1st $796 $ ,000 + $628 million. $212 million 42, , million. 4.3 billion. $1.3 billion 204,316. million PV10.

Transcription

1 ANNUAL REPORT 2011

2 387 million bbls probable reserves 4.3 billion bbls contingent resources (best estimate) $1.3 billion cash equity raised since inception to apply sagd to grosmont carbonates 1st $628 million working capital (as at december 31, 2011) 204,316 net acres oil sands leases 2 pending, 1 approved 3patents $796 $10.2 million PV10 4 projects under active development before tax future net revenue of probable reserves before tax future net revenue of contingent resources (best estimate) 500,000 + bbls per day net production potential 42,500 bbls/d net installed capacity targeted in ,700 $212 million capital invested in 2011 gross bbls/d production under regulatory application See Reserves and Resources starting on page 34 and glossary and abbreviations on page 87. billion PV10 community based business education health, recreation and arts $315,000+ in community investment since 2007

3 the big picture who we are Laricina Energy Ltd. is focused on underground or in situ development of under-explored bitumen-bearing sand and carbonate reservoirs in the oil sands region of northeast Alberta. Since its founding in late 2005, Calgary-based Laricina has assembled a high-quality asset base of 10 high-working-interest properties, has delineated extensive resource opportunities totalling more than 12 billion net barrels of exploitable original bitumen-in-place, and has advanced two major development areas, Saleski and Germain. Readying the Saleski pilot for solvent injection and recovery. producing from the grosmont carbonate developing the grand rapids investing in value enhancing innovations 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 38 for additional information on forward-looking statements. In March 2011 Laricina s Saleski pilot project passed a key company and industry milestone the first bitumen produced using steam-assisted gravity drainage (SAGD) from the Grosmont carbonates. This year, Laricina is continuing construction of its Germain Phase 1 SAGD commercial demonstration project (CDP), with steam injection expected to commence in spring 2013, and is working towards full pilot production at Saleski, with a goal of proving the commerciality of the Grosmont carbonates before year-end Innovation has been a core component of our business model. The Company s work on technology enhancements aimed at increasing operational efficiency and resource recovery resulted in Laricina s first patent in 2011 with two further patents pending. Laricina has shown demonstrable success in raising equity capital from large, high-quality investors, with more than $1.3 billion raised since inception. 2 our diversified asset portfolio 4 big progression at saleski 6 big developments at germain 8 president's letter 16 our potential is big 18 operations review 34 reserves and resources 38 management's discussion and analysis 57 auditors' report to the shareholders 58 consolidated financial statements 62 notes to the consolidated financial statements 88 corporate information 1 Laricina Energy Ltd.

4 our diversified asset portfolio Peace River Red Earth Fort McMurray Wabasca-Desmarais Alberta Edmonton McMurray bitumen trend > 10 metres Grosmont subcrop Burnt Lakes Grosmont bitumen trend > 18 metres Nisku subcrop Grand Rapids bitumen trend > 10 metres Saleski Boiler Rapids Conn Creek Poplar Creek Fort McMurray House River Germain Thornbury West Wabasca Desmarais Thornbury Portage Laricina properties Annual Report

5 the big opportunity resources, assets, development carbonates Laricina is a proven industry leader as the first operator with initial thermal horizontal well bitumen production from the Grosmont carbonates, an enormous and undeveloped reservoir with an estimated 406 billion barrels of bitumen-in-place in Alberta*. grand rapids The Germain SAGD project, where the Phase 1 CDP is under construction, makes Laricina part of the industry s first wave in west Athabasca of developing the Grand Rapids Formation, a thick and consistent oil sands deposit with an estimated 54.6 billion barrels of bitumen-in-place in Alberta*. growth opportunity With Saleski advancing pilot production, Germain under construction, applications for growth phases filed, eight further properties in its asset base, de-risking of reservoirs and proving of recovery models underway, and a best estimate of 12 billion net barrels of exploitable original bitumen-in-place in its asset base, Laricina represents a major growth opportunity. innovation Multiple initiatives are underway that aim to lever Laricina s resource base and capital investment to create more value for shareholders by demonstrating recovery from the carbonates and by increasing future resource recovery and/or the per-barrel value of the resource. Last year Laricina was granted its first patent in Canada and the U.S., for the PHARM process, which is intended to more efficiently unlock the Company s dual-zone carbonate opportunity. * According to the Alberta Energy Resources Conservation Board (ERCB). 3 Laricina Energy Ltd.

6 big progression 1.8 billion net bbls best estimate contingent resource 282,500 bbls/d gross production potential 42,880 gross acres 60% working interest 1,800 bbls/d installed capacity 55,500 gross bbls blended bitumen sales (1) Two-thousand eleven was a big year at Laricina s Saleski pilot. Steam injection had commenced into the first well-pair, drilled to test the carbonate Grosmont Formation s D zone, just days before the year began. That was followed in January by steaming of the second well-pair, which is testing the C zone. In March 2011, the D well-pair produced its first bitumen. This was a history-making day for Laricina and the oil sands sector, because it was the first bitumen ever recorded from a horizontal well-pair in the Grosmont carbonates. The C well-pair produced its first bitumen in April. Cumulative blended bitumen gross sales from the two well-pairs totalled 55,500 barrels through the end of The year s positive results strengthened Laricina s expectations of achieving commerciality in the Grosmont. (1) For the year ended December 31, Annual Report Condensate and blend tanks.

7 Saleski operator checking process conditions. Throughout the year, Laricina s technical and field operations teams were continuously at work, fine-tuning the pilot s systems, conducting a series of well injection and production performance cycles, evaluating, developing and implementing operating refinements to garner reservoir understanding from the well-pairs, expanding steam capacity later in the year, and planning for one additional horizontal well-pair in bitumen production from the grosmont Saleski plant site with operations camp in the distance. Hauling blended bitumen to market. Laricina has a full program planned in This year the for its crude oil transportation system the Stony Mountain Company aims to substantiate its modified well drilling and Pipeline; and receive regulatory approval plus launch completions approach; ramp up production toward the construction of Saleski Phase 1, the first of five commercial pilot s design capacity of 1,800 barrels per day; demonstrate phases planned at Saleski, with Phase 1 expanding upon the commerciality of the Grosmont carbonates; advance plans pilot by 10,700 gross barrels per day. at saleski 5 Laricina Energy Ltd.

8 big developments 387 million net bbls probable reserves 1.4 billion net bbls best estimate contingent resource (grand rapids and winterburn formations) 205,000 bbls/d gross production potential grand rapids 40,000 bbls/d gross production potential winterburn 44,161 gross acres 100% working interest 5,000 bbls/d capacity under construction Construction is underway on Laricina s Germain CDP Phase 1 of the Company s five-phase development plan in the Grand Rapids Formation, with a sixth phase in the Winterburn carbonate. Germain is a dual-resource play. It targets the Grand Rapids Formation, a thick and consistent bitumen-bearing sand reservoir, and the Winterburn carbonate, a shallow marine Upper Devonian dolomite reservoir like the Grosmont. The CDP has a planned capacity of 5,000 barrels per day, with an estimated cost of approximately $435 million, including natural gas, power and road infrastructure. In 2011 Laricina drilled the project s first six horizontal injector-producer SAGD well-pairs, as well as vertical observation and water source and disposal wells. An estimated 40 well-pairs from three well pads will be required over the life of the CDP. Engineering and procurement continued throughout the year and towards year-end Laricina completed earthworks at the central processing facility (CPF) site. Also in late 2011, Laricina submitted its regulatory application for Germain s Phase 2-4 expansion of 150,000 barrels per day Annual Report Germain CDP plant site and well pad ready for construction.

9 Drilling operations at Germain. FPO The CDP will be started up using conventional SAGD. As at Saleski, Germain s operations will later be converted to solvent-cyclic (SC) SAGD. By combining solvent injection with steam, Laricina anticipates SC-SAGD lowering the steam-tooil ratio (SOR) by an estimated one third. This will increase capital and operating efficiencies, lower energy consumption, and thereby also generate environmental benefits. Super-single rig drilling the slant horizontal wells at Germain. Camp expansion at Germain. Developing road infrastructure to Germain. strong progress in the commercial demonstration project As of mid-march 2012, Laricina had: Construction of the Germain CDP will continue throughout Laricina anticipates initiating steam injection in spring The Company also plans to commence Phase 2 engineering this year. The remaining four horizontal well-pairs planned for the Germain CDP will be drilled as required. for start-up; and at germain 7 Laricina Energy Ltd.

10 president s letter "Laricina has proved it is up to the complexities of the in situ development cycle to date and we are well prepared for the challenges ahead." In 2011 Laricina launched oil production at its Saleski pilot and advanced field activities at its Germain Phase 1 CDP, including drilling six horizontal well-pairs. Under the Company s phased growth plan these first two projects are moving toward commercialization as we advance on our medium-term goal to achieve 42,500 barrels per day of net installed capacity in While the potential scale of more than 500,000 barrels per day in combined gross production potential from Germain and Saleski is impressive, looking at how we have progressed to date helps define our confidence in achieving what lies ahead. Our 2011 targets included demonstrating that the Grosmont carbonates at Saleski are producible, advancing Germain at all levels, building our external relationships with regulators, the community and shareholders, and adding new capital. I am pleased to report that our goals were met in The past year was the Company s sixth operating year and we advanced across our spectrum of operations. We continued to lead in situ project development in the west Athabasca region, in both the Grosmont carbonates and the Grand Rapids sands. We continued to push forward with innovation in thermal solvent recovery, positioning future enhancements in extraction. We continued work on regulatory filings, maintaining our tempo of activity and preparation for future expansions. We worked closely with local communities to maintain their support. We expanded capacity in our people and infrastructure. We conducted two equity private placements, raising a combined $520 million from high-quality investors. We identified the challenges of project costs as well as a path forward to manage them. Laricina has demonstrated it is up to the complexities of the in situ development cycle to date and we are well prepared for the challenges ahead. The number of employees in our offices field, Calgary and Wabasca grew to more than 120 at year-end 2011 from only eight at inception. We also have a significant number of engaged consultants that are focused on our projects and their execution. The Company s $3 billion capitalization at the time of our summer 2011 financing was approximately 40 times the size of our first financing of $77 million completed in late We are well-funded to carry out our 2012 plans, exiting 2011 with $628 million in working capital. We will invest a further estimated $2 billion through 2015 to achieve our medium-term goal of net installed capacity of 42,500 barrels per day. This is an ambitious target that will deliver the value that we and our investors are seeking. Given Laricina s record, this is of a scale and staging that we believe we are capable of executing Annual Report

11 Advancing Our Key Projects Saleski The Saleski pilot in 2011 demonstrated the ability to produce bitumen from the Grosmont Formation, a crucial milestone in Laricina s path towards validating the carbonates as a commercial oil sands reservoir. Following commencement of steam injection in December 2010, first oil was achieved in March 2011 and cumulative blend oil sales totalled 55,500 gross barrels to the end of December We are continuing to validate our opportunity in the Grosmont and we are excited by the progress. Our main focus in 2011 was testing a horizontal injection-production well-pair in each of the Grosmont C and D horizons, with the goal to establish performance curves for each. Through this production cycling process we have gained understanding regarding optimization of well start-up, the volumes and timing of steam injection and production testing cycles, the development of the steam chamber along the well-bore and general thermal performance information. Our initial testing experience suggests continued injection and production cycles using horizontal wells is an efficient start-up process in this reservoir. We ended the year well along the path to establishing the initial performance curves and we anticipate demonstrating longer-term performance from each of the wells in Plans for 2012 include production optimization through further steam injection and production testing cycles, advancing production performance curves, drilling and start-up of an additional well-pair to test a managed pressure (or balanced) drilling technique, declaration of commerciality in the Grosmont carbonates, and the initiation of solvent-cyclic or SC-SAGD. The year s results increased our confidence, and the ongoing learning is creating the bridge from the pilot to the commercial project. We anticipate regulatory approval by mid-year of the 10,700 barrel-per-day Saleski Phase 1 commercial expansion, alongside continuing engineering and procurement, with civil construction planned before year-end, subject to additional funding. Glen Schmidt, Laricina President and CEO. Germain Germain s strong advancements with the Phase 1 CDP throughout the year included drilling of six horizontal SAGD well-pairs, completion of civil construction in September, advancement of detailed engineering and commencement of module procurement. In November we also filed the 150,000 barrel-per-day expansion application and continue to advance this through the regulatory process. 9 Laricina Energy Ltd.

12 From left to right: Derek Keller, VP Production; Karen Lillejord, VP Finance and Controller; Melanie Schmidt, Director Corporate Services; Glen Schmidt, President and CEO; Marla Van Gelder, VP Corporate Development; Neil Edmunds, VP EOR; Dave Theriault, Senior VP In Situ and Exploration. "Our job as a management team is not simply to identify risks but to evaluate how we will manage them and seek opportunities to overcome the current environment s challenges." We were pleased to see strengthening external validation of the initial SAGD well performance expected for Germain. Recently Grand Rapids pilots operated by two peers in the region have demonstrated SAGD production ramp-up similar to the benchmark set in the Wolf Lake Grand Rapids project, in typical McMurray projects and in our own simulations. The Grand Rapids sands present relatively low technical reservoir risks. The overall Grand Rapids opportunity is that of a very large early-stage reservoir, with a clear path towards long-term value creation through a combination of economies of scale plus productivity gains and technology enhancements such as SC-SAGD. Having filed the industry s first Grand Rapids commercial application in the west Athabasca region and having the largest such project under construction, Laricina is advancing Germain with confidence and remains a leader in this region as industry interest and involvement grow. As of mid-march 2012 six horizontal well-pairs have been drilled and completed for start-up, facility engineering is nearly complete, fabrication of modules is progressing, field construction is advancing with piling well underway, and equipment modules are being moved to the field for installation Annual Report Capital Management and Project Cost Control One of the largest challenges to our project plans is the accelerating pace of activity in the oil sands sector, which has brought back the pressures on costs and procurement timelines seen a few years ago. Our job as a management team is not simply to identify risks, but to evaluate how we will manage them and seek opportunities to overcome the current environment s challenges. In response, we expanded our benchmarking review of industry best practices in project management and execution, initiated a rigorous scope review of all project elements with a view to eliminating unnecessary scope and costs, as well as managing the timing of projects to optimize costs, and identifying any opportunities for savings. In 2012 we continue to work towards improving the cost efficiency of our projects in view of the current cost estimates for Germain Phase 1 and the 10,700 barrel-per-day Saleski Phase 1.

13 Leadership in Understanding Since inception Laricina has focused on gaining and maintaining leadership in understanding in situ oil sands. Our initial strategy was to identify and capture large project opportunities in new areas. This we did with Saleski and Germain, and most recently Burnt Lakes. Concurrently we sought to understand the carbonate and sand reservoirs for each asset, and then progress into development. Laricina s success in leading by understanding is borne out by the industry s response. At Germain our Phase 1 CDP has been followed by pilots of two other operators and, following our 150,000 barrel-per-day expansion application in November 2011, four other commercial developments were filed or announced. There are now 600,000 barrels per day of filed or planned applications for Grand Rapids projects. Additionally, following start-up of our Saleski pilot, four other Grosmont carbonate pilots were announced or filed by operators in the area, supporting Laricina s strategy of targeting big-untapped-potential resources. These events highlight the west Athabasca region as the newest significant in situ development region, where Laricina is firmly established with large leases, delineated resources, infrastructure and projects in development. Enhancing in situ development techniques is another area where Laricina demonstrates leadership to increase understanding of its assets. Thermal solvent extraction at a relatively early stage is part of the Saleski and Germain projects another example of gaining new understanding and then leading with what we know in shaping future project phases. We see it improving many dimensions including the expected ultimate recovery of oil-in-place, the SOR, and the per-well productivity. Higher well rates and a lower SOR support a project s overall capital efficiency, which in turn supports increasing the net present value. Building Capability While understanding what needs to be done is the starting point, building the capability and capacity to execute is a requirement for success. This centres on people. Led by a strong and experienced leadership team, Laricina employees and consultants have expanded industry understanding of oil sands reservoirs and opportunities, and they have driven continual innovation and improvement. In 2011 we added approximately 40 people in a competitive labour market and exited the year with more than 200 employees and consultants, including 27 employees in the field. Laricina worked on strengthening its commitment to the advancement of education, technology and innovation by continuing its partnership work with the University of Calgary and the academic community. In 2011 we invested or committed over $1 million in funding research, student scholarships and much-needed facilities in support of the U of C s Engineering Leaders campaign, and we continued to co-author several papers and presentations with the engineering faculty that were focused on enhancing oil sands development. We also continued to validate our relationships with the community and regulators. In 2011 we remained engaged with local communities on multiple levels, from employing local contractors to holding town-hall meetings to involvement in educational and cultural events, and we continued to garner community support. 11 Laricina Energy Ltd.

14 Laricina Calgary office employees planning for Germain development. Saleski field operations crew. "Led by a strong and experienced leadership team, Laricina employees and consultants have expanded industry understanding of oil sands reservoirs and opportunities, and they have driven continual innovation and improvement." 2012 Priorities and Goals Our key priorities for 2012 are to further advance the Saleski pilot and remain on-track with construction at Germain for start-up of the CDP in the second quarter of Our capital and operating budget is roughly $470 million and will cover executing all project work planned for 2012 as well as regulatory work to advance the next phases at both projects. Our 2011 financings met their key objective of providing for Saleski and Germain through With opening 2012 working capital of $628 million, we are well-financed for the year. Additional financing will be required to advance our next project phases and to meet our key medium-term goal of achieving installed capacity of 42,500 barrels per day in Phase 2 at Germain and Phase 1 at Saleski, together with infrastructure, delineation and other corporate needs, require an estimated $2 billion in additional funding over the next few years. The economic environment, receptive capital markets and continued success at Saleski and Germain are the critical factors for Laricina to meet its next financing requirements. As before, we will examine the range of private and public markets as well as debt and potential joint-venture structures as possible capital sources. Building our internal capacity to achieve effective capital cost management as we grow is also a major ongoing priority and we are committed to achieving the best balance of cost and schedule with each component, of each phase, of each project. Laricina s major goals for 2012 comprise: - Advancing the Saleski pilot through further testing cycles and refinement, establishing well type production curves for the Grosmont, and initiating solvent operations, with the overall goal of demonstrating competitive commercial performance in the Grosmont carbonates; - Progressing construction of the Germain CDP on schedule and budget; Annual Report

15 - Advancing engineering and procurement of the 10,700 barrel-per-day Phase 1 expansion at Saleski, with civil construction and drilling operations initiated before year-end; and - Demonstrating cost containment on actual spending at Germain and improvements in the cost estimates for Saleski Phase 1. - Receiving approval by mid-year for Saleski Phase 1; and - Advancing Germain Phase 2 for the next 30,000 barrel-per-day expansion, to remain on-track for late-2013 approval. - Securing the capital required to advance the next expansion phases through the end of Political and Commodity Price Outlook With an uncertain global political outlook for 2012, the economic environment and commodity prices carry as much or more risk than in prior years. Despite this, year-ahead forecasts for economic performance are modestly positive, among them the outlook for slightly improved economic growth in the United States and low but measurable growth in Canada. This trend appears to be reflected in crude oil prices. The the year, suggesting both increased strength and reduced volatility as we entered The commodity markets, therefore, could be reinforcing the view of a slightly more positive economic outlook. for lower natural gas prices are both supportive of oil sands development. With the right scale and technical execution, in situ oil sands development achieves top-quartile economics within the Canadian oil sands sector. Adequate export transportation will be crucial to the oil sands sector s longer-term growth. With the delay of the Keystone XL pipeline in the U.S., Canada faces an important test as to whether the approval process for the Gateway oil sands pipeline to the West Coast can avoid needless delay. The political will being shown by the federal government to achieve an efficient review process for Gateway inspires confidence as the need for access to new markets is understood. We have proven much in building Laricina to a $3 billion enterprise with current in situ oil sands production and two large projects under development. It is the superb people at Laricina who are driving this performance and I extend thanks and appreciation for their hard work. Our ambition is to continue advancing our projects in I am proud to share this ambition and to be part of the exemplary team at Laricina, and am looking forward to sharing further news of the Company s performance in the year ahead. (signed) "Glen C. Schmidt" Glen C. Schmidt President, Chief Executive Officer and Director March 21, Laricina Energy Ltd.

