winterburn formations although the

Company anticipates that SC-SAGD will have application to these other formations as well, and believes there is

potential to increase the net recoverable bitumen and value beyond what the current GLJ Report has assigned to

these formations.

The GLJ Report included an economic evaluation on approximately 90 percent of the Company’s resource base

using GLJ’s January 1, 2011 price forecasts. The net present value before income tax at a 10 percent discount rate

is as follows:

($ millions) Low Best High

Contingent resources 2,198 11,660 21,377

Prospective resources 99 156 678

Including the application of SC-SAGD the best estimate contingent net present value would increase

to $14.7 billion.

An economic evaluation was also provided for proved plus probable reserves and proved plus probable plus possible

reserves which resulted in net present value before income tax at a 10 percent discount rate of $46.1 million and

$80.6 million, respectively.


Laricina has explored and delineated the geological formations throughout its portfolio of properties,

including: Germain, Saleski, Burnt Lakes, Poplar Creek and Conn Creek. At December 31, 2010, Laricina had a

total of 325 delineation wells on its operated lands with approximately 60 percent of these wells within its two

primary development areas of Germain and Saleski. These delineation wells support the recoverable resource

estimates provided by GLJ, the Company’s overall confidence in its development plans, as well as the regulatory

applications.

Financial Overview

($ thousands) 2010 2009

Working capital 363,930 149,320

Capital expenditures (cash) 114,931 39,670

Net loss (3,345) (4,475)

Throughout 2010, Laricina made continuous progress towards first production at the Saleski pilot project including

the completion of module fabrication and transport to site, electrical and mechanical engineering and completion of

three well-pairs. Steaming of the first well-pair commenced December 23, 2010 with bitumen production anticipated

to follow in the second quarter of 2011.

The Company was able to secure significant capital through the receipt of $341.9 million gross proceeds

($329.6 million net of share issue costs) from private placements during 2010. On July 5, 2010, the Company

completed a private placement with Canada Pension Plan Investment Board of 8,333,333 common shares at $30.00

per common share for gross proceeds of $250.0 million. A private placement of 874,854 common shares at $30.00

per common share for gross proceeds of $26.2 million was completed on July 28, 2010 with new and existing

shareholders. Following these two private placements, the Company completed a private placement on August 27,

2010 of 1,666,000 common shares with a wholly-owned subsidiary of Korea Investment Corporation at $30.00 per

common share for gross proceeds of $50.0 million. These funds will allow Laricina to proceed with the construction

of the Germain commercial demonstration facility and advance the planning and regulatory processes for the

continued development of Saleski and Germain.

A flow-through financing private placement of 447,741 flow-through common shares was completed on

October 19, 2010 at $35.00 per flow-through common share. The gross proceeds of $15.7 million ($14.8 million net

of share issue costs) raised will support the 2010-2011 winter exploration drilling and geophysical programs.

Annual Financial Information

($ thousands, except per share amounts) 2010 2009 2008

Total assets 852,004 498,321 413,927

Revenue 5,388 558 4,377

Net income (loss) (3,345) (4,475) 6,259

Net income (loss) per common share – basic (0.07) (0.12) 0.18

Net income (loss) per common share – diluted (0.07) (0.12) 0.16

Laricina’s total assets increased substantially in 2010 due to the $329.6 million net proceeds raised through the four equity private placements during the year.


Revenue increased during 2010 due to a data sale to a third-party of certain technical information related

to the results of the Saleski pilot facility for net proceeds of $3.0 million. Interest income also contributed to

additional revenue in 2010 from an increase in the amount of funds on deposit throughout the second half of 2010.

Lower interest rates for funds on deposit were a significant factor in revenue reported in 2009. The net income in

2008 is primarily from the non-recurring recognition of future income tax recovery in relation to the disposition of

the Company’s one percent interest in the Joslyn oil sands property to an unrelated third-party for gross proceeds

of $34.2 million.

Capital Investment

($ thousands) 2010 2009

Oil sands properties

Land 663 394

Exploration 5,199 8,487

Development 94,723 20,529

Other 7,813 4,204

Capitalized general and administrative 10,982 10,450

Corporate 1,106 337

Capital asset additions 120,486 44,401

Capital expenditures (not including non-cash items) 114,931 39,670

Capital asset additions during 2010 were primarily for the completion of the Saleski pilot facility, including the modules and the drilling of the horizontal well-pairs for the Saleski pilot operations. Capital additions during 2010 were less than previously anticipated due to the timing of planned expenditures on the Germain commercial development project, partially offset by higher than expected costs related to the completion of the Saleski pilot project.

Land

Land additions during 2010 consisted of 1,285 hectares of oil sands and petroleum and natural gas rights in the

Burnt Lakes and Saleski areas for $0.4 million. During 2009, the Company added 1,229 net hectares of petroleum

and natural gas rights in the Saleski area for $0.1 million. At December 31, 2010, the total land position was

76,104 hectares compared to 74,819 hectares at December 31, 2009.

Exploration

Exploration activities during 2010 included an 8.6-square-km 3-D seismic program covering the future Germain

commercial demonstration site and 28.8 km of 2-D seismic over the Saleski Phase 1 planned site. Preparations for

the 2010-2011 exploration program of 13 exploration wells and 15.6 square km of 3-D seismic began in the fourth

quarter of 2010. At the date of this report, Laricina had completed all of the wells of the 2010-2011 exploration

program which were drilled to support further planning for the Germain, Saleski and Burnt Lakes areas.

The 2008-2009 exploration program consisted of a seven-well drilling program. The decrease in exploration costs

reflects the Company’s focus on the development of Saleski and Germain throughout 2010.


Similarly to 2009, a substantial amount of the development expenditures incurred during 2010 were attributable to

activities supporting the advancement of the Saleski and Germain projects.

($ thousands) 2010 2009

Saleski 85,831 13,041

Germain 8,768 7,488

Other 124 –

94,723 20,529

During 2010, development activities included the acquisition of equipment, fabrication of modules and construction to complete the first SAGD pilot facility targeting the Grosmont Formation. Additional development activities at the Saleski pilot included the drilling of two well-pairs and the completion of the laterals for all six horizontal wells as well as drilling of five water source wells, two water monitoring wells and four observation wells. The Saleski pilot facility was completed prior to year-end and includes three well-pairs with steam injection commencing on December 23, 2010. At the date of this report, steaming was occurring on two of the three well-pairs. At Germain development activities included two water monitoring and one observation well to support the Germain commercial demonstration project. In addition, development activities included the construction and final grading of the all-weather access road between Germain and Saleski.

Development activities during 2009 were related to front-end engineering and design for the Saleski SC-SAGD

and Germain commercial demonstration projects; equipment purchases and module fabrication for the

Saleski pilot facility; drilling an injectivity test well in the Winterburn Carbonates at Germain, one water monitoring

well and a carbon dioxide sequestration test well; and the initial construction of a 32-km road to the Saleski pilot

facility from Germain.

Laricina conducted a second phase non-thermal solvent-based production test in the Grosmont carbonate at Saleski

during the first quarter of 2009. This test supplemented the initial production test performed in the first quarter of

2008. Information obtained from these two production recovery tests has contributed to the development plans for

the Saleski pilot and Germain commercial demonstration project incorporating solvent-assisted thermal processes.

These processes are expected to improve recovery factors, enhance production rates and lower steam-to-oil ratios,

thereby improving environmental performance, lowering operating costs and capital requirements per unit of future

commercial production.

Other

Other capital activities during 2010 include the amended regulatory application for the second stage of the

Saleski pilot project including SC-SAGD processes, which was approved on April 30, 2010, and the Germain

5,000-barrel-per-day commercial demonstration project utilizing SC-SAGD, which received Order-in-Council

approval from the Government of Alberta on October 14, 2010. This approval was followed by Alberta Environment

approval on October 20, 2010 and Energy Resources Conservation Board approval on October 25, 2010.

Additional regulatory work was completed on the future expansion of Saleski to 12,500 barrels-per-day

production capacity with filing of the application completed in December 2010. Regulatory filing for the next

phase of development at Germain, with 30,000 barrels per day capacity, and two subsequent phases of

60,000 barrels-per-day each, is expected to be submitted prior to year-end 2011.


Throughout 2010 and 2009 other capital investment costs included research and development projects to advance

innovations and technology enhancements, a provision for future income tax related to capitalized non-cash costs,

and a provision for abandonment and restoration activities.

Capital expenditures before capitalized general and administrative costs are estimated to be $306.7 million for

2011. Of these capital expenditures, $43.2 million will be expended at Saleski for the pilot and Phase 1 expansion,

$196.2 million for the Germain commercial demonstration project and advancing Phase 2, $40.1 million to implement

electrical and fuel line infrastructure required to advance these two projects, $17.1 million to conclude the 2010-2011

winter exploration drilling and geophysical program and the remainder for studies and corporate development.

Laricina plans to finance future activities with current cash resources, debt and equity financings.

Corporate Results

($ thousands) 2010 2009

Revenue 5,388 558

General and administrative expenses, net 8,233 5,572

Income tax recovery 88 900

Net loss (3,345) (4,475)

Revenue

In December 2010 the Company sold data to a third-party concerning certain technical information relating to the

Saleski pilot facility results, for net proceeds of $3.0 million. The remaining increase in revenue in 2010 compared

to 2009 is due to increased funds on deposit partially combined with an increase in the average interest rates for

invested funds.

General and Administrative Expenses

Gross general and administrative expenses were higher in 2010 than in 2009 primarily as a result of the growth in

the employee base over both years. Costs directly related to project development activities are capitalized.

($ thousands) 2010 2009

General and administrative expenses, gross 13,138 11,085

Stock-based compensation costs 6,078 4,937

Capitalized costs (10,983) (10,450)

General and administrative expenses, net 8,233 5,572

Gross general and administrative expenses are primarily due to an increase in salaries and general costs associated with an increase in the number of employees to 80 at December 31, 2010 from 49 at December 31, 2009. As projects progress towards commercialization, a smaller percentage of general and administrative expenses will be allocated to capitalized costs.

Net Income

For 2010 Laricina recorded a net loss of $3.3 million compared to a net loss of $4.5 million for 2009. Laricina had

net income of $1.0 million during the fourth quarter of 2010 as a result of the data sold to a third-party. Typical of a

development-stage company, Laricina will continue to show net losses from earnings until commercial production

is achieved.


Selected Quarterly Information

($ thousands,

except per share amounts) Q4 2010 Q3 2010 Q2 2010 Q1 2010 Q4 2009 Q3 2009 Q2 2009 Q1 2009

Working capital 363,930 381,697 92,802 109,378 149,320 160,804 86,094 90,879

Capital asset additions 36,087 26,465 16,251 41,683 12,108 5,468 5,829 20,996

Revenue 4,251 912 118 107 122 111 80 245

Net income (loss) 997 (1,026) (1,731) (1,585) (1,574) (1,140) (864) (897)

Net income (loss) per

common share-basic $ 0.02 $ (0.02) $ (0.04) $ (0.04) $ (0.04) $ (0.03) $ (0.02) $ (0.03)

Net income (loss) per

common share-diluted $ 0.02 $ (0.02) $ (0.04) $ (0.04) $ (0.04) $ (0.03) $ (0.02) $ (0.03)

At the end of the third and fourth quarters of 2010, working capital was significantly higher due to the closing of four private placements of common shares resulting in net proceeds of $329.6 million. Working capital increased during the third quarter of 2009 due to the receipt of $80.2 million of net proceeds from the July 23, 2009 private placement.

Capital additions increased throughout 2010 due to increased spending for the Saleski pilot facility in preparation

for first-steam on December 23, 2010. Capital asset additions generally increase in the first quarter of each year due

to the seasonality of the drilling and geophysical programs usually completed during the winter months.

Revenue was higher during the fourth quarter of 2010 as a result of the proceeds from the data sale combined with

higher interest revenue resulting from increased funds on deposit from financings completed in the second half of

2010. Interest revenue during 2009 and the first half of 2010 was lower due to declining interest rates beginning in

late 2008.

Liquidity and Capital Resources

Working Capital

The Company’s working capital at December 31, 2010 was $363.9 million compared to $149.3 million at

December 31, 2009. Working capital increases were primarily due to the receipt of $329.6 million net proceeds from

private placement financings, the most significant of which closed in the third quarter of 2010. The increases were

partially offset by capital expenditures incurred for the 2009-2010 winter drilling program, the construction of the

all-weather road between Germain and Saleski and the completion of the Saleski pilot facility.

($ thousands)

Working capital, December 31, 2009 149,320

Proceeds from the issuance of common shares, net of share issuance costs 329,701

Capital expenditures (cash) (114,931)

Other (160)

Working capital, December 31, 2010 363,930

Laricina has sufficient working capital to finance the 2011 capital and operating spending program of approximately $340.0 million. It is anticipated that the majority of spending will be directly associated with the Germain commercial demonstration project.


As a development-stage company, future capital expenditures required to achieve commercial operations are

dependent and conditional on financing primarily from equity and debt sources. The Company anticipates funding

capital and operating activities primarily through equity financing; however, additional debt will be considered

under appropriate timing and circumstances. Asset sales or joint venture arrangements may also be considered as

alternative financing sources.

Investments

The Company’s excess cash is currently held in a business operating account with a major Canadian bank which

bears interest up to the bank’s prime rate minus two percent and a guaranteed investment certificate which currently

bears interest at 1.3 percent. The Company may invest in Canadian government securities or fixed-term and bankers’

acceptance investments with a minimum A rating.

Laricina has a demand credit facility of $15.0 million with a major Canadian bank which has been extended to

October 31, 2011 and is secured by a deposit of cash. The credit facility, if utilized, is intended for general corporate

purposes, including the exploration, development and acquisition of oil sands properties. At December 31, 2010 and

the date of this report, the Company had a $3.6 million letter of credit outstanding under this credit facility related

to the development of the Germain and Saleski projects.

As projects are advanced to the commercial development phase, Laricina will evaluate the markets for project

financing and term debt to prudently enhance the Company’s borrowing capacity.

Commitments and Contractual Obligations

As of the date of this report, the Company has contractual obligations for office space, communication equipment

and agreements, drilling rig rentals, natural gas purchases, camp facilities and other obligations as follows:

($ thousands) Office Field

2011 remainder 1,962 7,714

2012 2,734 10,022

2013 2,734 8,399

2014 2,750 4,059

2015 and thereafter 2,303 2,854

As at April 6, 2011, the Company had issued a $3.6 million letter of credit to a third-party partner to support the ongoing development of Saleski and Germain. If the development of these projects is interrupted the Company will be required to reimburse the costs incurred by the third-party partner up to $3.6 million. This letter of credit is renewed annually with the next renewal expected in July 2011.


At March 31, 2011, share capital consisted of the following:

(thousands)

Common shares 51,941

Performance warrants 4,071

Stock options 3,379

Performance share units 631

60,022

The outstanding performance warrants, stock options and performance share units are each convertible to one common share.

Critical Accounting Estimates

In the preparation of financial statements, Canadian GAAP requires certain estimates and assumptions that are

based on management’s best judgment. By their nature, estimates and assumptions are subject to uncertainty

and the effect of changes in these estimates and assumptions on the financial statements could be significant. The

following items involved estimations or assumptions by Laricina’s management in the preparation of the Company’s

consolidated financial statements.

Oil Sands Resources and Reserves

Laricina’s oil sands resources and reserves are independently evaluated by petroleum engineering consultants.