16 a big team the proof is in our people The range and depth of strengths and qualities in Laricina s human capacity and capability are driving the advancement of our projects. Our people not only create the core of our ability to execute, but strengthen risk management in every aspect of our business. With a current team of over 120 employees among our community office, field operations and Calgary head office, as well as many more consultants, contractors and sub-contractors, Laricina is proud of the quality and talent illustrated by its team. Our team has shown an incredible ability to work together, with a positive attitude, to reach our big ambitions Annual Report

17 accomplishing big things safety from office to field At Laricina safety is at the core of our operations. From the office to the field, we strive to create a transparent safety culture that promotes the accurate reporting of incidents. Our safety management system also incorporates leading indicators, with the goal of reducing the potential for accidents by understanding the key areas of risk, educating workers on those risks and providing clear corrective actions where needed. The health and safety of our employees, sub-contractors and the public is a top priority. Laricina has created and implemented written standards and practices to communicate our safety expectations to our personnel. We emphasize safety training and competency, and communicate safety regulations and practices through regular meetings and yearly training sessions. Prior to commencing work at Laricina, all workers receive safety orientation, as do all visitors to our field operations. finding our own path The willingness and courage of the people at Laricina to continue to explore and inquire about what s possible drives Laricina forward and has been foundational to our success. We have worked from the belief that we need to understand how, what and why things happen. The basis of our work is grounded in a passion for, innovation, creativity and teamwork. As we continue to grow, we travel along the same path of encouraging and fostering a culture in which we value open communication and sharing our knowledge with one another. 15 Laricina Energy Ltd.

18 our potential is big Burnt Lakes 63 R25 R24 R23 R22 R21 R20 R19 R18 R17 R16 Boiler Rapids Conn Creek Poplar Creek Fort McMurray T86 T85 Saleski House River Germain Saleski T84 Germain Wabasca Desmarais Thornbury West T Highway Al-Pac road Germain road Portage 63 Thornbury Saleski road Planned Crisp road Proposed Burnt Lakes access road Wabasca-Desmarais Athabasca River T82 T81 Germain and Saleski are well positioned relative to existing infrastructure. saleski germain project pilot phase 1 phase 2 phase 3 phase 4 phase 5 phase 1 phase 2 phase 3 phase 4 phase 5 phase 6 winterburn other conn creek projects poplar creek burnt lakes phase 1 burnt lakes phase 2 staged development 754 Stony Mountain pipeline and terminal Gas pipeline ATCO 240kV powerline and substation Proposed powerline and substation Highway Road Bridge Plant site T80 The current engineering, drilling and construction schedules may not proceed as planned. Delays in obtaining, or conditions imposed by, regulatory approvals may affect the current development timing. Start-up refers to initial steaming of the wells, with full production expected 12 to 18 months after start-up. Regulatory review & pre-engineering Engineering, drilling & construction Regulatory approval Start-up Annual Report

19 2012 and beyond Company founded in November Acquires leases at Germain, Saleski and eight other properties. Delineation drilling commences to establish resource base. Reservoir technical studies and laboratory simulation are conducted. Regulatory applications for Germain pilot filed Regulatory applications for Saleski pilot filed. Road constructed to Germain pilot site. Project modelling, planning and testing. Key approvals for Saleski and Germain pilots received. Amended Saleski pilot application. Amended and enlarged Germain pilot to CDP application. Construction for Saleski pilot commences. Additional leases acquired at Burnt Lakes Construction of Saleski pilot completed, with horizontal well drilling in 2010 and steam injection beginning that December. Field operations team is built. First bitumen produced in March Steaming, production testing, evaluation and modification throughout Saleski Phase 1 commercial application (10,700 barrel-per-day expansion) filed. Acquisition of additional Burnt Lakes leases. Germain CDP approved in October Well drilling, site preparation, engineering and procurement progress throughout Germain Phase 2-4 commercial expansion application filed in late Demonstrate commerciality in carbonates at Saleski and ramp-up pilot production. Initiate construction of Saleski Phase 1 in late At Germain, continue CDP construction throughout 2012, commence steam injection for SAGD operations in spring 2013 and realize first production by fall. Continue 30,000-barrel-per-day Phase 2 regulatory, engineering and procurement processes. Launch Phase 2 construction in 2013, target first steam from Phase 2 in late Laricina s oil sands asset base comprises 10 properties covering a total of approximately nine townships of land are held at 100 percent working interest except for Saleski, where Laricina holds a 60 percent working interest, and together provide exposure to four bitumen-bearing geological formations: the McMurray and Grand Rapids sands, and the Grosmont and Winterburn carbonates. Two of Laricina s properties Saleski (Grosmont carbonate) and Germain (Grand Rapids sand) are in an advanced stage of development. Testing cycles of thermal horizontal well production commenced at the Saleski pilot in March 2011 and Germain CDP is under construction, with steam injection for SAGD operations anticipated to begin in the spring of next year. Several other properties are partially delineated, while the remainder are undeveloped and provide future opportunities for growth. Laricina s development strategy entails building its projects in manageable-sized phases. This is consistent with Laricina s view of responsible development of the oil sands resource, facilitating successive economies of scale while permitting ongoing optimization and innovation, ultimately maximizing value for shareholders. Phasing enables Laricina to integrate knowledge gained and lessons learned. It allows for more controlled risk management concerning capital availability, labour sourcing, project execution and project timelines. It contributes to cost containment by taking advantage of standard equipment and module sizing, transportation and logistics. It facilitates accommodation of stakeholder concerns, and it contributes greatly to workforce management. As projects progress, their individual phases will increase from approximately 10,000 barrels per day to At full planned build-out, Saleski and Germain would have combined bitumen production capacity of approximately 527,500 gross barrels per day. Laricina's development approach is using underground or in situ recovery processes that reduce land disturbance and avoid the need for large surface mines and tailings ponds. Laricina s project plans include complementing thermal gravity drainage recovery processes with solvent in the Grosmont and Grand Rapids. The Saleski-Germain area has seen steady improvement in infrastructure, which was virtually nonexistent when Laricina became active in the area in Both projects are served by an all-weather road built by Laricina connecting to the nearby Al-Pac Chipewyan Lake forestry haul road. Natural gas service was installed at Saleski in 2010 and is being installed at Germain in The Saleski pilot is currently self-generating power while Germain will be connected to the main power grid in mid-2012 and Saleski in mid Non-potable water is sourced from and disposed of in approved underground wells. Permanent work camps at each site support the construction and operations staff. 17 Laricina Energy Ltd.

20 operations review proving saleski recovery model Like the Germain CDP, Saleski Phase 1 is expected to use Laricina s proprietary SC-SAGD process. SC-SAGD involves the phased co-injection of solvents and steam, with the steam injection rate declining as solvent is injected into the steam chamber formed around the well-pair. Laricina will utilize combinations of heavier hydrocarbons (C 5 +, diluent or condensate blend) and lighter hydrocarbons such as propane. Laricina expects SC-SAGD to achieve a reduction in the cumulative SOR, improve bitumen flow rates and overall resource recovery, and reduce natural gas consumption and water use, in turn lowering carbon emissions intensity (emissions per unit of production). Activities at the Saleski pilot comprise a series of steam injection and production testing cycles of the Grosmont carbonates using horizontal well-pairs supported by vertical observation wells. Data from each successive cycle builds up a baseline of knowledge that helps Laricina refine how the Company drills, completes and operates wells to achieve successful, sustainable production. The detailed understanding learned during this start-up stage can be applied in existing and subsequent wells, which will in turn supply further data to support the Phase 1 commercial expansion recovery model. Fundamentally, the purpose of the Saleski pilot is to position Laricina to move to a commercial in situ development of the Grosmont carbonates, with a first phase of 10,700 barrels per day gross. The pilot s specific goals are to: commercial thermal horizontal well productivity that meets or exceeds the McMurray oil sands benchmark of 600 barrels per day per well-pair at a steam-oil ratio of 3.0:1; and performance curve benchmarking; development in the Grosmont; development. Saleski pilot. Lorem ipsum dolot Annual Report

21 Laricina is pleased with the Saleski pilot s overall performance in 2011 and the initial steps toward reservoir production performance. The pilot s CPF delivered outstanding plant steam generator availability. The Grosmont carbonates are producing little to no solids, confirming the solids control liner design and the consolidated character of the rock, and the metal-to-metal progressive cavity pump is effective for the current operating conditions. A series of injection and production cycles were run throughout 2011, which advanced steam chamber development and reservoir performance. Through this production testing process we gained understanding regarding optimization of well start-up, the volumes and timing of steam injection and production testing cycles, the development of the steam chamber along the wellbore and general thermal performance. Injection and production testing cycles underway at the pilot. In summary, the approach Laricina has taken with the pilot will allow the reservoir to describe itself through empirical field evidence, which is provided from the ongoing production and injection tests. The initial well-pairs were drilled and completed as simply and practically as possible, with the basic objective of being able to demonstrate reservoir performance. In 2012 Laricina is moving to further understand the thermal horizontal well recovery process from the reservoir and optimize follow-on well-pairs. Additional cycles of production and injection testing to support the direction chosen for the start-up and long-term thermal recovery method in each of the C and D zones are expected. Moving Grosmont bitumen to market. 19 Laricina Energy Ltd.

22 operations review what are we learning The Saleski pilot, as previously reported, encountered slower well performance development in both the C zone and the D zone well-pairs due to restricted fluid inflow from near well-bore impairment caused by drill cutting losses plus mechanical well operating issues, which were addressed. Laricina s solution to the fluid inflow restriction was stimulation of each well-pair to remove the blockage. The well stimulations were carried out in November and December, 2011 and demonstrated favourable response. A new well-pair is also being added to the pilot, to incorporate drilling techniques expected to drive down the cost of future well-pairs and avoid the reservoir impairment. The well-pair horizontal laterals are being drilled with a balanced pressure drilling system with the goal of avoiding the loss of drill cuttings. The new well-pair was drilled into the C zone in early 2012 and was completed open-hole. The well-pair s horizontal sections were drilled 450 metres and the spacing between the injector and producer was reduced from that in the previous two well-pairs, to enhance early start-up. Steam injection is planned to commence in the second quarter, with initial bitumen response anticipated three to four months thereafter. Production and injection cycles in the other two well-pairs are continuing. In executing the Saleski pilot one step at a time, Laricina had installed the steam capacity needed to develop individually sequenced well-pairs. Increasing the number of steam cycles during this early stage in each of the first two well-pairs and adding a well-pair gave rise to the need for additional steam. In the third quarter of 2011 Laricina filed a regulatory application to add the second 50 MMBtu steam generator. It received timely approval in November 2011 and the equipment was installed before year-end, under budget. Following some de-bottlenecking of associated water source systems, currently underway, combined steam-generating capacity at Saleski is expected to reach 5,280 barrels per day (850 cubic metres) of cold-waterequivalent dry steam in the second quarter of Saleski steam generator Annual Report

23 the road to commercial development 2012 pilot objectives Laricina s main goals at the Saleski pilot this year are to: capital management and cost control In response to intensifying risks of cost escalation throughout the oil sands sector in 2011, Laricina extended its project time-frames while strengthening its internal cost management capabilities (see Germain project section). The added steam capacity at Saleski was installed at 20 percent below forecast cost within a tight time-frame, and the practices that led to this success will be applied in carrying out the Phase 1 expansion. In addition, every element of Phase 1, currently budgeted at $660 million gross, is being carefully examined for further cost reduction opportunities. C and D zones under various thermal horizontal well operating parameters; in the Grosmont; drilled well-pair for future drilling; and The goals for the new well-pair are to demonstrate cost reductions by improving drilling time, reduce risk and non-productive time, and avoid near-well-bore impairment from drill cutting losses. In short, to provide a line-of-sight to a cost competitive commercial well-pair and achieve an optimized start-up. The approach taken with this well-pair will provide a model for the Saleski Phase 1 commercial well-pairs. In addition, the Company will continue gathering data, running tests and implementing myriad refinements as experience is gained in the pilot, with a view to transferring the new understanding to the Phase 1 expansion. Setting up the rig to drill horizontal well-pair at Saleski. 21 Laricina Energy Ltd.

24 operations review saleski development plan saleski phase1 Following the Saleski pilot s demonstration of commerciality in the Grosmont, Laricina s next goal will be to achieve full pilot production of 1,800 barrels per day. Following this the Company plans a series of phased expansions to ultimate capacity of more than 282,500 gross barrels of bitumen per day. Phase 1 will integrate the Saleski pilot and expand capacity into a 12,500 gross barrel-per-day commercial facility. Regulatory approval of the Phase 1 application, filed in December 2010, is expected in the second quarter of saleski phase 1 timeline current schedule public consultation process regulatory review engineering and module fabrication drilling and completions field construction start-up Saleski Development Plan R20 R19 R18 W4 T86 Layout of Saleski pilot and Phase 1 development plan with initial well pads and corresponding infrastructure and facilities. N T85 3-D Seismic area 4-D Seismic area Phase 1 project area Phase 1 plant and well pad Pilot plant and well pad Camp site Borrow pit Future well pad, road and pipeline Road Gas pipeline Proposed Stony Mountain pipeline and terminal Road and pipeline Water disposal well Water source well Proposed powerline and substation ATCO 240kV powerline and substation T Annual Report

25 phase 1 timing With regulatory approval anticipated in the second quarter of this year, Laricina aims to launch Phase 1 field construction in the third quarter, subject to additional funding. The initial focus will be on drilling the first 16 well-pairs aimed at establishing 10,700 barrels per day of productive capacity. Over the next two years Laricina will carry out the other building elements, including engineering, module sourcing, fabrication, installation, site construction and commissioning. First steam is planned for the fourth quarter of 2014, with first Phase 1 oil expected approximately three to four months thereafter, and full production achieved 12 to 18 months after start of production. phase 1 project elements Like Laricina s Germain CDP, Saleski Phase 1 has three main physical elements: will be 16 well-pairs initially, with an ultimate total of 60 well-pairs over the 20+ year life of Phase 1; fluids are blended, separated and/or treated. The Saleski Phase 1 CPF s primary capacities will be 400 MMBtu of steam generation and a production rate of 10,700 barrels per day, equivalent to an operating SOR of 2.6; and pilot location, will take advantage of existing components, including site roads, fuel gas pipelines, water source and disposal wells and associated pipelines, communications and the construction and operations camp. Electrical power will be supplied via a new substation linked to a main 144 kv line that is nearby. The ATCO Livock substation being built for the Germain CDP will also serve as the tie-in point for Saleski, enabling a relatively simple and cost-effective interconnection to serve Phase 1. marketing and logistics Initial pilot production is being trucked to regional terminals. The sale price for Grosmont blended bitumen at Saleski is matching pricing from similar McMurray sands projects. Condensate to dilute bitumen for transport and handling is being supplied from the Edmonton area. Efficient, cost-effective and safe marketing of Saleski s larger future volumes mandates a permanent pipeline connection. Laricina has formulated plans for a 184-km-long system the Stony Mountain Pipeline. It will include a 24-inch line to transport bitumen blend and a 12-inch line to bring in condensate for blending and potential use in SC-SAGD. The Stony Mountain Pipeline will run from Saleski to a connection point at the Enbridge Pipelines Inc. Cheecham terminal south of Fort McMurray. Stony Mountain is the first regional pipeline initiative in the west Athabasca region. Laricina anticipates interest from other project operators in accessing take-away capacity from the producing region to Cheecham. Laricina intends to file regulatory applications by mid-year, with construction beginning in late 2013 and the pipeline entering service in mid Laricina is considering a range of alternative commercial structures and financing sources that maximize the strategic benefits of the Stony Mountain Pipeline. future phases Following Phase 1, Laricina plans five additional expansion phases to achieve production of 282,500 gross barrels per day at Saleski, a rate that would be sustained for 30 years. per day. This year Laricina will begin collecting environmental baseline data to prepare for an EIA and project applications for Saleski Phase Laricina Energy Ltd.

26 operations review on track at germain cost management strategy With accelerating oil sands activity and a tightening supply chain increasing the risks of project cost escalation, Laricina in 2011 extended the time-frame for the Germain CDP while implementing a full cost analysis including benchmarking of cost management best practices and a rigorous scope review of all project elements, to identify potential savings and contain go-forward costs. The current cost estimate of $435 million for the Germain CDP includes approximately 15 percent contingency on the CPF. In addition, to maintain our estimate we are working to manage an additional five to seven percent uncertainty due to current cost pressures. The Company remains committed to improving and is working across-the-board to reduce costs. Initial success in bringing the Saleski pilot s steam addition in under-budget in fall 2011 was a promising step. Progress throughout 2011 was steady at Laricina s Germain CDP, which is Phase 1 of its development plan for the Grand Rapids sand reservoir. The CDP has a planned capacity of 5,000 barrels per day using SC-SAGD, with an estimated cost of approximately $435 million, including natural gas, power and road infrastructure and initial sustaining well-pairs. Project start-up signalled by commencement of steam injection for initial SAGD operations is anticipated in spring of An estimated 40 well-pairs from three well pads will be required over the life of the CDP. Laricina s simulations forecast Germain SC-SAGD performance to be comparable to the typical McMurray sands SAGD performance of 600 barrels per day per well-pair. After starting under ordinary SAGD, the CDP will be converted to SC-SAGD (like Saleski, see previous pages). By combining solvent injection with steam, Laricina anticipates lowering the total project SOR at Germain by approximately one-third. Once SC-SAGD is proven, this reduction will generate significant gains in capital and operating efficiencies in future phases project activities The year opened at Germain with a drilling program of 18 vertical development wells, of which eight are observation wells and reservoir evaluation wells, and the remaining 10 are water-related wells. Drilling horizontal well-pairs at Germain CDP with plant site and camp in the distance. Over the summer Laricina drilled six horizontal injectorproducer well-pairs for future SAGD and SC-SAGD recovery. All were drilled on target and had liners installed, with wire-wrapped screens placed in two of the producers to determine if production is enhanced by reducing pressure drop across the liner. Following this, steam injection strings were installed in all 12 wells, readying them for start-up. One of the well-pairs will test vacuum-insulated tubing, an innovation intended to reduce operating costs by reducing heat loss to the overlying formation. The project s regulatory approval associated with the measurement, accounting and reporting plan was received in late The remaining four horizontal well-pairs planned for the Germain CDP will be drilled as required Annual Report

27 germain cdp advancing state of the project february 2012 Work on the well pad facilities and CPF continues to progress. Approximately 80 percent of the detailed engineering is complete. Procurement of the long-lead items was completed in December Earthworks for the well pad and CPF were completed in October 2011 and piling commenced in January In connection with its cost management strategy (see opposite page), Laricina has embarked on a value engineering exercise and reduced the initial 81 modules to 77 while maintaining full CPF capability. Fabrication has commenced and shipped to site by early March To accommodate the full scope of work, the Germain construction camp was enlarged to over 500 beds in November germain CDP timeline current schedule public consultation process regulatory review engineering and module fabrication drilling and completions field construction start-up infrastructure The 22-km fuel gas pipeline was laid in 2011 and the metering station is to be installed by the third quarter of 2012, with the system to be operational in September. Regulatory approval was received in April 2011 for the ATCO Livock to Germain 144 kv transmission line. Construction of the required two new substations is underway, the power line right-of-way was cleared over the winter, and electricity from the Alberta grid is expected to be available at Germain by July Illustration of Germain CDP. 25 Laricina Energy Ltd.

28 operations review development milestones at germain phase 2 work plan Laricina is initiating the Phase 2 front-end engineering and design study in the third quarter germain commercial expansion In November 2011 Laricina submitted a regulatory application with Alberta Environment and Water and the ERCB for a three-phase, 150,000 barrel-per-day expansion of the Germain Grand Rapids development. Phase 2 (Phase 1 being the current CDP) will be a 30,000 barrel-per-day facility, while Phases 3 and 4 will each add capacity of 60,000 barrels per day. of 2012, with completion anticipated by year-end. Commitments for long-lead items could begin in the fourth quarter of 2012, subject to additional financing. Detailed engineering is anticipated to commence in January An estimated 60 initial well-pairs drilled from six well pads will be required for start-up of Phase 2, with drilling anticipated to commence in late 2013 or early Phase 2 first steam is anticipated in the fourth quarter of phases 2, 3 and 4 Pending financing and regulatory approval, anticipated in mid- to late-2013, Phase 2 construction would commence in 2013 with first steam planned for the fourth quarter of Construction of Phases 3 and 4 would commence in 2016 and 2018, respectively, with first steam in 2018 and 2021, respectively. Like Phase 1, the expansion phases will use a combination of SAGD and SC-SAGD. Phase 2 may utilize either SC-SAGD or SAGD and the facility is being designed for flexibility in steam requirements. germain phase 2 timeline current schedule public consultation process regulatory review engineering and module fabrication drilling and completions field construction phase 2 start-up future phases 3-4 start-up Annual Report

29 project design Each phase will have its own CPF and a series of well pads, while drawing on phased expansions, where required, of existing power, natural gas, road and water infrastructure, so as to optimize use of capital and minimize overall land disturbance. The CPF of phases 2-4 will encompass only 2.5 square km over a lease area of 77 square km. The combined development will ultimately have up to 74 multi-well production pads over its anticipated 30-year operating life, supporting up to 1,160 horizontal well-pairs. Laricina intends to use double-sized well pads in future expansions where possible, supporting 20 well-pairs each, limiting the overall physical footprint. winterburn carbonate opportunity As part of its staged long-term development plan, Laricina also intends to exploit the Winterburn carbonate. The Winterburn transforms Germain into a dual-resource opportunity, offering capital synergies with the project facilities to access additional resources. In 2011 Laricina continued to further delineate and confirm the resource. During 2012 we will continue reservoir engineering to develop our recovery strategies, building on our understanding from Saleski. Developing the Winterburn is considered Phase 6 of the Germain development plan and will involve a separate approval process. Germain Grand Rapids Development Plan R23 R22 R21 W4M N T85 Layout of Germain development plan with initial well pads and corresponding infrastructure and facilities. EIA local study area Phase 1 plant, well pad and existing infrastructure T84 Phase 2 plant and well pad Phase 3 plant and well pad Phase 4 plant and well pad Camp site Borrow pit Pipeline tankage Future well pad, road and pipeline development to sustain production Gas pipeline Proposed powerline and substation Road Road and pipeline Water disposal well Water source well 27 Laricina Energy Ltd.

30 operations review future growth properties conn creek Laricina holds 24,320 gross acres at 100 percent working interest at its Conn Creek property just west of Fort McMurray. It has a best estimate of contingent and prospective resources of 262 million barrels* in a stacked reservoir with over 40 metres of net pay. The resources are contained in high-quality tributaries of the main McMurray channel trend to the east. Conn Creek is expected to support a 30,000 barrel-per-day project development plan with an anticipated SOR of 2.7:1, and project start-up in Conn Creek offers infrastructure advantages with the all-weather Tower Road and a 144 kv power line running across the property, and natural gas service available just west of the property. R11 Conn Creek (north) Athabasca River R10 R9 R8W4 T Conn Creek (south) Poplar Creek Fort McMurray T89 T88 Delineation at Conn Creek is currently one well per section in the northern portion, with further delineation drilling planned for Work on the regulatory application is underway and Laricina plans to initiate field studies for the EIA in the second half of Due to its proximity to Fort McMurray, Laricina plans extensive stakeholder engagement. The Company is working with the Regional Municipality of Wood Buffalo and the Government of Alberta to ensure compatibility between Laricina s development plans and city growth. Conn Creek is expected to follow Germain Phase 2 to take advantage of engineering, procurement and construction synergies. * According to the Proforma GLJ Report effective January 1, See Reserves and Resources page Annual Report poplar creek T87 Middle McMurray net pay Road Lower McMurray net pay Gas pipeline Crude oil pipeline Laricina holds 5,840 gross acres at 100 percent working interest at its Poplar Creek property, following the acquisition of the other 50 percent interest in February 2012 from a related party. Poplar Creek is estimated to contain 126 million barrels of best estimate contingent resources* which are expected to support the development plan of 25,000 barrels per day with an estimated SOR of 2.7:1. As at Conn Creek, the Poplar Creek resources lie in Lower and Middle McMurray tributary channels; however, Poplar Creek is closer to the main McMurray channel trend. Laricina has been working with the Regional Municipality of Wood Buffalo, the Government of Alberta and other oil sands companies to develop new permanent access to the east side of the Athabasca River, needed to develop Poplar Creek. The development plan for Poplar Creek is based on the current drilling density of five wells per section. Laricina plans to initiate the field studies for the EIA in the second half of 2012, to support start-up targeted in 2016.

31 R1W5 R25 R24W T96 10 burnt lakes Laricina s growing confidence in the viability of thermal recovery in the carbonates motivated it to add 12,800 acres to its Burnt Lakes holdings at the mid-december 2011 Crown land sale. This gives Laricina a contiguous, 100 percent working interest position in 41,548 acres or about 65 sections comparable in size to Saleski Contour (5m interval) Grosmont D zone net pay Grosmont C zone net pay T95 T94 Delineation wells The original Burnt Lakes property targets the bitumen-saturated Grosmont D zone, where Laricina has drilled and cored seven stratigraphic wells. The recent land acquisition targets the bitumen-saturated, highly porous and permeable Grosmont C zone, with greater than 20 metres of gross pay. Burnt Lakes is estimated to contain 640 million barrels of best estimate contingent and prospective resources*. Laricina intends to construct a 60-km road to the property in 2013 to facilitate year-round access. Ongoing resource delineation will continue at Burnt Lakes, with plans for a core hole program and 3-D seismic to be completed over the next few winters. Burnt Lakes is expected to support production of 60,000 barrels per day. Burnt Lakes Saleski Germain Wabasca Desmarais Boiler Rapids House River Conn Creek Thornbury West Thornbury Poplar Creek Fort McMurray other growth properties Laricina has a significant inventory of additional prospects in various stages of resource definition in the McMurray and Grand Rapids formations, representing approximately 31 percent of its land base. The larger of these prospects are Boiler Rapids and House River, followed by Thornbury and Thornbury West, all located in the McMurray Formation, and Portage, which is in the Grand Rapids Formation. These properties have combined best estimate contingent and prospective resources of 484 million barrels*. * According to the Proforma GLJ Report effective January 1, See Reserves and Resources on page 34. Portage Growth Properties A portfolio of future growth properties. 29 Laricina Energy Ltd.

32 operations review advancing innovations PHARM process schematic in the Grosmont carbonates. The granting of a Canadian and U.S. patent in May 2011 for Laricina s Passive Heat-Assisted Recovery Method (PHARM) made 2011 a milestone year for Laricina s innovation team. PHARM uses the heat lost in an initially developed steam chamber to recover bitumen from an adjacent zone using only a producing or injecting well. The issuance of the patent aptly illustrates Laricina s overall approach to innovation, including the primary goal of creating additional value for shareholders by using technology improvements to increase ultimate resource recovery as cost- and energy-efficiently as possible. Laricina s innovations are a competitive advantage. Ideas are rigorously filtered for practicality and profitability, while proposed innovations are stage-gated for difficulty, and clear paths to commerciality are planned. The ultimate goal is to gain new methods to reduce the SOR in our operations, ultimately improving operating efficiency and environmental performance due to a lower ratio of energy usage per barrel of bitumen produced, resulting in lower carbon emissions intensity. In 2011 Laricina continued to advance its researchbased technology innovations and to initiate operating improvements in the field, demonstrating significant new value for shareholders. Monitoring down-hole conditions and well operations. solvents Combining solvents with steam is integral to improving profitability and shareholder value. The use of solvent in Laricina s operations will help lower the SOR and maximize resource recovery and project net value. In 2011 Laricina continued to refine through laboratory and simulation studies its SC-SAGD process Annual Report

33 innovation in production Laricina is pursuing numerous improvements in production techniques and materials, including: through under-balanced drilling (also known as managed-pressure drilling). Following a feasibility study and four vertical coring wells drilled under-balanced at Saleski in 2011, Laricina applied this technique in the recently drilled well-pair at Saleski and aims to apply this technique to future Grosmont horizontal wells; the carbonates with lost-circulation issues; cement placement design in horizontal wells at Germain; to reduce costs and improve wellbore quality; and cement placement and reduced future well-spacing on drilling pads at the Saleski Phase I commercial project. innovation in facilities engineering and construction Association of Alberta s detailed cost database in exchange for access to industry benchmarks that include over 27 other project datasets. Laricina will have exclusive access to industry benchmark data to help measure performance and identify areas for construction improvement and immediate action; large unknown in understanding productivity performance. As a result Laricina will undertake a time and motion study using video cameras to measure and obtain realistic tool time output at the Germain CDP. The University of Calgary will be involved in measuring, analyzing and validating the results as well as identifying inefficiencies and opportunities for improvement in work through best practices; and engineering and construction capacity in local, eastern Canadian and Asian markets suited to alleviating the Company s current supply chain shortages. ESEIEH Enhanced Solvent Extraction Incorporating Electromagnetic Heating (ESEIEH) aims to improve solvent performance and ultimately eliminate the need for steam. Because solvents perform marginally at ambient reservoir temperature, ESEIEH would add heat through electromagnetic waves emanating from antennae placed in the horizontal wells. In 2010 the consortium in which Laricina is participating secured $16.5 million through the Climate Change Emissions Management Corporation to conduct a field trial during the planned four-year test program. The program s first phase included a surface test and an antenna design performance test on a bitumen ore mine face, and was completed on schedule in Phase 2 will involve an in situ pilot test planned to be operational in OASIS In 2011 Laricina commenced formal development of its in-house OASIS engineering modelling system. OASIS is a Laricina-designed tool for rapidly building computer simulators, from spreadsheet-scale problems up to advanced thermal reservoir codes with complex physics. The system involves a generic numerical engine and interface coupled with a simple programming language. OASIS is motivated by two opportunities. The first is increased operating efficiency through better understanding and prediction of various transient, complex, and hidden phenomena that arise in thermal wells and facilities. The second is to facilitate increasingly sophisticated recovery technology. Simulation was an enabling technology for the original SAGD, and is even more important for efficiently advancing concepts such as ESEIEH. Development has progressed well towards a v1.0 goal of demonstrating a basic thermal reservoir simulator that is generated from a few pages of formulation text. In 2012 Laricina will upgrade the OASIS numerical engine and user interface, and develop diverse system testing models, most of which the Company foresees having immediate engineering applications. 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 Solvent Heat-Assisted Recovery Process (SHARP) consortium. In 2011 Laricina joined the Industrial Research Chair in Reservoir Simulation at the University of Calgary, which the Company anticipates will help advance the OASIS process. Evaluating a drill cutting sample. 31 Laricina Energy Ltd.

34 proving the power of community relationships Presenting Laricina s donation towards health and safety education and training in Wabasca. traditional land users Before commencing its field operations Laricina asked traditional land users, including trappers, to assess the area for potential impacts on traditional sites, and to record the history of the area. The assessments, which include a process known as ground-truthing, were facilitated by the Bigstone Cree Nation and its Government and Industry Relations office. Western science is only one tool Laricina uses when assessing land and water and its project footprints. As a neighbour we want to learn from and be respectful of the traditional land users and include these perspectives to develop the best projects possible. It is important to us that our neighbours see Laricina as respectful of the land, air, water, animals and plants in all our operations. community engagement Laricina has clearly demonstrated its commitment to open dialogue and engagement with the communities in which it operates, including First Nations communities. Sharing information with stakeholders early in the project cycle creates the opportunity to respond to their concerns and achieve project approvals without stakeholder intervention. We have been told by community members that we are living up to that commitment. In spring 2011 Laricina hosted an open house to inform local residents and members of the Bigstone Cree Nation about its Saleski and Germain projects. The topics included Laricina s operations, environmental commitments, water recycling program and expansion plans. Maintaining continuous working relations with stakeholders is important. In 2011 Laricina increased its local community engagement staff by two, which supports the Company s efforts to work with the Wabasca community on opportunities and issues related to the expected growing development pace in the region. Our goal is to ensure the community understands SAGD operations and how they differ from oil sands mining operations, through communications about the Company s projects, oil sands development in general, and by touring the Company s operations Wabasca career fair provided information about current and potential career opportunities in the area. A passing caribou as seen by Laricina s remote camera Annual Report

35 Community engagement initiatives ($ thousands) Contracts in Wabasca area ($ millions) empowering growth The cornerstone of successful community engagement in the Wabasca area is economic development and sustainability. Part of Laricina s community engagement program is to ensure that local stakeholders living near Laricina s projects have an opportunity to benefit either through direct employment, contract opportunities or employment with local contractors. In 2011 several local companies provided goods and services to Laricina s Germain and Saleski projects. Since Laricina s inception, the Company has awarded approximately $47.6 million in local Wabasca contracts and awarded a further $13 million to businesses in the Slave Lake and Athabasca areas. We continue to grow our investment in Wabasca-area contractors as Laricina s projects advance and expand. The next steps include promoting stay-in-school initiatives, providing job placements to enhance work experience opportunities and working with other companies and learning institutions to provide the training that leads to long-term job opportunities. Our objective is to expand local job prospects in the service sector and lay the groundwork for local companies to have the confidence to make future business investments. residents, businesses and organizations, was the upgrading of approximately 68-km of the Al-Pac Chipewyan Lake gravel forestry haul road, which serves Laricina s projects. This initiative was funded by Laricina and carried out by many local contractors from September until early December 2011, and is much-appreciated by road users. Last year the Company continued its commitment to educational development by hosting the second career fair. Attendance was up from 2010, with over 30 employers providing information to more than 400 students. Community engagement includes providing funding and support to community projects that make a difference. We invest the time of our employees to support local not-for-profit agencies, community events and cultural activities because we are part of the community. In 2011 Laricina continued to consult with the Bigstone Cree Nation and the Municipal District of Opportunity #17. A major success, beneficial to Laricina as well as regional Al-Pac bridge over Hoole Creek. Laricina will begin upgrading and reconstruction of the bridge in April - May Laricina Energy Ltd.

36 reserves and resources (1) Laricina s assets contain very large resource potential, including best estimate exploitable original-bitumen-in-place of 12.2 net billion barrels, with 4.6 billion barrels classified as contingent and prospective resources (best estimate) and 387 million barrels of probable reserves effective January 1, 2012 based on the Proforma GLJ Report (1). Of these amounts, Saleski has 1.8 billion barrels of contingent resources (best estimate) in the Grosmont carbonates, while Germain has 1.4 billion barrels of contingent resources (best estimate) in the Grand Rapids sands and the Winterburn carbonates. Including all properties, Laricina s resources are balanced approximately equally between sand and carbonate reservoirs. The Proforma GLJ Report includes the acquisition from a related party of its working interest in jointly owned properties on February 15, 2012 and effective January 1, Recoverable resource by formation Clastics - McMurray/Wabasca 16% Carbonates - Grosmont & Winterburn 56% Clastics - Grand Rapids 28% Annual Report The following tables summarize certain information contained in the Proforma GLJ Report. It should be noted that the estimates of recovery, production, and net revenue presented in the tables below do not represent the fair market value of the Company s reserves and resources. Readers are directed to the footnotes and definitions in this section and the Oil Sands Reserves and Resources section of the MD&A on page 38. Project summary Average Area Anticipated Gross Peak Working in Acres Start-up (2) Production (2) Project Area Formation Interest (gross) (year) (bbls/d) Saleski Grosmont 60% 42, ,500 Germain Grand Rapids 100% 39, ,000 Germain Winterburn* 100% 44, ,000 Burnt Lakes Grosmont 100% 41, ,000 Conn Creek McMurray 100% 24, ,000 Poplar Creek McMurray 100% 5, ,000 Other Properties McMurray/Grand Rapids 100% 62,721 undefined undefined additional 5,120 acres of Winterburn rights only. (1) (2) See notes page 37.