The estimate of resources and reserves is a subjective process and is based on forecasts which are subject to

uncertainties such as geological and engineering data, projected future rates of production, commodity pricing and

the timing of future capital expenditures. Revisions to resource and reserve estimates can occur from the results of

future drilling, testing, production levels and economics of recovery. A revision to resource and reserve estimates

would have minimal impact to the financial statements as the Company is still in the development stage and has not

yet begun to depreciate or deplete its oil sands assets.

Impairment

Impairment is indicated if the net carrying value of capital assets may not be recoverable from the estimated

future undiscounted cash flows associated with those capital assets. The calculation of the estimated future cash

flows is based on a number of estimates, including resources, reserves, production rates, commodity prices, future

development costs and other relevant assumptions.

Asset Retirement Obligations

The fair value of the obligation is recognized as both an asset and a liability for existing asset retirement obligations.

This fair value of the obligation is the present value of the estimated amount of cash flows required for the future

abandonment of an asset. These future payments are discounted using a credit-adjusted risk-free rate appropriate

for the Company. Estimating the timing, amount and value of these retirement costs is subject to judgment.


Stock-based Compensation

The Company applies the fair value method for performance warrants, stock options and performance share

units granted. Compensation cost is recognized over the vesting period of the award based on the estimated fair

value of the performance warrant, stock option or performance share unit on the grant date using the Black-Scholes

pricing model.

Future Income Tax

The determination of future income tax assets and liabilities requires interpretation of complex laws and regulations,

and future income tax assets and liabilities are recognized at tax rates expected to be in effect at the estimated

timing of reversal of temporary differences between the accounting and tax values of certain assets and liabilities.

Changes in Accounting Pronouncements

In February 2008, the Canadian Institute of Chartered Accountants’ Accounting Standards Board confirmed the

adoption of International Financial Reporting Standards (IFRS) for interim and annual reporting purposes for fiscal

years beginning on or after January 1, 2011. In July 2009, the International Accounting Standards Board approved

additional IFRS transitional exemptions for entities to allocate their oil and natural gas asset balances under full cost

accounting to the IFRS categories of exploration and evaluation assets, and development and producing properties.

This exemption provides entities with relief from significant adjustments to oil and natural gas assets resulting from

the retrospective adoption of IFRS. Laricina will use this exemption upon adoption.

The Company has completed the identification of differences between Canadian GAAP and IFRS and has

determined the most significant impact of the IFRS conversion will be to property, plant and equipment. IFRS does

not provide specific oil and natural gas accounting guidance other than for costs incurred during the exploration

and evaluation phase. The conversion to IFRS will have a significant impact on the accounting for costs related to

the pre-exploration and development phases as well as the level at which impairment tests are performed and the

methodology used in testing impairment.

Other differences between Canadian GAAP and IFRS include the treatment of asset retirement obligations,

stock-based compensation and other first-time adoption exemptions. Laricina has assessed these differences

and provided recommendations for accounting policy changes. The impact on the Company’s January 1, 2010

opening financial position, required under IFRS for comparative purposes, is estimated to be the following: an

increase in asset retirement obligations of approximately $0.4 million; an increase in share capital of approximately

$3.0 million as a result of the change in accounting for flow-through shares issued prior to the date of conversion;

and an increase in contributed surplus of approximately $1.3 million as a result of the adjustments to accounting for

stock-based compensation. Each of these adjustments will have a corresponding change to retained earnings as

well as a future income tax impact.

The adoption of IFRS accounting policies will result in higher share-based payment expense (stock-based

compensation) due to the recognition of the expense related to each tranche being treated as a separate

grant with a different vesting date and fair value. Under Canadian GAAP, the expense was recognized on a

straight-line basis. In addition, depreciation expense will increase by approximately $0.6 million due to the

component depreciation required under IFRS and interest expense will increase by approximately $0.1 million due

to changes in accounting for site restoration provisions (asset retirement obligations). Under Canadian GAAP, the

accretion of the site restoration provision was capitalized until the Company reached commercial production. Under

IFRS, the accretion will be expensed as interest expense. Reported net loss in 2010 is expected to be approximately

$0.2 million higher when presented in accordance with IFRS primarily due to higher compensation costs and higher

depreciation expense.


Risk Management

Laricina’s operational and financial success can be affected by a variety of risks related to the oil and natural

gas industry, many of which are not in the control of the Company. Laricina does not have material producing

operations and the primary assets of the Company consist of oil sands properties that are undeveloped or under

current development plans. Accordingly, the Company’s success is dependent upon the outcomes of these current

development plans, on future development and potentially on additional acquisitions of oil sands properties. Current

risk factors influencing the Company include, but are not limited to, the following:

Uncertainty of Resources and Reserves

There are a number of uncertainties inherent in estimating the quantities of oil sands resources and reserves, and

no assurance can be given that the level of resources or recovery of bitumen will be realized. Reservoir engineering

is a subjective process of estimating and is highly dependent on the accuracy of the assumptions on which the

estimates are based. Assumptions such as historical production from similar properties, the effects of regulation by

government agencies, estimated future capital and operating costs and potential enhanced recovery techniques

are used in estimates of economically recoverable bitumen and actual results may vary considerably. All such

estimates are, to some degree, uncertain and classifications of reserves and resources are only attempts to define

the degree of uncertainty involved. For these reasons, estimates of the economically recoverable bitumen, and the

classification of such reserves and resources, are based on risk of recovery, and estimates of future net revenue

expected from those reserves, prepared by different engineers or by the same engineers at different times, may

vary substantially. Some of the formations from which Laricina intends to produce bitumen and to which GLJ has

assigned recoverable reserves and resources have not yet produced commercial quantities of bitumen.

Capital Requirement and Financial Resources

Similarly to many other growth-oriented oil sands companies, Laricina expects to make substantial capital

expenditures for the acquisition, exploration, development and production of oil sands resources and reserves in the

future. Such expenditures require financing from equity or debt sources, asset sales or joint venture arrangements.

There can be no assurance that any of these sources of financing will be available at terms that would be acceptable

to the Company, if at all.

Regulatory

Future development of Laricina’s oil sands properties is dependent on the approval of required regulatory

applications and permits. Failure to obtain regulatory approvals or failure to obtain them on a timely basis could

result in delays or increased costs or projects not proceeding.

Government regulations may be changed from time to time in response to economic or political conditions. The

implementation of new regulations or the modification of existing regulations could impact the timing of Laricina’s

project development plans or increase costs, which may make future projects uneconomic.

Regulatory approvals require the Company to consult with local communities and stakeholders. While Laricina has

an established stakeholder consultation and communication plan, there can be no assurance that the actions or

omissions of respective parties will not affect the timing or potential receipt of the necessary approvals to advance

the Company’s development plans.


In March 2010 the Alberta government initiated a comprehensive review of Alberta’s regulatory system called

the Regulatory Enhancement Project. The goal of this project is to create a modern, efficient, outcome-based

and competitive regulatory system that will contribute to Alberta’s overall competitiveness while protecting

the environment, public safety and resource conservation. The project included consultation with a range of

stakeholders, including industry participants. The project team recommended to the Minister of Energy the adoption

of a coordinated policy framework and an integrated regulatory system for the upstream oil and gas sector. The

Government of Alberta has accepted the recommendations of the project team and is expected to commence

implementation in the first half of 2011.

Alberta’s Land-use Framework, which is to be implemented under the Alberta Land Stewardship Act (ALSA),

outlines the Government of Alberta’s approach to managing land and natural resources to meet long-term

economic, environmental and social goals. The ALSA considers the amendment or removal of previously issued

items including regulatory permits, licenses, approvals or authorizations in order to achieve an objective or policy

resulting from the implementation of a regional plan. The Government of Alberta is expected to develop a regional

plan for seven regions in the province and has identified the Lower Athabasca Regional Plan (LARP) as a priority.

The intention of the LARP is to identify and set resource and environmental management outcomes for air, land,

water and biodiversity and to guide future decisions while considering the social and economic impacts. On

April 5, 2011, the Government of Alberta issued a draft LARP which is expected to be finalized in May 2011 after

public and industry consultation. The conservation lands identified in the draft plan do not cover oil sands leases

currently held by Laricina. As a stakeholder in the activities of the area, Laricina is engaged in the feedback process

and will continue to participate in the consultation and development of the final plan over the next several months.

Laricina will continue to work with the Government of Alberta to understand any potential plan for the Lower Peace

Region which includes the core development areas of Saleski, Germain and Burnt Lakes.

Environmental

Like all natural resource development, oil sands development has an impact on the environment and is subject to

environmental regulation. Environmental legislation and regulations provide for, among other things, restrictions or

prohibitions on releases or emissions of various substances. They also require that wells and facility sites be operated,

maintained, abandoned and reclaimed to the satisfaction of applicable regulatory authorities. No assurance can be

given that the current or future environmental laws and regulations will not have an adverse effect on the financial

condition of the Company.

Announcements from the federal and provincial governments on regulations for greenhouse gas and air emissions

legislation have caused uncertainty and changed the environmental regulation of oil sands operations. In 2007,

the Alberta government’s Climate Change Emissions Management Act and Specified Gas Emitters Regulation

(SGER) came into effect, requiring that facilities emitting more than 100,000 tonnes of greenhouse gases reduce

their greenhouse gas emissions intensity by two percent per year to a maximum of 12 percent from a regulated

baseline. If the emissions intensity target is not met through improvements in operations, other compliance tools

are available including: a $15 per tonne payment into the Climate Change Emissions Management Fund, purchase of

Alberta-based offsets, or purchase of emission performance credits from a different Alberta facility. Failure to

comply with these regulations results in a penalty of $200 per tonne of greenhouse gases over the allowable

greenhouse gas emission intensity limit. New in situ facilities are provided a baseline period for the first three years

of operation during which time the facility is exempt from compliance obligations.

The Saleski pilot is not subject to the SGER as emissions will be below the emissions threshold of 100,000 tonnes.

The Germain commercial demonstration project will require reporting but not compliance based on the current

threshold of 100,000 tonnes. Federal and provincial reporting is required for emissions above 50,000 tonnes. The

use of SC-SAGD technology is expected to decrease steam-to-oil ratios, thereby reducing emissions.


There is no federal legislation in Canada for the regulation of greenhouse gases. Until such time as this might occur,

the impact of future federal greenhouse gas regulation on the Company’s operations is unknown.

Laricina is a participant in several ongoing research studies and anticipates mitigating the impacts of these legislative

initiatives through innovations that increase operating efficiency by reducing both the use of energy and emissions

per unit of production. The Company is also a founding member of the In Situ Oil Sands Alliance, a group of

independent emerging oil sands companies organized to support industry dialogue with the federal and provincial

governments and the respective regulators.

Competition

The oil sands industry is highly competitive for the acquisition of reserves, exploration leases and skilled industry

personnel. Many competitors in the oil sands industry have significantly greater financial resources than Laricina.

Laricina’s success will be dependent on its ability to enter into joint venture arrangements with other oil sands

development companies, enter into beneficial partnerships with other industry participants or attract individuals

with oil sands expertise and attract financial capital.

Royalty Regime

On January 1, 2009, the New Royalty Framework and Transitional Royalty Program announced by the Government

of Alberta in 2007 became effective. Laricina’s revenue and expenses will be directly affected by the royalty regime

applicable to its projects. The economic benefit of future capital expenditures for any project is, in many cases,

dependent on a satisfactory royalty regime. There can be no assurance that the royalty structure currently in

place will remain unchanged. On March 11, 2010, the Government of Alberta announced the outcome of its Alberta

Competitiveness Review. No proposed changes resulting from the review affected bitumen production as the

review’s focus was on conventional oil and natural gas production.

Laricina’s success depends on its ability to find, acquire, develop and produce oil at an economically recoverable

cost. Oil sands exploration, by definition, involves risk. Laricina will be designing and testing improved recovery and

cost-reduction strategies for the development of in situ projects that are innovative to the oil sands industry. There

is no assurance that the Company will be able to obtain additional satisfactory properties for acquisition or that the

development strategies will have a positive influence on the Company’s financial results.

Infrastructure

The future development of the Company’s commercial projects will depend on certain infrastructure, including

but not limited to: pipelines for transportation of diluent and blended product, pipelines for the transportation of

natural gas and electricity transmission systems.

Insurance

The exploration for and development of oil sands properties may expose the Company to liability for pollution,

well blow-outs, property damage, personal injury or other hazards. Although Laricina obtains insurance to protect

against such risks, there are limitations on insuring against liabilities such that available insurance may not be

sufficient to cover the full extent of such costs, or a particular risk may not be insurable in all circumstances, or the

Company may elect not to obtain insurance in certain circumstances. The occurrence of a significant event that is

not fully insured against could have a material adverse effect on the Company’s financial position.


Assessment of Value of Acquisitions

Acquisitions of oil and natural gas issuers and oil and natural gas assets are typically based on engineering and

economic assessments. These assessments include assumptions regarding recoverability and marketability of oil

and natural gas, future commodity prices and operating costs, future capital expenditures, royalties and other

government levies. Many of these factors are subject to change and are outside the Company’s control. Initial

assessments may be based on reports by a firm of independent engineers that may have evaluation methods

and approaches that are different from those of the firm engaged by Laricina to complete its annual resource

evaluations. As a result, the initial assessments may differ significantly from the assessments by the Company’s

engineering firm and affect the return on and value of the acquisition.

Foreign Exchange

Crude oil prices and certain major equipment costs are generally based on a United States dollar market price.

Fluctuations in exchange rates between the United States dollar and Canadian dollar will therefore give rise to

foreign currency exchange exposure and could result in adverse effects on Laricina’s financial position or future

cash flows.

Commodity Price Risk

Oil prices, natural gas prices, diluent prices and heavy oil differentials fluctuate significantly in response to regional,

national and global supply and demand factors beyond the control of Laricina. The Company’s future financial

results are dependent on the future demand and any negative price effect that increased bitumen supplies by

competitors could have.

Operating Costs

The cost of natural gas is a significant component of the cost of production of the future bitumen produced by

the Company’s projects. Laricina’s future earnings may be reduced if there are significant increases in the cost of

natural gas. The availability and cost of diluent and hydrocarbon solvents may also reduce future earnings if there

are significant increases in diluent or light hydrocarbon solvent prices.

Lack of Liquidity

Laricina does not currently have a public market for its common shares. Any future offering may not lead to an

active trading market or, if developed, one that would be sustainable. There can be no assurance that a future offer

for the common shares will be made. Accordingly, an investment in the common shares should only be considered

by investors who do not require liquidity.

Reliance on Key Employees

The continued success of Laricina is dependent on the performance of key employees. Failure to retain or to attract

and retain additional key employees with the necessary skills could have an adverse effect upon the Company’s

development, growth and profitability.

Seasonality

Certain of Laricina’s properties are located in areas that are inaccessible during non-winter months or where

activities are restricted due to environmental concerns. Seasonal factors and unexpected weather may lead to

delays in exploration or development programs.


Third-party Credit Risk

The Company is or may be exposed to third-party credit risk through financial instruments, accounts receivable and

contractual arrangements with current or future joint venture partners and other parties. Should any counterparties

fail to meet their contractual obligations it could impact operations or there could be a material adverse effect on

the financial position or cash flow of the Company.