37 Summary of reserves and resource classification Reserves Contingent Resources (3) Prospective Resources (4) Probable Probable + Possible Reserves (5) Reserves (6) Low (7) Best (8) High (9) Low (7) Best (8) High (9) Property (mmbbls) (mmbbls) (mmbbls) (mmbbls) (mmbbls) (mmbbls) (mmbbls) (mmbbls) Saleski (10) ,750 2, Germain Grand Rapids , Germain Winterburn (10) , Burnt Lakes (10) , Conn Creek Poplar Creek Other Properties Total (11) ,364 4,342 7, bitumen reserves and resources 10 percent present value of future net revenue before tax Based on Forecast Prices and Costs ($ million) 01/ /2010 Change Probable Reserves Probable + Possible Reserves 1, ,067 Low Estimate Contingent Resources 1,545 2,198 (653) Best Estimate Contingent Resources 10,231 11,660 (1,429) High Estimate Contingent Resources 20,015 21,337 (1,322) Low Estimate Prospective Resources (6) Best Estimate Prospective Resources High Estimate Prospective Resources The economic forecasts have only been prepared for the Burnt Lakes, Conn Creek, Germain Grand Rapids, Germain Winterburn, Poplar Creek and Saleski properties that represent contingent and prospective resources (best estimate). Laricina s bitumen reserves are all associated with the Company s Germain Grand Rapids asset and increased nearly 11 times over December 2010 primarily as a result of the submission of the regulatory applications for the Germain expansion for Phases 2-4. Laricina s as at December 31, 2010, an increase of 1,630 percent. Laricina s Contingent Resources (best estimate) remained relatively unchanged from 4,373 million barrels at December 31, 2010 to 4,342 million barrels at January 1, 2012, and the PV10 decreased by 12.8 percent to $10.2 billion from $11.7 billion last year. The net change in resource volumes is a result primarily from a decrease due to the reclassification of contingent resources to probable reserves for Germain, and from an increase due to additional delineation drilling, acquisition of lands at Burnt Lakes and the acquisition of joint working interest lands from a related party. The reduction in PV10 is primarily due to increases in capital cost estimates offset by changes in forecast prices and increased resource volumes. The contingent resource and economic assessment at Germain Grand Rapids reflects GLJ s risked analysis of Laricina s planned SC-SAGD process which has been tested by other operators in the Athabasca and Cold Lake oil sands. (3)-(11) See notes page Laricina Energy Ltd.

38 Economic sensitivities were also prepared for the Germain Grand Rapids and Saleski properties using Laricina s risked assessment of the SC-SAGD process. The risked resource volumes as determined by Laricina using SC-SAGD technology for the Germain Grand Rapids and Saleski were 1,560 million barrels and 2,211 million barrels, respectively. The total of these volumes, 3,771 million barrels, is an incremental volume of 682 million barrels greater than the proved plus probable plus best estimate contingent resources assigned in the Proforma GLJ Report for these two properties. This assessment is included for information purposes and should not be construed as GLJ s independent view of the technology. SC-SAGD technology sensitivity 10 percent present value of future net revenue before tax Based on Forecast Prices and Costs ($ million) 01/ /2010 Change SC-SAGD Best estimate technology sensitivity (12) 14,281 14,884 (603) growth in value and resources Recoverable resources (mmbbls) 3,241 4,134 4,596 4,645 Net present value, before tax, 10 percent discount ($ millions) 8, , ,714 2,284 5,510 11,817 10, (1) (1) Probable reserves Best estimate prospective resources Best estimate contingent resources Probable reserves Best estimate prospective resources Best estimate contingent resources Annual Report

39 Notes: (1) (2) (3) (4) (5) (6) (7) (8) (10) (11) (12) Based on the report of GLJ Petroleum Consultants Ltd. (GLJ) regarding Laricina s properties effective proforma January 1, 2012 (Proforma GLJ Report) using GLJ s commodity price forecast as at January 1, 2012 and including the acquisition from a related party of its net working interest in Germain, Poplar Creek, Portage and Thornbury on February 15, 2012 and effective January 1, 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. 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. Contingent Resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies. Contingencies may include factors such as economic, legal, environmental, political, and regulatory matters, or a lack of markets. These resource estimates are not currently classified as reserves, pending further reservoir delineation, project application, facility and reservoir design work, preparation of firm development plans and company approvals. Contingent resources entail additional commercial risk than reserves and adjustments for commercial risks have not been incorporated in the summaries set forth herein. There is no certainty that it will be commercially viable to produce any portion of the contingent resources. Prospective Resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from undiscovered accumulations by application of future development projects. Prospective resources have both an associated chance of discovery and a chance of development. The Prospective resources estimates reflected herein have been risked for the chance of discovery but not for the chance of development and hence are considered partially risked estimates. Prospective resources entail additional commercial risk than reserves and contingent resources and adjustments for commercial risks have not been incorporated in the summaries set forth herein. If a discovery is made, there is no certainty that it will be developed. If it is developed, there is no certainty as to the timing of such development. Probable Reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved reserves plus probable reserves. Possible Reserves are those additional reserves that are less certain to be recovered than probable reserves. It is unlikely that the actual remaining quantities recovered will exceed the sum of the estimated proved plus probable plus possible reserves. There is a 10 percent probability that the quantities actually recovered will equal or exceed the sum of proved plus probable plus possible reserves. Low Estimate is considered to be a conservative estimate of the quantity that will actually be recovered. It is likely that the probability that the quantities actually recovered will equal or exceed the low estimate. Best Estimate is considered to be the best estimate of the quantity that will actually be recovered. It is equally likely that the actual remaining quantities recovered will be greater or less than the best estimate. If probabilistic methods are used, there should be at least a 50 percent probability that the quantities actually recovered will equal or exceed the best estimate. High Estimate is considered to be an optimistic estimate of the quantity that will actually be recovered. It is unlikely that the actual remaining quantities recovered will exceed the high estimate. If probabilistic methods are used, there should be at least a 10 percent probability that the quantities actually recovered will equal or exceed the high estimate. Laricina s resources at Saleski and Burnt Lakes are contained in the Grosmont Formation, and a portion of Germain s resources are contained in the Winterburn Formation, each a carbonate reservoir. SAGD and CSS, the recovery processes being considered to develop these assets, are considered by GLJ to be technology under development in carbonate reservoirs. Although the technology has been developed for application to non-carbonate reservoirs, and the Company is currently operating a pilot in the Grosmont Formation at Saleski, there are no known successful commercial projects that use SAGD or CSS to recover bitumen from a carbonate formation. These volumes are arithmetic sums of the Company's working interest share before royalties, which statistical principles indicate may be misleading as to volumes that may actually be recovered. Readers should give attention to the estimates of individual classes of resources and appreciate the differing probabilities of recovery associated with each class as explained. SC-SAGD best estimate technology sensitivity was based on Laricina s risked view of resources for Saleski-Grosmont and Germain-Grand Rapids based on SC-SAGD technology and remaining properties best estimate contingent and prospective resources based on SAGD/CSS technology. 37 Laricina Energy Ltd.

40 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, 2011 and December 31, 2010 was prepared as of March 21, 2012 and should be read in conjunction with the audited consolidated financial statements and accompanying notes for the years ending December 31, 2011 and December 31, The financial information presented in this MD&A was prepared in accordance with International Financial Reporting Standards (IFRS). In February 2008, the Canadian Institute of Chartered Accountants (CICA) Accounting Standards Board (AcSB) confirmed the adoption of IFRS for interim and annual reporting purposes for fiscal years beginning on or after January 1, Laricina converted to IFRS effective January 1, All comparative numbers were restated in accordance with the policies adopted under IFRS as outlined in note 3 to the consolidated financial statements, unless otherwise stated. The information in this MD&A provides management s analysis of the financial and operating results of Laricina and may contain 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 throughout this 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, reserves and 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, should or will be taken or occur in the future. The reader is 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, 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 March 21, 2012, 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. Unless required by law the Company does not undertake any obligation to update publicly or to revise any of the included forwardlooking 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 Annual Report

41 Overview 2011 Laricina is a privately-held in situ oil sands company founded in November 2005 and is focused on developing bitumen-bearing sand and carbonate reservoirs in the oil sands region of northeastern Alberta. The Company s business model is to extract bitumen using underground or in situ techniques and has advanced two major development projects, Saleski and Germain. The Company accomplished significant objectives in its progress towards commercialization during Commissioning of the Saleski pilot was completed during the first quarter of 2011 followed by first production and bitumen sales. The Saleski pilot is the first steam-assisted gravity drainage (SAGD) development project in the Grosmont Formation carbonate reservoir. At Germain, Laricina concentrated on advancing the construction of the Germain commercial demonstration project (CDP) including the completion of site preparation, and detailed engineering, and the commencement of module fabrication and electrical infrastructure. The ongoing construction of the Germain CDP will continue throughout 2012 with commissioning of the facility and initial steaming of well-pairs expected in the second quarter of In December 2011, Laricina increased land holdings at its Burnt Lakes property by 12,800 acres at a cost of $19.8 million, increasing the Company s total holdings at Burnt Lakes to 41,548 acres of oil sands rights. The Company completed equity private placements during 2011 for total net proceeds of $499.6 million. One of them was the Company s largest to date, with 8,928,709 common shares issued at $42.50 per common share. Laricina recruited a substantial number of employees and contractors required to support the Company s evolution toward commercial operations. In August 2011 the Company expanded its office space, moving from 33,624 square feet to 67,989 square feet at 800, st Street S.W., Calgary, Alberta to accommodate its growing team. Oil Sands Reserves and Resources Laricina has focused on four bitumen-bearing geological formations for development: the McMurray and Grand Rapids sands, and the Grosmont and Winterburn carbonates. 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, 2011 (GLJ Report). The Company has probable reserves of 387 million barrels and probable plus possible reserves of 488 million barrels, an increase from the 36 million barrels of probable reserves and 43 million barrels of probable plus possible reserves in the December 31, 2010 GLJ Report (1). These reserves are entirely associated with the Grand Rapids reservoir at the Company s Germain asset. The GLJ Report identified best estimate contingent and prospective resources of 4.5 billion barrels of net recoverable bitumen compared to the 4.6 billion barrels reported in the Company s 2010 annual report. The current high estimate contingent and prospective resources are 7.7 billion barrels compared to the 7.8 billion barrels reported in the December 31, 2010 GLJ Report (2) (4). The net change is primarily due to the reclassification of contingent resources to probable reserves at Germain partially offset by an increase of contingent and prospective resources due to additional delineation drilling and acquisition of lands at Burnt Lakes. Recovery methods including SAGD, solvent-cyclic (SC) SAGD and cyclical steam stimulation (CSS) were included when evaluating the resource potential of each reservoir. 39 Laricina Energy Ltd.

42 Reserves (1) Contingent Resources (2) (3) Prospective Resources (4) Probable plus (mmbbls) Probable Possible Low Best High Low Best High Saleski 330 1,750 2,636 Germain Grand Rapids ,031 Germain Winterburn 407 1,112 Burnt Lakes 567 1, Conn Creek Poplar Creek Other properties ,315 4,171 6, (1) (2) (3) (4) The Canadian Oil and Gas Evaluation Handbook (COGE Handbook) defines possible reserves as those additional reserves that are less certain to be recovered than probable reserves. There is a 10 percent probability that the quantities actually recovered will equal or exceed the sum of proved plus probable plus possible reserves. The 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. There is no certainty that it will be commercially viable to produce any portion of the contingent resources. Contingent resources for Conn Creek, Poplar Creek and Saleski are based on SAGD technology; Germain Winterburn is based on CSS; 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. 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. There is no certainty that any portion of the prospective resources will be discovered. If a discovery is made, there is no certainty that it will be developed. If it is developed, there is no certainty as to the timing of such development. The GLJ Report included economic evaluations for Saleski, Germain Grand Rapids, Germain Winterburn, Burnt Lakes, Conn Creek and Poplar Creek which represent approximately 70 percent of Laricina s net land base and 90 percent of the Company s resource base using GLJ s January 1, 2012 price forecasts. The net present value of future net revenue before income tax at a 10 percent discount rate is as follows: ($ millions) Low Best High Contingent resources 1,507 9,948 19,401 Prospective resources An economic evaluation was also provided for probable reserves and probable plus possible reserves, which resulted in net present value of future net revenue before income tax at a 10 percent discount rate of $0.8 billion and $1.1 billion, respectively. The December 31, 2011 economic evaluation represents a decrease in net present value of future net revenue from December 31, This decrease is primarily due to the increased capital costs estimated for the completion of these projects, including inflation, partially offset by changes in forecast prices and increased resource volumes. Laricina requested that GLJ provide an economic sensitivity of the best estimate reserves and resources for the Germain Grand Rapids and Saleski Grosmont reservoirs using Laricina s risked assessment of the SC-SAGD process. Inclusive of Laricina's Annual Report

43 risked assessment of SC-SAGD, the current best estimate net recoverable resources assigned by GLJ were 5.5 billion barrels at December 31, 2011, an increase from the December 31, 2010 GLJ Report SC-SAGD assessment of 5.3 billion barrels. This assessment is included for information purposes and should not be construed as GLJ s independent view of the technology. The economic evaluation of the application of Laricina's risked assessment of SC-SAGD would increase the best estimate contingent resources net present value of future net revenue before income tax at a 10 percent discount rate to $13.8 billion. This value is a decrease from the 2010 economic evaluation due to increased future development costs associated with capital investment, including inflationary expectations, partially offset by changes in resource volumes. The possible incremental value from applying SC-SAGD recovery techniques will depend on the successful operation of Laricina s Germain CDP and the second stage of the Saleski pilot, both of which will incorporate solvents. Laricina did not request an assessment of applying SC-SAGD to the McMurray, Wabiskaw or Winterburn formations although the Company anticipates that SC-SAGD will be applicable to them, and believes there is potential to increase the net recoverable bitumen and value beyond what the current GLJ Report has assigned to these reservoirs. Laricina has explored and delineated the geological formations throughout its portfolio of properties, including Germain, Saleski, Burnt Lakes, Poplar Creek and Conn Creek. At December 31, 2011, Laricina had a total of 367 delineation wells on its operated lands, of which approximately 70 percent were at Saleski and Germain. Delineation wells support the recoverable resource estimates provided by GLJ, the Company s overall confidence in its development plans, as well as the regulatory applications and lease retention requirements. Annual Financial Information ($ thousands, except per share amounts) Total assets 1,372, , ,321 Working capital 628, , ,320 Capital expenditures (cash) 212, ,873 39,670 Net operating revenue 2,359 Finance income 6,803 2, Net loss (21,659) (3,884) (4,475) Net loss per common share basic and diluted (0.38) (0.08) (0.12) The 2010 annual financial information was restated to conform with the conversion to IFRS. The 2009 annual financial information was prepared under Canadian GAAP. Laricina made significant progress in its transition from a development-stage company to an operating company during The Company completed its commissioning of the Saleski pilot; recorded first production and bitumen sales from the Saleski pilot; and progressed on the engineering, construction and fabrication of the Germain 5,000-barrel-per-day SC-SAGD CDP. Laricina completed equity private placements totalling 12,227,828 common shares at $42.50 per common share for net proceeds of $499.6 million during These financings included the Company s largest equity private placement, totalling 8,928,709 common shares on June 29, 2011, and attracted several new, high-quality investors as well as existing investors. The net private placement proceeds will be used to complete the construction of the Germain CDP, continue the expansion of additional phases at Saleski and Germain, advance other future development projects, and for general corporate purposes. 41 Laricina Energy Ltd.

44 Capital expenditures during 2011 were primarily for commissioning the Saleski pilot, advancement of Germain CDP construction, drilling and completion of six well-pairs to be used in the Germain CDP and infrastructure to support the Saleski and Germain projects. As an early-stage operating company with revenue coming from low-risk cash investments and early pilot bitumen sales, the net loss resulted primarily from operating costs associated with pilot production and general and administrative activities required to support the transition to an operating company. Laricina s increases in total assets during 2011 and 2010 are due to the $499.6 million and $329.6 million, respectively, of net proceeds raised through equity private placements in those years. The first reporting of net operating revenue in 2011 is due to the blended bitumen sales from the Saleski pilot, which began in the second quarter of Finance income increased during 2011 and 2010 as a result of increased funds on deposit beginning in the second half of 2010, combined with a minor increase in the average interest rate received for funds on deposit during Capital Investment Capital investment includes costs related to exploration and evaluation (E&E) assets, property, plant and equipment (PP&E), and intangible assets. ($ thousands) E&E assets: Land 20, Exploration 16,152 5,199 Development 135,917 84,159 Other 31,880 7,135 Capitalized general and administrative expenses 15,423 10, , ,137 PP&E: Facilities and other equipment 15,264 10,564 Corporate 1,643 1,106 16,907 11,670 Intangible assets 9,491 Capital asset additions 245, ,807 Capital expenditures (not including non-cash items) 212, ,873 Capital asset additions during 2011 were primarily for the initial drilling of six horizontal well-pairs for the Germain CDP; the construction of a permanent camp at Germain; detailed engineering, module fabrication and site preparation for the Germain CDP facility and initial well pad; and completion of the winter drilling program of 13 exploration wells and 27 development wells. Capital expenditures for 2011 were less than anticipated due to the revised timing of expenditures planned for the Germain CDP Annual Report

45 Land Land additions during 2011 primarily included 12,800 net acres of oil sands leases in the Burnt Lakes area for a total cost of $19.8 million. During 2010, the Company added 5,515 net acres of oil sands, petroleum and natural gas rights in the Burnt Lakes and Saleski areas for $0.4 million. At December 31, 2011, Laricina s total land holdings were 209,205 net acres compared to 192,588 net acres at December 31, At December 31, 2011, oil sands rights comprised 95 percent of the total land holdings compared to 96 percent at December 31, Laricina s land holdings will be used in future development projects including expansion phases at Saleski and Germain and additional development projects at Burnt Lakes, Poplar Creek and Conn Creek. Exploration Laricina s 2011 winter exploration program was primarily focused at Saleski and Germain and included a 15.6 square-km 3-D seismic program over the Saleski Phase 1 planned facility site, and the completion of the winter drilling program of 13 exploration wells, of which five were at Germain, five at Saleski and the remaining three at Burnt Lakes. The increase in exploration costs in 2011 over 2010 was primarily due to the winter drilling program. Exploration activities for 2010 included 8.6 square-km of 3-D seismic covering the future Germain CDP facility site and 28.8 km of 2-D seismic over the Saleski Phase 1 planned site. Preparations for the winter exploration drilling program to support the continued development of Laricina s core properties consisting of two wells in Saleski and three wells in Germain began late in At this date, the exploration wells were completed along with 20.7 square-km of 3-D seismic and 1.3 square-km of 4-D seismic at Saleski and 25.0 km of 2-D seismic at Germain. Development activities The majority of development expenditures throughout 2011 were to support the advancement of the Germain CDP. In comparison, development expenditures during 2010 were to finish construction and commissioning of the Saleski pilot facility. ($ thousands) Saleski $ 11,549 $ 85,831 Germain 138,397 8,768 Other 1, $ 151,181 $ 94,723 During 2011, Laricina drilled and completed 12 horizontal wells (six well-pairs) of the 20 horizontal wells (10 well-pairs) planned for the Germain CDP. Other development drilling activities during the year were primarily to support the Germain CDP and included 17 observation wells, eight water source and monitoring wells, and two water disposal wells. Germain development activities in 2011 included progress on the Germain CDP and a $15.0 million finance lease for the Germain permanent camp. As at December 31, 2011, Laricina had completed detailed engineering and site preparation for the facility and initial well pad, along with approximately 60 percent of equipment purchasing and five percent of module fabrication. In addition, Germain expenditures included the addition of a fuel gas pipeline, which is expected to have its metering station completed and tied-in by the third quarter of Construction of a new power substation is in progress and electricity from the Alberta grid is expected to be available by July Laricina Energy Ltd.