Income Taxes

Although Laricina files all required income tax returns and expects to be in compliance with the provisions of the

Income Tax Act (Canada) and applicable provincial tax legislation, there is no assurance that these returns will not

be reassessed by the applicable taxation authority. A successful reassessment may have an impact on current and

future income taxes payable.

2011 Outlook Summary

The private placements completed during the second half of 2010 provide the Company with flexibility in managing

its pace of development and support the pilot project at Saleski and the commercial demonstration project at

Germain. Laricina will continue to monitor the capital markets and consider a full range of financing strategies

to provide the funds necessary to advance its projects, such as private or public equity, asset sales, debt and

participation agreements with other oil sands development companies or joint venture agreements.

Reservoir steaming at Saleski commenced on December 23, 2010 with first production expected in the second

quarter of 2011. Other activities at Saleski will include front-end engineering and design for the Saleski Phase 1

expansion to support the regulatory application filed in December 2010.

Regulatory approval of the commercial demonstration project at Germain was received in October 2010. Detailed

engineering, module fabrication, infrastructure, site preparation and drilling six of the 10 horizontal well pairs is

expected to be completed in 2011, with start-up anticipated prior to year-end 2012.

The 2010-2011 winter exploration and development drilling programs were completed in the first quarter of 2011 and

consisted of 13 exploration wells, 15.6 square km of 3-D seismic and 27 development wells including 17 observation

wells, eight water source and monitoring wells and two water disposal wells.

During 2011, additional expertise will be required to execute the development of Germain and accommodate the

production expected from the Saleski pilot. It is expected that approximately 55 additional employees will be

obtained to provide the necessary expansion in technical capacity. Due to the increased size of the organization,

general and administrative expenses are expected to increase as a result of greater salary expense and office costs

from the planned expansion of office space in the second quarter of 2011.

With the conversion to IFRS, it is expected that general and administrative expenses will increase as a result of the

changes in calculating share-based payments and the ability to capitalize general and administrative expenses.

Other expenses will increase due to the requirement to expense accretion on site restoration provisions, higher

depreciation expense due to the requirement to depreciate individual components of assets and the expensing of

specific expenditures incurred prior to the exploratory and evaluation stages that were previously capitalized.

The 2011 capital and net operating expenditures (including cash general and administrative expenses) are

expected to be approximately $340.0 million, with the majority of costs directed to the Germain commercial

demonstration project.


To the Shareholders of Laricina Energy Ltd.

We have audited the accompanying consolidated financial statements of Laricina Energy Ltd. (the “Company”),

which comprise the consolidated balance sheets as at December 31, 2010 and 2009 and the consolidated statements

of loss, comprehensive loss and retained earnings and cash flows for the years then ended, and notes, comprising

a summary of significant accounting policies and other explanatory information.

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.

Auditors’ 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 auditors considers internal control relevant to the Company’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 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

the Company as at December 31, 2010 and 2009 and of its consolidated financial performance and its consolidated

cash flows for the years then ended in accordance with Canadian generally accepted accounting principles.

Chartered AccountantsCalgary, CanadaApril 6, 2011

Auditors’ Report to the Shareholders

(signed) “KPMG LLP”


Consolidated Balance Sheets

As at December 31

(thousands of dollars) 2010 2009

Assets

Current assets

Cash and cash equivalents (note 7) $ 375,426 $ 156,062

Accounts receivable 17,030 3,306

Prepaid expenses and deposits 449 461

Inventory 254 –

393,159 159,829

Abandonment deposits 507 358

Other long-term assets (note 4) 551 244

Capital assets (note 5) 457,787 337,890

$ 852,004 $ 498,321

Liabilities and Shareholders’ Equity

Current liabilities

Accounts payable and accrued liabilities $ 29,229 $ 10,509

Asset retirement obligations (note 6) 3,695 2,143

Deferred revenue – 32

Future income tax (note 11) 18,170 20,239

51,094 32,923

Shareholders’ equity

Share capital (note 8) 779,544 444,981

Contributed surplus (note 9) 20,472 16,178

Retained earnings 894 4,239

800,910 465,398

Commitments (note 10)

$ 852,004 $ 498,321

See accompanying notes to the consolidated financial statements

On behalf of the Board:

Brian K. Lemke Glen C. Schmidt Director Director

(signed) “Brian K. Lemke” (signed) “Glen C. Schmidt”


Consolidated Statements of Loss, Comprehensive Loss and Retained Earnings

For the years ended December 31

(thousands of dollars, except per share amounts) 2010 2009

Revenue

Interest $ 2,387 $ 558

Other income 3,001 –

5,388 558

Expenses

General and administrative 8,233 5,572

Amortization 588 361

8,821 5,933

Loss before income taxes (3,433) (5,375)

Future income tax recovery (note 11) (88) (900)

Net loss and comprehensive loss (3,345) (4,475)

Retained earnings, beginning of year 4,239 8,714

Retained earnings, end of year $ 894 $ 4,239

Net loss per common share (note 8)

Basic $ (0.07) $ (0.12)

Diluted $ (0.07) $ (0.12)



Consolidated Statements of Cash Flows

For the years ended December 31

(thousands of dollars) 2010 2009

Cash and cash equivalents provided by (used in):

Operating activities

Net loss $ (3,345) $ (4,475)

Add items not affecting cash:

Future income tax recovery (88) (900)

Deferred revenue (43) (43)

Stock-based compensation 2,772 1,585

Amortization 588 361

Changes in non-cash working capital (note 12) (3,608) 485

(3,724) (2,987)

Investing activities

Capital expenditures (114,931) (39,670)

Abandonment deposits (149) (242)

Refund of investment tax credits (note 4) 98 –

Changes in non-cash working capital (note 12) 8,327 1,403

(106,655) (38,509)

Financing activities

Share issues, net of share issuance costs (note 8) 329,703 81,355

Changes in non-cash working capital (note 12) 40 2

329,743 81,357

Increase in cash 219,364 39,861

Cash and cash equivalents, beginning of year 156,062 116,201

Cash and cash equivalents, end of year $ 375,426 $ 156,062



Notes to the Consolidated Financial Statements – December 31, 2010

(tabular amounts in thousands of dollars except per share amounts and as otherwise noted)

1. Financial Statement Presentation

Laricina Energy Ltd. (Laricina or the Company) was incorporated on November 11, 2005 under the Business

Corporations Act (Alberta). The consolidated financial statements of Laricina are prepared in accordance with

Canadian generally accepted accounting principles.

Basis of Presentation

The consolidated financial statements include the accounts of Laricina and its wholly-owned subsidiary corporations.

The Company has entered into joint venture arrangements and accordingly these accounts reflect only Laricina’s

proportionate interest in these activities.

Laricina is an early-stage enterprise focused on the development of oil sands properties through acquisition,

partnership or other arrangements. The Company is considered to be in the development stage as it does not

have any production revenue and will not have any material production until a project becomes commercial.

Since inception, Laricina has focused on acquiring prospective oil sands properties, developing properties into

projects, financing, attracting suitable personnel and developing innovative technologies. To date, two areas have

been identified as future commercial projects, Germain and Saleski. Until one of its projects reaches commercial

production, Laricina will continue to be in the development stage. The Company will require future equity or debt

financing in order to reach commerciality.

2. Summary of Significant Accounting Policies

Cash Equivalents

Cash equivalents consist of a guaranteed investment certificate that may be redeemed at the option of the

Company.

Capital Assets

The Company follows the full cost method of accounting whereby all costs associated with the acquisition,

exploration and development of oil sands properties are capitalized. All direct costs related to the development

of an oil sands property are considered pre-operating and are capitalized, including the cost of the acquisition of

leases, geological and geophysical costs, drilling, plant and equipment, pipeline costs and related overhead.

General and administrative costs directly related to development activities are capitalized.

Capital assets are assessed at each reporting period to determine if there are events or circumstances that would

indicate that the carrying values will not be recovered in the future. If the carrying value is unlikely to be recovered,

the excess of those costs over the fair value is charged to earnings in that period.

Proceeds from the sale of oil sands properties are applied against capitalized costs, with no gain or loss recognized,

unless such a sale would significantly change the rate of depletion.

Notes to the Consolidated Financial Statements

Laricina Energy Ltd.61 Laricina Energy Ltd.61

Corporate assets are amortized on a straight-line basis over the estimated service life of the related asset at annual

rates of 20 to 30 percent.

Amortization and depletion of oil sands properties will be provided following the unit-of-production method based

on the estimated proved reserves when commercial production begins.

Asset Retirement Obligations

The Company recognizes a liability for future asset retirement obligations associated with long-lived assets in the

period the obligation is incurred with a corresponding increase to the carrying amount of the related long-lived

asset. Asset retirement costs will be amortized on a basis consistent with the related amortization and depletion

policy. The liability is increased due to the passage of time until the retirement obligation is settled. Changes in

the estimated obligation resulting from revisions to estimated timing or amount of undiscounted cash flows are

recognized as a change in the asset retirement obligation and the asset retirement costs. Actual asset retirement

costs are charged against the asset retirement obligation when incurred. Accretion for the obligation is capitalized

prior to commercial production and expensed as operating cost after commerciality is achieved.

Inventory

Inventory consists of materials, parts and supplies and is valued at the lower of cost and net realizable value. Cost

is determined using a first-in, first-out basis.

Stock-based Compensation

The Company applies the fair value method for performance warrants, stock options and performance share units

granted. Compensation cost is recognized over the vesting period of the award based on the estimated fair value

of the performance warrants, stock options or performance share units on the grant date using the Black-Scholes

pricing model with a corresponding increase to contributed surplus. The fair value of stock-based compensation

granted to providers of service is estimated and any change in this value is recognized at each reporting date of the

Company. Upon exercise, consideration received together with the amount previously recognized in contributed

surplus is recorded as an increase to share capital.

Share Appreciation Rights

The Company established a share appreciation rights plan on March 25, 2010. Directors, officers, employees of,

or providers of services to, Laricina are eligible to receive grants of share appreciation rights which entitle the

holder to receive a cash payment equal to the excess of the market price of the Company’s common shares over

the exercise price on the date the share appreciation right is exercised. The fair value of the amount payable to

employees in respect of share appreciation rights, which are settled in cash, is recognized as an expense with a

corresponding increase in current liabilities, over the period that the employees become entitled to payment. The

liability is remeasured at each reporting date and at settlement date. Any change in the fair value of the liability is

recognized as compensation cost.

Flow-through Shares

A portion of the Company’s exploration activities has been financed through the issuance of flow-through common

shares. Under the terms of the share issue, the related resource expenditure deductions are renounced to the

shareholders in accordance with income tax legislation. Share capital is reduced, with a corresponding increase to

the future tax liability, by the estimated cost of the resource expenditure when the related income tax deductions

are renounced to the shareholders.


2. Summary of Significant Accounting Policies (continued)

Income Taxes

The asset and liability method of accounting for income taxes is followed whereby future income tax assets and

liabilities are recognized based on the estimated tax effects of temporary differences between the carrying value of

assets and liabilities and their respective tax bases. Future income tax assets and liabilities are measured using the

enacted tax rates that will apply in the years the temporary differences are expected to be recovered or settled.

Use of Estimates

Management makes estimates and assumptions that affect the amounts reported in the consolidated financial

statements and notes to the consolidated financial statements. These estimates are based on management’s best

knowledge of current events and actions that the Company may undertake in the future. Actual results may differ

from these estimates. Significant estimates used in the preparation of the consolidated financial statements include,

but are not limited to, the recovery of exploration and other costs capitalized in accordance with full cost accounting,

asset retirement obligations, future income tax and stock-based compensation.

Per Share Amounts

Basic net income per common share is calculated using the weighted average number of common shares issued

and outstanding during the year. The Company uses the treasury stock method to determine the dilutive effect of

performance warrants, stock options and performance share units.

Comprehensive Income

Comprehensive income is comprised of net income and other comprehensive income which represents the change in

equity for a period that arises from unrealized changes in the fair market value of derivative instruments designated

as cash flow hedges.

Financial Instruments

All financial instruments are to be recognized on the balance sheet initially at fair value. Subsequent measurement

of all financial assets and liabilities except those held-for-trading and available-for-sale are measured at amortized

cost determined using the effective interest rate method. Cash is designated as held-for-trading and the fair value

approximates the carrying value due to its short-term nature. Accounts receivable, prepaid expenses and deposits

are classified as loans and receivables while accounts payable and accrued liabilities are classified as other financial

liabilities and the fair values approximate their carrying value due to the short-term nature of these instruments. The

Company has not designated any financial instruments as available-for-sale.

3. New Accounting Pronouncements

In February 2008, the Canadian Institute of Chartered Accountants’ (CICA) Accounting Standards Board confirmed

the adoption of International Financial Reporting Standards (IFRS) for interim and annual reporting purposes for

fiscal years beginning on or after January 1, 2011. In July 2009, the International Accounting Standards Board

approved additional IFRS transitional exemptions for entities to allocate their oil and natural gas asset balances

under full cost accounting to the IFRS categories of exploration and evaluation assets, and development and

producing properties. This exemption provides entities with relief from significant adjustments to oil and natural

gas assets resulting from the retrospective adoption of IFRS. Laricina will use this exemption upon adoption.

The Company expects that the areas with the most significant impact as a result of the transition to IFRS will be

the accounting for oil sands assets and adjustments to retained earnings for the accounting treatment of asset

retirement obligations, stock-based compensation and flow-through common share renouncements.



4. Other Long-Term Assets

At December 31, 2010, the Company had investment tax credits of $0.6 million ($0.2 million at December 31, 2009).

The investment tax credits resulted from the Canada Revenue Agency’s Scientific Research and Experimental

Development (SR&ED) program and the related applications for 2007 and 2008 SR&ED expenditures. The

after-tax benefit associated with the investment tax credit is approximately $0.4 million for 2010 ($0.2 million in

2009). During 2010, the Company received an Investment tax credit refund of $0.1 million (nil in 2009).

In the first quarter of 2011, the Company received approval of the 2009 SR&ED application, increasing the investment

tax credits to $1.1 million.

5. Capital Assets

2010 2009

Oil sands properties $ 456,685 $ 337,306

Corporate assets 2,474 1,368

459,159 338,674

Accumulated amortization – corporate assets (1,372) (784)

$ 457,787 $ 337,890

During the fourth quarter of 2009, Laricina received funding from the Government of Alberta under the Innovative Energy Technology Program. This funding is received through royalty credits recovered by a third-party partner and resulted in net proceeds of $1.9 million, which has been recorded as a reduction to capital assets.

During the year ended December 31, 2010, the Company capitalized general and administrative expenditures of

$11.0 million ($10.5 million in 2009) including stock-based compensation costs of $3.3 million ($3.4 million in

2009). To date, no depletion has been recorded with respect to the oil sands properties as the Company has not

commenced commercial production.

6. Asset Retirement Obligations

The Company recorded obligations of $1.6 million during the year ended December 31, 2010 ($0.5 million in 2009).

The estimated undiscounted amount of cash flows required to settle the asset retirement obligations is $8.6 million

as at December 31, 2010 ($5.3 million as at December 31, 2009). These asset retirement costs have been discounted

at rates between 4.5 percent and 5.1 percent and are expected to be incurred between 2015 and 2040.