46 Development activities at Saleski included the addition of a second steam generator, expanding steam capacity to aid in ramping up production to the design capacity of 1,800 barrels per day. The development drilling activities during 2010 were primarily in support of the Saleski pilot and included the winter drilling program of five water source wells, four water monitoring wells and five observation wells and the completion of the well-pairs used in the Saleski pilot. Additional development activities during 2010 included the acquisition of equipment, fabrication of modules and completion of the Saleski pilot; initial steam injection at the Saleski pilot; and construction and final grading of the all-weather access road between Saleski and Germain. Other Other capital activities during 2011 included pre-operating activities associated with initial steaming and first production at the Saleski pilot; advancing the regulatory application for Saleski Phase 1; surface upgrades to access roads; initial engineering and regulatory work for a lateral crude sales pipeline, the Stony Mountain Pipeline; and the completion of the environmental impact assessment and regulatory application for the 3-phase, 150,000-barrel-per-day Germain expansion which was filed on November 14, The Stony Mountain Pipeline is a 184-km system that will include a 24-inch line to transport blended bitumen for sale and a 12-inch line to deliver condensate for blending and SC-SAGD purposes. The planned Stony Mountain Pipeline will run from Saleski to a connection point at the Cheecham terminal south of Fort McMurray. During 2010, other development activities consisted primarily of regulatory applications including an amended regulatory application for the second stage of the Saleski pilot project utilizing SC-SAGD, application and approval for the Germain 5,000-barrel-per-day CDP utilizing SC-SAGD, and the expansion of Saleski to 12,500 barrels per day of production capacity. Throughout 2011 and 2010 other capital investment costs were incurred to advance innovation and technology projects, such as the Enhanced Solvent Extraction Incorporating Electromagnetic Heating (ESEIEH) project, OASIS software design for reservoir simulation, surface road upgrades and reservoir studies. The Company also made provisions for future site restoration costs and capitalized costs associated with pre-operating activities. In July 2011, the Government of Alberta announced that Laricina had been selected to receive funding of up to $10.0 million (gross) under the Innovative Energy Technologies Program for the Saleski pilot. At December 31, 2011, $5.5 million (gross) of this funding had been approved and will be used to advance future development at Saleski. Intangible assets As at December 31, 2011 Laricina recorded intangible assets of $5.7 million relating to the expansion of available power for the Company s future development projects at Germain. Components of the pilot such as the development well-pairs directly contribute to the understanding of the reservoir, assist in the future assignment of proved reserves and will be recapitalized until the related reserves are recognized. As at December 31, 2011, $3.8 million was recorded as an intangible asset for the recapitalization of the depreciation of certain components of the Saleski pilot. Capital expenditures outlook Capital expenditures before capitalized general and administration costs are expected to be $418.5 million for Of this amount, $71.0 million relates to the Saleski pilot and Saleski Phase 1 expansion, $247.2 million to the construction of the Germain CDP and advancing Germain Phase 2, $52.6 million to development infrastructure, $10.2 million to conclude the winter exploration drilling and geophysical program, and the remainder to studies and corporate development. Of the total planned expenditures, $71.5 million has been carried over from 2011 due to a timing delay of incurred costs. Laricina plans to finance future activities with current cash resources, debt and equity financings Annual Report

47 Corporate Results ($ thousands) Net operating revenue 2,359 Operating expenses 11,421 General and administrative expenses, net 17,157 8,227 Finance income 6,803 2,387 Net loss (21,659) (3,884) Operating activities Laricina recorded its first production volumes and blended bitumen sales during the second quarter of Since initial production through December 31, 2011, Laricina recorded blended bitumen sales of approximately 55,500 gross (33,300 net) barrels at an average price of $73.06 per barrel. The Company completed well stimulations on the two well-pairs in December The early results from these stimulations were positive and the benefits are expected to be realized after production cycles are established in early Production is anticipated to increase with the well stimulations performed, along with additional steam injection and production testing. Operating, transportation and blending costs recognized throughout 2011 were directly related to production and blended bitumen sales from the Saleski pilot. Due to the experimental nature of a pilot, operating costs are expected to exceed net revenue throughout the life of the Saleski pilot. General and administrative expenses Gross general and administrative expenses increased in 2011 over 2010 primarily due to the continued growth in the Company s employee and consulting base. Costs directly related to project exploration and development activities are capitalized. ($ thousands) General and administrative expenses, gross 23,810 13,137 Share-based compensation costs 8,770 6,071 Capitalized costs (15,423) (10,981) General and administrative expenses, net 17,157 8,227 At December 31, 2011, the Company had 121 employees compared to 80 at December 31, This increase in employees and an increase in the consulting base required the Company to move to a larger office space in the third quarter of General and administrative expenses are expected to increase further as a result of the anticipated staffing increases as the Company continues to advance the Saleski and Germain projects. As the projects continue to progress towards commercialization, a smaller percentage of general and administrative expenses will be capitalized. Finance and other income The increase in finance income in 2011 over 2010 is due to having more funds on deposit, resulting from the net proceeds from the equity private placements, combined with an increase to the average interest rate received on invested funds. During the year ended December 31, 2011, excess cash was held in high-interest savings accounts and guaranteed investment certificates with interest rates ranging from 1.2 percent to 1.7 percent, compared to the 1.3 percent earned during the year ended December 31, Other income is related to the sale of certain technical data from the Saleski pilot to a third-party for net proceeds of $2.7 million during 2011 and $3.0 million during Laricina Energy Ltd.

48 Finance costs Finance costs include accretion of site restoration provisions and interest recorded on the finance lease associated with the Germain permanent camp. Finance costs increased to $1.4 million during 2011 from $0.1 million in 2010 due to the commencement of the finance lease in January 2011 combined with the additional costs associated with future site restoration at Germain, including the central processing facility site, initial well pad and horizontal well-pairs. Pre-exploration costs Pre-exploration activities of $0.4 million during the year ended December 31, 2011 included initial surveying work to support the Stony Mountain Pipeline infrastructure and studies related to a possible central camp site. There were no pre-exploration activities during Depreciation Depreciation expense of $5.7 million during the year ended December 31, 2011 increased from the $1.2 million during the year ended December 31, The increase in depreciation expense during 2011 is related to the completion of the all-weather road, the availability of the Germain camp for use and the start-up of the Saleski pilot facilities. Net loss Laricina recorded a net loss of $21.7 million for 2011 compared to a net loss of $3.9 million for This increase is due to operating activities associated with the Saleski pilot and increased general and administrative expenses. Typical of a company in early stages of operations, Laricina expects to continue to show net losses from operating activities at least until commercial levels of production are achieved. Due to the experimental nature of a pilot project the Saleski pilot is expected to have operating costs in excess of net revenue throughout its life. Selected quarterly information ($ thousands of dollars, except per share amounts) Q Q Q Q Q Q Q Q Working capital 628, , , , , ,783 92, ,378 Capital asset additions 77,431 61,333 25,382 81,703 35,753 26,399 16,157 41,498 Net operating revenue 1, Finance and other income 4,919 2,622 1, , Net profit (loss) (5,476) (6,089) (5,755) (4,339) 716 (1,264) (1,756) (1,580) Net profit (loss) per common share, basic and diluted (0.09) (0.10) (0.11) (0.08) 0.01 (0.03) (0.04) (0.04) Working capital increased during the second and third quarters of 2011 due to the closing of private placements of common shares in June and August contributing net proceeds of $365.8 million and $133.8 million, respectively. At the end of the third and fourth quarters of 2010, working capital was significantly higher than at the end of previous quarters due to the closing of private placements of common shares providing net proceeds of $314.8 million and $14.8 million, respectively. The increase in capital asset additions during the third and fourth quarters of 2011 is attributable to the drilling of 12 horizontal wells (six well-pairs), the completion of approximately 80 percent of the detailed engineering and five percent of the fabrication for the Germain CDP. The increase in capital asset additions during the first quarter of 2011 is due to the recording of the $15.0 million Germain camp finance lease and expenditures incurred for the winter drilling program of 13 exploration wells and 27 development wells. Capital asset additions generally increase in the first quarter of each year due to the seasonality of the exploration drilling and geophysical programs, which are usually completed during the winter months Annual Report

49 The increase in other income in the fourth quarter of 2011 and 2010 resulted from the sale of Saleski pilot data to a third-party for net proceeds of $2.7 million and $3.0 million, respectively. In addition, finance income has increased since the third quarter of 2010 due to increased funds on deposit from financings completed in the second half of Liquidity and Financial Resources Working capital Working capital increased by $266.4 million from December 31, 2010 to $628.1 million at December 31, 2011 primarily due to net proceeds of $499.6 million received from private placement financings which closed in the second and third quarters of The increase was partially offset by capital expenditures incurred for the Germain CDP. Capital expenditures for the Germain CDP consisted primarily of engineering and construction costs, and the drilling of 12 horizontal wells. ($ thousands) Working capital, December 31, ,751 Proceeds from the issuance of common shares, net of share issuance costs 499,598 Capital expenditures (cash) (212,389) Operating activities (14,933) Other (5,906) Working capital, December 31, ,121 Laricina has sufficient working capital to finance the 2012 capital and operating spending program of approximately $470.1 million. Approximately 45 percent of the program is directly associated with the Germain CDP and nine percent is tied to the advancement of the Saleski Phase 1 project, the timing of which will depend on the pilot s results. The balance of the spending will include pilot operations, the advancement of future phases at Saleski and Germain, infrastructure, studies, other corporate capital, and general and administrative expenses. The future capital expenditures Laricina requires to continue advancing to commercial operations depend on continued financing. The Company anticipates funding capital and operating activities through an appropriate combination of debt and equity. Asset sales or joint venture arrangements may also be considered. Investments The Company s cash is held in a business operating account with a major Canadian bank which bears interest up to the bank s prime rate minus 1.9 percent. In addition, the Company holds excess cash in high-interest savings accounts and guaranteed investment certificates with interest rates ranging from 1.2 to 1.7 percent. The Company may invest in Canadian government securities or fixed-term and bankers acceptance investments with a minimum A rating. Debt financing Laricina has a demand credit facility of $15.0 million with a major Canadian bank which has been extended to October 31, 2012 and is secured by an equivalent cash deposit. The credit facility is intended for general corporate purposes, including the exploration, development and acquisition of oil sands properties. At December 31, 2011 and the date of this report, the Company had letters of credit totalling $11.1 million and $13.5 million, respectively, under this credit facility related to the development of the Saleski and Germain projects. As projects are advanced to the commercial development phase, Laricina will evaluate the markets for prudent interim or long-term debt funding alternatives. 47 Laricina Energy Ltd.

50 Commitments and contractual obligations At this date, 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 2012 remainder 2,329 9, ,979 10, ,837 5, ,337 1, and thereafter The Company s letters of credit at December 31, 2011, included $9.9 million to a supplier of utilities to support development at Saleski and Germain and $1.2 million for the installation of a natural gas sales metering station. If project development is interrupted the Company will be required to reimburse up to $11.1 million of the suppliers costs. The letters of credit of $9.3 million, $1.2 million and $0.6 million are renewable on June 30, 2012, September 1, 2012 and December 31, 2012, respectively. Subsequent to December 31, 2011 the Company issued additional letters of credit to the utility supplier for $2.4 million. As at March 21, 2012, the Company has $54.6 million of purchase commitments which relate to the acquisition of long-lead equipment for the Germain CDP and Saleski Phase 1. Outstanding share data At March 21, 2012, share capital consisted of the following: (thousands) Common shares 64,923 Stock options 3,824 Performance share units 746 Performance warrants 4,071 Total 73,564 Each performance warrant, stock option and performance share unit is convertible to one common share Annual Report

51 Subsequent Event On February 15, 2012, the Company closed a transaction to acquire additional working interests in certain jointly-owned oil sands assets from a related party for total fair market consideration of $30.0 million in exchange for 705,882 common shares of Laricina. The Company requested that GLJ prepare a proforma reserves and resource assessment and economic evaluation report that incorporated the additional working interests (Proforma GLJ Report), effective January 1, Laricina s best estimate contingent and prospective resources increased to 4.6 billion barrels of net recoverable resource from 4.5 billion barrels and the best estimate contingent and prospective resources net present value before income tax at a 10 percent discount rate increased to $10.4 billion from $10.1 billion (2) (4). The economic evaluation for the Proforma GLJ Report, which included probable reserves and probable plus possible reserves, was consistent with the GLJ Report s net present value of future net revenue before income tax at a 10 percent discount rate of $0.8 billion and $1.1 billion, respectively. Reserves (1) Contingent Resources (2) (3) Prospective Resources (4) Probable plus (mmbbls) Probable Possible Low Best High Low Best High Saleski 330 1,750 2,636 Germain Grand Rapids ,094 Germain Winterburn 432 1,157 Burnt Lakes 567 1, Conn Creek Poplar Creek Other properties ,364 4,342 7, (1) (2) (3) (4) The COGE Handbook defines possible reserves as those additional reserves that are less certain to be recovered than probable reserves. There is a 10 percent probability that the quantities actually recovered will equal or exceed the sum of proved plus probable plus possible reserves. The 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. There is no certainty that it will be commercially viable to produce any portion of the contingent resources. Contingent resources for Conn Creek, Poplar Creek and Saleski are based on SAGD technology; Germain Winterburn is based on CSS; 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. 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. There is no certainty that any portion of the prospective resources will be discovered. If a discovery is made, there is no certainty that it will be developed. If it is developed, there is no certainty as to the timing of such development. 49 Laricina Energy Ltd.

52 The net present value of future net revenue before income tax at a 10 percent discount rate is as follows: ($ millions) Low Best High Contingent resources 1,545 10,231 20,015 Prospective resources Critical Accounting Estimates IFRS requires certain estimates and assumptions in the preparation of financial statements that are based on management s best judgment. By their nature, estimates and assumptions are uncertain 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 reserves and resources Laricina s oil sands reserves and resources are independently evaluated by petroleum engineering consultants. The estimation of reserves and resources 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 reserve and resource estimates could occur from the results of future drilling, testing, production levels and economics of recovery. Impairment Impairment is indicated if the net carrying value of capital assets is deemed unrecoverable 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, production rates, commodity prices, future development costs and other relevant assumptions. Site restoration provisions The fair value of the provision is recognized as both an asset and a liability for existing site restoration obligations. The 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 discount rate appropriate for the Company. Estimating the timing, amount and value of these retirement costs is subject to judgment. Share-based payments 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. Deferred income tax The determination of deferred income tax assets and liabilities requires interpretation of complex laws and regulations, and deferred 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 Annual Report

53 Changes in Accounting Policies In February 2008, the CICA AcSB confirmed the adoption of IFRS for interim and annual reporting purposes for fiscal years beginning on or after January 1, In July 2009, the International Accounting Standards Board approved additional IFRS transitional exemptions for entities to allocate their oil and natural gas assets under full cost accounting to the IFRS categories of E&E 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 used this exemption upon adoption. The most significant impact of the IFRS conversion is the accounting for E&E assets and PP&E. IFRS does not provide specific oil and natural gas accounting guidance other than for costs incurred during the E&E phase. The conversion to IFRS will have a significant impact on the future 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 site restoration provisions (asset retirement obligations), share-based payments (stock-based compensation) and other first-time adoption exemptions. The impact on the Company s January 1, 2010 opening financial position, required under IFRS for comparative purposes, was as follows: an increase in site restoration provisions of $0.4 million, an increase in share capital of $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 $1.3 million as a result of the adjustments to accounting for share-based payments. Each of these adjustments has a corresponding change to retained earnings as well as a deferred income tax impact. The adoption of IFRS resulted in higher share-based payment expense at the time of grant 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 increased due to the component depreciation required under IFRS. Risk Management Laricina s operation and financial success could be affected by a variety of risks related to the oil and natural gas industry, many of which are not in the Company s control. Laricina does not have commercial oil sands operations and its primary assets consist of oil sands properties that are undeveloped or under current development plans. Accordingly, the Company s success depends on the successful execution of its current development plans, future development and additional acquisitions of oil sands properties. Current risk factors influencing the Company include, but are not limited to, the following: Uncertainty of reserves and resources Estimating oil sands reserves and resources is inherently uncertain and no assurance can be given that the level of reserves and resources or recovery of bitumen will be realized. Reservoir engineering is a partially subjective process of estimating and is highly dependent on the accuracy of the assumptions on which it is 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. Estimates of the economically recoverable bitumen and the classification of such reserves and resources are based on risk of recovery, and the 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. 51 Laricina Energy Ltd.