7. Credit Facility

The Company’s credit agreement with a Canadian chartered bank has been extended to October 31, 2011. Amounts

drawn under the facility can take the form of prime rate-based loans, bankers’ acceptances, LIBOR loans or letters

of credit and will bear interest at the prime rate, bankers’ acceptances rates or at LIBOR plus a spread above the

reference rate between 1.0 percent and 2.0 percent per annum. The credit agreement provides a demand credit

facility of $15.0 million and is secured by a deposit of cash equal to the amount of the credit facility. As at December

31, 2010 and April 6, 2011 the Company had a $3.6 million letter of credit outstanding under this credit facility.

.


8. Share Capital

Authorized

Unlimited number of common shares without par value

Unlimited number of preferred shares without par value, issuable in series

Issued

Number of

Shares

(thousands) Amount

Common Shares

Balance, January 1, 2009 34,748 $ 362,330

Issued for cash 5,590 83,844

Share issue costs, net of tax benefit – (2,707)

Performance share units exercised 42 327

Performance warrants exercised 100 1,187

Balance, December 31, 2009 40,480 $ 444,981

Issued for cash 11,322 341,887

Share issue costs, net of tax benefit – (9,247)

Performance share units exercised 85 1,727

Stock options exercised 29 196

Balance, December 31, 2010 51,916 $ 779,544

On July 23, 2009, Laricina closed a private placement of 5,589,568 common shares at a price of $15.00 per common share for gross proceeds of $83.8 million ($80.2 million net of share issue costs).

On July 5, 2010, Laricina closed a private placement of 8,333,333 common shares at a price of $30.00 per common

share with a single investor for gross proceeds of $250.0 million ($242.5 million net of share issue costs).

On July 28, 2010, Laricina closed a private placement of 874,854 common shares at a price of $30.00 per common

share for gross proceeds of $26.2 million ($25.2 million net of share issue costs).

On August 27, 2010, Laricina closed a private placement of 1,666,000 common shares at a price of $30.00 per

common share with a single investor for gross proceeds of $50.0 million ($47.1 million net of share issue costs).

On October 19, 2010, Laricina closed a private placement of 447,471 flow-through common shares at a

price of $35.00 per flow-through common share for gross proceeds of $15.7 million ($14.8 million net of share

issue costs). In accordance with the terms of the offering and pursuant to the Income Tax Act, the Company has

renounced, for income tax purposes, exploration expenditures of $15.7 million to holders of the flow-through common

shares effective December 31, 2010. The Company is required to incur the associated qualifying expenditures by

December 31, 2011.



Performance Warrants

In conjunction with its initial private placement, the Company granted performance warrants on a one-time basis

to certain founding directors, officers, employees of, and providers of services to the Company. The performance

warrants were issued in five series with the targeted exercise prices ranging from $6.00 to $16.00, vesting over

three years, and for each warrant exercised the holder will receive one common share.

2010 2009

Weighted Weighted

Average Average

Number Exercise Number Exercise

(thousands) Price (thousands) Price

Outstanding, beginning of year 4,071 $ 11.20 4,171 $ 11.20

Exercised – – (100) 11.20

Outstanding, end of year 4,071 $ 11.20 4,071 $ 11.20

Exercisable, end of year 4,071 $ 11.20 4,071 $ 11.20

The following table is an analysis of outstanding and exercisable performance warrants as at December 31, 2010:

Outstanding Exercisable

Weighted Weighted Weighted

Average Average Average

Remaining Exercise Exercise

Number Contractual Price Number Price

Exercise Price ($/warrant) (thousands) Life (years) ($/warrant) (thousands) ($/warrant)

$ 6.00 814 2.0 $ 6.00 814 $ 6.00

$ 8.00 814 2.0 $ 8.00 814 $ 8.00

$ 12.00 814 2.0 $ 12.00 814 $ 12.00

$ 14.00 814 2.0 $ 14.00 814 $ 14.00

$ 16.00 815 2.0 $ 16.00 815 $ 16.00

4,071 2.0 $ 11.20 4,071 $ 11.20

For the year ended December 31, 2010, no amount (nominal in 2009) has been recognized for compensation cost of performance warrants granted.

The fair value calculation for performance warrants was not required during the years ended December 31, 2010 and

2009 as no performance warrants were granted or required a change in measurement.


8. Share Capital (continued)

Stock Option Plan

The Company has a stock option plan under which directors, officers, employees of, and providers of services to

the Company are eligible to receive grants of options. The exercise price and vesting period of options granted is

determined by the Board of Directors at the time of grant.

2010 2009

Weighted Weighted

Average Average



Outstanding, beginning of year 2,588 $ 11.54 2,582 $ 11.57

Granted 524 22.72 16 19.38

Exercised (29) 5.00 – –

Forfeited – – (10) 32.50

Outstanding, end of year 3,083 $ 13.50 2,588 $ 11.54

Exercisable, end of year 2,179 $ 9.12 2,012 $ 7.54

The following table is an analysis of outstanding and exercisable options as at December 31, 2010:

Outstanding Exercisable

Weighted Weighted Weighted

Average Average Average

Remaining Exercise Exercise

Number Contractual Price Number Price

Exercise Price ($/option) (thousands) Life (years) ($/option) (thousands) ($/option)

$ 5.00 – 9.99 1,690 2.0 $ 5.00 1,690 $ 5.00

$ 10.00 – 14.99 86 3.0 $ 12.50 86 $ 12.50

$ 15.00 – 19.99 15 5.9 $ 15.00 3 $ 15.00

$ 20.00 – 24.99 780 4.8 $ 20.00 215 $ 20.00

$ 25.00 – 29.99 3 6.3 $ 25.00 – $ –

$ 30.00 – 32.50 509 5.0 $ 31.80 185 $ 32.50

3,083 3.3 $ 13.50 2,179 $ 9.12

For the year ended December 31, 2010, compensation cost of $2.3 million ($2.1 million in 2009) has been recognized for options that have been granted.

The estimated fair value of options was calculated at the date of grant using the Black-Scholes model and the

following assumptions:

2010 2009

Weighted average fair value per option $ 7.65 $ 6.42

Expected volatility (percent) 25.0 25.0

Average risk-free interest rate (percent) 2.9 2.8

Expected life (years) 7 7



Performance Share Unit Plan

The Company has a performance share unit plan under which directors, officers, employees of, and providers of

services to the Company are eligible to receive grants of performance share units (PSUs). PSUs have an exercise

price of $0.01 per PSU and vest on dates determined by the Board of Directors at the time of grant, and for each

PSU exercised the holder will receive one common share. The PSUs outstanding at December 31, 2010 have a

weighted average remaining contractual life of 5.4 years.

2010 2009

Weighted Weighted

Average Average



Outstanding, beginning of year 404 $ 0.01 286 $ 0.01

Granted 236 0.01 163 0.01

Exercised (85) 0.01 (42) 0.01

Forfeited – 0.01 (3) 0.01

Outstanding, end of year 555 $ 0.01 404 $ 0.01

Exercisable, end of year 107 $ 0.01 63 $ 0.01

For the year ended December 31, 2010, compensation cost of $3.8 million ($2.6 million in 2009) has been recognized for PSUs that have been granted.

The estimated fair value of PSUs was calculated at the date of grant using the Black-Scholes model and the following

assumptions:

2010 2009

Weighted average fair value per PSU $ 23.53 $ 19.20

Expected volatility (percent) 25.0 25.0

Average risk-free interest rate (percent) 2.9 2.1

Expected life (years) 7 7

Share Appreciation Rights

On March 25, 2010, the Company established a share appreciation rights plan under which directors, officers,

employees of, and providers of services to the Company are eligible to receive grants of share appreciation rights

providing for cash payments equal to the excess of the market price of the common shares over the exercise price

of the right. The vesting period of the share appreciation rights is two years.

Number Weighted Average

(thousands) Exercise Price

Outstanding, beginning of year – $ –

Granted 36 26.88

Outstanding, end of year 36 $ 26.88

Exercisable, end of year – $ –

For the year ended December 31, 2010, compensation cost of $0.1 million (nil in 2009) has been recorded for the share appreciation rights that have been granted.