54 Capital requirements and financial resources Similar 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 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 depends 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 in 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 affect the timing of Laricina s project development plans or increase costs, which might 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. Local communities are active in reviewing and participating in the regulatory process. Interventions should they occur can impact the timing and risks of regulatory approvals. 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 natural gas sector. The government remains committed to this initiative and is drafting legislation for the fall 2012 session of the Legislative Assembly that would facilitate the implementation of the contemplated changes. 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, licences, 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 guide future decisions while considering the social and economic impacts. The Government of Alberta released the draft LARP in August 2011 and the proposed conservation areas do not directly affect any of Laricina s current oil sands leases. The full impact of the proposed legislation on the Company cannot be determined until the LARP is finalized and the various regional environmental management outcomes are established. 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 spills 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 Company s financial condition Annual Report

55 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 12 percent from a regulated baseline starting July 1, If the emissions intensity target is not met through improvements in operations, compliance tools include 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. The Saleski pilot is not subject to the SGER as its emissions will be below the threshold. The Germain commercial demonstration project will require reporting but not compliance based on the current threshold. Federal and provincial reporting is required for emissions above 50,000 tonnes. In addition, 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 Government of Canada has also indicated its intention to develop greenhouse gas regulations for the oil and natural gas industry with a view to having draft regulations prepared by the end of Environment Canada is currently working with industry and other stakeholders on the design of the regulations. It is unclear at this time what additional financial liability the federal regulations would create but there has been agreement in principle that there will be harmonization with provincial regulations and a suite of flexible compliance mechanisms designed to ensure that the sector s competitiveness is maintained. There is no federal regulation of greenhouse gases. Until such time as this might occur, the impact on the Company s operations remains unknown. On February 3, 2012 the Government of Alberta and the Government of Canada announced their intention to significantly increase the level of environmental monitoring occurring on the oil sands region through the creation of a new, scientifically rigorous, comprehensive, integrated and transparent environmental monitoring program. It will include increased air, water, land and biodiversity monitoring and commence immediately. The estimated cost of the program is $50 million per year and will be borne by the oil sands producers. It is unclear how the funding requirement will be allocated among companies, but it is likely that Laricina will be required to provide some funding in 2012 and the level of funding will likely increase over time in conjunction with increases in Laricina s future production. Laricina participates in several ongoing research studies and anticipates mitigating the impacts of the aforementioned legislative initiatives through innovations that increase operating efficiency by reducing energy consumption 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 depend on its ability to enter into joint venture arrangements with other oil sands development companies, enter into beneficial partnerships with other industry participants, 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. In the event that a commercial bitumen recovery project is developed and becomes operational, Laricina s revenue and expenses will be directly affected by the applicable royalty regime. The economic benefit of future capital expenditures 53 Laricina Energy Ltd.

56 for any project, in many cases, depends 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 Competiveness Review. The review did not affect bitumen production as its focus was on conventional oil and gas production. Exploration, development and production risks 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 is designing and testing innovative, improved recovery and cost-reduction strategies for in situ projects. There is no assurance that the Company s development strategy will achieve positive financial results. Infrastructure The future development of the Company s commercial projects will depend on certain infrastructure, including roads and camps, pipelines for transportation of diluent and blended bitumen, natural gas fuel pipelines 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 liability that 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. 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 include assumptions regarding recoverability and marketability of oil and natural gas, future commodity prices, future 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 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 not under Laricina s control. The Company s future financial results depend on 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 bitumen production. Laricina s future earnings could be reduced should natural gas prices increase. Higher costs of diluent and hydrocarbon solvents could also reduce future earnings Annual Report

57 Lack of liquidity Laricina is privately held. A future public offering might not lead to an active trading market or, if developed, one that would be sustainable. There can be no assurance that a future offering 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 Laricina s continued success depends on the performance of key employees. Failure to retain current key employees or to attract and retain additional key employees with the necessary skills could have an adverse effect on the Company s development, growth and profitability. Seasonality Certain of Laricina s properties are in areas that are inaccessible during non-winter months or where activities are restricted due to environmental concerns. Seasonal factors and unexpected weather may delay exploration or development. 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 affect operations or there could be a material adverse effect on the Company s financial position or cash flow. 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 taxation authorities in a way that would have an impact on current and future income taxes payable Outlook The equity private placements completed throughout 2011 enable Laricina to manage the pace of commercial development including the Germain CDP and the Saleski Phase 1 expansion. 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 developers or joint venture agreements. During 2012, the majority of capital spending will be focused on the Germain CDP construction including the remaining 20 percent of detailed engineering, completion of module fabrication, electrical infrastructure and site construction. Module fabrication started in 2011 and the first completed modules were transferred to Germain in the first quarter of The Germain CDP is anticipated to be commissioned early in 2013 and to start initial steaming during the second quarter of 2013, with production expected three to four months later. The remaining four horizontal well-pairs planned for the Germain CDP to sustain 5,000 barrels per day will be drilled as required. In 2012 the Company also plans to commence engineering for the Germain Phase 2, 30,000-barrel-per-day expansion. 55 Laricina Energy Ltd.

58 The Saleski pilot will continue injection and production testing cycles throughout 2012 to obtain performance curve information for SAGD operations. In the first quarter of 2012, the Company commissioned the second steam generator and is currently completing a second well-pair in the C-zone of the Grosmont Formation. This well-pair incorporated drilling techniques that are expected to reduce the cost of future well-pairs. The spacing between the injector and producer wells was reduced from that of the previous two well-pairs to enhance early start-up. Steam injection in the new well-pair is planned to commence in the second quarter of 2012 with initial bitumen response anticipated three to four months thereafter. The second stage of applying solvent to SAGD production is expected to commence in the second half of 2012 once longer-term conventional SAGD performance has been established. Laricina will continue to advance the Saleski Phase 1 expansion of 10,700 barrels per day, with an initial focus on drilling 16 well-pairs, completing front-end engineering and design, and preparing the site. The regulatory application for the Saleski Phase 1 expansion was filed in December 2010 with approval expected in the second quarter of Additional activities in 2012 will include the replacement of bridges and upgrades to access roads, and advancing plans for the Stony Mountain Pipeline, all to support the continued growth of the Saleski and Germain projects. As production increases, a permanent pipeline connection becomes critical to cost-effective marketing of blended bitumen sales. Laricina has begun planning the Stony Mountain Pipeline, a 184-km system which includes a 24-inch line to transport blended bitumen sales and a 12-inch line to bring in condensate for blending and SC-SAGD purposes. It is the first regional pipeline initiative in the west Athabasca region and Laricina anticipates interest from other area operators to access pipeline capacity. The regulatory applications are expected to be filed by mid-year, with construction beginning in late 2013 and the pipeline entering service in mid As the Company continues to advance its projects, additional expertise will be required to complete and execute the Germain CDP, advance the Saleski Phase 1 expansion and accommodate the increased production expected from the Saleski pilot. This expertise will be required for all aspects of the business and will include head office and field employees as well as consultants. General and administrative expenses are expected to increase as a result of additional salaries and overhead to accommodate costs associated with personnel increases. The winter exploration and development drilling programs were completed in the first quarter of 2012 and consisted of 25.0 km of 2-D seismic at Germain, 20.7 square-km of 3-D seismic at Saleski, and 1.3 square-km of 4-D seismic over the Saleski pilot, five exploration wells and four observation wells. The 2012 capital and net operating expenditures (including cash general and administrative expenses) are expected to be approximately $470.1 million mostly to advance the Germain CDP. Laricina anticipates that 2012 will be a year of significant growth and advancement as the Company continues its evolution to commercial production by advancing the Germain CDP, ramps up production at the Saleski pilot, advances plans for pipeline transportation, commences construction on Saleski Phase 1 and secures the expertise of additional employees and consultants to support the projects Annual Report

59 Auditors Report to the Shareholders To the Shareholders of Laricina Energy Ltd. We have audited the accompanying consolidated financial statements of Laricina Energy Ltd., which comprise the consolidated statements of financial position as at December 31, 2011, December 31, 2010 and January 1, 2010, the consolidated statements of comprehensive loss, changes in equity and cash flows for the years ended December 31, 2011 and December 31, 2010, 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 International Financial Reporting Standards, and for such internal control as management determines is necessary to enable the preparation of consolidated financial statements that are free from material misstatement, whether due to fraud or error. 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 our 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, we consider internal control relevant to the entity s preparation and fair presentation of the consolidated financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity s internal control. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of accounting estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that the audit evidence we have obtained in our audits is sufficient and appropriate to provide a basis for our audit opinion. Opinion In our opinion, the consolidated financial statements present fairly, in all material respects, the consolidated financial position of Laricina Energy Ltd. as at December 31, 2011, December 31, 2010 and January 1, 2010 and of its consolidated financial performance and its consolidated cash flows for the years ended December 31, 2011 and December 31, 2010 in accordance with International Financial Reporting Standards. (signed) "KMPG LLP" Chartered Accountants Calgary, Canada March 21, Laricina Energy Ltd.

60 Consolidated Statements of Financial Position As at December 31 December 31 January 1 (thousands of dollars) Note Assets Current assets Cash and cash equivalents 12 $ 656,891 $ 375,426 $ 156,062 Trade and other receivables 17,892 17,030 3,306 Prepaid expenses and deposits Inventories 5 1, , , ,829 Non-current assets Abandonment deposits Other long-term assets 6 1, Exploration and evaluation assets 7 638, , ,669 Property, plant and equipment 8 45,313 30,705 20,221 Intangible assets 9 9, , , ,492 Total assets $ 1,372,640 $ 850,728 $ 498,321 Liabilities and shareholders equity Current liabilities Trade and other payables $ 44,210 $ 31,408 $ 10,509 Finance lease obligation 8 5,000 49,210 31,408 10,509 Non-current liabilities Site restoration provision 10 16,178 4,747 2,584 Deferred revenue 32 Finance lease obligation 8 7,851 Deferred income tax 11 10,403 16,777 20,129 34,432 21,524 22,745 Total liabilities 83,642 52,932 33,254 Shareholders equity Share capital 13 1,286, , ,872 Contributed surplus 28,478 21,771 17,484 Deficit (25,832) (4,173) (289) Total shareholders equity 1,288, , ,067 Total liabilities and shareholders equity $ 1,372,640 $ 850,728 $ 498,321 The accompanying notes are an integral part of these consolidated financial statements. On behalf of the Board: (signed) "Brian K. Lemke" Brian K. Lemke Director (signed) "Glen C. Schmidt" Glen C. Schmidt Director Annual Report

61 Consolidated Statements of Comprehensive Loss For the years ended December 31 (thousands of dollars) Note Revenue Blended bitumen sales $ 2,433 $ Royalties (74) Net operating revenue 2,359 Other income 2,892 3,001 5,251 3,001 Expenses Transportation and blending 1,230 Operating 11,421 Pre-exploration 364 General and administrative 17,157 8,227 Depreciation 5,769 1,186 35,941 9,413 Results from operating activities (30,690) (6,412) Finance income 6,803 2,387 Finance expenses 8, 10 (1,361) (128) Net finance income 5,442 2,259 Loss before tax (25,248) (4,153) Deferred income tax recovery 11 (3,589) (269) Total comprehensive loss for the year $ (21,659) $ (3,884) The accompanying notes are an integral part of these consolidated financial statements. 59 Laricina Energy Ltd.

62 Consolidated Statements of Changes in Equity Share Contributed (thousands of dollars) Capital Surplus Deficit Total Equity Balance at January 1, 2010 $ 447,872 $ 17,484 $ (289) $ 465,067 Comprehensive loss (3,884) (3,884) Issuance of common shares 339, ,650 Share issuance costs, net of tax of $3,083 (9,247) (9,247) Share-based payments 6,066 6,066 Options exercised 196 (53) 143 Performance share units exercised 1,727 (1,726) 1 Balance at December 31, ,198 21,771 (4,173) 797,796 Comprehensive loss (21,659) (21,659) Issuance of common shares 519, ,683 Share issuance costs, net of tax of $5,022 (15,065) (15,065) Share-based payments 8,242 8,242 Performance share units exercised 1,536 (1,535) 1 Balance at December 31, 2011 $ 1,286,352 $ 28,478 $ (25,832) $ 1,288,998 The accompanying notes are an integral part of these consolidated financial statements Annual Report

63 Consolidated Statements of Cash Flows For the years ended December 31 (thousands of dollars) Cash flows from operating activities Comprehensive loss $ (21,659) $ (3,884) Adjustments for: Depreciation 5,769 1,186 Equity settled share-based payments 4,227 2,766 Unwinding of site restoration discount Deferred income tax recovery (3,589) (269) Deferred income (32) (43) (14,933) (116) Change in trade and other receivables (733) (6,116) Change in prepaid expenses and deposits (153) 1 Change in inventories (896) (254) Change in trade and other payables 4,948 2,761 Net cash used in operating activities (11,767) (3,724) Cash flows from investing activities Property, plant and equipment, and exploration and evaluation expenditures (198,108) (106,506) Intangible expenditures (5,667) Abandonment deposits (399) (149) Net cash used in investing activities (204,174) (106,655) Cash flows from financing activities Proceeds from the issuance of common shares 519, ,032 Finance lease obligation (2,149) Share issuance costs (20,129) (12,289) Net cash from financing activities 497, ,743 Net increase in cash and cash equivalents 281, ,364 Cash and cash equivalents, beginning of year 375, ,062 Cash and cash equivalents, end of year $ 656,891 $ 375,426 The accompanying notes are an integral part of these consolidated financial statements. 61 Laricina Energy Ltd.

64 Notes to the Consolidated Financial Statements December 31, 2011 (tabular amounts in thousands of dollars except per share amounts and as otherwise noted) 1. Reporting Entity Laricina Energy Ltd. (Laricina or the Company) was incorporated on November 11, 2005 under the Business Corporations Act (Alberta). The consolidated financial statements of the Company as at and for the year ended December 31, 2011 are comprised of the Company and its subsidiaries. Since inception, Laricina has focused on acquiring prospective oil sands properties, developing properties into projects, financing, attracting suitable personnel and developing innovative technologies. Two areas have been identified as near-term commercial projects, Saleski and Germain. The Company will require equity and debt financing to fund projects beyond the Saleski pilot plant and Germain commercial demonstration project. 2. Basis of Preparation Statement of compliance These consolidated financial statements have been prepared in accordance with International Financial Reporting Standards (IFRS) and IFRS 1 First-Time Adoption of International Financial Reporting Standards applied effective January 1, An explanation of how the transition to IFRS has affected the reported financial position, financial performance and cash flows of the Company is provided in note 21. On March 21, 2012, the December 31, 2011 consolidated financial statements were approved for release to shareholders by the Board of Directors. Basis of measurement The consolidated financial statements were prepared on the historical cost basis except for liabilities for cash-settled share-based payment arrangements measured at fair value which are included in trade and other payables. The methods used to measure fair value are discussed in note 4. Functional and presentation currency The consolidated financial statements are presented in Canadian dollars, which is the Company s functional currency. Financial information presented in Canadian dollars has been rounded to the nearest thousand except for per share amounts and if otherwise stated. Use of estimates and judgments The preparation of consolidated financial statements in conformity with IFRS requires management to make judgments, estimates and assumptions that affect the application of accounting policies and the reported amounts of assets, liabilities, income and expenses. 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 Annual Report

65 consolidated financial statements include, but are not limited to, the valuation of investment tax credits (note 6), the recovery of exploration and evaluation (E&E) assets (note 7), the valuation of property, plant and equipment (PP&E) (note 8), the valuation of intangible assets (note 9), site restoration provisions (note 10), valuation and utilization of tax losses (note 11) and measurement of share-based payments (note 13). 3. Summary of Significant Accounting Policies The accounting policies set out below were applied consistently by the Company and its subsidiaries to all years presented in the consolidated financial statements. Basis of consolidation Subsidiaries are entities controlled by the Company. Control exists when a company has the power to govern the financial and operating policies of an entity so as to obtain benefits from its activities. The financial statements of subsidiaries are included in the consolidated financial statements from the date that control commences until the date that control ceases. Many of the Company s oil sands activities involve jointly-controlled assets. The consolidated financial statements include the Company s share of these jointly-controlled assets and a proportionate share of the relevant revenue and related costs. Exploration and evaluation assets Costs of exploring for and evaluating oil sands properties are initially capitalized and may include costs of lease acquisition, technical services and studies, seismic acquisition, exploration drilling and testing, directly attributable overhead and administration expenses, and the projected costs of retiring the assets but do not include general prospecting or evaluation costs incurred prior to having obtained the legal rights to explore the area, which are expensed as they are incurred. E&E assets are not depleted or amortized until the earlier of: the asset is in use as management intended and the determination of technical feasibility and commercial viability of extracting a mineral resource. The technical feasibility and commercial viability of extracting a mineral resource is considered to be determined when proved reserves have been estimated. E&E assets are allocated to cash generating units (CGUs) for purposes of determining whether or not the assets must be transferred to the development and producing category within PP&E and for performing impairment testing when indicators of impairment exist. The Company uses the following CGUs for E&E assets: Saleski, Germain, Burnt Lakes and Other. A review of each exploration project is performed, at least annually, to determine whether proved reserves have been discovered. Upon determination of proved reserves, E&E assets attributable to these reserves are tested for impairment within the associated CGU and then transferred to development and producing (D&P) assets. E&E assets that are in use as management intended are amortized and recapitalized as intangible assets until technical feasibility and commercial viability of extracting a mineral resource can be determined. Once this has occurred the underlying intangible asset is transferred to D&P assets and subsequently depleted. Other E&E assets, including facilities and infrastructure, are amortized when they are used to support the gathering of reservoir information. The depreciation of these assets is recognized in profit or loss. 63 Laricina Energy Ltd.

66 3. Summary of Significant Accounting Policies (continued) Property, plant and equipment PP&E consists of assets which have been transferred from E&E assets to D&P assets, facilities and other equipment, and corporate assets. D&P assets are measured at cost less accumulated depreciation and depletion. The cost of D&P assets at January 1, 2010, the date of transition to IFRS, was determined as provided by the IFRS 1 exemption whereby oil and natural gas companies using full cost accounting could allocate carrying values of E&E assets to CGUs based on amounts determined under Canadian generally accepted accounting principles (GAAP) and allocate carrying values of D&P assets to appropriate CGUs using pro-rata reserve volumes or reserve values. The Company has allocated E&E assets to CGUs based on amounts previously determined under Canadian GAAP. There was no value assigned to the D&P assets at January 1, 2010 as no projects had met the criteria of technical feasibility and commercial viability. Costs incurred subsequent to the determination of technical feasibility and commercial viability and the costs of replacing parts of D&P assets are recognized as PP&E only when they increase the future economic benefits embodied in the specific asset to which they are related. All other expenditures are recognized as an expense when incurred. Such costs generally represent costs incurred in developing proved or probable reserves and bringing in or enhancing production from such reserves and are accumulated on a project-area basis. The carrying amount of any replaced or sold components is derecognized. The costs of the day-to-day maintenance of PP&E are recognized in profit or loss as incurred. Gains and losses on disposal of an E&E asset or PP&E are determined by comparing the proceeds from disposal with the carrying amount of the E&E asset or PP&E and are recognized on a net basis in other income or other expense in profit or loss. Depreciation and depletion The net carrying value of E&E assets is amortized on a straight-line basis over their estimated useful lives of between 10 and 25 years. E&E assets which are producing bitumen and gathering information about the reservoir to assist in the determination of technical feasibility and commercial viability of extracting mineral resources are recapitalized as intangible assets and will be subsequently transferred to D&P assets when proved reserves are assigned. Other E&E assets are transferred to D&P assets when production commences and proved reserves have been assigned. The net carrying value of D&P assets is depleted using the unit-of-production method which uses the ratio of production to the related total proved and probable reserves, taking into account the future development costs necessary to bring the related reserves into production. The estimate of future development costs is reviewed by independent reservoir engineers on an annual basis. Proved plus probable reserves are estimated using independent reservoir engineering reports and represent the estimated quantity of bitumen which geological, geophysical and engineering data demonstrate with a specified degree of certainty to be recoverable in future years from known reservoirs which are considered commercially producible. Such reserves may be considered commercially producible if management has the intention of developing and producing them and such intention is based upon: made available Annual Report

67 Reserves which can be produced economically through application of enhanced recovery techniques are only included in the proved plus probable classification when successful testing by a pilot project, or other reasonable evidence, such as experience of the same techniques on similar reservoirs or reservoir simulation studies, provide support for the engineering analysis on which the project was based. For facilities and other equipment, depreciation is recognized in profit or loss on a straight-line basis over their estimated useful life of 25 years. For corporate assets, depreciation is recognized in profit or loss on a straight-line basis over their estimated useful lives at annual rates of 20 to 30 percent. The expected residual value of facilities and other equipment, and corporate assets is evaluated when depreciation commences. Depreciation methods, useful lives and residual values are reviewed at each reporting date. When significant components of an E&E asset or PP&E have different useful lives, they are accounted for and depreciated as separate items. Inventories Inventories consist of materials, condensate, production blend and other inventory. Materials inventory consists of materials, parts and supplies and is valued at the lower of cost or net realizable value with cost determined using a first-in, first-out basis. Condensate inventory is condensate purchased for the purpose of blending and is valued at the lower of cost or net realizable value with cost determined using a weighted-average cost. Production blend inventory is produced bitumen that has been blended for purposes of transporting the product to market and is valued at the lower of cost or net realizable value with cost determined using a weighted-average cost. Other inventory consists primarily of gravel for use in road maintenance and site preparation, and is valued at the lower of cost or net realizable value with cost determined using a weighted-average cost. Leased assets Leases where the Company assumes substantially all the risks and rewards of ownership are classified as finance leases. Upon initial recognition the leased asset is measured at an amount equal to the lower of its fair value and the present value of the minimum lease payments. Subsequent to initial recognition, the leased asset is accounted for in accordance with the accounting policy applicable to the associated asset. Other leases are classified as operating leases and are not recognized in the Company s statement of financial position. Impairment A financial asset is assessed at each reporting date for objective evidence that it is impaired such as one or more events would have a negative effect on the asset s estimated future cash flows. Significant financial assets are tested for impairment on an individual basis with the remaining financial assets assessed in groups that have similar credit risk. An impairment loss of a financial asset is recognized in profit or loss and is calculated as the difference between the carrying amount and the present value of the estimated future cash flows, discounted at the original effective interest rate. 65 Laricina Energy Ltd.

68 3. Summary of Significant Accounting Policies (continued) The carrying amounts of the Company s non-financial assets, other than E&E assets and deferred income tax assets, are reviewed at each reporting period for indications of impairment. If there is an indication of impairment, the asset s recoverable amount is estimated. E&E assets are assessed for impairment when they are reclassified to D&P assets and if facts and circumstances suggest that the carrying amount exceeds the recoverable amount. For the purposes of impairment testing, assets are grouped into the smallest group that generates independent cash inflows from continuing use or CGU. The recoverable amount of the asset or the CGU is the greater of its value-in-use and its fair value less costs to sell. The Company s corporate assets do not generate separate cash inflows. If a corporate asset may be impaired, the asset is assessed for impairment by reviewing the recoverable amount for the CGU to which the asset has been allocated. In assessing value-in-use, the estimated future cash flows are discounted to their present value using a pre-tax discount rate that reflects the current market assessment of the time-value-of-money and the specific risks of the asset. Value-in-use is generally calculated using the present value of the future cash flows expected to be derived from the production of proved and probable reserves. An impairment loss is recognized if the carrying amount of an asset or its CGU exceeds its estimated recoverable amount. Impairment losses are recognized in profit or loss and are reversed in subsequent periods if indicators exist such that the impairment has decreased. The impairment loss is the lower of the recoverable amount and the carrying value of the asset, net of depreciation or depletion, as if no previous impairment existed. The Company assesses the impairment of E&E assets, before and at the moment of reclassification to PP&E using E&E CGUs. After the reclassification to PP&E on the basis of technical feasibility and commercial viability, D&P CGUs are used for impairment testing. Site restoration provision A provision is recognized if, as a result of a past event, the Company has a legal or constructive obligation that can be reliably estimated and it is probable that payment will be required to settle the obligation. A provision is determined by discounting the expected future cash flows at a rate that reflects the current assessment of the time-value-of-money and the risks specific to the underlying liability. The Company recognizes a provision for site restoration obligations as the activities of the Company give rise to dismantling, decommissioning and site disturbance remediation requirements. A provision is made for the estimated cost of site restoration with a corresponding increase to the related E&E asset or PP&E. Site restoration costs are amortized on a basis consistent with the related asset s depreciation and depletion policy. The site restoration provision is measured at the present value of management s best estimate of expenditures required to settle the obligation at the reporting date. Subsequent to the initial measurement, the provision is adjusted at the end of each reporting period to reflect the passage of time and changes in the estimated future cash flows underlying the obligation. The unwinding of the discount related to the passage of time is recognized as a finance expense and the changes in the estimated future cash flows are capitalized. Actual site restoration costs are charged against the site restoration obligation when incurred to the extent the estimated expenditure was provided for Annual Report

69 Share-based payment arrangements 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. A forfeiture rate is estimated on the grant date and is adjusted over time to reflect the actual number of stock options that vest. Upon exercise, consideration received together with the amount previously recognized in contributed surplus is recorded as an increase to share capital. The fair value of the amount payable to employees in respect of share appreciation rights, which are settled in cash, is recognized as compensation cost over the vesting period with a corresponding increase in accrued liabilities. Revenue Revenue from the sale of bitumen is recorded when the significant risks and rewards of ownership of the product are transferred to the buyer, typically when legal title passes to an external party. This is generally at the time the product is delivered to a sales terminal. Finance income and finance costs Finance income is recognized as it accrues using the effective interest method. Finance expense includes the unwinding of the site restoration provision discount and interest associated with finance leases. Income tax Income tax is comprised of current and deferred income taxes which are recognized in profit or loss except when they relate to items recognized directly in equity, or in other comprehensive income. The asset and liability method of accounting for income taxes is followed whereby deferred 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. Deferred income tax assets and liabilities are measured using the enacted or substantially enacted tax rates that will apply in the years the temporary differences are expected to be recovered or settled. Deferred income tax assets and liabilities are offset if there is a legally enforceable right to offset current income tax assets and liabilities, and they relate to income taxes levied by the same tax authority on the same taxable entity. A deferred income tax asset is recognized to the extent that it is probable that future taxable income will be available against which the temporary difference can be utilized. Deferred income tax assets are reviewed at each reporting date and are reduced to the extent the related tax benefit will no longer be realized. Share capital Common shares are classified as equity. Incremental costs directly attributable to the issuance of common shares are recognized as a deduction from equity, net of any tax effects. 67 Laricina Energy Ltd.

70 3. Summary of Significant Accounting Policies (continued) Flow-through common 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. Flow-through shares issued are recorded in share capital at the fair value of common shares on the date of issue. The premium received on issuing flow-through shares is initially recorded as a deferred credit. As qualifying expenditures are incurred, the premium is reversed and a deferred income tax liability is recorded. The net amount is then recognized as deferred income tax expense. Government assistance The Company receives funding from the Government of Alberta related to energy technology. The assistance is recorded as a reduction of the corresponding asset or expense when there is reasonable assurance of the collection of funding. Earnings per share Basic net profit or loss per common share is calculated using the weighted-average number of common shares issued and outstanding during the reporting period. The Company uses the treasury stock method to determine the dilutive effect of performance warrants, stock options and performance share units. Financial instruments Financial instruments are initially recognized in the statement of financial position at fair value. Subsequent measurement of financial assets and liabilities, except those at fair value through profit or loss and available-for-sale, are measured at amortized cost determined using the effective interest rate method. Cash and cash equivalents comprise cash balances and guaranteed investment certificates that may be redeemed at the option of the Company. Trade and other receivables, prepaid expenses and deposits are classified as loans and receivables while trade and other payables 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. New accounting standards and interpretations not yet adopted A number of new accounting standards, and amendments to standards and interpretations, are not yet effective for the year ended December 31, 2011, and were not applied in preparing these consolidated financial statements. None are expected to have a significant effect on the Company s financial statements, except for IFRS 9 Financial Instruments, which will be adopted on January 1, 2015 and is expected to affect the classification and measurement of financial assets. The impact to the Company s consolidated financial statements has not been determined. 4. Determination of Fair Values Certain accounting policies and disclosures require the Company to determine fair value for purposes of measurement or disclosure. Fair values have been determined based on the methods outlined below using the applicable hierarchy, where applicable. Level 1 fair value measurement Level 1 fair value measurements are based on unadjusted quoted market prices Annual Report

71 Level 2 fair value measurement Level 2 fair value measurements are based on valuation models and techniques where the significant inputs are derived from quoted indices. Stock options, performance share units and share appreciation rights The fair value is estimated using the Black-Scholes option pricing model based on market prices for the underlying common shares, volatility based on historical prices of publicly traded peer companies and published risk-free interest rates. Level 3 fair value measurement Level 3 fair value measurements are based on unobservable information derived from management s estimate of fair value. Additional disclosure about the assumptions used in determining fair value is in the notes specific to the asset or liability. Cash, trade and other receivables, and trade and other payables The fair value of cash and cash equivalents, trade and other receivables, and trade and other payables is estimated at the present value of the future cash flows, discounted at the market rate of interest at the reporting date. At December 31, 2011 and December 31, 2010 the fair value of these balances approximated their carrying value due to their short-term nature. Stock options, performance share units and share appreciation rights The fair value of stock options, performance share units and stock appreciation rights is measured using the Black-Scholes option pricing model. Measurement inputs include share price on the measurement date, the exercise price, expected volatility, expected life, expected forfeitures, expected dividends and the risk-free interest rate. The carrying value of accrued liabilities for stock appreciation rights has been assessed at a Level 2 fair value measurement as the significant inputs are derived from market prices, volatility based on historical prices of publicly traded peer companies and published risk-free interest rates. 5. Inventories December 31 December 31 January Condensate $ 123 $ $ Parts Production blend 92 Other 579 $ 1,740 $ 254 $ 6. Other Long-Term Assets At December 31, 2011, the Company had investment tax credits of $1.2 million ($0.6 million at December 31, 2010). The investment tax credits resulted from the Canada Revenue Agency s Scientific Research and Experimental Development (SR&ED) program and the Company s applications for 2007, 2008, and 2009 SR&ED expenditures. The after-tax benefit associated with the investment tax credits is approximately $0.9 million ($0.4 million at December 31, 2010). The investment tax credits will be used to offset current income taxes payable and begin to expire in Laricina Energy Ltd.

72 7. Exploration and Evaluation Assets Cost Deemed cost at January 1, 2010 $ 317,669 Additions during the year 108,137 Balance at December 31, ,806 Additions during the year 219,451 Balance, December 31, 2011 $ 645,257 Depreciation Balance, January 1, 2010 $ Depreciation for the year Balance, December 31, 2010 Depreciation for the year (6,852) Balance, December 31, 2011 $ (6,852) Carrying amounts As at January 1, 2010 $ 317,669 As at December 31, 2010 $ 425,806 As at December 31, 2011 $ 638,405 E&E assets consist of the Company s exploration projects which are pending the determination of technical feasibility and commercial viability. Additions represent the Company s share of the costs incurred on E&E assets during the period. During the years ended December 31, 2011 and December 31, 2010 no amount was transferred to PP&E. In March 2011 the Company began producing bitumen from the Saleski pilot. There are no proved reserves assigned to this project and as a result no assets were transferred to PP&E. Depreciation of the pilot s central processing facility and related infrastructure has been recorded in profit or loss. The depreciation of assets providing additional reservoir information has been recapitalized as intangible assets. E&E assets were recognized on transition to IFRS in accordance with IFRS 6 Exploration and Evaluation of Mineral Resources. All CGUs were tested for impairment as at January 1, 2010 and no impairment was identified. On July 19, 2011 the Government of Alberta announced that the Company was selected to receive funding of up to $10.0 million (gross) under the Innovative Energy Technologies Program for the Saleski pilot. The funds will be recorded as a reduction to the corresponding E&E asset when received. As at December 31, 2011, $5.5 million gross ($3.3 million net) has been recorded as a reduction of the costs associated with the Saleski pilot Annual Report

73 8. Property, Plant and Equipment Facilities and other Corporate Cost equipment assets Total Deemed cost, January 1, 2010 $ 19,637 $ 1,368 $ 21,005 Additions 10,564 1,106 11,670 Balance, December 31, ,201 2,474 32,675 Additions 15,264 1,643 16,907 Balance, December 31, 2011 $ 45,465 $ 4,117 $ 49,582 Depreciation Balance, January 1, 2010 $ $ (784) $ (784) Depreciation for the year (598) (588) (1,186) Balance, December 31, 2010 (598) (1,372) (1,970) Depreciation for the year (1,815) (484) (2,299) Balance, December 31, 2011 $ (2,413) $ (1,856) $ (4,269) Carrying amounts As at January 1, 2010 $ 19,637 $ 584 $ 20,221 As at December 31, 2010 $ 29,603 $ 1,102 $ 30,705 As at December 31, 2011 $ 43,052 $ 2,261 $ 45,313 During the year ended December 31, 2011 the Company entered into a contract with a third-party to establish a permanent camp at Germain. The Company assumes substantially all of the risks and rewards of ownership and, as a result, the contract is classified as a finance lease. As at December 31, 2011 assets held under finance lease have a gross carrying value of $15.0 million (nil at December 31, 2010) and accumulated depreciation of $0.6 million (nil at December 31, 2010) which is included in facilities and other equipment. 9. Intangible Assets At December 31, 2011 the Company had intangible assets of $5.7 million relating to payments made to a third-party to expand the availability of power for the Company s future development projects at Saleski and Germain. The depreciation of this asset will commence once the expansion is complete for the term of the contract with the third-party provider. At December 31, 2011, the Company had intangible assets of $3.8 million relating to the recapitalization of the depreciation of E&E assets. During the second quarter of 2011, the Company commenced production from the Saleski pilot. Although no proved reserves have been assigned to this project, the pilot is operating as management intended and, as a result, depreciation of the related assets is recognized. The depreciation of assets which directly contribute to the continued understanding of the reservoir and assist in the future assignment of proved reserves has been recognized as an intangible asset. 71 Laricina Energy Ltd.

74 10. Site Restoration Provision Balance, January 1, 2010 $ 2,584 Provisions made during the year 1,598 Revisions (change in discount rate) 461 Unwinding of discount 104 Balance, December 31, ,747 Provisions made during the year 8,916 Revisions (change in estimates) (457) Revisions (change in discount rate) 2,621 Unwinding of discount 351 Balance, December 31, 2011 $ 16,178 The Company s provisions include site restoration obligations arising from its ownership interest in oil sands assets including well sites and gathering systems. The total future site restoration obligation is estimated based on the Company s net ownership interest in all wells, facilities, roads, communication infrastructure and camps, estimated costs to reclaim and abandon these wells and facilities and the estimated timing of the costs to be incurred in future years. The Company has estimated the net present value of the site restoration obligation to be $16.2 million as at December 31, 2011 ($4.7 million at December 31, 2010) based on an undiscounted total future liability of $32.5 million ($13.3 million at December 31, 2010). These payments are expected to be made over the next 29 years with the majority of the costs to be incurred between 2025 and The discount factor, being the risk-free rate related to the liability, is 2.5 percent at December 31, 2011 (3.5 percent at December 31, 2010). 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 profit or loss before income taxes. A reconciliation of the difference for the years ended December 31 is as follows: Reconciliation of effective tax rate Loss before income taxes $ (25,248) $ (4,153) Canadian statutory income tax rate (percent) Expected income tax recovery at statutory rate (6,691) (1,163) Increase in income taxes resulting from: Reduction in effective tax rate Non-deductible costs 1, Flow-through share renunciation 3,915 (1,352) (269) Flow-through share premium (2,237) Total income tax recovery $ (3,589) $ (269) Laricina has unrecognized deferred tax assets of $4.3 million that relate to capital losses recognized in previous years. This amount has not been recognized as it is not probable that Laricina will have capital gains to offset these capital losses. The statutory rate decreased to percent in 2011 from percent as a result of tax legislation enacted in Annual Report

75 The temporary differences that give rise to the deferred tax assets and liabilities in the years ended December 31 are as follows: Deferred tax liabilities PP&E and E&E assets $ 52,855 $ 28,175 Deferred tax assets Non-capital losses (36,225) (7,883) Share issue costs (6,227) (3,515) (42,452) (11,398) $ 10,403 $ 16,777 Movement in deferred tax balances during the year ended December 31, 2011: Recognized Opening Recognized directly in Ending balance in loss equity balance PP&E and E&E assets $ 28,175 $ 24,680 $ $ 52,855 Non-capital losses (7,883) (28,842) (36,225) Share issue costs (3,515) 2,310 (5,022) (6,227) $ 16,777 $ (1,352) $ (5,022) $ 10,403 Movement in deferred tax balances during the year ended December 31, 2010: Recognized Opening Recognized directly in Ending balance in loss equity balance PP&E and E&E assets $ 27,709 $ 466 $ $ 28,175 Non-capital losses (5,397) (2,486) (7,883) Share issue costs (2,183) 1,751 (3,083) (3,515) $ 20,129 $ (269) $ (3,083) $ 16,777 As at December 31, 2011, the Company has non-capital losses of $144.7 million which begin to expire in Credit Facility The Company s credit agreement with a Canadian chartered bank has been extended to October 31, Amounts drawn 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 acceptance 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 an equivalent cash deposit. As at December 31, 2011 and March 21, 2012 the Company had issued letters of credit totalling $11.1 million and $13.5 million, respectively, under the credit facility and no amount had been drawn. 73 Laricina Energy Ltd.