8. Share Capital (continued)

Per Share Amounts

Basic and diluted net loss per common share has been calculated using the weighted average number of common

shares outstanding during the years ended December 31, 2010 and 2009 of 45,812,000 and 37,252,000, respectively.

The calculation of diluted net loss per share does not include performance warrants, options or units as the effect

would be anti-dilutive.

9. Contributed Surplus

2010 2009

Contributed surplus, beginning of year $ 16,178 $ 11,816

Performance warrants granted – 39

Performance warrants exercised – (67)

Options granted 2,295 2,114

Options exercised (53) –

Performance share units granted 3,778 2,603

Performance share units exercised (1,726) (327)

Contributed surplus, end of year $ 20,472 $ 16,178

10. Commitments

As at April 6, 2011 the Company’s contractual and lease obligations for office space, communication equipment and

arrangements, drilling rig rentals, natural gas purchases, camp facilities and other obligations are as follows:

Office Field

2011 remainder $ 1,962 $ 7,714

2012 $ 2,734 $ 10,022

2013 $ 2,734 $ 8,399

2014 $ 2,750 $ 4,059

2015 and thereafter $ 2,303 $ 2,854

As at April 6, 2011, the Company had issued a $3.6 million letter of credit to a third-party partner to support the ongoing development of Saleski and Germain. If the development of these projects is interrupted the Company will be required to reimburse the costs incurred by the third-party partner up to $3.6 million. The letter of credit is renewed annually with the next renewal expected in July 2011.

11. Income Taxes

The provision for income taxes differs from the amount which would be expected by applying the combined

statutory income tax rates to income before income taxes. A reconciliation of the difference is as follows:

2010 2009

Loss before income taxes $ (3,433) $ (5,375)

Canadian statutory income tax rate (percent) 28.00 29.00

Expected income tax recovery at statutory rate $ (961) $ (1,559)

Increase (decrease) in income taxes resulting from:

Non-deductible costs 854 509

Reduction in effective tax rate 19 150

Future income tax recovery $ (88) $ (900)



The temporary differences that give rise to the future income tax assets and liabilities are as follows:

2010 2009

Future income tax liabilities

Capital assets $ 29,583 $ 27,819

Future income tax assets

Non-capital losses (7,898) (5,397)

Share issue costs (3,515) (2,183)

Capital losses (4,263) (4,263)

13,907 15,976

Valuation allowance 4,263 4,263

$ 18,170 $ 20,239

As at December 31, 2010 the Company has non-capital losses of $31.5 million which will begin to expire in 2025.

Changes in Non-cash Working Capital

2010 2009

Cash and cash equivalents provided by (used in):

Operating activities

Accounts receivable $ (6,116) $ (56)

Prepaid expenses and deposits 1 (39)

Inventory (254) –

Accounts payable and accrued liabilities 2,761 580

$ (3,608) $ 485

Investing activities

Accounts receivable $ (7,608) $ (2)

Prepaid expenses and deposits 11 91

Accounts payable and accrued liabilities 15,924 1,314

$ 8,327 $ 1,403

Financing activities

Accounts receivable $ – $ (1)

Accounts payable and accrued liabilities 40 3

$ 40 $ 2

Other Cash Flow Information

2010 2009

Interest paid $ 38 $ 34


13. Capital Management

The Company’s objectives when managing capital are to safeguard its ability to pursue the acquisition, exploration,

development and production of oil sands resources and reserves, and to maintain a flexible capital structure which

optimizes the costs of capital at an acceptable level of risk.

Laricina’s capital structure includes the components of shareholders’ equity, bank debt and working capital.

The Company does not have material producing operations and the primary assets consist of oil sands properties

for development. Accordingly, the Company may adjust capital spending, issue new shares, acquire or dispose of

assets, enter into joint venture arrangements or issue new debt to manage the capital structure. To date Laricina

has limited the use of debt primarily to the issuance of letters of credit and may consider alternative forms of debt

financing in the future.

The Company’s capital management objectives remained unchanged during the year ended December 31, 2010.

Laricina is not subject to externally imposed capital restrictions; however, the credit facility referred to in note 7 is

secured by a deposit of cash.

14. Financial Instruments

The Company is exposed to certain financial risks from its financial instruments, including credit risk, liquidity risk

and market risk.

Credit Risk

Credit risk is the risk that the counterparty to a financial asset will default, resulting in the Company incurring a financial

loss. This credit exposure is mitigated through credit practices that limit transactions according to counterparties’

credit quality. A substantial portion of the Company’s accounts receivable is with a small number of joint venture

partners in the oil and natural gas industry and is subject to normal industry credit risk and resolution processes

under the joint venture agreements. The maximum credit risk exposure associated with accounts receivable is the

total carrying value.

Liquidity Risk

Liquidity risk is the risk that the Company will encounter difficulties in meeting its financial liability obligations.

The Company manages liquidity risk through the management of its capital structure and timing of discretionary

expenditures to ensure it will meet its liabilities when due without incurring unacceptable losses or risking harm to

the Company’s reputation. Laricina prepares annual expenditure budgets that are monitored on a regular basis and

updated as necessary.

As at December 31, 2010, cash was held in a fully liquid, interest-bearing operating account and Laricina had

$11.4 million available in the bank credit facility to manage its expenditures, if necessary. Accounts payable and

accrued liabilities are expected to be paid in the first quarter of 2011.

Market Risk

Market risk is the risk that the value of financial instruments or future cash flows will fluctuate due to

movements in market prices, such as commodity prices. Oil prices, natural gas prices and heavy oil differentials

fluctuate significantly in response to regional, national and global supply and demand factors, as well as downstream

industry factors such as pipeline or refinery capacity additions or outages, all of which are beyond the control of

Laricina. The Company closely monitors commodity prices to determine the appropriate course of action to be

taken by the Company.


Abbreviations

The following is a summary of the abbreviations that have been used in this Annual Report.

bbls/d barrels per day

CSS cyclic steam simulation

EIA environmental impact assessment

IFRS International Financial Reporting Standards

km kilometres

mmbbls million barrels

m metres

PHARM passive heat–assisted recovery method

WTI West Texas Intermediate


Senior Management

Glen C. SchmidtPresident and CEO

Senior Vice President In Situ and Exploration

Neil R. EdmundsVice President Enhanced Oil Recovery

Karen E. LillejordVice President Finance and Controller

Marla A. Van GelderVice President Corporate Development

Vice President Production

George C. BrindleVice President Facilities

Directors2, 3

Senior Principal – Principal Investing

CPPIB Equity Investments Inc.

2, 3

Managing Director, Lime Rock Partners

3, 4C

Chairman, TransCanada Corporation

2, 4

President and CEO, Enerplus Corporation

Brian K. Lemke 1, 2C

Independent Investor

Robert A. Lehodey, Q.C. 3C, 4

Partner, Osler, Hoskin & Harcourt LLP

W. Glen Russell 3, 4

Principal, Glen Russell Consulting

Glen C. SchmidtPresident and CEO, Laricina Energy Ltd.

1 Chairman of the Board2 Audit Committee3 Governance & Human Resources Committee4 Technical CommitteeC Committee Chairman

Auditors

KPMG LLP

Bankers

Canadian Imperial Bank of Commerce

Solicitors

Osler, Hoskin & Harcourt LLP

Reservoir Engineers

Registrar and Transfer Agent

Equity Financial & Trust Company

Corporate Information


Saleski Pilot First Steam December 2010

Laricina Energy Ltd.4100, 150 – 6th Ave. S.W.Calgary, Alberta, Canada T2P 3Y7403-750-0810

www.laricinaenergy.com

Laricina Energy Ltd.

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