76 13. 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, ,480 $ 447,872 Issued for cash 11, ,650 Share issuance costs, net of tax benefit (9,247) Stock options exercised Performance share units exercised 85 1,727 Balance, December 31, , ,198 Issued for cash 12, ,683 Share issuance costs, net of tax benefit (15,065) Performance share units exercised 67 1,536 Balance, December 31, ,211 $ 1,286,352 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 issuance 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 issuance 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 issuance 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 issuance costs). In accordance with 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, The Company had incurred the associated qualifying expenditures by April 30, On June 29, 2011, Laricina closed a private placement of 8,928,709 common shares at a price of $42.50 per common share for gross proceeds of $379.5 million ($365.8 million net of share issuance costs). In August 2011, Laricina closed additional private placements of 3,299,119 common shares at a price of $42.50 per common share for gross proceeds of $140.2 million ($133.8 million net of share issuance costs) Annual Report

77 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 Weighted Weighted average average Number exercise Number exercise (thousands) price (thousands) price Outstanding, beginning of year 4,071 $ ,071 $ Outstanding, end of year 4,071 $ ,071 $ Exercisable, end of year 4,071 $ ,071 $ Outstanding and exercisable performance warrants as at December 31, 2011: Outstanding Exercisable Weighted Weighted Weighted average average average remaining exercise exercise Exercise price Number contractual price Number price ($/warrant) (thousands) life (years) ($/warrant) (thousands) ($/warrant) $ $ $ 6.00 $ $ $ 8.00 $ $ $ $ $ $ $ $ $ , $ ,071 $ The fair value calculation for performance warrants was not required during the year ended December 31, 2011 and December 30, 2010 as no performance warrants were issued or required a change in measurement. Stock option plan The Company has a stock option plan under which directors, officers, employees of, and providers of services 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 Weighted Weighted average average Number exercise Number exercise (thousands) price (thousands) price Outstanding, beginning of year 3,083 $ ,588 $ Granted Exercised (29) 5.00 Forfeited (26) Outstanding, end of year 3,485 $ ,083 $ Exercisable, end of year 2,498 $ ,179 $ Laricina Energy Ltd.

78 13. Share Capital (continued) Outstanding and exercisable options as at December 31, 2011: Outstanding Exercisable Weighted Weighted Weighted average average average remaining exercise exercise Exercise price Number contractual price Number price ($/option) (thousands) life (years) ($/option) (thousands) ($/option) $ , $ ,690 $ 5.00 $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ 3, $ ,498 $ For the year ended December 31, 2011, compensation cost of $3.8 million ($2.1 million in 2010) has been recognized for options granted of which $2.0 million ($1.1 million in 2010) was capitalized. The estimated fair value of options was calculated at the date of grant using the Black-Scholes model and the following weighted average assumptions: Fair value per option $ $ 7.65 Expected volatility (percent) Risk-free interest rate (percent) Expected life (years) 7 7 Expected dividend yield (percent) A forfeiture rate of 2.0 percent in 2011 ( percent) was used when recording share-based payments related to the stock option plan. This estimate is adjusted to the actual forfeiture rate at time of forfeiture. Expected volatility is based on historical volatility of publicly traded peer companies. Expected life is based on general option holder behavior and the risk-free interest rate is based on Government of Canada bonds of a similar duration. 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, 2011 have a weighted average remaining contractual life of 5.0 years Annual Report

79 Weighted Weighted average average Number exercise Number exercise (thousands) price (thousands) price Outstanding, beginning of year 555 $ $ 0.01 Granted Exercised (67) 0.01 (85) 0.01 Forfeited (17) Outstanding, end of year 675 $ $ 0.01 Exercisable, end of year 159 $ $ 0.01 For the year ended December 31, 2011, compensation cost of $4.5 million ($3.9 million in 2010) has been recognized for PSUs granted of which $2.4 million ($2.2 million in 2010) was capitalized. The estimated fair value of PSUs was calculated at the date of grant using the Black-Scholes model and the following weighted average assumptions: Fair value per option $ $ Expected volatility (percent) Risk-free interest rate (percent) Expected life (years) 7 7 Expected dividend yield (percent) A forfeiture rate of 2.0 percent in 2011 (1.2 percent in 2010) was used when recording share-based payments related to the PSUs. Expected volatility is based on historical volatility of publicly traded peer companies. Expected life is based on general option holder behavior and the risk-free interest rate is based on Government of Canada bonds of a similar duration. Share appreciation rights The Company has 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 (SARs) 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 SARs is two years Weighted Weighted average average Number exercise Number exercise (thousands) price (thousands) price Outstanding, beginning of year 36 $ $ Granted Exercised (11) Forfeited (8) Outstanding, end of year 77 $ $ Exercisable, end of year 6 $ $ 77 Laricina Energy Ltd.

80 13. Share Capital (continued) All SARS were granted to employees directly involved in field activities. For the year ended December 31, 2011, compensation cost was $0.3 million on SARs granted ($0.1 million in 2010). At December 31, 2011, the Company had recorded an accrued liability of $0.3 million ($0.1 million at December 31, 2010) for outstanding SARs. At December 31, 2011, the Company had a nominal obligation (nil at December 31, 2010) for SARs that had vested. The estimated fair value of SARs for the year ended December 31, 2011 was calculated at the date of grant using the Black-Scholes model and the following weighted average assumptions: Fair value per SAR $ 6.95 $ 4.25 Common share per price on the date of grant $ $ Exercise price $ $ Expected volatility (percent) Risk-free interest rate (percent) Expected life (years) Expected dividend yield (percent) A forfeiture rate of 10.0 percent was applied for grants issued during the year ended December 31, 2011 (10.0 percent in 2010), when recording share-based payments related to the SARs. Expected volatility is based on historical volatility adjusted for changes expected due to publicly available information. Expected life is based on general option-holder behavior and the risk-free interest rate is based on Government of Canada bonds of a similar duration. 14. Loss per Share Basic loss per share The calculation of basic loss per share at December 31, 2011 was based on the loss attributable to common shareholders of $21.7 million ($3.9 million in 2010) and a weighted average number of common shares outstanding during the year ended December 31, The weighted average number of common shares outstanding was calculated as follows: (thousands of shares) Issued common shares at beginning of year 51,916 40,480 Effect of common shares issued 5,763 5,156 Effect of options exercised 1,460 Effect of PSUs exercised Weighted average common shares outstanding (basic) 57,726 47,137 Diluted loss per share The calculation of diluted net loss per share does not include performance warrants, options or performance share units as the effect would be anti-dilutive. The basic and diluted loss per share was $0.38 for the year ended December 31, 2011 compared to $0.08 for the year ended December 31, Annual Report

81 15. Personnel Expenses The aggregate payroll expense of employees and executive management are as follows: Wages and salaries $ 11,885 $ 6,891 Benefits and other personnel costs 2,875 1,534 Share-based payments 8,770 6,071 Total remuneration 23,530 14,496 Capitalized portion of total remuneration (11,496) (8,639) $ 12,034 $ 5,857 Personnel expenses directly related to E&E activities were capitalized and included in E&E assets. 16. Operating Leases Non-cancellable operating lease rentals as at December 31 are payable as follows: Less than one year $ 9,414 $ 3,989 Between one and five years 19,921 3,722 $ 29,355 $ 7, Executive Compensation In addition to salaries, the Company provides non-cash benefits to executive officers. The executive officers comprise the Chief Executive Officer, Senior Vice President In Situ and Exploration, Vice President Finance and Controller, Vice President Enhanced Oil Recovery, Vice President Corporate Development, Vice President Production, and Vice President Facilities. Executive officers also participate in the Company s stock option and performance share unit plans. Executive officer compensation costs for the years ended December 31 are comprised of the following: Salaries $ 1,835 $ 1,635 Other short-term employment benefits Share-based payments 2,031 1,571 $ 4,835 $ 4,089 Share-based payments represent the amortization of compensation costs associated with grants of stock options and performance share units to executive officers as recorded in the financial statements. 79 Laricina Energy Ltd.

82 18. Financial Risk Management The Company is exposed to certain financial risks as a result of exploration, development and financing activities. These risks include credit risk, liquidity risk and market risk. This note discusses the Company s exposure to these risks as well as the objectives, policies and processes for measuring and managing risk as well as capital management. The Board of Directors oversees management s establishment and execution of the risk management policies. The policies are established to identify and analyze the risks faced by the Company, to set appropriate risk limits and controls and to monitor risks and market conditions. Credit risk Credit risk is the risk that the counterparty to a financial asset will default resulting in the Company incurring a financial loss. It is mitigated through credit practices that limit transactions according to counterparties credit quality. A substantial portion of the Company s trade and other receivables 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. Laricina has historically not experienced any collection issues and joint venture receivables are typically collected within one month of the joint venture bill being issued. The Company does not anticipate any default as it transacts with creditworthy customers and management does not expect any losses from non-performance; as a result no provision for doubtful accounts has been recorded at December 31, 2011 or The carrying amount of financial assets represents the maximum credit exposure, as follows: December December 31 January Cash and cash equivalents $ 656,891 $ 375,426 $ 156,062 Trade and other receivables 17,892 17,030 3,306 $ 674,783 $ 392,456 $ 159,368 The maximum exposure to credit risk for trade and other receivables by type of customer was: December December 31 January Joint venture partners $ 3,466 $ 9,571 $ 1,000 Other 14,426 7,459 2,306 $ 17,892 $ 17,030 $ 3,306 The Company s most significant receivable of $5.5 million at December 31, 2011 was for the sale of data to a third-party. The Company s most significant receivable at December 31, 2010 was with a joint venture partner for $9.6 million. The Company s trade and other receivables were aged based on invoice date and all were classified as current (less than 30 days) as at December 31, 2011 and December 31, Annual Report

83 Liquidity risk Liquidity risk is the risk that the Company will encounter difficulties in meeting its financial liabilities. 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 capital and operating expenditure budgets that are monitored on a regular basis and updated as necessary. As at December 31, 2011, cash was held in a fully-liquid, interest-bearing operating account and Laricina had $15.0 million available in the bank credit facility to manage its expenditures, if necessary. Trade payables are expected to be paid within one month. The Company s liabilities at December 31 are payable as follows: Less than one year Trade and other payables $ 44,210 $ 31,408 Finance lease obligation 5,000 49,210 31,408 Between one and three years Finance lease obligation 7,851 $ 57,061 $ 31,408 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 beyond Laricina s control. The Company closely monitors commodity prices to determine the appropriate course of action. Prices for oil are determined in global markets and generally denominated in US dollars. The exchange rate effect cannot be quantified but generally an increase in the Canadian dollar versus the US dollar reduces the price received for oil. 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 to maintain a flexible capital structure which optimizes the costs of capital at an acceptable risk. Laricina s capital structure includes shareholders equity, bank debt and working capital. The Company does not have material 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. The Company s capital management objectives remained unchanged during the year ended December 31, Laricina is not subject to externally imposed capital restrictions; however, the credit facility referred to in note 12 is secured by an equivalent cash deposit. 81 Laricina Energy Ltd.

84 19. Capital Commitments At December 31, 2011, the Company had purchase orders outstanding of $61.4 million for the purchase of E&E assets. All of these purchase orders are due within one year. At December 31, 2010, the Company had purchase orders outstanding of $0.4 million for the purchase of E&E assets. 20. Subsequent Event On February 15, 2012, the Company acquired additional working interests in jointly-owned oil sands properties from a related party effective January 1, 2012 for total consideration of $30.0 million consisting of 705,882 common shares valued at $42.50 per common share Annual Report

85 21. Reconciliation from Canadian GAAP to IFRS Consolidated Statement of Financial Position at the date of IFRS Transition January 1, 2010 Effect of Canadian transition (thousands of dollars) Note GAAP to IFRS IFRS Assets Current assets Cash and cash equivalents $ 156,062 $ $ 156,062 Trade and other receivables 3,306 3,306 Prepaid expenses and deposits , ,829 Non-current assets Abandonment deposits Other long-term assets Exploration and evaluation assets a 317, ,669 Property, plant and equipment a 337,890 (317,669) 20, , ,492 Total assets $ 498,321 $ $ 498,321 Liabilities and shareholders equity Current liabilities Trade and other payables $ 10,509 $ $ 10,509 Non current liabilities Site restoration provision b 2, ,584 Deferred revenue Deferred income tax f 20,239 (110) 20,129 22, ,745 Total liabilities 32, ,254 Shareholders equity Share capital e 444,981 2, ,872 Contributed surplus c 16,178 1,306 17,484 Retained earnings (deficit) 4,239 (4,528) (289) Total shareholders equity 465,398 (331) 465,067 Total liabilities and shareholders equity $ 498,321 $ $ 498, Laricina Energy Ltd.

86 21. Reconciliation from Canadian GAAP to IFRS (continued) Consolidated Statement of Financial Position at the end of the last reporting year under Canadian GAAP December 31, 2010 Effect of Canadian transition (thousands of dollars) Note GAAP to IFRS IFRS Assets Current assets Cash and cash equivalents $ 375,426 $ $ 375,426 Trade and other receivables 17,030 17,030 Prepaid expenses and deposits Inventory , ,159 Non-current assets Abandonment deposits Other long-term assets Exploration and evaluation assets a 425, ,806 Property, plant and equipment a, d 457,787 (427,082) 30, ,845 (1,276) 457,569 Total assets $ 852,004 $ (1,276) $ 850,728 Liabilities and shareholders equity Current liabilities Trade and other payables $ 29,229 $ 2,179 $ 31,408 Non-current liabilities Site restoration provision b 3,695 1,052 4,747 Deferred revenue Deferred income tax f 18,170 (1,393) 16,777 21,865 (341) 21,524 Total liabilities 51,094 1,838 52,932 Shareholders equity Share capital e 779, ,198 Contributed surplus c 20,472 1,299 21,771 Retained earnings (deficit) 894 (5,067) (4,173) Total shareholders equity 800,910 (3,114) 797,796 Total liabilities and shareholders equity $ 852,004 $ (1,276) $ 850, Annual Report

87 Consolidated Statement of Comprehensive Loss for the year ended December 31, 2010 Effect of Canadian transition (thousands of dollars) Note GAAP to IFRS IFRS Revenue Other income $ 3,001 $ 3,001 3,001 3,001 Expenses General and administrative c $ 8,233 $ (6) $ 8,227 Depreciation d ,186 8, ,413 Results from operating activities (5,820) (592) (6,412) Finance income 2,387 2,387 Finance expenses b (128) (128) Net finance income 2,387 (128) 2,259 Net loss before income tax (3,433) (720) (4,153) Deferred income tax recovery f (88) (181) (269) Comprehensive loss $ (3,345) $ (539) $ (3,884) 85 Laricina Energy Ltd.

88 21. Reconciliation from Canadian GAAP to IFRS (continued) Notes to the Reconciliation from Canadian GAAP to IFRS: (a) IFRS 1 election for full cost oil and gas entities The Company elected an IFRS 1 exemption whereby the Canadian GAAP full cost pool was measured upon transition to IFRS as follows: i. E&E assets were reclassified from the full cost pool to E&E assets at the amount previously recorded under Canadian GAAP. ii. No amounts were allocated to the development and producing assets as technical feasibility and commercial viability has not been established at the date of transition. (b) Site restoration provision Under Canadian GAAP asset retirement obligations were discounted at a credit-adjusted risk-free rate of between 4.5 percent and 5.1 percent. Under IFRS the estimated cash flows for site restoration have been risk-adjusted; therefore, the provision is discounted at a risk-free rate and re-evaluated at each reporting period. Upon transition to IFRS this resulted in an increase in the site restoration provision with a corresponding decrease in retained earnings. Under Canadian GAAP, unwinding of the discount was capitalized as Laricina was a pre-operational company. Under IFRS, the unwinding of the discount is included as a finance expense. (c) Share-based payments Under Canadian GAAP, the Company recognized an expense related to share-based payments on a straight-line basis through the date of vesting and accounted for forfeitures as they occurred. Under IFRS, the Company is required to recognize the expense over the individual vesting periods for the graded vesting awards and to estimate a forfeiture rate. (d) Depreciation When significant components of E&E or PP&E, have different useful lives they are accounted for and depreciated as separate items. Certain assets became available for use during 2010 and were subject to depreciation. (e) Flow-through shares Under Canadian GAAP, the Company recorded flow-through shares at the amount received on issuance. Under IFRS, the Company is required to record the flow-through shares at the value of common shares and recognize a liability associated with the premium received for renunciation of tax pools to the investor. (f) Deferred income tax liability and deferred income tax recovery Deferred income tax liability and deferred income tax recovery was recorded based on the adjustments previously mentioned. Material adjustments to the condensed consolidated statements of cash flows during 2010 There are no material differences between the statements of cash flows presented under IFRS and the statements of cash flows presented under previous Canadian GAAP for the year ended December 31, Annual Report

89 glossary CSS CDP CPF EIA ERCB ESEIEH GAAP IFRS PHARM SAGD SC-SAGD SOR WTI cyclic steam stimulation commercial demonstration project central processing facility environmental impact assessment Energy Resources Conservation Board enhanced solvent extraction incorporating electromagnetic heating generally accepted accounting principles International Financial Reporting Standards passive heat-assisted recovery method steam-assisted gravity drainage solvent-cyclic SAGD steam-to-oil ratio West Texas Intermediate abbreviations % percent bbls barrels bbls/d barrels per day km kilometre(s) kv kilovolt m metre(s) mmbbls million barrels MMBtu million British thermal unit PV10 net present value, before tax, 10 percent discount 87 Laricina Energy Ltd.

90 Corporate Information Senior Management Glen C. Schmidt President and CEO David J. Theriault Senior Vice President In Situ and Exploration Neil R. Edmunds Vice President Enhanced Oil Recovery Karen E. Lillejord Vice President Finance and Controller Marla A. Van Gelder Vice President Corporate Development Derek A. Keller Vice President Production Directors Brian K. Lemke (1) (2C) Independent Investor Jeffrey M. Donahue, Jr. (2) (3) Senior Principal Principal Investing, CPPIB Equity Investments Inc. Jonathan C. Farber (2) (3) Managing Director, Lime Rock Partners S. Barry Jackson (3) (4C) Chairman, TransCanada Corporation Gordon J. Kerr (2) (4) President and CEO, Enerplus Corporation Robert A. Lehodey, Q.C. (3C) (4) Partner, Osler, Hoskin & Harcourt LLP W. Glen Russell (3) (4) Principal, Glen Russell Consulting Glen C. Schmidt President and CEO, Laricina Energy Ltd. Annual General Meeting The Annual General Meeting of Laricina s shareholders will take place on May 24, 2012 at a.m. MDT in the Lecture Theatre Room of the Metropolitan Centre, at th Ave. SW, Calgary, Alberta. (1) Chairman of the Board (2) Audit Committee (3) Governance & Human Resources Committee (4) Technical Committee (C) Committee Chairman Auditors KPMG LLP Bankers Canadian Imperial Bank of Commerce Solicitors Osler, Hoskin & Harcourt LLP Reservoir Engineers GLJ Petroleum Consultants Ltd. Registrar and Transfer Agent Equity Financial Trust Company Annual Report

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92 Head Office Laricina Energy Ltd. East Tower, 5th Ave. Place Suite 800, 425 1st Street S.W. Calgary, AB. T2P 3L8 Phone: Fax: Field Office Wabasca Community Office Laricina Energy Ltd Mistassiniy Road P.O. Box 540 Wabasca, AB. T0G 2K0 Phone: Fax: